**Artificial Lift Application Engineering Reference Manual** ##### Table of Contents [**Purpose of the Manual vii**](.) - **Artificial Lift Methods** *1-1* - Artificial Lift Method Selection *1-1* - [Rod Pumps 1-4](.) - Progressing Cavity Pump *1-5* - Hydraulic Lift – Jet Pumps *1-6* - Gas Lift *1-7* - Electric Submersible Pumps *1-8* - [**Electrical Submersible Pump (ESP) 2-1**](.) - [Gather the Data and Specifications (ESP) 2-1](.) - [Pump 2-55](.) - [Protector 2-78](.) - [Motor 2-96](.) - [Permanent Magnet Motor 2-106](.) - [Power Cable 2-106](.) - [Other Equipment 2-117](.) - [**Electrical Submersible Progressing Cavity Pump (ESPCP) 3-1**](.) - [Gather the Data and Specifications 3-1](.) - [PCP 3-1](.) - [Flex-Shaft Unit 3-1](.) - [Support Unit 3-2](.) - [PMM Motor 3-7](.) - [Power Cable 3-7](.) - [**Advanced Completion ESP 4-1**](.) - [Gather the Data and Specifications 4-1](.) - [ESP Bypass System 4-1](.) - [POD ESP System 4-30](.) - [Dual Concentric ESP System 4-30](.) - [Auxiliary Equipment 4-31](.) - [**Alternative Deployed ESP 5-1**](.) - [Gather the Data and Specifications 5-1](.) - [Coiled-Tubing Deployed ESP 5-1](.) - [Shuttle Deployed ESP 5-1](.) - [Cable Deployed ESP 5-1](.) - [Auxiliary Equipment 5-1](.) - [**Horizontal Pumping System 6-1**](.) - [Gather the Data and Specifications 6-1](.) - [System Components 6-1](.) - [HPS Skid Weldment Assembly 6-16](.) - [Prime Mover 6-19](.) - [Instrumentation 6-24](.) - [Installation Considerations 6-26](.) - [Reference Links to HPS Information 6-27](.) - [Auxiliary Equipment 6-27](.) - [**Gas Lift 7-1**](.) - [Gather the Data and Specifications 7-1](.) - [Gas Lift Equipment Selection 7-1](.) - [Gas Lift Introduction 7-10](.) - [Auxiliary Equipment 7-13](.) - [**Downhole Monitoring 8-1**](.) - [Gather the Data and Specifications 8-1](.) - [Monitoring Tools and Gauges 8-1](.) - [Types of Gauges 8-2](.) - [Surface Data Acquisition System 8-8](.) - Monitoring Guidelines *8-10* - Monitoring Parameters *8-12* [*A Surface Electrical Equipment A-1*](.) | A.1 Gather the Data and Specifications | A-1 | |--------------------------------------------|-------| | A.2 Introduction | A-1 | | A.3 Transformers | A-1 | | A.4 Switchboards | A-4 | | A.5 Transient Voltage Surge Suppressor | A-5 | | A.6 VSD | A-5 | | A.7 Controllers | A-18 | | A.8 Site Communications Box | A-20 | | A.9 Junction box and Wellhead | A-21 | | A.10 Soft Starters | A-21 | | A.11 Generators | A-24 | | A.12 Surface Cable | A-25 | | A.13 Conductors | A-27 | | A.14 Terminology | A-44 | | A.15 Surveillance and Optimization | A-46 | | B Advanced ESP Lifting Service | B-1 | | B.1 Advanced ESP lifting service | B-1 | | B.2 How it works | B-1 | | B.3 Case Studies | B-2 | | C Advanced Material Selection | C-1 | | C.1 Gather the Data and Specifications | C-1 | | C.2 Material Selection | C-1 | ##### Purpose of the Manual Application engineering for artificial lift methods and systems is a very challenging and diverse disci- pline, requiring domain knowledge and experience with many different downhole and surface prod- ucts and environments. This manual is intended to provide a reference to application engineers new to the role as well as those with many years of experience. An overview of the entire design and specification process is presented, as well as detailed discussions of each of the ordered tasks that must be completed to provide a sound artificial lift solution for the client’s unique well or field. Many data sources and business systems (software) are consulted during the design and specifica- tion process for artificial lift systems. It is not within the scope of this manual to include data from these various sources, but links to data sources are provided. Also, this manual does not include a primer or tutorial for any design software packages. As with all publications of this type, the guidelines and instructions in this manual are not a magic pill and are never substitute for common sense and advice from experienced practitioners. If in doubt about any tasks, procedures, or calculations encountered in this publication, seek advice or assis- tance from Artificial Lift InTouch engineers through their helpdesk on the InTouch knowledge man- agement system. ##### Artificial Lift Methods - **Artificial Lift Method Selection** ***1-1*** - [**Rod Pumps 1-4**](.) - **Progressing Cavity Pump** ***1-5*** - **Hydraulic Lift – Jet Pumps** ***1-6*** - **Gas Lift** ***1-7*** - **Electric Submersible Pumps** ***1-8*** *1* **Artificial Lift Methods** ###### 1 Artificial Lift Method Selection At a certain point in the life of an oil well (or field), and depending on the reservoir characteristics and drive mechanism, artificial lift will most likely become necessary for a more economic oil production. Typically required: - when reservoir pressures do not sustain optimum flow rates or incapable of producing fluid flow at all. - to transfer energy downhole or decrease fluid density in the wellbore to reduce hydrostatic pressure on formations so liquids will flow. Not only oil wells require forms of artificial lift. For example: - Gas fields dewatering: Gas Bed Methane/Coal Seam Gas - Water wells: Potable water - Hot spring water wells: Geothermal energy; Recreation - Mine dewatering - HPS: Water injection - HPS: Boosters pumps **Figure 1-1: Artificial Lift Methods** Once the decision is made to use some form of artificial lift at a certain point, the task of selecting the most suitable method becomes very important. The task of selecting the artificial lift method for a field or well depends on many factors: - Technical details and oil well conditions, including downhole temperature, GLR, water cut, sand and abrasives, corrosive gases and compounds, viscosity, casing size and completion type, inclination and doglegs, etc. - Location (onshore versus offshore), and availability of resources, power, gas, etc. - Economics in relation to operator objectives, both short terms and long term, price of oil, etc. **Example** Maximum oil production for the short term, as compared to balancing current oil productions with oil reserves for the long term (National Oil Companies). - Operating company preferences and inclinations. Upon discussions with different artificial lift experts in different operating companies and countries, one would notice that there are existing AL cultures that may favor certain types of AL or tries to avoid others. These AL biases are usually related to the background of the AL personnel, and their previous successes or failures. **Figure 1-2: Selection Factors** A typical “first pass” approach to AL method selection includes the technical details and well conditions, availability of electric power and/or gas, equipment footprint and space available, and a budgetary look at capital and operating expenses. The first pass, as such, usually filters out certain methods of AL but does not necessarily produce the final choice. In many situations, once an AL engineer considers the key issues of target flow rate, GLR, well details, availability of gas source or electric power nearby, and budgetary economics, the decision becomes quite clear. **Figure 1-3: Application Range** **Figure 1-4: Efficiency** **Example** High GLR vertical well, moderate depth, and with gas available at surface, immediately lends itself to gas lift. A deep well with high water cut and an inclination of 80 degrees, with electric power available at surface becomes an obvious candidate for ESP lift. Shallow wells with moderate amounts of sand and high viscosity oil may require a top driven PCP’s (a progressive cavity pump that is mechanically driven by a surface motor through rods); while a deeper well with similar characteristics may require a bottom driven (submersible motor) PCP. ###### 2 Rod Pumps Transfer of mechanical energy from surface via rod string to downhole pump. Rod Pumps combine a cylinder (barrel) and piston (plunger) with valves to transfer well fluids into the tubing and lift the fluid to the surface. ###### 3 Progressing Cavity Pump Advantages: - Most widely used AL method - Usually the cheapest - Low intervention cost - Can often pump below perforations Disadvantages: - Restricted flow (~2,000bpd) and depth - Susceptible to free gas - Frequent maintenance - Susceptible to well deviation - Potential wellhead leaks The rotor seals tightly against the rubber stator as it rotates, forming a set of fixed-size cavities in between. The cavities move when the rotor is rotated but their shape or volume does not change. The pumped fluid is moved inside the cavities. ###### 4 Hydraulic Lift – Jet Pumps Advantages: - Simple two piece design - Excellent for viscous oil - Non-pulsating - Efficient power usage - Resistant to abrasives and solids Disadvantages: - Sensitive to overpressure - Restricted flow rate - Restricted depths - Temperature ( < 100 deg.C) - Chemical compatibility H2S & CO2 Transfers energy downhole by pressurizing special power fluid, usually light refined oil, that is pumped through well tubing or annulus to a subsurface pump, which transmits the potential energy to produced fluids. Common pumps are: jets (venturi and orifice nozzles), reciprocating pistons, rotating turbines. ###### 5 Gas Lift Advantages: - No moving parts - Good for deviated wells - Chemicals can be injected with power fluid - Low capital cost per unit production - Heavy and viscous fluids can be produced Disadvantages: - Low system efficiencies (5 to 30%) - High surface maintenance costs if using piston power fluid pumps - Least efficient method - Well testing can be difficult due to power fluid included in the production system Gas Lift uses external high pressure gas supply to supplement formation gas. Produced fluids are lifted by reducing fluid density in tubing to lighten the hydrostatic column, or back pressure, load on formations. ###### 6 Electric Submersible Pumps Advantages: - Fairly low operational cost - Flexibility on production - Replacement of gas lift valves without pulling tubing - High volume lift method - Very good for sand / deviated wells Disadvantages: - Must have a source of gas - High installation costs - Top sides modifications to existing platforms - Compressor installation & maintenance - Limited by available reservoir pressure Electric Submersible Pump (ESP) systems convert energy into hydraulic energy. ESPs add pressure to produced fluids by using a centrifugal pump powered up by a downhole electric motor. Electricity comes from surface using a power cable. Advantages: - High versatility and range of operation - Can work with HT <250 deg. C - Can work with H2S and CO2 - Can work in deep and deviated/horizontal wells Disadvantages: - Higher Cost - Reduced reliability with Abrasives - and free Gas - Several downhole components, which are susceptible to fail - Higher installation time in the rig ##### Electrical Submersible Pump (ESP) ##### - [**Gather the Data and Specifications (ESP) 2-1**](.) - [Gathering the Data for the Application 2-1](.) - [Basic Conversion Formulas 2-5](.) - [Additional Information 2-6](.) - [PVT Data 2-20](.) - [Viscosity 2-30](.) - [Gas, Oil and Water Composition Report 2-34](.) - [Wellbore Characterization 2-38](.) - [Well Directional Survey (TVD, MD, Inclination, Deviation, DLS) 2-39](.) - [Equipment Clearance 2-39](.) - [Equipment Drawing 2-40](.) - [Tubulars 2-40](.) - [Operating Design Requirements and Criteria 2-40](.) - [Environment issues 2-48](.) - [Pump Selection 2-55](.) - [Determine Pump Series 2-56](.) - [Pump Stage Selection 2-56](.) - [Housing Selection 2-57](.) - [Tandem Pumps 2-58](.) - [Pump Configuration 2-58](.) - [Stage Types and Pump Construction 2-61](.) - [Pump Construction 2-64](.) - [Pump Performance and Curves 2-66](.) - [Definitions 2-67](.) - [Pump Operating Range and the Best Efficiency Point (B.E.P.) 2-68](.) - [Gas Separation and Handling 2-70](.) - [Pump Operation in Abrasive Environment 2-74](.) - [Pump Performance De-rating 2-74](.) - [Material Selection 2-77](.) - [Protector Configurations 2-78](.) - [Downthrust for Compression or Fixed Impeller Pumps 2-86](.) - [Seals 2-90](.) - [Oil Selection 2-90](.) - [Elastomers 2-92](.) - [Materials 2-93](.) - [Torque / HP Consumption 2-93](.) - [Tandem Protectors 2-93](.) - [Motor Cooling in ESP systems 2-97](.) - [Size – Motor Series 2-98](.) - [Motor Rating 2-98](.) - [Material 2-99](.) - [Winding Insulation 2-100](.) - [Oil Selection 2-100](.) - [Start-up, Voltage Cable 2-102](.) - [Tandem Application 2-103](.) - [Motor Operation with Variable Speed (VSD) 2-104](.) - [Motor Physical Limitations 2-104](.) - [ProMotors 2-105](.) - [Integrated Motors 2-106](.) - [**Power Cable 2-106**](.) - [Conductors 2-109](.) - [Selecting the Proper Conductor Configuration 2-110](.) - [EPDM 2-112](.) - [PEEK 2-112](.) - [Selecting a Barrier 2-113](.) - [Braid 2-113](.) - [Selecting the Jacket Material 2-114](.) - [Armor 2-114](.) - [Thickness 2-114](.) - [Profile 2-114](.) - [Selecting the Cable Configuration (Flat or Round) 2-115](.) - [Other considerations when selecting ESP cable 2-115](.) - [Ampacity 2-116](.) - [Wellheads 2-119](.) - [Penetrators 2-120](.) - [Shrouds 2-124](.) - [Deviation Analysis in DesignPro 2-127](.) *2* **Electrical Submersible Pump (ESP)** ###### 7 Gather the Data and Specifications (ESP) - [General Information 2-1](.) - [Nomenclature 2-1](.) - [Fluid data 2-18](.) - [Fluid Properties 2-18](.) - [Surface Characterization — Power Issues 2-37](.) - [Well Data 2-38](.) - [Centrifugal Pump Basics 2-55](.) - [Customer Requirements and Data Collection 2-56](.) - [Constraints and Limitations 2-76](.) - [Protector Basics 2-78](.) - [Series and Parallel Connections 2-80](.) - [Protector Configuration Selection 2-80](.) - [Chamber Selection 2-81](.) - [Thrust Bearing Selection 2-86](.) - [Downthrust for Floating Impeller Pumps 2-86](.) - [Shaft HP Capacity 2-89](.) - [Downthrust Handling in ESP Systems with Tandem Protectors 2-93](.) - [Special – High Temperature (HT), H2S, Abrasives, Other Chemicals 2-94](.) - [H2S Scavenger 2-95](.) - [Failure Modes of Protectors and Thrust Bearings 2-95](.) - [Induction Motor Basic Functions 2-96](.) - [Motor Re-rating 2-99](.) - [Volts and Amps 2-99](.) - [Selecting the Appropriate Cable for the Application 2-107](.) - [Selecting the Proper Conductor Size 2-109](.) - [Selecting the Insulation Material 2-111](.) - [PPE (Polypropylene) 2-111](.) - [Selecting the Insulation Thickness 2-112](.) - [Armor Material 2-114](.) - [Special Components 2-115](.) - [Explosive Decompression 2-115](.) - [Available Power Cable and MLE Systems 2-117](.) - [Packers 2-117](.) - [Penetrator suppliers 2-121](.) - [Anodes 2-124](.) - [Solids Production with Shrouds 2-126](.) ####### 7.1 General Information The starting point for a proper application design is gathering all available well data, and identify the well and who collected the data on what date. Use latest test data or request a new one. ######## 7.1.1 Nomenclature The descriptions format and glossary for artificial lift ESP equipment is available through GED-008 that can be accessed in [GeMs](https:\www.gems.slb.com\ematrix\emxLogin.jsp) . [InTouch Content ID 3043579](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3043579) provides components, materials and specifications for electric submersible pumps, gas separators, protectors, motors and motor bases. It includes top-level bills of material and drawings. [InTouch Content ID 4004007](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4004007) provides additional descriptions and definitions for most of the Well Completions, related to Artificial Lift Products and Services and worldwide petroleum industry. This document allows Schlumberger field users to find the meaning of acronyms and abbreviations used in documentation, including catalogs and companies web sites. ######## 7.1.2 Gathering the Data for the Application The basic information needed is detailed in DesignPro data sheet. This form in [Table 2-1:](.) can be used to gather necessary information for the input parameters of the DesignPro ESP application software. **Table 2-1: DesignPro Well Data** | GENERAL DATA | GENERAL DATA | |----------------|----------------| | COMPANY NAME: | | | Address: | | | Address: | | | Country: | | | Date: | | | WELL DATA | WELL DATA | |--------------|---------------| | FIELD NAME: | FIELD NAME: | | ONSHORE WELL | OFFSHORE WELL | | WELL DATA | WELL DATA | WELL DATA | WELL DATA | WELL DATA | |------------------------|--------------------------------|---------------------|------------------------|---------------------| | Well Name: | | Well Name: | Well Name: | | | Location: | | Platform: | Platform: | | | Formation Type: | | Formation Type: | Formation Type: | | | Reservoir Name: | | Reservoir Name: | Reservoir Name: | | | CURRENT WELL STATUS | CURRENT WELL STATUS | CURRENT WELL STATUS | CURRENT WELL STATUS | CURRENT WELL STATUS | | New Well | Redesign | Redesign | Lift Conversion | Lift Conversion | | | Current Pump Data | Current Pump Data | Current Lift Method | Current Lift Method | | YES | Pump Type/Stages: | | Rod Pump: | | | NO | Protector: | | Gas Lift: | | | | Motor Hp/Volts/ Amps: | | Jet Pump: | | | | Cable Type: | | Hydraulic - Piston: | | | | Pressure /Temp Monitor / Type: | | Other - Describe: | | | | By-Pass: | | | | | | Packer: | | | | | Vertical / Directional | Vertical / Directional | | Vertical / Directional | | **Table 2-2: Surface Data** | Surface Data | Surface Data | Surface Data | Surface Data | |--------------------------------------------------------------------|--------------------------------------------------------------------|-----------------------|-----------------------------------------------| | Wellhead Data: (Advise connections and working pressures required) | Wellhead Data: (Advise connections and working pressures required) | Electrical Data: | Electrical Data: | | Casing HeadDetails: | | Primary Power Supply: | Volts Frequency Phase | | Tubing Head Details: | | Power Supply Details: | Total System KVA | | Tubing Hanger Details: | | Power Supply Details: | Power GenerationDistribution Grid or On- Site | | Surface Data | Surface Data | Surface Data | Surface Data | |----------------------|----------------|--------------------------------------|-----------------------------------------| | X-mas Tree Assembly: | | Power Supply (Existing Pump System): | Primary Volts Secondary Volts KVA Hz | | Other Accessories: | | Power SupplyDe- tails: | % Impedence: % Reactance: | **Table 2-3: Casing and Tubing Data** | Casing and Tubing Data (Identify all depths as MD or TVD) | Casing and Tubing Data (Identify all depths as MD or TVD) | Casing and Tubing Data (Identify all depths as MD or TVD) | Casing and Tubing Data (Identify all depths as MD or TVD) | Casing and Tubing Data (Identify all depths as MD or TVD) | Casing and Tubing Data (Identify all depths as MD or TVD) | |-------------------------------------------------------------|-------------------------------------------------------------|-------------------------------------------------------------|-------------------------------------------------------------|-------------------------------------------------------------|-------------------------------------------------------------| | Casing Profile: | inches O.D. | inches O.D. | pounds per foot | Top Bottom | Ft./M Ft./M | | Liner Profile: | inches O.D. | inches O.D. | pounds per foot | Top Bottom | Ft./M Ft./M | | Liner Profile: | inches O.D. | inches O.D. | pounds per foot | Top Bottom | Ft./M Ft./M | | Liner Profile: | inches O.D. | inches O.D. | pounds per foot | Top Bottom | Ft./M Ft./M | | Perforated | From | Ft./M | From Ft./M | From | Ft./M | | Interval(s): | To | Ft./M | To Ft./M | To | Ft./M | | Total Well Depth: | Total Well Depth: | | Ft./M (MD or TVD) | | | | Production Tubing Size: | inches O.D. | inches O.D. | pounds per foot | Top Bottom | Ft./M Ft./M | | Production Tubing Size: | inches O.D. | inches O.D. | pounds per foot | Top Bottom | Ft./M Ft./M | **Table 2-4: Reservoir and Production Data** | RESERVOIR and PRODUCTION DATA | RESERVOIR and PRODUCTION DATA | RESERVOIR and PRODUCTION DATA | RESERVOIR and PRODUCTION DATA | |---------------------------------|---------------------------------|---------------------------------|---------------------------------| | Fluid Properties | Fluid Properties | Production Conditions | Production Conditions | | Initial Reservoir Pressure: | PSIG at ft/min | Static Bottom Hole Pressure: | psi at ft/min | | Bubble Point Pressure: | PSIA | Bottom Hole Flowing Pressure: | psi Flow ft/min | | Reservoir Temperature: | degF / degC | Production or Test Flow Rate: | BFPD | | RESERVOIR and PRODUCTION DATA | RESERVOIR and PRODUCTION DATA | RESERVOIR and PRODUCTION DATA | RESERVOIR and PRODUCTION DATA | |---------------------------------|---------------------------------|---------------------------------|---------------------------------| | Original GOR | SCF/BBL M3/M3: | Productivity Index: | bbl/d/ psi | | Oil API Gravity: | O API | Wellhead Temperature: | degF / degC | | Water Specific Gravity: | | | | | Gas Specific Gravity (Air= 1): | | | | | Water Cut (% Water): | | | | | Impurities: | %CO2 %H2S % N2 | | | | Tubing / Wellhead Pressure: | | | | | Casing Pressure: | | | | | Casing Vented: | Yes / No | | | **Table 2-5: PVT Data** | PVT DATA | PVT DATA | PVT DATA | |---------------------|--------------|------------| | Solution GOR | FVF | PSIG | | Solution GOR | FVF | PSIG | | Solution GOR | FVF | PSIG | | Solution GOR | FVF | PSIG | | Temperature for PVT | degF / deg C | | **Table 2-6: Viscosity Data** | VISCOSITY DATA | VISCOSITY DATA | VISCOSITY DATA | VISCOSITY DATA | VISCOSITY DATA | |-------------------------------|-------------------------------|-------------------------------|-------------------------------|-------------------------------| | Point | Pressure | Temperature | Viscosity | Saturated Gas or Dead Oil | | 1 | | | | | | 2 | | | | | | 3 | | | | | | PROPOSED OPERATING CONDITIONS | PROPOSED OPERATING CONDITIONS | PROPOSED OPERATING CONDITIONS | PROPOSED OPERATING CONDITIONS | PROPOSED OPERATING CONDITIONS | | Desired Production Rates: | Desired Production Rates: | Total Rate - BFPD | Total Rate - BFPD | Total Rate - BFPD | | VISCOSITY DATA | VISCOSITY DATA | |--------------------------------------|-------------------------------------| | | Total Rate - BOPD Total Rate - BWPD | | Desired Pump (Intake) Setting Depth: | Feet / M | | Desired Pump Intake Pressure: | psi | | SPECIAL COMMENTS | SPECIAL COMMENTS | SPECIAL COMMENTS | SPECIAL COMMENTS | |-----------------------------------------------------------------------|-----------------------------------------------------------------------|-----------------------------------------------------------------------|----------------------------------------------------------| | Known Problems | Known Problems | Remarks | Remarks | | Sand Production: | | | | | Scale: | | | | | Paraffin: | | | | | Severe Corrosion: | | | | | Other, such as: | | | | | Drawings and Schematics to be Submitted with Well Data : | Drawings and Schematics to be Submitted with Well Data : | Drawings and Schematics to be Submitted with Well Data : | Drawings and Schematics to be Submitted with Well Data : | | Well Completion Diagram | Well Completion Diagram | Well Completion Diagram | | | Platform or Well Site Layout Diagram | Platform or Well Site Layout Diagram | Platform or Well Site Layout Diagram | | | Electrical Distribution Layout Diagram | Electrical Distribution Layout Diagram | Electrical Distribution Layout Diagram | | | Well Deviation Survey or Schematic (for Deviated / Directional Wells) | Well Deviation Survey or Schematic (for Deviated / Directional Wells) | Well Deviation Survey or Schematic (for Deviated / Directional Wells) | | | Field Layout Diagram | Field Layout Diagram | Field Layout Diagram | | - **Basic Conversion Formulas** Refer below for basic conversion formulas. *galUS/min x 34.3 = bbl/d* *bbl/d /34.3 = galUS/min* *Head Feet x Specific Gravity/2.31 = psi psi x 2.31/Specific Gravity = Head Feet* *Fluid Velocity (ft/s) = galUS/min x .4085 / (ID)2* ######## 7.1.3 Additional Information Refer to ESP failure analyses, amp charts, and workover reports on prior ESP installations from the well of interest or offset wells. Those reports can also provide valuable design clues. If offset well information is included, make certain that the completion reservoir is specified for both the well of interest and the offset wells. As we take on more risk and responsibility with performance-based contracts, it is necessary to have a more holistic understanding of the environment the ESP operation is dependent on. This environment encompasses the reservoir as well as the wellbore. It is also important to understand how conditions vary with time and what level of uncertainty is associated with the data provided by the customer. Hence, on some of the data, the form in this section asks for original, current and future trend in order to capture the time dimension. Finally, the source of the data is also asked in order to establish the degree of uncertainty associated with the data, for instance how and when the data was measured. The following form may serve as a starting place to complement the DesignPro datasheet. It can be modified and enhanced to meet the needs of a specific area. For example, if an emulsion is expected, inquire if there is any laboratory work on it. For some applications, water, crude and gas laboratory analysis may be needed if available. You can also modify the units to those most used in the area where you work. **Operator / Oil Company Field Name** **Reservoir Name (s)** **Well Name** **Artificial Lift Engineer Date** **Well Completion** Completion drawing Attached (yes/no) Well deviation Survey / Schematic (yes/no) Wellhead & Xmas Tree Diagram Attached (yes/no) Previous ESP Pull & Run Report Attached (yes/no) Is an FIV being used and will it be considered on future completions? Packer type & Depth? Sub Surface Safety Valve and depth? Tubing Hanger description & Feedthru profile. | | Top (ft/m) | Bottom (ft/m) | OD | Lbs/ft | |-------------------|--------------|-----------------|------|----------| | Casing | | | | | | Liner | | | | | | Liner | | | | | | Liner | | | | | | Production Tubing | | | | | | Production Tubing | | | | | | Perforated Interval | Perforated Interval | 1 | 2 | 3 | 4 | |------------------------|-----------------------|-----|-----|-----|-----| | Top of Perforations | (ft/m) | | | | | | Bottom of Perforations | (ft/m) | | | | | **Electrical Surface Data** | Primary Power Supply | (Volts) | (hz) | |---------------------------------------------------------------------------|---------------------------------------------------------------------------|------------------------------------------------------| | Existing switchboard / VSD size | Existing switchboard / VSD size | Existing switchboard / VSD size | | Existing Transformer Details Rating (kva) Secondary Voltage Taps (Volts) | Existing Transformer Details Rating (kva) Secondary Voltage Taps (Volts) | Power Supply Details % Impedence (%) % Reactance (%) | **Reservoir Data & Fluid Properties** PVT Data Attached (yes/no) Fracture or Unfractured Formation Type (Sandstone/Carbonate) Consolidated or Unconsolidated | Drive Mechanism (Gas Solution, Gas Cap Expansion, Water Drive or Combination) Primary & Secondary | Drive Mechanism (Gas Solution, Gas Cap Expansion, Water Drive or Combination) Primary & Secondary | Drive Mechanism (Gas Solution, Gas Cap Expansion, Water Drive or Combination) Primary & Secondary | Drive Mechanism (Gas Solution, Gas Cap Expansion, Water Drive or Combination) Primary & Secondary | |-----------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------| | Pressure Support Type (water and/or gas injection) Description (Geometry, volumes, etc…) | Pressure Support Type (water and/or gas injection) Description (Geometry, volumes, etc…) | Pressure Support Type (water and/or gas injection) Description (Geometry, volumes, etc…) | Pressure Support Type (water and/or gas injection) Description (Geometry, volumes, etc…) | | | | | | | | | | Source of Data | | | | Value | Date How was it measured? | | Porosity | (%) | | | | Formation Thickness | (ft/m) | | | | Permeability | (mD) | | | | Bottom Hole Temperature | (deg C) | | | | Solids | (%) | | | | Solution GOR (Rs) @ Pb | (scft/bbl) | | | | Gas Deviation Factor - Z @ Pb | | | | | FVF @ Pb | | | | Page 1 of 2 **Figure 2-1: ESP Data Form** | | | | | | Source of Data | Source of Data | |-------------------------|-------------|----------|---------|--------------|------------------|----------------------| | | | Value | Value | Value | Date | How was it measured? | | | | Original | Current | Future Trend | Date | How was it measured? | | Reservoir Pressure | (psi / bar) | | | | | | | Bubble Point Press (Pb) | (psi) | | | | | | | Water Cut | (%) | | | | | | | Producing GOR | (scft/bbl) | | | | | | | Vertical Referrence Datum Measured Referrence Datum | (ft/m) (ft/m) | | | | | |-------------------------------------------------------|-----------------|----------|-------------|------------|--------------------| | Specific Gravity | Oil Water Gas | | | Impurities | % CO2 % H2S % Sand | | | | | | | | | Viscosity Data | Point | Pressure | Temperature | Viscosity | | | | 1 | | | | | | | 2 | | | | | | | 3 | | | | | **Production, Well Bore & Design Data** | | | Original | Current | Future | |---------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------| | Year | | | | | | Mode of production (free flow or mode of AL) | Mode of production (free flow or mode of AL) | | | | | Stock Tank Production | (bpd or m3/d) | | | | | Water | (bpd or m3/d) | | | | | Oil | (bpd or m3/d) | | | | | Gas | (scft/d or m3/d) | (scft/d or m3/d) | | | | Flowing Bottom Hole Pressure | (psi/bar) | | | | | Calculated Staright Line PI | (bpd/psi or m3/day/bar) | | | | | Pressure Sensor Vertical depth | (ft or m) | | | | | Tubing Head Temperature | (deg C) | | | | | Tubing Head Pressure | (psi/bar) | | | | | Current ESP Design PUMP Type Number of Stages Motor ( HP, Volts, Amps, Frequency) Operating Frequency (Hz) Current Drawn (Amps) | Current ESP Design PUMP Type Number of Stages Motor ( HP, Volts, Amps, Frequency) Operating Frequency (Hz) Current Drawn (Amps) | Current ESP Design PUMP Type Number of Stages Motor ( HP, Volts, Amps, Frequency) Operating Frequency (Hz) Current Drawn (Amps) | Current ESP Design PUMP Type Number of Stages Motor ( HP, Volts, Amps, Frequency) Operating Frequency (Hz) Current Drawn (Amps) | Current ESP Design PUMP Type Number of Stages Motor ( HP, Volts, Amps, Frequency) Operating Frequency (Hz) Current Drawn (Amps) | Why is artificial Lift Being considered (accelrated production, improved recovery, other…)? Is there a limit on the drawdown to be applied to the reservoir and why? Is water coning expected? How was the well perforated? Is the well killed during workovers and how? SG & type of kill fluid utilised? Page 2 of 2 **Figure 2-2: ESP Data Form** The following document is an example of an ESP Project Planning Guide which serves as a step-by- step worksheet that prompts the users for critical information in planning a project. This information includes QHSE considerations, IPR and design considerations, reservoir data, PVT information, wellbore and completion details, equipment and material selection, power and operational control requirements, installation and pull considerations, as well as start up and operational guideline considerations. **ESP Project Planning Guide** **Company Name:** **Field Name:** **Type of Project:** **Project Number:** **Scope of Project Work:** **Table 2-7: Project Planning Initial Steps** **Contacts and Team Members Step Action** - Collect and compile a list of contacts / phone and fax numbers and e-mail addresses. Ensure that this information is in an attached spreadsheet. - The attached spreadsheet should have captured all of the above – mentioned information for all oil company, SLB and third party personnel involved in this project **Table 2-8: Administrative** | Project Number | Purchase Order Number | |---------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------| | | | | Contract Number | AFE Number | | | | | Type of Contract: | Type of Contract: | | Have all of the technical specifications and requirements been submitted to the team? | Have all of the technical specifications and requirements been submitted to the team? | **Table 2-9: QHSE Considerations** | Does a risk and hazard assessment need to be done for this project? | |------------------------------------------------------------------------------| | How will the risk and hazards with this project be managed? | | What safety precautions and procedures will be required? | | What type or types of safety training will be required? | | What will be required for safety equipment? | | What environmental precautions and procedures are required for this project? | | What communication methods exist at the field location? | | Does a risk and hazard assessment need to be done for this project? | |------------------------------------------------------------------------------------| | Ensure that all of the safety codes and laws are clearly understood for this area. | | Ensure that all pre-job, job and tailgate safety meetings are documented. | | Ensure that all safety permits are obtained prior to the start of the job. | **Table 2-10: Important Project Dates** | Date that equipment order was placed: | |--------------------------------------------------| | Completion date for manufacture of equipment: | | Equipment testing and certification dates: | | Required equipment shipping dates: | | What date must the equipment arrive at location? | | Equipment installation dates: | | Commissioning and start up dates: | **Table 2-11: IPR and Design Considerations** | What is the production strategy for the well and field? | |------------------------------------------------------------| | If applicable what is the present form of Artificial Lift? | **Table 2-12: Present Production Data** | Average Gross Production Rate: | Oil Rate: | |-------------------------------------------|-------------------------------------------| | Water Rate: | Gas Rate: | | Water Cut: | GOR: | | Tubing Pressure: | Casing Pressure: | | Tubing Size: | Casing Size: | | Present pump setting depth if applicable: | Present pump setting depth if applicable: | **Table 2-13: Pressure and Fluid Level Data** | Static Reservoir Pressure: | Static Level: | |-------------------------------|------------------------| | Flowing Bottom hole pressure: | Producing Fluid Level: | | Pump Intake Pressure: | Fluid Gradients: | | Q-MAX of well: | Productivity Index: | **Note** Do you have enough information to generate a believable IPR? **Table 2-14: Desired Production Rate (STB/BD)** | Gross Production Rate: | Oil Rate: | |--------------------------|--------------------------| | Water Rate: | Gas Rate: | | Pump Intake Pressure: | % of free gas at intake: | | Tubing Pressure: | Casing Pressure: | | Miscellaneous: | | **Table 2-15: Reservoir Data and PVT Information** | Producing Formation type and name: | | |--------------------------------------------------------------------------------|--------------------------------------------------------------------------------| | Is the field located on shore or offshore? | Is the field located on shore or offshore? | | What is the reservoir management strategy for the field? | What is the reservoir management strategy for the field? | | Is the field on primary production or does one or more of the following apply? | Is the field on primary production or does one or more of the following apply? | | Water Flood: | Miscible Flood: | | Steam Flood: | Fire Flood: | | Formation Porosity: | Formation Permeability: | |-----------------------------------------------------|-----------------------------------------------------| | API Oil Gravity: | Specific Gravity Water: | | Specific Gravity Gas: | Bubble Point Pressure: | | Static Reservoir Pressure: | Static Reservoir Temperature: | | Flowing Bottom Hole Pressure: | Flowing Bottom Hole Pressure: | | Formation Volume Factors Oil: Gas: Water: | Formation Volume Factors Oil: Gas: Water: | | Oil Viscosity at Reservoir Temperature: | Oil Viscosity at Reservoir Temperature: | | H2S Content: | CO2 Content: | | Water Salinity: | Other: | | Does the well have any of the following conditions? | Does the well have any of the following conditions? | | Scale: | Asphaltenes: | | Wax or Paraffin: | Sand Production: | | Other: | | | Does the well have a “NORM” problem? | Does the well have a “NORM” problem? | **Table 2-16: Design Considerations** | How will the free gas be handled? | |------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Does the C02 / Salinity and H2S warrant the use of special materials or coatings? | | Is the well fluid or gas corrosive? | | If applicable how will the sand, scale, wax, or asphaltene problems be handled? | | Does this application warrant the use of high temperature materials? | | If the viscosity is high what steps will be taken in the application design? | | What chemical maybe pumped down hole and how will they effect the ESP system? | | Will a Y-Tool or motor shroud be required? | | Has the well file been reviewed? | | Has a wellbore diagram been obtained? | | If the well is deviated do you have a copy of the survey? | | Can the production facilities accommodate the ESP production or will gas and water handling constraints be an issue? | | What type and amount of chemicals will be pumped down the well? What type of work over or completion fluid will be used? Are the chemicals and work over fluid types compatible with elastomers and cable that will be used? | | Will sub surface valves be required? | | Does the wellbore have a casing patch or another problem that could hamper the installation of a ESP? | **Note** Please state the type of design program used to complete the design and analysis for this application and attach a copy of the completed work. **Table 2-17: Wellbore and Completion Details** | Completion Type: Completion Date: | |----------------------------------------------------------------| | Producing Formations: | | TVD and MD of producing formations: | | Plug back depth: | | Top of Perforations: MPP: | | Perforated Intervals: | | Size of perforation charges / number shots per foot / phasing: | | Was the well directionally drilled or is it a horizontal well? | | Completion Type: Completion Date: | |------------------------------------------------------------------------------| | If applicable ensure that a deviation survey has been obtained and reviewed. | | Remarks: | **Table 2-18: Casing String Details** | Surface casing type: | ID and OD size / Weight: | |---------------------------|----------------------------| | Casing Top: | Casing Bottom: | | Intermediate casing type: | ID and OD size / Weight: | | Casing Top: | Casing Bottom: | | Production casing type: | ID and OD size / Weight: | | Casing Top: | Casing Bottom: | | Liner-size: | ID and OD size / Weight: | | Liner Top: | Liner Bottom: | | Age of casing: | Age of casing: | **Table 2-19: Tubing String Details** | Tubing Type: | Tubing Size: | |--------------------------------|--------------------------------| | Tubing ID and OD: | Tubing Weight: | | Age of tubing string: Remarks: | Age of tubing string: Remarks: | **Table 2-20: Equipment and Material Selection** | Pump Type: | Pump Type: | |-------------------------------------------------------|-------------------------------------------------------| | Stage material required: | Shaft Material: | | Housing material required: | Housing Burst Pressure: | | Bearing material: | Bushing material: | | Does the application require coated pump stages? | Does the application require coated pump stages? | | Do the pump stages require dynamic balancing? | Do the pump stages require dynamic balancing? | | What size – a thread type-tubing adapter is required? | What size – a thread type-tubing adapter is required? | | Remarks: | Remarks: | | Intakes and Gas Separators: | Intakes and Gas Separators: | |---------------------------------------------------|-------------------------------| | Materials selected: | Bearing Type: | | Does the intake or gas separator require coating: | Other: | | Remarks: | | | Protector Type: | Protector Type: | |------------------------------------------|-------------------| | Elastomer and O-ring material selection: | | | Shaft Type: | Bearing Type: | | Remarks: | | | Motor Type and Series: | Motor Type and Series: | |---------------------------------------------------|--------------------------| | Housing material: | Bearing Type: | | Shaft Type: | Oil Type: | | What is the motor OD to casing clearance? | | | What is the cooling velocity rate past the motor? | | | Remarks: | | | Pressure Sensor Type: | |----------------------------------------| | Sensor housing material: | | Sensor Pressure and Temperature range: | | Remarks: | | Motor Flat Extension: | Motor Flat Extension: | Motor Flat Extension: | |-------------------------|-------------------------|-------------------------| | MLE Type: | Size: | Length: | | Remarks: | Remarks: | Remarks: | | Power Cable: | |--------------------------------------------------------------------------| | Cable Type: | | Cable Size and Length: | | Remarks: | | What is the clearance between the casing wall and cable / tubing collar? | | How will the cable be attached to the tubing? Provide details. | | Remarks: | | Electrical Connector Systems: | |-------------------------------------------------------------------------------------------------------| | Provide details on type / size / classification of the electrical connector system that will be used. | | Miscellaneous: | |-------------------------------------------------------------------------| | Ensure that a equipment deflection analysis is completed and reviewed. | | Ensure that a equipment dimensional analysis is completed and reviewed. | | Will the equipment string require Monel coating? | | If required what is the nominal thickness of the coating? | | Do you require a tungsten carbide overlay to protect the monel coating? | | What type of bolts will be used size and type? | | Remarks: | **Table 2-21: Electrical Power Supply and Operational Control Requirements** | Considerations: | Considerations: | Considerations: | |-----------------------------------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------| | Has an electrical load study been completed to ensure an adequate supply of clean stable power? Provide details and report. | Has an electrical load study been completed to ensure an adequate supply of clean stable power? Provide details and report. | Has an electrical load study been completed to ensure an adequate supply of clean stable power? Provide details and report. | | Has a fuse and protection coordination study been performed? | Has a fuse and protection coordination study been performed? | Has a fuse and protection coordination study been performed? | | What electrical codes and area classifications need to be adhered to? | What electrical codes and area classifications need to be adhered to? | What electrical codes and area classifications need to be adhered to? | | If a generator or turbine is used to power attach details if utilized. | If a generator or turbine is used to power attach details if utilized. | If a generator or turbine is used to power attach details if utilized. | | Is the power supplied by a utility? | Is the power supplied by a utility? | Is the power supplied by a utility? | | Primary Supply Voltage: | Secondary Voltage: | Cycles: | | Remarks: | Remarks: | Remarks: | | Transformers: | Transformers: | |------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------| | Required KVA: | Primary Voltage: | | Secondary Voltage: | Manufacturer: | | Will a VSD rated transformer be required? | Will a VSD rated transformer be required? | | Will a phase shifting transformer be required? | Will a phase shifting transformer be required? | | Will step down and or will step up transformers be required? | Will step down and or will step up transformers be required? | | If using existing transformers on location provide details on size / type and condition. | If using existing transformers on location provide details on size / type and condition. | | Remarks: | Remarks: | | Switchboards and Motor Controllers: | |-----------------------------------------------------------------------------------------------------| | Size and type of switchboards with options required. | | Type and options for motor controller: | | Provide details and condition of any equipment that is on location that maybe used in this project. | | Variable Speed Drives: | |----------------------------------------------------------------------------------------------------| | Size and type of VSD required: | | Provide details and conditions of any equipment at this location that maybe used for this project: | | Remarks: | | TVSS / Harmonic and Load Filters / Power Factor Correction Capacitors | |---------------------------------------------------------------------------------------------------------| | Size and type of TVSS equipment to be used. | | If Harmonic or Load Filters are required for this project. Provide Details. | | Will Power Factor correction capacitors be required? Provide Details. | | Provide details and condition of any existing equipment on location that could be used on this project. | | SCADA and Wellhead Instrumentation: | |------------------------------------------------------------------------| | Provide details of the SCADA system to be used and provide information | | List and provide details of instrumentation to be used: | | Miscellaneous: | |---------------------------------------------------------------------------------------------| | How will the electrical equipment be grounded? | | Is the wellhead and associated piping under cathodic protection? | | List details of junction boxes to be used. | | Provide details of surface cable used to connect power to transformers and related devices. | | Remarks: | **Table 2-22: Equipment Testing and Shipping Details** | Testing: | |----------------------------------------------------------------------------------------| | Has all of the equipment been tested / certified and documented? | | Has all of the equipment met or exceeded the Technical and Engineering specifications? | | Testing: | |------------------------------------------------------------------------------------------------------| | Is the customer or their designate satisfied with all tests and have they approved their acceptance? | | Remarks: | | Shipping Details: | |----------------------------------------------------------------------------------------------| | Has all of the equipment been properly prepared and secured for shipment? | | How will the equipment ship? | | Have all of the proper shipping, insurance and export documents been obtained? | | Is a secure staging area required to store equipment prior to the shipment to the well site? | | Will there be proper lifting equipment available such as cranes or forklifts? | | Have equipment-handling procedures been provided and are they understood? | **Table 2-23: Equipment Installation and Pulling Considerations** | Have detailed pull and run procedures been developed? | |-----------------------------------------------------------------------------------------------------| | Has a site risk and hazard assessment been conducted? | | Review equipment – handling procedures with rig crews. | | Have all cable sheaves and safety slings been checked for soundness? | | Has a procedure been developed and reviewed with rig crews in case of a “run away” cable situation? | | Do SLB personnel know what to do in the event of a loss of well control? | |--------------------------------------------------------------------------------------------------------------| | Ensure clear sight lines between cable spooler and driller? | | Stress importance of keeping the cable out of harm’s way. | | Has a required field service list of materials and consumable been developed for the project? | | Have the equipment installation and pulling speeds been reviewed with the rig crews and are they understood? | | Remarks: | **Table 2-24: Start Up and Operational Guideline Considerations** | Develop clear and concise start up and operating procedures. | |--------------------------------------------------------------------------------------------| | Develop clear and concise monitoring process and trouble shooting procedures. | | Develop a training procedure for personnel. | | Have all personnel involved in operating and maintaining the equipment been fully trained? | | Develop clear and concise start up and operating procedures. | |---------------------------------------------------------------------------------------| | Ensure critical spares are available at the location or close proximity to the field. | | Try to have SLB personnel conduct timely performance follow-ups. | | Obtain information on the performance of the equipment on a regular basis. | | Other: | ####### 7.2 Fluid data ######## 7.2.1 Fluid Properties In order to define the environment in which the pump will operate, properties of the produced fluid need to be determined. A basic classification of reservoir fluids based on production and PVT data is listed below (and can also be accessed via [InTouch Content ID 3942289](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3942289) ). **Table 2-25: PVT Data** | Reservoir Fluid | Surface Appear- ance | GOR Range | Gas Spe- cific Gravi- ty | API Grav- ity | Typical Composition, Mole % | Typical Composition, Mole % | Typical Composition, Mole % | Typical Composition, Mole % | Typical Composition, Mole % | Typical Composition, Mole % | |----------------------------------|------------------------------------------------------------------|---------------------------------------|----------------------------|-------------------|-------------------------------|-------------------------------|-------------------------------|-------------------------------|-------------------------------|-------------------------------| | Reservoir Fluid | Surface Appear- ance | GOR Range | Gas Spe- cific Gravi- ty | API Grav- ity | C1 | C2 | C3 | C4 | C5 | C6 | | Dry Gas | Colorless gas | Essentially no liquids | 0.60 - 0.65 | | 96 | 2.7 | 0.- 3 | 0.- 5 | 0.1 | 0.4 | | Wet Gas | Colorless gas with small amount of clear or straw colored liquid | Greater than 100MSCF/ bbl | 0.65 - 0.85 | 60o - 70o | | | | | | | | Condensa- tion | Colorless gas with significant amounts of light colored liquid | 3 to 100MSCF/ bbl (900 - 18000 m3/m3) | 0.65 - 0.85 | 50o - 70o | 87 | 4.4 | 2.- 3 | 1.- 7 | 0.8 | 3.8 | | “Volatile” or high shrinkage oil | Brown liquid with various yellow, red, or green hues | About 3000 SCF/ bbl (500 m3/m3) | 0.65 - 0.85 | 40o - 50o | 64 | 7.5 | 4.- 7 | 4.- 1 | 3.0 | 16- .7 | | “Black” or low shrinkage oil | Dark brown to black viscous liquid | 100 - 2500 SCF/ bbl (20 - 450 m3/m3) | | 30o - 40o | 49 | 2.8 | 1.- 9 | 1.- 6 | 1.2 | 43- .5 | |--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Heavy Oil | black, very viscous liquid | Essentially no gas in solution | | 10o - 25o | 20 | 3.0 | 2.- 0 | 2.- 0 | 2.0 | 71 | | Tar | Black Substance | Viscosity >10,000 cp | | <10o | - | - | - | - | - | 90 + | | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | There are no definite boundaries for these classifications and usage may vary depending on location. Gravities and GOR are also depended on separation conditions. | The typical properties used to size an ESP application include: - Oil Gravity - Gas Specific Gravity - Water Specific Gravity - Water Salinity - Water Cut - Solution GOR - Bubble Point Pressure - Production GLR - Production GOR - Gas Chemical Content: - N2 - CO2 - H2S - H2 - CO - Gas Corrosive Potential - Reservoir Temperature - Oil FVF - Paraffin Content - Sand - Fluid Viscosity - Fluid Emulsion Tendency - Water Chemical Content - Water Corrosion Potential - Water Scale-forming Tendency. The specific gravity of the produced fluids has a direct impact on the horsepower required to turn a given size pump. Although, relatively few applications encounter fluid viscosities high enough to influence pump performance, it is important to be aware that flowrate, head, and horsepower correction factors may be required. In wells with a water cut of 50% or higher, the fluid may not require viscosity correction factors (except when emulsions are present). A fluid can exist in vapor, liquid or solid phase depending on the conditions it is subjected. A phase is defined as a homogenous system having proprietary physical properties throughout a given phase and can be recognized by its distinct boundaries. A change in pressure and temperature may cause a phase change. The PVT data is required when gas is present. Determination of fluid properties may be improved in two ways: - using measured PVT lab data - measured values of oil viscosity. Heavy crudes, emulsion formation and slugging can have a significant impact on head, horsepower, torque, start up and surface requirements. [InTouch Content ID 2039625](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2039625) , [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4412053) [4412053](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4412053) is a study which describes in details relevant field experience and observations for numerous operators. It also discusses design considerations and operational procedures with a view to needed developments in fluid heating and correction factors for modeling. The study shows the results of an optimization project. A summary of some findings includes: - Water continuous behavior can occur between 25% and 50% water cut. In general, above 40% BSW viscosity is close to that of water. - Viscosities can be up to four times that one of oil alone. - Heat Generation Lowers Viscosity. - Cold well startup can have high current draw. Need to adequately size surface equipment. - Motor derating required for low heat dissipation with high oil cut. - Operating instrumentation is critical. ######## 7.2.2 PVT Data Petroleum is a complex mixture of hydrocarbons, which varies from very small molecules to very big ones. The small ones like methane and ethane are actually gases at surface conditions but can be dissolved in the fluid under downhole conditions. Since the gas is such light weight, the impeller cannot impart much centrifugal force to it so the pump does not develop as much head with the lighter weight total fluid. It is important to predict free gas for a proper application design. If we take a reservoir fluid, which is initially all liquid and lower the pressure, the smaller components such as methane can be released and form a gas. The pressure at which gas bubbles begin to form is called the . Refer to [Figure 2-3](.) . **Figure 2-3: Phase Diagram** One thing we can see immediately is that if we want to produce 1.00 bbl of oil at the surface, we will need to produce more than this downhole. This means that we would have to size a somewhat larger pump than we would expect for water. Another thing which we can see is that the free gas can be, depending on temperature and pressure, very much larger in volume than the original oil being produced. Since we cannot easily produce free gas, we are very interested in knowing what this volume is. The availability of PVT data helps to model the fluid properties more accurately. Fluid from the reservoir is identified using pressure, volume and temperature (PVT) values. PVT data is derived from samples that are taken either at the surface or downhole using sampling techniques and equipment. PVT values are obtained from the lab analysis of these samples. A sizing software allows to input PVT data for a specific temperature and calculates the required PVT data using correlations. A correlation is based on a large sampling of crude oils with varying Gas/Oil ratios, gravities, etc. The result is a mathematical expression or a graph, which allows us to estimate properties we are interested in based on those we know. One example of this is a correlation to predict the bubble point. Several different correlations are available and no single one is always best to use. Selecting the best correlation can vary by geographic area or even type of oil. An example of such a correlation was provided by Standing that can be seen in [Figure 2-4](.) . **Figure 2-4: Standing's Correlation** **Equation 2-1:** *The following equation is simply a mathematical relation, which will yield the same results as the previous graph.* **Equation 2-2:** *Equation to calculate the solution gas if we know the bubble point.* **RSB :** solution gas at the bubble point - GOR **Pb:** bubble point pressure - psi **T:** temperature in Fahrenheit **API:** stock tank oil gravity in API **Υg:** gas specific gravity (Air = 1.0) **Tip** Different correlations will be valid over slightly different ranges. The reservoir characteristics can change dramatically over time and, if we use data taken today, it might not be representative of the reservoir oil initially produced. **Example** For example, every oil will have some bubble point and this value will not usually change very much over time. The produced Gas/Oil ratio, on the other hand, can change dramatically over time. We can view this graphically. The produced GOR will remain at the initial value for some amount of time and then begin to rise quickly as the reservoir producing pressure falls below the bubble point. Some maximum value will be reached and the GOR will decline and eventually settle at some value well below the initial level. This behavior is due to the fact that the gas will flow more easily than the oil within the reservoir so the gas and oil are not being produced together. The gas bypasses the oil leaving the depleted oil within the reservoir to be produced more slowly. This oil will also have a different composition than the initial oil. **Figure 2-5:** If we use the GOR to calculate the bubble point, depending on where we are in the producing life of the reservoir, we can get very large differences in calculated bubble point. **Figure 2-6:** In addition to the bubble point, we also need to know the formation volume factor (FVF). This is because oil will occupy more volume downhole than at the surface. The reason is that the oil will have gas dissolved in it and will also be at a higher temperature, which causes thermal expansion. We should consider the FVF when sizing pumps because we may need a unit to produce a much larger volume downhole to get our required volume to the surface. Failing to consider the FVF can often lead to "undersizing" a pump and can even affect the operating thrust characteristics. If we use a correlation above the bubble point, we would predict the FVF according to the dashed line but what we will really see is that the FVF will decrease slightly. This is because we have no more gas to dissolve in the oil yet the oil is slightly compressible. **Figure 2-7:** Because of this, we need to calculate the oil "compressibility factor" above the bubble point. Once again, we have an equation to estimate this. This correlation calculates the FVF above the bubble point based on the FVF at the bubble point. We usually treat water as "incompressible" and, relative to oil, it may appear to be. But water will expand as temperature increases. In addition to this, water will dissolve some of the gas. We know that a certain amount of gas will dissolve in water because, if it did not, all the fish would die. Normally, volume changes for a gas are calculated from the "Ideal Gas law". An "Ideal Gas" is simply one that obeys the law. Having said that, the law is: *PV = nRT* **:** where, **P:** pressure **V:** volume **n:** amount of gas **R:** a conversion constant **T:** absolute temperature The only problem with the ideal gas law is that there really is no such thing as an ideal gas. On the other hand the law is really convenient to use. Rather than throw it away, we can simply apply a correction factor ( *Z* factor) to make the law work. The *Z* factor changes with the type of gas as well as with pressure and temperature for a particular gas. Also "impurities" such as CO2 and H2S will affect the *Z* factor as well. **Equation 2-1:** **Z:** compressibility factor [InTouch Content ID 3853604](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3853604) provides a comprehensive explanation of PVT properties including some formulas and gives some examples to illustrate how these properties are calculated. The following tables provide a compilation of some correlations available to facilitate making the choices for PVT correlations. **Physical Properties** **Table 2-26: Dead Oil Viscosity** | Correlation | Development Ranges or Parameters | Data Origin | |---------------------------|-----------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------| | Beal (1946) | T ≤100 degF | 753 data values | | Beggs and Robinson (1975) | | 460 data values | | Glaso (1980) | 50 degF ≤ T ≤ 300 degF | 26 crude oil samples | | Kartoatmodjo (1990) | 14.4 ≤ API ≤ 59 24.7 ≤ P (psi) ≤ 7170.7 80 degF ≤ T ≤ 320 degF F0 ≤ Rs (SCF/STB) ≤ 2890 | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | **Table 2-27: Saturated Viscosity** | Correlation | Development Ranges or Parameters | Data Origin | |---------------------------|-------------------------------------------------------------------------------------------------|------------------| | Chew and Connally (1959) | 72 degF ≤ T ≤ 292 degF 132 ≤ P (psi) ≤ 5645 51 ≤ Rs (SCF/STB) ≤ 3544 .377 ≤ Dead Oil (ucp) ≤ 50 | 457 data values | | Beggs and Robinson (1975) | 16 ≤ API ≤ 58 | 2073 data values | | Correlation | Development Ranges or Parameters | Data Origin | |---------------------|----------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------| | | 132 ≤ P (psi) ≤ 5265 70 degF ≤ T ≤295 degF 20 ≤ Rs (SCF/STB) ≤ 2070 | | | Khan (1987) | 14.3 ≤ API ≤ 44.6 100 ≤ P (psi) ≤ 4315 75 degF ≤T ≤ 240 degF 24 ≤ Rs (SCF/STB) ≤ 1901 | Saudi Arabian crude oils: 75 bottomhole samples; 62 fields | | Kartoatmodjo (1990) | 14.4 ≤ API ≤ 59 24.7 ≤ P (psi) ≤ 7170.7 80 degF ≤ T ≤ 320 degF 0 ≤ Rs (SCF/STB) ≤ 2890 | 5321 data points sources: Indonesia; North America including offshore, Middle East, Latin America | **Table 2-28: Undersaturated Viscosity** | Correlation | Development of Ranges or Parameters | Data Origin | |--------------------------|------------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------| | Beal (1946) | | 26 crude oil samples | | Vasquez and Beggs (1976) | 15.3 ≤ API ≤ 59.5 141 ≤ P (psi) ≤ 9515 9.3 ≤ Rs (SCF/STB) ≤ 2199 .117 ≤ (ucp) ≤ 148 .511 ≤ g ≤ 1.351 | 3593 data values | | Khan (1987) | | 1503 data points: Saudi Arabian crude | | Kartoatmodjo (1990) | 14.4 ≤ API ≤ 59 24.7 ≤ P (psi) ≤ 6014.7 75 degF ≤ T ≤ 320 degF 0 ≤ Rs (SCF/STB) ≤ 2890 | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | **Table 2-29: Gas Viscosity** | Correlation | Development of Ranges or Parameters | Data Origin | |----------------|----------------------------------------------------------------------------------------|----------------| | Carr (1954) | Pressure corrections; temperature corrections for 40 to 400 degF; sour gas corrections | | | Lee (1966) | Sour gases taken into account through the gas density term | | **Table 2-30: Water Viscosity** | Correlation | Development of Ranges or Parameters | Data Origin | |----------------------|------------------------------------------------------------|----------------| | Matthews and Russell | Accounts for effects of pressure, salinity and temperature | | | Brill and Beggs | Considers only temperature effects | | **Table 2-31: Oil Density** | Correlation | Development of Ranges or Parameters | Data Origin | |-----------------|-------------------------------------------------------------------------------------------------------|----------------| | Katz (1942) | For standard conditions must be corrected for specific temperature and pressure. | | | Standing (1981) | Function of Temperature, Rs, g g, and g o for specified temperature and pressure; corrects the others | | | Ahmed (1985) | For standard conditions must be corrected for specific temperature and pressure | | **Table 2-32: Oil Compressibility** | Correlation | Development of Ranges or Parameters | Data Origin | |----------------------|---------------------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------| | Vasquez-Beggs (1980) | Linear regression model | 4036 experimental data points | | Ahmed (1985) | Non-linear regression model | 245 experimental data points | | Kartoatmodjo (1990) | 14.4 ≤ API ≤ 59 24.7 ≤ P (psi) ≤ 6014.7 75 degF ≤ T ≤ 320 degF 0 ≤ Rs (SCF/STB) ≤ 2890 .4824 ≤ Υ gsep ≤ 1.668 | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | **Table 2-33: Oil Formation Volume Factor** | Correlation | Development of Ranges or Parameters | Data Origin | |--------------------------|---------------------------------------|----------------------------------------| | Standing (1947) | | 105 data points 22 California systems | | Vasquez and Beggs (1980) | | 6000 measurements at various pressures | | Glaso (1980) | | 45 oil samples from North Sea | | Correlation | Development of Ranges or Parameters | Data Origin | |---------------------|----------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------| | Marhoun (1988) | | 160 data points from 69 Middle East oil reserves | | Arps (1962) | Quick approximation; use other correlations if available | | | Ahmed (1988) | | Used Marhoun and Glaso data | | Kartoatmodjo (1990) | 14.4 ≤ API ≤ 59 | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | | | 14.7 ≤ P (psi) ≤ 6054.7 | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | | | 75 degF ≤ T ≤ 320 degF | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | | | 0 ≤ Rs (SCF/STB) ≤ 2890 | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | | | .4824 Υ gsep ≤ 1.668 | 3588 data points collected from 661 samples: sources Indonesia; North America including offshore; Middle East; Latin America | **Table 2-34: Z Factor** | Correlation | Development of Ranges or Parameters | Data Origin | |---------------------------|-----------------------------------------------------------------------|-------------------------------------------------------------| | Hall and Yarborogh (1973) | Method not recommended is pseudo reduced temperature is less than one | Equation form of Standing and Katz graph – iterative | | Brill and Beggs | Not recommended if you have H2S or CO2 | Simplified equations for Standing-Katz graph (not rigorous) | **Table 2-35: Solution Gas Oil Ratio** | Correlation | Development of Ranges or Parameters | Data Origin | |--------------------------|------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------| | Standing (1947) | | 105 data points 22 California systems | | Lasater (1958) | Best when API > 15 | 158 measured bubble points from 137 systems | | Vasquez and Beggs (1980) | | 5008 data points | | Marhoun (1988) | | 160 data points from Middle East crude | | Glaso (1980) | Accuracy best for less than 1400 SCF/STB | 45 North Sea oil samples | | Kartoatmodjo (1990) | 14.4 ≤ API ≤ 59 | 5392 data points collected from 740 crude oil samples: Indonesia, North America including offshore, Middle East, Latin America | | | 14.7 ≤ P (psi) ≤ 6054.7 | 5392 data points collected from 740 crude oil samples: Indonesia, North America including offshore, Middle East, Latin America | | | 75 degF ≤ T≤ 320 degF | 5392 data points collected from 740 crude oil samples: Indonesia, North America including offshore, Middle East, Latin America | | | 1.007 ≤ Bo ≤ 2.144 | 5392 data points collected from 740 crude oil samples: Indonesia, North America including offshore, Middle East, Latin America | | | .4824 ≤ Υ gsep ≤ 1.668 | 5392 data points collected from 740 crude oil samples: Indonesia, North America including offshore, Middle East, Latin America | **Table 2-36: Bubble Point** | Correlation | Development of Ranges or Parameters | Data Origin | |--------------------------|----------------------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------| | Standing (1947) | 16.5 ≤ API ≤ 63.8 130 ≤ Pb (psi) ≤ 7000 100 degF ≤T (res) ≤ 258 degF F20 ≤ Rs (SCF/STB) ≤ 1425 .59 ≤ Υ g ≤ .95 | 105 bubble point pressures: 22 California Systems; no corrections for non-hydrocarbon components | | Lasater (1958) | 17.9 ≤ API ≤ 51.1 48 ≤ Pb (psi) ≤ 5780 82 degF ≤ T (res) ≤ 272 degF 3 ≤ Rs (SCF/STB) ≤ 2905 .574 ≤ Υ g ≤ 1.223 | 158 samples: Canada, Western and Mid-continent U.S., and South America; no corrections for non-hydrocarbon components | | Glaso (1980) | Corrections for N2, CO2, and H2S | 45 North Sea samples | | Vasquez and Beggs (1980) | 16 ≤ API ≤ 58 50 ≤ Pb (psi) ≤ 5250 70 degF ≤ T (res) ≤ 295 degF 20 ≤ Rs (SCF/STB) ≤2070 .56 ≤ Υ g ≤ 1.18 | 5008 data points from 600 oil systems | | Kartoatmodjo (1990) | 14.4 ≤ API ≤ 59 14.7 ≤ P (psi) ≤6054.7 75 degF ≤ T ≤ 320 degF 0 ≤ Rs (SCF/STB) ≤ 2890 .4824 ≤ Υ gsep ≤ 1.668 | 5392 data points from 740 samples: Indonesia, North America including offshore, Middle East and Latin America | | Marhoun (1988) | | 160 data points Middle East crude | ######## 7.2.3 Viscosity Another PVT property, which is of interest to us is viscosity. We will treat it in detail in this section due to the importance of correct prediction of the fluid viscous behavior. Viscosity is a measure of the amount of energy it takes to shear the fluid. With higher viscosity it takes more energy to shear the fluid so we will usually have a higher pressure drop. When we calculate the density, we use a weighted average of the fluid as: where, **Term Definition** **ƒw** is the water fraction **SGw** is the water specific gravity **ƒo** is the oil fraction **SGo** is the oil specific gravity. However, viscosity cannot be determined in the same way. Viscosity generates shear stresses. These stresses generate a friction loss, which is not a "bulk" fluid property but it is a surface phenomenon. The following are two extreme cases (oil in black and water in white). At high oil fractions, the pipe will be "oil wet" so friction will be due to oil only. At high water fraction, this reverses itself and the friction will be due to water only since the pipe is now "water wet". The apparent viscosity will remain that for oil up to a certain point and then the pipe will become water-wet and the apparent viscosity will be that for water. The water cut where this change occurs is called the "inversion point" and this will vary for different oil/water types but will usually fall somewhere in the range of 40% to 75% water. There is no good way to predict it and should actually be measured for a particular reservoir. Once the "dead oil" viscosity is determined, it can be adjusted to the "live oil" viscosity using any of a number of correlations. The Beggs and Robinson correlation for predicting oil viscosity below the bubble point pressure begins by calculating the dead oil viscosity and then using the Correlation for Live Oil viscosity. We should note that gas dissolved in the oil will reduce the viscosity significantly. In fact this is used specifically in CO2 floods. CO2 dissolved in the oil can reduce the viscosity by an order of magnitude or more. In addition to the oil viscosity, we need to know the viscosity of the water. Water viscosity will be affected somewhat by gas and temperature and can also be affected by impurities and dissolved solids. Normally we do not worry about gas viscosity but with multiphase flow correlations this is very important in estimating "slippage". Slippage is a term used to account for the tendency for gas to want to proceed up the tubing faster than the oil or water. This can be thought of as gas "slipping" past the liquid. The viscosity could be treated as oil only up to the inversion point and then we should use water viscosity for calculations. However, in some instances, certain oils and at certain water fractions for those oils, the viscosity can be very much greater than we would expect. This is due to a tendency for some fluids to form an "emulsion". An emulsion has a much greater viscosity than any of the individual components. Emulsion degrades pump performance. Every emulsion is unique, so there is no easy solution to dealing with them. Unfortunately emulsions are hard to predict and the viscosity can vary so much that we are better off simply measuring the viscosity for the actual produced fluid with lab tests. Emulsions are important because they may make it impossible to produce a well if the viscosity is high enough. Viscosity of the water-oil emulsion mixture is not easy to predict since it varies from case to case. The tendency reported from Woelflin's experience in 1942 is for the viscosity of the water in oil emulsion to increase as the water cut increases until a specific water cut where the phase inversion to oil in water emulsion takes place. From this inversion point and for higher water cuts, the mixture viscosity is practically viscosity of water. This inversion point is not the same in all cases. From our experience we have seen it is more common to happen between 50 and 60% water cut; however, we have seen cases where this inversion point happens at 20 - 30% water cut and others at 80% water cut. The best thing to do is have an analysis done on the specific oil that is to be produced and generate this type of emulsion viscosity vs. water cut curve. [InTouch Content ID 2060497](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2060497) provides some guidelines to address emulsion formation in viscous fluid applications. [InTouch Content ID 3566890](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3566890) provides an study on estimation of emulsions viscosity at various water cuts for a specific project in KMCPL's Bohai Bay. For viscous applications, the viscosity can be dealt with either by using the calibration provided by the customer or using correction factors. ######## 7.2.4 Viscosity Calibration Sometimes actual viscosity data is furnished by the customer for better viscosity calibration. The sizing software will determine the oil viscosity using the oil viscosity correlations designated in the PVT correlations. The fluid viscosity will be calculated on a stage-by-stage basis and the pump viscosity correction factors for Q, H and HP are calculated and applied to the pump catalogue performance curves. The oil viscosity is calculated using the user selected correlation choices for dead oil, saturated, and undersaturated oil viscosity. Since oil viscosity is a crucial parameter in the overall well system calculations, having the oil viscosity calibrated to actual data can improve calculation accuracy. The oil viscosity correlations can be calibrated to closely match actual laboratory viscosity values using the viscosity calibration dialog. The sizing software allows to enter from one to three points of actual viscosity data. The advantage of this viscosity calibration data over lab data entry is the ability to input data for more than one temperature. The recommendation for calibration of viscosity to laboratory data is to use lab data or viscosity data but not both features at the same time. The oil viscosity correlations were derived from general empirical data and will usually calculate an oil viscosity with a marginal discrepancy when compared to actual laboratory oil viscosity. DesignPro software uses the selected correlations for viscosity and adjusts them to fit through the actual data points. These points may be for dead oil (atmospheric pressure - no dissolved gas) or for live oil (wellbore conditions where there is gas in solution). While selecting the pump and then the motor it is advisable to consider adding the heat generated by each to the fluid in the Advanced Options tabs. There is no substitute for field modeling and establishing correction factors for a specific field oil. DesignPro (and SubPUMP) allow to override the calculated correction factors with specified ones. ######## 7.2.5 Viscosity Corrections Factors This emulsion viscosity can be entered in to the viscosity calibration section of DesignPro as if it is the oil viscosity for the specific water cut. Then select your viscosity correction factors based on oil viscosity. DesignPro allows you to select the type of fluid you want to use for pump viscosity correction: Liquid, Fluid, Oil, or Water. When you select viscosity of the "fluid", DesignPro will use the weighted average of oil, water and gas viscosities to establish the pump correction factors. Viscosity is not a weighted property but rather a surface wet property, water wet or oil wet. Fluid weighted average is not the realistic situation when you have viscous oil. With viscous oil and water cut under 40-50%, you should use the oil viscosity for the correction factors. DesignPro offers correlations to model and calculate the viscosity for emulsions if the operator does not supply them as advised above. If emulsion occurs only in the pump and then breaks, select the Pump Only option. If you select the All System option, the emulsion will be modeled from perforations to intake, inside the pump, and from the pump discharge to the surface. Inversion water cut or point is a limit to use oil in water or water in oil emulsion in the REDA model. If water cut in the system is less than inversion, the model for water in oil emulsion is used, and if it is higher, then model for oil in water emulsion is used. Inversion water cut for the Woelflin model is used different. It is more of a cut-off point. The model is used to calculate the emulsion viscosity for values below the inversion, and beyond that it will use the water viscosity. It is recommended that you use 64%, 70%, and 72% for tight, medium, and light emulsion respectively. **Note** - Use the Emulsion option with caution and analyze the results carefully. - The inversions water cut is used differently in the calculations for the Woelflin and REDA models. Additional details on the how DesignPro models the viscous behavior with emulsions is presented in [InTouch Content ID 2060497](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2060497) . Motor heat rise calculations also use the viscosity of the fluid passing by it. DesignPro offers the option to take into consideration the heating by the motor and pump due to the work expended there. This heat will affect the viscosity in a favorable manner. Additional details on this are also provided in [InTouch Content ID 2060497](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2060497) . [InTouch Content ID 3014109](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3014109) provides information on how DesignPro calculates the viscosity correction factors and how it applies them based in the user input criteria. **Note** DesignPro allows the input of viscosity correction factors if for some reason the user wants to override the calculated correction factors (Under Pump Advanced/Options tab screen). ######## 7.2.6 Gas, Oil and Water Composition Report Knowing the fluid physical properties help to determine: - best metallurgy for the application - tendency to scale formation - tendency for corrosion - suitable equipment configuration (ES, FL, CR, ARZ, etc.). The best option is to have an analysis done on a representative sample of the pumped fluid. This type of analysis will give one key factor to determine the most suitable pump type which is the sand content that is usually expressed in ppm (parts per million). The sand content is helpful to determine the stage type and the type of pump. In this type of analysis we also ask for the determination of the particle size and the amount of total solids, dissolved solids and solids in suspension. The particle size usually comes in the form of a range of grain sizes and the percentage of the total solids that fall in that size range. The size of the particles is helpful to determine the most appropriate material for stages and bearings and sleeves for optimum abrasion resistance. On the other hand, if you do not have a representative sample of the pumped fluid but you have sample of the sand, the analysis will be simplified. You may request a grain analysis of the sample that gives you the particle size distribution. To have the complete picture, you may also request an analysis of the water to determine its actual chemical composition. These analysis are usually done by third parties (local laboratories). ######## 7.2.7 Elastomers [InTouch Content ID 4118158](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4118158%2A) provides a Review of Elastomer selection for a completion taking into consideration life of well operations and their ability to handle the following four types of environments: - Reservoir well fluids - Kill Fluid - Scale treatment - Reservoir stimulation. [InTouch Content ID 4443347](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4443347%2A) lists a elastomer selection chart describing the recommended material (Nitrile, HNBR, Aflas, Viton) based on the environment (crude oil, H2S, bromides, temperature conditions) PROCO website offers an online elastomer compatibility tool good for checking out chemical and elastomer compatibility. It can be accessed at [https://www.procoproducts.com/proco-tool-box/](https:\www.procoproducts.com\proco-tool-box\chemical-guide) [chemical-guide/](https:\www.procoproducts.com\proco-tool-box\chemical-guide) . Another useful link with elastomer compatibility tool can be accessed at [https://www.allorings.com/o-ring-compatibility](https:\www.allorings.com\o-ring-compatibility) ######## 7.2.8 Metallurgy The important criteria for metallurgy selection with respect to corrosion in oil and gas wells are temperature, partial pressures of H2S and CO2, pH and chlorides. The presence of water and its chemistry also plays an important role. The following table provides the material selection guideline based on successful field experience and includes various corrosion and environmental factors. As can be seen from the table, Redalloy (referring to ESP material configuration of using 9Cr1Mo housing and 416/410 SS head & base) is to be used for CO2 corrosion dominated environments and carbon steel is to be used in applications that have a high H2S exposure. The corrosion rate of carbon steel rapidly increases at low pH and hence, it is restricted to pH > 5.5. 13Cr (13Cr housing, 410SS head & base) should be considered when CO2 partial pressure more than 300psi and temperature more than 275 deg.F are present. **Table 2-37: Metallurgy Guidelines** | ESP Metallurgy Configura- tion | Max. pH2S | Max. pCO2 | Upper Temp Limit (°F) | Min pH | Max. (ppm) Chlorides (1) | |----------------------------------|-------------|-------------|-------------------------|----------|----------------------------| | CS | - | 15 psi | 475 | 5.5 | 100,000 | | CS-Monel coated | 200 psi | 300 psi | 275 | 5.5 | 150,000 | | ESP Metallurgy Configura- tion | Max. pH2S | Max. pCO2 | Upper Temp Limit (°F) | Min pH | Max. (ppm) Chlorides (1) | |----------------------------------|-------------|-------------|-------------------------|----------|----------------------------| | CS-625 coated | - | 300 psi | 350 | 5.5 | 150,000 | | Redalloy | 15 psi | 200 psi | 250 | 5 | 100,000 | | Redalloy- Monel coated | 20 psi | - | 275 | 4.5 | 150,000 | | Redalloy-625 coated | 20 psi | - | 350 | 4.5 | 150,000 | | 13 Cr | 15 psi | 500 psi | 300 | 3.5 | 100,000 | - ppm=mg/l. here for Chloride ion concentration in water phase only, and is different from NaCl concentration. E.g. 100,000 ppm=100 g/l Cl-, which is about 165 g/l NaCl. 150,000 ppm=150 g/l Cl-, which is about 247 g/l NaCl. Typical sea water has 3.5% NaCl, which means 35,000 ppm =35 g/l NaCl and 20g/l Cl-. The partial pressure of CO2 and H2S must be calculated to determine whether the alloy/configuration selected is within the guidelines specified in the table. Partial pressure of any one component gas present in a mixture of gases is the pressure that would be exerted by that gas if it alone occupied the same volume as the mixture at the same temperature. **Example** Examples are given below to calculate partial pressure of CO2 and H2S based on their concentration in the units of mole percent or ppm in the gas phase. - pCO2 = CO2 concentration (mole%)* Working Pressure (psi) - pH2S = H2S concentration (mole%)* Working Pressure (psi) **Example 1** : 35% CO2 (mole %) in the gas phase with Reservoir Pressure at 1,595 psi. **pCO2 = 0.35 * 1,595 psi= 558 psi** **Example 2** : 60 ppm H2S in gas phase with Bottom Hold Pressure (BHP)=2,000 psi H2S is generally reported in ppm and needs to be converted to mole percent first. 10,000 ppm = 1 mole% or multiply ppm by 10-6 to obtain mole fraction. **pH2S = 60 * 10-6 * 2,000psi= 0.12 psi** **Note** It is good practice to use bubble point pressure (BPP) as the worst case. When pressure is above the BPP, only 2 phases (oil, water) exists and there will be no free gas. In that case, still use the Bubble Point Pressure to calculate the partial pressure of H2S and CO2 per NACE MR0175 Annex C. It is not recommended to use reservoir pressure or BHP unless bubble point pressure is not available. A calculator to determine partial pressures of CO2 / H2S can be found in [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3697636) [3697636](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3697636) . **Example** T = 180 degF H2S = 0.1% CO2 = 1.2% FBHP = 2000 psi Chlorides concentration = 7800 ppm pH = 5.2 Under these conditions the partial pressure of H2S is 2 psia. The partial pressure of CO2 is 24 psia, chlorides concentration is 7800 ppm and pH is 5.2. This sets requirement for Redalloy metallurgy. As the percentage of CO2 is increased, the environment becomes more corrosive as the pH will fall. If high bicarbonates are present, i.e. 300-400 mg/l the pH will stay above 5.0. If corrosive conditions are worse, a flame spray coating with Monel or Inconel 625 can be applied to the pump. Aerated applications (H2S free): Applications with dissolved oxygen in water are not common in oil wells as soon as formation water doesn't usually contains O2, such types of applications usually associates with shallow water wells. Note that in cases when dissolved oxygen content is greater than 10ppb, minimum recommended metallurgy for exterior configuration (housing, H&B) is 22Cr and preferable is 25Cr. However, such materials cannot always be approved by Product Center, because corrosion resistance alloys are very complicated from a machining and assembling point of view and requires a lot of resources. Therefore, each request for exotic exterior will be reviewed by Business Line in terms of business value. Aerated applications also requires other considerations in terms of metallurgy used in ESP equipment, therefore high nickel alloys should be used for metal parts, for example: 5530 stages (unless 22Cr Duplex stages are available for specific pump), alloy 718 shafts, shaft seal assembly with 718 alloy parts, Monel or Inconel couplings and fasteners, Monel armor for cable/MLE, pressure transfer line from Inconel alloys. [InTouch Content ID 3463922](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3463922) provides documents with general recommendations for completion equipment in corrosive environments where different type of corrosion can occur like chloride stress corrosion cracking, CO2 corrosion, and CO2 + H2S + chlorides corrosion. [InTouch Content ID 3881510](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3881510) , provides NACE MR-0175 2003 Metallic Material Guideline for H2S, temperature and chloride limits for the most common materials used in completion hardware. ####### 7.3 Surface Characterization — Power Issues The main surface equipment required for most downhole electrical submergible pump systems comprises of: **Term Definition** **Wellhead** is the equipment that is installed at the surface of the wellbore to receive the produced fluids and send them to the production line. It’s purpose is to suspend the tubing string in the well, and to monitor and control high pressures conditions often present within the well. **Surface panel** used to control the downhole motor. This can be a Switchboard (SWB), Softstarter (SS), or Variable Speed Drive (VSD). **Transformer** is used to power the surface panel. The transformer is used to adapt the voltage from the grid to the motor requirements. The transformer sends the correct voltage to the panel which is designed for the proper motor operation. The well and field total power demand and availability has to be considered from the beginning of a design. If power from a grid is not available, local generation (generators) needs to be considered. Primary power available at the well site will be in the form of high or medium voltage (i.e., 1000, 4600, 7200, 12470, 13200, 14400, 24950, etc.), although low voltage can also be available (380, 440, 460, 480, etc.) A constant frequency of 60 Hz (50 Hz in some countries) is also provided. Although the voltage and fixed frequency may vary from region to region, it is important that the power source and surface equipment provide the ESP motor three-phase power and the required surface voltage. Proper voltage, and therefore amperage, is essential to maintain a high efficiency of the motor. The availability of an electrical load study will help to ensure an adequate supply of clean stable power. The design should be made so that determining the best matching of surface electrical equipment to the downhole load requirements. For example, certain national regulations allow a limit on the power factor. Below this limit, utility companies can impose fines on the end user. When using certain types of VSD, harmonics can be a source of problems such as additional losses and requirements of reactive power, overload of capacitors, transients, and overheating. In addition to surface effects, harmonics also have a detrimental effect on ESP efficiency and runlife. ####### 7.4 Wellbore Characterization ######## 7.4.1 Well Data The basic wellbore information needed include: - Casing OD, ID, roughness, weight and depth - Tubing OD, ID, roughness, weight and depth - Location of top perforations - Total depth. Well directional survey and equipment clearance are also analyzed in this section. ######## 7.4.2 Well Directional Survey (TVD, MD, Inclination, Deviation, DLS) In case of an ESP installation in a deviated well, particularly with tight clearance, a survey of the well is necessary not only for the Application Engineer but also for the Field Service Technician in order to determine the RIH speed in each section of the well, i.e. slowing down in the section that has high DLS. The formula to compute DLS is: *(d/DMD)*inv cos[ cos(I2-I1) - (sin I1* sin I2)*(1-cos(A2-A1)) ]* where, **Term Definition** **d** DLS interval (100 ft or 30 m) **DMD** measured depth interval between surveys (ft or m) **I1** inclination at survey station 1 **I2** inclination at survey station 2 **A1** azimuth at survey station 1 **A2** azimuth at survey station 2 ######## 7.4.3 Equipment Clearance A clearance of around 0.200 inches would be needed to run the unit safely between the overall equipment OD and the casing drift diameter. If a gauge is run before running the unit in the hole, tighter clearances are possible. There are many instances where clearances as small as .02 inches have been used. Visualization of pump/motor clearance on flat and round cable side as presented in the ALFORM—D can be found in [InTouch Content ID 3869581](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3869581) . This graphical representation does not consider cable guards, cable protectolizers, etc. The visualization generated does not substitute detailed Autocad or Cadkey drawings. It is a quick check of the clearance allowed downhole. Cadkey detailed drawing can be obtained through Rapid Response. Same assumptions for the equation in the ALFORM—D ( [InTouch Content ID 3255850](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3255850) ) apply for the spreadsheet. It is recommended to download the spreadsheet before using it. Clearance end view drawings for several most common configurations are available in [InTouch](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4028671) [Content ID 4028671](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4028671) . These drawings show the minimum casing ID allowed for different motor/ protector/pump series combinations. Casing irregularities or deformation can restrict what is already limited clearance between the ESP system and the casing. This may result in damage to the power cable, often resulting in premature system failure or inability to reach the setting depth before insulation failure. Best Practice [InTouch](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3347306) [Content ID 3347306](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3347306) shows that when casing clearance is a concern there are some guidelines to follow. These guidelines include: - Running a bit and scraper to clear the casing of obstructions and debris. - Running a gauge ring to verify casing integrity and dimension. - Running a "stiff string" that approximates the dimensions of the ESP system to be installed. - Running a mockup assembly prior to running the purchased system. While designing for crossflow and Y-tool, spreadsheet in [InTouch Content ID 3867283](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3867283) was developed to easily calculate clearances and fluid velocity across the motor. Spreadsheet requires user to enter casing, bypass tubing and ESP Series from a list, automatically calculates the clearance. By inputting the flowrate, fluid velocity across the motor is also calculated. [InTouch](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3039062) [Content ID 3039062](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3039062) provides an example of how to deal with clearance issues when a Y-Tool is used. ######## 7.4.4 Equipment Drawing WellBuilder is the completions software for schematic graphics and part number listings with links to [OneCAT](http:\www.wcp.oilfield.slb.com\cs\catalog) . This software provides a standard reporting for schematics to our customers. WellBuilder provides for a local OneCAT catalogue without a network link, custom reporting, and custom catalogues for locally supplied product inclusion. OneCAT order carts can be made in WellBuilder and uploaded. Completions can now be designed with part numbers in listing mode with graphics automatically generated, or in the traditional mode of drag and drop icons with the listing automatically created. WellBuilder builds on the functionality of and replaces Well Vision. Visio® is required and can be purchased through Radia [http://www.ssds.slb.com:8080/ssdp/cmd](http:\www.ssds.slb.com:8080\ssdp\cmd) . ######## 7.4.5 Tubulars There are a number of sources for tabular data within [InTouch Content ID 3275557](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3275557) provides a link to web page to access a quick reference for API tubing performance properties. Data can also be downloaded as a standalone software though [InTouch Content ID 3543141](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3543141) , which includes the Latest Electronic Version of the Field Data Handbook (i-Handbook). [InTouch Content ID 3001892](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3001892) provides the criteria to choose Corrosive Resistant Alloys for Down Hole Completions. ######## 7.4.6 Operating Design Requirements and Criteria This sections describes IPR, outflow, AL intake pressure, AL pressure requirement, wellhead pressure required, TDH. ######## 7.4.7 Inflow (PI IPR, Composite) The objective of the design is to install a pump that can help bring the fluid to the surface for the specified wellbore conditions. The system perforations-surface can be visualized in the following graph. *Above the pump* we have TDH and Outflow. TDH is the sum of three basic components: **Term Definition** **The Net Vertical Lift** is the vertical distance through which the fluid must be lifted to get to the surface. **The friction loss in the tubing string** Friction is an energy loss (we actually measure it as a pressure loss) due to viscous shear of the flowing fluid. **The wellhead pressure** The unit must pump against pressure. Wellhead pressure is sometimes called "Surface Pressure", "Back Pressure" or even "Flowline Pressure". Actually the most accurate term is "Tubing Discharge Pressure" since this is the pressure at the discharge of the tubing from the well. *Across the pump* is when the pump is expected to deliver energy to fluid as a means of increasing its energy so it can flow to the surface. The pump intake pressure will be dependent on the pump setting depth and is the flowing bottomhole pressure adjusted for a change in pressure due to vertical distance to the perforations and due to friction losses along the portion of casing between perforations and pump. The pump discharge pressure will depend on the fluid properties, reservoir pressures and pump chosen, and pump condition. *Below the pump* we have the Inflow. Inflow Performance is the ability of the reservoir to deliver oil or gas through the formation and is described by the pressure / rate response of the reservoir. The Inflow Performance depends on reservoir parameters and reservoir fluid characteristics. Pr, the average reservoir pressure, is the maximum pressure there is in the rock. This is also a measure of the total energy available in the reservoir. It should be noted that pressure is just one way to measure energy. The higher the Pr, the more energy is available to produce fluids from the well. Pr is the initial energy value. If we drill a hole into a reservoir and open the hole up for fluid flow, a lower pressure will exist at the wellbore than deep inside the reservoir. If we did not have a lower pressure, there could be no flow since we have to have a pressure difference to allow the flow. Now that we know the nature of the problem, it is simply a matter of figuring out how to calculate the flow rate we will get from the reservoir as the pressure in the wellbore is lowered. Henry Darcy, while working with pressure losses in sand filters, proposed what we now call Darcy's law. where, **Term Definition** **Pr** the average reservoir pressure **Pwf** pressure at the wellbore perforations **qo** flowrate It is described graphically in [Figure 2-8](.) . **Figure 2-8: Graphical Presentation** **Term Definition** **K** is a constant that depends on viscosity, permeability, wellbore radius, formation volume factor, drainage radius, feet of pay. **Pr-Pwf** drawdown In this way we define Productivity Index (PI) as the flow rate divided the drawdown. In some cases, the PI can also be improved slightly by acidizing or fracturing. Acidizing cleans up "skin" on the perforations and can improve porosity in limestone reservoirs by making larger holes for oil flow. Fracturing can also improve porosity by making large cracks near the wellbore. Darcy's law works great for single phase fluid (i.e. water, oil, or water/oil) flowing into a wellbore. If gas comes out of solution in the reservoir the dynamic of the fluid will be affected. In this way, the oil flow we get as the pressure is lowered will be less than we would predict using Darcy's law. Vogel's IPR curve is used in the equation below. where, **Term Definition** **qo max** is the maximum flowrate the well can produce To construct this curve, well test data is used. We can use Darcy's law when gas is not a problem as in a high water cut well. We can use Vogel's IPR for cases where Pr < Pb. Where Pr > Pb > 0 we can use the Combined IPR. The Combined IPR uses Darcy's law for Pr > Pwf > Pb and Vogel's IPR for the portion where Pb > Pwf > 0 to account for gas presence. Vogel's relationship works reasonably well for water cuts below 50%. For higher water cuts, a method has been developed which takes arithmetic average of the PI and IPR equations to yield a "composite IPR". Some care must be exercised when applying this particular technique. The concept of a composite IPR is reasonable in certain cases and is not applicable in others. The difference lies in where the water is coming from. If the water being produced is connate water, this technique will give optimistic results and should not be used. If the water is coming from below (or even above) the producing oil zone or if the water is fingering through long fractures, this method can be used with some success. Summarizing: depending on the reservoir fluid, we may use a straight line PI, an IPR, or a combination of the two. ######## 7.4.8 Outflow Multiphase Flow Correlations We can be reasonably good with our simple equations to determine the TDH calculations in very high water-cut wells or even in oil wells where the GOR is fairly low. But in low water cut and/or high GOR wells, TDH is not the way to go. We use multiphase flow correlations that help us to determine the pressure and temperature profile along a tubing or casing. In multiphase flow, the type of flow "regime" will depend on the relative amounts of gas and liquid and on the pressure and temperature of the phases. One of the main tasks of a multiphase flow correlation is to try and predict the type of flow in a differential element of conduit. Different correlations will categorize flow regimes a little differently and some differentiate more types than others. Researchers spend a great deal of time studying multiphase flow to measure the properties and then try to "correlate" the data into a useful form for calculation. Multiphase flow is flow of more than one phase. Water and oil would be a multiphase mixture — pecifically two-phase. Oil and gas would also be two-phase flow. There are different outflow (tubing) correlations to consider. [Table 2-38](.) has been compiled to facilitate making the choices for multiphase flow correlations when using DesignPro for application sizing. Each one was developed under a particular set of conditions and may work better on a certain type of crude or a particular gas composition so never believe that one is the best. This may change by geographical area or even within different reservoirs in a given field. **Table 2-38: Multiphase flow correlations when using DesignPro for application sizing** | Correlation | Development Parameters | Data Origin | |---------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------| | Hagedorn and Brown (1963) | Liquid hold-up and flow pattern not measured or observed; have been modifications to the original model in computer versions | 1500 ft. vertical instrumented well; tubing 1.25 – 2.875 in O. D.; viscosities = 10, 35, and 110 cp; oil, air and water used | | Orkiszewski (1967) | New method for slug flow only; used Duns and Ros for mist, Griffith Y Wallis for bubble flow; a discontinuity as the mixture velocity reaches 10 ft/ sec (Triggia correction software) | Used Hagedorn and Brown data plus field data from 148 vertical well conditions; pipe 1- 3 in; oil, air and water | | Duns and Ros (1963) | Liquid hold-up was measured; flow pattern was observed; Mobil/Shell modification for directional wells is proprietary and not in SubPUMP | Vertical 10 meter lab facility used; low pressure using air, oil and water; tubing 3.2 – 8.02 cm | | Aziz et al (1972) | Tried to improve on Okiszewski’s bubble and slug flow, but negligible difference in comparison study of 48 wells | Theoretical | | Beggs and Brill (1973) | Gas: 0-300 mscf/d; liquid:0-30 gpm; pressure 35-95 psi; liquid hold-up: 0-.87 measured; pressure gradient: 0-.8 psi/ft; inclination angle: -90 degrees to +90 degrees (downhill flow included); flow patterns observed; horizontal flow regimes established; Palmer correction factors for liquid hold-up on uphill and downhill; Payne corrections – rough pipe friction | Lab facility using 90 foot acrylic pipe 1-1.5 inch diameter; 584 measured tests using water and air | | Mukherjee and Brill (1985) | Emphasis on improving correlations for inclined flow: both upflow and downflow, redefinition of flow regimes and friction factors for inclined flow | | | Ansari (1990) Mechanistic Model | Comprehensive model for upward two-phase flow; predicts flow pattern and characteristics such as liquid hold-up | Evaluated by using a well data bank of 1775 well cases | Given the nature of the data origin for the multiphase flow correlations, correlation choices can be narrowed to one or two which best fit the application. Hagedorn and Brown has consistently ranked at the top for vertical flow in numerous studies. The Mechanistic Model by Ansari for upward flow, when compared with six common empirical correlations against the 1775 well cases covering a wide variety of field data, performed the best with the least average error and smallest scattering of results. Rajan Chokshi studied multiphase flow in large diameter tubing with the intent to improve Ansari's model. His initial tests have shown that the overall prediction error for pressure gradient in large diameter tubing is the smallest using Hagedorn and Brown, then the ranking is as follows: Duns and Ros, Beggs and Brill, Aziz, Ansari, Mukherjee and Brill with Orkiszewski bringing up the rear with the largest error. If the application has considerable deviation or upflow and downflow as in a horizontal well leg, Beggs and Brill or Mukherjee and Brill will be a wise choice since these correlations were developed to include deviated and horizontal pipe flow. DesignPro has multiphase flow correlations for determining the pump intake pressure in the casing. This provides more accuracy than past models that used gradient calculations, especially where the pump set depth is at a considerable distance from the perforations or pressure datum depth. [InTouch Content ID 3461113](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3461113) provides a comprehensive list of multiphase flow correlation and gives recommendations on where to use one or the others, depending on a number of factors including GOR, watercut and other fluid properties, angle of inclination, flow pattern, etc. Some correlations are fairly general whereas others apply only to a narrow range of conditions. If a pressure survey is available, DesignPro software can be used to determine which correlation most closely matches field data via the Flow Correlation Matching operation. In the absence of additional test data, the chosen correlation can then be applied to other wells in the same field with similar producing conditions. If the well is in the design stage and thus no test data is available, a correlation can be selected based on field experience and comparative studies. Most two-phase flow correlations begin with a prediction of flow pattern. Depending on which flow pattern is predicted, an associated method is used to predict liquid holdup and pressure drop. To achieve yet a closer match with field data, DesignPro is a good tool that allows adjusting a multiplier for each the liquid holdup and the frictional component of the pressure drop. In 1995, a major JIP was completed by Baker Jardine (now part of SIS), which compared the performance of flow correlations based on field data for wells and pipelines (see attachment). The results show the best correlation for: - Single phases systems (Moody) - Vertical Oil Wells (Hagedorn Brown) - Highly Deviated oil wells (Hagedorn Brown, Duns and Ros, OLGA-S) - Gas/condensate well (Hagedorn Brown) - Oil Pipelines (Oliemans) - Gas/condensate pipelines (Baker Jardine Revised). [InTouch Content ID 3036266](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3036266) provides additional documentation on flow correlations. [InTouch](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3991169) [Content ID 3991169](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3991169) provides a link to a more complete listing of Multiphase Flow Correlations used in the oil industry. This listing has been compiled by the Schlumberger Cambridge Research group. ######## 7.4.9 Environment issues - **Inorganic Deposits** **Scale (Carbonates, Sulfates, Oxides, Sulfides, Silicates)** Scales are water-soluble chemicals that precipitate out of solution in response to changes in conditions or the mixing of incompatible waters. They can be present in the tubing, perforations and/ or formation. The most common oilfield scales are calcium carbonate, calcium sulfate and barium sulfate. Scales can occur in both production and injection wells, as long as water is present. Water- formed scale deposits are among the most troublesome and common damage problems. Scale forms when the solution equilibrium of produced waters is upset. Pressure decreases and temperature changes as the fluids move from the reservoir to the surface can upset the equilibrium. The supersaturated solutions react by precipitating a compound from solution. The deposition of scale is influenced by pressure drop, temperature, dissolved gases, flow viscosity, nucleation sites and metal type, in short, anything that upsets the solution equilibrium. Scales can also form by mixing incompatible waters. The water used in any injection operation into a well will mix with the reservoir water. The waters are considered to be incompatible if precipitation occurs when they are mixed. Computer programs are available which model water mixing to show potential precipitates. The Scale Prediction module in StimCADE is one of these. Basically what it does is to determine the chemical status when mixing two waters. There is a need of a complete chemical analysis including but not limited to pH, Alkalinity, Iron, CaCO3, Calcium, Magnesium etc. The program calculates whether the mix of those two waters has scaling tendency (Stiff and Davis Index is positive), corrosive tendency (Stiff and Davis index is negative) or neutral (Stiff and Davis Index is zero). It can be used after water injection to help identify scale sources. Better yet, it should be used before the fluid is mixed and injected into the well in order to prevent scale issues. It should be emphasized that all water used in well operations may be potential scale sources, not just water injected in secondary waterflood operations. It is often easy to forget that filtrate from completion or workover fluids, as well as treating fluids must also be compatible with the formation waters. Sea water is sometimes used for injection into offshore wells. Sea water typically contains traces of barium, which could react with the reservoir water to form detrimental precipitates. The risks associated with water incompatibility should be considered and accepted before injecting the water. Common scales encountered in wells include: - *Calcium carbonate or calcite (CaCO3)* is usually formed when the pressure is reduced on waters that are rich in calcium and bicarbonate ion. The deposition can be affected by CO2 outgassing, which raises the pH value and makes high concentrations of calcium unstable. - *Gypsum (gyp)* may be the most common sulfate scale in the oil industry (Cowen and Weintritt, 1976). With a chemical structure of CaSO4 and 2 H2O, it shares a similar composition to the hemihydrate CaSO4 and 1/2 H2O, commonly called plaster of Paris or by its mineral name, bassonite. It also has the same chemical formula as the evaporite mineral anhydrite (CaSO4). - *Barium sulfate (BaSO4)* is a less common form of sulfate deposit, but it causes extensive problems. Almost any combination of barium and sulfate ions causes precipitation. It is difficult to remove. Normal solvents do not affect it unless it is finely ground or the structure is interrupted with impurities such as carbonate scale. Like calcium sulfate, barium sulfate is usually thought to be a product of mixing incompatible waters, with precipitation accelerated by pressure drop, outgassing or turbulence. Some barium sulfate is radioactive. It is one of the naturally occurring radioactive material (NORM) scales. The radioactivity results from a concentration of uranium in the lattice of the scale. The buildup of radioactive scale can be monitored using a gamma ray logging tool. Care must be exercised when analyzing well debris to avoid mislabeling barite (BaSO4) from drilling mud residue as barium sulfate scale. - *Strontium sulfate or celestite (SrSO4)* is a common substitute in the barium sulfate crystal lattice. Strontium scale can also be associated with radioactive scale (NORM). It may be more soluble than barium sulfate in chemical remover systems. - *Iron scales* , such as iron carbonate and iron sulfide are more difficult to remove than calcite scales. They are usually seen in wells that have both a high background iron count and a tendency to precipitate calcium carbonate. Iron sulfide scales react according to their structure. Several different forms of iron sulfide scale have been identified. Only two of these iron sulfide forms are readily soluble in hydrochloric acid (HCl). The remaining iron sulfide scales are either slowly soluble or not significantly soluble. - *Chloride scales* , such as sodium chloride precipitation from water caused by temperature decrease or evaporation of the water, are common. There is no effective way to prevent salt precipitation. Salt has a limited solubility in acid (1/4 lbm/gal in 28% HCl), so using acid is not generally considered as a treating fluid. Cleanup is typically accomplished using water only. Redesigning the mechanical system to avoid temperature loss and water evaporation can help prevent chloride scales. - *Silica scales* generally occur as finely crystallized deposits of chalcedony or as amorphous opal. They are associated with alkaline or steamflood projects and stem from the dissolution of siliceous formation minerals by high-pH fluids (Lieu et al., 1983) or high-temperature steam condensates (Reed, 1980; Amaefule et al., 1984). This dissolution can cause poorly consolidated sandstones to collapse or silica to re-precipitate at a distance from the wellbore where the alkalinity, temperature or both of the floods has decreased. Contact time is a very important factor to consider when designing a scale removal treatment. Sufficient time must be allowed for the treating fluid to reach and effectively dissolve the bulk of the scale material. When treating some types of slow dissolving scales, shutting in the well to allow the treatment to soak may be required. [InTouch Content ID 3963532](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3963532) provides a thorough explanation of the challenges faced when scale deposition occurs on ESP’s. Several ways of handling scale deposition are exposed having into consideration: Main causes for scale precipitation **Term Definition** **Pressure** can be increased by setting the ESP at higher depth temperature. **Oxygen** setting the ESP at higher depth will reduce availability of oxygen. **Chemical Treatment** Based on the amount and type of scale, chemical inhibitors are injected below the motor to avoid precipitation of scale. Need to consult Chemist for more details. **Coating of the stages:** depending on type of scale. A field guide used to help identify types of scale can be accessed in the following link [http://csl.](http:\csl.houston.oilfield.slb.com\onlinetraining\scale%20analysis) [houston.oilfield.slb.com/onlinetraining/scale%20analysis/](http:\csl.houston.oilfield.slb.com\onlinetraining\scale%20analysis) . It can also be downloaded from [InTouch Content ID 3861345](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3861345) . [InTouch Content ID 3252202](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3252202) provides means for Scale Control. Scale Control involves prevention or remediation. [InTouch Content ID 4201962](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4201962) provides a good picture of how to interact with a chemical company in order to determine the proper method to control scale. ######## 7.4.10 Scale Prevention Keeping producing wells healthy is ultimately the most efficient way to produced hydrocarbons. In most cases, scale prevention through chemical inhibition is the preferred method of maintaining well productivity. Depending on the degree and type of scale, inhibition techniques can range from basic dilution methods to the most advanced and cost-effective methods of threshold scale inhibitors. The most convenient way for chemical inhibition is using cable with a capillary tubing. Depending on the cable gauge, capillary tube diameters can be 5/16 in or 3/8 in . The inhibitor, is pumped from surface with an alternative pump through the power cable capillary tube. The formulation of the inhibitor depends upon each field, and it's crucial to ensure proper inhibition, scale control, avoid capillary plug and extend the ESP runlife. The main concern when running an ESP is where to leave the capillary end, depending on the ESP setting depth, if it is shrouded or not, the capillary end can reach the UMB or sensor base, or it can be left above the ESP. ######## 7.4.11 Scale Remediation Scale-removal techniques must be quick, non-damaging to the wellbore, tubing, or formation environment, and effective at preventing re-precipitation. Formation matrix stimulation treatments frequently employ scale dissolvers to arrest production decline. The best scale removal technique depends on knowing the type and quantity of scale, and its physical composition or texture. One of the methods to control scale is by performing batch acidization treatments. Schlumberger AL first advice is not to perform batch acidization treatments while the ESP is in the well. Continuous chemical treatment is preferred as a preventive measure. These jobs are performed by pumping fluids, which include acids such as HCl, HF, formic, acetic, etc. by the annulus or by the tubing with relative success. Among the variables that determine how the different materials of the ESP components are affected when exposed to the injected fluids are: - temperature (usually bottomhole temperature) - acid composition - process of the treatment - solvents - corrosion inhibitors - flushing, residence time or time the acid is in contact with the ESP materials - and pressure. Most of these factors are out of our control as they are defined and performed by other companies. The customer should always be made aware that there is a risk of shortening the runlife after an acidizing job performed with the ESP in the well. While we would like to see acids like formic and acetic used because they are less damaging to the ESP materials, its up to the chemical engineers of the operating company to define the most appropriate acid and exposure time for their stimulation in each well. Corrosion inhibitors are only good for specific alloys. An inhibitor that works for carbon steel may not, and usually does not work for stainless steel, 9Cr-1Mo or for Ni-Resist. Thus, there is not one inhibitor that will protect all the ESP materials. For example, Stainless Steel, especially 416 (but also 410) can corrode more in HCl when corrosion inhibitor is designed for the protection of carbon steel or low-alloy steels. The observation of more corrosion on 416 or 410 martensitic stainless steel than on carbon steel parts during acid simulation in downhole environment is not uncommon. Organic acids (formic and acetic) will have the following effects on various materials: - 300 Series Stainless Steels - good resistance - 400 Series Stainless Steels - poor resistance - Carbon or alloys steels - poor resistance - Copper alloys - good resistance - Aluminum alloys - fair resistance - Titanium alloys - good resistance - Nickel alloys - good resistance - Rubbers and Elastomers - fair to good resistance. Hydrochloric acid will have the following effects on various materials: - 300 Series Stainless Steels - poor resistance - 400 Series Stainless Steels - poor resistance - Carbon or alloys steels - poor resistance - Copper alloys - fair resistance - Titanium alloys - fair to good resistance - Nickel alloys - fair to good resistance - Rubbers and Elastomers - good resistance. In general, we have seen that in most field jobs where exposure time has been between 30 and 60 minutes, there has not been a negative impact on the materials, however, there are no guarantees this will always be the case. ######## 2.1.4.7.1 Organic deposits (Asphaltenes, Paraffin) Organic deposits are heavy hydrocarbons (paraffins or asphaltenes) that precipitate as the pressure or temperature is reduced. They are typically located in the tubing, perforations or formation. Although the formation mechanisms of organic deposits are numerous and complex (Houchin and Hudson, 1986), the main mechanism is a change in temperature or pressure in the flowing system. Cooling of the wellbore or the injection of cold treating fluids can also cause organic deposits to precipitate. are a mixture of linear and branched chained hydrocarbons. Paraffin deposition is a crystallization reaction that is triggered by a loss of pressure, temperature, or light ends (the short-chain hydrocarbon compounds in the crude). Wax is a solid form of paraffin. Paraffins are soluble in aromatic solvents (Xylene, Toluene). Crude oil in an untapped reservoir exists in a state of chemical and physical equilibrium. As the oil is produced through the formation, this equilibrium is lost and the fluid undergoes physical and chemical changes. The volatile liquid constituents are continuously lost from the crude oil after it enters the fracture and the wellbore since the pressure there is less than the pressure driving the fluid through the reservoir. Also, because of the pressure differentials that exist in the well, the crude oil begins to cool below formation temperature. A loss of light ends and a decrease in temperature combine to cause the solution to become saturated with paraffin. Then the paraffin begins to precipitate, and often it collects on the tubing, in flow lines but can also affect the well permeability. Injection of cold fluids (for example in a stimulation treatment) that cause the fluid in the formation to cool to a temperature below the cloud point (the temperature at which paraffin particles first begin to precipitate from solution) will cause paraffins to precipitate and may deposit in the formation pores, partially blocking or plugging the fluid flow channels and thus restricting the flow. This may contribute to slow cleanup in many wells after stimulation. Hot oil treatments used to remove paraffins from the tubulars can also produce paraffins deposition in the wellbore and the consequent permeability damage. The injected oil looses temperature as it travels downhole removing the paraffin in the tubing. If this oil reaches the perforations and the bottomhole temperature is below its cloud point precipitation can occur in the wellbore. The precipitation of paraffin can be an irreversible process. The wax, once removed from solution, is very difficult to put back into solution even after the original formation temperatures are restored. For this reason, mechanical or chemical well treatments are needed to remove or inhibit paraffin deposition. Although paraffin can form anywhere in the well (Cole and Jessen, 1960; Burger et. al., 1981; Newberry, et. al., 1986; Thomas, 1988; Sutton and Roberts, 1974), they are usually found in the tubing near the surface where the temperature and pressure drops are the highest. They can also form at the perforations or in the reservoir matrix in cases where the reservoir pressure is nearly depleted or the formation has experienced dry gas cycling. When dealing with paraffin its composition should be determined. Knowing if the paraffin contains salts, fines, resins, scale, gums, asphaltic materials, water, etc., what the cloud point/pour point and BHT is important to ensure the proper methods are analyzed to deal with the problem. These are the questions to ask: - Where is the paraffin deposition likely to occur? Near wellbore, in the pump, in the tubing or wellhead? Knowing this will assist in a cost effective method to deal with the problem. - What are the expected production rates? How much gas will come out of solution and will it be enough to cool the oil enough to precipitate out paraffin? - How much cooling will take place through out the wellbore, does the well have a number of cooler zones? are organic materials consisting of aromatic and naphthenic ring compounds containing nitrogen, sulfur, and oxygen molecules (Leontaritus, 1989, Leontaritus and Mansoori, 1987; Tuttle, 1983, Newberry and Barker, 1985; Addison, 1989; Thawer, et al., 1990). The asphaltene fraction of the crude is defined as the organic part of the oil that is not soluble in a straight-chain aliphatic solvents, such as pentane or heptane but is soluble in aromatics such as xylene or toluene. They are present in crude oils as a colloidally dispersed particles stabilized by maltene neutral resin molecules. Maltenes are condensed polynuclear aromatic ring systems (pyrrole and indoles) with alkyl or naphthenic side chains. The stability of asphaltic dispersions depends on the ratio of resin to asphaltene molecules. Resin ratios larger than 1:1 (resins to asphaltenes) are more stable, whereas ratios less than 1:1 are unstable and may precipitate during production. Resin ratios of more than 10:1 are known and are much less likely to cause significant problems. The actual quantity of asphaltenes in the oil is less important than the resin ratio in determining if asphaltene damage will be a problem. Although asphaltene contents up to 60% have been found, major problems can occur in oils with asphaltene contents as low as 1% to 3%. Asphaltene precipitation can be influenced by pressure drop, shear (turbulence), acids, solution CO2 (lowers the pH value), injected condensate, gas, commingling with other (incompatible) oils and charged metal surfaces. Addition of low surface tension organic fluid such as gasoline, pentane, hexane, naphtam condensates, diesel may precipitate asphaltenes. Anything that takes away the resins or breaks the stability of the asphaltene micelle can lead to precipitation. Iron ions in solution (usually during an acid job) compound and favor the formation of asphaltene deposition. In general, asphaltene deposits can be classified as: - Hard coal like solid deposits - Sludges and rigid film emulsions. Asphaltene deposition can cause operating problems similar to those of paraffin but it is often more difficult to treat. **Note** These organic deposits must not be confused with another type of mixed deposits where fines or scale particles become oil wet and act as a nucleation site for organic deposits. They are a blend of organic compounds and either scales, silts, or clays. Their treatment usually require a dual-solvent system in order to strip the organic phase with an organic solvent and dissolve inorganic material with mineral solvent ######## 7.4.12 Paraffin/Asphaltene Treatment There are a number of chemical solutions available from the larger chemical companies to treat these organic deposits: - Solvents used to dissolve existing deposits are of high aromatics content since both paraffins and asphaltenes are soluble in aromatics. - Dispersants break paraffin deposits into much smaller particles that are then reabsorbed by the oil stream. - Detergents also break up deposits in the presence of water. - Crystal modifiers are polymers that alter the crystal formation and inhibit the precipitation. Formation squeezes in some cases are successful in treating paraffin problems. If a large temperature drop occurs in parts of the tubing string and paraffin deposition within the tubing is a problem, it may be worthwhile to look at using a heat trace cable to heat the tubing or even use internally coated tubing. The base solvent used in most cases is Xylene. Xylene is one of the most cost effective and one of the most readily available chemicals that can be used to treat wax or asphaltenes. But Xylene is an extremely aggressive solvent to the elastomers in the ESP. Xylene will dissolve the nitrile rubber jacket, HSN and Aflas protector bags and Aflas/ HSN O-rings. The first advise is to remove the ESP from the well prior to treating with anything containing xylene unless the time s kept to a minimum and concentrations are low. Once the chemical is pumped into the well, the chemical will be diluted. Many chemical treatments on wells to free paraffin/asphaltene plugged pumps and to clear tubing have been done successfully without pulling the unit. For these reasons, chemicals should be checked for compatibility with the ESP cable and elastomers before doing the job. The use of coated pump stages with coatings such as Impreglon 237, 410M or HyTek Teflon can also be considered when paraffin/asphaltene depositions are likely. The use of the largest vane pump for the production is recommended. Mixed flow stages are often the best to use. If the pump does become plugged there is a better chance to flush the pump without pulling it. Also monitoring the stall time of when the unit starts up is useful in determining if deposition is occurring in the pump. At that point a preventative chemical treatment can be done. When paraffin formation occurs in the well, the need for pigging and chemical treatment of surface flow lines is likely. In some cases injection of chemicals at the wellhead may be needed for flow assurance. It should be noted that in the cases where Impreglon coated stages are used the Xylene will help restore some of the release characteristics of the coating. Based on experience using only Xylene does not promote a decrease in ESP run life if the right elastomers are used in the equipment. When a paraffin/asphaltene inhibitor is injected in a well, there are different locations for the point of injection: - **Below the pump.** A stinger can be run or a basket can be installed below the motor. The idea is to supply the chemical via a capillary string and mix it with the well fluid prior to being ingested into the pump. This has been done mainly to prevent scale deposition in ESP pumps, although this idea can be applied to wells where asphaltenes are a problem. The same concept applies if the point of injection is at the pump intake. - **Into the string above the pump.** There are chemical injection mandrels that could be installed above the pump handling pup joint. A capillary string can be run to inject the chemical into the tubing. - **Via the annulus (no packer installed).** This may be more effective in shrouded applications. Although if large amounts of gas were produced up the annulus, the gas may carry the chemical out of the well. Experiences in Canada using various slip stream devices that are suppose to deliver chemical to the pump intake via the annulus have shown no measurable success on a rod pump or ESP well. A very common application of chemicals for remedial purposes involves clean up of the production string with solvent injection down the tubing. When trying to pump through the pump it is important to watch pressures and rates, since sometimes a breakdown in the paraffin/ asphaltenes in the pump can be seen. Most of the solvent slug would be displaced out through the intake or gas separator into the casing filled with oil. Oil is a better carrier of asphaltenes than water. Being able to have large vane pumps is very important when dealing with asphaltene plugging. Soaking time can be as long as 24 hours or shorter time. A period of 2-4 hours soak before trying to start the pump can be acceptable since the well needs to return to production as soon as possible and it can be assumed that a certain amount of mixing will occur reducing the strength of the chemical. Other method that can be used is a staged job pumping solvent down the casing. Sometimes the pump intakes or gas separators become coated on the outside with asphaltenes. A staged job requires larger volumes of solvent and should be repeated twice more. Then displace with oil past the pump setting depth. [InTouch Content ID 3014066](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3014066) provides some experiences on treating ESP’s wells with asphaltenes/ paraffin deposition. [InTouch Reference Page ID 3319312](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3319312) provides additional relevant information about removal and inhibition of organic deposits. ###### 8 Pump ####### 8.1 Centrifugal Pump Basics The pump section in an Electrical Submersible Pump (ESP) is a device that converts motor shaft brake horse power (bhp) to Hydraulic energy. The pump mainly consists of impellers and diffusers driven by a common shaft, in a multistage configuration. Impellers are driven by the shaft and transfer energy to the well fluid (work done on fluid by centrifugal action). Diffusers basically redirect fluid from the output of one impeller into the input of the next one. In other words, work done by rotating impellers increase the fluid velocity (Kinetic) and diffusers convert some of the fluid velocity to higher pressure (potential) and direct the flow back to the eye of the next impeller, and so on. Most of the brake horse power provided by the shaft is converted to hydraulic power that lifts the fluid to surface and provides wellhead pressure. The rest of the bhp is lost in the form of hydraulic losses, friction, and heat. ####### 8.2 Pump Selection - Customer requirements and data collection - Determine Pump Series (OD) - Pump Stage Selection - Determine number of stages required - Pump Construction ######## 8.2.1 Customer Requirements and Data Collection Sizing an ESP starts with selecting the pump, and the selection of the rest of the components follows. To properly select a pump it is important to ensure the customer objectives are well understood and also the best and latest data possible is collected. Pump selection should consider: casing size, flow rate and head, free gas percent at pump intake, oil viscosity, solids, corrosive environment. For a proper selection of pumps, it is also important to understand the customer’s outlook towards the future within the expected runlife of the system. The future outlook would include changes in total flow, water cut, amount of free gas, scale, and any other future needs the customer would expect. [InTouch Content ID 4050501](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4050501) includes the data form required to perform an ESP design using DesignPro. ######## 8.2.2 Determine Pump Series The first pump selection task for an AE is to match the pump series (OD) to fit the well internal diameter (ID) with suitable clearance to avoid damage (depending on application). In general, it is best to fit the largest series possible for the casing ID. Given enough casing space, bigger diameter pumps typically are better than smaller diameter pumps. For a given flow rate, a larger diameter pump always produces more head per unit length of pump than a smaller diameter pump, which means a larger diameter pump will be more cost effective. Also, shorter pumps with larger OD’s are physically more rigid when operating in deviated wells. DesignPro limits the pump series selection to what would fit in the casing, given the clearance choice under the Options section. ######## 8.2.3 Pump Stage Selection After selecting the pump series, the most suitable stage type has to be selected. Use these guidelines to help decide on which stage is appropriate: ######## 8.2.4 Volume and Recommended Operating Range Once you know the total fluid flow rate (including any free gas) through the pump and the operating frequency, select a pump that would operate in the recommended operating range (ROR) through the expected life of the pump and for the range of desired operating frequencies. This range (ROR) outlines flow rates that should result in best pump performance, minimum wear and reasonable efficiencies. It is particularly critical to understand the total volume of fluid the pump has to handle over its expected runlife. This includes the volume of liquid plus free gas entering the pump; which is usually governed by the well conditions, fluid type, PVT, changing reservoir condition, and the selection of gas separators when applicable. In DesignPro, equipment data entry starts with the gas separator section, and the pump section follows. This is to ensure that the effects of gas separation (and possibly a packer) on total volume entering the pump are calculated before pump selection. on Gas separation and handling. The amount of free gas (fraction) entering the pump also determines the need for any gas handlers (AGH or MGH), that can be selected under the Gas Handler tab in the pump section. DesignPro prompts the user if a gas handling device is recommended. Generally, an AGH is selected when free gas fraction is in the 20% to 45% range and MGH is selected for a range between 40% and 75%. DesignPro includes very useful tables at the right hand side of the gas separator and pump sections that provide key information about fluid volumes, gas fraction, etc. DesignPro can also limit stage type selection set to a certain percentage above and below Design Flow Rate. ######## 8.2.5 Pump Efficiency When considering multiple pump types for a given application, compare the efficiencies of the pumps for the given conditions. A higher efficiency pump will result in lower operating costs and may allow for a smaller motor hp selection. Radial vs. Mixed stage design: In certain circumstances, mixed flow stages are preferable over radial flow stages. Specifically, mixed flow stages handle gas, viscosity, and solids better than radial flow stages. But this improved handling is at the expense of head produced. Mixed flow stages produce lower head per unit length than radial stages, and using a mixed-flow stage may require going to a smaller pump series, both of which will increase the pump cost. DesignPro allows the user to compare pump type selection and results through the use of multiple cases. ######## 8.2.6 Determine Number of Stages Required The total head of the pump is determined by the number of stages and housing length choices. Each stage is able to develop a given head at a given speed. The application total head requirements (TDH) determine the number of stages required for the pump to deliver the required H/Q. **Equation 2-2:** DesignPro uses nodal analysis to calculate pressure differential across the pump and converts to head. It also suggests a number of stages under the pump section, once a stage type is selected. ######## 8.2.7 Housing Selection The second step is selecting a housing length (one or more) that will have the required number of stages. You will find that normally there are housings available with more stages and housings available with fewer stages than what you require. In these cases, select the housing with a greater number of stages than your calculated requirement. Matching number of stages to well TDH needs is a judgment call that requires a balance of extra stages with cost implications, changing well conditions, future needs, etc. Remember to adjust for actual motor speed before choosing a specific housing. Motor speed can have a large effect on stage requirements. Refer to product bulletins for more details on specific pumps. Use a single housing when possible. If you cannot fit all your stages in one housing, then you must use multiple housings, also known as tandem pumps (Refer to the following tandem pump section). In DesignPro, housing selection is done under the Housing/Intake tab in the pump section. Choices under the tab include floater and compression, and also bearing configurations such as ES and ARZ. ######## 8.2.8 Tandem Pumps The length of a single pump section is usually limited by shipping considerations (trucking, lifting) and practical pump construction and assembly issues such as thermal expansion, stage stack-up, etc. The following are guidelines to selecting and using tandem pumps: - Pumps installed in tandem should be of the same series. - Torque is at its peak at the bottom end of the lowest tandem pump (acting on the shaft). Moving up the pump, torque is reduced as stages transfer shaft hp to hydraulic power. In cost-sensitive applications, this may allow you to use lower strength shafts on the upper equipment, but it is recommended to standardize shaft types to avoid installation errors. - In long pumps with four or five tandem sections, make sure that shaft and housing material thermal expansion is compatible (consult InTouch when in doubt). Remember that the longer the string of tandem pumps, the more sensitive the combination is to pump stack-up, material thermal expansion (differential) and shimming. - Ensure that installers of tandem pumps have the latest shimming procedures and adhere to them. - Tandem pumps should preferably use the same metallurgy (Redalloy or CS) and construction (CR vs. FL) except for emergencies where it may be required to use existing equipment in tandem. DesignPro facilitates the selection of tandem pumps under the Housing/Intake tab in the pump section. DesignPro calculations will check if shaft hp limits and housing burst pressure limits are exceeded, and will warn the user accordingly. However, DesignPro does not check for thermal expansion or stack-up issues, and these will have to be addressed with engineering through InTouch or an RFQ when applicable. ######## 8.2.9 Pump Configuration Pumps used in ESP’s come in several different configurations. Most pumps (especially the smaller diameter ones) come as "center tandems" (or -CT type). Other types are "upper tandems" (-UT), "lower tandems" (-LT) and "single" (-S) pumps. The difference is mainly in the type of heads and bases used. ######## 8.2.10 Single Pump (S) An “S” pump has an intake and discharge head intrinsic to the pump itself. No other pumps can be attached to it. Built-in Discharge Head Main Body of Pump Built-in Intake **Figure 2-9: Single Pump** ######## 8.2.11 Center Tandem Pump (CT) A “CT” pump has neither a discharge nor an intake. “CT” pumps offer the most flexibility. If the required number of stages for the well cannot fit into a single section, more sections can be added until the stage requirement is met (normally limited to five sections). A CT pump cannot be used alone since a complete pump needs both a discharge head and an intake. Since a “CT” pump can be either a single (with a bolt-on discharge and intake added) or a part of a larger pump, inventory requirements are greatly reduced. For Example, a “CT” pump pulled from one well where a standard intake was used and placed in another well with a where a gas separator is required can easily be adapted simply by changing the type of intake. No alteration of the pump is necessary. No Discharge Head Main Body of Pump No Intake ( Common Flange) ( Common Flange) **Figure 2-10: Center Tandem Pump** ######## 8.2.12 Upper Tandem Pump (UT) An “UT” pump has a discharge head but no intake section. It can be placed on top of another pump or an intake section. The “UT” pump has either another pump below it or else an intake section to complete the assembly. It can be converted into a single pump by simply adding an intake section at the bottom. Built–in Discharge Head Main Body of Pump No Intake ( Common Flange) **Figure 2-11: Upper Tandem Pump** ######## 8.2.13 Lower Tandem Pump (LT) A LT pump an intake section but no discharge section. It can be placed below another pump or else can be converted into a single pump by simply adding a discharge head at the top. The lower tandem has either another pump above it or else a bolt-on discharge to complete the assembly. Lower tandems are especially common in the larger diameter, higher flow rate pumps. This helps to reduce entrance losses associated with higher flow rates and also, in some cases, allows a gas separator to be built directly into the intake where a standard add–on separator could not handle the fluid throughout. No Discharge Head Main Body of Pump Built–in Intake ( Common Flange) **Figure 2-12: Lower Tandem Pump** ######## 8.2.14 Combinations in Tandem Several combinations are possible. See [Figure 2-13](.) through [Figure 2-15](.) . Upper Tandem Lower Tandem **Figure 2-13: Upper and Lower Tandem Pumps** Upper Tandem Lower Tandem Center Tandem **Figure 2-14: Upper and Lower Tandem Pumps** Bolt–on Discharge Bolt–on Intake Center Tandem **Figure 2-15: Two Center Tandem Pumps with Bolt–on Head and Intake** Different types of Intakes, Gas Separators, Discharge Heads, and Advanced Gas Handlers are available for most pump series. They can be bolted onto pumps of the same series (400, 540, etc.) without the need for any adapters. To bolt on to another series of pump will require an adapter flange, and a longer coupling. **Table 2-39:** | Configuration | Description | Top connection | Bottom Connection | Use When | |------------------|-------------------------------------------------|------------------------|-----------------------------------|------------------------------------------------| | CT | Pure pump section | BOH, pump | Pump, AGH, MGH, Std. Intake, VGSA | General use, gives good flexibility | | UT | Pump section with integral tubing thread on top | Specific tubing thread | Pump, AGH, Std. Intake, VGSA | Tandem pump with exact tubing thread specified | | Configuration | Description | Top connection | Bottom Connection | Use When | |------------------|----------------------------------------------------------------------------------------|------------------------|---------------------|----------------------------------------------------------| | LT | Pump section with integral standard intake on bottom | BODH, pump | Protector | Tandem pumps with std. Intakes | | S | Pump section with integral tubing thread on top and integral standard intake on bottom | Specific Tubing Thread | Protector | Exact configuration known and lack of flexibility is OK. | In DesignPro, pump construction is selected under the Housing/Intake tab in the pump section. ######## 8.2.15 Stage Types and Pump Construction The submersible pumps used currently in the production of oil wells belong to the category of closed impeller, multistage, single suction and radial and mixed flow centrifugal pumps. The type of impeller determines the amount of flow available and the head developed. The main difference between radial, mixed flow and axial designs is in the pump impeller vane angles and the size and shape of the internal flow passages. The different types and shapes of stages are categorized into different Specific Speed (Ns) groups. Refer to pump technical references for more design details. ######## 8.2.16 Radial Flow Stage A radial flow (pancake) impeller has vane angles at close to 90 degrees, and is therefore, usually found in pump ranges for lower flow rates; hence it is a stage where the pressure is developed entirely by centrifugal force. This geometry is also more susceptible to the effects of the presence of free gas and solids fluids. Eye of the Impeller **Figure 2-16: Radial Flow Impeller and Diffuser** Impeller Diffuser **Figure 2-17: Radial Flow Stage** ######## 8.2.17 Mixed Flow Stage The vanes of mixed flow stages present a vertical (axial) component in its geometry, which allows the stage to handle more free gas than the radial flow stage. A mixed flow centrifugal pump is a centrifugal pump in which the pressure is developed by centrifugal and axial forces on the liquid. Eye of the Impeller **Figure 2-18: Mixed Flow Impeller and Diffuser** ########## Impeller Diffuser **Figure 2-19: Mixed Flow Stage** ######## 8.2.18 Axial Flow Stage The third stage type uses an axial flow design. Artificial Lift utilizes the helico-axial multiphase stage which can handle high percentages of free gas. The only use of this stage is in the MGH gas handling product which, like the AGH, is installed between the intake or gas separator and the pump. Axial flow stages are only used in gas handlers and not in submersible pumps. The figures below provide a view of the MGH stages. Refer to MGH product bulletins and training material for more details. Note that MGH gas handlers can be selected in DesignPro as part of the ESP system under the Gas Handler Devices tab in the pump section. Also, DesignPro prompts the user when free gas calculations indicate the needs for any type of gas handler. **Figure 2-20: Axial Flow Impeller (MGH) Figure 2-21: Axial Flow Diffuser (MGH)** **Figure 2-22: Axial Flow Stage (MGH)** ######## 8.2.19 Pump Construction The centrifugal pumps used in ESP’s come in two basic varieties: floater and compression construction. Pump construction mainly affects the way hydraulic thrust is handled. Compression pumps generally better handle wider operating range and higher thrust, when properly shimmed and matched to protectors. Construction type can be selected under the Housing/Intake tab in the pump section. ######## 8.2.20 Floater Pump Construction Each impeller is free to move up and down the shaft depending on the balance of forces (thrust) acting on it. Hence the impeller is allowed to "float" on the shaft between the diffusers above and below it. This is mostly used in smaller and medium sized pumps where thrust forces can typically be handled by thrust washers. In this floater construction, the shaft is held in position by a shaft stop near the top of the pump (keeps it from dropping off); and the thrust acting on the shaft is supported by the protector thrust bearing. Floater pumps have an appreciable shaft end play, and normally do not require any shimming. **Figure 2-23: Floater Construction Assembly** ######## 8.2.21 Compression Pump Construction In the compression construction, the impellers and shaft are assembled (along with diffusers) to form one impeller/shaft subassembly. The shaft and impeller become essentially one part and move together both rotationally and axially. Thrust forces acting on each impeller are not handled by each impeller, and by design are to be transmitted down through the shaft to the protector thrust bearing. Hence, compression pumps usually have a small amount of shaft end play and normally require some shimming to ensure proper transmission of shaft and stage thrust to protector thrust bearing. Shimming details are included in product technical references and the [ALFORM-D InTouch Content](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3255850) [ID 3255850](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3255850) . **Figure 2-24: Compression Ring Construction Assembly** Compression Ring (CR) and standard Compression (C) are the two main designs used to build compression construction pumps. They are different only in the manufacturing process that results in the compression design, and have the same guidelines and are treated the same from an application point of view. Compression pumps offer the advantage of transferring the downthrust from the bearing/diffuser contact to the protector bearing. Therefore, compression pumps can be used to reduce potential thrust problems, such as: - Operating below the minimum recommended operating flow rate, which allows the pump to extend its expected average run time. Note that operating outside the ROR normally drastically reduces pump efficiency. - Operating in poor lubrication conditions, such as in high GLR applications (high fraction of free gas passing through the pump). **Note** Note that it is required to select housing lengths and numbers in DesignPro to allow the software to calculate actual thrust in relation to selected protector capacity. Job design for compression pumps also have additional design considerations, such as: - Some compression pumps may experience shaft axial deflection issues under certain dynamic conditions. For more details on physics of shaft axial deflection refer to. [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=8029396) [8029396](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=8029396) - Some compression pumps may experience excessive thermal expansion issues due to high BHT, certain material combinations and longer equipment lengths. This may require thermal shimming corrections. For more details on thermal expansion refer to [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=7950669) [7950669](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=7950669) . ######## 8.2.22 Pump Performance and Curves Pump performance is fully described by a set of curves showing Head-Flow, power consumption and efficiency for a constant rpm. An example is shown in Fig. 13. The three main curves show the variation of head, power and efficiency with flow. Other parameters used to describe the pump performance are net positive suction head (NPSH) and specific speed (Ns). NPSH is more critical in HPS applications. **Figure 2-25: Pump Performance Curves** In the AEPAD view, the technical data section is above the pump curve. This section provides most of the basic pump information, at a glance. The left column shows the specific gravity of the fluid to be pumped, pump series and pump model. The center column shows physical parameters of the pump such as diameter, minimum casing size and shaft size and cross section area. The right column shows important physical limitations of the pump itself such as the recommended operating range and shaft horsepower and housing burst pressure limits. ######## 8.2.23 Definitions **Term Definition** **Flow rate (capacity)** is the volume of liquid pumped per unit time, and in the oil industry is generally measured in barrels per day (BPD). The application flow rate figure handled by the pump is usually the total flow, including any free gas (in gassy wells, for example). **Head** is the net work done on a unit volume of liquid by the pump impeller. It is the amount of energy added to the liquid between the suction and the discharge sides of the pump. Pump head is measured as lift/head difference between the discharge and suction side of the pump. Head is usually expressed in feet (ft) or meters (m) of liquid (Lift). Horsepower curves are shown on the chart and give the horsepower required to operate the pump within a certain range. The horsepower can be calculated with the total head, flow rate and efficiency at the operating point. Pump HP can be expressed as: **Equation 2-3:** where, Efficiency is the fraction of power input to the pump shaft that is transferred to the liquid. Typical pump efficiencies are in the 60 to 70% range. The graph in fig 13 represents the performance of one stage of the SN8500 pump at 60 Hz (one speed/rpm). Pump performance curves change with speed/rpm in such a way that the performance curves preserve their characteristic features. The key pump characteristics (H/Q, P, and Eff) generally follow the pump affinity laws when rpm is varied. The equations below describe how these parameters change with the speed. **Equation 2-3: Flow rate or capacity** *Flow varies proportionally with speed* **Equation 2-4: Head** *Head varies in proportion to speed squared* **Equation 2-5: Brake horsepower** *hp varies in proportion to speed cubed* However, the multi-speed or VSD curves (fig. 14) available in AEPAD and in DesignPro provide the best quick reference and graphical description of performance. These curves can be a good first tool for an AE before making decisions on equipment selection. The performance curves are obtained by running the pump at a constant speed and varying the flow rate. The flow rate, pressure and brake horsepower are measured for at least five points. The pressure is converted to head based on the working fluid specific gravity, usually water. The overall efficiency is calculated based on the flow rate, head and break horsepower. Note that performance curves reflect the actual testing of a set of pumps. All commercially produced REDA pumps are tested prior to delivery to the field, either in factory or Art center. API recommended practice (API RP11S2) is used to evaluate tested pumps. **Figure 2-26: Head vs Flow Rate – Multiple Frequency Curves** ######## 8.2.24 Pump Operating Range and the Best Efficiency Point (B.E. P.) The yellow zone in a typical pump curve represents the recommended operating range (ROR). The ROR is the flow range where the pump is expected to deliver the best hydraulic performance with minimum thrust forces (axial) acting, either upward or downward, on pump stages. In other words it is the range where efficiency is at a maximum range, and stage wear is at minimum. It is generally recommended to aim for the ROR when selecting an ESP pump, taking into consideration the total flow including free gas, possible changes over the expected lifetime of the pump, and any changes to Hz/RPM. When the pump is operated outside the recommended operating range limits the pump hydraulic efficiency usually drops appreciably, depending on curve shape; which means the pump delivers much lower H/Q for same hp or requires much higher hp to maintain a certain H/Q. Pump wear also increases when operating outside the ROR, particularly for floater pumps (FL). Compression pumps operating outside the ROR would suffer a decline in hydraulic performance, but wear is normally unchanged from BEP as long as shimming is correct and thrust bearing capacity is not exceeded. **Axial thrust, Down-thrust and Upthrust** The axial thrust acting on a pump impeller is the sum of three forces: weight of the impeller immersed in the fluid (always downward) seen in [Figure 2-27](.) , the net force resulting from the differential pressure across the stage (either downward or minimal at wide open) seen in [Figure 2-28](.) , and the force from the momentum of the fluid coming into the stage (either upward or zero; zero occurs at shut-in or no flow condition) seen in [Figure 2-29](.) . **Figure 2-27: Weight of the Impeller in the Fluid** **Figure 2-28: Net Force Resulting from the Differential Pressure in the Stage** **Figure 2-29: Force from the Momentum of the Fluid** In general, a pump is considered to be in downthrust when the operating point is to the left of ROR, and in upthrust when the operating point is to the right of the ROR. However in reality, the limits of ROR do not always mean a sudden change to extreme thrust, leading to rapid wear and deterioration. Pump performance has to be analyzed on a case by case basis, in order to decide on the pros and cons of any pump operating point/range. Also, note that most pumps are designed to be run in slight down thrust, especially floater pumps. On the other hand, smaller size floater pumps are more sensitive to changes in flow and may shift quickly from down thrust to up thrust. Larger size pumps, especially in compression construction almost never operate in extreme up thrust. Compression construction is preferred when operating range is expected to be outside the ROR, particularly on the lower end (left hand side) of the pump flow range. For more information on downthrust calculations, refer to the protector thrust bearing section. **Figure 2-30: Upthrust and Downthrust approximate range in the Chart** ######## 8.2.25 Gas Separation and Handling When an appreciable amount of free gas is present in the bottom-most few impellers, it takes up usable space (volume) and restricts the volumetric efficiency of the pump. The result is a decline in expected production and amount of head developed. If a few stages are completely filled with gas, the pump may stop producing lift, and flow to surface stops. This condition is known as gas lock. The pump stage type affects its ability to handle free gas. A Radial pump can typically handle from 10 to 15% free gas by volume, and mixed flow stages can handle from 15 to 25 % free gas by volume. These are guideline figures only. When the estimated free gas at the pump intake is higher than the respective stage type can handle a gas separator and/or an AGH or a MGH should be used. DesignPro prompts the user when gas handling equipment is required. For quick information on amounts of free gas, before and after separation, and total volume, refer to the summary tables shown at the right hand side of the gas separator and pump sections in DesignPro. A typical ESP pump has to handle the amount of free gas that enters the system, after natural and mechanical gas separation. Order of magnitude figures for gas separation in typical ESP applications are 5 to 30% natural separation (20% most common in vertical wells), and 50 to 90% mechanical separation (check GS graphs). DesignPro provides a good estimate of gas volume fraction entering the pump. In DesignPro, the decision to select an intake or a gas separator is made under the Gas Separator section. Note that DesignPro requires that you to either calculate natural separation or enter a user defined figure. ######## 8.2.26 Standard Intakes The pump intake is the point at which the fluid enters the pump. There are many types of intake Sections: Standard or bolt on intake (BOI), Integral intake (included at bottom of single or LT pump in factory); and gas separators that do both functions of fluid entry into pump while separating some of the gas. In standard (and integral) intakes, the size of fluid passages are designed to assure low losses even at the highest flow pumps of the series. In gassy applications, some natural gas separation might occur due to change of direction of fluid and the related changes in fluid pressure. Typical natural separation is in the order of 20 to 30% in vertical wells and may exceed 40% in deviated wells. **Figure 2-31: Bolt 0n Intake (BOI)** Lateral support for the intake shaft can be either AR type (Abrasion Resistant), which is the preferred configuration, or standard. It is recommended that only AR type intakes be used whenever possible, because the reliability of the system will be greatly enhanced by the added durability of the AR bearing system (such as compliant Zirconia bearings – ARZ). This is particularly true when the system is handling abrasives. Also, the use of Improved lateral support in the intake or gas separator in abrasive environment, helps continued lateral support to neighboring components such as the top protector seal and the bottom most stages in the pump. Intakes are available in various combinations of Carbon Steel and Redalloy, Monel and Inconel shafts, ARZ, ARZ-SS and ARZ-ZS bearing pairs for all pump series. ######## 8.2.27 Gas Separators There are two types of gas separators: - static - dynamic. **Static Gas Separators** Original gas separator designs were based on increasing gas separation by forcing the fluid flow to reverse direction in the wellbore. This is where the name of this type of gas separator, Reverse Flow, comes from. Since this type of gas separator does no real "work" on the fluid, it is also called a "static" gas separator. Static gas separators are obsolete and are currently seldom used. **Figure 2-32: Static Gas Separator** **Dynamic Gas Separators** Dynamic gas separators actually impart energy to the fluid in order to get the vapor to separate from the liquid. The original gas separator was called a KGS. This design uses an inducer to increase the pressure of the fluid and a centrifuge to separate the vapor and the liquid. This design could likewise be called a centrifugal gas separator. The rotary gas separator design works in a similar fashion to a centrifuge. The first model had centrifuge "paddles" spinning at 3500 rpm and was believed to cause the heavier fluids to be forced to the outside, through the crossover and up into the pump, while the lighter fluid (vapor) stays toward the center, and exits through the crossover and discharge ports back into the well. **Figure 2-33: Rotary Gas Separator** The latest and most advanced dynamic gas separation device available is the VGSA Vortex Gas Separator. This dynamic separator represents several years of testing and development that provides improved separation efficiency and reliability. **Figure 2-34: Vortex Gas Separator** The lower section imparts velocity to the mixture and starts separation (Vortex). The upper section separates gas and liquid phases, and converts velocity into positive pressure. The vortex gas separator is currently available in 400 and 538 Series, VGSA D20-60 in 400 series and VGSA S20-90 and S70-150 models in 538 series. It is available in many metals and bearing and trim combinations. Use DesignPro menu’s for selection, and OneCAT to check available models. Similar to pump selection, the total fluid volume (O+W+G) must be within the permissible operating range of the Gas Separator selected for the application. DesignPro side tables under the Gas Separator and Pump sections provide the required calculation summary and information to check total volumes. Related InTouch Content IDs: [2039194](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2039194) , [3323376](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3323376) , [3016123](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3016123) , [4231340](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4231340) . ######## 8.2.28 Gas Handling Devices A Gas Handling Device is a pump add-on that fits between the intake or gas separator and the bottom-most pump section. The AGH modifies or conditions the liquid-free gas mix into a more homogeneous fluid that is easier to handle by the pump stages. There are two types of Gas Handling Devices: Advanced Gas Handler (AGH) and the Multiphase Gas Handler (MGH). Advanced Gas Handler (InTouch Content IDs: [3279150](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3279150) , [3014164](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3014164) , [2036790](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2036790) , [3014067](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3014067) , [4033130](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4033130) ) The primary aim of the Gas Handling device is to avoid "gas-locking" in the pump, and assure continuous flow. The AGH improves the overall efficiency of many submersible lift systems in comparison to those employing gas separators only. In many cases, the AGH can allow successful production of wells with higher production stability and increased draw-down, improving well economics for many types of wells. This is achieved through the ability of AGH to handle higher GVF and reduced gas locking and underload (protection) trips. Examples of the typical amp charts below, with and without an AGH, show the difference. **Figure 2-35: Amp Charts Showing the Effect of the AGH on the ESP Operation** The AGH improves the ESP ability to handle gas by: - Homogenizing the mixture and reducing the bubble size - Putting some free gas back into solution - Facilitating gas movement into the main stream flow. In general, an AGH should be considered if the following conditions exist at the intake of the pump: - Free Gas Percentage = 20 to 40% by volume (or greater) - Intake VLR = 0.25 bbl/bbl (or greater) - The maximum Free Gas Percentage the AGH can handle is 45%. The AGH can be used with a standard intake or with a gas separator. The choice will depend on how much free gas will be present at the intake for producing condition, and on whether there is a packer preventing gas production up the annulus. Gas separators cannot be used below packers unless there is a method to vent the gas. **MGH** (InTouch Content IDs: [3844523](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3844523) , [3379907](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3379907) , [3924403](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3924403) , [3923532](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3923532) , [3923113](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3923113) ). The MGH multiphase pump is a more advanced form of gas handler. The main difference is that the MGH uses stages of a unique and patented helico-axial stage design. In a high GLR application, the MGH pump primes the main centrifugal production pump and pushes the gas-liquid flow stream into the centrifugal stages. Any free gas is compressed in the MGH, reducing the gas volume factor (GVF). A unique property of the MGH stage (helico-axial) is its ability to retain high boost pressure as the amount of inlet gas fraction increases. Similar to an AGH, the MGH multiphase pump/gas handler is installed above a gas separator when gas can be vented in the casing, or above an intake if all the produced gas has to go through the submersible pump (in presence of packer). The MGH can handle a maximum of 75% (at 60 Hz) free gas without pump gas lock compared to a maximum of 45% for the AGH. ######## 8.2.29 Pump Operation in Abrasive Environment Handling of abrasives is one of the main challenges for ESP pumps. Solutions for handling abrasives in pumps typically use advanced material to delay the wear of key components such as bearings in heads and bases and in stages. Abrasives are field specific, and vary in their effect on pumps. Key variables are, abrasives amount (per unit flow), size, shape, and material (hardness). While there is no universal solution to abrasive application problems; the best approach and practice usually involves establishing a starting point based on a set of advanced bearings and material, and incremental improvements thereof. Best practice, in other words, involves the use of standard solution as a starting point (such as using an ARZ pump) and then using local learning to improve performance. Note that while compression pumps reduce the axial wear on stages, they do not prevent radial wear erosion, which increases with presence of sand, abrasives and fluid velocity. For more information on abrasive applications refer to InTouch Content ID : [3264050](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3264050) , [3251800](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3251800) . ######## 8.2.30 Pump Performance De-rating Typical ESP pump performance curves are based on tests done using fresh water, as described in the previous pump performance section. De-rating pump performance is the task of determining suitable de-rating factors to flow, head, and power (applied to original water based standard curves). This is done to estimate the pump performance deterioration caused by well fluid conditions. The most common fluid conditions that require pump de-rating are: - High well GOR/GLR causing a high percentage of free gas to enter the pump. - High viscosity fluids. Performance degradation depends on viscosity or amount of free gas in pump. ######## 8.2.31 High GLR Gas has two main effects on pump performance: Reduced volumetric efficiency and Gas locking. As the fraction of free gas entering the pump increases (also known as gas volume fraction, GVF), the volume of liquid entering the pump decreases, causing reduced volumetric efficiency. Also, the ability of each stage to produce head becomes less because part of the energy is used to compress the gas (some of it goes into solution, depending on PVT). As gas increases further, liquid would not flow from one stage to the next; this is where gas lock happens and the flow to the discharge stops. DesignPro calculates gas compression or gas going back to solution on a stage by stage basis (depending on choices made under the Advanced tab in the pump section). However, DesignPro does not de-rate or suggest de-rate factors for pump performance automatically. It provides de-rate factor entry boxes in the top right hand side of the Advanced tab. Refer to AE training material, DesignPro tutorial ( [4011832](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4011832) ) and existing related InTouch content for more details ( [3941862](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3941862) , [2036790](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2036790) ). ######## 8.2.32 Viscous Fluids ESP pump performance curves are generated using fresh water, as mentioned earlier. Water and most low viscosity oils have low and constant viscosities, which means the resistance to flow is low and they respond to higher forces acting on the fluid by increasing their velocity (act as a Newtonian fluids). This increase in velocity is what ensures flow from one stage to the next. In these cases pump behavior is close to original water based curves and de-rating is not necessary. At high viscosities (oil), the fluid velocity does not increase in proportion to impeller forces acting on it. This is due to higher fluid shear losses within the fluid itself. In these cases pump performance de- rating becomes necessary. High viscosity fluids typically being produced by ESP’s can be viscous heavy oils, mixture of heavy oils with water, and/or the presence of emulsions formed by the mix. From a practical ESP application point of view, it is important to note the following: Fluid viscosity is not a weighted property. In other words the resistance to flow caused by viscosity does not vary in proportion to oil/water ratio. Pump stage surfaces predominantly encounter either water or oil. In the absence of emulsion formation, field experience tells us that stage surfaces encounter water-only viscosity when water cut is above 40% to 50%. Oil becomes the dominant fluid when water cut is less than 40% or so (stages working against oil-only viscosity). As such, we can say that we have oil-in-water flow in high water cut cases; and water-in-oil flow in low water cut cases. The following is a summary of key observations and application recommendations: - Oil-Water emulsions develop more common with API 21 oils or lower. - Emulsions form more commonly in the 40 to 60% water cut, but are possible in the 20 and 80% range. - DesignPro calculates viscosity corrections based on built in correlations, if operator does not enter specific corrections. - DesignPro will calculate emulsion related viscosity corrections, provided the user specifies that emulsion exists on the viscosity data screen. - There is no substitute to field modeling based on field specific tests and experiences, to establish local correction factors (most accurate). - Viscosities can differ from field to field and one part of the world to another, for the same API heavy oil. Local experiences can be useful to other areas as learning points, but are seldom transferable “as-is”. - DesignPro has an option in the advanced tab of both the pump and motor sections to calculate the effect of heating on fluid (heating reduces viscosity). - Pump type: Use large vane pumps (mixed flow stages) that result in lower resistance to flow and better performance. Also, Compression Type Pumps and Abrasion Resistant (AR) construction and High Strength Shafts help enhance reliability and flexibility. - Diluents can be used to reduce viscosity of fluid produced; but they have to be matched to specific fluids and well conditions after tests are made. - ESP applications beyond a viscosity range of 1000 cP have to be carefully analyzed and other AL alternatives may be advantageous. - High starting torque for high viscosity applications is a main application concern in regards to shaft limits and type and rate of starting. It is recommended to make sure shaft can handle the additional torque. - Surface equipment sizing: Oversize surface equipment to account for cold well starting and the resulting additional amps. - De-rate and oversize the motor to account for reduced motor cooling caused by high viscosity. - Not the difference between live oil versus dead oil testing, and the effect on the application at hand. - Work closely with customer to ensure that data is accurate and up to date, and that past experience in their field is well understood and utilized. Compare lab tests with any field experience provided by customer. - Downhole monitoring is critical to optimization and success, so a downhole sensor is a good investment and can provide crucial information on temperature (viscosity), motor temperature, and differential pressure and flow. - Use a VSD for improved starting properties and flexibility later on in system life. For more details on viscosity correction, refer to InTouch Content ID : [4412053](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4412053) , [3843734](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3843734) , [4062226](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4062226) , [3563364](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3563364) and to DesignPro tutorial [4011832](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4011832) . ####### 8.3 Constraints and Limitations The following are the main physical limitations, which must be checked for every pump selection. - Shaft maximum horsepower rating - Housing maximum pressure rating - Maximum thrust generated Several limits are directly related to the pump, while others are due to motor and protector designs. Regardless, they all limit the number of stages, hence the lift that can be produced. Shaft maximum horsepower rating The amount of torque required to break the shaft is constant regardless of the speed. It just happens that hp and torque are related by the equation below. As long as we know what the torque is, we can calculate the horsepower limit at any speed. (Remember that we assume speed changes in proportion to the frequency.) **Equation 2-4:** Housing maximum pressure rating The pump exerts a pressure on the inside of the pump housing. Note that although the head is constant for a pump, the pressure developed varies with the specific gravity. The housing has a surface area which translates internal pressure into a force acting on the housing and the head (peak pressure) and base. The housing contains the pressure through its hoop strength, but it is often that the head thread is the weak point. Maximum thrust generated The amount of down thrust transferred to the protector thrust bearing varies with construction type (refer to previous section on subject). The compression pump transfers all down thrust generated to the protector, while the floater transfers only shaft thrust. The maximum shut-in pressure is calculated and compared to thrust bearing capacity in DesignPro, once the pump housings are selected. Other physical limitations are related to special configurations applied to high volume/flow 400 and 387 series pumps and related equipment. This includes the re-positioning of the coupling position below the pump neck and into the head below it to avoid flow restrictions. These special configurations include “deeper” heads, extended shafts (below their normal settings) and special couplings. Examples are the D5800N and the D4300N pumps and related equipment. DesignPro calculates and produces warnings on most critical physical limitations to the application. These warnings show up just after selections are made, and a summary is available under the Limits report. ####### 8.4 Material Selection Pump material are selected to suit well and production conditions such as: - Corrosion (CO2, H2S, acids, Chloride ions, Oxygen, etc.) - Erosion and erosion-corrosion - Thermal expansion (differential) - Requirement for higher strength shafts - Abrasives entering ESP systems - Special pump and stage coatings [InTouch Content ID 4062226](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4062226) . - Elastomers ( [InTouch Content ID 3315714](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3315714) ) Standard pump material includes carbon steel for housings and heads and bases, Monel shafts, and Ni-resist stages. HSN elastomers are standard. Redalloy (9% Cr and 1% Moly) is the most common material used to improve corrosion resistance over CS in CO2 environment. Higher metallurgies include 13% Cr, 22% Cr and 25% Cr, but these are needed only in extreme cases of CO2 and shallow aerated applications, and will have to be analyzed and recommended by metallurgy experts and agreed with customers as they are very expensive and have long deliveries. Monel shafts are suitable for most standard applications. Inconel is used when high strength shafts are required. Differences in hp can be seen in OneCAT and AEPAD, and limits are calculated in DesignPro. Pump trim includes bolts, plugs, etc and can be upgraded to SS or to Monel depending on application. It is important to make sure that material selection for pump, protector, motor, cable etc. is uniform and consistent with environment conditions. There are a few guidelines to follow in selecting ESP system material including metallurgy and elastomers. These guidelines can be found in InTouch. Completions and other Help Desks, including metallurgy and partial pressure calculators ( InTouch Content IDs [3463922](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3463922) , [4325230](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4325230) ) and elastomers ( [3315714](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3315714) , [4118158](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4118158) , [3441315](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3441315) , [3285748](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3285748) ). For more challenging cases, and specific material-matching to well conditions, an expert must be consulted through InTouch. ###### 9 Protector ####### 9.1 Protector Basics The Protector has four primary functions: - couples the torque developed in the motor to the pump via the protector shaft. - prevents entry of well fluid into the motor. - provides pressure equalization. - houses the bearing to carry the thrust developed by the pump. ####### 9.2 Protector Configurations [Figure 2-36](.) , [Figure 2-37](.) and [Figure 2-38](.) shows basic parts of the protector. **Figure 2-36: Modular Protector System** **Figure 2-37: Labyrinth Protector** **Figure 2-38: Positive Seal/ Bag Protectors** ######## 9.2.1 Series and Parallel Connections A protector will always have multiple chambers. These chambers can be connected in series (designated with an “S”), which results in a redundant seal, or in parallel (designated with a “P”), which results in larger capacity. Parallel connections are only possible with positive seal chambers – i.e. bags or bellows. A parallel connection between two bellows is possible, when the bellows are also available in variable lengths, which accomplishes the same result (larger capacity). Contact InTouch for help when selecting advanced protectors for the first time. As noted above, a parallel connection results in a larger volume capacity, which is necessary for high power applications. Series connections, however, result in redundant seals, increasing the reliability of a protector. Bag type protectors should be considered for applications where frequent cycling is anticipated. In deviated wells the bag chamber section should be installed on top to prevent contamination of the labyrinth chamber motor oil. In vertical wells the bag chamber section may be installed on the bottom for increased protection of the bag from chemical attack by the well fluids. ####### 9.3 Protector Configuration Selection When selecting a protector, major considerations should be taken: - compatibility with pump and motor - casing clearance when cable is installed - use of labyrinth or bag type design - fluid expansion capacity - ratings for temperature and exposure to chemicals. Generally, the protector will be selected in the same nominal diameter as the pump. An alternate diameter protector may be used if the shaft, thrust and oil expansion capacity are adequate. **Table 2-40: Protector Compatibility** | Protector Series | Motor Series | Pump Series | |--------------------|----------------|----------------------| | 325 | 375 | 338 | | 387 | 456 | 387 | | 400 | 456 | Any | | 387 or 400 Maximus | 456 Maximus | Any | | 540 | 540 or 562 | 400, 540 or 538 | | 562 | 562 | 562-Series or larger | | 738 | 738 | Any | | 950 | 738 | Industrial Pumps | **Note** Have proper head and base flange designs for connection to the pump and motor, or select an adapter kit to make the connection. The 562 Protector is exactly the same as the 540 and, in fact, uses the same parts. The 562 has an enlarged thrust section and larger bearing and thrust runner for high thrust applications. ######## 9.3.1 Chamber Selection **Table 2-41: Types of Protector Chambers – Application Advantages and Disadvantages** | Configuration | Advantages | Disadvantages | |---------------------|----------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Labyrinths (L) | Excellent separation in vertical wells with high WC. Easily serviceable and reusable. Inexpensive. | Deviations over 45 deg are questionable; deviations over 70 deg render the labyrinth practically useless. Oil well fluid density problems depend on the type of motor oil, but typically anything lighter than 0.85 SG (35 deg API) is dangerous. | | Bags (B) | Positive seal and can be used regardless of deviation or well fluid density. | Chemical attack is a problem, High H2S content. High hp. High temperature | | Parallel Bags (BPB) | Same as single bag but larger volume capacity | Chemical attack is a problem, High H2S content. Select elastomer based on temperature. | | Configuration | Advantages | Disadvantages | |------------------------|-------------------------------------------------------------------|--------------------------------------------| | Bellows (M) | Positive seal, high temperature, no chemical compatibility issues | Cost is an issue. Advanced protector only. | | Parallel Bellows (MPM) | Same as normal metal bellows but larger volume capacity. | Cost is an issue. Advanced Protector only. | **Table 2-42: When to Use Parallel Bags** | Protector Series | Above Motor hp (60-Hz rating) | |--------------------|---------------------------------| | 456 | 108 | | 562 | 150 | Three-chamber protectors are recommended for standard normal conditions. Extreme situations may require four chambers. In a three-chamber protector, the user can select from two to four shaft seals, depending on the chambers and connection types. **Example** Standard protectors only: - Two Seals: LSBPB & BSBPB - Three Seals: BPBSL, LSBSB, LSLSB, BSBSB & BSLSB - Four Seals: LSLSL & LSBSL **Note** The LSLSL protector is generally not recommended. ######## 9.3.2 Four-Chamber Protectors For 400-series and 540-series protectors, you may opt for the increased protection of a four- chamber protector, such as LSBPBSL (solving the problem of where to put the Labyrinth) or BPBSBPB (solving the problem of high-volume in highly deviated wells). The 562-series protectors are not available in the four-chamber configurations due to potential shaft buckling problems. Only one four-chamber protector is currently available in the catalog (400-series LSBPBSL). Others should be ordered through Rapid Response. ######## 9.3.3 Sizing Criteria – Thermal Cycling The required oil expansion capacity of the protector is a function of the total oil volume in the motor and protector and the maximum thermal cycle the unit experiences during installation and operation. Usually the motor/protector assembly is at the lowest temperature during installation. The highest temperature will typically occur when the motor has reached operating temperature downhole. The following illustrations show the life cycling of a specific protector configuration. Protector bags are subject to collapse due to oil contraction caused by cooling at motor shutdown or equipment pull. [Table 2-43](.) gives recommendations for protector bag configurations based on operating or pull conditions. **Table 2-43: Protector Sizing Recommendations** | Protector Series | Bag Configura- tion | Motor Series | Max Rotors Operating | Max Rotors Pull | Max Rotors Pull | |--------------------|-----------------------|----------------|------------------------|-------------------------------------|-----------------------| | 400 | Single Bag | 456 | 3 X 18 | 1 X 18 at 200 degF Max BHT | | | 400 | Parallel Bag | 456 | No Limit | 2 X 18 at 200 degF Max BHT | 1 X 18 BHT > 200 degF | | 540/562 | Single Bag | 540 | No Limit | 1 X 20 at 220 degF Max BHT | 1 X 15 BHT > 220 | | 540/562 | Parallel Bag | 540 | No Limit | No Limit BHT < 200 degF | 2 X 20 BHT > 200 | | 540/562 | Single Bag | 562 | 2 X 15 | 11 Rotor Single Max at BHT 200 degF | | | 540/562 | Parallel Bag | 562 | No Limit | 2 X 10 at 200 degF Max BHT | 1 X 15 BHT > 200 degF | **Note** Use the DesignPro protector sizing check capability. ######## 9.3.4 Speed Effect/Heating Because the power waveform is not sinusoidal, operating an ESP with a non-SineWave variable speed drive will cause increased motor heating, which results in additional oil expansion. The protector must have adequate capacity to accommodate motor oil expansion at the highest anticipated operating speed. DesignPro provides the Total Winding Temperature and also specific adders for VSD impact under the heat rise tab on the Motor screen. If the application is a VSD application, the appropriate temperature adders should be included with the Total Winding Temperature for consideration of the oil expansion in protector sizing. Shaft torque and thrust bearing capacity should also be checked at the highest operating speed since pump torque and thrust increase with speed. ####### 9.4 Thrust Bearing Selection The pump thrust characteristics will determine the required thrust bearing capability. The thrust load rating for the protector bearing should be greater than the highest possible thrust load for the application. DesignPro does this calculation and gives a warning if the trust bearing limit has been exceeded. HL and HL Glacier (GTB) thrust bearings are uni-directional. The load ratings in : are published with the consideration that the shaft/runner rotates in forward (counterclockwise) direction, but they have much reduced load rating in reverse (clockwise) direction which will be the case in back spin situation when there is no check valve and with many start-stops. Note that HL and HL Glacier (GTB) thrust bearing load ratings are considered to be the same. On the other hand, KTB is bi-directional thrust bearing. It has the same load rating regardless the shaft rotation direction, whether in forward (counterclockwise) or reverse (clockwise) direction. Due to its bi-directional design, KTB is recommended for wells with no check valve and with tendency of many start-stops that cause back spin. Based on the expected pump down thrust, refer to the thrust bearing load ratings in : to determine the oil type required and ensure that both the protector and motor have the same oil type. Oil selection should consider temperature limits and guidelines published in [Table 2-46:](.) . In the cases where there is a need to change oil type in existing on stock equipment, the units need to be sent to ART center for oil change. Note that when equipment with different REDA oils mixed in one ESP string (for example due to limited availability on stock), the lowest thrust bearing load rating should be considered for the application. In the cases where the well conditions are very aggressive, including constant failures of standing valves, back spin, multiple shutdowns, and no/low flow conditions, and if HL or KTB thrust bearings could not survive the conditions, RTB, a bi-directional ceramic bearing, could be the solution. ######## 9.4.1 Downthrust for Floating Impeller Pumps *Downthrust in lbf = (Maximum head at shut-in in ft/stage X number of stages X specific gravity of the fluid X 0.433 psi/ft) * pump shaft cross-sectional area in square inches* The worst-case scenario, when the flowrate is zero. It should be evaluated to simulate production against a closed production valve. **Note** Note that this value will be impacted by the frequency the pump is running at. ######## 9.4.2 Downthrust for Compression or Fixed Impeller Pumps Each type of pump has a distinct compression downthrust determined from testing, which is usually published in the Product Bulletin of the specific pump. See [InTouch Content ID 3285770](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A3285770%2A) for more details. The highest downthrust point may or may not be at zero flow but it should be used in the calculations and is the point used in DesignPro. It is provided for 60 Hz and for one stage so the adjustment for RPM and number of stages must be made. All phases of operation that directly impact thrust should be considered, including the pumping of heavy fluids. Each protector series has several thrust bearing options. When selecting the thrust bearing, you must consider: - the temperature rating of the bearing, - the oil used in the protector, - the load rating. In general, but not always, thrust requirements higher than standard are due to compression pumps. Consult [Table 2-44](.) and [Table 2-45](.) for available thrust bearings. **Table 2-44: Thrust Bearing Types** | Abbreviation | Full Name | Properties | |----------------------|----------------------|-----------------| | STB | REDA Babbit | Bi-directional | | NTB | REDA Bronze | Bi-directional | | KTB | KMC Bronze | Bi-directional | | RTB | REDA Silicon Carbide | Bi-directional | | HL, HL Glacier (GTB) | High Load Tilt Pad | Uni-directional | **Table 2-45: Bearing Thrust Limits and Temperature Ratings** | Series | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | Thrust By Bearing Type - Maximum Thrust Load (lbf) | |---------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------| | Series | STB | NTB | NTB | KTB | KTB | HL, HL Glacier (GTB) | HL, HL Glacier (GTB) | RTB | RTB | | Series | STB | #2 Oil | #5 Oil | #2 Oil | #5 Oil | #2 Oil | #5 Oil | #5 Oil | #6 Oil | | 325 | - | 900 | 1100 | 2010 | 2450 | 2500 | 3200 | - | - | | Maximus 325 | - | - | - | 2010 | 2450 | 2500 | 3200 | 6000 | - | | 375 | 995 | - | - | - | - | - | - | - | - | | 387/400 | 1600 | 1600 | 2000 | 3900 | 5070 | 8600 | 11180 | - | - | | Maximus 387/ 400 | - | - | - | 3900 | 5070 | 8600 | 11180 | 12500 | - | | Agile 400 (1) | - | - | - | - | - | - | - | - | 11000 | | 540 | 2550 | 2550 | 3200 | 9500 | 11500 | 12000 | 15000 | - | - | | Maximus 540 | - | - | - | 9500 | 11500 | 12000 | 15000 | 25000 | - | | 562 | - | - | - | - | - | 17500 | 21500 | - | - | | Maximus 562 | - | - | - | - | - | 17500 | 21500 | - | - | | 738 | 3500 | 3500 | 4400 | 8500 | 21400 | 20000 | 33000 | - | - | | Maximus 738 | - | - | - | - | - | - | - | - | - | | 950 | 7850 | - | - | - | - | 44000 | 55000 | - | - | | Maximum Temperature | Temperature Rating for Bearings (degF) | Temperature Rating for Bearings (degF) | Temperature Rating for Bearings (degF) | Temperature Rating for Bearings (degF) | Temperature Rating for Bearings (degF) | Temperature Rating for Bearings (degF) | Temperature Rating for Bearings (degF) | Temperature Rating for Bearings (degF) | | | Maximum Temperature | 190 | 250 | 250 | 350 | 350 | 350 | 350 | 350 | 350 | (1) The load rating for bearings in high-speed equipment is valid from 6000 to 10000 rpm. Operation below 6000 rpm is not recommended. **Note** For standard equipment (i.e., Maximus, Modular, Advanced, etc.), the maximum thrust bearing load applies to frequencies of 60 Hz and above. The thrust load is affected by the affinity laws for frequencies below 60 Hz by the ratio of the design frequency / 60 Hz. For example, the maximum load for **KTB in Maximus 400** at 50 Hz is equal to 4225 lbf (50 Hz/60 Hz * 5070 lbf). The maximum load for **KTB in Maximus 400** at 63 Hz is 5070 lbf. **Note** For high-speed equipment (i.e., Reda Agile), the maximum thrust bearing load is for **all** operating speeds from 3600 rpm up to 10,000 rpm (or VSD frequency of 171 Hz). The thrust load is affected by the affinity laws for speeds below 3600 rpm by the ratio of the design speed (rpm) / 3600 rpm. For example, the maximum load for **RTB in Reda Agile 400** at 3000 rpm is 9167 lbf ( *3000rpm/ 3600rpm x 11000lbf* ). The maximum load for **RTB in Reda Agile 400** at 6000 rpm and at 10000 rpm is 11000 lbf. **Note** In addition to the downthrust bearing, the protector will also come with an upthrust bearing to assure that the shaft has a limit to upward motion. This bearing will have identical properties to a downthrust bearing of the same series, but will likely have a different specification (e.g. NTB upthrust with HL downthrust). The OneCat description of the protector will include the upthrust bearing, then a slash (‘/’), and then the downthrust bearing. A protector will not support the upthrust generated in the pump unless the pump uses a special feature called ‘pinned shafts’, common only on bottom-discharge equipment. ####### 9.5 Shaft HP Capacity One other function, which a Protector carries out, is transmission of the motor torque to the pump since it is physically located between the two. Although this may seem a little trivial, in the selection process we need to be certain that the protector shaft is capable of delivering the full torque required without exceeding its yield strength, which could result in a broken shaft. DesignPro does this calculation and provides a warning if the protector shaft capacity has been exceeded but it does not carry all the material option limits. Standard shaft is usually standard Monel, and high strength shaft is usually Inconel 625. Visually check in the Limits report to see what limit is being used. Protector shaft sizes are fixed for a given protector series, but there are several shaft strength options for most. Similar to intake shafts, the protector shafts tend to be large compared to pump shafts, but always double check, especially in high hp applications. The 562-series protectors are only available in high-strength shafts. Refer to [InTouch Content ID 3761235 REDA Equipment Shaft HP Limits](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3761235) which provides horsepower limits for different shaft materials ####### 9.6 Seals Schlumberger standard shaft seals today use stainless steel parts, Monel spring, Silicon Carbide faces, and either HSN or Aflas for the bellows and O-ring. There are some special seals used on bottom intake, bottom discharge, and Hotline protectors (special applications). These seals use the metal bellows instead of the elastomer bellows due to possible sudden pressure changes or temperature. Some of these seals may use Hastalloy-C, Inconel, Chemrez O-ring, but typically use Silicon Carbide faces. ####### 9.7 Oil Selection The oils to be used in motors and protectors should be determined by the internal temperature of the motor in the string. The same oil should be used in both the motors and the protectors in the same string of equipment. [GeMs](http:\www.gems.slb.com\ematrix\emxLogin.jsp) document ED-191 is a guideline for the selection of oils to be used in electrical submersible motors, protectors and any oil-filled motor accessories. [Table 2-46](.) is an excerpt from ED-191. **Table 2-46: Guideline for the Selection of Oils in ESP Motors, Protectors, and Oil-filled Motor Accessories** | Motor Internal Temperature | Oil Selection | Application Notes | MS # | Descrip- tion | |------------------------------|-----------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------|---------------------| | < 270 degF (< 130 degC) | Reda #3 | Cool well applications. | MS-11-233 | Synthetic (PAO) Oil | | < 290 degF (< 145 degC) | Reda #2 | Oil will need to be heated during servicing when surface temperature is below 32 degF or 0 degC. | MS-11-164 | White Mineral Oil | | < 360 degF (< 180 degC) | Reda #5 | Recommended for general applications and all applications that use Maximus motors, protectors and ProMotors, 456 Dominators, 375 AS, 540 AS, 562 Series Motors and 738 Dominators. Unless specified in product description. Should also be used as a minimum for Hotline applications. | MS-11-279 | Synthetic (PAO) Oil | | Motor Internal Temperature | Oil Selection | Application Notes | MS # | Descrip- tion | |------------------------------|-----------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------|---------------------| | <400 degF (< 204 degC) | Reda #6 | Under special requirements, this may be used down to 300 degF or 150 degC motor internal temperature. At startup, motor efficiency may be up to 10% points lower due to high oil viscosity at bottom hole temperature down to 150 degF or 65 degC | MS-11-292 | Synthetic (PAO) Oil | | >400 degF (> 204 degC) | Reda #7 | High Temperature extended run life protector, SAGD and Hotline motors | MS-11-314 | Synthetic (PAO) Oil | Detailed information on each oil is contained in the material specification and can be located in [GeMs](http:\www.gems.slb.com\ematrix\emxLogin.jsp) . Material Safety Data Sheet (MSDS) for each of the Reda oils are listed in [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3258882) [3258882](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3258882) . **Figure 2-40: Viscosity Comparison of Reda Motor Fluids** **Figure 2-41: Viscosity Comparison of Reda Motor Fluids** For a comparison of standard protector with advanced protector materials see [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4012406) [4012406](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4012406) . ####### 9.8 Elastomers When selecting elastomers for a completion it is essential to consider both life of field and operational interventions to ensure that the elastomer selected can handle all the load cases. [InTouch Content ID 4118158 Best Practice](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4118158) gives an excellent example. All temperatures (high and low) that the material will be exposed to in all aspects of unit life, i.e. storage, shipping, testing, and installation should be considered as well as the full spectrum of future reservoir fluids and treatment fluids. High temperature elastomers may not be the best selection for a low temperature application for example. [InTouch Content ID 4443347](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4443347%2A) provides an Elastomer Selection Guide for Completions equipment and can be used as a reference, however it can't be fully applied to ESP equipment. Elastomers in completions tools are usually constrained, it typically sees static BHT and designed for high dP, so there is minimal extrusion gaps (and could be anti-extrusion rings), therefore usually elastomer's swelling is not an issue. Not all of the elastomers in the ESP strings are constrained with small extrusion gaps (i.e., protector bags and shaft seals bellows). **Example** The guidelines ( [InTouch Content 4443347](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4443347%2A) ) indicate that Aflas can be used for long-term applications with hydrocarbon aromatic solvents (eg. Xylene,Toluene). The situation changes for ESP equipment as soon as it sees significant thermal cycles, low dP and given that not all of the elastomers are constrained with small extrusion gaps. Such aromatic solvents as Xylene or Toluene will cause swelling of unconstrained Aflas parts, will make it less robust (durometer and tensile strength drop) and less tolerant to abrasives, mechanical impact, etc. Protectors typically have the choice between HSN and Aflas elastomers for shaft seals, O-rings, and bags. Special attention is required to bag selection, since the bags in a protector are often the limiting factor in runlife. ####### 9.9 Materials When choosing Protector metallurgy, use the same guidelines as for pumps. Generally the protector should be matched to the rest of the string, but it can be higher specification. Avoid using lower specification than the rest of the equipment in order to avoid galvanic corrosion. **Note: Galvanic corrosion** The greatest possibility of dissimilar metal corrosion associates with shallow water wells applications due to presence of dissolved oxygen in water, which is one of the strong catalyst for galvanic corrosion as soon as it greatly increases water conductivity. Galvanic corrosion is not common for deep wells, because formation water usually doesn't contains dissolved oxygen. The Material specifications for protectors can be found in [InTouch Content ID 3043579](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3043579) . ####### 9.10 Torque / HP Consumption Tests have confirmed that the horsepower consumed by a protector during operation is minimal and is not a factor when sizing equipment. DesignPro does not add horsepower for a protector. ####### 9.11 Tandem Protectors Tandem protectors' configuration are used to provide additional/redundant protection. The decision of running tandem protectors and selecting their configuration is based on operating conditions, acid treatments to the well, well fluid type, gas, well geometry, down-thrust, etc. Experience from previous runs in the same well or similar conditions must be considered. Several operating companies set their policies to run tandem protectors on every system. In general, when running three-chamber protectors with one or both having two bags in parallel, running a second protector provides additional shaft seals and chambers. ######## 9.11.1 Downthrust Handling in ESP Systems with Tandem Protectors The performance of the thrust bearing relies on the pure condition of the oil. Consequently, all Schlumberger Modular Protectors were designed to keep the thrust bearing as far away as possible from the well fluid interface, with the thrust-bearing chamber located below all sealing chambers and mechanical shaft seals. In order to maximize the runlife of an ESP system equipped with tandem protectors the thrust load is carried by the thrust bearing of the lower protector, which is the furthermost from the well fluid / motor oil interface. This assembly allows the protector thrust bearing to operate without compromising its load capacity as it operates in a clean oil environment. In the event of a progressive contamination of the motor oil with well fluid, the thrust-bearing chamber would be the last to be contaminated because the path of the contamination would be from the top downwards. The assembly of tandem-protectors to operate as described is rather difficult due to the extremely tight tolerances involved that requires special tools, measurements and precise procedures. Schlumberger developed the Manufacturing Procedure for Matching Tandem Protectors (MPI- 53120) to be applied in a case-by-case basis and takes into consideration the following: - the specific configuration of the protector, size, materials of the housings and shafts, etc., and - the environmental and operating temperature of the application where the tandem protector will be installed. When ordering Tandem Protectors from any Product Center, the Bottom Hole Temperature (BHT) for the application must be given to Customer Service. is the well fluid temperature at pump setting depth. This information is needed to calculate the Protector shaft growth and then determine the required shimming needed between the Tandem Protectors per MPI-53210. As noted in MPI-53210, if there are transportation constraints, the Protectors can be shipped separately but please note the following: The specific coupling and the exact amount of shims determined (based on the given BHT) are included in the same shipment. The information on the relative position of each Protector Serial Number (upper and lower) is clearly indicated in the shipping documentation. This information must be communicated to all the personnel involved in the field operations. ####### 9.12 Special – High Temperature (HT), H2S, Abrasives, Other Chemicals The Extended Runlife Protector (also known as Advanced Protector) is a component of the Extended Runlife project. It is a new protector system that will substantially increase runlife in hostile applications. The function of the protector is to handle the down-thrust load from the pump section and to act as the compensation section for the pressure-balanced, oil-filled motor. Protector failure or even a small leakage past the seal allows well fluid into the high-voltage motor section which usually results in catastrophic system failure. The current protectors, when only a single tandem is used, can handle benign environment wells but are in many cases the weak link in the submersible pump system. The use of tandem protectors has eliminated the majority of the system failures that are protector related, however, wells with high bottomhole temperature, wells with a high percentage of H2S and wells with high abrasive content are still problematic even for tandem protectors. As such, Extended Runlife Protectors are targeted at the following type wells. Advanced Protectors are for: - **Wells with high bottomhole temperatures** — the operating temperature limit of existing protectors is 400 degF (204 degC) and is limited by the elastomers used in the protectors. Also, the effectiveness of labyrinth protectors is limited due to reduced oil/water separation at higher temperatures. - **Wells with high H2S or other incapable chemicals** — for applications with a high percentage (up to 30%) of H2S at low-to-moderate temperatures (100 to 300 degF [38 to 150 degC]) the elastomer bag currently being used is ineffective as an H2S barrier. H2S can easily migrate through the bag to attack the copper wires and other copper base components inside the protector and motor. The advanced protector is an excellent choice where other chemical/elastomer incompatibility is a problem, ruling out bags. These chemical incompatibilities may be due to well fluid contents (CO2, etc.), or well treatment chemicals (Amines, acids, alkaline solutions, etc.). - **Wells with high abrasive content** — abrasives in well fluids tend to settle on the top end of the protector where it is connected to the pump intake. Accumulations of abrasives in this area will either directly damage the mechanical shaft seal located there or will damage the adjacent journal bearings that are used to support the shaft seal. The Advanced Protector Bellows Sizing Software is on [InTouch Content ID 3869546](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3869546) . *2.3.12.1* **H2S Scavenger** For severe H2S applications (greater than 5%), the protector may need to have special considerations to prevent H2S from migrating into the motor. H2S is very bad for motors because it breaks down the insulation of the windings and it causes corrosion on the copper wire. The difficulty is that H2S is a small molecule and tends to get everywhere. The best solution in these cases is to use an advanced protector with a metal bellows as stated above, but an older solution is to use sacrificial metal to absorb or ‘scavenge’ the H2S before it can make its way to the motor. Note that another effective method is to reduce the number of stops and starts that the ESP goes through (each cycle introduces more H2S into the protector). See [InTouch Content ID 3035167](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3035167) for more information. ####### 9.13 Failure Modes of Protectors and Thrust Bearings Failure modes of protectors and thrust bearings: - Labyrinth protectors will fill with well fluid if cycled excessively, causing the thrust bearing and motor to fail. Many times dismantle inspections show water in the lower portion of a labyrinth protector and this is mistakenly thought to have been there when the unit was operating down hole. Always remember that a labyrinth protector will normally operate with some water (well fluid) in the top end by design. If the unit is laid on its side and transported, the water can move to the bottom. - Protector bags will fail if exposed to incompatible well fluids, or if subjected to excessive temperatures. - Bearings will fail if misaligned or subject to excessive thrust outside of design conditions. - High temperature may cause bearing damage due to viscosity variations in the oil film between the rotating and stationary sections of the thrust bearing. - Vibration caused by faulting pump/motor may lead to premature bearing failure. - Contaminated lubricant will cause premature failure. Great care must be taken during system installation that oil fluids are clean and free from solids, etc. - Some types of high load thrust bearings will be permanently damaged by rotation of the shaft in the wrong direction, and care should be taken to ensure that the motor coils are connected correctly to the three phase supply. Back spinning of the pump due to well fluid flowing back down the tubing following pump shut down must also be prevented with such bearings. This can be achieved by installation of a check valve at the pump outlet. ###### 10 Motor ####### 10.1 Induction Motor Basic Functions An ESP motor is basically a three-phase AC, two-pole squirrel cage induction motor. The function of the motor is to convert three-phase electrical power it receives through the power cable to mechanical power at the shaft end to drive the pump (bhp). A typical ESP motor consists of a stator-housing, head and base and rotor-shaft subassembly. Three-phase power is fed through the cable pothead into the motor head, to the stator windings causing the rotor-shaft subassembly to rotate, delivering torque to the pump. **Figure 2-42: Motor Drawing** Motors are selected using DesignPro, and data collected on well conditions, completion, customer objectives. Selection is done to suit well conditions and pump selection. **Figure 2-43: Typical Temperature Profile in a Motor** Motor rating and application can only be understood if one understands the key variables: - Motor cooling and well conditions. - Motor winding internal thermal limits. ####### 10.2 Motor Cooling in ESP systems Electrical motors used with ESP’s rely on a flow of well fluid past the motor housing to carry away the heat produced by motor operation (losses). The common rule of thumb often used of a recommended 1 ft/sec, is quite conservative. Adequate cooling is often possible with lower fluid velocities, depending on the bottom-hole temperature and motor load. **Note** Liquid velocities below .5 ft/sec make the heat rise calculation invalid. The rate of heat transfer to the well fluid also depends on the physical properties of the fluid. The amount of water and free gas in the flow will affect the heat carrying capacity of the fluid. Higher flow (velocity) and higher water cut improve the cooling, while higher viscosity and free gas reduce the cooling. Use DesignPro calculations to estimate motor winding temperature, bearing in mind that winding temperature calculations are based on simple fluid density calculations and tend to be less accurate in multiphase flow past the motor. The calculated winding temperature can be viewed under the motor/heat rise tab. A general guideline is to know the internal limit of the motor winding temperature (the most common limit is 400 degF) and try to keep the DesignPro calculated temperature in the neighborhood of 350 to 360 degF. If calculated winding temperature is close to 400 degF (or the limit as per motor type), it is recommended to check your cooling assumptions and sources of uncertainty to make sure that the motor can survive the application. Consult [InTouchSupport.com](http:\intouchsupport.com) if in doubt. In cases where the motor is positioned below the point of fluid entry into the well or if the fluid velocity is low, a shroud may be necessary in order to improve cooling. Approximate simulation of shroud cooling can be done using DesignPro casing sizes. Refer to [2.7.5:](.) . ####### 10.3 Size – Motor Series Series selection (375, 456, 562, and 738) is determined by the casing ID at the setting depth, the well deviation and the dog-leg-severity (DLS) at installation depth, and at times by what is available in stock to meet a specific need in the field. It is generally recommended to select the largest series possible that fits comfortably in the casing. This usually results in lower cost per hp for any given application. And depending on flow (Q) and casing ID, may result in better motor cooling due to higher fluid velocity past motor. DesignPro will only allow the selection of equipment that fit in the casing ID (culling), after considering your choice of equipment clearance under “Options”. You will have to include any dimensions of banding material or cable protectors in your clearance calculation manually; with special attention given to calculations in tight wells. A minimum clearance between equipment OD and casing ID of at least 0.02 inches is recommended. **Note** Each motor series has unique losses referred to as "slip" which is reflected in the actual rpm operation for a fixed frequency. Refer to Product Bulletins: [InTouch Content ID 3048089](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3048089) - 456 series, [InTouch Content ID 3796855](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3796855) - 562 series, 540 series- [InTouch Content ID 3405390](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3405390) , and [InTouch Content ID 3879905](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3879905) - 738 series. ####### 10.4 Motor Rating DesignPro offers a choice of a conventional motor or a variable rated motor (under motor tab). A conventional motor is designed to operate at a certain fixed rating regardless of well conditions, limited by a defined internal winding temperature. A variable rated motor (Dominator) is a motor with a nominal rating (Nameplate details) that is based on the best well cooling conditions (for 100% rating), and with the assumption that it will have to be de-rated in order to operate in more aggressive conditions. The variable rated concept is designed to allow the field user to decide how far the application operating point needs to be from physical motor limits (given well conditions). The default 100% motor rating (at a given Hz) published in catalogues and in DesignPro lists are the maximum rating values that are suitable for the best downhole cooling conditions (usually equivalent to a low temperature water well). One of the main physical limitations when rating a motor is the internal winding temperature, which is fixed based on the type of insulation and material used in motor construction. Most motors have an internal winding temperature limit of 400 degF. Hotline motors are targeted for high temperature applications. Refer to the HotlineSA3 Product Bulletin [(InTouch ID 5648061)](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=5648061) for more detailed information. ######## 10.4.1 Motor Re-rating Re-rating is used to reduce the assigned nameplate hp, volts and amps (from published 100% rating) to match the reduced cooling rate in aggressive well conditions. As such a derated motor is physically oversized but its selection (and new nameplate values) is governed by less-than-perfect cooling conditions that limit the maximum current, in the target well. DesignPro allows the field user to select the right motor and its Re-rating, and check the motor winding temperature in relation to the limits. **Note** Note that rating a variable rated motor is both a technical and competitive exercise (not purely technical). Rating a motor decides how far the motor is from its application limitations, and therefore the technical and commercial risk involved in the application. ####### 10.5 Volts and Amps After selecting the motor size, rating and hp from DesignPro’s Motor tab, the field user is faced with a choice of possible combinations of Volts and Amps (for same hp). The choice may include single or tandem combinations of motors. The combination of volts and amps to be selected for any given hp choice depends on the application, cable choice or availability, transformer taps, etc. Normally, the user is advised to select the highest possible voltage that is practical given transformer taps, cable ampacity, pothead (FCE) limitations, etc. However, in the case of using a VSD, lower voltages may help reduce the effect of harmonics on motor and cable insulation. **Note** In deep wells higher voltage motors may be necessary to enable start-up. **Note** See : for detailed information on MLE (cable only) selection. ####### 10.6 Material When choosing motor metallurgy and elastomers, use the same guidelines as for pumps. Generally you want to match the motor to the rest of the string, but it can be higher specification. Avoid using lower specification than the rest of the equipment in order to avoid galvanic corrosion. **Note: Galvanic corrosion** The greatest possibility of dissimilar metal corrosion associates with shallow water wells applications due to presence of dissolved oxygen in water, which is one of the strong catalyst for galvanic corrosion as soon as it greatly increases water conductivity. Galvanic corrosion is not common for deep wells, because formation water usually doesn't contains dissolved oxygen. The Material specifications for motors can be found in Sections 11, 12 and 13 of [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3043579) [3043579](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3043579) . ####### 10.7 Winding Insulation The most common motor winding insulation systems used are the Polyimide magnet wire insulation (Kapton™) and the PEEK system (Poly-Ether-Ether-Ketone). Both are rated as 5 kV systems (5000 Volts AC). The Kapton system is rated to a temperature of 400 degF (winding temperature). Schlumberger Kapton motors are double wrapped with Kapton insulation (at 55% overlap) and in certain models encapsulated with M-11 varnish. Kapton is currently being used in both states as varnished and unvarnished depending on the product. Refer to specific motor Product Bulletins for details. The unvarnished system is, at the time of writing, used in the RA Dominator motors and the Maximus ProMotors. The PEEK magnet wire insulation proprietary to SLB is currently rated to 550 degF for some motors (such as Hotline special applications). Refer to product catalogue description and Product Bulletin for more details. PEEK motors do not use varnish, and have a H2S application limit of 3% concentration. Refer to [InTouch Content ID 4016787](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4016787) for the latest on comparison between Kapton and PEEK. Note that as more testing and research is being done, application guidelines for non-standard or aggressive applications will change. Refer your cases to [InTouchSupport.com](http:\www.intouchsupport.com) for any questions. ####### 10.8 Oil Selection Oil selection for motors and protectors is determined by internal operating temperature of the motors and the ambient temperature at the time of installation. The same oil should be used in both the motors and the protectors in the same string of equipment. [GeMs](http:\www.gems.slb.com\ematrix\common\emxNavigator.jsp) document ED-191 is a guideline for the selection of oils to be used in electrical submersible motors, protectors and any oil-filled motor accessories. The information below is an excerpt from ED-191. **Table 2-47: Guideline for the Selection of Oils in ESP Motors, Protectors, and Oil-filled Motor Accessories** | Motor Internal Temperature | Oil Selection | Application Notes | MS # | Descrip- tion | |------------------------------|-----------------|--------------------------------------------------|-----------|---------------------| | < 270 degF (< 130 degC) | Reda #3 | Cool well applications. | MS-11-233 | Synthetic (PAO) Oil | | < 290 degF (< 145 degC) | Reda #2 | Oil will need to be heated during servicing when | MS-11-164 | White Mineral Oil | | Motor Internal Temperature | Oil Selection | Application Notes | MS # | Descrip- tion | |------------------------------|------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------|---------------------| | | | surface temperature is below 32 degF or 0 degC. | | | | < 360 degF (< 180 degC) | Reda #5 | Recommended for general applications and all applications that use Maximus motors, protectors and ProMotors, TPS-Line motors and protectors, 456 Dominators, 375 AS, 540 AS, 562 Series Motors and 738 Dominators. Unless specified in product description. Should also be used as a minimum for Hotline I applications. | MS-11-279 | Synthetic (PAO) Oil | | <400 degF (< 204 degC) | Reda #6 | Under special requirements, this may be used down to 300 degF or 150 degC motor internal temperature. At startup, motor efficiency may be up to 10% points lower due to high oil viscosity at bottom hole temperature down to 150 degF or 65 degC | MS-11-292 | Synthetic (PAO) Oil | | >400 degF (> 204 degC) | Reda #7 | High Temperature extended run life protector, SAGD and Hotline motors. Should also be used as a minimum for Hotline550 applications. | MS-11-314 | Synthetic (PAO) Oil | | >428 degF (> 220 degC) | Purified Reda #7 | High Temperature HotlineSA3 integrated motors. | MS-11-314 | Synthetic (PAO) Oil | Detailed information on each oil is contained in the material specification and can be located in [GeMs](http:\www.gems.slb.com\ematrix\emxLogin.jsp) . Material Safety Data Sheet (MSDS) for each of the Reda oils are listed in [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3258882) [3258882](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3258882) . **Figure 2-44: Viscosity Comparison of Reda Motor Fluids** ####### 10.9 Start-up, Voltage Cable Nameplate hp, volts and amps reflect the steady state operating conditions at full load. At start-up the motor passes through a transient situation that begins at the “push-of-the-button” and ends when the full speed steady state situation is achieved. This typically takes less than 0.2 seconds (approximate, order of magnitude figure). **Figure 2-45: Speed — Torque of Typical Reda Motor** At start-up, the motor draws between four to six times the nameplate current, while the voltage drops. Voltage drop depends on power line voltage regulation (how stiff the power supply is) and system impedance; or the generator capacity in relation to starting current. Motor torque is proportional to the square of terminal voltage. As a consequence, the torque available (motor output) will decrease in proportion to the square of the terminal voltage drop; and in some cases it may be insufficient to overcome inertia and friction and to start the pump. Hence, it is important not to drop the motor terminal voltage below 50% of required nameplate voltage, which is typically the minimum to start a pump. Softstarting a motor should be considered in certain applications. There are two methods for soft starting an ESP: - Variable Speed Drive (VSD) - Reduced voltage soft starter. If any of the following conditions exist, use of a softstarter should be examined further: - High horsepower in a shallow well (less than 2000 feet) - Motor horsepower rating exceeds 75% of the max shaft rating for the motor. (Protector shaft ratings and pump shaft ratings are assumed to be at least as big as the motor shaft rating.) - Pump shaft diameter is larger than motor shaft diameter - There is a deep-set packer that eliminates the mechanical Softstarting normally available from the tubing. - Operation directly from a 4160 Volt grid with no transformer. For more details refer to [InTouch Content ID 3834149](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3834149) . ####### 10.10 Tandem Application For a given series (OD), motor hp is increased by adding more rotors and hence longer motors. Transport and handling consideration limit how long single section motors can be. Hence for any given series, motors may be combined in tandem to provide the total power required by larger pumps (UT, CT and LT). The motors should preferably be identical, with the same power ratings, and nameplate voltages and currents. Tandem motors are connected in series. The voltage required by a series of tandem motors is the sum of the nameplate voltages of the individual motors, adjusted for the operating frequency. The current drawn will be the nameplate current of a single motor (NP). The top tandem motor is always a UT, the middle section(s) is a CT, and the bottom most is either an LT or a CT depending on whether a sensor will be installed or not. Depending on the type of motor, an adapter is required. The practical limits of combining tandem motors is usually shaft hp and/or total voltage (not to exceed the motor limit of 5 kV). When selecting tandem motors in DesignPro, matching of the motors is already taken care of. Combinations of two to five motors are provided as options with the resulting hp, volts, etc. **Note** For tandem Maximus Motors (CT/LT) it is recommended to increase the frequency in steps of no more than 5Hz and allow time for the motor temperature to stabilize before the next step-up. There is a risk of thrust bearing overloading during startup due to locked coupling (frictional downthrust). Refer to [InTouch Content 6631349](https:\intouchsupport.com\index.cfm?event=content.preview&contentid=6631349) for details. **Note** In deep wells higher voltage motors may be necessary to enable start-up. ####### 10.11 Motor Operation with Variable Speed (VSD) In certain applications, the pump speed needs to be varied in order to increase or reduce production; or to set the system to automatically control certain variables such as maximum current, downhole pressure, wellhead pressure, etc. In such cases, a VSD becomes a necessary surface component in the system. Varying the frequency of the applied AC current allows the control of downhole pump speed. Motor power will increase approximately linearly with increase of Hz and voltage, as long as the physical limits of the motor are not exceeded. The motor torque loading is proportional to the square of the rotational speed ratio. While, Pump hp demand (load) will increase approximately proportionally to the cube of the speed ratio *P2/P1 = (Hz2/Hz1)3 (Affinity Laws)* Generally, ESP system behavior follows the affinity laws (discussed in AE school material, pump section) Hence for any given combination of available motor and load, the maximum speed (Hz) is the intersection point of the straight line describing the motor hp, and the polynomial describing the pump load hp. *Hz2 = 60 x sq. rt. (HPmotor at 60/hppump at 60)* The formula can also be used to determine the size of motor needed for a target running Hz. ####### 10.12 Motor Physical Limitations An ESP motor has the following main physical limitations: - **Insulation voltage limits** Motor insulation is normally rated at 5 kV. The insulation voltage limit has to be taken into consideration when selecting volts-amps combinations and when system is subject to appreciable harmonics. - **Motor thermal limits** The main source of heat in a motor is the electrical current passing through the windings (due to the resistance), and to lesser extents any friction in bearings, VSD harmonics, etc. Motor thermal limits are governed by insulation type, age and amount of stress it has been subjected to (surges, voltage spikes, testing, etc.). The motor thermal limit is the main reason for de-rating motors, when cooling conditions are less than excellent. Note that when frequency is varied (Hz), motor thermal load will tend to increase with the cube of the frequency. - **Shaft hp limits** Shaft hp limit is related to material used, heat treatment, shaft dimensions, and any notches/ stress concentrators, etc. The hp limit is actually a torque limit at a certain RPM. Shaft limits are included in DesignPro and in catalogues. High strength shafts (HSS) are available for different models and are required in certain tandem combinations. DesignPro normally prompts the user to use HSS when needed. Refer to [InTouch Content ID 3761235 REDA Equipment Shaft HP Limits](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3761235) which provides horsepower limits for different shaft materials - **Electro-Magnetic limits (EM)** Electro-magnetic limits are related to magnetic flux and the ability of the motor laminations to pass the electro-magnetic energy from stator to rotors without reaching EM saturation. EM load increases in proportion to the cube of the frequency. - **Running in deviated wells with dog-leg-severity (DLS)** This is normally a physical limitation that is imposed by well conditions. A rule-of-thumb used often is to limit applications to passing (while installing) through a maximum of 6.0 deg/100 ft DLS, and to set (equipment operating in) in a maximum of 1.0 DLS. DesignPro offers a built in tool to enable user to do the deflection and stress analysis. In borderline cases it may help to use smaller OD equipment, shorter equipment, smaller size tubing just above the pump, and flange- neck support by installing cable protectors. Generally, it is advised to keep ESP system size (series) as uniform and consistent as possible, keep string as short as possible, and remember that smaller necks take most of the deflection. ####### 10.13 ProMotors ProMotors are first generation of motors (part of the Maximus system) that integrate the most common components of the motor and protector to improve installation and reliability. Refer to ProMotor Product Bulletin ( [InTouch Content ID 4064952](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4064952) ) and other InTouch content related for application details. ####### 10.14 Integrated Motors Integrated Motors are second generation of motors (part of the HotlineSA3 system) that integrate motor and protector components to increase operational specifications, integrate monitoring, improve installation and improve reliability. Refer to HotlineSA3 Product Bulletin ( [InTouch Content ID 5648061](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=5648061) ) and other InTouch content related for application details. ###### 11 Permanent Magnet Motor Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. Refer to TPS-Line Permanent Magnet Motor for ESP (VPEDMT) - Product Bulletin [(InTouch ID](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7139934%2A) [7139934)](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7139934%2A) . ###### 12 Power Cable The power cable is a major component of the ESP system, which carries the electrical power from surface to the downhole motor, and carries pressure, temperature, vibration, etc. signals from the downhole monitoring sensor back to the surface. The Electrical Submersible Pump (ESP) power cable is designed and manufactured from five primary components, conductors, insulation, barrier, jacket and armor. In special applications, two additional components, stainless steel capillary tubing and an outer PVC jacket can also be provided. **Conductor Insulation** Barrier Jacket Armor **Figure 2-46: Power Cable** These cables typically operate on three-phase systems, which mean there will be three conductors in the cable. These copper conductors can be configured to be solid, stranded, or compact-stranded, each of which have its own unique advantages and disadvantages. On the surface of each of these conductors is a thin lead-alloy coating, called Amaloy. This coating provides a layer of protection for the copper substrate from chemical attack due to exposure to hydrogen sulfide (H2S). Each phase is individually insulated with a high dielectric material and this insulation is physically bonded to the conductor with an adhesive. The voltage rating for the cable is dictated by the wall thickness of this insulation layer. ESP cable is manufactured in several voltage ratings 3, 4, 5 and 8 kV. In an ideal situation, in which handling damage and environmental exposure is not a problem, the conductor and insulation is all that would be required to adequately operate this ESP cable; however, these cables are not being installed in ideal situations, therefore we need to provide additional protection for the conductor and the insulation. This additional protection comes in the form of a barrier over each of the conductors, additional jacketing material over all three phases and finally a damage resistant metallic armor layer over the entire cable. The selection or design of a proper ESP cable for a particular application depends on many factors. There are several industry standards, ICEA (Insulated Cable Engineering Association), IEEE (Institute of Electronic and Electrical Engineers) and API (American Petroleum Institute) that are referenced for the design, qualification testing, manufacture, acceptance testing, and application of ESP power cables. ####### 12.1 Selecting the Appropriate Cable for the Application The process of selecting a power cable is basically a two-part process: - Selecting the proper size and configuration of conductor (AWG), and - Selecting the required construction and cable configuration, considering: - Calculations for the surface voltage required - Calculations for the cable conductor temperature (ampacity), and - Special operating and fluid conditions, fluid treatments, gas, fluid level, etc. - Surface temperature. [InTouch Content ID 3016052](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3016052) contains an Excel spreadsheet(s) that can be used to automatically generate an ESP power cable or MLE (cable only) Ampacity Chart and calculate temperature and amps limits for a range of common cable types. ########## T  (a I2) T c well **Equation 2-5:** Tc  Twell a where Im ax  **Term Definition** **Tc** adjusted conductor temperature, degF **a** current carrying capacity factor, dimensionless **I** current, amperes **Twell** ambient well temperature, degF **Imax** is the maximum current in amps **MLE temperature rating** An MLE includes the flat cable length and the pothead that fits into the motor head. Typically the flat cable has a higher temperature rating than the pothead connection itself. The spreadsheet(s) under [InTouch Content ID 3016052](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3016052) calculate the conductor temperature of the most common REDA cables, based on cable type, current, and downhole temperature. Note that for MLE's included in the spreadsheet(s), the calculation result DOES NOT include the pothead limitation. Be aware that this can be misleading. The MLE temperature rating of the combined flat cable and pothead is based on the weaker component (usually pothead) and is found under the attributes in OneCAT details. In general, all standard MLE's have a pothead temperature rating of 300 degF (conductor), which is usually the limiting factor. The Hotline MLEs range have pothead ratings up to 482 degF, depending on the motor and MLE design. The MaxLok MLEs have a pothead temperature rating up to 400 degF. The Trident MLEs have a pothead temperature rating between 300 and 400 degF, depending on the motor design and application (i.e., H2S). All MLE types are listed in OneCAT with the rating. Explanation for the lower rating of the pothead part of typical standard MLE: The standard pothead typically being used in most MLE’s have a external body casting made of grey iron which is a non- magnetic high –Nickel alloy, while the internal blocks are made of PEEK. The limiting factor in pothead rating is the PEEK glass transition temperature. Once the temperature exceeds 300F the PEEK material will become soft and the seal block(s) will begin to deform the front block due to the stored energy when compressed to from the seal. If this were to happen the seal would be compromised. The failure mode will be either well fluid entering the motor or electrical fault within the MLE due to the seal block movement damage to the insulation. It is not recommended by LPC to use this MLE within these operating conditions. Remember that the above describes an example standard MLE. If in doubt, if you have a special application or if you have questions about the rating, please contact InTouch. Therefore, to check the temperature limit of an MLE (combined flat cable and pothead) using the attached MLE spreadsheet, make sure you do the following: - Find the temperature rating of the MLE through OneCAT or GeMS (contact InTouch if you cannot find it). - Use the attached spreadsheet(s) ( [InTouch Content ID 3016052](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3016052) ) to calculate operating temperature (after entering your application data). - Compare the calculated operating temperature of selected cable to MLE rating determined in step -1- above. Calculated operating temperature must be below the MLE temperature rating for acceptable application. Cable-related calculations in DesignPro: DesignPro, in its current version (Jan 08) does not check selected MLE's against temperature rating. MLE rating check has to be done by the AE separately using the described procedure, above. Also note that DesignPro has a rigorous voltage drop calculation for the power cable only. It does the calculation and check on the power cable conductor temperature. In fact in the LIMITS report you get the Max Ampacity, actual cable conductor temperature, start-up ratio, the cable temperature rating. On the Detail report some of the same parameters are given but here you see the actual power cable voltage drop that was calculated. The system KVA and Surface Voltage requirements are a result of the total power calculations. Future versions of DesignPro will include MLE rating calculation and comparison. This will be announced separately at the time of new version release. ####### 12.2 Conductors ######## 12.2.1 Selecting the Proper Conductor Size The primary consideration in selecting a conductor for a particular application is selecting its appropriate size. In general, selecting a conductor size is a balance between reliability and cost. The main purpose of the conductor is to carry current from the surface to the motor. The size of a conductor refers to the cross-sectional area. Most electrical cable manufacturers refer to the Brown and Sharpe American Wire Gauge (AWG) to denote the size of the conductor. Standard conductors used in ESP applications are #2/0, #1/0, #1, #2, #4, and #6 gauge. Increasing gauge numbers give decreasing wire diameters and hence decreasing cross-sectional areas. The cross-sectional area of the conductor is important for several reasons. First, the smaller the conductor, the higher the resistance, which results in a higher temperature increase in the conductor. So, conductor size has a direct influence on the cable temperature rating. Second, a higher resistance results in more voltage loss in the conductor. If the voltage loss is too high, this can result in motor starting problems. In addition, of course, voltage loss in the cable is less efficient from an electrical operation standpoint. Finally, the resistance in the conductor plays a role in defining the resonant frequency of the electrical system, which is important for harmonic analysis, especially with PWM-style variable speed drives. Larger conductors have a higher overall efficiency. But there is a point of diminishing return, the larger the conductor, the higher the cost of the cable. So, there is a trade-off between capital cost and operating cost. To select the most appropriate conductor size for an application, we first need to determine the voltage drop in the conductor. Voltage drop is a function of the current flowing through the wire, the size of the wire, the length of the wire and, to some extent, the temperature of the wire. Voltage drop can be calculated; however, the easiest way to do this is with a voltage drop chart as shown in [Figure 2-47](.) . **Figure 2-47: Voltage Drop Chart** An increase in conductor temperature will increase the voltage drop in the conductor. There are “correction factors” available to correct the voltage drop based on the conductor temperature, but it is usually better to ignore the temperature multiplier. The reason for this is that the voltage loss in the cable is not “in phase” with the voltage in the motor but rather the current. To get the true voltage drop in the cable would require a power factor calculation, which would show the voltage drop to be less than what we would predict by simply making a resistance calculation. Next, we need to evaluate motor starting issues. The length and size of the conductor are the biggest determining factors on starting characteristics for a submersible motor. Proper selection of the conductor and starting method can insure that the motor will start reliably. ######## 12.2.2 Selecting the Proper Conductor Configuration The secondary consideration in selecting a conductor is selecting the conductor configuration (solid/ stranded/compact-strand). Typical ESP cable conductors are made from electrical grade copper and are coated with a thin layer of a lead-alloy for corrosion resistance from H2S chemical attack. There are three different options available for the selection of the conductor configuration, each with its own unique advantages and disadvantages. Solid conductor – just as the name sounds, this conductor has a circular cross-section. Stranded conductor - seven wire stranded configuration, comprised of a center strand and six outer strands that are twisted around the center strand. **Figure 2-48: Solid** Compact-strand – seven wire stranded configuration that has been pulled through several sets of compacting rollers, effectively reducing the diameter of the conductor. **Figure 2-49: Stranded** **Figure 2-50: Compacted** **Table 2-48: Advantage/Disadvantage Conductor Configurations** | Configuration | Advantage | Disadvantage | |-----------------|---------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------| | Solid | Smallest diameter Lowest cable cost Low electrical stress | Decreased flexibility, especially with larger conductors | | Strand | Increased flexibility | Larger diameter Increased cable cost due to more material usage and additional processing steps Higher conductor-insulation electrical stress | | Compact-strand | Larger diameter than solid but smaller than strand Good flexibility | Increased cable cost due to more material usage and additional processing steps | Using a stranded conductor for ESP power cable results in cable that is much more flexible (physically) than the solid conductor and therefore easier to work with. This becomes more critical when working with larger conductor sizes. Most ESP stranded cables use seven-strands, six strands twisted around a single center strand. Compact-strand is very similar except the outer strands have been compacted, resulting in a reduced physical size. Stranded cable of any given size (gauge) approximates the cross-sectional area of the same size solid cable. The resulting stranded conductor will have a larger diameter, and therefore the outer dimensions of the cable will be larger as well. Due to higher process costs and larger size, stranded cable tends to be more expensive than the same size solid cable. ####### 12.3 Selecting the Insulation Material Once the conductor has been selected, the next component to select is the insulation. The insulation is a dielectric layer that is extruded directly onto the conductor and provides the electrical isolation of the conductor from other conductors and from the ground plane. Schlumberger offers three types of dielectric insulations, polypropylene (PPE), ethylene propylene diene rubber (EPDM) and PEEK (poly-ether-ether-ketone). The differences between the three types of insulations are the basis of the differences between cable types. ######## 12.3.1 PPE (Polypropylene) PPE, considered a thermoplastic material, is characterized as follows: - low temperature rating (250 degF) - excellent resistance to well fluid - excellent electrical properties - low cost - susceptible to crazing (microcracking) when exposed to high levels of CO2 (>5%) ######## 12.3.2 EPDM EPDM, a thermoset, elastomeric material, is characterized as follows: - high temperature rating (450 degF) - excellent electrical properties, though perhaps not as good as PPE - limited resistance to well fluids (oil swell). ######## 12.3.3 PEEK PEEK, a thermoplastic material, is characterized as follows: - high temperature rating (500 degF) - excellent resistance to oil - excellent electrical properties - high cost. **Note** There are many types of PPE and EPDM available on the market. Even though the material may say PPE or EPDM, the physical, electrical and thermal properties may vary significantly depending on how the material is formulated and processed. This is also true when comparing EPDM compounds between different material manufacturers. During the extrusion operation, a high temperature adhesive is applied directly onto the copper conductor, bonding the insulation to the conductor. This bond between these two components is critical for several reasons: - **Eliminate gas transmission in conductor** . Without this bond, gas permeating the insulation is free to travel up the conductor at this interface. When the gas reaches an area of lower external pressure, the higher pressure gas will cause the insulation to expand, resulting in damage. - **Eliminate damage from corrosive gas** . This bond prevents corrosive from accumulating at the surface of the conductor, resulting in damage to the conductor over time. - **Eliminate corona discharge** . Accumulation of gas at the surface of the conductor can become ionized due to the current flow through the conductor. This ionization can result in a corona being formed, resulting in damage to the insulation layer. ####### 12.4 Selecting the Insulation Thickness The voltage rating for the cable is selected based on the maximum voltage the cable will see during the operation of the ESP equipment. This will typically be the operating voltage at the surface since there will be a drop in voltage throughout the length of the cable due to resistance losses. The cable voltage rating is determined by the wall thickness of the dielectric layer (insulation) over the copper. Schlumberger currently offers three voltage ratings for cable, 4, 5 , and 8 kV, each with increasing insulation wall thickness. ####### 12.5 Selecting a Barrier Over each of the insulated conductors is a barrier layer. The barrier is used to protect the underlying insulation from exposure to well fluids and well gas, both of which could cause accelerated deterioration of the insulation and copper conductor. The rate of deterioration is dependent upon the gas, the concentration of the gas and the exposure temperature. Some examples of this degradation include EPDM oil swell, copper conductor reduction to copper sulfate when exposed to H2S, EPDM expansion and damage in a gas decompression mode. To prevent this exposure and damage, a barrier over the insulation is critical in certain environments. There are two categories of barriers, non-lead and lead. Non-lead barriers, such as PTFE tape wraps, provide excellent protection from well fluid and excellent hoop strength for decompression, but do not stop the ingress of gas into the insulation. This typically is not an issue unless the gas contains H2S levels greater than 3%. In this case, lead barriers are recommended. Extruded lead jackets are the ultimate barrier, providing an excellent barrier to both well fluids and gas. In highly corrosive applications, the lead barrier may also be wrapped with the PTFE tape, protecting the lead from corrosive damage. Schlumberger can also offer extruded fluoropolymer barriers. However, extruded barriers have significantly less hoop strength than taped barriers. In side-by-side testing with tape barriers, extruded barriers consistently exhibiting significant damage in both the barrier and the underlying insulation in decompression modes. For this reason, the use of extruded fluoropolymer barriers is highly discouraged. [Table 2-49](.) indicates the temperature rating, advantages and disadvantages for each type of barrier. **Table 2-49: Temperature Rating, Advantages and Disadvantages for each type of barrier.** | Barrier | Type of Barrier | Temp. Rating | Advantage | Disadvantage | |-----------|-------------------|----------------|---------------------------------------------------------------|----------------------------------------------------------| | Non-lead | PTFE tape wrap | 400 degF | Excellent barrier to fluids Good hoop strength for insulation | No barrier to gas | | Lead | Extruded lead | 450 degF | Excellent barrier to fluids and gas | Heavy weight Increased susceptibility to handling damage | ####### 12.6 Braid Polyester braid is commonly used with taped barriers (as a result, many people refer to taped barrier as “tape and braid”) and leaded round cables. The braid's function is to protect the tape and lead during subsequent manufacturing processes. In the dowhhole application, it serves no use. The braid was also used on leaded flat cables to act as a cushion during the armoring operation; however, significant improvements have been made to the armoring process, allowing the elimination of the braid from these cables. ####### 12.7 Selecting the Jacket Material The primary function of the jacket is to provide damage resistance for the underlying insulated conductor (RedaMax250 – POTB) or underlying twisted cable core for numerous round cables. There are a several jacketing materials that can be used depending upon the application being targeted. Possible materials for the jacket are high-density polyethylene, Nitrile, or EPDM. The jacket selection depends upon chemical resistance properties and temperature considerations. Nitrile is lower temperature and provides better resistance to oil, but has poor resistance to water. Just like the material used as insulation, EPDM jacket is higher temperature but tends to swell in oil. ####### 12.8 Armor The final component for the cable that we need to address is the armor layer. The armor, a formed, metallic layer that is helically wrapped around the cable core, provides two services to the power cable. First, it protects the cable from mechanical damage during handling and installation. Second, it provides reinforcing hoop strength to protect against jacket swelling - this is very important for EPDM jackets. Do not underestimate this second role; many failure analyses for cable have determined that loss of the armor due to corrosion was the reason that the cable eventually failed. ######## 12.8.1 Armor Material SLB cable armor is offered in three types of material: galvanized steel, stainless steel (316 L) and Monel (copper-nickel alloy), listed in increasing order of corrosion resistance. Galvanized armor is the standard armor used for most downhole applications. For more corrosive wells, stainless steel can be used; however, this material has temperature limits, especially in the presence of chloride ions, which could result in stress chloride cracking. For the most severe corrosive well environments, Monel armor is the best choice due to its excellent corrosion resistance. Monel is also the standard armor for MLEs because of the potential for high temperature, corrosive environments, and galvanic corrosion as the cable passes by various materials on the ESP equipment. ######## 12.8.2 Thickness The different armor materials are available in different thicknesses. For example, galvanized armor is available in 0.020, 0.025, and 0.034-in., while stainless steel is available in just 0.020-in and Monel is available in 0.015 and 0.020-in. Thicker armor layers are typically recommended for more corrosive environments. ######## 12.8.3 Profile Armor is available in various profiles. The basic profile for armor is crowned interlocked and is used for round cable constructions. Also available are flat profile interlocked, low profile armors, and double armor (two layers of armor). The choice depends upon the downhole environment and the expected handling conditions. Flat and low profile armor are used more frequently with flat cable, where the cable dimensions and profile are typically more critical. Round Profile Flat Profile **Figure 2-51: Profile types** ####### 12.9 Special Components In addition to the standard five cable components discussed, additional components such as integral injection lines, outer PVC extruded jackets (over the armor), and ground wires can be supplied. The 316L stainless steel injection lines can be supplied in ¼, 5/16, 3/8, and ½-in x 0.049-in sizes and are integral to the cable. For ocean floor applications (subsea umbilicals), a PVC outer jacket can be extruded over the armor layer, providing a layer of protection for the armor. ####### 12.10 Selecting the Cable Configuration (Flat or Round) Schlumberger offers two cable configurations either flat or round. The biggest advantage to flat cable is the small overall profile, allowing the cable to be used in wells where space constraints exist. For example, applications in 7" liners often require flat cable to adequately fit without damage. Most flat cables do not have an overall jacket. This, coupled with the overall flat configuration, make these cables more susceptible to damage. In applications with highly deviated wells, some consideration should be given to the use of round cables instead. ####### 12.11 Other considerations when selecting ESP cable ######## 12.11.1 Explosive Decompression Explosive decompression occurs as a result of a rapid decrease in the pressure that the cable is exposed to. At elevated pressure in a well environment, gas will permeate the non-metallic cable components and, over time, saturate the elastomer compounds in the cable. When the pressure external to the cable decreases, the higher pressure gas in the elastomer materials will start to migrate to the lower pressure. If this pressure drop occurs too quickly or the differential pressure is significant, the gas will not be able to diffuse quickly enough through the elastomer wall and will rapidly expand. This expansion places significant stress on the elastomers and can result in severe damage to the cable component. This rapid decompression can occur during motor start-up when the well fluid is drawn down or during cable retrieval from the well. Controlling how rapidly we decrease the annular pressure in the well or how quickly the ESP system is pulled to the surface can significantly decrease the potential for damage. In addition, we can also prevent the gas from entering the insulation with the use a lead barrier. ######## 12.11.2 Ampacity In the earlier discussion, we have mentioned ampacity and the role it plays in the temperature rise in the conductor. The ampacity of a cable is a function of the size of the conductor, the operating amperage placed on the conductor, the ambient temperature the cable is exposed to in the well, and the thermal properties of the various cable components and the cable configuration. So, each cable at each size has an ampacity value. The ampacity calculations are used to determine the temperature rise in the conductor and is defined by the [Equation 2-6](.) . **Equation 2-6:** Where, **Term Definition** **Tc** temperature of the conductor, degF **I** operating current, amps **a** ampacity coefficient, unique term for each cable type encompassing the thermal properties of each cable. **Twell** ambient temperature of the well The conductor temperature calculated using this equation must be below the temperature rating of the cable. Conductor Current (Ampere) Using [Equation 2-6](.) , ampacity charts have been created for each cable type. An example is shown in [Figure 2-52](.) . | 250 200 150 #1AWG #2AWG #4AWG 100 #6AWG 50 0 100 200 300 400 500 Well Temperature (°F) | 250 200 150 #1AWG #2AWG #4AWG 100 #6AWG 50 0 100 200 300 400 500 Well Temperature (°F) | 250 200 150 #1AWG #2AWG #4AWG 100 #6AWG 50 0 100 200 300 400 500 Well Temperature (°F) | |----------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------| | | Maximumall owable conductor temperature 450°F | | Maximumall owable conductor temperature 450°F **Figure 2-52: Sample of Ampacity Chart for 450 degF Cable** ####### 12.12 Available Power Cable and MLE Systems Power cable and MLE systems are designed and manufactured for: - land and offshore wells - gas, oil, or condensate producers - high-temperature, gassy, and corrosive wells - deepwater wells with high-horsepower ESP systems. While a basic configuration of the main components is suitable for most well conditions, each standard cable can be customized to suit the specific requirements of a given well, including temperature and pressure ratings, corrosive properties, and gas/oil ratios. Various grades of armor ranging from standard galvanized steel to MONEL alloys are available for protection against corrosive environments. All these ESP cables feature fully annealed, high- conductivity copper and tin lead–alloy-coated conductors for additional protection against corrosion. They also include fluid- and gas-impermeable barriers and corrosion-resistant, high-strength metallic armors. Refer to [InTouch Content 7046458](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7046458%2A) for the current power cable and MLE specifications. The part numbers for available power cables and MLEs can be found in [OneCAT](https:\onecat.slb.com\cs\catalog) . Additional variation can be requested via RFQ. Guidelines for cable testing and splicing can be found in the Cables Reference Manual [(InTouch ID 5765593)](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A5765593%2A) . ###### 13 Other Equipment ####### 13.1 Packers A Packer is a subsurface tool used to provide a seal between the tubing and the casing (or wall) of a well, thus preventing the movement of fluids past this sealing point. Packers are designed to direct and control the well fluids by isolating the well annulus. There are different reasons to run a packer: - Production control – In a Gas Lift well ∗ to keep casing pressure of the formation ∗ to prevent produced (abrasive) fluids from passing through the gas lift valves. – In multiple zone completions ∗ incompatibility of pressures and/or fluids from different zones ∗ separate production from different zones ∗ control of an individual layer for high GOR or high water cut. – In steam injection wells ∗ to provide/maintain the annulus for heat loss control - Well testing - In exploration well testing ∗ unknown properties of formation fluids - In production well testing ∗ to locate entry point of water or gas - Equipment protection - to protect the casing from corrosive fluids - to keep off high formation pressures off the casing and wellhead. - Well repair and stimulation - pressure testing of the casing - detection of a casing leak - to shut-off gas or water entry - during squeeze cementation - during fracturing, to keep high pressures off the casing - during acidification as a diversion tool. - Health, Safety and Environment (HSE) - To protect against the effects of surface hazards ∗ offshore ship collision ∗ plane crash ∗ sabotage. - To reduce the effects of wellhead leaks ∗ populated areas ∗ environmentally sensitive areas. Packers are available in two main types: - Permanent - production phase (long term) - Retrievable - multiple completions - production phase (short term) - tool for production/pressure testing. Packers can be set in two locations: - Deep set (or low set) packers. The packer may be installed with the production tubing and set above a pumping system. This requires that all fluid passes through the pump and a feedthrough, and power cable connectors will be required for the ESP powered cable. The companies that provide these are BIW, QCI, RMS, and Tronic. The high set packers are often used when it is required to vent the gas and the venting valve is normally opened under pressure and is activated through a control line which normally also operates a safety valve. Therefore, when the safety valve closes the packer vent also closes. On the low set packers, one of their main features is to protect the casing and tubing from corrosive well fluids. These are not normally vented. Low set packers installed with a pumping system are placed usually 200 ft above the pump discharge head. One of the reasons that 200 ft was chosen was that this was a length that could be used for a motor lead extension cable that could be moulded directly into a packer penetrator with a 15–ft pigtail coming out of the top. Packers can also be set prior to running a submersible pump system. In this case, the pump intake is normally stung into the packer and special cable feedthrough systems are not necessary. This packer arrangement usually allows reservoir to be isolated with formation isolation valves during pump change-outs. This is a similar configuration as when a well is gas lifted. When adding a packer to a completion in a well producing oil and gas, the gas separation/gas handling need to be specially analyzed when designing a ESP systems as the free gas can not be freely produced by the tubing/casing annulus. One other reason for installation of deep set packers is for protection of the casing against its collapse due to external pressure. This is achieved by setting the packer and filling the annulus with liquid. Detailed information on packers and their applications can be found by searching [InTouchSupport.](http:\www.intouchsupport.com) [com](http:\www.intouchsupport.com) . A good starting place would be to search for "packer" with Content Type = Reference Page and Segment = Completions. ####### 13.2 Wellheads The surface termination of a wellbore that incorporates the means of hanging the production tubing and installing the “Christmas Tree” and surface flow-control facilities in preparation for the production phase of the well. Its purpose is to suspend the tubing string in the well and control high pressures conditions often present within the well. The wellhead must be equipped with a tubing hanger/ packoff, which provides for a fluid and pressure seal around the tubing and power feed through. To ensure safe operations, piping and valves of adequate pressure ratings should be installed to connect the wellhead to the flowline. In a case of a pumping system, consideration should be given to pump discharge pressure, wellbore pressure, maximum shut-in pressure and other applicable parameters. There really is no special criteria to selecting a wellhead other than the type of system being run and pressure. For example, if using a flat cable, then space may be a factor in selecting a wellhead. The pressure will lead to select a low or a high pressure rated wellhead. If dealing with a relatively low pressure well, there may not be a need to run a penetrator type wellhead. Pack-off type wellheads are widely used with no problems as long as the limits of the wellhead are not exceeded. Information on this type of wellhead can be found in the ALSSFSM. Usually, it is a client decision to use them or to buy a wellhead on its own. The HSM wellhead is for round cable and HHS is for flat cable. Both cables are sealed at the wellhead by using a rubber grommet to compress around the cable to stop gas escaping; however, gas can migrate through the cable and that is why a junction box is used to vent the gas to the atmosphere and avoid the gas accumulation in the switchboard or drive and creating a hazardous environment. During ESP operations, when free gas is present the casing valve must stay open (vented or piped to flowline) to allow the gas to exit the annulus. Wellheads are manufactured to fit standard casing sizes. Since the wellhead or tubing support is used as a limited pressure seal, it provides a pressure tight pack-off around the tubing and power cable. High-pressure wellheads, up to 5,000 psi, must use an electrical power feed through to prevent gas migration through the cable. BIW, QCI, RMS and Tronic all have a line of cable connector systems for high pressure and high voltage/amperage for various types of applications and environments. All of these conditions must be taken into consideration when selecting a wellhead. Whether using a factory molded connector or a field attachable connector is also dependant on the client and/or the AE when making a design. ####### 13.3 Penetrators Penetrators or feed through mandrels are pressure/fluid barriers around electrical conductors that allow the flow of electrical power through a packer, BOP Can and/or wellhead. The electrical connection may be by connectors or cable leads. Connectors types available are factory molded or field attachable. Penetrator selection is limited by the wellhead, BOP Can or packer size and type, cable size, tubing and casing size, and weight. Some suppliers have individual penetrators for each of the power phases and will work with most wellheads and many packers. Others have penetrators specific to a wellhead or packers configuration. Selection is also dependant on the client and/or the AE when making a design. BIW, RMS, QCI and Tronic all have a line of cable connector systems for high pressure and high voltage/amperage for various types of applications and environments. All of these conditions must be taken into consideration when selecting a wellhead and penetrator. ######## 13.3.1 Penetrator suppliers Penetrator, Connector, Feed-Through suppliers (BIW, PFT, RMS, Tronic, etc.) must be in the approved supplier list and/or buying guide. Installation procedure, electrical ratings, pressure rating, threads, length and relation of sealing areas, seal types, explosion proof requirements, etc. must be verified during the selection process. Refer to the Connector system selection section for a summary of some of the selection criteria. Criteria may vary depending on the type. ######## 13.3.2 Connector system selection For additional penetrator selection guidelines refer to the Penetrator Selection Checklist [(InTouch ID](https:\intouchsupport.com\index.cfm?event=content.preview&contentid=4617554) [4617554)](https:\intouchsupport.com\index.cfm?event=content.preview&contentid=4617554) . - Establish early communication between ESP designer, electrical feedthrough supplier, wellhead and packer suppliers, drilling and production engineers, electricians, and production operators. Keep lead times in mind to meet delivery schedules. - Ask for stack-up drawings from wellhead suppliers and packer vendors to be supplied. To avoid charges for rework and possible delivery delays all dimensions need to be approved by all involved before machine work is started. - Make sure the packer set and release movements are known and accounted for so that tubing or cable movement will not cause mechanical stress on the electrical connection system. - Ensure the voltage, amperage, and pressure specifications of the system are suitable for the well conditions. - If a VSD is used, multiple VSDs are on the distribution system, or the electrical supply is dirty, specify equipment voltage. - Ensure electrical ratings, pressure ratings and electrical code classifications are followed per local electrical standards. - Make sure you have the latest version of the OEM (original equipment manufacture) documentation. - Ensure that the equipment technical specifications, datasheet and/or OEM documentation include clear pressure rating for both the absolute pressure rating and differential pressure rating. - Field attachable connectors are cable specific. Provide the exact cable specification if known. If unknown due to the use of used cable or different cable supplier, provide backup alternative field attachable connectors components. Do not guess on the characteristics of the third party components assuming they have the same performance. Do not modify the components. When connecting used cable, take special precautions. - If annular treatment fluids such as acid jobs, corrosion inhibition, steam flushes are to be used, inform the connector company in advance. - Special considerations are required to account for H2S, CO2, high gas volume and high temperature wells. Electrical feedthroughs and connectors with special metallurgy may require longer lead times. - Small clearance through secondary bores of dual string packers or in the offset bore of tubing hangers may require smaller, lower rated mandrels and flat cable to be used. - Specify if the backup equipment is on location along with the primary equipment so that rig time is not lost if damage occurs to any item during installation or workover. - Establish an inventory stock reorder point plan based on forecasted demand and lead-time. - Specify that a certified field service technician be utilized on the installation. - If vertical splices are required, inform the customer's engineers, operators, and rig supervisors so that they are aware of the planned procedures. Secure variances and permits for hot work conditions. Make sure field service technicians are aware of the vertical splice requirements. ######## 13.3.3 Lower connector with pigtails Potential Severity: Light Potential Loss: Assets Hazard Category: Machinery and Powered Hand Tools Always refer to the OEM manual for installation procedures. - Make sure rig operators are aware of proper handling procedures. - Provide protection to connection points and cable below the wellhead. - Keep the protective cap on until installation. - Do not over tighten the coupling connection. On BIW systems, cover the red dot (nothing more) and follow the other installation procedures. - Provide protection to the lower connector and cable as the tubing hanger is lowered into the wellhead. A 4-ft pup joint on the lower side of the tubing hanger with a mid joint protector installed below the collar is recommended to help guide the assembly and prevent damage to the connector. - Ensure that no cable string weight is transferred to connector. Leave a slight amount of slack in the area immediately adjacent to the connector housing after the connector-coupling nut is fully mated to feedthrough. Tight stretching of the cable when the connector is mated or when bands are installed too close to the connector housing can cause the cable to be stressed leading to premature failure. - Do not allow crushing or gouging of the cable. - Do not rerun any lower connectors made from EPDM. - Tag used lower connectors with dates run. ######## 13.3.4 Surface connectors Potential Severity: Light Potential Loss: Assets Hazard Category: Machinery and Powered Hand Tools Always refer to the OEM manual for installation procedures. - Avoid excessive bending, especially within 3 ft of the connector end. - Always cap the mating end whenever it is not mated to protect against water ingress, thread damage, and out-of-round damage to the coupling nut. - Keep the cable portion away from crushing or gouging hazards. - Position the surface connector safely away from rig work during a workover. - Perform a fit-up test with any new or replacement wellhead feedthru mandrels to be installed to make sure the threads, seal pattern and pins match the mating surface connector coupling nut. Do this upon arrival on location to avoid potential delays. - Inspect the primary and secondary sealing elements before use or reuse. If any salt water gets into the face area of the feedthrough or connector, clean it carefully with electrical cleaner and then distilled water. - Do not use Teflon tape on the threads of the surface connector-coupling nut, as these are not sealing threads. - Follow the manufacture's coupling directions for torque and sealing. - If connector does not mate up properly, do not energize the system. - Ensure cable tray or some other means of supporting the cable is in place to protect it. ######## 13.3.5 Additional references Content [2034563](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2034563) provides a discussion on adherence to API RP11S5 to use wellhead feedthrough penetrators Content [3384536](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3384536) provides some considerations to have present in packer installations with field attachable connectors. Content [3741529](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3741529) provides a manual and presentation of assembly of BIW Field attachable connector. A connector may be located on both sides of the packer/wellhead, thereby connecting the power cables. Content [3944463](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3944463) provides instructions for installation of BIW Field Attachable lower and upper connectors. Content [4175616](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4175616) details a QCI Training Manual for P3000 systems. Content [4240480](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4240480) provides a link to Tronic subsea power electrical connector systems website. Content [3833731](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3833731) provides Tronic Wet Mate Connector Drawings. ####### 13.4 Anodes In occasions, anodes are attached to the bottom of the motor to act as sacrificial to the corrosive fluids. Anodes are usually made of aluminum or zinc materials and they are expected to consume as they corrode while protecting the motor. The reality is that there is no benefit because an anode in this location is limited in what it can protect. The orientation of the anodes will only allow protection of the very bottom part of the REDA equipment and whatever casing or tubing is within the immediate line of sight of the anodes. Anodes only protect what they can "see" and only for a short distance. Moreover, if the well is a low water cut or high GOR well, the conductivity of the solution the anode rests in may not be sufficient to support the galvanic couple so even the bottom of the REDA equipment will not be protected. Even under the best of circumstances current will not be thrown far up the hole so the motor and pump might only be partially protected. This is even worse than no protection since it could set up a cell that could potentially cause a higher corrosion rate on the pump than if no anode were present. To protect the entire string of REDA components with anodes, you would need to run a ribbon anode along the entire length of the string or put something like donuts every few feet to protect the exterior of the components over a short distance. These are not simple procedures, which is the reason that the petroleum industry does not use anodes for tubing strings ever. Instead, the industry relies on corrosion resistant alloys (CRAs) for corrosion protection in corrosive downhole environments. In conclusion, the use of anodes at the end of submersible pump strings has no value and should be discontinued. **Note: Galvanic corrosion** The greatest possibility of dissimilar metal corrosion associates with shallow water wells applications due to presence of dissolved oxygen in water, which is one of the strong catalyst for galvanic corrosion as soon as it greatly increases water conductivity. Galvanic corrosion is not common for deep wells, because formation water usually doesn't contains dissolved oxygen. **Note** It is not recommended to connect accessories such as motor guides, centralizers or anodes directly below the ESP, especially in deviated (non vertical) wells and where OD is greater than the motors. If the OD is greater than the motor OD, it will lift the base of the motor off the casing wall, and will add to bending stresses to the string (refer to [InTouch Content 4012939](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4012939%2A) ). ####### 13.5 Shrouds Shrouds are generally used to provide sufficient fluid flow past the motor to cool it. The recommended minimum velocity of the fluid past the motor is 0.5 ft/sec. When the casing is much larger than the OD of the motor, the fluid velocity may fall below this recommendation. In general 456 motors are used in 5 1/2 inch casing and 540 and 562 series motors in 7 inch casing. The velocity past the motor is usually sufficient in this applications. When these motors are installed in 9 5/8 inch casing or larger, a shroud may be needed to bring the velocity of the fluid up. Other reason to use is a shroud is when the equipment is installed below the perforations. This will force the fluid flow past the motor. The sump or rat-hole below the perforations is a stagnant fluid pool with no movement. By pulling the fluid into the bottom of a shroud and past the motor to get to the intake, motor cooling is provided. There are a few different configuration options to consider: - a shrouded intake - the standard, collar type, shroud hanger - the use of one of the different types of hangers available which are machined to fit in the "necked down" area on the pump/AGH base. A few examples of this style are listed below: - p/n 7003890 6.625 in casing/stainless steel - p/n 7003882 5.50 in casing/carbon steel - p/n 2006582 6.625 in casing/carbon steel. In OneCAT under Miscellaneous Equipment the standard off the shelf offerings are listed. The shroud tubes and rings in the catalog are labeled as to what equipment they are used on. **Figure 2-53: OneCAT Miscellaneous Equipment** When planning to use a standard intake to the pump, it is recommended to use a Shrouded Intake with Integral Ring and the appropriate Shroud Tube. When planning a gas separator, then a Ring Adaptor should be used for Different Size Shrouds and the Shroud Tube. [InTouch Content ID 3037686](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3037686) provides general Shroud Applications and Installation Procedures. This content provides details for putting lockplates on the gas separator or AGH to hold the Ring Adaptor and this should be done in the ART Center or Plant. The shroud hanger should be installed just above the two lockplates welded on the AGH base, 180 degrees apart to prevent downward slippage. There should be another set of lockplates welded just above the hanger, to prevent upward slippage. It is also acceptable to fit the shroud ring above the intake on the pump flange. The shroud ring will rest on the connection bolts but this should not be a problem. In this scenario, the shroud ring is assumed to be a split type that tightly fits on the pump neck so the shroud weight rests on the ring but not on the fasteners/bolts used to attach the shroud to the shroud ring. In DesignPro the best way to check both velocity past the motor and motor heating is to use a string of casing that matches the shroud OD and ID for the length of the motor. [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4011832) [4011832](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4011832) DesignPro Tutorial - ESP Application provides a tutorial for simulating a shroud in DesignPro and get an accurate calculation of the motor heat rise in the shrouded configuration. BPC Engineering recommends the shroud length should not extend past the end of the motor. The reason for this is that there are lugs welded inside the shroud to keep the motor centered in the shroud. If the shroud is ran past the motor the lugs will not keep the motor centered, thus resulting in the motor laying against the shroud if installed in a deviated well. If the motor is lying against the shroud there could be the possibility of failure caused by what are referred to as "hot spots". Recommended practice would be to stop the shroud at the bottom of the motor or slight above (within one foot of the bottom of the motor). There have been many variations on shrouds in the industry and many specially built for specific applications. For instance, inverted shrouds have been used to act like a reverse flow gas separator. Fluid levels must always remain above the top of the shroud in this configuration. There have been shrouds with tapered tubing below the motor to a tailpipe which stings into a packer. This may work fine when there is no free gas build up in the shroud. ######## 13.5.1 Solids Production with Shrouds Care should be taken in wells producing solids. Motor failures have been reported because of lack of refrigeration due to sand plugging the space between the motor housing OD and the ID of the shroud. See [InTouch Content ID 3759553](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3759553) ESP Failure with a Shroud Application. In some cases, the use of a grooved shroud can help extend run life in high solid applications. See [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3768758) [3768758](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3768758) Use of Grooved Shroud to Avoid Passage of Solids through the ESP Unit. The use of sand screen in the shroud can also cause plugging. See [InTouch Content ID 2034243](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2034243) Shroud with Possible Sand Screen. **Does incorporating a shroud in the system affect the natural gas/well fluid separation?** Although there have not been any laboratory tests to determine the effect of a shroud on gas separation when utilizing a gas separator as opposed to no shroud, there are some fluid flow mechanics that probably come into play. In the calculations, the gas separation is a combination of the natural and mechanical. It is fairly impossible to divorce one from the other because they impact each other once the gas separator has been put into the wellbore. The first instinct is to believe more gas bubbles are going to escape around a shroud, but actually the light gas components are likely going to be pulled wherever the highest velocity takes place. That high velocity is going to be inside the shroud. There is a pressure drop in the shroud that was not in the fluid path prior to reaching it. It is sort of like the VOGEL principal that says the gas is going to move preferentially into the wellbore due to the pressure drop. When testing was done for the LOSF (Caltex Light Oil Steam Flood) in the Texaco Humble loop, there was a vortex separator and an AGH on the pump with a shroud and the equipment was sumped below where the fluid and gas was coming into the wellbore. Very little gas separation was seen. The reason was believed to be due to the fluid flow down to the shroud intake pulling the gas from the gas separator ports right back down to the bottom of the shroud. The gas separator ports were below the perforations and the recirculation caused by the fluid drawdown canceled the benefit of it. It is recommended just using the Gas Separation Routine in the DesignPro software to determine how much TOTAL gas separation to expect regardless of whether there is a shroud or not. In case there is a field with similar casing, equipment, flow rates, GOR, etc. in most of the wells (alliance situation perhaps), and there is any means to measure the gas volumes off the back side as well as through the tubing for a couple of them, the gas separation efficiency for that specific type of environment could determined. Environment is the key word and also is usually unique from well to well. ######## 13.5.2 Deviation Analysis in DesignPro Shroud Deviation Analysis in DesignPro is described in [InTouch Content ID 4368464](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4368464) . This content also covers other special configurations. Additional application notes - [InTouch Content ID 4197363](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4197363) Shroud Sizes Used for Different Submersible Equipment and [InTouch Content ID 4253112](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4253112) Shroud sizes Examples provide information on types of shrouds used for different ESP equipment. - When using a shroud there will be some pressure losses along the shroud due to the restricted fluid passage. An estimation of the pressure difference between the sensor and the pump intake for turbulent flow (Reynolds number > 2100) can be obtained by using the spreadsheet in [InTouch Content ID 3875673](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3875673) Pressure Drop Between Sensor and Pump Intake - Turbulent Flow. [(ESPCP)](.) ##### Electrical Submersible Progressing Cavity Pump (ESPCP) - [**Gather the Data and Specifications 3-1**](.) - [**PCP 3-1**](.) - [**Flex-Shaft Unit 3-1**](.) - [**Support Unit 3-2**](.) - [Configurations 3-2](.) - [Configuration Selection 3-2](.) - [Thrust Bearing Selection 3-2](.) - [Shaft HP Capacity 3-2](.) - [Seals 3-3](.) - [Oil Selection 3-3](.) - [Elastomers 3-5](.) - [Materials 3-6](.) - [Torque / HP Consumption 3-6](.) - [Failure Modes of Protectors and Thrust Bearings 3-6](.) - [Conductors 3-10](.) - [Selecting the Proper Conductor Configuration 3-11](.) - [EPDM 3-13](.) - [PEEK 3-13](.) - [Selecting a Barrier 3-14](.) - [Braid 3-14](.) - [Selecting the Jacket Material 3-15](.) - [Armor 3-15](.) - [Thickness 3-15](.) - [Profile 3-15](.) - [Selecting the Cable Configuration (Flat or Round) 3-16](.) - [Other considerations when selecting ESP cable 3-16](.) - [Ampacity 3-17](.) [(ESPCP)](.) ##### 3 Electrical Submersible Progressing Cavity Pump (ESPCP) ###### 14 Gather the Data and Specifications - [Basics 3-2](.) - [Material 3-7](.) - [Selecting the Appropriate Cable for the Application 3-8](.) - [Selecting the Proper Conductor Size 3-10](.) - [Selecting the Insulation Material 3-12](.) - [PPE (Polypropylene) 3-12](.) - [Selecting the Insulation Thickness 3-13](.) - [Armor Material 3-15](.) - [Special Components 3-16](.) - [Explosive Decompression 3-16](.) - [Available Power Cable and MLE Systems 3-18](.) Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. - General Information - Fluid Data - Surface Characterization — Power Issues - Wellbore Characterization - Operating Design Requirements and Criteria - Environment issues ###### 15 PCP Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. - Basics - PCP Selection - Constraints and Limitations - Material Selection ###### 16 Flex-Shaft Unit Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. - Basics - Unit Selection - Constraints and Limitations - Material Selection [(ESPCP)](.) ###### 17 Support Unit ####### 17.1 Basics The Support Unit has four primary functions: - couples the torque developed in the motor to the PCP via the support unit/protector shaft. - prevents entry of well fluid into the motor. - provides pressure equalization. - houses the bearing to carry the thrust developed by the pump. ####### 17.2 Configurations The support unit has four main configurations: - B-S/LT - LSB-S/LT - BSB-S/LT - LSBSB-S/LT ####### 17.3 Configuration Selection Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ####### 17.4 Thrust Bearing Selection Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ####### 17.5 Shaft HP Capacity One other function, which a Protector carries out, is transmission of the motor torque to the pump since it is physically located between the two. Although this may seem a little trivial, in the selection process we need to be certain that the protector shaft is capable of delivering the full torque required without exceeding its yield strength, which could result in a broken shaft. DesignPro does this calculation and provides a warning if the protector shaft capacity has been exceeded but it does not carry all the material option limits. Standard shaft is usually standard Monel, and high strength shaft is usually Inconel 625. Visually check in the Limits report to see what limit is being used. [(ESPCP)](.) Protector shaft sizes are fixed for a given protector series, but there are several shaft strength options for most. Similar to intake shafts, the protector shafts tend to be large compared to pump shafts, but always double check, especially in high hp applications. The 562-series protectors are only available in high-strength shafts. Refer to [InTouch Content ID 3761235 REDA Equipment Shaft HP Limits](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3761235) which provides horsepower limits for different shaft materials ####### 17.6 Seals Schlumberger standard shaft seals today use stainless steel parts, Monel spring, Silicon Carbide faces, and either HSN or Aflas for the bellows and O-ring. There are some special seals used on bottom intake, bottom discharge, and Hotline protectors (special applications). These seals use the metal bellows instead of the elastomer bellows due to possible sudden pressure changes or temperature. Some of these seals may use Hastalloy-C, Inconel, Chemrez O-ring, but typically use Silicon Carbide faces. ####### 17.7 Oil Selection The oils to be used in motors and protectors should be determined by the internal temperature of the motor in the string. The same oil should be used in both the motors and the protectors in the same string of equipment. [GeMs](http:\www.gems.slb.com\ematrix\emxLogin.jsp) document ED-191 is a guideline for the selection of oils to be used in electrical submersible motors, protectors and any oil-filled motor accessories. [Table 3-1](.) is an excerpt from ED-191. **Table 3-1: Guideline for the Selection of Oils in ESP Motors, Protectors, and Oil-filled Motor Accessories** | Motor Internal Temperature | Oil Selection | Application Notes | MS # | Descrip- tion | |------------------------------|-----------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------|---------------------| | < 270 degF (< 130 degC) | Reda #3 | Cool well applications. | MS-11-233 | Synthetic (PAO) Oil | | < 290 degF (< 145 degC) | Reda #2 | Oil will need to be heated during servicing when surface temperature is below 32 degF or 0 degC. | MS-11-164 | White Mineral Oil | | < 360 degF (< 180 degC) | Reda #5 | Recommended for general applications and all applications that use Maximus motors, protectors and ProMotors, 456 Dominators, 375 AS, 540 AS, 562 Series Motors and 738 Dominators. Unless specified in product description. Should also be used as a | MS-11-279 | Synthetic (PAO) Oil | [(ESPCP)](.) | Motor Internal Temperature | Oil Selection | Application Notes | MS # | Descrip- tion | |------------------------------|-----------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------|---------------------| | | | minimum for Hotline applications. | | | | <400 degF (< 204 degC) | Reda #6 | Under special requirements, this may be used down to 300 degF or 150 degC motor internal temperature. At startup, motor efficiency may be up to 10% points lower due to high oil viscosity at bottom hole temperature down to 150 degF or 65 degC | MS-11-292 | Synthetic (PAO) Oil | | >400 degF (> 204 degC) | Reda #7 | High Temperature extended run life protector, SAGD and Hotline motors | MS-11-314 | Synthetic (PAO) Oil | Detailed information on each oil is contained in the material specification and can be located in [GeMs](http:\www.gems.slb.com\ematrix\emxLogin.jsp) . Material Safety Data Sheet (MSDS) for each of the Reda oils are listed in [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3258882) [3258882](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3258882) . **Figure 3-1: Viscosity Comparison of Reda Motor Fluids** [(ESPCP)](.) **Figure 3-2: Viscosity Comparison of Reda Motor Fluids** For a comparison of standard protector with advanced protector materials see [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4012406) [4012406](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4012406) . ####### 17.8 Elastomers When selecting elastomers for a completion it is essential to consider both life of field and operational interventions to ensure that the elastomer selected can handle all the load cases. [InTouch Content ID 4118158 Best Practice](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4118158) gives an excellent example. All temperatures (high and low) that the material will be exposed to in all aspects of unit life, i.e. storage, shipping, testing, and installation should be considered as well as the full spectrum of future reservoir fluids and treatment fluids. High temperature elastomers may not be the best selection for a low temperature application for example. [InTouch Content ID 4443347](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4443347%2A) provides an Elastomer Selection Guide for Completions equipment and can be used as a reference, however it can't be fully applied to ESP equipment. Elastomers in completions tools are usually constrained, it typically sees static BHT and designed for high dP, so there is minimal extrusion gaps (and could be anti-extrusion rings), therefore usually elastomer's swelling is not an issue. Not all of the elastomers in the ESP strings are constrained with small extrusion gaps (i.e., protector bags and shaft seals bellows). **Example** The guidelines ( [InTouch Content 4443347](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4443347%2A) ) indicate that Aflas can be used for long-term applications with hydrocarbon aromatic solvents (eg. Xylene,Toluene). The situation changes for ESP equipment as soon as it sees significant thermal cycles, low dP and given that not all of the elastomers are constrained with small extrusion gaps. Such aromatic solvents as Xylene or Toluene will cause swelling of unconstrained Aflas parts, will make it less robust (durometer and tensile strength drop) and less tolerant to abrasives, mechanical impact, etc. Protectors typically have the choice between HSN and Aflas elastomers for shaft seals, O-rings, and bags. Special attention is required to bag selection, since the bags in a protector are often the limiting factor in runlife. [(ESPCP)](.) ####### 17.9 Materials When choosing Protector metallurgy, use the same guidelines as for pumps. Generally the protector should be matched to the rest of the string, but it can be higher specification. Avoid using lower specification than the rest of the equipment in order to avoid galvanic corrosion. **Note: Galvanic corrosion** The greatest possibility of dissimilar metal corrosion associates with shallow water wells applications due to presence of dissolved oxygen in water, which is one of the strong catalyst for galvanic corrosion as soon as it greatly increases water conductivity. Galvanic corrosion is not common for deep wells, because formation water usually doesn't contains dissolved oxygen. The Material specifications for protectors can be found in [InTouch Content ID 3043579](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3043579) . ####### 17.10 Torque / HP Consumption Tests have confirmed that the horsepower consumed by a protector during operation is minimal and is not a factor when sizing equipment. DesignPro does not add horsepower for a protector. ####### 17.11 Failure Modes of Protectors and Thrust Bearings Failure modes of protectors and thrust bearings: - Labyrinth protectors will fill with well fluid if cycled excessively, causing the thrust bearing and motor to fail. Many times dismantle inspections show water in the lower portion of a labyrinth protector and this is mistakenly thought to have been there when the unit was operating down hole. Always remember that a labyrinth protector will normally operate with some water (well fluid) in the top end by design. If the unit is laid on its side and transported, the water can move to the bottom. - Protector bags will fail if exposed to incompatible well fluids, or if subjected to excessive temperatures. - Bearings will fail if misaligned or subject to excessive thrust outside of design conditions. - High temperature may cause bearing damage due to viscosity variations in the oil film between the rotating and stationary sections of the thrust bearing. - Vibration caused by faulting pump/motor may lead to premature bearing failure. - Contaminated lubricant will cause premature failure. Great care must be taken during system installation that oil fluids are clean and free from solids, etc. - Some types of high load thrust bearings will be permanently damaged by rotation of the shaft in the wrong direction, and care should be taken to ensure that the motor coils are connected correctly to the three phase supply. Back spinning of the pump due to well fluid flowing back down the tubing following pump shut down must also be prevented with such bearings. This can be achieved by installation of a check valve at the pump outlet. [(ESPCP)](.) ###### 18 PMM Motor Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. Refer to TPS-Line Permanent Magnet Motor for ESP (VPEDMT) - Product Bulletin [(InTouch ID](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7194181%2A) [7194181)](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7194181%2A) . ####### 18.1 Material When choosing motor metallurgy and elastomers, use the same guidelines as for pumps. Generally you want to match the motor to the rest of the string, but it can be higher specification. Avoid using lower specification than the rest of the equipment in order to avoid galvanic corrosion. **Note: Galvanic corrosion** The greatest possibility of dissimilar metal corrosion associates with shallow water wells applications due to presence of dissolved oxygen in water, which is one of the strong catalyst for galvanic corrosion as soon as it greatly increases water conductivity. Galvanic corrosion is not common for deep wells, because formation water usually doesn't contains dissolved oxygen. The Material specifications for motors can be found in Sections 11, 12 and 13 of [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3043579) [3043579](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3043579) . ###### 19 Power Cable The power cable is a major component of the ESP system, which carries the electrical power from surface to the downhole motor, and carries pressure, temperature, vibration, etc. signals from the downhole monitoring sensor back to the surface. The Electrical Submersible Pump (ESP) power cable is designed and manufactured from five primary components, conductors, insulation, barrier, jacket and armor. In special applications, two additional components, stainless steel capillary tubing and an outer PVC jacket can also be provided. **Conductor Insulation** Barrier Jacket Armor **Figure 3-3: Power Cable** These cables typically operate on three-phase systems, which mean there will be three conductors in the cable. These copper conductors can be configured to be solid, stranded, or compact-stranded, each of which have its own unique advantages and disadvantages. On the surface of each of these [(ESPCP)](.) conductors is a thin lead-alloy coating, called Amaloy. This coating provides a layer of protection for the copper substrate from chemical attack due to exposure to hydrogen sulfide (H2S). Each phase is individually insulated with a high dielectric material and this insulation is physically bonded to the conductor with an adhesive. The voltage rating for the cable is dictated by the wall thickness of this insulation layer. ESP cable is manufactured in several voltage ratings 3, 4, 5 and 8 kV. In an ideal situation, in which handling damage and environmental exposure is not a problem, the conductor and insulation is all that would be required to adequately operate this ESP cable; however, these cables are not being installed in ideal situations, therefore we need to provide additional protection for the conductor and the insulation. This additional protection comes in the form of a barrier over each of the conductors, additional jacketing material over all three phases and finally a damage resistant metallic armor layer over the entire cable. The selection or design of a proper ESP cable for a particular application depends on many factors. There are several industry standards, ICEA (Insulated Cable Engineering Association), IEEE (Institute of Electronic and Electrical Engineers) and API (American Petroleum Institute) that are referenced for the design, qualification testing, manufacture, acceptance testing, and application of ESP power cables. ####### 19.1 Selecting the Appropriate Cable for the Application The process of selecting a power cable is basically a two-part process: - Selecting the proper size and configuration of conductor (AWG), and - Selecting the required construction and cable configuration, considering: - Calculations for the surface voltage required - Calculations for the cable conductor temperature (ampacity), and - Special operating and fluid conditions, fluid treatments, gas, fluid level, etc. - Surface temperature. [InTouch Content ID 3016052](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3016052) contains an Excel spreadsheet(s) that can be used to automatically generate an ESP power cable or MLE (cable only) Ampacity Chart and calculate temperature and amps limits for a range of common cable types. ########## T  (a I2) T c well **Equation 3-1:** Tc  Twell a where Im ax  **Term Definition** **Tc** adjusted conductor temperature, degF **a** current carrying capacity factor, dimensionless **I** current, amperes [(ESPCP)](.) **Term Definition** **Twell** ambient well temperature, degF **Imax** is the maximum current in amps **MLE temperature rating** An MLE includes the flat cable length and the pothead that fits into the motor head. Typically the flat cable has a higher temperature rating than the pothead connection itself. The spreadsheet(s) under [InTouch Content ID 3016052](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3016052) calculate the conductor temperature of the most common REDA cables, based on cable type, current, and downhole temperature. Note that for MLE's included in the spreadsheet(s), the calculation result DOES NOT include the pothead limitation. Be aware that this can be misleading. The MLE temperature rating of the combined flat cable and pothead is based on the weaker component (usually pothead) and is found under the attributes in OneCAT details. In general, all standard MLE's have a pothead temperature rating of 300 degF (conductor), which is usually the limiting factor. The Hotline MLEs range have pothead ratings up to 482 degF, depending on the motor and MLE design. The MaxLok MLEs have a pothead temperature rating up to 400 degF. The Trident MLEs have a pothead temperature rating between 300 and 400 degF, depending on the motor design and application (i.e., H2S). All MLE types are listed in OneCAT with the rating. Explanation for the lower rating of the pothead part of typical standard MLE: The standard pothead typically being used in most MLE’s have a external body casting made of grey iron which is a non- magnetic high –Nickel alloy, while the internal blocks are made of PEEK. The limiting factor in pothead rating is the PEEK glass transition temperature. Once the temperature exceeds 300F the PEEK material will become soft and the seal block(s) will begin to deform the front block due to the stored energy when compressed to from the seal. If this were to happen the seal would be compromised. The failure mode will be either well fluid entering the motor or electrical fault within the MLE due to the seal block movement damage to the insulation. It is not recommended by LPC to use this MLE within these operating conditions. Remember that the above describes an example standard MLE. If in doubt, if you have a special application or if you have questions about the rating, please contact InTouch. Therefore, to check the temperature limit of an MLE (combined flat cable and pothead) using the attached MLE spreadsheet, make sure you do the following: - Find the temperature rating of the MLE through OneCAT or GeMS (contact InTouch if you cannot find it). - Use the attached spreadsheet(s) ( [InTouch Content ID 3016052](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3016052) ) to calculate operating temperature (after entering your application data). - Compare the calculated operating temperature of selected cable to MLE rating determined in step -1- above. Calculated operating temperature must be below the MLE temperature rating for acceptable application. Cable-related calculations in DesignPro: DesignPro, in its current version (Jan 08) does not check selected MLE's against temperature rating. MLE rating check has to be done by the AE separately using the described procedure, above. Also note that DesignPro has a rigorous voltage drop calculation for the power cable only. It does the calculation and check on the power cable conductor temperature. In fact in the LIMITS report you get the Max Ampacity, actual cable conductor temperature, start-up ratio, the cable temperature rating. On the Detail report some of the same parameters are given but here you see the actual power cable voltage drop that was calculated. The system KVA and Surface Voltage requirements are a result of the total power calculations. [(ESPCP)](.) Future versions of DesignPro will include MLE rating calculation and comparison. This will be announced separately at the time of new version release. ####### 19.2 Conductors ######## 19.2.1 Selecting the Proper Conductor Size The primary consideration in selecting a conductor for a particular application is selecting its appropriate size. In general, selecting a conductor size is a balance between reliability and cost. The main purpose of the conductor is to carry current from the surface to the motor. The size of a conductor refers to the cross-sectional area. Most electrical cable manufacturers refer to the Brown and Sharpe American Wire Gauge (AWG) to denote the size of the conductor. Standard conductors used in ESP applications are #2/0, #1/0, #1, #2, #4, and #6 gauge. Increasing gauge numbers give decreasing wire diameters and hence decreasing cross-sectional areas. The cross-sectional area of the conductor is important for several reasons. First, the smaller the conductor, the higher the resistance, which results in a higher temperature increase in the conductor. So, conductor size has a direct influence on the cable temperature rating. Second, a higher resistance results in more voltage loss in the conductor. If the voltage loss is too high, this can result in motor starting problems. In addition, of course, voltage loss in the cable is less efficient from an electrical operation standpoint. Finally, the resistance in the conductor plays a role in defining the resonant frequency of the electrical system, which is important for harmonic analysis, especially with PWM-style variable speed drives. Larger conductors have a higher overall efficiency. But there is a point of diminishing return, the larger the conductor, the higher the cost of the cable. So, there is a trade-off between capital cost and operating cost. To select the most appropriate conductor size for an application, we first need to determine the voltage drop in the conductor. Voltage drop is a function of the current flowing through the wire, the size of the wire, the length of the wire and, to some extent, the temperature of the wire. Voltage drop can be calculated; however, the easiest way to do this is with a voltage drop chart as shown in [Figure 3-4](.) . **Figure 3-4: Voltage Drop Chart** [(ESPCP)](.) An increase in conductor temperature will increase the voltage drop in the conductor. There are “correction factors” available to correct the voltage drop based on the conductor temperature, but it is usually better to ignore the temperature multiplier. The reason for this is that the voltage loss in the cable is not “in phase” with the voltage in the motor but rather the current. To get the true voltage drop in the cable would require a power factor calculation, which would show the voltage drop to be less than what we would predict by simply making a resistance calculation. Next, we need to evaluate motor starting issues. The length and size of the conductor are the biggest determining factors on starting characteristics for a submersible motor. Proper selection of the conductor and starting method can insure that the motor will start reliably. ######## 19.2.2 Selecting the Proper Conductor Configuration The secondary consideration in selecting a conductor is selecting the conductor configuration (solid/ stranded/compact-strand). Typical ESP cable conductors are made from electrical grade copper and are coated with a thin layer of a lead-alloy for corrosion resistance from H2S chemical attack. There are three different options available for the selection of the conductor configuration, each with its own unique advantages and disadvantages. Solid conductor – just as the name sounds, this conductor has a circular cross-section. Stranded conductor - seven wire stranded configuration, comprised of a center strand and six outer strands that are twisted around the center strand. **Figure 3-5: Solid** Compact-strand – seven wire stranded configuration that has been pulled through several sets of compacting rollers, effectively reducing the diameter of the conductor. **Figure 3-6: Stranded** **Figure 3-7: Compacted** [(ESPCP)](.) **Table 3-2: Advantage/Disadvantage Conductor Configurations** | Configuration | Advantage | Disadvantage | |-----------------|---------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------| | Solid | Smallest diameter Lowest cable cost Low electrical stress | Decreased flexibility, especially with larger conductors | | Strand | Increased flexibility | Larger diameter Increased cable cost due to more material usage and additional processing steps Higher conductor-insulation electrical stress | | Compact-strand | Larger diameter than solid but smaller than strand Good flexibility | Increased cable cost due to more material usage and additional processing steps | Using a stranded conductor for ESP power cable results in cable that is much more flexible (physically) than the solid conductor and therefore easier to work with. This becomes more critical when working with larger conductor sizes. Most ESP stranded cables use seven-strands, six strands twisted around a single center strand. Compact-strand is very similar except the outer strands have been compacted, resulting in a reduced physical size. Stranded cable of any given size (gauge) approximates the cross-sectional area of the same size solid cable. The resulting stranded conductor will have a larger diameter, and therefore the outer dimensions of the cable will be larger as well. Due to higher process costs and larger size, stranded cable tends to be more expensive than the same size solid cable. ####### 19.3 Selecting the Insulation Material Once the conductor has been selected, the next component to select is the insulation. The insulation is a dielectric layer that is extruded directly onto the conductor and provides the electrical isolation of the conductor from other conductors and from the ground plane. Schlumberger offers three types of dielectric insulations, polypropylene (PPE), ethylene propylene diene rubber (EPDM) and PEEK (poly-ether-ether-ketone). The differences between the three types of insulations are the basis of the differences between cable types. ######## 19.3.1 PPE (Polypropylene) PPE, considered a thermoplastic material, is characterized as follows: - low temperature rating (250 degF) - excellent resistance to well fluid - excellent electrical properties - low cost - susceptible to crazing (microcracking) when exposed to high levels of CO2 (>5%) [(ESPCP)](.) ######## 19.3.2 EPDM EPDM, a thermoset, elastomeric material, is characterized as follows: - high temperature rating (450 degF) - excellent electrical properties, though perhaps not as good as PPE - limited resistance to well fluids (oil swell). ######## 19.3.3 PEEK PEEK, a thermoplastic material, is characterized as follows: - high temperature rating (500 degF) - excellent resistance to oil - excellent electrical properties - high cost. **Note** There are many types of PPE and EPDM available on the market. Even though the material may say PPE or EPDM, the physical, electrical and thermal properties may vary significantly depending on how the material is formulated and processed. This is also true when comparing EPDM compounds between different material manufacturers. During the extrusion operation, a high temperature adhesive is applied directly onto the copper conductor, bonding the insulation to the conductor. This bond between these two components is critical for several reasons: - **Eliminate gas transmission in conductor** . Without this bond, gas permeating the insulation is free to travel up the conductor at this interface. When the gas reaches an area of lower external pressure, the higher pressure gas will cause the insulation to expand, resulting in damage. - **Eliminate damage from corrosive gas** . This bond prevents corrosive from accumulating at the surface of the conductor, resulting in damage to the conductor over time. - **Eliminate corona discharge** . Accumulation of gas at the surface of the conductor can become ionized due to the current flow through the conductor. This ionization can result in a corona being formed, resulting in damage to the insulation layer. ####### 19.4 Selecting the Insulation Thickness The voltage rating for the cable is selected based on the maximum voltage the cable will see during the operation of the ESP equipment. This will typically be the operating voltage at the surface since there will be a drop in voltage throughout the length of the cable due to resistance losses. The cable voltage rating is determined by the wall thickness of the dielectric layer (insulation) over the copper. Schlumberger currently offers three voltage ratings for cable, 4, 5 , and 8 kV, each with increasing insulation wall thickness. [(ESPCP)](.) ####### 19.5 Selecting a Barrier Over each of the insulated conductors is a barrier layer. The barrier is used to protect the underlying insulation from exposure to well fluids and well gas, both of which could cause accelerated deterioration of the insulation and copper conductor. The rate of deterioration is dependent upon the gas, the concentration of the gas and the exposure temperature. Some examples of this degradation include EPDM oil swell, copper conductor reduction to copper sulfate when exposed to H2S, EPDM expansion and damage in a gas decompression mode. To prevent this exposure and damage, a barrier over the insulation is critical in certain environments. There are two categories of barriers, non-lead and lead. Non-lead barriers, such as PTFE tape wraps, provide excellent protection from well fluid and excellent hoop strength for decompression, but do not stop the ingress of gas into the insulation. This typically is not an issue unless the gas contains H2S levels greater than 3%. In this case, lead barriers are recommended. Extruded lead jackets are the ultimate barrier, providing an excellent barrier to both well fluids and gas. In highly corrosive applications, the lead barrier may also be wrapped with the PTFE tape, protecting the lead from corrosive damage. Schlumberger can also offer extruded fluoropolymer barriers. However, extruded barriers have significantly less hoop strength than taped barriers. In side-by-side testing with tape barriers, extruded barriers consistently exhibiting significant damage in both the barrier and the underlying insulation in decompression modes. For this reason, the use of extruded fluoropolymer barriers is highly discouraged. [Table 3-3](.) indicates the temperature rating, advantages and disadvantages for each type of barrier. **Table 3-3: Temperature Rating, Advantages and Disadvantages for each type of barrier.** | Barrier | Type of Barrier | Temp. Rating | Advantage | Disadvantage | |-----------|-------------------|----------------|---------------------------------------------------------------|----------------------------------------------------------| | Non-lead | PTFE tape wrap | 400 degF | Excellent barrier to fluids Good hoop strength for insulation | No barrier to gas | | Lead | Extruded lead | 450 degF | Excellent barrier to fluids and gas | Heavy weight Increased susceptibility to handling damage | ####### 19.6 Braid Polyester braid is commonly used with taped barriers (as a result, many people refer to taped barrier as “tape and braid”) and leaded round cables. The braid's function is to protect the tape and lead during subsequent manufacturing processes. In the dowhhole application, it serves no use. The braid was also used on leaded flat cables to act as a cushion during the armoring operation; however, significant improvements have been made to the armoring process, allowing the elimination of the braid from these cables. [(ESPCP)](.) ####### 19.7 Selecting the Jacket Material The primary function of the jacket is to provide damage resistance for the underlying insulated conductor (RedaMax250 – POTB) or underlying twisted cable core for numerous round cables. There are a several jacketing materials that can be used depending upon the application being targeted. Possible materials for the jacket are high-density polyethylene, Nitrile, or EPDM. The jacket selection depends upon chemical resistance properties and temperature considerations. Nitrile is lower temperature and provides better resistance to oil, but has poor resistance to water. Just like the material used as insulation, EPDM jacket is higher temperature but tends to swell in oil. ####### 19.8 Armor The final component for the cable that we need to address is the armor layer. The armor, a formed, metallic layer that is helically wrapped around the cable core, provides two services to the power cable. First, it protects the cable from mechanical damage during handling and installation. Second, it provides reinforcing hoop strength to protect against jacket swelling - this is very important for EPDM jackets. Do not underestimate this second role; many failure analyses for cable have determined that loss of the armor due to corrosion was the reason that the cable eventually failed. ######## 19.8.1 Armor Material SLB cable armor is offered in three types of material: galvanized steel, stainless steel (316 L) and Monel (copper-nickel alloy), listed in increasing order of corrosion resistance. Galvanized armor is the standard armor used for most downhole applications. For more corrosive wells, stainless steel can be used; however, this material has temperature limits, especially in the presence of chloride ions, which could result in stress chloride cracking. For the most severe corrosive well environments, Monel armor is the best choice due to its excellent corrosion resistance. Monel is also the standard armor for MLEs because of the potential for high temperature, corrosive environments, and galvanic corrosion as the cable passes by various materials on the ESP equipment. ######## 19.8.2 Thickness The different armor materials are available in different thicknesses. For example, galvanized armor is available in 0.020, 0.025, and 0.034-in., while stainless steel is available in just 0.020-in and Monel is available in 0.015 and 0.020-in. Thicker armor layers are typically recommended for more corrosive environments. ######## 19.8.3 Profile Armor is available in various profiles. The basic profile for armor is crowned interlocked and is used for round cable constructions. Also available are flat profile interlocked, low profile armors, and double armor (two layers of armor). The choice depends upon the downhole environment and the expected handling conditions. Flat and low profile armor are used more frequently with flat cable, where the cable dimensions and profile are typically more critical. [(ESPCP)](.) Round Profile Flat Profile **Figure 3-8: Profile types** ####### 19.9 Special Components In addition to the standard five cable components discussed, additional components such as integral injection lines, outer PVC extruded jackets (over the armor), and ground wires can be supplied. The 316L stainless steel injection lines can be supplied in ¼, 5/16, 3/8, and ½-in x 0.049-in sizes and are integral to the cable. For ocean floor applications (subsea umbilicals), a PVC outer jacket can be extruded over the armor layer, providing a layer of protection for the armor. ####### 19.10 Selecting the Cable Configuration (Flat or Round) Schlumberger offers two cable configurations either flat or round. The biggest advantage to flat cable is the small overall profile, allowing the cable to be used in wells where space constraints exist. For example, applications in 7" liners often require flat cable to adequately fit without damage. Most flat cables do not have an overall jacket. This, coupled with the overall flat configuration, make these cables more susceptible to damage. In applications with highly deviated wells, some consideration should be given to the use of round cables instead. ####### 19.11 Other considerations when selecting ESP cable ######## 19.11.1 Explosive Decompression Explosive decompression occurs as a result of a rapid decrease in the pressure that the cable is exposed to. At elevated pressure in a well environment, gas will permeate the non-metallic cable components and, over time, saturate the elastomer compounds in the cable. When the pressure external to the cable decreases, the higher pressure gas in the elastomer materials will start to migrate to the lower pressure. If this pressure drop occurs too quickly or the differential pressure is significant, the gas will not be able to diffuse quickly enough through the elastomer wall and will rapidly expand. This expansion places significant stress on the elastomers and can result in severe damage to the cable component. This rapid decompression can occur during motor start-up when the well fluid is drawn down or during cable retrieval from the well. Controlling how rapidly we decrease the annular pressure in the well or how quickly the ESP system is pulled to the surface can significantly decrease the potential for damage. In addition, we can also prevent the gas from entering the insulation with the use a lead barrier. [(ESPCP)](.) ######## 19.11.2 Ampacity In the earlier discussion, we have mentioned ampacity and the role it plays in the temperature rise in the conductor. The ampacity of a cable is a function of the size of the conductor, the operating amperage placed on the conductor, the ambient temperature the cable is exposed to in the well, and the thermal properties of the various cable components and the cable configuration. So, each cable at each size has an ampacity value. The ampacity calculations are used to determine the temperature rise in the conductor and is defined by the [Equation 3-2](.) . **Equation 3-2:** Where, **Term Definition** **Tc** temperature of the conductor, degF **I** operating current, amps **a** ampacity coefficient, unique term for each cable type encompassing the thermal properties of each cable. **Twell** ambient temperature of the well The conductor temperature calculated using this equation must be below the temperature rating of the cable. Conductor Current (Ampere) Using [Equation 3-2](.) , ampacity charts have been created for each cable type. An example is shown in [Figure 3-9](.) . | 250 200 150 #1AWG #2AWG #4AWG 100 #6AWG 50 0 100 200 300 400 500 Well Temperature (°F) | 250 200 150 #1AWG #2AWG #4AWG 100 #6AWG 50 0 100 200 300 400 500 Well Temperature (°F) | 250 200 150 #1AWG #2AWG #4AWG 100 #6AWG 50 0 100 200 300 400 500 Well Temperature (°F) | |----------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------| | | Maximumall owable conductor temperature 450°F | | Maximumall owable conductor temperature 450°F **Figure 3-9: Sample of Ampacity Chart for 450 degF Cable** [(ESPCP)](.) ####### 19.12 Available Power Cable and MLE Systems Power cable and MLE systems are designed and manufactured for: - land and offshore wells - gas, oil, or condensate producers - high-temperature, gassy, and corrosive wells - deepwater wells with high-horsepower ESP systems. While a basic configuration of the main components is suitable for most well conditions, each standard cable can be customized to suit the specific requirements of a given well, including temperature and pressure ratings, corrosive properties, and gas/oil ratios. Various grades of armor ranging from standard galvanized steel to MONEL alloys are available for protection against corrosive environments. All these ESP cables feature fully annealed, high- conductivity copper and tin lead–alloy-coated conductors for additional protection against corrosion. They also include fluid- and gas-impermeable barriers and corrosion-resistant, high-strength metallic armors. Refer to [InTouch Content 7046458](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7046458%2A) for the current power cable and MLE specifications. The part numbers for available power cables and MLEs can be found in [OneCAT](https:\onecat.slb.com\cs\catalog) . Additional variation can be requested via RFQ. Guidelines for cable testing and splicing can be found in the Cables Reference Manual [(InTouch ID 5765593)](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A5765593%2A) . ##### Advanced Completion ESP - [**Gather the Data and Specifications 4-1**](.) - [**ESP Bypass System 4-1**](.) - [Design Considerations 4-3](.) - [Physical Limitations 4-4](.) - [Deviation 4-6](.) - [Metallurgy 4-6](.) - [Elastomers 4-7](.) - [Bypass Tubing 4-17](.) - [Bypass Tubing Clamps 4-18](.) - Wireline Re-Entry Guide *4-20* - Motor Base Plug *4-20* - [Pump Support Subs 4-21](.) - [Isolation Tool 4-22](.) - [Wireline Logging Plug 4-23](.) - [Coiled Tubing Logging Plug 4-24](.) - [Safety Clamp 4-27](.) - [Stove Pipe Table 4-28](.) - [**Dual Concentric ESP System 4-30**](.) - [**Auxiliary Equipment 4-31**](.) *4* **Advanced Completion ESP** ###### 20 Gather the Data and Specifications - [Bypass System Overview 4-1](.) - [Requirements 4-3](.) - [Bypass System Equipment 4-8](.) - [Y-Tool Sub-Assemblies 4-9](.) - [Bypass System Plugs 4-21](.) - [Standing Valve 4-21](.) - [Bypass Handling Tools 4-26](.) - [Swivel Lift Nubbin 4-26](.) - [Bypass Design Check List 4-28](.) Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 21 ESP Bypass System ####### 21.1 Bypass System Overview The Bypass system is a solution to enable intervention, or logging with wireline or coiled tubing, below an electrical submersible pump (ESP), without the need to pull the completion from the well. **Figure 4-1: ESP Bypass System Diagram** The junction in the Bypass System is created by the Y-tool, highlighted blue in [Figure 4-1](.) . The Y-tool aligns the axis of the bypass tubing (clamped to the ESP) with the axis of the production tubing above, creating an intervention conduit to below the ESP. The ESP discharge enters the tubing string via the eccentric leg of the Y-tool and is prevented from recirculating down the bypass tubing by a flapper in the Auto Y-Tool, or a wireline blanking plug in the Standard Y-Tool. Where intervention is required to be undertaken with the ESP running, for example in production logging, a Bypass Logging Plug is run with the wireline or coil tubing to prevent recirculation. Bypass systems have expanded from their original use to become the primary method for installing multiple ESP systems in the same well. In this case, the bypass tubing allows production past the ESP. ####### 21.2 Design Considerations The following section highlights the various aspects to consider when using a bypass system. These include the suitability of a bypass system for, and the physical limitations of a given well. : provides a check list of all aspects that must be covered when designing a bypass system. ######## 21.2.1 Requirements When considering a bypass system there are several issues that must be addressed. The first consideration is to establish why one is required. Typically, the reason for a bypass system is to gain access to the wellbore while an ESP is installed. The following is a list of operations that can be carried out via a logging bypass system with an ESP in the well: - Wireline logging below the ESP - Coiled tubing logging below the ESP - Retrieval of plugs below the ESP - Memory gauge deployment below the ESP - Bridge plugs can be set for water shut off - TCP guns deployed and detonated below the ESP - Well stimulation through Coiled Tubing or Bypass tubing - Wireline perforating below ESP - Bottom hole samples can be deployed - Anything that can normally be carried out with wireline or Coiled Tubing. Another reason for a bypass system is if the intention is to deploy a back-up ESP in what is commonly known as a “dual system”. If this is the only reason for using bypass systems then access below the ESP is of no concern. However, if there is still a requirement to access the wellbore, then two bypass systems are required. Once the need for a bypass system has been established, the design of the system can be looked at in more detail. For example, if a bypass system is required to allow coiled tubing logging below the ESP, then the size of coil that will be used needs to be known. This will determine what size of bypass tubing should be used and what size of seal bores are required. However, several variables must first be considered when designing a bypass system: - downhole conditions - casing details - production tubing details - minimum uphole restrictions - and ESP details, bearing in mind that the ESP supplier may not be Schlumberger. ######## 21.2.2 Physical Limitations The first area to consider is the suitability of the well for a bypass system. To determine whether an ESP and bypass system will fit inside the well, the size of the equipment to pass through the tubing to access the wellbore must be decided. This in turn determines the minimum size of bypass tubing required, which affects the maximum size of ESP allowed when compared against the drift diameter of the well casing. To decide on the minimum size of bypass tubing, the drift diameter of the tubing, and not the inner diameter (ID), must be used. **Example** For example, if the customer wants to run a 1.85 in OD plug into the well, the drift size of the bypass tubing cannot be less than 1.85 in. The minimum drift size suitable, therefore, is 1.901 in , meaning the bypass tubing cannot be less that 2.375 in OD, as shown in [Table 4-1](.) . **Table 4-1: Standard Bypass Tubing Data** | Tubing OD (in) | Tubing ID (in) | Drift Size (in) | |------------------|------------------|-------------------| | 3.5 | 2.992 | 2.867 | | 2.875 | 2.441 | 2.347 | | 2.75 | 2.362 | 2.268 | | 2.375 | 1.995 | 1.901 | | 2.125 | 1.869 | 1.775 | | 1.5 | 1.244 | 1.15 | Once the minimum size of the bypass tubing is known, [Table 4-2](.) can be used to determine the maximum allowable OD of the ESP when compared against the drift diameter of the well casing. However, only the largest diameter of all ESP equipment should be taken into account. **Table 4-2: Maximum OD of ESP Assembly** | | 3.750 in | 4.000 in | 4.562 in | 5.130 in | 5.400 in | 5.440 in | 5.625 in | |-----------------------|------------------|------------------|------------------|------------------|------------------|------------------|------------------| | Cabling Size | Bypass Tubing OD | Bypass Tubing OD | Bypass Tubing OD | Bypass Tubing OD | Bypass Tubing OD | Bypass Tubing OD | Bypass Tubing OD | | 6 5/8 in — 20 lbf. ft | 2.125 in | 1.500 in | | | | | | | 6 5/8 in — 20 lbf. ft | 1.500 in | 1.500 in | | | | | | | 6 5/8 in — 20 lbf. ft | 1.500 in | 1.500 in | | | | | | | 6 5/8 in — 20 lbf. ft | 1.500 in | 1.500 in | | | | | | | | 3.750 in | 4.000 in | 4.562 in | 5.130 in | 5.400 in | 5.440 in | 5.625 in | |------------------------|------------|------------|------------|------------|------------|------------|------------| | | | | | | | | | | 7 in — 23 lbf.ft | 2.375 in | 2.125 in | | | | | | | 7 in — 26 lbf.ft | 2.375 in | 2.125 in | | | | | | | 7 in — 29 lbf.ft | 2.125 in | 1.500 in | | | | | | | 7 in — 32 lbf.ft | 2.125 in | 1.500 in | | | | | | | 7 in — 35 lbf.ft | 2.125 in | 1.500 in | | | | | | | | | | | | | | | | 7 5/8 in — 26.4 lbf.ft | 2.875 in | 2.750 in | 2.125 in | 1.500 in | | | | | 7 5/8 in — 29.7 lbf.ft | 2.875 in | 2.375 in | 2.125 in | 1.500 in | | | | | 7 5/8 in — 33.7 lbf.ft | 2.875 in | 2.875 in | 1.500 in | 1.500 in | | | | | | | | | | | | | | 8 5/8 — 28 lbf.ft | 2.875 in | 2.875 in | 2.875 in | 2.750 in | 2.375 in | 2.375 in | 2.125 in | | 8 5/8 — 32 lbf.ft | 2.875 in | 2.875 in | 2.875 in | 2.375 in | 2.375 in | 2.125 in | 2.125 in | | 8 5/8 — 36 lbf.ft | 2.875 in | 2.875 in | 2.875 in | 2.375 in | 2.125 in | 2.125 in | 1.500 in | | | | | | | | | | | 9 5/8 in — 40 lbf. ft | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | | 9 5/8 in — 43.5 lbf.ft | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | | 9 5/8 in — 47 lbf. ft | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | | 9 5/8 in — 53.5 lbf.ft | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.875 in | 2.750 in | | | | | | | | | | | | 3.750 in | 4.000 in | 4.562 in | 5.130 in | 5.400 in | 5.440 in | 5.625 in | |----------------------|----------------------------------------------|----------------------------------------------|----------------------------------------------|----------------------------------------------|----------------------------------------------|----------------------------------------------|------------| | 10 3/4 — 51 lbf.ft | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in | | 10 3/4 — 55.5 lbf.ft | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in | | 10 3/4 — 60.7 lbf.ft | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in Bypass Tubing or larger may be used | 3.500 in | Using [Table 4-2](.) and the example of the 2.375 in bypass tubing previously given, it can be seen that when the well casing size is 7-5/8 in, 29.7 lb/ft, the maximum allowable OD of the ESP is 4.00 in. It should be borne in mind, however, that if the largest ESP allowed is too small for a specific application, then the suitability of a bypass system should be reconsidered. It should also be noted that while the minimum size of bypass tubing for a specific application can be determined, the largest OD of bypass tubing which can be accommodated in the well is recommended for use in case of future intervention operations that may not be considered at the design stage. ######## 21.2.3 Deviation Bypass systems are designed to be near to casing drift. As a result, the deviation severity of the ESP string is likely to be the same as the deviation severity of the casing and reviewing the limitations should, therefore, be simple. Nevertheless, it is recommended that a deviation analysis should always be performed. While DesignPro has a deviation analysis function, it does not have the ability to include bypass tubing alongside the ESP. The recognized method to best simulate this, therefore, is to run a case with a new 'theoretical casing ID' which is calculated from the actual casing ID minus the bypass tubing OD. ######## 21.2.4 Metallurgy The metallurgy of the equipment and the type of elastomers required are very important: if they are wrong equipment may fail prematurely. To determine the specific metallurgy required for a bypass system, the downhole conditions, most specifically the well chemistry, needs to be known. The majority of bypass equipment typically comes in two different metallurgies: Low Alloy Steel (Consisting of L80 Type 1, AISI 4130, AISI 4140 parts) or 13Cr (consisting of L80 13Cr, AISI 410, AISI 420, CA6NM parts). For manufacturing reasons, some legacy components made from castings are commonly provided as standard in 13Cr materials, unless specifically requested otherwise. So, for example, a low alloy steel Y-Tool sub-assembly P/N, may have a 13Cr Y-Tool (block). Sub assembly details should be checked, and where the combination of materials is not suitable, other options should be selected. Generally a corrosion resistant alloy, such as 13Cr, is selected based on the content of the H2S and/ or CO2 in the produced gas, as well as the acidity of the produced water. [Table 4-3](.) can be used as a guide. **Table 4-3: General Metallurgy Recommendations for Artificial Lift Bypass Systems and Monitoring** | Bypass Systems | H2S | CO2 | Ph | Chlorides | Comments | |------------------|----------|----------|---------------|---------------|-----------------------------------------------------| | Low Alloy Steel | | | Not Specified | Not Specified | Good for H2S service for low WC or inhibited wells. | | 13Cr | <1.5 psi | <200 psi | 3.5 | 100,000 mg/l | H2S limit 1.5 psi | | No | |---------| | Yes | | Caution | **Note** The statements above are only guidelines. If Redalloy material is being used for the ESP units, 13Cr should be used for the bypass equipment. 1 can provide more details on the correct grade. ######## 21.2.5 Elastomers Viton and Aflas are commonly used elastomers in bypass systems, although other materials have been used where required. Again, the well chemistry and maximum operating temperature of the system must be known before deciding which elastomer is more suitable. [Table 4-4](.) provides a quick reference. **Table 4-4: Elastomer Limits** | Elastomer | Viton | Aflas | |-----------------------------------------|-----------------------------------------|-----------------------------------------| | Temperature Limit | 400 degF | 400 degF | | Relative Chemical Resistance Properties | Relative Chemical Resistance Properties | Relative Chemical Resistance Properties | | Water/Oil | OK | OK | | Hydrogen Sulfide | OK | OK | | Amines | Avoid | OK | | Polar Chemicals | OK | OK | | Carbon Dioxide | OK | OK | 1. [InTouch Content ID 3985484](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3985484) ####### 21.3 Bypass System Equipment The following section describes the various components of a bypass system (as seen in [Figure 4-2](.) ). **Note** Bypass Products were moved to outsource supply in 2016. Refer to [InTouch Content 6853607](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A6853607%2A) . The following sections are based on legacy SLB bypass products and provided only as reference. Contact outsource supplier for further details. As each part is specific to each application, care must be taken to ensure that each part is correct when designing an application. **Figure 4-2: A Typical Bypass System** ######## 21.3.1 Y-Tool Sub-Assemblies Y-Tools are usually provided as part of a completed sub-assembly (Handling Sub, Y-Tool, Telescopic Swivel Nipple etc). Due to the number of options, a large number of sub-assembly combinations are possible. To simplify the choice, common options have available sub-assembly part numbers. For other configurations or customizations, please contact supplier. **Example** Part Number 101681304 Description: Y-TOOL: SUB-ASSY, 9-5/8 STD, ALL 13CR, 3-1/2 9.3 EUE SC B X 2-3/8 4.6 PTJ P X 3-1/2 9.3 EUE P, 2.750 X 2.312 SEAL, VIT/AFL | Casing OD | Y-Tool Type | Thread Connecting Upper [Handling Sub] | Thread Connect- ing Lower [Bypass] | Thread Connecting Discharge Leg [Discharge] | Mate- rial | Elasto- mers | Upper Nipple Size [Top Nipple] | Lower Nipple Size [Teleswi- vel] | Plug Type | |-------------|---------------|------------------------------------------|--------------------------------------|-----------------------------------------------|--------------|----------------|----------------------------------|------------------------------------|-------------| | 9-5/8 in | Stand- ard | 3-1/2 EUE SC Box | 2.375 PTJ Pin | 3-1/2 EUE Pin | 13Cr | Viton/ Aflas | 2.75 | 2.312 | PL | **Figure 4-3: Y-Tool Sub-Assemblies** ######## 21.3.2 Handling Sub A Handling Sub is provided at the top of the Y-Tool Assembly to ensure ease of handling on the rig floor and to prevent damage to the specialized components within the system, during installation. The Handling Sub should suit the previously selected production tubing. If a crossover is required to step-up to a larger size of production tubing, and shipping length is not a problem, a second Handling Sub above the crossover is recommend to avoid galling or damage during make up. The length of the Handling Sub required is dependent on the tubing outside diameter above, allowing the tubing to kick over from the off centre position above the Y-Tool. Typically a 6 ft, 3 ½ in Handling Sub is sufficient, which suits up to 4 ½ in tubing directly above. However, if larger tubing is required the length will have to be increased for offset. If the Y-Tool assembly utilized a Top Nipple the Handling Sub would be provided and made-up to the Top Nipple. ######## 21.3.3 Top Nipple The Top Nipple is an optional item, positioned directly above the Y-Tool, to provide the operator with a seal bore profile within the pressure tested assembly. Seating of a Plug or Standing Valve in the Top Nipple seal bore enables the operator to pressure test the production tubing to surface without the requirement of a check valve above the pump discharge head, ensuring a fully tested system from ESP to wellhead. A Standing Valve can also be used to set a hydraulic ESP packer. The Top Nipple can also be utilized to accommodate an Isolation Tool. The Isolation Tool locates in both the Telescopic Swivel Nipple and Top Nipple and is used to isolate the ESP leg of the Y-Tool. This allows bull heading of fluids directly through the bypass tubing, without entering the ESP. ######## 21.3.4 Seal Bore Size As with the Telescopic Swivel Nipple, the seal bore size of the Top Nipple is very important. The same three criteria can be used to determine the seal bore size of the Top Nipple. The seal bore size of the Top Nipple must be larger than the seal bore size of the Telescopic Swivel Nipple and large enough to allow the no-go OD of the Blanking Plug and intervention plugs to pass. ######## 21.3.5 Y-Tool The Y-Tool forms the heart of the bypass system. It allows access below the completion while the ESP remains in place alongside the bypass string. The Y-Tool also provides a single connection to the production string above and has a bypass connection below, directly in line with the production string. This allows the passage of logging tools to the well below via the bypass tubing. A second connection at the base of the Y-Tool allows the ESP assembly to be suspended. The internal profile of the Y-Tool, as seen in [Figure 4-4](.) , is designed to ensure a smooth flow path from ESP discharge to the production tubing. It also ensures the fishing profiles of Blanking Plugs (used to prevent recirculation of produced fluids) remain free of debris and sand build-up, while simultaneously protecting the fishing profiles of these plugs from damage by erosion. The Y-Tool comes with one MLE protector clip, fitted to one side as standard. An additional cable clip is required for the opposite side of the Y-Tool for applications with additional service lines, for example, a chemical injection line. In the case of a well with multiple ESPs, a second cable clip would be required to secure the other MLE. There are two different kinds of Y-Tool available: the Standard Y-Tool and the Auto Y-Tool. The difference between the two is the flapper valve installed in the Auto version; the Standard Y-Tool has no moving parts. Standard Y-Tool when ESP is not in operation With the ESP running and no Blanking Plug installed the fluid re-circulates down the bypass leg With a Blanking Plug installed the fluid cannot re-circulate **Figure 4-4: The Operation of a Standard Y-Tool** ######## 21.3.6 Auto Y-Tool As [Figure 4-5](.) highlights, the Auto Y-Tool consists of a spring-loaded dual-sealing diverter valve which seals off the bypass tubing whenever the pump is running. This prevents recirculation of produced fluids down the bypass tubing. The tool is automatically closed by the flow produced by the downhole pump when the ESP is started. The diverter, which starts off in the flow path of the pump, will hinge over and seal off the bypass tubing, while pressure generated by the pump will keep the diverter closed while the pump is running. It should be noted that it is not pressure that moves the diverter but rather a minimum flow rate of 100 gallons per minute. When the pump is shutdown and the pressure across the diverter has equalized, the spring on the diverter will return it to the open position, in other words, closed against the pump side. This, in turn, allows well intervention by wireline or coiled tubing without the requirement to first pull a plug before the operation commences. The diverter can be locked in the open position by landing a logging plug into the nipple below. This extends up into the Y-Tool and prevents the diverter from closing, allowing logging to be performed while the pump is running. Position of diverter when ESP is not in operation Diverter movement during ESP start-up Position of diverter during ESP operation Position of diverter during wireline or coiled tubing operations with the ESP running **Figure 4-5: The Operation of an Auto Y-Tool** ######## 21.3.7 Standard Y-Tool versus Auto Y-Tool The benefit of the Auto Y-Tool over a Standard Y-Tool is the diverter valve, which saves on wireline and coil tubing operations and so typically reduces the number of runs by two on any given well intervention operation. This is an obvious benefit to the customer, especially when sub sea applications are considered. **Figure 4-6: Standard Y-Tool with Plug and Auto Y-Tool with Flapper** There are, however, other factors to consider when deciding between the Standard Y-Tool and the Auto Y-Tool. Firstly, the expected flow rate from the well needs to be known. If the flow rate is expected to be less than 3500 barrels per day (bbl/d), an Auto Y-Tool is not suitable as the pump must be able to generate an instantaneous flow with no head in order to move the flapper valve off- seat. Table 4-5 highlights other differences between the Standard and Auto Y-Tools. **Table 4-5: The Standard Y-Tool verses the Auto Y-Tool** | Specifications | 9-5/8 in Standard Y-Tool | 9-5/8 in Auto Y-Tool | |-----------------------------------|---------------------------------------|---------------------------------------| | Maximum OD | 8.250 in | 8.250 in | | Minimum ID | 2.992 in | 2.992 in | | Length | 17.00 in | 17.00 in | | Weight | 90-lbm | 90-lbm | | Maximum Differential Pressure | 5000-psi | 3000-psi | | Threaded Connections | 3-1/2 in, 9.2-lbf/ft PMJ | 3-1/2 in, 9.2-lbf/ft PMJ (1) | | Material | AISI 4130 (low alloy) or CA6NM (13Cr) | AISI 4130 (low alloy) or CA6NM (13Cr) | | MLE (FCE) Groove | 2.70 in x 0.625 in | 2.70 in x 0.625 in | | Flow rate to close diverter (min) | | 100 gallons/minute(2) | | Specifications | 9-5/8 in Standard Y-Tool | 9-5/8 in Auto Y-Tool | |----------------------------------------|------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------| | Pressure to keep diverter closed (min) | | 5-psi | | Advantages | No moving parts Simple | Automatic switching Saves on wireline and coiled tubing operations Can still run a Blanking Plug for back-up purposes | | Disadvantages | A plug must be set before the ESP can be run A plug must be pulled before intervention work can be carried out, then be replaced on completion of the task | Minimum flow rate required Potential for leaking flapper | - Refers to threads on block only. Provided as a sub-assembly with handling sub, with threads to suit make up to tubing. - The pump must be able to generate this instantaneous flow with no head. Check the pump performance curve. *4.2.3.1.1* **Telescopic Swivel Nipple** The Telescopic Swivel Nipple is situated at the top of the bypass tubing, immediately below the Y- Tool and provides a seal bore profile into which a plug or valve may be seated, such as a blanking plug, a wireline logging plug or a coiled tubing logging plug. The Telescopic Swivel Nipple also provides a rotary telescopic connection to enable make up to the bypass tubing; 15 in adjustment is standard (±7.5 in). ######## 21.3.8 Thread Type and Size Selecting the thread type and size of the Telescopic Swivel Nipple is fully determined by the Y-Tool and the bypass tubing: the thread type and size. ######## 21.3.9 Seal Bore Size Three things determine the size of the seal bore in the Telescopic Swivel Nipple: - the seal bore profile of the plug or valve that will be seated in the nipple (for example a blanking plug, wireline logging plug or coiled tubing logging plug); - whatever is to be run through the bypass tubing (just as the bypass tubing is governed by whatever is required to be passed through it, so is the seal bore size of the Telescopic Swivel Nipple); - the smallest uphole restriction (the smallest drift ID that would be above the Y-Tool assembly). Essentially, the seal bore size cannot be smaller than the maximum tool string diameter that will be deployed through the bypass tubing, while it should be no larger than the smallest drift ID above. Plugs will be looked at in greater detail in : , but as a simple guide the seal bore size of the Telescopic Swivel Nipple must match the seal bore size of the blanking plug. If they do not, the plug will not seal in the nipple. Standard Y-Tools require a blanking plug to prevent recirculation during ESP production so when selecting a plug for the system it is important to match the size of the plug to the size of the nipple. In the previous example, a 1.85 in plug was to be run through the bypass tubing. If the seal bore size was smaller than this, the plug would clearly not pass through. With regards to uphole restrictions, if the system had a minimum drift ID of 2.50 in above the Y-Tool assembly then it would not be suitable to select a seal bore size larger than 2.50 in. Seal bore sizes must get progressively smaller from the top to the bottom of the string. This is called ‘Tapered Nipple Profiles’. As a result, when the size of plug to be run through a nipple (to a nipple further down the string) is looked at, the no-go size of the plug and not the seal bore size should be recorded as the no-go size is larger. **Example** A Coiled Tubing Logging Plug with a seal bore size of 2.750 in has a no-go size of 2.802 in. *4.2.3.1.1* **Blanking Plug** The main use of the Blanking Plug is to prevent recirculation of produced fluids via the Bypass Tubing. It is seated in the Telescopic Swivel Nipple seal bore, immediately below the Y-Tool, and blanks off the bypass leg of the Y-Tool. A Blanking Plug is provided in Standard Y-Tool Sub Assemblies, or can be purchased separately if required. The Blanking Plug is not required with an Auto Y-Tool system. The plug can be run with the completion to save on a wireline run or it can be run after the completion to avoid well fluids being forced through the ESP. ######## 21.3.10 How to Choose a Blanking Plug Historically, two types of Blanking Plug were available: ‘Blanking Plug with Lock’ or ‘Blanking Plug with Lantern Collets’. Both types are still available by request, but have been superseded by the PL Blanking Plug, which has become the standard blanking plug provided with Y-Tool sub-assemblies for many years. The PL plug was designed to replace either the older Blanking Plug with Lock or the Blanking Plug with Lantern Collets, and with a number of improvements. ######## 21.3.11 PL Blanking Plug The PL Blanking Plug is a modular design, and although it is provided assembled, it consists of a common base unit which can re-assembled to different sizes using a different No-Go Seal Module kit if required. The seal diameter of the plug must be compatible with the seal diameter of the Telescopic Swivel Nipple. The type of elastomers required must also be confirmed. The PL Blanking Plug is deployed and retrieved using standard slickline tools, or can also be deployed and retrieved using hydraulic release tools on coiled tubing. The plug locks in place in the nipple profile and so is suitable for naturally free flowing wells. When the plug is released it actives a pressure equalizing facility. The size of the pressure equalization ports and path through the plug is larger than that of the older plug designs, to aid pulling. Refer to [InTouch Content 7338311](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7338311%2A) , which has links to product sheets, drawings and Assembly Procedures for plugs used in Y-Tool Bypass Systems. Refer to the following for older Locking Plug and Lantern Plug details. ######## 21.3.12 Blanking Plug with Lantern Collets The Blanking Plug with Lantern Collets is deployed and retrieved using standard slickline tools. The plug is simply set in the nipple profile by a jar-down action. All the plugs have an equalizing feature allowing the plug to be easily retrieved if a hydrostatic pressure exists above. To release the plugs from the nipple and activate the equalizing feature shear pins are sheared by upward jarring action. The Blanking Plug with Lantern Collets is not suitable for deployment on coiled tubing or when wells are naturally free flowing. ######## 21.3.13 Blanking Plug with Lock The Blanking Plug with Lock is deployed and retrieved using standard slickline tools and can also be set and pulled using hydraulic release tools on coiled tubing. The Plug is simply set in the nipple profile by a jar-down action. Assurances of correct seating is achieved on over-pull, which cannot activate the equalizing facility. To release the Plug from the nipple and activate the equalizing feature, the Plug is pulled on a separate neck by upward jarring action. Where deployment on coiled tubing is necessary and for naturally free flowing wells, the Blanking Plug with Lock must always be specified. ######## 21.3.14 Bypass Tubing Bypass tubing is positioned alongside the ESP to provide a clear, fully protected passage for coiled tubing or wireline strings. The bypass tubing has a smooth internal profile to remove the possibility of hang-up of the coiled tubing or wireline strings. In the case of wells where multiple ESPs are deployed, the bypass tubing can act as a flow path for the fluid produced by the lower ESP. As previously discussed, the OD of the bypass tubing is governed by whatever is required to be passed through it. In the previous example given in : , it was determined that 2.375 in tubing was the minimum size required to allow a 1.85 in OD plug to pass through. When selecting bypass tubing the thread-type and the overall length of the bypass tubing that is required also needs to be decided. ######## 21.3.15 Bypass Tubing Threaded Connections The type of thread required depends on the application: if the bypass tubing is purely a conduit to allow tools to be passed through, then the thread-type is not so critical. Where it does become more critical is if extended tailpipe will be run, a second ESP is deployed below the bypass, or if fluids are expected to flow through the bypass tubing. In these cases, a premium, high-pressure sealing thread is required. The PTJ thread is the standard connection for legacy Schlumberger bypass tubing. The thread can be used on standard bypass systems or on more specialized bypass completions that require a structural and pressure-tight bypass tubing thread. The connection can be made up without the need to use power tongs and is flush joint for maximum clearance. This is important as there is generally not enough room in the well to accommodate bypass tubing with a larger connection OD, such as EUE. Where the bypass system will sting into a lower completion, the Bypass Assembly can be configured to prevent excessive compression forces being applied to the Bypass Tubing. This requires a Pump Support Sub. ######## 21.3.16 Length of Tubing The length of tubing required again depends on the application. If extended tailpipe needs to be run then as much as required should be run. However, in a logging bypass system application where the bypass tubing will not sting into anything then a minimum of 10 ft of bypass tubing should be run past the bottom of the ESP (overhang) to ensure any wireline tools do not get caught on the bottom of the ESP. ######## 21.3.17 Bypass Tubing Clamps The Bypass Tubing Clamp is designed to secure the bypass tubing alongside the ESP units and to secure and protect the ESP MLE cable and any auxiliary control/injection lines passing the ESP. At the same time it ensures maximum flow area around the completion and maintains a stand-off between the ESP assembly and the casing to give cooling to the electric motors. Selection of Bypass Clamps requires the following information: - Casing size and Weight - Bypass Tubing Size and Type - ESP String details (Series, Number of Sections, Configuration) - ESP MLE Cable Details (Type, Size, Dimensions) - Other Control Lines and dimensions (Quantity, size, bare/encapsulated, any special orientation) ######## 21.3.18 Universal Bypass Clamp For common applications in 9-5/8” casing, Universal Bypass Clamps are available. Universal Bypass Clamps are adjustable to enable fitting to Schlumberger ESP necks ranging from 400 to 562 series. The clamp is available in 2-3/8” or 2-7/8” bypass tubing versions. The Universal Bypass Clamp also secures and protects cables and lines passing the ESP. An integrated cable clip accepts standard ESP MLE cable sizes, and integrated slots can accommodate 2 x ¼” and 2 x 3/8” bare control lines. An additional cable clip is provided as standard, and can be used for a variety of purposes, such as securing a control line flatpack, or a second MLE cable in dual ESP applications. For applications with non-standard MLE cable sizes or control line packs, alternative clip arrangements can be requested. **Figure 4-7: Universal Bypass Clamp** ######## 21.3.19 Dedicated Neck Bypass Clamps For other sizes of casing, or for non-standard ESP equipment ‘Dedicated Neck Bypass Clamps’ may be used. The Dedicated Neck Bypass Clamps are designed and selected to suit specific casing size, bypass tubing size, ESP series and type of section individually. Cable clips to suit the MLE cable dimensions and any other control lines are selected separately, and fitted to the Dedicated Neck Bypass Clamp at the well site. Dedicated Neck Bypass Clamps are used most commonly for 7 in and 10-3/4 in bypass systems. Clamps for other applications, such as 13-3/8 in casing have also been provided, and for bypass tubing sizes ranging from 1.9 in to 4-1/2 in. **Figure 4-8: Dedicated Neck Bypass Clamps** Refer to bypass clamp datasheet in [InTouch Content 4283107](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A4283107%2A) . Contact supplier for additional options or special requirements. ######## 21.3.20 Wireline Re-Entry Guide The Wireline Re-Entry Guide is made up to the end of the bypass tubing to ensure the logging string passes freely back into the bypass tubing upon retrieval. It is obviously essential that the Wireline Re-Entry Guide has the same thread-type (size and weight) as the bypass tubing. Refer to the Wireline Re-Entry Guide Data Sheet ( [InTouch Content ID 4161528](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4161528) ) for details of available Re-Entry Guides. ######## 21.3.21 Motor Base Plug The Motor Base Plug (bullnose) is recommended when either an ESP gauge is to be used, or a single motor section (lower tandem) is used which has no neck suitable for a clamp. The Motor Base Plug is installed below the gauge or Motor, providing an additional profile for an MLE or Bypass Tubing Clamp. This ensures protection of any control lines and prevents hang up of the ESP assembly during installation. As the Motor Base Plug screws directly into the gauge or motor base, the correct thread must be selected to ensure make-up. The Motor Base Plug OD and neck size should match the ESP motor. A Motor Base Plug is not required if a Pump Support Sub is used, while Bypass Tubing Clamps available for Motor Base Plugs. For more details of available plugs refer to the Motor Base Plug Data Sheet ( [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4193307) [4193307](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4193307) ). ######## 21.3.22 Pump Support Subs The Pump Support Sub is an optional component of the bypass system and is primarily used when tailpipe is to be run below the ESP and located into a PBR. The purpose of the Pump Support Sub is to transfer any compressive loading to the ESP and tensile loading to the bypass tubing upon retrieval of the completion. The Pump Support Sub can also be used as a ‘building block’ as a part of more complex bypass installations such as Dual ESP systems. The Pump Support Sub is situated at the bottom of the bypass tubing. It includes a 'spear' which makes up to the base of the ESP (or gauge). This has the effect of ‘fixing’ the overall length of the bypass tubing required as the tubing must make up between the Pump Support Sub and the Telescopic Swivel Nipple, which will be a fixed distance apart. At the design stage, a space out must be carried out to ensure that the correct individual lengths of bypass tubing will be available to make up the overall length of bypass required successfully. The lengths of tubing must be accurately determined so that the overall length is correct to within a few inches over the length of the bypass assembly. This will allow the bypass tubing to be made up to the Telescopic Swivel Nipple which has a small length of adjustment (±7.5 in) The space out, however, must also take in to account several factors about the bypass/ESP system. The type of system and deployment method will influence where the make up points of the bypass tubing must be in relation to the ESP alongside it. Other factors such as tailpipe and ESP weight can result in having to use specialized running equipment and bypass tubing to suit. For more details refer to the Pump Support Data Sheet (InTouch ID 4444256). ####### 21.4 Bypass System Plugs The following section describes the additional intervention plugs available for use with bypass systems. These include Standing Valves, Isolation Tools, Wireline Logging Plugs and Coiled Tubing Logging Plugs. ######## 21.4.1 Standing Valve The Standing Valve is designed to be set in the Top Nipple above the Y-Tool. It can be landed in the nipple against a full column of fluid and is used to pressure test the production tubing string to surface, or for setting of a hydraulic packer. The maximum rated pressure depends on the particular model. ######## 21.4.2 How to choose a Standing Valve The most important criteria when selecting any plug is to ensure that its seal bore size is compatible with the nipple it is to seal into. In the case of a Standing Valve, the seal diameter of the valve and the Top Nipple must be compatible. When selecting the Standing Valve for testing tubing to surface or setting hydraulic packers, it is necessary to confirm the minimum restriction above to ensure the plug no-go OD will pass, and the test pressures required. Therefore, if the Top Nipple (taking into consideration the minimum uphole restriction) is properly selected, then choosing the correct Standing Valve is simple. Standing Valves comes in various seal-bore sizes to suit the Top Nipple seal bore; the type of elastomers required must also be confirmed. A locking option is not required as the plug is designed to allow flow in one (upwards) direction, meaning there should be no pressure below the plug capable of blowing it out of the nipple. The Standing Valve with lantern collets allows the completion to be installed with the Plug already fitted due to the ball check valve in the plug, discounting the need for a dedicated wireline run. The Standing Valve Data Sheet ( [InTouch Content ID 4283109](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4283109) ) should be referred to for details of available Standing Valves. ######## 21.4.3 Isolation Tool The Isolation Tool can be deployed in all standard bypass systems which are equipped with a Top Nipple. The plug has two sets of seals which straddles the seal bores of the Top Nipple and Telescopic Swivel Nipple. It can also be commonly known as a “Straddle”. The plug has a through bore to allow fluids to be injected through the bypass tubing, while fully isolating the ESP. This is especially useful when potentially damaging chemicals (for the ESP) are pumped down the production tubing. The plug can also be used in dual ESP bypass systems, where the flow rate may be too low for the Auto Y-Tool and so standard Y-Tools are used. In this case the Isolation Tool creates a flow path past the back-up ESP, preventing recirculation of produced fluids through the upper pump. Locking plugs are available for this application. In this application a blanking plug would also be installed in the lower of the two bypass completions. As there is a permanent flow path from Bypass to Production legs the completion can be installed with the Isolation Tool already fitted, discounting the need for a dedicated wireline run. ######## 21.4.4 How to Choose an Isolation Tool Excluding seal bore sizes there are two types of Isolation Tool available: - lock-type - lantern-type. The locking option should be selected if it is expected that flow from below to above will be seen. The locking-type can also be run on coiled tubing. Regardless of which type is chosen, when selecting the Isolation Tool compatibility with the Top Nipple and Telescopic Swivel Nipple must be confirmed. The top seal should suit the Top Nipple and the bottom seal should suit the Telescopic Swivel Nipple. The type of elastomers required must also be confirmed. Attention should always be paid to uphole restrictions which could prevent the installation of the Isolation Tool, or could prevent the retrieval of an Isolation Tool which was pre-fitted at the time of installation of the completion. Another point to consider is the ID of the Isolation Tool. For the same seal bore sizes the ID of the Isolation Tool will be different for the lantern-type and the lock-type. Refer to the Isolation Tool Data Sheet ( [InTouch Content ID 4283114](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4283114) ) for details of available plugs. ######## 21.4.5 Wireline Logging Plug The Wireline Logging Plug can be deployed in all bypass systems. The plug allows wireline strings to be suspended beneath the ESP through the bypass tubing. The plug seals between the Telescopic Swivel Nipple bore and the wireline outside diameter enabling wireline work to be carried out under both dynamic and static conditions. There is, therefore, no need to pull the completion to perform wireline operations. The Wireline Logging Plug has been utilized successfully in the past for production logging, memory logging, perforating and also as a means of running downhole samplers below ESPs. ######## 21.4.6 How to choose a Wireline Logging Plug There are two different types of Wireline Logging Plug. - Conventional Wireline Logging Plugs are used for conventional gravity deployed wireline applications, and are the most common. - Self-Seating Logging Plugs are used for wireline operations at high inclinations and where a wireline tractor is being used for deployment. ######## 21.4.7 Conventional Wireline Logging Plugs The PL Wireline Logging Plug is a modular plug that is provided as a base unit that can be prepared in the field to the required seal bore size by fitting the appropriate No-Go Seal Module kit, which is available separately. No-Go seal Module Kits are available for seal bore sizes 2.312 in to 2.750 in. For other seal bore sizes, dedicated wireline logging plugs are available. Contact InTouch or supplier for details. ######## 21.4.8 Flow Tubes To accommodate different sizes of wire, ‘Flow Tubes’ that fit inside the PL Wireline Logging Plug are available. Flow Tubes are available for 0.092 in to 0.460 in wire sizes. The Flow Tubes are brass material and intended to be replaced when they become worn, or when required to use a different wire size ######## 21.4.9 Tool Catcher An optional ‘Tool Catcher’ is available for the PL Wireline Logging Plug. The Tool Catcher is supplied as a kit which is made up to the base of the PL Wireline Logging Plug. At the end of the PLT operation, the tool string which is below the ESP (and Y-Tool) is retrieved from the well. During the retrieval, the top of the tool string (rope socket) will reach the PL Wireline Logging Plug seated in the Y-Tool telescopic swivel nipple. The Tool Catcher will latch the fish neck at the top of the rope socket. Should there be a problem recovering the plug, and the wireline weak point is released, the tool string is retained by the Tool Catcher, for subsequent fishing, and will not drop downhole. ######## 21.4.10 Cable Grapple and Inserts A wireline ‘Cable Grapple’ is used to aid seating of the PL Wireline Logging Plug. The Cable Grapple is installed onto the wireline at a pre-determined distance above the toolstring (equivalent to the maximum depth below the Y-Tool that the tool string should reach). During deployment, the PL Wireline Logging Plug will reach the Y-Tool telescopic swivel nipple, and the wireline can continue to be deployed, sliding though the Flow Tube, until the Cable Grapple lands on top of the plug. The ESP can be started when Cable Grapple has landed on the PL Wireline Logging Plug. Once the ESP is running the PLT can be moved up and down as required to perform the log. The Cable Grapple is available as a separate item. Cable Grapple Inserts to fit into the Cable Grapple, to suit different wire sizes are also required and available separately. For further information, refer to [InTouch Content 7338311](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7338311%2A) , which has links to product sheets, drawings and Assembly Procedures for plugs used in Y-Tool Bypass Systems ######## 21.4.11 Self-Seating Logging Plug The self-seating wireline logging plug is intended for deviated wells, where a Wireline Tractor will be used to deploy the tool string; and is selected to suit the Telescopic Swivel Nipple seal bore size, and the fish neck size of the tool string. The plug is made up to the wireline at surface. A detachable ‘Retaining Sleeve’ that is provided with plug latches on to the fish neck of the tool string. The wireline is deployed into the well using a Wireline Tractor. When the plug reaches the Y-Tool it locks into the Telescopic Swivel Nipple and releases the Retaining Sleeve and tool string assembly. The wireline can continue to be deployed below the ESP. A Flow Tube inside the plug provides a seal against the wire. Flow Tubes are interchangeable for different sizes of wire and are available separately for sizes from 0.082 in to 0.474 in. The Flow Tubes are brass material and intended to be replaced when they become worn. Note: Flow Tubes for Sealf-Seating Wireline Logging Plugs are not interchangeable with Flow Tubes for conventional wireline logging plugs. When the tool string is at the required logging depth the ESP can be started. The plug will prevent re- circulation of produced fluids during ESP operation and allows the wireline to be moved up and down as required. After completion of the production log and retrieval of the tool string, the Retaining Sleeve re-enters the Self-Seating Logging Plug. The locking mechanism releases and opens pressure equalization ports. The Self Seating Logging Plug is unseated ad recovered with the tool string. For further information, refer to [InTouch Content 7338311](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A7338311%2A) , which has links to product sheets, drawings and Assembly Procedures for plugs used in Y-Tool Bypass Systems ######## 21.4.12 Coiled Tubing Logging Plug The Coiled Tubing Logging Plug can be deployed in all bypass systems. The plug allows coiled tubing strings to be suspended beneath the ESP through the bypass tubing. The plug seals between the Telescopic Swivel Nipple bore and the outside diameter of the coiled tubing, enabling coiled tubing work to be carried out under both dynamic and static conditions. The plug can be used for various combinations of coiled tubing strings and Telescopic Swivel Nipple size and is fitted with a positive locking mechanism to prevent it from being dislodged by movement of the coil. The Coiled Tubing Logging Plug has been utilized successfully in the past for clean out operations, production-logging runs and also as a means of running downhole samplers below ESPs on horizontal reservoir sections. ######## 21.4.13 How to choose a Coiled Tubing Logging Plug There are several components which make-up a Coiled Tubing Logging Plug and it is important to select each part carefully. The first thing to consider, as always, is the seal bore size of the plug, which must be compatible with the seal bore size of the Telescopic Swivel Nipple. The second consideration is the size of the coil itself; this is determined by the seal bore size (or plug size), with the coiled tubing operator making the ultimate decision (as seen in Figure 4.1 below). **Table 4-6: Maximus CT Sizes — 2 7/8 in Bypass Tubing** | Teleswivel Seal Bore | Maximum CT Size | |------------------------|-------------------| | 2.312 in | 1.50 in | | 2.625 in | 1.75 in | | 2.750 in | 2.00 in | **Table 4-7: Maximus CT Sizes — 2 3/8 in Bypass Tubing** | Teleswivel Seal Bore | Maximum CT Size | |------------------------|-------------------| | 2.312 in | 1.50 in | | 2.625 in | 1.50 in | | 2.750 in | 1.50 in | Coiled Tubing Logging Plugs are available in various sizes to suit the Telescopic Swivel Nipple, to suit a range of coiled tubing sizes and wall thicknesses, as well as a choice of crossover to the tool string. The Coiled Tubing Logging Plug is used in conjunction with a roll-on connector, sleeve and crossover. The dimensions of the sleeve and crossover, as well as the tool string, must be compatible with the bypass tubing drift. ######## 21.4.14 Roll-On Connector The roll-on connector (left) connects to the coil tubing and is therefore dependant on the coiled tubing operator, the coiled tubing wall thickness, and the logging/workover string crossover thread. ######## 21.4.15 Sleeve The sleeve fits between the Roll-On-Connector and Tool String Crossover. In some cases the Roll- On-Connector and Sleeve may be provided as combined 'Roll -On-Sleeve'. ######## 21.4.16 Crossover The retaining sleeve is clamped in place by the crossover (left), which in turn screws onto the neck of the coiled tubing toolstring. The crossover is dependant on the coiled tubing operator, the coiled tubing wall thickness, and the logging/workover string crossover thread. The legacy Coiled Tubing Plug and Connector parts has been replaced by PL Coiled Tubing Plug, which is provided by outsource supplier to suit legacy parts. Refer to content 7338311, which has links to product sheets, drawings and Assembly Procedures for plugs used in Y-Tool Bypass Systems, including the PL Coiled Tubing PLug. ####### 21.5 Bypass Handling Tools There are three main items of handling equipment for a bypass system; the swivel lift nubbin, stove pipe table and the safety clamp. Handling equipment is used for installing standard logging and advanced lift systems and is designed to provide a safe installation of ESP bypass systems. Each part of the handling equipment is load tested by the product centre prior to shipment but regular load testing should be carried out. The ESP bypass installation procedure should be consulted for instructions on how to use the handling equipment, as well as the Handling Equipment Data Sheet ( [InTouch Content ID 4195322](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4195322) ) for details of handling equipment to suit your application. ######## 21.5.1 Swivel Lift Nubbin Swivel Lift Nubbins are used for picking up bypass tubing and supporting tubing joints during installation, with two typically used per installation. There are only two decisions to be made when selecting nubbins. The first is the type of thread they should have – the thread connection on the nubbins must match that of the bypass tubing. The second decision is whether a standard duty nubbin is sufficient. Normally a standard duty swivel lift nubbin is suitable but if the bypass system will have extended tailpipe or your application is a dual ESP completion then the heavy duty lift nubbin should be used (these nubbins have a shoulder for 3 ½ in side door elevators). To fully determine this, the load rating of the swivel lift nubbin needs to be compared to the string weight (from the Y-Tool down). For normal logging bypass systems, the bypass tubing is picked up and assembled using the lifting nubbin, with its hook/shackle held in a tugger line. For heavy duty applications, the heavy duty swivel lift nubbin is used, which is held in the elevators to accommodate the string weight. The load rating of the swivel lift nubbin is then limited only by the bypass tubing connection tensile strength. **Figure 4-9: Swivel Lift Nubbin** ######## 21.5.2 Safety Clamp The safety clamps secures the Bypass Tubing, supporting it by friction during the installation to allow further make-ups. The safety clamp would sit on the stove pipe table during installation. The safety clamp body is common to both 2-3/8 in and 2-7/8 in tubing sizes. The slip dies fitted to the safety clamp can be replaced should it be required to change to another size of bypass tubing. As with the swivel lift nubbin the load rating needs to be compared with the string weight prior to use. **Figure 4-10: Safety Clamp** ######## 21.5.3 Stove Pipe Table The stove pipe table is positioned over the rotary table to provide a work surface to land the ESP and Bypass Safety Clamp. The stove pipe table must be large enough to accommodate the O.D. of the combined string (ESP plus Bypass). The standard design has a 7 in cut, which allows up to 675- series equipment. As with the swivel lift nubbins and the safety clamp, the load rating and string weight need to be compared prior to use. **Figure 4-11: Stove Pipe Table** ####### 21.6 Bypass Design Check List **Table 4-8: Bypass Design Check List** | Casing Details | | |---------------------------|----| | Size | | | Weight | | | Material Type | | | Heavy Sections | | | Patches | | | Production Tubing Details | | | Size | | | Weight | | | Production Tubing Details | | |---------------------------------------------------|----| | Connection Type | | | Material Type | | | Minimum Uphole Restriction | | | Size | | | Downhole Conditions | | | Pressure | | | Temperature | | | H2S Content | | | CO2 Content | | | Na Cl Content | | | ESP Details | | | Manufacturer | | | Pump Series | | | – Discharge head thread size, type and weight | | | – Is there a check valve? | | | – Number of sections & lengths | | | Intake or Gas Separator | | | – Series and lengths | | | Protector Series | | | – Number of sections and lengths | | | Motor Series | | | – Number of sections and lengths | | | MLE size and length | | | Control/Injection Lines | | | Sizes and diameters | | | What do they want to be able to do with a bypass? | | | Tools and diameters to be run through? | | | What tools do they want with a bypass? | | | Blanking Plug with collet or lock | | | Standing Valve to set packer | | | What tools do they want with a bypass? | | |-----------------------------------------------|----| | Isolation Tool | | | Wireline Logging Plug | | | – Wireline diameter | | | Coiled Tubing Logging Plug | | | – Tubing diameter | | | – Wall thickness | | | – Operating company | | | Multisensor / ESP Gauge? | | | Discharge Pressure Sub? | | | Do They Require Installation Equipment? | | | Stove Pipe Table | | | Safety Clamp | | | Swivel Lift Nubbins | | | General Considerations | | | Pump Orientation in Deviated Wells & Standoff | | | Casing Drift & Largest ESP Diameter | | | By-Pass Tubing Size to Fit in Casing | | | Use of Flush Joint Tubing | | | Nipple Sizing Reduces Downhole | | | Deflection and Kickover | | ###### 22 POD ESP System Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 23 Dual Concentric ESP System Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 24 Auxiliary Equipment Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ##### Alternative Deployed ESP - [**Gather the Data and Specifications 5-1**](.) - [**Coiled-Tubing Deployed ESP 5-1**](.) - [**Shuttle Deployed ESP 5-1**](.) - [**Cable Deployed ESP 5-1**](.) - [**Auxiliary Equipment 5-1**](.) *5* **Alternative Deployed ESP** ###### 25 Gather the Data and Specifications Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 26 Coiled-Tubing Deployed ESP Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 27 Shuttle Deployed ESP Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 28 Cable Deployed ESP Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 29 Auxiliary Equipment Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ##### Horizontal Pumping System - [**Gather the Data and Specifications 6-1**](.) - [**System Components 6-1**](.) - [G3A and G3 Thrust Chamber Descriptions 6-1](.) [Decal 6-2](.) - [New Thrust Chamber Designation 6-2](.) - [Summary Of TC Changes 6-2](.) - [Operating at Shut-in and High Temperature 6-7](.) - [Pump Thrust 6-7](.) - [Liquid Specific Gravity and Boost Pressure 6-7](.) - [Liquid Specific Gravity and Pump Horsepower Demand 6-8](.) - [Burst Pressure Considerations - MAWP 6-8](.) - [Centrifugal Pump Attribute Description for HPS 6-8](.) - [Net Positive Suction Head Required 6-9](.) - [Discharge 6-12](.) - [Mechanical Shaft Seal and Seal Flush Plans 6-14](.) - [Normal Duty Skid Specifications 6-17](.) - [Maximum Duty Skid Specifications 6-18](.) - [Service Factor Stator Temperature Rise 6-19](.) - [Winding Temperature Design Life 6-20](.) - [Insulation Class Maximum Hot Spot Temperatures 6-20](.) - [Ambient Temperature 6-20](.) - [Motor Current Loading Effect 6-20](.) - [Voltage Imbalance Effect on Winding Temperature 6-21](.) - [High or Low Voltage 6-21](.) - [Altitude Effect On Winding Temperature 6-21](.) - [Temperature Measurement 6-22](.) - [Frequency – Horsepower Output 6-22](.) - [Power System Grounding 6-22](.) - [Motor Enclosures 6-22](.) - [Weather Protected Type II (WPII) 6-23](.) - [Totally Enclosed Fan Cooled (TEFC, IP-54) 6-23](.) - [Totally Enclosed Air To Air Cooled (TEAAC, IP-54) 6-23](.) - [Use With Variable Speed Drives 6-24](.) - [Monitoring 6-25](.) - [Motor Instrumentation 6-25](.) - [Centurion Controller 6-25](.) - [HPS Foundation and Support 6-26](.) - [**Auxiliary Equipment 6-27**](.) *6* **Horizontal Pumping System** ###### 30 Gather the Data and Specifications - [Introduction 6-1](.) - [New Thrust Chamber (G3A) with Thrust Chamber Oil Level Gauge](.) - [Centrifugal Pump Performance Curve Relationships 6-6](.) - [General Seal Arrangements 6-15](.) - [Light Duty Skid Specifications 6-17](.) - [Motor Horsepower Capacity/Pump Horsepower Demand 6-19](.) - [Open Drip Proof (ODP) 6-22](.) - [Standard Instrumentation Package - Switches 6-24](.) - [HPS Shaft Alignment 6-26](.) Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 31 System Components ####### 31.1 Introduction The Horizontal Pumping System (HPS) is a multistage centrifugal downhole type pump, that has been horizontally mounted on a rigid skid for surface pumping applications. Horizontal pumping systems are used in a variety of applications such as waterfloods, salt water disposal, water supply, booster service, crude oil transfer, liquid propane injection, pumps, and amine service. Currently there are five basic models of HPS: - Model 88 — This model includes HD and booster models. - G2 — This model was only produced for a short period of time. The identifying feature for this unit is the thrust chamber (TC) support is bolted on. - RedaHPS G2 — The physical appearance of this model is the same as the G2; however, on this model the TC support is welded to the motor support frame. - G3 — The main change for this version involves strengthening the intake to allow API-610 nozzle loading. The intake will be moved to bolt directly to the TC vertical mounting plate and the intake adapter will be moved to the motor side of the TC vertical mounting plate. - G3A — This model is dimensionally interchangeable with the G3. However, the TC has been slightly redesigned The TC has a lower acceptable oil operating level and uses Inpro oil seals. ####### 31.2 G3A and G3 Thrust Chamber Descriptions The standard product thrust chamber changed to designation G3A in 2007. The changes were made to both lower manufacturing costs and improve performance. ######## 31.2.1 New Thrust Chamber (G3A) with Thrust Chamber Oil Level Gauge Decal A new thrust chamber level gauge decal (decal p/n 100236108), which will lower the acceptable oil operating level to eliminate leakage past the oil seals, has been developed and commercialized. The new oil level was verified by engineering dimensional calculations and HPS shop experimentation. Decals can be ordered through the Bartlesville Product Center. Old decals need to be removed, new decals installed and oil level adjusted according to the new scale on the decal. ######## 31.2.2 New Thrust Chamber Designation Based upon recent Lean Six Sigma initiatives, the following G3 HPS Thrust Chamber (TC) improvements and modifications are now in effect. These changes do not alter the G3 TC. These changes are based upon extensive engineering testing, which validated equivalent mechanical performance and reliability to the previous G3 TC version. The changes to the current G3 design require a new top level part number. With this new top level part number comes a new TC designation: G3A. The designation will allow distinction between current and new model versions. G3 TCs are still available, if required, and will include NSK bearings and Clipper Oil Seals with the same housing that is already included on existing G3 TCs. ######## 31.2.3 Summary Of TC Changes - The bulls-eye site glass is eliminated. Engineering still determining if an orifice is needed to control flow rate from the circulating pump. - New TC gauge decal shows correct oil fill level. - TC shaft mechanical seal surface finish area was updated along with length of shaft surface finish, such that new type 2 bellows seals have a rougher surface area to vulcanize, thus precluding seal leak issues. The MPI for this was updated and posted to GEMS. All inventory was reworked. JC recommendations were followed for surface roughness recommendations. The G3 and G3A thrust chambers basic configuration [Table 6-1](.) includes part number, shaft spline size, shaft horsepower rating, and number of thrust bearings. **Table 6-1: G3 and G3A Thrust Chambers Basic Configuration** | Number of Bearings | G3 PN | G3 Description | | Number of Bearings | G3A PN | G3A Description | | Horsepower Rating and Shaft Material | Thrust Rating (3600 RPM, Using Royal Purple Synfilm GT46) | Inconel Shaft PN's | 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| 1 | 100160298 | 1.18-6B SPLINE | | 1 | 100447636 | 1.18-6B SPLINE | | 17-4PH SS: 730 hp | 5,000 Lbs- No Cooler | | | 2 | 100160329 | 1.18-6B SPLINE | | 2 | 100447637 | 1.18-6B SPLINE | | 17-4PH SS: 730 hp | 8,000 Lbs- No Cooler, 12,000 Lbs- With Cooler | | | 3 | | 1.18-6B SPLINE | | 3 | 100447638 | 1.18-6B SPLINE | | 17-4PH SS: 730 hp | 18,000 Lbs- With Cooler | | | 1 | 100084425 | 1.50-6B SPLINE | | 1 | 100448445 | 1.50-6B SPLINE | | 17-4PH SS: 1500 hp | 5,000 Lbs- No Cooler | | | 2 | 1000884424 | 1.50-6B SPLINE | | 2 | 100448447 | 1.50-6B SPLINE | | 17-4PH SS: 1500 hp | 8,000 Lbs- No Cooler, 12,000 Lbs- With Cooler | 100478125 (2150 hp) | | 3 | 100084423 | 1.50-6B SPLINE | | 3 | 100448448 | 1.50-6B SPLINE | | 17-4PH SS: 1500 hp | 18,000 Lbs- With Cooler | | | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Note G3 and G3A use the same thrust and radial bearings (NSK). G3 uses clipper oil seals, G3A uses Inpro oil seals. G3 and G3A are dimensionally interchangeable based upon above p/n using either cartridge or non-cartridge JC mechanical seals. G3 cannot be retrofitted to match G3A due to the oil seal fit. Housing connections vary significantly between G3 and G3A versions. G3A retrofit of G1 (Model 88) is not included in this comparison. Note NSK Bearing Information: 40 deg angular contact thrust bearing NSK Model 7313BEAMRSUNP6, p/n 100307037. Deep groove sealed for life/shielded radial bearing NSK Model 6013ZZC3EEA2S, p/n 100307054. Note Inpro Oil Seal Info Bearing isolator (2.375 in motor/outboard side), model VBX, p/n 100447640. Bearing Isolator (1.50 in pump/outboard side), model VBX, p/n 100390497. | Figure 6-1 is an engineering drawing of a three-bearing G3A thrust chamber. **Figure 6-1: Engineering Drawing of a Three-Bearing G3A TC** ####### 31.3 Centrifugal Pump General Information The centrifugal pump generates flow rate by the transfer of motor shaft power to the pump impellers, which in turn transfers the power to the fluid in the form of flow rate liquid velocity. The pump develops pressure head as the liquid passes through each diffuser. Each stage includes one impeller and one diffuser, and can produce a small amount of pressure head. Multiple stages are stacked end-to-end to meet the system boost pressure requirement. Pump head capacity performance will change if fluid viscosity, fluid specific gravity, free gas volume, or pump c/min are changed. ######## 31.3.1 Centrifugal Pump Performance Curve Relationships One stage HPS performance curves for the M520A taken from AE-PAD are shown in [Figure 6-2](.) . Three different curves, which include the head capacity curve, horsepower demand curve, and efficiency curve are shown. - The total head generated by a pump changes with flow rate change increases as flow rates change from low to high. This relationship between head and flow rate is defined by the head capacity curve for each pump. The pump head capacity curve will define the operating point for an application. - The horsepower curve defines the pump horsepower demand. Typically, horsepower demand increases as flowrate increases. - The efficiency curve defines the hydraulic power output as a percent of shaft input power from the motor. - The operating range for each pump is defined on the pump curve; for the M520A below, it is shaded in yellow. Operating ranges have been extended to lower rates for HPS pumps when configured as compression pumps. The pump curves provided in the unit manual should have the correct c/min and fluid specific gravity. **Figure 6-2: M520A Performance Curve** *1 Stage, Specific Gravity = 1.0 and 3500 c/min* ######## 31.3.2 Operating at Shut-in and High Temperature Shut-in conditions can occur when the pump efficiency of the M520 shown above is zero. All shaft input horsepower is converted to heat, which can generate very high pump temperatures in a matter of minutes. Temperatures can be high enough to melt lead. It is important to set discharge pressure shutdowns to open at a pump’s recommended minimum flow rate point. ######## 31.3.3 Pump Thrust Centrifugal pumps develop axial thrust load, which decreases going from low to high flow rates. The maximum axial thrust force toward the intake (down) occurs at shut-in. HPS pumps are typically configured in compression to transfer the downthrust load from the impellers to the shaft and onto the thrust chamber’s thrust bearing. HPS pumps operating in upthrust can result in pump damage, sometimes very quickly with the larger staged pumps. ######## 31.3.4 Liquid Specific Gravity and Boost Pressure The boost pressure developed by a pump stage is directly proportional to the specific gravity of the liquid pumped. Specific gravities for the fluids pumped in HPS applications can vary from 0.4 to 1.3. The heavier the fluid, the more boost pressure developed per stage. ######## 31.3.5 Liquid Specific Gravity and Pump Horsepower Demand The pump horsepower demand is directly proportional to the specific gravity of the liquid pumped. Specific gravities for the fluids pumped in HPS applications can vary from 0.4 to 1.3. Motor- overloading can potentially be a problem if a design’s specific gravity is exceeded. The motor will draw higher current load to generate the horsepower needed by the pump. Current loads that exceed motor nameplate will increase motor winding temperatures, potentially shortening motor winding life or causing a winding failure. ######## 31.3.6 Burst Pressure Considerations - MAWP MAWP is the maximum absolute working pressure for a pump housing design. MAWPs for HPS pumps are provided in ED-189. Maximum pump working pressure occurs at shut-in. ######## 31.3.7 Centrifugal Pump Attribute Description for HPS Centrifugal pumps are provided with options based on the conditions specified by the application. These options are provided in OneCAT as attributes and given on the pump description. [Table 6-2](.) describes a pump which is located in [OneCAT catalog](http:\www.wcp.oilfield.slb.com\cs\catalog) . Similar descriptions are provided in each unit manual sent to the field and include the unique pump part number. The description below is for a M520, and its explanations can be found in the [Table 6-2](.) . **Table 6-2: PUMP: M520-A C-CT 15 STG 862/862 15 RLOY BTHD, 1.37 MON, M- TRM, HSN, ARZ, 316SS H and B, HPS, BLUE PAINT** | Attributes | Abbreviations | |---------------------------|-----------------------------------------------------------------| | PUMP SERIES DESIGNATION | D, G, S, H, J, M, N | | FLOWRATE | Gallons Per Minute at BEP | | TANDEM CONNECTION | C-CT | | NUMBER STAGES ACTUAL | Defined in the pump description | | BASE FLANGE | 400, 540, 562, 675, 725, 738, 862, 950, or 1000 / Grayloc | | HEAD FLANGE | 400, 538, 540, 562, 675, 725, 862, 950, 1000, or 1125 / Grayloc | | HOUSING SIZE | 10, 20, 30, 23, 24, etc. | | HOUSING MATERIAL | CS, RLOY, RLOY 13 CR, or NONE | | HOUSING THREAD | Buttress, V, Square | | SHAFT DIAMETER & MATERIAL | HS Monel, Monel, Inconel | | TRIM | S-trim & M-trim | | MATERIAL/ELASTOMERS | HSN, AFLAS, CHEMRAZ, VITON, or HNBR | | MATERIAL/RADIAL BEARING | NONE, ZZ, ZS, SS, ZT, SLB, or SICG | | Attributes | Abbreviations | |-------------------------|--------------------------------------------------------------------| | MATERIAL/HEAD and BASE | CS, RLOY, RLOY 13 CR, NAB, or 316 SS (use only in HPS application) | | HOUSING PRESSURE DESIGN | NA, HPS, HPS-H, or HPS-XH | ######## 31.3.8 Net Positive Suction Head Required Pump suction pressure head must be high enough to prevent cavitation as fluid passes through the intake and into the lower stages of the pump. Net positive suction head can be defined as the total suction head in feet absolute, determined at the suction nozzle and corrected to datum, less the vapor pressure of the liquid in feet absolute. It is an analysis of energy conditions on the suction side of a pump to determine if the liquid will vaporize/ cavitate at the lowest pressure point in the pump. This condition can achieved by staying above the net positive suction head required curve for the application in question. A NPSHR curve has been developed for each pump. HPS net positive suction head required (NPSHR) curves were developed for water at temperature of 60 degF and a pump speed of 3500 c/min. Two values of net positive suction head must be considered; NPSHR and net positive suction head available (NPSHA). The Hydraulic Institute defines NPSHR for centrifugal pumps as, the amount of suction head, over vapor pressure, required to prevent more than 3% loss in total head at a specific capacity. NPSHA is the total head available. NPSHA should always be equal to or greater than NPSHR. NPSHA for a pressurized system can be calculated as follows: *NPSHA (feet) = Pressure Head - Vapor Pressure Head. Pressure head (at suction) = absolute pressure (gauge pressure + 14.7)/specific gravity of liquid Vapor pressure head = vapor pressure of liquid at liquid temperature/specific gravity of liquid* **Note** Pressure units are in psi Head units are in feet NPSHA for a tank source the calculation would be as follows: *NPSHA (feet) = Atmospheric pressure Head + Liquid Level Head – Vapor Pressure Head – Friction Loss head Atmospheric Head = atmospheric pressure/liquid specific gravity Liquid Level Head = height of tank liquid level above pump intake center line Vapor pressure head = vapor pressure of liquid at liquid temperature/specific gravity of liquid Friction head loss = friction loss in feet in flowline between tank and pump intake* **Note** Pressure units are in psi Head units are in feet Below is the link to the NPSHR curve file that is stored on the [HPS Sustaining Engineering web site](http:\www.hub.slb.com\Docs\ofs\RED\reda\TESupport\NPSHRCurves.pdf) . ####### 31.4 Intake The standard flanges supplied by HPS are ANSI rated flanges. The intake assembly is available either in RF (raised face) or RTJ (ring type joint). RF is the most common face employed on steel flanges. The raised face is 1/16 in. high on 150 lbf class flanges and 1/4 in on all others. Raised face flanges are generally installed with soft flat composite gaskets. The RTJ is the most expensive standard facing, but also the most efficient because the internal pressure acts on the ring to increase the sealing force. RTJ flanges are generally used in 1500 Class and higher. The ring gaskets are oval in profile and usually made of metal of the softest carbon steel or iron obtainable. **Table 6-3: ANSI pressure ratings for HPS flanges at 100 degF** | ANSI Class | Pressure Rating CS (PSI) | Pressure Rating 316L (PSI) | Pressure Rating 410- 13Cr SS (PSI) | |---------------|----------------------------|------------------------------|--------------------------------------| | 150 | 285 | 230 | N/A | | 300 | 740 | 600 | N/A | | 600 | 1480 | 1200 | N/A | | 900 | 2220 | 1800 | N/A | | 1500 | N/A | 3000 | N/A | | 2500 | N/A | N/A | 6000 | The intake of RedaHPS is comprised of three major components: intake assembly, intake adaptor, and seal housing. , , and contain the main components of the intake. **Figure 6-3: Intake tubing section, nozzle, and flange** **Figure 6-4: Seal housing positioned on TC side of intake tubing section** **Figure 6-5: Intake adapter bolted to the pump side on the intake tubing section** ####### 31.5 Discharge The discharge head is a double-flanged adapter. The pump portion of the discharge head is a Reda pump base flange, either standard or extra heavy (XH), with an internal O-ring seal. The other half is a standard ANSI flange to mate with the customer piping system or dropout spool. **Figure 6-6: Discharge head assembly** [Table 6-4](.) contains the pressure ratings for the HPS discharge. **Table 6-4: HPS flange rating summary** | | Carbon Steel (ASTM # A105) Carbon Steel (ASTM# A4130) | Carbon Steel (ASTM # A105) Carbon Steel (ASTM# A4130) | Carbon Steel (ASTM # A105) Carbon Steel (ASTM# A4130) | 316L SS 410SS-13 Chrm | 316L SS 410SS-13 Chrm | 316L SS 410SS-13 Chrm | |--------------------------|---------------------------------------------------------------------|--------------------------------------------------------------------|----------------------------------------------------------------|--------------------------------------------------------------------|--------------------------------------------------------------------|----------------------------------------------------------------| | ANSI B16.5 Flange Rating | Max Allowable Working Pressure (MAWP) (psig), – 20 degF to 100 degF | Max Allowable Working Pressure (MAWP) (psig), 100 degF to 200 degF | Max Hydrostatic Test Pressure (psig) 1.5 x MAWP (30 min Water) | Max Allowable Working Pressure (MAWP) (psig), -20 degF to 100 degF | Max Allowable Working Pressure (MAWP) (psig), 100 degF to 200 degF | Max Hydrostatic Test Pressure (PSIG) 1.5 x MAWP (30 min Water) | | 150 | 285 | 260 | 450 | 230 | 190 | 350 | | 300 | 740 | 675 | 1125 | 600 | 500 | 900 | | 600 | 1480 | 1350 | 2225 | 1200 | 1000 | 1800 | | 900 | 2220 | 2020 | 3350 | 1800 | 1500 | 2700 | | 1500 | 3705 | 3375 | 5575 | 3000 | 2500 | 3600 | | 2500 | 6170 | 5600 | 9255 | 6000 | 5225 | 9000 | **Note** - Above chart applies to all HPS intakes, discharges and drop out spools. - Reference GeMS document 100098795 (latest revision) for Hydro Test Procedures. - Gray Loc Discharge Adapters MAWP/Test Pressures are not covered under this rating chart (consult HPS Engineering). ####### 31.6 Mechanical Shaft Seal and Seal Flush Plans A mechanical seal is a device that fits onto a pump shaft that allows pressure to build within the pump intake and, therefore, precludes liquid from leaking down the rotating shaft to atmosphere. Typically, a seal consists of a static element and a dynamic (rotating) element that are in ‘rubbing’ contact with each other to form a sealing face with a minimum leak path. These surfaces (faces) are pushed together under spring and/or hydraulic pressure to provide the sealing contact. Successful operation depends on achieving the right conditions at the interface, as a thin hydrodynamic film of the liquid being contained lubricates the faces. The faces are highly polished, are very flat, and are made of hard materials with very low friction characteristics. HPS system mechanical shaft seal and flush plan options allow usage of HPS in a variety of fluids, and ranges of fluid pressure and temperature. The fluids include water, oils, liquid CO2, NGLs, and amines. Fluid temperatures up to 250 degF have been pumped, and all higher temperature applications require thorough design analyses. Improper application of seal systems can result in sealing problems including rapid seal system failure. It is important to double check the actual conditions the seal will encounter and compare those conditions to the design limits of the sealing system on the skid. The leakage path across the two sealing surfaces is the heart of the mechanical seal. Proper lubrication of the sealing faces is essential to minimize wear and provide reasonable life, and is normally provided by a fluid film across the faces. It is, therefore, imperative that the fluid in the seal area provides adequate lubrication (and cooling). If the process fluid will not provide adequate lubrication, then it will be necessary to improve this environment within the sealing area. Flush plans are commonly employed to do this. Seals should typically be operated a 160 degF or below. If the fluid temperature exceeds this temperature a heat exchanger flush system may be required. The greater the temperature is over 160 degF, the more potential for problems to occur. A critical temperature would allow boiling of the fluid between the seal faces or result in a significant loss of fluid lubricity between the seal faces. Use of a seal in a higher pressure condition than its design specifications can cause immediate seal failure. It is important to review the potential pressure conditions with the client’s site personnel to double check maximum pressure potential. Design data received by the application engineer does not always reflect the full range of potential pressure that exists. ######## 31.6.1 General Seal Arrangements - **Non-Cartridge (Rubber Bellows) Seal** These seals are built of separate component pieces: a dynamic rotating seal element which spins with the shaft (with drive transmitted through the rubber bellows or boot) and a static element (containing the stationary face) that is secured to the seal chamber. This type of seal usually does not contain a gland, which means there is no external flush system. Typically, a dead-ended stuffing box is used that relies on pump inlet fluid pressure to cool and lubricate faces. A non-cartridge seal is specified for single style seal build. ######## 31.6.2 Cartridge Seals A cartridge seal is a self-contained sealing assembly consisting of the following: - The complete mechanical seal (containing both stationary and rotating parts) - The seal gland (that always requires flushes to be connected) - A seal sleeve - A device (usually clips) to hold, center and position all the components until the cartridge is set and locked down on the shaft (at this point the clips are removed and the seal is ready for operation). - The cartridge which can be single, double or tandem style builds. ######## 31.6.3 Materials of Construction Standard ranges are generally offered in a variety of materials of construction. Materials of principal components (seal ring bodies, spring housings, springs etc.) range from common stainless steel to corrosion resistant options such as HastelloyC. Face materials used in RedaHPS* are typically higher specification materials such as Tungsten Carbide or Silicon Carbide on Carbon. The majority of seals use one face in carbon, which is mechanically weak in distortion. Its main advantage is its excellent self-lubricating properties for start up conditions and excellent heat transfer to remove heat from the faces. Face materials are typically selected to have one face less hard than the other and , thus, the hard face wears into the softer one over time. ######## 31.6.4 Single Seals Single seals use one set of seal faces (a stationary and a rotating face) to control leakage. They are generally suitable for sealing fluids that will provide adequate lubrication to the seal faces. If seal leaks past the faces, it will drain to the ground or atmosphere. This type of seal typically uses pumped liquid as a source to cool, lubricate and clean the seal faces. ######## 31.6.5 Multiple Seals **Tandem Sealing Arrangements** These modular cartridge seals utilize two sets of seal faces arranged in the same direction. Inboard (closest to pump) seals use pumped liquid to cool and lubricate. Outboard (closest to driver) seals use barrier fluid to cool and lubricate, provided from an external non-pressurized barrier system. **Note** This type of seal is often referred to as a safety seal because it contains the pumped product in the event of leakage. The following conditions may call for the use of tandem seals: - A lack of adequate quench fluid, with carbon forming at the seal’s atmospheric side or with the pumped liquid crystallizing at the same location. - Presence of hazardous liquid that will vaporize at atmospheric conditions (fire hazard) or will leak causing an environmental hazard. - A need to contain leakage from the primary seal and to delay leakage in the case of a catastrophic failure of the primary seal. - Higher stuffing box pressures than a single mechanical seal can tolerate. **Double Seal Arrangements** These modular cartridge seals utilize two sets of seal faces arranged back to back (mirrored). Both sets of faces use pressurized barrier fluid to cool and lubricate between the two seals, provided from an external pressurized barrier system. **Note** The barrier fluid is held at a higher pressure than the process liquid to ensure that the clean barrier fluid migrates across the seal face. It is essential to design the liquid side seal accurately to prevent product entering the barrier fluid if the barrier pressurization system is shut off. The following conditions require the use of double mechanical seals: - The difference between the stuffing box pressure and the pumped liquid’s vapor pressure is less than 25 psi. - The pumped fluid is abrasive or highly corrosive and there is no adequate flush liquid. - High solids content lethal or toxic liquids. ###### 32 HPS Skid Weldment Assembly HPS skid weldment assembly is a robust welded steel frame on which HPS components are mounted and aligned. The HPS unit comes complete with the motor, thrust chamber, thrust chamber support, pump, pump clamps, and the necessary shutdown switches. Key design features of HPS skids are the three standard skid types light duty (LD), normal duty (ND), and maximum duty (MD). - Flexible skid design - ability to resize pumps/motors (same frame) without ordering a new skid - Short lead time - set of components can be stocked for flexible design - One standard thrust chamber support for all skid types. ####### 32.1 Light Duty Skid Specifications The light duty (LD) skid is engineered to handle a shorter single-pump applications using only NEMA motors with up to a 449 frame. All skids have a fixed center line height of 18 in. The LD skid is available in two-clamp and three-clamp configurations. LD skid recommended specifications are - Motor hp: less than or equal to 250 hp - Pump section: single only - Skid length: less than or equal to 23 ft - Pump length: up to 16 ft - Motor and thrust chamber length: 7.3 ft. **Figure 6-7: Light duty skid drawing** ####### 32.2 Normal Duty Skid Specifications The normal duty (ND) skid is engineered to accommodate longer single-pump and shorter two-pump applications up to 900 hp. RedaHPS ND skids are available in two-clamp through six-clamp configurations with a fixed shaft height of 32 in. ND recommended specifications are: - Motor hp: less than or equal to 900 hp - Pump section: single or double - Skid length: from 19.25 ft to 37 ft - Total pump length: from 9.31 ft to 24.43 ft - Motor and thrust chamber length: 9.25 ft. **Figure 6-8: Normal duty skid drawing** ####### 32.3 Maximum Duty Skid Specifications The maximum duty (MD) skid is engineered for applications requiring over 900 hp or two tandem- pump sections and is available in six-, seven-, and eight-clamp configurations. This configuration can accommodate above-NEMA motors up 1500 hp and like the ND skid, it has a fixed 32–in. shaft height. It is accepted practice to design a system for two pump housings but only install one pump in the short term. MD skid recommended specifications are: - Motor hp: less than or equal to 1500 hp - Pump section: double - Skid length: from 24 ft to 45 ft - Tandem pump length: from 23.82 ft to 35.75 ft - Motor and thrust chamber : 9.25 ft. **Figure 6-9: Maximum duty skid** ###### 33 Prime Mover The three phase AC induction electric motor is the standard prime mover used for the HPS. Below is a summary of motor basics ####### 33.1 Motor Horsepower Capacity/Pump Horsepower Demand AC induction motors by design will attempt to output the horsepower required by pump demand, even if that amount exceeds motor capacity. The motor is not self-regulating. Motor winding temperatures increase as motor loading increases. Motors operated above name plate horsepower can reach temperatures that shorten insulation winding life, possibly causing severe insulation damage that could result in a stator winding short. The pump horsepower demand curve typically slopes upward from low to high flow rate. Typically the horsepower at the operating point will be significantly lower than at run-out. ####### 33.2 Service Factor Stator Temperature Rise Service factor and stator temperature rise are specific to motor, environmental, and power system parameters, and should be discussed with engineering when attempting to operate above a 1.0 SF design. In general the NEMA motors Siemens supplies are rated to a 1.15 service factor to a class B temperature rise of 900 degF, and the above NEMA motors are rated to a 1.15 service factor at a class F rise of 1,150 degF. The NEMA motors at 115% load will operate below the class F insulation rating of 155 degF, while the above NEMA motors will operate at the insulation rating. When operated at rated insulation temperature, motors will last 15 to 20 years. ####### 33.3 Winding Temperature Design Life As a motor operates, it converts electrical energy to mechanical energy. Inefficiencies in the motor cause heat to be generated. Heat generated by the operation of the motor will cause its windings to have a significantly higher temperature when running loaded than when idle. This is referred to as temperature rise. Actual motor winding temperature governs the insulation life of the windings. Motors that operate within their name plate specifications and design parameters can expect design life. Motors that exceed name plate specifications and do not follow design parameters will probably not reach design life. The temperature of a motor winding is affected by heat coming from various sources. These sources can be internal to the motor resulting from its operation, or they can be external to the motor resulting from its environment. External effects like direct sun, proximity to other heat sources, poor air circulation, etc, can raise ambient temperature above design limits. ####### 33.4 Insulation Class Maximum Hot Spot Temperatures Motor insulation systems are classified according to the total temperature capability of the system. Motors purchased for HPS application should be type F, but to verify check on the motor name plate. [Table 6-5](.) contains maximum insulation hotspot temperatures. These temperatures would be the sum of ambient and motor rise temperatures. **Table 6-5: Total Temperature capability of motor insulation systems** | Insulation Class | Maximum Hotspot Temperature degC (degF) | |--------------------|-------------------------------------------| | A | 105 (221) | | B | 130 (266) | | F | 155 (311) | | H | 180 (356) | ####### 33.5 Ambient Temperature Ambient temperature is the temperature caused by the environment in which the motor is located, is a function of such things as local weather patterns, plant cooling systems, and nearby equipment. A motor operating in an air-conditioned office building will see a lower ambient than one located directly in the exhaust of a nearby motor. For standardization purposes, design ambient is considered 40 degC ####### 33.6 Motor Current Loading Effect Motor temperature rise is predominately influenced by motor current; heating due to motor current is directly proportional to the square of the motor current. A motor overloaded by 5% would have an incremental 10% temperature increase and, if overloaded by 15%, would have a 32% temperature increase. ####### 33.7 Voltage Imbalance Effect on Winding Temperature A small voltage unbalance will cause a significant increase in motor winding temperature. Although there is no exact formula to determine the effect of voltage phase unbalance on temperature rise, laboratory tests indicate the percentage increase in motor temperature is approximately equal to twice the square of the percentage voltage unbalance. This can be expressed by the following formula: **Example** Let the voltage unbalance = 2.61% and the full load motor temperature rise at balanced voltage be equal to 80 degC. **Equation 6-1:**  % voltageunbalance 2  Tem perature Rise on unbalanced System = Tem perature rise on balanced system x 1 2   100  **Example** Let the voltage unbalance = 2.61% and the full load motor temperature rise at balanced voltage be equal to 80 degC. ####### 33.8 High or Low Voltage A 10% increase or decrease in voltage off of nameplate voltage may increase motor heating, however, such an increase in heating will not exceed safe limits provided motor is operated at values of nameplate HP and ambient temperature or less. Do not exceed 10%. ####### 33.9 Altitude Effect On Winding Temperature Motors operating at altitudes above 3,300 feet will be subject to higher temperature rises than those operating at sea level because the ambient air is less dense, and therefore will dissipate less heat. Refer to [Table 6-6](.) which contains the standard motor derate factors. **Table 6-6: Standard motor derate factors** | Altitude | Derate Factor | |-------------------|-----------------| | 3300 to 5000 feet | 3% | | 5000 to 6600 feet | 6% | | Altitude | Derate Factor | |-------------------|-----------------| | 6600 to 8300 feet | 10% | | 8300 to 9900 feet | 14% | ####### 33.10 Temperature Measurement Winding temperature can be measured by placement of two RTDs in each winding. RTDs are not standard across the HPS product line and require an RTD reader to monitor the signals. RTDs come pre-wired to the motor junction box. ####### 33.11 Frequency – Horsepower Output Motors can be provided for either 50 or 60 Hz power systems. Motor horsepower capacity is reduced at lower frequency by the ratio of operating frequency over design frequency. A motor designed for 60 Hz operation with a capacity of 120 hp will have a 100 hp capacity at 50 hertz. ####### 33.12 Power System Grounding An ungrounded power system is a serious concern that, if not properly addressed, can lead to very early motor insulation failure. On a well balanced grounded power system, the voltage line to neutral (VL-N) will equal the voltage line to ground. This is not necessarily true on an ungrounded system, where it is not unusual to see voltage swings line to ground in the power supply to the motor that approach the magnitude of line to line voltage. It can be higher in faulty conditions. A standard 4,000 V motor will have insulation from coil to ground rated for 2,400 volts (4,000 V/1.73). In ungrounded systems where the magnitude of the line to ground voltage can reach 4000 volts, insulation strength will be exceeded. ####### 33.13 Motor Enclosures ######## 33.13.1 Open Drip Proof (ODP) The open drip proof motor offers minimal protection against the elements. It will resist the entrance of water which falls at an angle less then 15 deg from the vertical. It is not suited for outdoor applications or a dirt filled environment. **Figure 6-10: ODI Enclosure Motor** ######## 33.13.2 Weather Protected Type II (WPII) This machine minimizes the entrance of wind blown snow or rain and is suitable for outdoor applications. The machine is designed with blow through, so that high velocity air and airborne particles blown into the machine can be discharged without entering the internal ventilating passages leading directly to the electrical parts. Filters can be added. **Figure 6-11: WP-II Motor Enclosure** ######## 33.13.3 Totally Enclosed Fan Cooled (TEFC, IP-54) The totally enclosed fan cooled design is the one that can withstand the dirtiest environment. It has no tubes nor air passages to clog and can be easily hosed down if the fins get caked with dirt. **Figure 6-12: TEFC Motor Enclosure** ######## 33.13.4 Totally Enclosed Air To Air Cooled (TEAAC, IP-54) TEAAC machines are designed with cooling tubes not fins as with the TEFC. The TEAAC has greater horsepower output per active winding than the fin cooled TEFC. The expense of the heat exchanger makes the TEAAC more expensive. Under some extreme environmental conditions the tubes may clog. CAZ **Figure 6-13: TEAAC Motor Enclosure** ######## 33.13.5 Use With Variable Speed Drives Motors used with VSDs encounter two problems: - incremental winding temperature rise - shaft ground currents that traverse across uninsulated bearing. [Table 6-7](.) contains a summary for the different drives used in HPS applications, and includes both impacts and design requirements for Siemens motors. The motors purchased from Siemens come in a number of configurations, which should be reviewed before use with the PWM or six step drives. **Table 6-7: Summary for the different drives used in HPS** | Drive | Winding Temperature Increase | Shaft Ground Current | |---------------------------------------|---------------------------------|---------------------------------| | Toshiba MVD | OK with standard Siemens Motors | OK with standard Siemens Motors | | Toshiba Speedstar w/ Sine Wave Filter | OK with standard Siemens Motors | OK with standard Siemens Motors | | Toshiba Speedstar (PWM) | 16.8 degC | Use grounding brush | | Centrilift (Six Step) | 35 degC | Use grounding brush | ###### 34 Instrumentation Instrumentation is used to condition monitor the HPS system to prevent catastrophic damage or system problems. Instrument signals are sent to the client SCADA system, the HPS motor controller, or an on skid controller such as the Centurion. ####### 34.1 Standard Instrumentation Package - Switches The standard HPS skid primarily uses FW Murphy mechanical switches set to trip the HPS motor when set points are exceeded. Three switches are used: - intake pressure switch, - discharge pressure switch, - thrust chamber vibration switch. The pressure switches are high and low set point devices, and the vibration switch is a high level set point device. The thrust chamber cooler system is provided with several instrumentation options, which include: - RTDT to measure TC oil temperature, - oil level switch in the cooler’s oil supply tank, - oil cooler flow switch. ####### 34.2 Monitoring The alternative to the standard instrumentation package is use of analog output devices that transmit a data stream to either an on or off skid controller. This methodology provides both set point control and data monitoring. Data monitoring provides the ability to trend conditions and evaluate changing conditions before significant problems occur. Two types of analog devices are used on HPS: - Transmitters (4 – 20mA analog instruments) - 100 ohm platinum motor RTDs. ####### 34.3 Motor Instrumentation The electric motor supplied with the HPS unit have several standard instrumentation options: - no instrumentation, - with winding temperature RTD’s, - with bearing RTDs, - bearing RTD ready, but RTDs not included. Motor operating winding temperature will define the life of the motor winding insulation. Motor insulation temperature can be estimated without instrumentation, but continuous monitoring of these temperatures can stop excursions above critical temperatures. Instrumentation to measure motor bearing vibration is not a standard feature, but is requested by clients occasionally. HPS Sustaining Engineering recommends use of the Centurion Controller to monitor vibration signals. Use of high end systems, like Bentley Nevada, which provides significant measurement detail, far exceeds actual variables that cause HPS vibrations. Cost of these high end systems can be extreme. ####### 34.4 Centurion Controller The Centurion is a FW Murphy compressor control product reconfigured for HPS. It is a universal plug and play device that can interface with any motor starter, soft starter, or VSD through its analog and digital inputs and outputs. The Centurion itself stores only alarm level events, and no instrument data; real time data capture must be routed through the MODBUS interface via a SCADA system that has been programmed for logging functionality. The link below connects to the INTOUCH document that introduces the Centurion. [http://www.hub.](http:\www.hub.slb.com\Docs\ofs\RED\reda\HPS_PLC\Announcement.pdf) [slb.com/Docs/ofs/RED/reda/HPS\_PLC/Announcement.pdf](http:\www.hub.slb.com\Docs\ofs\RED\reda\HPS_PLC\Announcement.pdf) - Read digital, analog, and RTD signals from skid instruments. - Perform automated set point control and alarming (alarm/on/off). - Provide instrument readings and controller information to client SCADA via MODBUS protocol over RS485 or RS232 connections. - Provide a corrective action to an external process, such as change the frequency of a VSD through an analog output. - Access remote control of the Centurion/skid operation via the MODBUS protocol. ###### 35 Installation Considerations ####### 35.1 HPS Shaft Alignment The straight line relationship of the shaft from end to end of a HPS plays a major role in the wear rate/reliability of the system parts. Misalignment can cause rapid wear and system failure, and should not be overlooked when commissioning, servicing, or troubleshooting is done. Alignment should be evaluated as part of the overall HPS installation during commissioning and include the effect of system piping. It is not enough to just align the HPS itself and assume piping forces are negligible. Piping forces are applied by: - Misalignment of piping flange to pump flange - High vertical load (weight) of pipe flanges and piping - High axial load (space limitations) deflecting an HPS shaft Pipe flanges should align with HPS flanges without any force required to bring them together so the bolts can be inserted, including alignment in the axial direction. Axial force applied to the discharge can apply loads along the entire length of the pump to the thrust chamber. System piping should be supported off skid so that minimal weight load is carried by the HPS flange. ####### 35.2 HPS Foundation and Support HPS foundation type and the support it provides can define long-term success of an HPS installation. Bottom contact support along the entire length of the skid frame is needed to provide a stable and level installation. Use of other methods such as timbers and piers, provides the opportunity for increased vibration which increases wear rate. The [InTouch link](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4010148) provides a typical plan and foundation details for an HPS skid. ###### 36 Reference Links to HPS Information A detailed overview of all HPS components is available in the HPS selection guide that can be accessed through the link below: [http://www.hub.slb.com/Docs/ofs/RED/reda/TESupport/HPSSelectionGuide.pdf](http:\www.hub.slb.com\Docs\ofs\RED\reda\TESupport\HPSSelectionGuide.pdf) The link below connects to the NAM Geomarket HPS website, which includes technical and sales information. [http://www.hub.slb.com/display/index.do?id=id2648897](http:\www.hub.slb.com\display\index.do?id=id2648897) The link below connects to the BPC Sustaining Engineering website, which contains design information, and all the unit manuals from 2003 to present. [http://www.hub.slb.com/display/index.do?id=id1571221](http:\www.hub.slb.com\display\index.do?id=id1571221) ###### 37 Auxiliary Equipment Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ##### Gas Lift - [**Gather the Data and Specifications 7-1**](.) - [**Gas Lift Equipment Selection 7-1**](.) - [Unloading Valves – PPO 7-2](.) - [Orifice Valves 7-2](.) - [Venturi Orifice Valves (Nova) 7-2](.) - [Shear Type Orifice Valves 7-3](.) - [Dummy Valves 7-3](.) - [Chemical Injection Valves 7-3](.) - [Water Flood Regulator Valves 7-3](.) - [X-Lift High Pressure Valves 7-4](.) - [Barrier Valves 7-4](.) - [Circulating Valves 7-5](.) - [Pilot Valves 7-5](.) - [Gas Lift Valve Latches 7-5](.) - [Oval Side Pocket Mandrels 7-7](.) - [Round Side Pocket Mandrels 7-7](.) - [X-Lift Gas Lift Mandrels 7-8](.) - [Barrier Mandrels 7-8](.) - [Conventional Orifice Valves 7-8](.) - [Conventional Reverse Flow Check Valves 7-8](.) - [O-rings 7-9](.) - [Mandrel Metallurgy 7-10](.) - [Continuous Flow Gas Lift 7-11](.) - [Production Pressure Operated System (PPO) 7-11](.) - [High Pressure Gas Lift Barrier System 7-12](.) - [PerfLift Gas Lift System 7-12](.) - [Intermittent Gas Lift 7-13](.) *7* **Gas Lift** ###### 38 Gather the Data and Specifications - [Retrievable Gas Lift Valves 7-1](.) - [Unloading Valves – IPO 7-1](.) - [Gas Lift Side Pocket Mandrels (SPM) 7-6](.) - [Gas Lift Mandrel Nomenclature 7-6](.) - [Conventional Gas Lift Valves 7-8](.) - [Conventional Unloading Valves 7-8](.) - [Conventional Gas Lift Mandrels 7-9](.) - [Conventional Mandrel Series 7-9](.) - [Elastomer Selection 7-9](.) - [Chevron V-Packings 7-9](.) - [Metallurgy Selection 7-10](.) - [Valve Metallurgy 7-10](.) - [Introduction 7-11](.) - [Injection Pressure Operated System (IPO) 7-11](.) - [X-Lift High Pressure Gas Lift System 7-12](.) Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 39 Gas Lift Equipment Selection The scope of this chapter is to briefly explain the different types of gas lift equipment that might be used in the field. This serves as a quick reference for the person that’s not too familiar with gas lift systems but might be involved with equipment selection and/or use. ####### 39.1 Retrievable Gas Lift Valves Retrievable gas lift valves are the most common types of gas lift valves seen in the field. They are to be installed in tubular sections in the production string, also called side pocket mandrels. These valves generally come in either 1 in or 1-1/2 in OD versions, except for the X-Lift valves which come in 1- 3/4 in OD versions. The barrier valves come in either 1 in, 1-1/2 in or 1-3/4 in OD versions. There are different metallurgy and elastomer options available, depending on the required operating conditions. ######## 39.1.1 Unloading Valves – IPO These valves have mostly Nitrogen but sometimes a spring charge in them that keeps them normally closed, unless the gas injection pressure is high enough to keep them open. Therefore the opening and closing of these valves is controlled by the gas injection pressure. These valves are used during the initial unloading phase of gas lift operations where liquids from the annular space are evacuated into the production string. During normal gas lift operating conditions these valves will stay closed and the only valve passing gas into the production string will be the operating gas lift valve, also called orifice valve. - BK1-M - Nitrogen charged, 1 in OD, with integrated running head and bottom latch. - BK-PE – Nitrogen charged, 1 in OD, premium elastomers. - BK – Nitrogen charged, 1 in OD, the most widely used 1 in IPO valve. - R20-PE — Nitrogen charged, 1-1/2 in OD, premium elastomers. - R20 — Nitrogen charged, 1-1/2 in OD, most widely used 1-1/2 in OD IPO valve. - R20-02 — Nitrogen charged, 1-1/2 in OD, improved back check design. ######## 39.1.2 Unloading Valves – PPO These valves have mostly Nitrogen but sometimes a spring charge in them that keeps them normally closed, unless the production pressure is high enough to keep them open. Therefore the opening and closing of these valves is controlled by the production pressure. These valves are used during the initial unloading phase of gas lift operations where liquids from the annular space are evacuated into the production string. During normal gas lift operating conditions these valves will stay closed and the only valve passing gas into the production string will be the orifice valve. - BKR-5 - Nitrogen charged, 1 in OD, with integrated running head and bottom latch. - BKF-12 - Spring charged, 1 in OD, temperature insensitive. - BKR-5P - Nitrogen charged, 1 in OD, integral crossover seat with larger port size. - R-25 - Nitrogen charged, 1-1/2 in OD, max port size 5/16 in. - R-25P - Nitrogen charged, 1-1/2 in OD, integral crossover seat with 3/8 in max port size. ######## 39.1.3 Orifice Valves These valves are the operating valves of the gas lift system and are designed to control the injection gas passage into the production string. Only one of these valves will be incorporated in the completion string, whereas there normally are multiple unloading valves. The orifice valve type does not incorporate a Nitrogen or spring charged bellows that would keep the valve normally closed, only a back check valve and orifice plate; therefore this valves will always be open as long as it sees a positive pressure differential. - DKO-2 - 1 in OD, integrated running head and bottom latch. - BKO-3 - 1 in OD, most widely used 1 in OD orifice valve, max port size 20/64 in. - BKO-5 - 1 in OD, max port size ½ in, metal-to-metal check, Inconel parts used, relatively expensive. - OM21-R, 1 in OD, standard orifice for port sizes bigger than 20/64 in, max port size ½ in. - RDO-20 - 1-1/2 in OD, standard orifice, max port size ½ in. - O21-R - 1-1/2 in OD, used when larger port sizes than ½ in are needed. - O2-30R - 1-1/2 in OD, dual back check orifice valve. ######## 39.1.4 Venturi Orifice Valves (Nova) This type of operating gas lift valve has a funnel-like venturi profile orifice, instead of a square edged orifice plate. The effect of the venturi profile is that the valve always operates in critical flow, in other words it always passes the maximum, and therefore constant, gas injection rate. This constant gas injection rate, which does not vary with the pressure differential over the valve, greatly promotes stable injection and production conditions. - NOVA-10 - 1 in OD Venturi Orifice valve - NOVA-15 - 1-1/2 in OD Venturi Orifice valve ######## 39.1.5 Shear Type Orifice Valves This operating valve type incorporates a draw bar assembly that effectively keeps the valve sealed; until there’s enough pressure differential applied over the valve in order to shear the draw bar. The activation pressure of the valve depends on the strength of the drawbar selected, ranging from 1,000 to 4,250 psi. From the moment the draw bar shears, the valve basically continues to function as a dual check orifice valve. The shear orifice valve is only available in a 1-1/2 in OD version. - SO2-30R, 1-1/2 in OD shear type orifice valve ######## 39.1.6 Dummy Valves Dummy valves are basically acting as plugs for the pocket section of the side pocket mandrel; when the mandrel is not used for gas lifting it can be sealed up with a dummy valve. This type of valve is basically a block of steal in the form of a gas lift valve, with a full set of V-packings to seal off inside the pocket section of the mandrel. When later on the mandrel is to be used for gas lifting operations, the dummy can be retrieved with slickline tools and replaced by another type of gas lift valve. - E – 1 in OD, most widely used 1 in OD dummy valve. - DK-1 – 1 in OD, with integrated running head and bottom latch. - RD – 1-1/2 in OD dummy valve. ######## 39.1.7 Chemical Injection Valves These types of valves are used, in combination with a gas lift mandrel that accepts a chemical injection line, in order to control the injection of treatment chemicals into the production string. They can be either Nitrogen charged working on absolute pressure, Nitrogen charged working on differential pressure, or spring charged in order to control the activation pressure of the valve. - BKLK-2 – 1 in OD, Nitrogen charged, absolute activation pressure, max. port size 5/16 in . - CM-40R – 1 in OD, Spring charged, differential activation pressure, improved tapered seat, 2 spring options. - LK-3 – 1 in OD, Spring charged, differential activation pressure. - BKCI-2 – 1 in OD, Nitrogen charged, high pressure chemical injection valve, max. dome pressure 10,000 psi. - C-31R – 1-1/2 in OD, Spring charged, differential activation pressure. - RCDC – 1-1/2 in OD, no charge, dual check valve. - RCB – 1-1/2 in OD, Nitrogen charged, absolute activation pressure. ######## 39.1.8 Water Flood Regulator Valves This type of valve is not used for gas injection purposes, but for regulation injection volume on water injector wells. By correctly selecting the port size on these valves, we control the water volume that passes through them. Therefore it makes it easy to control the exact volume that’s being injected into different zones of the reservoir by correctly sizing and placing the water flood regulator valves. As mentioned before, these valves regulate the water passage through them based only on the port size; they do not vary the water injection volume based on the pressure differential over the valve. - CWFT-1 – 1-1/4 in OD, increased injection volume as compared to 1 in OD valve, ran in long 1 in nominal pocket mandrel - RWF-B – 1-1/2 in OD, single entry port for water - RWF-D – 1-1/2 in OD, top and bottom entry point for water, increased injection volumes as compared to RW-B - P-15 – 1-1/2 in OD, Spring charged, differential activation pressure ######## 39.1.9 X-Lift High Pressure Valves Besides their higher setting pressures, the X-Lift valves differ from other gas lift valves in their size, which is 1- 3/4 in OD. There are X-Lift IPO, Orifice and Dummy valve available. Both the X-Lift IPO and Orifice valves incorporate the venturi orifice for constant gas injection rates, as well as positive sealing back check valves. - XLI – 1-3/4 in OD, IPO valve, max 5,000 psi activation pressure, incorporates venturi orifice and positive sealing back check. - XLO – 1-3/4 in OD, Orifice valve, incorporates venturi orifice and positive sealing back check. - XLO-B – 1-3/4 in OD, Orifice valve, incorporates burst (rupture) disc assembly, venturi orifice and positive sealing back check. - XLD – 1-3/4 in OD, Dummy valve. **Note** There are several valves listed in the catalog with the XJR added to the name of the valve, such as NOVA-15 XJR. All that means is that these valves incorporate the positive sealing check design instead of the traditional velocity back check. ######## 39.1.10 Barrier Valves The higher setting pressures and check valve design is the only difference between the barrier valve and the other gas lift valves. There are barrier chemical injection, IPO, and Orifice valves available. All the barrier vavles incorporate the venturi orifice for constant gas injection rates, as well as the metal-to-metal back check design. - TCBV – 1-in OD Tubing Casing Valve, continuous flow applications - RLC-4R-B – 1-1/2 in OD Chemical Injection Valve - O2-30R-B – 1-1/2 in OD Dual-Check Orifice Valve - SO2-30R-B – 1-1/2 in OD Dual-Check Shear Orifice Valve - R-20-02-B – 1-1/2 in OD Injection Pressure–Operated Valve - O-21R-B – 1-1/2 in OD Single-Point-Injection Orifice Valve - NOVA 15-B – 1-1/2 in OD Venturi Orifice Valve - XLI-B – 1-3/4 in OD IPO Valve - XLOB – 1-3/4 in OD Venturi Orifice Valve - XLO-R-B – 1-3/4 in OD Venturi Orifice Valve, incorporates burst (rupture) disc assembly **Note** There are several valves listed in the catalog with the “-B” added to the name of the valve, such as NOVA-15–B. Typically, that means these valves incorporate the barrier check design. The exception is the XLO-B which in some cases identifies the XLift burst disc Orifice valve. The barrier version of the XLO is XLOB. ######## 39.1.11 Circulating Valves Circulating valves are designed for passing liquids instead of gas and are used to protect the polished bores of the pocket of the SPM in case liquids needs to be circulated through it. It is not recommended to circulate liquids through an empty pocket of the SPM because this could lead to scoring of the polished bores which might result in a leaking mandrel. - CSK-1 – 1 in OD, integrated running head and bottom latch. - DCK-3 – 1 in OD, dump kill valve w/ shear pin activation. - RKFS – 1-1/2 in OD, flow sleeve, bottom entry/exit port. - DCR – 1-1/2 in OD, normally closed w/ shear pin activation. ######## 39.1.12 Pilot Valves The Pilot valve is used for intermittent gas lift operations, where a large burst of gas needs to enter the tubing very quickly. In order to be able to pas a large volume of gas, but at the same time still to be injection pressure sensitive, the Pilot valve opens up larger by-pass ports once the injection pressure sensitive valve mechanism itself is activated. - PK-1M – 1 in OD, max. port size 5/16 in. ######## 39.1.13 Gas Lift Valve Latches A gas lift valve is ran, retrieved and locked in place inside the SPM pocket by using a latch mechanism that screws onto the top of the gas lift valve itself. Some valve types have an integrated running head and bottom latch mechanism, but the majority of gas lift valves use a separate latch. There several types of latches, they either lock behind a 180 or 360 degree profile above the SPM pocket section. - BK-2 - spring loaded, ring style Latch for 1 in valves that locks behind 180 degree profile. - BK-4 – spring loaded, ring style Latch for 1 in valves that locks behind 180 degree profile, steel pinned to prevent accidental unscrewing. - BK-5 - spring loaded, ring style Latch for 1 in valves that locks behind 180 degree profile, steel pinned to prevent accidental unscrewing. - RK - spring loaded, ring style Latch for 1-1/2 in valves that locks behind 180 degree profile (most widely used 1-1/2 in latch). - RK-SP - spring loaded, ring style Latch for 1-1/2 in valves that locks behind 180 degree profile, steel pinned to prevent accidental unscrewing. - RKP - spring loaded, ring style Latch for 1-1/2 in valves that locks behind 180 degree profile, ported center section, to be used with SO2-30R shear valve. - RM - spring loaded Latch for 1-1/2 in valves that locks behind 360 degree profile (MMA/ MTA Mandrels). - RA - spring loaded Latch for 1-1/2 in valves that locks behind 360 degree profile (MMA/ MTA Mandrels). ####### 39.2 Gas Lift Side Pocket Mandrels (SPM) The gas lift side pocket mandrel is a tubular section of the production string that acts as the receptacle for the gas lift valve. Most gas lift side pocket mandrels contain similar components such as the pocket section, orienting sleeve for kick over tool, discriminator sleeve and latch profile. There are other options available such as external guard rails, extended swage for thread recuts or an NPT connection for a chemical injection lines. Furthermore side pocket mandrels are available either in forged oval shapes (more economical, lower metallurgy and pressure rating) or machined round shapes (more expensive, higher metallurgy and pressure rating). Therefore we can see there are literally hundreds of different SPM designs out there; this section intends to make navigating this wealth of options easier. ######## 39.2.1 Gas Lift Mandrel Nomenclature Different letters and numbers in the naming of the gas lift side pocket mandrels stand for specific design features in a design. The gas lift mandrel nomenclature will make it easier to understand a specific mandrel’s attributes. **KB:** as 1st identifier – Mandrel for 1 in valves **M :** as 1st identifier – Mandrel for 1-1/2 in valves **M:** as 2nd identifier – Oval body pipe **M:** as 3rd identifier – Machined pocket w/ tool discriminator **G:** Tool discriminator and Orienting sleeve **R:** Camco design, round body pipe **T:** Tru Guide, slim line design, round body pipe **A:** A-pocket latch profile (360 degrees) **U :** Reduced OD and ID **E :** Standard pocket porting, bottom exhaust **EC:** Pocket ported to tubing, bottom exhaust **W :** Waterflood **2 :** Slightly reduced Major OD **3 :** Special threading considerations **4:** Allows thread re-cuts **5 :** External guard rails for cable by-pass **7 :** Special internal modifications **8 :** Special pocket modification **9 :** Bottom latch only **10 :** Pluggable or no ports **LT :** Side pipe pocket porting **LTS :** Side lug to accept injection line **V :** Multiple pockets ######## 39.2.2 Oval Side Pocket Mandrels The oval type gas lift side pocket mandrels are made out of forged tubing. Therefore the grade of metallurgy that is available for these types of mandrels is less than 12Cr. These mandrel types are generally more economical to fabricate, their raw material cost is less and their major OD is smaller, but at the same time they have relatively lower pressure ratings as compared to the round mandrel types. - KBMG – Standard mandrel for 1 in valves, available in up to 12Cr metallurgy, relatively small Major OD. - KBMG – Low-cost mandrel for 1 in valves, available in up to 12Cr metallurgy, relatively small Major OD, max 3-1/2 in tubing. - MMG - Standard low-cost mandrel for 1-1/2 in valves, available in up to 12 Cr metallurgy, relatively small Major OD. - MMM – Low-cost mandrel for 1-1/2 in valves, available in up to 12Cr metallurgy, relatively small Major OD, machined pocket, max 4-1/2 in tubing. ######## 39.2.3 Round Side Pocket Mandrels The round type gas lift side pocket mandrels are made out of machined section. Therefore the grade of metallurgy that is available for these types of mandrels can be higher than 12Cr. These mandrel types are generally more expensive to fabricate, their raw material cost is higher and their major OD is larger, but at the same time they have relatively higher pressure ratings as compared to the oval mandrel types. - KBG – Mandrel for 1 in valves, up to 4-1/2 in tubing size - KBTG – Tru Guide, slim-line mandrel for 1 in valves - MMRG – Mandrel for 1-1/2 in valves, up to 7 in tubing size - MTG – Tru Guide, slim-line mandrel for 1-1/2 in valves - MTA – Tru Guide, slim-line mandrel for 1-1/2 in valves, RM/RA latch profile ######## 39.2.4 X-Lift Gas Lift Mandrels The X-Lift gas lift mandrel design was based on the WRFC-H flow control valve body, and accepts the larger 1-3/4 in X-Lift valves. - EXTREMELIFT – Mandrel for 1-3/4 in X-Lift valves, available in either 4-1/2 in or 5-1/2 in tubing sizes ######## 39.2.5 Barrier Mandrels The barrier valves are installed in the standard gas lift mandrel based on the valve size. The TCBV is typically used in dual valve applications using a dual-pocket barrier mandrel. - MMRG-2V-B Barrier Series Dual-Pocket, Side Pocket Mandrel ####### 39.3 Conventional Gas Lift Valves The conventional type of gas lift valve was the traditional gas lift valve before the invention of the Side Pocket Mandrel (SPM). They screw onto the outside of a conventional gas lift mandrel. Therefore these types of valves are only tubing retrievable; they can not be changed out with slickline tools. ######## 39.3.1 Conventional Unloading Valves - J-20 – 1-1/2 in OD conventional IPO valve ######## 39.3.2 Conventional Orifice Valves - JO-20 – 1-1/2 in OD conventional orifice valve ######## 39.3.3 Conventional Reverse Flow Check Valves These check valves are optional items, to be combined with the conventional gas lift valves that don’t have integrated check valves. - J-20 – Reverse flow check valve for 1-1/2 in conventional valves - B-1 - Reverse flow check valve for 1 in conventional valves - SJ-20 – Same as J-20, manufactured by Southern Oilfield Services (SOS) - SB-1 – Same as B-1, manufactured by Southern Oilfield Services (SOS) - Waterflood – 1-1/16 in check for waterflood applications ####### 39.4 Conventional Gas Lift Mandrels The conventional mandrels series, which are not manufactured by Schlumberger, are basically sections of tubing with a thread connection welded onto it that accepts the conventional gas lift valve. These mandrel series are sourced from a company called Mandrels Inc. ######## 39.4.1 Conventional Mandrel Series - B-series – Conventional mandrel for 1 in valves ####### 39.5 Elastomer Selection There are two important parts inside gas lift valves that are made out of elastomers; one is the V- packing that seals off the polished bores of the pocket, and the other are internal O-rings. Selection of the elastomer type used for these parts depends on well conditions, such as pressure, temperature, H2S content or acidity. For further information on elastomer selection for Oilfield applications see the WCP Materials Engineering / Elastomers and Plastic reference page on [InTouch Content ID 3315714](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3315714) . ######## 39.5.1 Chevron V-Packings There are several types of V-packing material for gas lift valves; selection of appropriate type depends on expected well conditions. - Nitrile – Standard service V-packing - Neoprene – Standard Service V-packing - Aflas – Sour service V-packing, also good for chemical injection purposes, good up to 350 degF - CamPac – Premium V-packing for extreme conditions ######## 39.5.2 O-rings There are basically two types of O-ring material available for gas lift valves, selection of appropriate type depends on expected well conditions. - Viton – Standard service O-ring - Aflas – Sour service O-ring, also good for chemical injection purposes, good up to 350 degF. ####### 39.6 Metallurgy Selection Gas lift valves and mandrels can be made out of a wide range of metal types. Selection of the appropriate metallurgy type depends on well conditions, such as pressure, temperature, H2S content or acidity. For further information on metallurgy selection for Oilfield applications see the WCP Materials Engineering/ Metals reference page on [InTouch Content ID 3285474](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3285474) . ######## 39.6.1 Valve Metallurgy There are several types of metallurgy available for gas lift valves; selection of appropriate type depends on expected well conditions. - 316SS – Standard service, no or only low concentration of H2S/ CO2 present. - Monel – Sour service, good up to 275 degF with H2S/ CO2, chemical injection purposes. - Inc918 – Sour service, combined with high temperature. - Inc718 - Sour service, combined with high temperature, expensive. ######## 39.6.2 Mandrel Metallurgy There are several types of metallurgy available for gas mandrels; selection of appropriate type depends on expected well conditions. A good reference for material selection is the metallurgy of the tubing the client is intending to run, as well as other completion accessories such as packers or safety valves. - 4130/4130 – Good in H2S up to 22 Re Hardness, available in Low or High heat treat, not good for CO2. - 9Cr – Fair in H2S and CO2, not recommended for water injection, max 300 degF. - 13Cr – Fair in H2S, good for CO2 service up to 300 degF. - Super 13Cr – Not good for H2S, good for CO2 service up to 350 degF, inexpensive relative to nickel based alloys. - 25Cr – Fair in H2S, good up to 450 degF, excellent in water injection service - Alloy 925 – Very good for H2S/ CO2/ CL service, high strength up to 300 degF, compatible in acidizing solutions, expensive relative to stainless steels. ###### 40 Gas Lift Introduction This chapter gives a very brief overview of what gas lift is, and the different types of gas lift systems that one might expect to come across in the field. ####### 40.1 Introduction The artificial lift method of Gas Lift uses high pressure natural gas to lighten the liquids that are being produced from the well. For standard operations gas is injected down the annular space of the well, through a sequence of downhole valves, and into the production tubing. The objective is to lighten the hydrostatic load on the formation to the maximum extent, hereby allowing an increase in drawdown, resulting in incremental production. The injection of the gas into the tubing, at different sequential depths in the well, is controlled by gas lift valves that are installed inside tubular sections called side pocket mandrels. The flow of injection gas can be continuous or intermittent, depending on the well conditions. Gas lift can be found on land and offshore wells, as well as deep subsea wells such as those found in the Gulf of Mexico or West Africa. ####### 40.2 Continuous Flow Gas Lift Continuous flow gas lift operations have non-stop gas injection into the production string. Once the gas injection point has sequentially stepped down the production string through a series of unloading gas lift valves, and it arrives at the deepest injection point where an orifice gas lift valve is installed, we continue to inject gas into the production string in order to maintain the increased drawdown on the formation. If we were to stop the gas injection when arriving at the deepest point of injection we would simply return the well to its natural production state, whereas with gas lifting the aim is to maintain the incremental drawdown and its associated higher production rate. The optimum gas injection rate is a function of the well conditions and can vary from a few hundred thousands to several million standard cubic foot of gas. When injecting the gas into the production string at the deepest point possible in the well, the only gas lift valve that is open is the orifice valve; the other (unloading) valves in the completion string would have closed down either as a function of a declining injection pressure (IPO) or a declining production pressure (PPO). All unloading valves have a nitrogen or spring charge in them that acts as a force to close the valve down, so they’re closed unless there’s a large enough force from either the production or injection pressure to keep them open. ######## 40.2.1 Injection Pressure Operated System (IPO) In an Injection Pressure Operated (IPO) gas lift system, the opening and closing of the gas lift valves is controlled by the gas injection pressure. Therefore it is the injection pressure that acts as a force to hold the unloading valves open. As soon as we see drops in the gas injection pressure, the IPO unloading valves will sequentially close down. Every time we step down from one injection point in the string to the next injection point located below it, there will be a drop in injection pressure that closes down the higher valve. This type of gas lift system is most widely used. ######## 40.2.2 Production Pressure Operated System (PPO) In a Production Pressure Operated (PPO) gas lift system, the opening and closing of the gas lift valves is controlled by the production pressure. Therefore it is the production pressure that acts as a force to hold the unloading valves open. As soon as we see a decrease in the production pressure as we inject the gas deeper down the well, the PPO unloading valves will sequentially close down. Every time we step down from one injection point in the string to the next injection point located below it, there will be a decrease in production pressure that closes down the higher valve. This type of gas lift system is used mainly with Dual String gas lift completions, where we have two production strings both on gas lift and one common annular space. Another application of the type of gas lift system would be in case we don’t have a good enough control over the gas injection pressure, or this pressure varies greatly over time. ####### 40.3 X-Lift High Pressure Gas Lift System Traditional gas lift technology, rated for 2,000 psi maximum gas injection pressure, is normally installed in today’s wells and is designed with check valves that could introduce leak paths. In higher-pressure completions, such as deep subsea applications, significant problems can result from the normal operating configurations of traditional gas lift systems. The Schlumberger XLift high- pressure gas lift system extends the capability of existing systems by raising the maximum operating pressure from 2,000 psi to 5,000 psi. In addition, the XLift system uses a performance tested positive-sealing check valve system, designed to replace the velocity check valve systems used in traditional gas lift valves. At the same time these X-Lift valves incorporate a Venturi style orifice to control and stabilize the gas passage into the production string. This new system enables operators to complete and operate gas lift wells with far higher gas injection pressures and deeper (multiple) injection points to significantly increase well performance and tubing integrity. ####### 40.4 High Pressure Gas Lift Barrier System The Schlumberger gas lift barrier system extends the capability of existing high pressure systems by raising the maximum operating pressure from 5,000 psi to 10,000 psi. The positive-sealing check valves are qualified to meet API-19G1 and G2 industry standards and pressure barrier qualifications. With a test pressure rating of 10,000 psi [68,947 kPa], they form a metal-to-metal barrier between the tubing and casing annulus that prevents undesired communication or reverse flow and mitigates the risks associated with typical gas lift valve check systems. This system enables operators to complete and operate gas lift wells with far higher gas injection pressures and deeper (multiple) injection points to significantly increase well performance and tubing integrity. The barrier valves are available in either 1 in, 1-1/2 in or 1-3/4 in OD versions, unlike XLift valves which are only available in 1-3/4 in OD versions. ####### 40.5 PerfLift Gas Lift System The PerfLift perforated-zone gas lift system is a cost-effective artificial lift system for low-rate gas- lifted oil and liquid-loaded gas wells. The system incorporates gas lift products in an innovative completion architecture that enables gas lift across long completion intervals below (!) a production packer. This method reduces the cost and complexity of liquid removal; most other methods of liquid removal require costly intervention, using a traditional workover rig or coiled tubing unit. The PerfLift system is permanently installed when the completion is run, so there is no need for a service rig to install a system after the well is already producing. The PerfLift gas lift system is ready for service whenever liquid loading limits production, or in cases where liquid loading is an ongoing problem it can be used continuously to maximize production. The PerfLift system employs a series of gas lift mandrels and valves in tubing strings above and below a ported or dual-bore production packer. Conventional or side-pocket gas lift mandrels are installed in the upper tubing string. Internal-mount gas lift mandrels and valves are sized and installed on the lower tubing string across the perforated zone. During system operation, gas is injected down the upper tubing-string annulus and into the lower tubing string through the packer to lift the fluid column across the entire perforated zone. Liquids then travel to the surface through the production. ####### 40.6 Intermittent Gas Lift As opposed to continuous injection gas lift, an intermittent gas lift system goes through cycles of injection periods. At a certain point in the well life, the reservoir pressure can become so low that, even with the optimum amount of gas, the well is not able to produce up to the surface. In that case intermittent gas injection might be used where, as opposed to continuous gas lift operations, we actually push a liquid slug of production up to the surface with the injection gas. So these are the main differences between the two; with continuous gas lift we inject the gas to lighten the produced fluids and we inject it continuously, and with intermittent gas lift we use a burst of high pressure gas to actually push the liquid up to the surface and we inject it in cycles. Sometime a metal plug is used as an interface between the liquid slug that’s pushed up to the surface and the injection gas in order to improve upon the efficiency of the system; this is also called plunger lift. The application of intermittent gas lift operations is limited to shallow land wells. Currently there’s no Schlumberger software released that handles intermittent gas lift designs, but there’s ample literature published on the manual design of these systems. ###### 41 Auxiliary Equipment Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ##### Downhole Monitoring - [**Gather the Data and Specifications 8-1**](.) - [**Monitoring Tools and Gauges 8-1**](.) - [**Types of Gauges 8-2**](.) - [CTS ESP Gauges 8-5](.) - [Hotline CTS Gauges 8-7](.) - **Monitoring Parameters** ***8-12*** *8* **Downhole Monitoring** ###### 42 Gather the Data and Specifications - [ESP Gauges 8-3](.) - [Standard Type 0 and Type 1 Gauges 8-3](.) - Cable-to-Surface Non-ESP Gauges *8-6* - [Phoenix CTS Gauges 8-7](.) - Phoenix Surface Chokes *8-9* The selection of adequate downhole monitoring system is important to provide the most effective and reliable gauge to well environment and required type of application. During selections specification of the gauge need to match or exceed the minimum requirements The following data is required for equipment selection. - Artificial Lift Application (ESP, PCP, ESPCP, Gas Lift, Beam Pump, Jet Pump, Zeitecs, RedaCoil) - Reservoir Bottom Hole Pressure (BHP) - Reservoir Bottom Hole Temperature (BHT) - Environment conditions H2S, CO2 - Measurement Parameters required. - Does the gauge require a separated cable? - Type of Data Acquisition i.e Standalone, data acquisition included with VSD Controller. Upon the identification of applications and well conditions, the monitoring tool is selected according the gauge Specifications which is mainly provided in the Marketing Material and the Gauge User Manuals. Make sure always to verify the specifications in the Gauge User Manual. ###### 43 Monitoring Tools and Gauges An Artificial Lift (AL) downhole gauge is a tool that is normally installed at downhole level as part of the AL string. The purpose is usually to measure and transmit downhole parameters (related to well and/or lift equipment) that are critical to the operation and protection of the AL system. The measurement parameters depend on the selected gauge. Some of main parameters include: - Intake Pressure (Pi) - Intake Temperature (Ti) - Pump Discharge pressure (Pd) - Motor Temperature (Tm), commonly used to connect to thermocouple provided with the motors for measuring Motor Winding Temperature. - Vibration (Vib) measured using accelerometers - Current leakage may also be measured and used. AL gauges can be used in a variety of applications that range from single-well focused equipment protection and production control to field-wide trending and optimization. The selected gauge type and surface equipment depend on customer objective. The different combinations of equipment installed, measured parameters and the response on surface have to address customer objectives. Single Well objectives include: - AL system (single) protection; example: In case of ESP the Protection of motor, pump, etc. and assurance, pre-warning of system deterioration or well pump-off. - Well automation using feedback loops to VSD’s; such as using intake pressure, or well head pressure feedback to control VSD frequency (Hz), etc. Field-wide objectives may include: - Equipment and well monitoring and production maintenance, where measured data are used to ensure all equipment are running (up-time) and minimum production is maintained. This also allows for customer resource planning including spare equipment, rigs and crews. - Field production monitoring trending and optimization, where measured data are acquired, trended and analysed to allow production engineers to optimize production in line with customer production policy. Both single-well and field-wide downhole gauge measured data can be delivered to production engineers through traditional or remote data transmission systems such as SCADA systems (with RTU’s) at well-site or through satellite systems, such as the LiftWatcher or LiftIQ service. Examples of how different monitored parameters can be used: **Term Definition** **Intake Pressure** Provide information about level of fluid (pressure), references to drawdown and build up. Additionally, give references for ALARM for protection during pump-off. **Discharge Pressure** Monitor pump discharge behaviors which in combination with Pump Intake can help to determine the operation efficiency of the pumps, but also help to detect plugging and leakage above the discharge head of the pump. **Discharge Temperature** Protect your MLE and analyses your pump performance in viscous fluids. **Motor Temperature** Use the high temperature rating sensor (Thermocouple) to monitor motor winding temperatures. **Vibration** Know when your ESP is experiencing significant change in mechanical conditions due possible wear or damage, solids production and possibly helpful in preparing spares and work over. **Current Leakage** Use to monitor the electrical integrity of the Downhole components in the system (Cable, transformers, Motor winding, etc). Refer to [https://www.slb.com/completions/artificial-lift/electrical-submersible-pumps/gauges](https:\www.slb.com\completions\artificial-lift\electrical-submersible-pumps\gauges) . ###### 44 Types of Gauges The current range of gauges offered includes analog and digital telemetry gauges. There are two gauge families. There are two gauge families: - **Phoenix** : Compatible with the Phoenix Interface Card (PIC) includes all Phoenix digital gauges (xt150, xt175, CTS, CTS6000, xt150-R, xt150-To-Surface, etc.). This family includes both Standard ESP and CTS (cable-to-surface) gauges. CTS type gauges require a monitoring cable for communication and power. - **Hotline** : Compatible with the Hotline Extreme Interface Card (Extreme Card) includes all Hotline gauges (Hotline CTS, Hotline ESP, etc.). This family only include CTS (cable-to-surface) There are two primary ALS gauge applications: - ESP applications use gauges which are attached to the ESP motor. The standard ESP gauges (i. e., xt150, xt175, xt150-R, Zeitec gauge, Redacoil) use the ESP power cable as means of communication and power. The CTS gauges (i.e., Hotline ESP, xt150-To-Surface, etc.) use a permanent downhole cable (PDC) as means of communication and power are also available for ESP applications. - Non-ESP applications use gauges which are mounted to the tubing string. These gauges (i.e., CTS6000, Hotline CTS, etc.) are all CTS type gauges and require a monitoring cable for communication and power. They are commonly used with PCP, Beam Pump, Gas Lift and Jet Pumps applications. ####### 44.1 ESP Gauges Typically, ESP gauges are installed on the base of the downhole ESP motor. The Phoenix gauges use the ESP cable as means of communication and power. The Hotline gauges use a monitoring cable as means of communication and power ######## 44.1.1 Standard Type 0 and Type 1 Gauges There are two main type of standard ESP gauges: - The Type 0 gauge measures Intake Pressure (Pi), Intake Temperature (Ti), motor winding temperature when motor thermocouple is provided with the motor (Tm), Vibration (Vib) and Current Leakage (Cla) of the ESP electrical system. - The Type 1 gauge measures additionally the pump Discharge Pressure (Pd), and this is achieved by transferring the pressure from the Discharge Pressure Sub (Installed on the top or above the pump head) through the Pressure hydraulic Transfer Line until the base gauge. The xt150-to-Remote gauge is similar to a type 1 gauge but it measures Discharge Pressure (Pd), Discharge Pressure Temperature (Td) and Vibration axis at the discharge (Vibx, Viby and Vibz). The parameters from discharge are achieved by installing a Remote gauge/sensor above the pump head and data to base gauge is transferred by an electrical cable (I-wire). Annulus pressure Annulus temperature Motor winding temperature Motor vibration (X, Y, Z axes) Current leakage **Figure 8-1: Type 0** For specifications, refer to the applicable gauge manual in InTouch. Pump discharge pressure Pump discharge temperature Pump discharge vibration (X, Y, and Z axes) Annulus pressure Annulus temperature Motor winding temperature Motor vibration (X, Y, Z axes) Current leakage **Figure 8-2: Type 1** For specifications, refer to the applicable gauge manual in InTouch. ######## 44.1.2 CTS ESP Gauges The cable-to-surface gauges use a permanent downhole monitoring cable from downhole gauge to surface data acquisition as means of communication and power. The CTS gauges can be used for non-ESP and ESP applications. The Hotline ESP gauge systems, with Paine sensors, are used in high temperature ESP applications up to 250degC. On the surface the Extreme Card is installed in the surface controller (UniConn, Instruct, etc.). The gauge accessories (wellhead connectors, junction box, Cable connector/Kemlon, surface cable) are also required as part of the gauge monitoring system. **Figure 8-3: Hotline ESP Monitoring System** The Hotline SA3 gauge is only offered as an integrated component of the REDA Hotline XTend extended-capacity high-temperature ESP system. The Hotline SA3 integrated motor can be ordered with one of two options: - RTD+Paine: monitors Motor Temperature, Intake Pressure and Intake Temperature - RTD Only: monitors Motor temperature. The xt150-to-Surface gauge is based on xt150 technology and used for applications where a separate downhole monitoring cable is required. On the surface the PIC is installed in the surface controller (UniConn, Instruct, etc.). This gauge system is intended for ESP systems where the surface connections are required to connect to the Y-point to ground on the transformers or step-up transformer for safety reasons. The downhole monitoring cable helps to ensure gauge power and data transfer without any electrical interference. ####### 44.2 Cable-to-Surface Non-ESP Gauges The cable-to-surface gauges use a permanent downhole monitoring cable from downhole gauge to surface data acquisition as means of communication and power. The CTS gauges are typically used for non-ESP applications (i.e., PCP, Beam Pump, Gas Lift and Jet Pumps) but can also be used for ESP applications. ######## 44.2.1 Phoenix CTS Gauges The Phoenix Select CTS and Phoenix CTS6000 gauges are a more cost effective, compact, and durable gauges for non-ESP applications. Applications include PCP, Beam Pump, Jet Pump, Gas Lift and reservoir pressure monitoring. The gauges support either one or two pressures depending on the application requirements along with downhole temperature and three axis of vibration. The suite of gauges is suitable for casing sizes from 5.5 in. and larger, and is either mounted using a ported coupling for access to the tubing pressure or simply clamped to the tubing for annulus. **Cable** **Gauge** Gauge Protector **Ported Couplin g** **Figure 8-4: Phoenix CTS Gauge Downhole System** On surface the Phoenix Interface Card (PIC) is installed in on of the slots of Instruct/Uniconn Controller. Other type of data acquisition is the Soloconn. The Gauge accessories (wellhead connectors/wellhead outlet, junction box, cable connection and surface cable) are also required as part of the gauge monitoring system. ######## 44.2.2 Hotline CTS Gauges This monitoring system can be offered for high temperature/high pressure applications of PCP, Beam Pump, Gas Lift and Jet Pumps applications. The Hotline CTS system can also be used with ESP system in specific applications if required. The Hotline CTS gauges includes two optional versions of transducers, the Sapphire or Paine sensors. The temperature ranges of these gauges range up to 220degC and 250degC respectively. This gauge provides a Single Pressure and Temperature. On surface the Extreme Interface Card is installed in combination with Instruct/Uniconn Controller. The gauge accessories (Well head connectors/Wellhead Outlet, Junction box, Cable connection to gauge consumables and surface cable) are also required as part of the gauge monitoring system. The gauge uses a ported coupling for annular or tubing pressure measurement. Additionally, it uses a Gauge Clamp for protection of the gauge. Autoclave collar Autoclave inverted nut Sensor adapter Test port Housing Shim Cable head **Figure 8-5: Hotline CTS Gauges** ###### 45 Surface Data Acquisition System The surface data acquisition systems are data gathering and control platforms with designed flexibility to operate with motor control systems, downhole tool systems, SCADA and communication systems (i.e., LiftWatcher, LiftIQ), etc. This provides an integrated device for acquisition, viewing and storage for AL acquisition data for Schlumberger family of downhole tools (DHT). Always refer to gauge Manual for compatibility with Surface Data Acquisition System. There are currently three surface data acquisition system: - Instruct or UniConn (Controller): This is a data acquisition which use a combination of the controller platform and either the Phoenix Interface Card (PIC) for Phoenix Gauges, or Hotline Extreme Interface Card for Hotline Gauges. The Instructor or UniConn can be set to operate as a ESP protection and data gathering system or a standalone data gathering system. UniConn was obsoleted back in 2017, however still there is a large inventory of use specially where old drives are installed. The actual technology is the Instruct Controller - ARConn: This is a standalone data gathering system which can monitor up to 16 interface cards. Currently, the ARConn is only compatible with the Phoenix Interface Card (PIC). This Unit became Obsolete in 2019 and Instruct is the primary option supporting up to four interface cards maximum. - SoloConn: The SoloConn is a standalone data gathering system which can monitor a single interface card. Currently, the SoloConn is only compatible with a modified version of the Phoenix Interface Card (PIC). The PIC transfers information onto the controller display or PC via StarView. Data is also available through an extensive Modbus telemetry map for SCADA, LiftWatcher or LiftIQ applications. The PIC is designed to operate with the gauge telemetry equipment using current loop control. The PIC is capable of adjusting the output power to counteract the effects of long cable runs. The power is controlled for optimum tool operation. **Note** Always verify the firmware version of Surface Panel and/or Interface Card. Not all firmware versions work with all of the different tools. Refer to the Gauge Manuals and contact InTouch as required. *8.4.1* **Phoenix Surface Chokes** A Phoenix surface choke provides a safe electrical link between the low voltage digital systems and the high voltage motor power system for the connection to the standard ESP gauge. The surface choke assembly is used to isolate the surface controller from the high-voltage AC on the ESP cable, but allows the DC signals to and from the controller to pass freely. This enables communication with the downhole tool without high voltages present on the controller. In high AC noise conditions, the gauge telemetry may be difficult to detect at the surface. A noise filter is installed in all 3-phase choke and 1-phase chokes to prevent data loss. This filters out the noise, improving telemetry detection and data quality. With less noise on the telemetry, the chance of erratic data spikes and frozen gauge parameters is greatly reduced. **Figure 8-6: 5kV Three-phase choke and Surface Controller** **Figure 8-7: 1kV Single-phase choke and Surface Controller** Refer to Phoenix Surface Choke reference Page [(InTouch ID 6903791)](http:\www.intouchsupport.com\index.cfm?event=content.preview&contentid=%2A6903791%2A) for details. ###### 46 Monitoring Guidelines The following table lists different guidelines on how the data could be used for alarming and trip the ALS equipment. **Table 8-1: Monitoring Alarm Configuration for Protection** | Phoenix Warning measurements in ESP Applications | Phoenix Warning measurements in ESP Applications | |----------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Measurements | Application | | Current leakage | Alarm protects electrcial system from deterioration from high pump heat, breakdown of winding insulation, and phase to ground insulation loss. | | Discharge Pressure | High-Pressure alarm and trip protect the pump from closed-valve shut-ins and heavy fluid slugs. | | Discharge temperature | High-Temperature alarm and trip protect the pump from overheating. Protects the MLE and avoid damage in the cable due to high temperature | | Intake Pressure | Low Pressure alarmand trip protect the pump from low fluid level, pump-off due to blocked intakes, gas locking, etc. High Intake Pressure could alert in recirculation and in no flow conditions. | | Phoenix Warning measurements in ESP Applications | Phoenix Warning measurements in ESP Applications | |--------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Intake Temperature | High-temperature alarm and trip protect pump from high temperature intake re-circulation and elevated production fluid temperature. | | Motor Temperature | High-temperature alarm and trip protect motor from low flow conditions, high motor load, and poor cooling because of scale, or poor cooling due to fluid propierties. Sometimes low fluid velocity around the motor | | Motor and Pump Vibration | Vibration alarm protects pump from mechanical damage from high solids production and excessive mechanical wear resonance frequency. | | Pressure Differential | Low or high pressure alarm and trip protect the pump from upthrust in high-flow conditions and downthrust in low flow conditions | | Phoenix Warning measurements in PCP Applications | Phoenix Warning measurements in PCP Applications | | Measurements | Application | | Discharge Pressure | High pressure trip protects the pump from closed-valve pressure buildups and accidental shut-ins. | | Pressure Differential | High pressure alarm and trip protect the pump from running out of head range | | Intake Pressure | Low pressure alarm and trip protect the pump from low fluid level, pump-off and damage from high gas volumes. | | Temperature Protection | High temperature trip protects pump from high temperature conditions. | | Pump Vibration | Vibration alarm protects pump from mechanical damage from high-solids production and excessive stator wear and resonance frequency. | | Phoenix Warning measurements in Beam Pump Applications | Phoenix Warning measurements in Beam Pump Applications | | Measurements | Application | | Intake Pressure | Low pressure alarm and trip protect the pump from low fluid level, pump-off, and damage from high gas volume. | | Pump Vibration | Vibration alarm protects pump from mechanical damage from high-solids production and excessive mechanical wear and pounding. | | Phoenix Warning measurements in Gas Lift Applications | Phoenix Warning measurements in Gas Lift Applications | |---------------------------------------------------------|--------------------------------------------------------------------------------------------------------------| | Measurements | Application | | Annulus Pressure | Sensor system automatically detect and warns of injection pressure change and pressure instability downhole. | | Tubing Pressure | System warns of increasing weight in the tubing column from poor injection or increasing water cut. | ###### 47 Monitoring Parameters **Figure 8-8: Monitoring System Parameters** The ALS Gauge Portfolio is available at [www.slb.com](https:\www.slb.com\completions\artificial-lift\electrical-submersible-pumps\gauges) . Refer to [https://www.slb.com/completions/](https:\www.slb.com\completions\artificial-lift\electrical-submersible-pumps\gauges) [artificial-lift/electrical-submersible-pumps/gauges](https:\www.slb.com\completions\artificial-lift\electrical-submersible-pumps\gauges) . ##### Surface Electrical Equipment | A.1 Gather the Data and Specifications | A-1 | |--------------------------------------------------------------------------|-------| | A.2 Introduction | A-1 | | A.3 Transformers | A-1 | | A.3.1 Transformer Principals | A-2 | | A.4 Switchboards | A-4 | | A.5 Transient Voltage Surge Suppressor | A-5 | | A.6 VSD | A-5 | | A.6.1 Harmonics | A-11 | | A.6.2 Sine Wave Producing Filters for Schlumberger Variable Speed Drives | A-12 | | A.6.2.1 References: | A-12 | | A.6.3 When to use a DC Link Reactor Option on Schlumberger VSDs | A-13 | | A.6.4 VSD Sizing | A-13 | | A.6.4.1 Selecting the correct VSD | A-13 | | A.6.4.2 Calculating the correct equipment sizes for a low voltage VSD | | | system | A-15 | | A.6.4.3 Packaging | A-17 | | A.6.4.4 TVSS | A-17 | | A.6.4.5 Junction box | A-18 | | A.6.4.6 Space heater with thermostat | A-18 | | A.6.4.7 Recording ammeter | A-18 | | A.7 Controllers | A-18 | | A.8 Site Communications Box | A-20 | | A.9 Junction box and Wellhead | A-21 | | A.10 Soft Starters | A-21 | | A.10.1 Soft Starting Electrical Submergible Pumps (ESPs) | A-21 | | A.10.2 Starting on a VSD | A-23 | | A.10.3 Starting on a Reduced Voltage Soft Starter | A-23 | | A.10.4 When to use a Soft starter | A-24 | | A.10.5 When the use of the Soft Starter is not Required | A-24 | | A.11 Generators | A-24 | | A.11.1 Rules for Sizing Generators that Operate VSDs | A-25 | | A.11.2 Rules for Applying Generators to VSDs | A-25 | | A.12 Surface Cable | A-25 | | A.12.1 Conduit | A-25 | | A.12.1.1 Cable Tray | A-26 | | A.12.1.2 Liquid Tight Flexible Metal Conduit | A-27 | | A.13 Conductors | A-27 | | A.13.1 General Conductor Information | A-43 | | A.13.2 Motor Conductors | A-43 | | A.13.3 Transformer Conductors | A-44 | | A.13.4 Capacitor Conductors | A-44 | | A.14 Terminology | A-44 | | A.15 Surveillance and Optimization | A-46 | | A.15.1 ESP Surveillance Guidelines for an Application Engineer | A-46 | | A.15.1.1 Introduction | A-46 | | A.15.1.2 General surveillance issues | A-46 | | A.15.1.3 Current/Amperage (primary switchboard or VSD surveillance) | A-49 | | A.15.1.4 Other motor controller data for potential surveillance | A-53 | | A.15.1.5 Surface measurements | A-54 | | A.15.1.6 Downhole ESP monitor | A-55 | | A.15.1.7 Permanent gauge (ESP independent gauge) | A-56 | | A.15.1.8 How to choose an appropriate alarm or trip value | A-57 | *A* **Surface Electrical Equipment** ###### 48 Gather the Data and Specifications Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 49 Introduction The downhole motor requires a supply of energy in the form of electricity at a required voltage and amperage to operate per the application design. The surface equipment, switchboard or variable speed drive, transformers, and surface wiring must be appropriate to supply this electrical energy. Other considerations for the surface equipment involve the environment that it will be exposed to and primary power at the well site, which is usually high voltage (such as 7200, 12470, 14400, 24950) or low voltage (such as 380, 440, 460, 480). A constant frequency of either 50 or 60 Hz is provided which depends on the country. The primary power source plus the surface equipment must supply the motor with three-phase power and the required surface voltage for the application. If the motor receives the needed voltage then the needed amperage will also be supplied to it and the best efficiency will be achieved for it. *Surface Voltage = Motor Voltage + Cable Voltage Drop* Schlumberger’s line of surface equipment has been undergoing considerable change in the past two years. Although Schlumberger must support the old equipment, this manual is mainly focused on the new equipment. Material for the older equipment will be available on [InTouchSupport.com](http:\intouchsupport.com) as these will have to be supported in the field for years to come. Also the UniConn Controller can be retrofitted on many Variable Speed Drives. There is a comparison of induction motor starting methods in [InTouch Content ID 3999366](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3999366) . ###### 50 Transformers A transformer may be required to provide the proper voltage at the motor. A low voltage power supply may require transformers be installed that will increase the primary voltage to match the surface voltage needs. Transformers are predominately sized by kVA (Kilo-Volt-Ampere). The calculated kVA value must not exceed the transformer’s rating. Three single-phase transformers have a total kVA rating of the sum of their individual ratings. Step Down Transformer When high voltage power is supplied, a step-down transformer is required for supplying the proper voltage to the motor. Overloading of transformers is not advised and special ratings are required for desert applications. Offshore applications may require special non-flammable oil to meet Class 1 Division 2 requirements for transformers. Dry type transformers are sometimes used in offshore applications. Step Up Transformer Low voltage power requires transformers that will increase the primary voltage to match the surface voltage requirement. This may occur if the primary power is low voltage (480) and the control panel is also low voltage but the required motor voltage is higher. In this case a step up transformer may be placed between the control panel and the downhole motor. In the case of a variable speed controller, the input and output to the controller is low voltage (480 volts, for example) and a step up transformer is used between the controller and motor to bring the voltage up to that required by the motor. Overloading transformers is not advised and special ratings are required for desert applications. Offshore applications may require special non-flammable oil to meet Class 1 Division 1 or 2 requirements for transformers. Dry type transformers are sometimes used in offshore applications. ####### 50.1 Transformer Principals - If "WYE-phase" connected the winding voltage is equal to the phase-phase voltage divided by 1.73 - If "WYE-phase" connected the output voltage is equal to the phase-phase voltage x 1.73 - If Delta connected the winding voltage is equal to the phase-phase voltage - When a transformer is fully loaded according to the kVA rating the difference between no-load voltage and loaded voltage can be quite significant due to impedance losses. - Ensure the primary voltage does not exceed the winding voltage rating. - Make sure output voltage is compatible with required surface voltage. - Exposed or Covered bushings - Special purpose transformers are used on VSD applications. They contain more iron required for developing more flux at lower frequencies. - 50 cycle rated transformers can be used on 60 cycle systems but a 60 cycle transformer operating on a 50 cycle system needs to be derated. There are three major sources of heat in the transformer. - Core losses - Harmonic losses - Copper losses **Core Losses** The core losses are determined by the Volts/Hz ratio at the primary and the frequency of operation. They are not influenced by the load. **Harmonic Losses** The harmonic losses are determined by the tuning of the downhole system and the VSD carrier frequency. Harmonic losses are influenced by the load. **Copper Losses** Copper losses are load dependent. They vary as the square of the load current. The standard transformer rating is based on a 30 degC 24 hour average ambient with a 65 degC rise. If the ambient is above 30 degC, the transformer is typically derated 1.5% per degC above 30. The transformer winding is rated at 105 degC. The top oil temperature will be about 10 degC lower than the winding. If you ever see a top oil temperature of 95 degC, it means you are right on the limit of the winding temperature rating. As long as the top oil temperature is below 85 degC, there are typically no corrective action required. **Note** Refer to transformer manufacturer's specifications for rating of the units. **Example** There have been several episodes of REDA system installations where the selected surface equipment comprising of SS2K VSDs, VSD rated step up transformers and R992 capacitive filters were not compatible. The harmonic currents between the VSD and the filter were excessive, causing the VSD to trip off on over current or overheating in the transformers.. In order to make the system operate the filter had to be removed. The drawback to this solution is the excessive voltage overshoots that occur in the unfiltered system. When the capacitors are appropriately sized to give a filter roll off frequency below 1000 Hz and the VSD carrier frequency is 2200 Hz, the predominant factor that determines the harmonic currents into the filter is the transformer impedance. A recommendation from Engineering that the transformer impedance be at least 3.5%. The majority of Southwest transformers have an impedance greater than 3.5%. **Note** A 60 Hz VSD input transformer can be operated at 50 Hz as long as you reduce the input voltage, output voltage and kVA rating are all reduced by the ratio of 50/60. A transformer designed for 480 volt 60 Hz operation will saturate and overheat if operated at 480 volts 50 Hz. For information relating to Phase Shifting Transformers (12-pulse) for VSDs see [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3294846) [3294846](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3294846) . For a list of common Southwest Transformers, drawings and nameplates refer to [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3315064) [3315064](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3315064) . **Note** A 1996 ESP Workshop Paper “Power System Design Considerations When Applying Variable Frequency Drives” can be found in [InTouch Content ID 3316792](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3316792) . ###### 51 Switchboards All applications, except where Variable Speed Drives are used, will require a switchboard, also sometimes referred to as a control panel or Fixed Speed Drive. Switchboards provide four basic functions: - Switchgear to start and stop the motor - Current overload and underload motor shutdown protection - Current monitoring for predicting downhole conditions - Transient surge protection. High voltage applications require the switchboard to be on the secondary side of the step-down transformer with a rating that meets or exceeds the calculated surface voltage and amperage required by the motor. Switchboards have traditionally come in two types: - Electromechanical - Solid state. The electromechanical switchboard provides a manual disconnect switch, magnetically operated motor controller, magnetic-oil dashpot overcurrent relays, and undercurrent relay for pump off and gas lock protection. A recording ammeter with a mechanical lock records running time, downtime and amount of current being used during operation. A solid state controlled switchboard provides a greater level of protective functions plus selected operating parameters and status indicators. There are various optional accessory packages that can be included with a switchboard. Switchboards are sized based on ratings: - Maximum Voltage - Maximum Amp Load Schlumberger now markets the FixStar switchboard with a UniConn controller. The datasheets for both and a datasheet for the StarView software for the Uniconn can be found in [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4169656) [4169656](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4169656) . The FixStar specification document can be found in [InTouch Content ID 4143925](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4143925) . The FixStar Operations Manual is in [InTouch Content ID 4128912](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4128912) . The software StarView is used to control UniConn. See [InTouch Content ID 3378105](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3378105) . ###### 52 Transient Voltage Surge Suppressor Schlumberger utilizes the StarShield Transient Voltage Surge Suppressor (TVSS). The business plan and some comparative information on TVSS can be found on [InTouch Content ID 4133713](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4133713) . **When Should A TVSS be Used in a System?** A TVSS is used to protect against lightning strikes, power line surges, and other transients that may be present on the system. The TVSS achieves this by providing voltage suppression when over voltage conditions appear on an electrical system. There are two main causes of over voltages: voltage spikes and systems transients. These over voltages could cause the immediate loss of equipment and/or reduce the reliability (MTBF-mean time before failures) of equipment; therefore, a TVSS should be installed into a system whenever there is the chance that over voltages may occur. In some cases, a power system study may be required to determine whether the use of a TVSS is warranted. Proper selection should be the result of a thorough diagnostic evaluation of the customer systems and environment. Schlumberger-EPC-Power Systems Group offers diagnostic expertise. There is a comparison of induction motor starting methods in [InTouch Content ID 3999366](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3999366) . **Over Voltages - What Causes Them and What are They?** The causes of over voltages can be grouped into four categories: - *Lightning* – a natural phenomenon that produces severe and/or destructive levels of over voltage. - *Local Electrical Utilities* – can introduce transients and over voltages depending on the quality of the utility service. - *Inhouse systems* – Electrical equipment that introduces over voltages due to the operation of equipment (e.g. Variable Speed Drives, rectifiers, etc.). - *Adjacent facilities* – Introduction of the over voltages may be caused by equipment in an adjacent facility down stream. ###### 53 VSD A VSD: - Provides constant torque through the entire speed range - Can be used manually to set the V/Hz ratio for specific applications (base speed) - Provides reduced starting capabilities (soft start) - Optimizes the output of the well (avoids cycling of the well and equipment) - The VSD controls the output Voltage and Frequency to the motor by: - Changing the input AC signal to DC signal, - Chopping the resulting DC signal, and finally, - Varying the output voltage and frequency to the motor. - By varying the voltage and frequency to the motor, we are changing what is called the V/Hz ratio. As the frequency increases, so does the motor speed as well as its horsepower capability. The increased speed causes the pump to put out more head and flow and, in an effort to obey the laws of physics, the brake horsepower required to do this task also increases. We can predict the change in pump performance with affinity laws. Sizing a VSD application is then a matter of matching the pump and motor at the speed of interest. In a VSD application, we try to match the pump performance curve to the well system curve and where they meet is where the well should produce. The unit will operate where the pump and motor torques are equal. ######## Useful Equations If we know the pump performance at 60 Hz, we can correct it to another frequency by the affinity laws: *FlowHZ HeadHZ* **Equation A-1:** (  ### HZ ( *Flow* 60 *X* 60  *HZ* 2 ( *Head* 60 *X* 60 *BHPHZ*  *BHP* 60 *X* *HZ* 3 ## 60 ## If we know the motor 60 Hz nameplate rating, we can calculate the output horsepower rating at any other frequency with Equation 1. ### MHP  MHP X (HZ *HZ* 60 60 (1) If we prefer to work with 50 Hz as a base, we can substitute in 50 in place of 60 everywhere it appears in the equations. If we know the pump bhp at 60 Hz and we know what is the maximum frequency we desire to run at, we can determine the minimum permissible 60 Hz motor hp rating as: Hz 60 2 ######### MHP60 = BHP x 60 MHP60 BHP60 If we know the pump bhp at 60 Hz and we know what our motor size is at 60 Hz, we can calculate the maximum allowable frequency before overloading the motor as: ## HZ=60 X If we know the voltage at 60 Hz, we can calculate it at another frequency as: ( ## HZ Volts = Volts60 X 60 If we know the pump bhp at 60 Hz and the motor rated hp at 60 Hz, we can determine the motor load at any frequency as: ######### % Load = BHP 60 X MHP60 ######### HZ 2 ( 60 At any frequency, if we know the volts and amps, we can calculate the kVA as: ## KVA = Volts x Amps x 1.732 1000 If we know the drive kVA rating at one input voltage, we can convert it to another input voltage as: ######### Drive Output KVA = KVA x V in 480 ######### 480V ######### Same will apply for any frequency. VSD kVA at the base frequency are rated kVA, we can then calculate it for another frequency as: #### Drive Output KVA= KVA x HZ #### Base F #### Base f #### If we know the pump shaft hp rating at 60 Hz, we can convert it to another frequency as: ## SHP Limit =SPH Limit x HZ HZ 60 60 SPH60 BPH60 If we know the pump shaft hp rating at 60 Hz and the pump bhp requirement at 60 Hz, we can determine the maximum frequency allowable before we exceed the shaft capability as: ## HZ = 60 x ## The VSD will give us a big advantage in increasing our pump performance envelope. For example, given a well system curve that looks something like this, which corresponds to some static pressure and PI. If one raises the static pressure, intuitively one would expect the well system curve to drop. If one reduces the PI, the curve will be steeper. Raising the static pressure and lowering the PI one might have these possible curves but one design rate required. The object is to size one equipment string for worst and best situation. See below for an example. **VSD Applications** | Parameter: | Direction: | Effect: | |---------------------------|--------------|--------------------------------------------------| | Productivity Index | Raising | Shifts system curve down and flattens it out | | | | (more flow). | | Wellhead Pressure | Lowering | Lowers system curve down (more flow). | | Static Reservoir Pressure | Raising | Lowers system curve down (more flow). | | Water Cut | Raising | Shifts curve up and increases slope (less flow). | | GOR | Raising | Lowers and flattens curve (more flow). | | Tubing Size | Lowering | Shifts curve up and increases slope (less | | | | flow). | | Viscosity | Increasing | Shifts upwards + affects pump head and | | | | rate | ####### 53.1 Harmonics The voltage total harmonic distortions (VTHD) are significantly affected by the drive input impedance at the input of multiple pulse VSDs. However, the current total harmonic distortions (ITHD) varied considerable with the loading factor since the ITHD value is determined based on the harmonics in percent of the fundamental. Once the load factor is assumed to be fixed, the ITHD values become almost constant with a little variation for different VFD input impedances. Reference [InTouch Content ID 4021305](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4021305) ####### 53.2 Sine Wave Producing Filters for Schlumberger Variable Speed Drives This note is issued to provide an overview of the recent studies performed by Schlumberger and Toshiba on the application of sine wave producing filters to the SpeedStar range of Variable Speed Drives (VSDs) and to provide a simple guideline to their use to mitigate ESP System Failures and increase Total ESP System integrity. Schlumberger effectively opened the book on recognizing the true effect of voltage stresses on ESP System components in the groundbreaking paper presented to the SPE ESP Workshop in 1999, “Voltage Stresses in Electrical Submergible Pumps Operated by Variable Speed Drives”. The remit of this paper was to investigate the voltage stresses in ESP Systems that are now recognized to be very different from those in surface motor applications. The paper explored the cause and effect of the voltage stresses in Pulse Width Modulated (PWM) VSDs of the type used by Schlumberger and compared field measurements to computer models in order to investigate ways of reducing these stresses to non-invasive levels. **The Paper Concluded** “With proper application of a SWD with a step up transformer on 6000 ft ” long cables, it has been demonstrated that system efficiency at the motor shaft will approach 86% which is surprisingly only 8.6% lower than a surface application of motor and drive. Results of this testing show the sine wave output of a drive provides many application benefits: - Voltage stresses are reduced, which should result in increased reliability of cables, penetrators, transformers and motor insulation - Improved efficiency reduces energy costs - Magnetic noise reduction in transformers - Lower losses will reduce temperature rise of components especially transformers. Referenced [InTouch Content ID 3956699](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3956699) . A SpeedStar SWD should be selected at all times for ESP control, except under the following conditions: - System kVA less than 200 kVA - Cable length less than 100 Meters (~328 Feet). - All HPS Systems *A.6.2.1* **References:** “Voltage Stresses in Electrical Submergible Pumps Operated by Variable Speed Drives” Bill Pelton - SLB, Kurt LeDoux - TIC, Don Kelly- ACA Presented at the SPE ESP Workshop, 1999 [InTouch Content ID 3011208.](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3011208) “Performance Testing of a Sine Wave VSD on Submersible Pump Applications” Bill Pelton - SLB, Kurt LeDoux - TIC, Richard Bristow -SLB Presented at the SPE ESP Workshop, 2002 [InTouch Content ID 3316353.](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3316353) [InTouch Content ID 4025075](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4025075) contains an MS Word template that can be filled out and supplied to EPC when an analysis is needed on an ESP system where there are starting problems and downhole electrical harmonic problems are suspected causing overcurrent starts in VSDs. These problems exist when PWM VSDs are used such as the SS2K and SS2K+ and NOT SWD units. The R992 Load Filter Datasheet is on [InTouch Content ID 3912024](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3912024) . ####### 53.3 When to use a DC Link Reactor Option on Schlumberger VSDs In the typical land based REDA system application there is a dedicated transformer between the VSD and the power system that provides all of the impedance needed, so use of the DC link reactor option would serve no useful purpose. Reference [InTouch Content ID 2049809](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2049809) . For any EPC warranty documents and any older VSD information search the InTouch Reference pages. For Phoenix Surface Equipment information see the [InTouch Reference Page 3995504](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3995504) . Refer to Section for Transformer information and to Section for Generators information also. ESP Papers in [InTouch Content ID 3002698](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3002698) (The Effect of VSD Modulation Schemes on Motors Including Heat Rise and Vibration Data), [InTouch Content ID 3316792](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3316792) (Power System Design Considerations When Applying Variable Frequency Drives), [InTouch Content ID 3316353](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3316353) (Performance Testing of a Sine Wave VSDs on Submersible Pump Applications), and [InTouch](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3011208) [Content ID 3011208](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3011208) (Voltage Stresses in Electric Submergible Pumps Operated by VSDs) are valuable sources of information also. Besides the DesignPro software there is a spreadsheet to assist with VSD setup in [InTouch Content](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2062717) [ID 2062717](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=2062717) . ####### 53.4 VSD Sizing ######## 53.4.1 Selecting the correct VSD To select the proper VSD system for each application, the following points need to be considered, regardless whether low or medium voltage systems are in use - Ensure that the system can be powered up by the power at a wellsite, and meets customer- specified input harmonics requirements (if exist). - For low voltage VSD system, unless the power available is 380/480 V, the use of a step-down transformer becomes mandatory. Select a unit that ∗ has a VSD-rated transformer (has more iron core compared to standard transformers to handle the input harmonics of a VSD) ∗ has a kVA rating that meets or exceeds the surface kVA power requirement- calculation will be detailed later on. ∗ has the correct input and output voltage tap ratings and settings. ∗ If the VSD is a 12-pulse system and 12-pulse input harmonics level is required, then the transformer should also be a phase-shifter. ∗ If a series harmonic filter is to be utilized, then it must be installed between the step-down transformer and the VSD. – For SpeedStar MVD ensure that the drive has the input voltage rating that matches the input voltage and frequency available at wellsite. - Check whether load filter is required or not, if the system is used to power an ESP system or the VSD is used which then has an PWM output (SS2K+ or Varistar-PWM). This can be done by performing either load harmonics analysis or resonance sweep using R991 resonance analyzer. If resonance occurs, then the R992 needs to be utilized. - Ensure the drive (system) has the proper enclosure rating for its intended installation location: - A NEMA-3/R rated enclosure may be installed outdoor on land. - A NEMA-4/X rated enclosure must be used for outdoor offshore installation. - For installation in a hazardous zone, the overall system must be fully enclosed in a package that utilizes explosion-proof rated air-conditioning system. - Select a drive system that can supply the required output (surface) voltage: - A NEMA-1 rated enclosure may only be installed indoor, with an assisted weather regulation system (such as air-conditioning) - For low voltage VSD system see calculation method and influencing factors in [A.6.4.2:](.) . Select a unit that ∗ has a VSD-rated transformer (has more iron core compared to standard transformers to handle the harmonics output by the VSD) ∗ has the required surface voltage between its minimum and output voltage range ∗ has a kVA rating that meets or exceeds the surface kVA power requirement of the pump. - For SpeedStar MVD ensure that the required surface voltage does not exceed the maximum voltage that can be MVD's output. - has the sufficient number of analog and digital inputs and outputs to connect all the required instrumentations at the wellsite. - has the control algorithm required, such as maintaining constant pump intake pressure, speed follower mode, etc. - has the required interfaces to connect it to the remote monitoring and control system(s) used (if it exists). **Example** The CE certification is mandatory for any countries which is an EU member. So installing a SpeedStar SWD in Germany would require the addition of the EMC filter at its input to comply with CE certification. **Note** The selection logic and algorithm has been implemented in DesignPro since version 2.0. **Note** - A VSD’s output rating is determined primarily by its output current rating, its kVA rating is derived by multiplying its output current rating by its rated output voltage. - Historically REDA (Schlumberger) VSDs have been sized based on kVA. This approach might work with low voltage VSDs, since in most cases the step-up transformer used with a VSD has a wide range output voltage taps available, which can be used to make sure the drive output current still falls within the drive rating. - However, this is not the case with MVD. **Example** An application requiring 128 A motor current and 3,420 V surface voltage means that the required surface kVA required is 758.2 kVA. However, this does not mean that a 4,160 V, 124 A NEMA-1 MVD (893 kVA rated) can be used for this application, since it can only output 124 A. To power up this application, the next bigger size is required 155 A rated output current unit ######## 53.4.2 Calculating the correct equipment sizes for a low voltage VSD system Refer to the following requirements for equipment size calculation: - Calculate surface voltage, motor running current and surface kVA consumption (at junction box). - Calculate the ambient temperature at wellsite, if installed outdoor (annual average, high point and how long it exists on annual basis). - Calculate altitude of the installation location (above sea level). - Calculate carrier frequency of the VSD. - Analyze quality of the power system stiff or weak. - Analyze type of pump connected (ESP, PCP or HPS). - Observe whether a load filter is utilized or not. - Analyze frequency of power supply (50/60 Hz) and the frequency rating of the transformers (50/ 60 Hz). - Run frequency and base frequency. Calculations to be done: - Use the VSD’s voltage and kVA ratings that fit the input voltage of the drive, but not the power supply frequency. - 50 Hz rated transformers retain their voltage and kVA ratings when used with 60 Hz supply; however, the kVA and voltage ratings of 60 Hz units used with 50 Hz supply must be multiplied by 5/6 (0.833). See [InTouch Content ID 3892618](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3892618) for further details. - *VSD output voltage at run frequency would be the input voltage multiplied by run frequency divided by base frequency.* - *VSD output kVA capacity available would be its kVA rating at the power supply frequency multiplied by run frequency divided by base frequency.* **Note** In a real application, run frequency would always be less or equal to the base frequency. - The kVA rating for the step-up transformer should at least be equal to the required surface kVA divided by 0.97 (3% power loss in the transformer) and by the derating factor for altitude: *1 - { [(Altitude - 3300) / 330 ] x 0.004* }. Altitude must be in feet only if altitude exceeds 3,300 ft above MSL. - The required output current rating of the VSD should be equal or exceed maximum required motor running current multiplied by output voltage rating at the tap setting, divided by the input voltage rating. If these are unknown yet, they can be substituted by surface voltage divided by VSD output frequency (at the running frequency). This should then be divided by the following derating factors: - Weak power quality is 0.95 (5% derating factor) - Drive carrier frequency is 0.86% (14% derating factor) with 3 kHz carrier frequency; 0.73 (27% derating factor) with 4 kHz carrier frequency. - Application derating factor is 0.95 (5% derating factor) for ESP without the use of load filter, or - Power loss in step-up transformer is .97 (3% derating factor) 0.8 (20% derating factor) for PCP. - Altitude derating factor as defined for SpeedStar MVD above. - Temperature derating factor as defined for SpeedStar MVD above (for NEMA-3/R units only). **Note** With the SWD and Varistar SWD, the carrier frequency is locked at 2.2 kHz to ensure the sinewave output filter works as intended. - The drive’s kVA rating required should be equal or greater than surface kVA requirement divided by all the relevant multipliers above, and then divided by 0.98 (2% derating factor) to account power loss in the VSD. - The kVA rating for the step-down (phase-shift) transformer should at least equal the calculated minimum VSD kVA rating required (see point above), divided by 0.97 (3% power loss in the transformer) and by the derating factor for altitude as defined above for the step-up transformer. **Problem** Select the proper low and medium voltage VSD system for an ESP installation where the maximum motor running current would be 128 A and required surface voltage is 3,420 V. The well is located onshore with the ambient temperature of 100.4 degC, elevation of 150 ft above MSL. Power available at the wellsite is 6,000 V at 50 Hz, it is weak, and the customer requires that the system’s input harmonics comply with IEEE-519 standard. **Resolution** Low voltage system: - Surface kVA power requirement: *3,420 V x 128 A x 1.732/1,000 = 758.2 kVA* - Step-up transformer kVA rating = 758.2 kVA/0.97 = 782.7 kVA. So we can choose SWE 875 kVA step-up transformer with input voltage rating of 480 V and output voltage tap range of 1,400- 4,850 V. Output tap selected is 3 A, WYE is 3,435 V rated. - VSD uses a six-pulse, NEMA-3/R SpeedStar SWD, with the output current rating of *128 A x (3,435 V/480 V)/(0.97 x 0.95) = 994 A* (no application, altitude and temperature derating factors applicable, only step-up transformer loss (0.97) and weak power system (0.95). *VSD kVA rating required = 758.2/(0.97*0.95*0.98) = 839.5 kVA* , so we can use a sx-pulse, NEMA-3/R 40 degC (104 degF) rated 932 kVA, 1,122 A rated SpeedStar SWD. - A Lineator series harmonic filter with of 880 kVA, 50 Hz rating would be inserted between the step-down transformer and VSD input to achieve the required input harmonics level. - Step-down transformer requires a 6,000 V input/480 V output, 50Hz VSD rated unit, with kVA rating of 839.5kVA/0.97 = 865.5 kVA or larger (for example a 900 kVA unit would suffice). **Note** We still utilize the VSD kVA rating at 480 V since the output of the step-down transformer is 480 V but not 380/400 V, even with 50 Hz supply frequency. Medium voltage system: - Use a NEMA-3/R SpeedStar MVD with 186 A output current rating, with input transformer specified to handle 6,000 V, 50 Hz input voltage. - Minimal output current requirement = 128A/(0.95 x 0.98) = 137.5 A (weak power supply and internal losses derating factor only, no temperature and altitude deratings applicable). ######## 53.4.3 Packaging The SS2K VSD comes in two standard packages. - NEMA 3R for outdoor applications - NEMA 1 for indoor (control room) applications Custom skids designs are available through EPC for Desert and Arctic applications. ######## 53.4.4 TVSS The TVSS is not a Toshiba supplied option, but is considered mandatory for protection against surges such as lightning. All SpeedStar 2000 VSD’s are to be equipped with a TVSS unless the VSD is to be installed on a power system that already has surge protection. One TVSS unit is required for a 6-pulse VSD and two TVSS units are required on a 12-pulse VSD. Please reference [OneCAT](http:\www.wcp.oilfield.slb.com\cs\catalog) for TVSS part numbers. ######## 53.4.5 Junction box The junction box option provides added room for connecting incoming cables. This will add to the overall dimensions of the VSD. The Junction box includes connection terminals. ######## 53.4.6 Space heater with thermostat This option is provided when it is necessary to keep the ambient temperature in the VSD 5 degrees higher than the outside ambient to avoid condensation inside the VSD cabinet. ######## 53.4.7 Recording ammeter The same Bristol Recording Ammeter used on REDA switchboards is available for use on VSDs. ###### 54 Controllers Refer to UniConn Reference Page [InTouch Content ID 3985891](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3985891) . A UniConn Operation presentation is available on InTouch Content ID [4068121](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4068121) . The UniConn Technology Based Training is available on InTouch Content ID [3984569](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3984569) . Refer to UniConn Operations Manual [InTouch Content ID 3953183](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?method=iteview&caseid=3953183) . DescriptionP: hoenix Interface Card (PIC) Part Number: 100324335 Application: Enables communication with Phoenix downhole tool. DescriptionU: niConn - Universal Site Controller 100018805 Fixed speed controller and base unit for Variable Speed Drive and Reservoir Monitoring & Control applications. The UniConn also accepts analog and digital I/O. DescriptionI:solated RS-232/485 100228568 Communications Card Enables communication with SpeedStar 2000/SWD/Titan VSD control board, SCADA system and Site Communication Box (SCB); older versions are P/N 100069382 (non-isolated version) and 100169107 (isolated, RS232 only) DescriptionP: otential Multiple Numbers Transformer (PT) Three (Qty. 3) are required to provide 3-Phase voltage readings (including average & unbalance) on switchboards, or at the input (6- pulse only)/output of a VSD. Correct input fusing must be used. P/N 1157726-480V P/N 1157114-3600V/multi-tap P/N 2003957-5400V/multi-tap DescriptionA: 095 Backspin Shunt Detects motor back-spin, prevents motor startup under back-spin conditions, and detects leg ground faults. Part Numbers: 1157742: 400-1000VAC 1157734: 800-2000VAC 1157122:1800-4000VAC 7003619: 3000-5000VAC DescriptionC: urrent Transformer (CT) Module 10007203 One CT module is required to obtain 3- phase current reading (calculated average & calculated unbalance) on switchboard or VSD input/output. | DescriptionU: niConn Memory Module 32Mb | DescriptionU: niConn Memory Module 32Mb | |----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Part Number: | 100203033 | | Application: Removable storage media for the capture and trending of I/O values and historical data. The 32Mb module will store up to 500,000 data points. The 64Mb module (Part Number - 100247379) will store up to 1,000,000 data points. | Application: Removable storage media for the capture and trending of I/O values and historical data. The 32Mb module will store up to 500,000 data points. The 64Mb module (Part Number - 100247379) will store up to 1,000,000 data points. | **Figure A-1: UniConn Controller and Available Accessories Table A-1: UniConn Specifications** | Dimensional | Dimensions Box | 5.5 in. (139.7 mm) H x 8.3 in. (210.8 mm) W x 6 in. (152.4 mm) D | |--------------------|-------------------------|-------------------------------------------------------------------------------------------------------------------------------------------| | Dimensional | Dimensions Faceplate | 7.5 in. (190.5 mm) H x 10.5 in. (266.7 mm) W | | Dimensional | Mounting | Indoor use only. External applications must be mounted in NEMA 3R or NEMA 4X rated enclosure. | | Dimensional | Shipping Weight | 8 lbm (3.6 kg) | | Operating | Power Supply AC | 100-240 volts AC, 25 W, 50/60 Hz. Voltage fluctuations of +/- 10% of nominal voltage. Category II over-voltage (300 Vrms max. over-range) | | Operating | Power Supply AC typical | 100-240 volts AC, 2.25 W, 50/60 Hz | | Operating | Power Supply DC | 24 volts DC +/- 10% at 1 A | | Operating | Power Supply DC typical | 24 volts DC +/- 10% at 0.075 A, 1.8 W | | | Protection | Ingress protection rating of IP20 (no special protection) | |-------------------------|----------------------------------------|---------------------------------------------------------------------------------------------------------| | | Temperature Operating CE Compliant | –40 degF (-40 degC) to +131 degF (+55 degC) | | | Temperature Operating Absolute Maximum | –40 degF (-40 degC) to +167 degF (+75 degC) | | | Temperature Storage | –40 degF (-40 degC) to +185 degF (+85 degC) | | | Digital Outputs | 120 volts AC max., 8 A max. 10–28 volts DC, 8 A max. | | | Digital Inputs | 0–24 volts DC DC power provided on connector number 21 DIGITAL POWER | | | Analog Outputs | 0–20 mA in current sink mode. DC power provided on connector number 28 ANALOG PWR | | | Analog Inputs | 0–10 volts DC. 1% precision 0–20 mA, 26 mA over-range, 5% precision | | | Maintenance Port | RS232 (DCE) 8-N-1 | | | Expansion Chassis | 24 volts DC, 24 W max, all four cards combined. | | Operating Environ- ment | Humidity % (Percent) | Maximum relative humidity (RH) of 80% (non condensing) at 31 degC decreasing linearly to 50% at 40 degC | | Operating Environ- ment | Altitude (Meters) | 2000 m (6562 ft) | | Operating Environ- ment | Environmental Pollution Degree | Pollution degree 2 according To IEC/CSA /UL 61010-1 | | Operating Environ- ment | Installation | Non-hazardous locations | ###### 55 Site Communications Box The Site Communications Box (SCB) is the field equipment to enable Schlumberger controllers for espWatcher Monitoring System. The SCB-B and SCB-21X series equipment can be used anywhere in the World except North America. In North America, use the SCB-A, SCB-22X series field equipment. The SCB-23X, SCB-24X and SCB-3 series equipment can be used anywhere in the World. The SCB includes the Wireless Matrix Processor Assisted Connector (PAC) and the Nera World Communicator (NWC), a satellite modem that works with the Inmarsat-3 satellites to provide high- speed data service (MPDS). The SCB works in conjunction with InterACT Production, a web-based application, database, and message delivery center that allows viewing and control of the production environment from any Internet-enabled location. [InTouch Content ID 3833966](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3833966) has the installation and operation manual. ###### 56 Junction box and Wellhead The recommended distance between the junction box and the wellhead is at least 15 feet. The reason for having a 15 ft. minimum is to get the vent box out of the way when a workover rig moves in. The vented junction box has 2 functions, 1 to allow the cable coming from downhole to be connected to the surface cable close to the wellhead. The other is to allow any gas that may be moving up through the center of the cable to be vented. On an offshore rig or platform the entire area may be considered a hazardous area and if so an Explosion Proof J-Box must be used. Schlumberger can supply these boxes when needed. A relatively shallow, no-gas, low-gas, low temp, non-sour environment Submergible Pump installation would not require anything other than the “old standard” Huber-Hercules wellhead for cable pack-off. A deeper, more-gas, higher temperature installation would require the “mandrel-type” wellhead for better gas control and temperature containment. Submergible Well Installations inside the perimeter of Gasoline Plants, or in other like Hazardous locations would require the ESP Explosion Proof wellhead penetration systems, or another System which carries the proper approval. Sour environments would require wellheads of exotic materials in order to survive a reasonable length of time. **Note** Junction boxes are outside the CE directive and the certificate attached to [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4075784) [4075784](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4075784) can be used to demonstrate CE compliance (i.e., it cannot be CE Certified). ###### 57 Soft Starters ####### 57.1 Soft Starting Electrical Submergible Pumps (ESPs) [Figure A-2](.) , illustrates starting of an Electric Submergible Pump (ESP) across the line from a torque standpoint. **Figure A-2: Starting an ESP from a torque standpoint** The starting torque requirements of the pump (at zero speed) are not shown, but typically they are 30% of the running torque or less. Once the pump begins to turn, the torque drops almost to zero and then increases with the square of speed. Then the pump speed rapidly accelerates until stabilizing at the speed where the pump torque vs. speed curve intersects the motor torque vs. speed curve. The starting torque developed by the motor is typically 1.5 to 2.5 times the full load running torque at nameplate voltage, depending on the motor series. At 60 Hz the full load running torque is about 1.5 ft. lbs per horsepower. Typically, the starting torque developed by the motor greatly exceeds what is required to start the pump. The starting current experienced during an across the line start varies from 400% to 600% of the nameplate motor current, depending on the cable length and the power system impedance. It is related only to the nameplate current of the motor and not to which pump is connected to the motor. There are two reasons one might want to soft start an ESP. - Mechanical reasons - Electrical reasons The mechanical reason for wanting to soft start an ESP is in applications where the total motor horsepower is high relative to the horsepower rating of the motor, protector or pump shaft. The electrical reason for wanting to soft start an ESP is to eliminate the requirement for the power system to have to deliver the 400% to 600% starting current. There are two methods for soft starting an ESP. - Variable Speed Drive (VSD) - Reduced voltage soft starter ####### 57.2 Starting on a VSD The VSD starts the motor at a reduced frequency (10 Hz or less) and a reduced voltage. The starting current will vary with the VSD setup, but typically it would be about 150% of the motor nameplate current. It can be set up to be less if that is desired. It can be more if the VSD is oversized. The starting torque can be more or less than what can be achieved with an across the line starter, depending on the VSD setup. Once the pump begins to turn, the VSD is operating the motor in the stable low slip part of the motor speed vs. torque curve. Current requirements in this region of the curve are nameplate or less. ####### 57.3 Starting on a Reduced Voltage Soft Starter [Figure A-3](.) , illustrates starting on a reduced voltage soft starter from a torque standpoint. The pump speed vs. torque curve is the same, but now there is a family of curves for the motor, one for each voltage. Just as with the across the line start, most of the acceleration to running speed occurs in high slip (high current) regions of the motor curve. **Figure A-3: Starting on a Reduced Voltage Soft Starter** An experience in the mid 1980s proved that starting too softly on a reduced voltage soft starter could break the motor shaft. For that reason a rule was developed that the softest allowable start would result in 250% of motor nameplate current during the start. With application of that rule, the broken shaft problem disappeared. A 250% current draw at start is easier on the power system than 600% with an across the line start, but not as easy as the 150% that would be achieved with a VSD. As a result of the rule, the starting kVA of a fully loaded ESP motor will be at least 250% of the running kVA even though a Soft starter is employed. By comparison, the typical start on a switchboard will be 350% to 550% depending on the cable gauge, cable length and transformer impedance. Since there is so little to be gained, soft starters are rarely used on ESP oil well applications. The typical application of an ESP motor with a soft starter is in a high horsepower (600 Hp and up) shallow set (1000 to 2000 feet) mine dewatering application. **Below are some typical guidelines to follow on when to use and not use a Soft start on an ESP application.** ####### 57.4 When to use a Soft starter If any of the following conditions exist, use of a Soft starter should be examined further. - High horsepower in a shallow well (less than 2000 feet) - Motor horsepower rating exceeds 75% of the max shaft rating for the motor. (Protector shaft ratings and pump shaft ratings are assumed to be at least as big as the motor shaft rating.) - Pump shaft diameter is larger than motor shaft diameter - There is a deep-set packer that eliminates the mechanical Soft starting normally available from the tubing. - Operation directly from a 4160 volt grid with no transformer ####### 57.5 When the use of the Soft Starter is not Required The soft starter recommended for use with ESPs is the Southwest Reactor type. A documentation package can be found on InTouch by doing a search on "soft starter". Just be sure that the voltage and current rating of the soft starter selected exceed your requirements. ###### 58 Generators When using a generator with a switchboard, the generator kVA rating selected should be equal to or greater than the motor full load kVA plus any surface load kVA, transformer loss kVA and cable loss kVA. However, a generator that is capable of carrying the full load continuously will not necessarily supply the required kVA to start and accelerate the motor to full speed. Historically, rule of thumb multipliers were used on the motor horsepower rating to determine the generator kW rating required for motor starting. With the many generator manufacturers today providing different design characteristics, rules-of-thumb are no longer a reliable method for equipment sizing. The Generator manufacturer should be consulted for a recommendation, as generator selection needs to be based on its individual electrical characteristics. When using a Generator with an ESP a soft starter will not be needed as the generator will act like a Softstarter because of the internal electrical and transient reactance's that are inherent to generator designs. The generator has two impedance's or reactance's. One is "electrical" and the other is called "transient". The electrical reactance is same type of reactance that you will find in most power system circuits. The transient reactance is the amount of "sag" that the generator will have when a large load is placed on it. Of course when the generator detects this sag the voltage regulator will adjust the voltage to the field windings and raise the output voltage of the generator. ####### 58.1 Rules for Sizing Generators that Operate VSDs There are three basic rules: - Oversize the generator by 25 to 50% based on the load. The reason for oversizing the generator is to allow for harmonic heating in the generator. This rule assumes a 6 pulse VSD. - It is not necessary to oversize the engine. The harmonics that contribute to heating of the generator are largely reactive and do not contribute significantly to the load on the engine. Assuming a 90% efficient generator, the KW rating of the engine just needs to be about 10% larger than the KW load on the generator. - Do not use a generator that has a kVA rating that is less than the kVA rating of the VSD. The reason not to have a generator with a kVA rating less than the kVA rating of the VSD is to allow for the capacitor pre-charge current when the VSD is first connected to the generator. A 25% transient reactance is assumed for the generator. If the generator is too small, a large voltage drop will occur, which will cause the system to malfunction. ####### 58.2 Rules for Applying Generators to VSDs Two SS2K VSDs would behave the same as one VSD with a kVA rating that is the sum of the two, assuming that they are in reasonably close proximity. Feedback from one VSD will not cause the other VSD to malfunction. Feedback from the VSDs to the generator will cause it to malfunction if it is not properly sized and outfitted per the above discussions. ###### 59 Surface Cable The local electrical codes should always be followed when cabling to and from the equipment. Normally the National Electrical Code – 2005 (NEC) is followed here as a guideline. Where the NEC and local codes conflict the most stringent guidelines should be followed. **Example** If the NEC calls for a conductor that is sized for a 4/0 and the local code calls for 3/0 the larger 4/0 cable should be used as it’s the larger of the two cables. ####### 59.1 Conduit Several types of conduit may be used in the installation but choice of type should take into consideration the ambient conditions found on site. Areas where ruggedness is a factor should use Rigid metal conduit, EMT (Electrical Metallic Conduit / thin wall) conduit can be used but its not recommended as this type of conduit is subject to crushing at times. For areas where high humidity is a factor use Rigid PVC as its more capable withstanding corrosion but is more susceptible to impact damage as well as needs more support devices per foot of installation. Conduit should only be bent with an acceptable conduit-bending tool. Offsets should be constructed using 15 deg bends whenever possible. Bends of more than 30 deg should not be used as this may cause too much damage to the conduit or cabling that is to go inside of it. When using PVC it’s only recommended to use factory supplied preformed parts as bending can damage the PVC parts on this type of conduit. Conduits should be supported according to the applicable electrical code. Conduit may be installed directly onto solid surfaces or to mechanical supports installed for such purpose. Conduit entry into enclosures should be finished with either sealing washers or conduit hubs such as Thomas and Betts “Bullet” Hub Connectors, Die Cast Zinc Hub Connectors, or equivalent. **Note** Conduit entry using back to back lock washers is not acceptable as this leaves openings to allow for water entry into the enclosure. ######## 59.1.1 Cable Tray Cable trays carrying cables operating above 750 volts should have tray covers installed to prevent unauthorized contact with the cable. Barriers should be installed within cable trays to separate high voltage and low voltage conductors. Cables installed within cable trays should have a steel wire armor (served armoring) or interlocking armor (TECK/MC). [Figure A-4](.) shows the two main types of cables used for surface applications. **Figure A-4: TECK 90** ######## 59.1.2 Liquid Tight Flexible Metal Conduit As an option to running rigid conduit for control circuit runs, Liquid tight flexible metal conduit (LTFMC) may be used. Extremely long runs of LTFMC are generally not approved by electrical inspectors. For installations requiring lengths in excess of 8 ft (2.5 m) armored cable is the better choice. ###### 60 Conductors This section covers the use of two types of conductors, wire and cable. Conductor ampacities are found in [Table A-2](.) . When choosing conductors amperage, ambient temperature, and number of conductors must be taken into consideration. There is also a safety margin of 125% that is taken into account that covers issues with harmonic heating, sun loading, motor starting, etc. This margin is typically 125% of the cable rating. This margin is already added to the tables below when it comes to sizing the cables for VSDs. Steps to select the proper sized cable for your surface equipment: - Select the amperage or VSD rating and then the amperage from [Table A-2](.) . **Table A-2: VSD Amperages** | kVA | Amperage | Amperage x 1.25 | |-------|------------|-------------------| | 66 | 79 | 99 | | 83 | 100 | 125 | | 111 | 134 | 168 | | 130 | 156 | 195 | | 163 | 196 | 245 | | 200 | 241 | 301 | | 260 | 313 | 391 | | 325 | 391 | 489 | | 390 | 469 | 586 | | 454 | 546 | 683 | | 518 | 623 | 779 | | 600 | 722 | 903 | | 700 | 842 | 1053 | | 815 | 980 | 1225 | | 932 | 1121 | 1401 | | 1000 | 1203 | 1504 | | 1200 | 1443 | 1804 | | kVA | Amperage | Amperage x 1.25 | |-------|------------|-------------------| | 1400 | 1684 | 2105 | | 1500 | 1804 | 2255 | - The cable type that you will be using from (TW, THWN, THHN, etc.) the tables below. **Table A-3: 60 degC (140 degF) Types TW and UF** | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM Cable Size AWG / MCM | 26-30 degC 78-89 degF | 31-35 degC 87-95 degF | 36-40 degC 96-104 degF | 41-45 degC 105-113 degF | 46-50 degC 112-122 degF | 51-55 degC 122-131 degF | 56-60 degC 132-14 degF | | 14 | 15 | 14 | 12 | 11 | 9 | 6 | N/A | | 12 | 20 | 18 | 16 | 14 | 12 | 8 | N/A | | 10 | 30 | 27 | 25 | 21 | 17 | 12 | N/A | | 8 | 40 | 36 | 33 | 28 | 23 | 16 | N/A | | 6 | 55 | 50 | 45 | 39 | 32 | 23 | N/A | | 4 | 70 | 64 | 57 | 50 | 41 | 29 | N/A | | 3 | 85 | 77 | 70 | 60 | 49 | 35 | N/A | | 2 | 95 | 86 | 78 | 67 | 55 | 39 | N/A | | 1 | 110 | 100 | 90 | 78 | 64 | 45 | N/A | | 1/0 | 125 | 114 | 103 | 89 | 73 | 51 | N/A | | 2/0 | 145 | 132 | 119 | 103 | 84 | 59 | N/A | | 3/0 | 165 | 150 | 135 | 117 | 96 | 68 | N/A | | 4/0 | 198 | 180 | 162 | 141 | 115 | 81 | N/A | | 250 | 215 | 196 | 176 | 153 | 125 | 88 | N/A | | 300 | 240 | 218 | 197 | 170 | 139 | 98 | N/A | | 350 | 260 | 237 | 213 | 185 | 151 | 107 | N/A | | 400 | 280 | 255 | 230 | 199 | 162 | 115 | N/A | | 500 | 320 | 291 | 262 | 227 | 186 | 131 | N/A | | 600 | 355 | 323 | 291 | 252 | 206 | 146 | N/A | | 700 | 385 | 350 | 316 | 273 | 223 | 158 | N/A | | 750 | 400 | 364 | 328 | 284 | 232 | 164 | N/A | | 800 | 410 | 373 | 336 | 291 | 238 | 168 | N/A | | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132-14 degF | | 900 | 435 | 396 | 357 | 309 | 252 | 178 | N/A | | 1000 | 455 | 414 | 373 | 323 | 264 | 187 | N/A | **Table A-4: 60 degC (140 degF) Types TW and UF** | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM Cable Size AWG / MCM | 26-30 degC 78-89 degF | 31-35 degC 87-95 degF | 36-40 degC 96-104 degF | 41-45 degC 105-113 degF | 46-50 degC 112-122 degF | 51-55 degC 122-131 degF | 56-60 degC 132- 140 degF | | 14 | 12 | 11 | 10 | 9 | 7 | 5 | N/A | | 12 | 16 | 15 | 13 | 11 | 9 | 7 | N/A | | 10 | 24 | 22 | 20 | 17 | 14 | 10 | N/A | | 8 | 32 | 29 | 26 | 23 | 19 | 13 | N/A | | 6 | 44 | 40 | 36 | 31 | 26 | 18 | N/A | | 4 | 56 | 51 | 46 | 40 | 32 | 23 | N/A | | 3 | 68 | 62 | 56 | 48 | 39 | 28 | N/A | | 2 | 76 | 69 | 62 | 54 | 44 | 31 | N/A | | 1 | 88 | 80 | 72 | 62 | 51 | 36 | N/A | | 1/0 | 100 | 91 | 82 | 71 | 58 | 41 | N/A | | 2/0 | 116 | 106 | 95 | 82 | 67 | 48 | N/A | | 3/0 | 132 | 120 | 108 | 94 | 77 | 54 | N/A | | 4/0 | 158 | 144 | 130 | 112 | 92 | 65 | N/A | | 250 | 172 | 157 | 141 | 122 | 100 | 71 | N/A | | 300 | 192 | 175 | 157 | 136 | 111 | 79 | N/A | | 350 | 208 | 189 | 171 | 148 | 121 | 85 | N/A | | 400 | 224 | 204 | 184 | 159 | 130 | 92 | N/A | | 500 | 256 | 233 | 210 | 182 | 148 | 105 | N/A | | 600 | 284 | 258 | 233 | 202 | 165 | 116 | N/A | | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 700 | 308 | 280 | 253 | 219 | 179 | 126 | N/A | | 750 | 320 | 291 | 262 | 227 | 186 | 131 | N/A | | 800 | 328 | 298 | 269 | 233 | 190 | 134 | N/A | | 900 | 348 | 317 | 285 | 247 | 202 | 143 | N/A | | 1000 | 364 | 331 | 298 | 258 | 211 | 149 | N/A | **Table A-5: 60 degC (140 degF) Types TW and UF** | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM Cable Size AWG / MCM | 26-30 degC 78-89 degF | 31-35 degC 87-95 degF | 36-40 degC 96-104 degF | 41-45 degC 105-113 degF | 46-50 degC 112-122 degF | 51-55 degC 122-131 degF | 56-60 degC 132- 140 degF | | 14 | 11 | 10 | 9 | 7 | 6 | 4 | N/A | | 12 | 14 | 13 | 11 | 10 | 8 | 6 | N/A | | 10 | 21 | 19 | 17 | 15 | 12 | 9 | N/A | | 8 | 28 | 25 | 23 | 20 | 16 | 11 | N/A | | 6 | 39 | 35 | 32 | 27 | 22 | 16 | N/A | | 4 | 49 | 45 | 40 | 35 | 28 | 20 | N/A | | 3 | 60 | 54 | 49 | 42 | 35 | 24 | N/A | | 2 | 67 | 61 | 55 | 47 | 39 | 27 | N/A | | 1 | 77 | 70 | 63 | 55 | 45 | 32 | N/A | | 1/0 | 88 | 80 | 72 | 62 | 51 | 36 | N/A | | 2/0 | 102 | 92 | 83 | 72 | 59 | 42 | N/A | | 3/0 | 116 | 105 | 95 | 82 | 67 | 47 | N/A | | 4/0 | 139 | 126 | 114 | 98 | 80 | 57 | N/A | | 250 | 151 | 137 | 123 | 107 | 87 | 62 | N/A | | 300 | 168 | 153 | 138 | 119 | 97 | 69 | N/A | | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM Cable Size AWG / MCM | 26-30 degC 78-89 degF | 31-35 degC 87-95 degF | 36-40 degC 96-104 degF | 41-45 degC 105-113 degF | 46-50 degC 112-122 degF | 51-55 degC 122-131 degF | 56-60 degC 132- 140 degF | | 350 | 182 | 166 | 149 | 129 | 106 | 75 | N/A | | 400 | 196 | 178 | 161 | 139 | 114 | 80 | N/A | | 500 | 224 | 204 | 184 | 159 | 130 | 92 | N/A | | 600 | 249 | 226 | 204 | 176 | 144 | 102 | N/A | | 700 | 270 | 245 | 221 | 191 | 156 | 110 | N/A | | 750 | 280 | 255 | 230 | 199 | 162 | 115 | N/A | | 800 | 287 | 261 | 235 | 204 | 166 | 118 | N/A | | 900 | 305 | 277 | 250 | 216 | 177 | 125 | N/A | | 1000 | 319 | 290 | 261 | 226 | 185 | 131 | N/A | **Table A-6: 60 degC (140 degF) Types TW and UF** | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132-140 degF | | 14 | 8 | 7 | 6 | 5 | 4 | 3 | N/A | | 12 | 10 | 9 | 8 | 7 | 6 | 4 | N/A | | 10 | 15 | 14 | 12 | 11 | 9 | 6 | N/A | | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132-140 degF | | 8 | 20 | 18 | 16 | 14 | 12 | 8 | N/A | | 6 | 28 | 25 | 23 | 20 | 16 | 11 | N/A | | 4 | 35 | 32 | 29 | 25 | 20 | 14 | N/A | | 3 | 43 | 39 | 35 | 30 | 25 | 17 | N/A | | 2 | 48 | 43 | 39 | 34 | 28 | 19 | N/A | | 1 | 55 | 50 | 45 | 39 | 32 | 23 | N/A | | 1/0 | 63 | 57 | 51 | 44 | 36 | 26 | N/A | | 2/0 | 73 | 66 | 59 | 51 | 42 | 30 | N/A | | 3/0 | 83 | 75 | 68 | 59 | 48 | 34 | N/A | | 4/0 | 99 | 90 | 81 | 70 | 57 | 41 | N/A | | 250 | 108 | 98 | 88 | 76 | 62 | 44 | N/A | | 300 | 120 | 109 | 98 | 85 | 70 | 49 | N/A | | 350 | 130 | 118 | 107 | 92 | 75 | 53 | N/A | | 400 | 140 | 127 | 115 | 99 | 81 | 57 | N/A | | 500 | 160 | 146 | 131 | 114 | 93 | 66 | N/A | | 600 | 178 | 162 | 146 | 126 | 103 | 73 | N/A | | 700 | 193 | 175 | 158 | 137 | 112 | 79 | N/A | | 750 | 200 | 182 | 164 | 142 | 116 | 82 | N/A | | 800 | 205 | 187 | 168 | 146 | 119 | 84 | N/A | | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132-140 degF | | 900 | 218 | 198 | 178 | 154 | 126 | 89 | N/A | | 1000 | 228 | 207 | 187 | 162 | 132 | 93 | N/A | **Table A-7: 75 degC (167 degF) Types RHW, THHW, THW, THWN, XHHW, USE, ZW** | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 14 | 20 | 19 | 18 | 16 | 15 | 13 | 12 | | 12 | 25 | 24 | 22 | 21 | 19 | 17 | 15 | | 10 | 35 | 33 | 31 | 29 | 26 | 23 | 20 | | 8 | 50 | 47 | 44 | 41 | 38 | 34 | 29 | | 6 | 65 | 61 | 57 | 53 | 49 | 44 | 38 | | 4 | 85 | 80 | 75 | 70 | 64 | 57 | 49 | | 3 | 100 | 94 | 88 | 82 | 75 | 67 | 58 | | 2 | 115 | 108 | 101 | 94 | 86 | 77 | 67 | | 1 | 130 | 122 | 114 | 107 | 98 | 87 | 75 | | 1/0 | 150 | 141 | 132 | 123 | 113 | 101 | 87 | | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 2/0 | 175 | 165 | 154 | 144 | 131 | 117 | 102 | | 3/0 | 200 | 188 | 176 | 164 | 150 | 134 | 116 | | 4/0 | 230 | 216 | 202 | 189 | 173 | 154 | 133 | | 250 | 255 | 240 | 224 | 209 | 191 | 171 | 148 | | 300 | 285 | 268 | 251 | 234 | 214 | 191 | 165 | | 350 | 310 | 291 | 273 | 254 | 233 | 208 | 180 | | 400 | 335 | 315 | 295 | 275 | 251 | 224 | 194 | | 500 | 380 | 357 | 334 | 312 | 285 | 255 | 220 | | 600 | 420 | 395 | 370 | 344 | 315 | 281 | 244 | | 700 | 460 | 432 | 405 | 377 | 345 | 308 | 267 | | 750 | 475 | 447 | 418 | 390 | 356 | 318 | 276 | | 800 | 490 | 461 | 431 | 402 | 368 | 328 | 284 | | 900 | 520 | 489 | 458 | 426 | 390 | 348 | 302 | | 1000 | 545 | 512 | 480 | 447 | 409 | 365 | 316 | **Table A-8: 75 Deg. C (167 F) Types RHW, THHW, THW, THWN, XHHW, USE, ZW** | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | | 14 | 16 | 15 | 14 | 13 | 12 | 11 | 9 | | 12 | 20 | 19 | 18 | 16 | 15 | 13 | 12 | | 10 | 28 | 26 | 25 | 23 | 21 | 19 | 16 | | 8 | 40 | 38 | 35 | 33 | 30 | 27 | 23 | | 6 | 52 | 49 | 46 | 43 | 39 | 35 | 30 | | 4 | 68 | 64 | 60 | 56 | 51 | 46 | 39 | | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | | 3 | 80 | 75 | 70 | 66 | 60 | 54 | 46 | | 2 | 92 | 86 | 81 | 75 | 69 | 62 | 53 | | 1 | 104 | 98 | 92 | 85 | 78 | 70 | 60 | | 1/0 | 120 | 113 | 106 | 98 | 90 | 80 | 70 | | 2/0 | 140 | 132 | 123 | 115 | 105 | 94 | 81 | | 3/0 | 160 | 150 | 141 | 131 | 120 | 107 | 93 | | 4/0 | 184 | 173 | 162 | 151 | 138 | 123 | 107 | | 250 | 204 | 192 | 180 | 167 | 153 | 137 | 118 | | 300 | 228 | 214 | 201 | 187 | 171 | 153 | 132 | | 350 | 248 | 233 | 218 | 203 | 186 | 166 | 144 | | 400 | 268 | 252 | 236 | 220 | 201 | 180 | 155 | | 500 | 304 | 286 | 268 | 249 | 228 | 204 | 176 | | 600 | 336 | 316 | 296 | 276 | 252 | 225 | 195 | | 700 | 368 | 346 | 324 | 302 | 276 | 247 | 213 | | 750 | 380 | 357 | 334 | 312 | 285 | 255 | 220 | | 800 | 392 | 368 | 345 | 321 | 294 | 263 | 227 | | 900 | 416 | 391 | 366 | 341 | 312 | 279 | 241 | | 1000 | 436 | 410 | 384 | 358 | 327 | 292 | 253 | **Table A-9: 75 degC (167 degF) Types RHW, THHW, THW, THWN, XHHW, USE, ZW** | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | | 14 | 14 | 13 | 12 | 11 | 11 | 9 | 8 | | 12 | 18 | 16 | 15 | 14 | 13 | 12 | 10 | | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | Cable Size 26-30 31-35 36-40 56-60 AWG / MCM degC degC degC 41-45 degC 46-50 degC 51-55 degC degC 132- Cable Size 78-89 87-95 96-104 105-113 112-122 122-131 140 AWG / MCM degF degF degF degF degF degF degF | | 10 | 25 | 23 | 22 | 20 | 18 | 16 | 14 | | 8 | 35 | 33 | 31 | 29 | 26 | 23 | 20 | | 6 | 46 | 43 | 40 | 37 | 34 | 30 | 26 | | 4 | 60 | 56 | 52 | 49 | 45 | 40 | 35 | | 3 | 70 | 66 | 62 | 57 | 53 | 47 | 41 | | 2 | 81 | 76 | 71 | 66 | 60 | 54 | 47 | | 1 | 91 | 86 | 80 | 75 | 68 | 61 | 53 | | 1/0 | 105 | 99 | 92 | 86 | 79 | 70 | 61 | | 2/0 | 123 | 115 | 108 | 100 | 92 | 82 | 71 | | 3/0 | 140 | 132 | 123 | 115 | 105 | 94 | 81 | | 4/0 | 161 | 151 | 142 | 132 | 121 | 108 | 93 | | 250 | 179 | 168 | 157 | 146 | 134 | 120 | 104 | | 300 | 200 | 188 | 176 | 164 | 150 | 134 | 116 | | 350 | 217 | 204 | 191 | 178 | 163 | 145 | 126 | | 400 | 235 | 220 | 206 | 192 | 176 | 157 | 136 | | 500 | 266 | 250 | 234 | 218 | 200 | 178 | 154 | | 600 | 294 | 276 | 259 | 241 | 221 | 197 | 171 | | 700 | 322 | 303 | 283 | 264 | 242 | 216 | 187 | | 750 | 333 | 313 | 293 | 273 | 249 | 223 | 193 | | 800 | 343 | 322 | 302 | 281 | 257 | 230 | 199 | | 900 | 364 | 342 | 320 | 298 | 273 | 244 | 211 | | 1000 | 382 | 359 | 336 | 313 | 286 | 256 | 221 | **Table A-10: 75 degC (167 degF) Types RHW, THHW, THW, THWN, XHHW, USE, ZW** | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 deg F | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 14 | 10 | 9 | 9 | 8 | 8 | 7 | 6 | | 12 | 13 | 12 | 11 | 10 | 9 | 8 | 7 | | 10 | 18 | 16 | 15 | 14 | 13 | 12 | 10 | | 8 | 25 | 24 | 22 | 21 | 19 | 17 | 15 | | 6 | 33 | 31 | 29 | 27 | 24 | 22 | 19 | | 4 | 43 | 40 | 37 | 35 | 32 | 28 | 25 | | 3 | 50 | 47 | 44 | 41 | 38 | 34 | 29 | | 2 | 58 | 54 | 51 | 47 | 43 | 39 | 33 | | 1 | 65 | 61 | 57 | 53 | 49 | 44 | 38 | | 1/0 | 75 | 71 | 66 | 62 | 56 | 50 | 44 | | 2/0 | 88 | 82 | 77 | 72 | 66 | 59 | 51 | | 3/0 | 100 | 94 | 88 | 82 | 75 | 67 | 58 | | 4/0 | 115 | 108 | 101 | 94 | 86 | 77 | 67 | | 250 | 128 | 120 | 112 | 105 | 96 | 85 | 74 | | 300 | 143 | 134 | 125 | 117 | 107 | 95 | 83 | | 350 | 155 | 146 | 136 | 127 | 116 | 104 | 90 | | 400 | 168 | 157 | 147 | 137 | 126 | 112 | 97 | | 500 | 190 | 179 | 167 | 156 | 143 | 127 | 110 | | 600 | 210 | 197 | 185 | 172 | 158 | 141 | 122 | | 700 | 230 | 216 | 202 | 189 | 173 | 154 | 133 | | 750 | 238 | 223 | 209 | 195 | 178 | 159 | 138 | | 800 | 245 | 230 | 216 | 201 | 184 | 164 | 142 | | 900 | 260 | 244 | 229 | 213 | 195 | 174 | 151 | | 1000 | 273 | 256 | 240 | 223 | 204 | 183 | 158 | **Table A-11: 90 Deg. C (194 F) Types TBS, SA, SIS, FEP, FEPB, MI, RHH, RHW-2, THHN, THHW, THW-2, THWN-2, USE-2, XHH, XHHW, XHHW-2, ZW-2** | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 1 to 3 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 14 | 25 | 24 | 23 | 22 | 21 | 19 | 18 | | 12 | 30 | 29 | 27 | 26 | 25 | 23 | 21 | | 10 | 40 | 38 | 36 | 35 | 33 | 30 | 28 | | 8 | 55 | 53 | 50 | 48 | 45 | 42 | 39 | | 6 | 75 | 72 | 68 | 65 | 62 | 57 | 53 | | 4 | 95 | 91 | 86 | 83 | 78 | 72 | 67 | | 3 | 110 | 106 | 100 | 96 | 90 | 84 | 78 | | 2 | 130 | 125 | 118 | 113 | 107 | 99 | 92 | | 1 | 150 | 144 | 137 | 131 | 123 | 114 | 107 | | 1/0 | 170 | 163 | 155 | 148 | 139 | 129 | 121 | | 2/0 | 195 | 187 | 177 | 170 | 160 | 148 | 138 | | 3/0 | 225 | 216 | 205 | 196 | 185 | 171 | 160 | | 4/0 | 260 | 250 | 237 | 226 | 213 | 198 | 185 | | 250 | 290 | 278 | 264 | 252 | 238 | 220 | 206 | | 300 | 320 | 307 | 291 | 278 | 262 | 243 | 227 | | 350 | 350 | 336 | 319 | 305 | 287 | 266 | 249 | | 400 | 380 | 365 | 346 | 331 | 312 | 289 | 270 | | 500 | 430 | 413 | 391 | 374 | 353 | 327 | 305 | | 600 | 475 | 456 | 432 | 413 | 390 | 361 | 337 | | 700 | 520 | 499 | 473 | 452 | 426 | 395 | 369 | | 750 | 535 | 514 | 487 | 465 | 439 | 407 | 380 | | 800 | 555 | 533 | 505 | 483 | 455 | 422 | 394 | | 900 | 585 | 562 | 532 | 509 | 480 | 445 | 415 | | 1000 | 615 | 590 | 560 | 535 | 504 | 467 | 437 | **Table A-12: 90 degC (194 degF) Types TBS, SA, SIS, FEP, FEPB, MI, RHH, RHW-2, THHN, THHW, THW-2, THWN-2, USE-2, XHH, XHHW, XHHW-2, ZW-2** | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | From 4 to 6 Cables in Raceway, Conduit, or Cable Ambient Temperature for Cable | |----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------|----------------------------------------------------------------------------------| | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 14 | 12 | 12 | 11 | 10 | 10 | 9 | 9 | | 12 | 16 | 15 | 15 | 14 | 13 | 12 | 11 | | 10 | 24 | 23 | 22 | 21 | 20 | 18 | 17 | | 8 | 44 | 42 | 40 | 38 | 36 | 33 | 31 | | 6 | 60 | 58 | 55 | 52 | 49 | 46 | 43 | | 4 | 76 | 73 | 69 | 66 | 62 | 58 | 54 | | 3 | 88 | 84 | 80 | 77 | 72 | 67 | 62 | | 2 | 104 | 100 | 95 | 90 | 85 | 79 | 74 | | 1 | 120 | 115 | 109 | 104 | 98 | 91 | 85 | | 1/0 | 136 | 131 | 124 | 118 | 112 | 103 | 97 | | 2/0 | 156 | 150 | 142 | 136 | 128 | 119 | 111 | | 3/0 | 180 | 173 | 164 | 157 | 148 | 137 | 128 | | 4/0 | 208 | 200 | 189 | 181 | 171 | 158 | 148 | | 250 | 232 | 223 | 211 | 202 | 190 | 176 | 165 | | 300 | 256 | 246 | 233 | 223 | 210 | 195 | 182 | | 350 | 280 | 269 | 255 | 244 | 230 | 213 | 199 | | 400 | 304 | 292 | 277 | 264 | 249 | 231 | 216 | | 500 | 344 | 330 | 313 | 299 | 282 | 261 | 244 | | 600 | 380 | 365 | 346 | 331 | 312 | 289 | 270 | | 700 | 416 | 399 | 379 | 362 | 341 | 316 | 295 | | 750 | 428 | 411 | 389 | 372 | 351 | 325 | 304 | | 800 | 444 | 426 | 404 | 386 | 364 | 337 | 315 | | 900 | 468 | 449 | 426 | 407 | 384 | 356 | 332 | | 1000 | 492 | 472 | 448 | 428 | 403 | 374 | 349 | **Table A-13: 90 degC (194 degF) Types TBS, SA, SIS, FEP, FEPB, MI, RHH, RHW-2, THHN, THHW, THW-2, THWN-2, USE-2, XHH, XHHW, XHHW-2, ZW-2** | From 7 to 9 Cables in Raceway, Conduit, or Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable | From 7 to 9 Cables in Raceway, Conduit, or Cable | |----------------------------------------------------|----------------------------------------------------|----------------------------------------------------|----------------------------------------------------|----------------------------------------------------|----------------------------------------------------|----------------------------------------------------|----------------------------------------------------| | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 deg F | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 14 | 11 | 10 | 10 | 9 | 9 | 8 | 7 | | 12 | 14 | 13 | 13 | 12 | 11 | 11 | 10 | | 10 | 21 | 20 | 19 | 18 | 17 | 16 | 15 | | 8 | 39 | 37 | 35 | 33 | 32 | 29 | 27 | | 6 | 53 | 50 | 48 | 46 | 43 | 40 | 37 | | 4 | 67 | 64 | 61 | 58 | 55 | 51 | 47 | | 3 | 77 | 74 | 70 | 67 | 63 | 59 | 55 | | 2 | 91 | 87 | 83 | 79 | 75 | 69 | 65 | | 1 | 105 | 101 | 96 | 91 | 86 | 80 | 75 | | 1/0 | 119 | 114 | 108 | 104 | 98 | 90 | 84 | | 2/0 | 137 | 131 | 124 | 119 | 112 | 104 | 97 | | 3/0 | 158 | 151 | 143 | 137 | 129 | 120 | 112 | | 4/0 | 182 | 175 | 166 | 158 | 149 | 138 | 129 | | 250 | 203 | 195 | 185 | 177 | 166 | 154 | 144 | | 300 | 224 | 215 | 204 | 195 | 184 | 170 | 159 | | 350 | 245 | 235 | 223 | 213 | 201 | 186 | 174 | | 400 | 266 | 255 | 242 | 231 | 218 | 202 | 189 | | 500 | 301 | 289 | 274 | 262 | 247 | 229 | 214 | | 600 | 333 | 319 | 303 | 289 | 273 | 253 | 236 | | 700 | 364 | 349 | 331 | 317 | 298 | 277 | 258 | | 750 | 375 | 360 | 341 | 326 | 307 | 285 | 266 | | 800 | 389 | 373 | 354 | 338 | 319 | 295 | 276 | | 900 | 410 | 393 | 373 | 356 | 336 | 311 | 291 | | 1000 | 431 | 413 | 392 | 375 | 353 | 327 | 306 | **Table A-14: 90 degC (194 degF) Types TBS, SA, SIS, FEP, FEPB, MI, RHH, RHW-2, THHN, THHW, THW-2, THWN-2, USE-2, XHH, XHHW, XHHW-2, ZW-2** | From 10 to 20 Cables in Raceway, Conduit, or Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable | From 10 to 20 Cables in Raceway, Conduit, or Cable | |------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------|------------------------------------------------------| | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | Ambient Temperature for Cable | | Cable Size AWG / MCM | 26-30 degC | 31-35 degC | 36-40 degC | 41-45 degC | 46-50 degC | 51-55 degC | 56-60 degC | | Cable Size AWG / MCM | 78-89 degF | 87-95 degF | 96-104 degF | 105-113 degF | 112-122 degF | 122-131 degF | 132- 140 degF | | 14 | 8 | 7 | 7 | 7 | 6 | 6 | 5 | | 12 | 10 | 10 | 9 | 9 | 8 | 8 | 7 | | 10 | 15 | 14 | 14 | 13 | 12 | 11 | 11 | | 8 | 28 | 26 | 25 | 24 | 23 | 21 | 20 | | 6 | 38 | 36 | 34 | 33 | 31 | 29 | 27 | | 4 | 48 | 46 | 43 | 41 | 39 | 36 | 34 | | 3 | 55 | 53 | 50 | 48 | 45 | 42 | 39 | | 2 | 65 | 62 | 59 | 57 | 53 | 49 | 46 | | 1 | 75 | 72 | 68 | 65 | 62 | 57 | 53 | | 1/0 | 85 | 82 | 77 | 74 | 70 | 65 | 60 | | 2/0 | 98 | 94 | 89 | 85 | 80 | 74 | 69 | | 3/0 | 113 | 108 | 102 | 98 | 92 | 86 | 80 | | 4/0 | 130 | 125 | 118 | 113 | 107 | 99 | 92 | | 250 | 145 | 139 | 132 | 126 | 119 | 110 | 103 | | 300 | 160 | 154 | 146 | 139 | 131 | 122 | 114 | | 350 | 175 | 168 | 159 | 152 | 144 | 133 | 124 | | 400 | 190 | 182 | 173 | 165 | 156 | 144 | 135 | | 500 | 215 | 206 | 196 | 187 | 176 | 163 | 153 | | 600 | 238 | 228 | 216 | 207 | 195 | 181 | 169 | | 700 | 260 | 250 | 237 | 226 | 213 | 198 | 185 | | 750 | 268 | 257 | 243 | 233 | 219 | 203 | 190 | | 800 | 278 | 266 | 253 | 241 | 228 | 211 | 197 | | 900 | 293 | 281 | 266 | 254 | 240 | 222 | 208 | | 1000 | 308 | 295 | 280 | 268 | 252 | 234 | 218 | - Choose how many cables you will need for your application. For most equipment the drawings should be referenced for the lug sizes and amperages needed. - Choose the ambient temperature that you will be operating your equipment at. Typically 46-50 degC (112-122 degF) **Note** An example is below for reference. **Example** VSD – 390 kVA Ambient Temperature – 45 degC Cable – 500 MCM THHN Wire is available The VSD drawings specify the following items for a 390 kVA unit : - Input terminals – 3 x (3/0 ~ 500 MCM) per phase - Output terminals – 2 x (#4 ~ 500 MCM) per phase For the input connections we will use the following cables. VSD = 469 Amps= 586 Amps for 1.25% safety margin Do the division for each number of wire(s) that may be used. 586 / 1 = 586 Amps for a single wire 586 / 2 = 293 Amps for 2 wires each 586 / 3 = 195 Amps for 3 wires each Refer to the table that has the THHN – Remember that the VSD can accommodate up to 3 x 500 MCM wires. The table that has the 1 to 3 conductors has no choices that can be used here, so the next table is used that has the 4 to 6 conductors. If the 500 MCM row is reviewed and the temperature column is followed down the value of 299 Amps is sufficient for 2 conductors per phase for a total of 598 Amps. **Note** In some cases it will be found that this reference will size the wire or cable that will not fit the lugs in the VSD. This is because of the 1.25% adder for harmonic heating. The normal heating effects of harmonics may be as little as 5% so the largest possible wire or cable should be used. **Note** Wire is defined as single conductors or groups of single conductors made up of copper conductor surrounded by insulation and should only be installed in conduit or dedicated wire way. **Note** Cable is defined as single conductors or groups of single conductors made up of copper conductor surrounded by insulation which in turn is surrounded by an armor sheath and thermoplastic outer covering. Armor may be continuous metal sheath, steel wire armor, or interlocking armor. Interlocking armor type cable is available in two armor types, steel or aluminum. Cable can be installed in conduit, cable tray, or attached to equipment where necessary with the proper cable clamps. ####### 60.1 General Conductor Information All conductors should be terminated at an approved terminating device (terminal). Terminals may be compression type, or stud type terminal. Stud type terminal blocks are found as male or female type. The male type has a threaded stud and a nut, the female type has a screw that turns into a threaded base. Studded terminal blocks may use crimp type wire lugs or set screw type wire lugs. In no case should wire be terminated directly to a stud type terminal without the use of a lug. Crimp type wire lugs should be sized correctly for the wire being terminated as well as the stud the lug is terminated on. Setscrew compression lugs cover a range of wire sizes but should also be chosen in a correct range for the wire to be terminated. Separate lugs should be used for each wire terminated. All wire and cable, with the exception of downhole cable, should be of stranded construction. No solid wire should be used for surface installations. Use of aluminum conductors is limited to high voltage terminations only and should be used on the primary side of step down transformers run from the fused cut-outs at the utility service. All other conductors should be copper. Where parallel conductors are installed in separate raceways (conduit or tray) each raceway should contain an equal number of conductors from each phase. For example: if two parallel runs of wire were to run in two separate conduits, each conduit should contain phase A, phase B, and phase C plus any associated neutral conductor, if used. It is not permissible, for example, to install two runs of A phase plus one run of B phase in one conduit then install two runs of C phase and one run of B phase in the second conduit. ####### 60.2 Motor Conductors Conductors to be used for surface motors should be sized to carry 125% of the full load current of the motor. This would mean that an 80 Amp motor would require a conductor rated for 100 amps. Below is a table giving the current Part Numbers for the Medium Voltage surface Cable that SLB currently offers. **Table A-15: Schlumberger PNs for MV Surface Cable** | SLB P/Ns for Medium Voltage (MV) Surface Cable | SLB P/Ns for Medium Voltage (MV) Surface Cable | SLB P/Ns for Medium Voltage (MV) Surface Cable | Ampacity from Okonite | Ampacity from Okonite | |--------------------------------------------------|--------------------------------------------------|-------------------------------------------------------------------------------------------------------|-------------------------|-------------------------| | SLB P/N | A- WG | Description | Air | Con- duit | | 100189824 | 1 | #1 AWG COMPACT-STRAND SURFACE CABLE, ARMORED, 5 kV ROUND, PVC JACKET, INSULATION SCREENING/ SHEILDING | 160 | 140 | | 100189822 | 2 | #2 COMPACT STRAND SURFACE CABLE, ARMORED, 5 kV ROUND, PVC JACKET, INSULATION SCREENING/SHEILDING | 140 | 125 | | 100189819 | 4 | #4 AWG COMPACT-STRAND SURFACE CABLE, ARMORED, 5 kV ROUND, PVC JACKET, INSULATION SCREENING/ SHEILDING | 105 | 91 | Potential Severity: Major Potential Loss: Assets, Personnel Hazard Category: Electrical Downhole cable cannot be used as surface cable. ####### 60.3 Transformer Conductors Transformer supply conductors should be not less than 125% of the rated full load primary or secondary current of the transformer. The following example shows how the conductor choice is arrived at. A 600 kVA transformer has a 13,800-volt primary and a 480-volt secondary. The primary current is: (600 X 1000) / (13,800 X 1.73) = 25.13 Amps The cable needed for the primary would be 1.25 X 25.13 = 31.4 amps The available secondary current is: (600 X 1000) / (480 X 1.73) = 721.7 Amps The cable needed for the secondary would be 1.25 X 721.7 = 902 Amps **Note** It’s important to note that for conductors rated for higher than 15 kV the smallest available conductor is #2 AWG. ####### 60.4 Capacitor Conductors Capacitor supply conductors should be not less than 135% of the rate full load current. For the installation of an R992 load filter connected in delta, the full load current is 110 Amps. This requires a conductor that carries 1.35 X 110 = 148.5 Amps. Cable selection for medium voltage capacitors should have 5 kV insulation as a minimum. ###### 61 Terminology **Term Definition** **Electricity** Electromotive force **Kilowatts** 1 hp = 746 kW **kVa** apparent power = Volts x Amps 1.732 x .001 **Power Factor** ratio of Watts to Volt/Amps **1 horsepower** 33,000 lbs raised 1 foot/ 1 min **Term Definition** **Volt** measurement of units of electricity at work or rest **Amperage** measurement of units of electricity at work **Current** see Amperage **Resistance** measurement of units of electricity expressed as Ohms to resist the flow of electricity **Hertz** preferred terminology to cycles or frequency **Short circuit** a mechanically connected conductor to earth **Continuity** electrically measuring the resistance from the end or a conductor to the other end **Insulation** a non-conducting material **Isolated** a conducting material separated by non-conducting material **Line side** referred to as the source of power (primary) **Load side** referred to as the use of power (secondary) **Ground earth** an uninsulated conductor to connect electricity to the physical earth **Ground Return** an insulated or isolated conductor used to complete a circuit **Ground fault** an electrically connected conductor to earth **Single phase** one (1) phase of electricity connected across a circuit to earth ground or neutral produces work **Three phase** Three (3) voltages separated by 120 degrees **Phase** Electricity flowing on a conductor **Phase-to-phase fault** two conductors electrically connected **Induction** electrically connected by magnetism **Capacitance** stored electrical energy **Winding** wire coils wound into a motor stator **End turns** winding coils change direction (location of connections to motor terminals) **Synchronous speed** actual speed without friction or stickage **Slip** actual speed with friction and stickage **Wye (Y) connection** a transformer or a motor connection, which creates a Y-point or a neutral location **Term Definition** **Delta connection** a transformer or a motor connection that does not create neutral location **Neutral or Wye point** a location point of a three-phase circuit, where theoretically, zero voltage is present ###### 62 Surveillance and Optimization ####### 62.1 ESP Surveillance Guidelines for an Application Engineer ######## 62.1.1 Introduction - **What is ESP surveillance?** ESP surveillance is monitoring data from an operating ESP for abnormalities and therefore potential problems. While the concept is simple, setting the proper parameters is neither easy nor intuitive. ######## 62.1.2 Why ESP surveillance? ESP Surveillance will increase the average runlife of an ESP and decrease downtime. The first step is to detect operating problems before they cause the pump to fail and to shut down the pump. The second step is to diagnose potential operating problems before they happen and avoid them, therefore avoiding a shutdown. ######## 62.1.3 General surveillance issues - **Alarms vs. Trips** Before getting started, let us establish an important distinction in data surveillance: alarms vs. trips. This document will use this naming convention to distinguish between the two types of surveillance. You will see many other naming systems used in your career in the oilfield (e.g. soft vs. hard alarms, passive vs. active, high vs. high-high or low vs. low-low, etc.). | Trip | A trip is a condition that causes the motor controller (switchboard or VSD) to shut down. Using traditional amperage surveillance (such as overload and underload) on a motor controller is a perfect example of a trip. Though trips are undeniably useful, since they may prevent a failure, they also shut down the system, which may have been avoided if the proper alarm was setup. | |--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Alarm | An alarm is a condition that causes a warning signal to be sent to someone or something. This distinction is very important for several reasons: First, in order for the alarm value to be recognized before a trip, its ‘limit’ must be closer to the normal operating value than the trip condition. Second, there must be some system in place to relay the alarm message. Example systems are a SCADA system and espWatcher. Third, someone must recognize the alarm and take action to determine the cause of the alarm – otherwise the whole system is pointless. | **Example** Consider the graphical example below. In the example, the expected value is 1, the alarms are at +/- 5 percent around the expected value and the trips are set at +/- 15 percent around the expected value. As the measured value starts to trend up and pass the 105 percent alarm limit, it would initiate alarm exceptions. If the system were setup properly, someone would receive notification of the alarms and take action to determine why they were occurring. **Figure A-5: Graphical Example of Alarms vs. Trips for a Measured Parameter.** ######## 62.1.4 Variable timing methods Several protection methods use a time delay between the beginning of a trip condition and the actual shut-off. This is particularly useful for electrical parameter surveillance, such as current or voltage, where a short departure outside the acceptable operating range (generally a matter of seconds) may not adversely harm the downhole equipment. These time delays are often complex, with a variable delay depending upon the severity of the value. Consider, for example, the default over-current time delay curve for the K095 switchboard controller. | percent OL | Time Delay | | |--------------|--------------|-----| | percent | sec- onds | | | 100 | 16 | | | 110 | 8 | | | 120 | 5 | | | 130 | 3.5 | | | 150 | 2.6 | | | 170 | 2.2 | | | 200 | 1.7 | | | 230 | 1.4 | | | 260 | 1.2 | | | 300 | 1 | | | 360 | 0.9 | | | 400 | 0.8 | | | 500 | 0.7 | | | 600 | 0.6 | | | 700 | 0.5 | | Variable timing methods are one method to avoid ‘nuisance shutdowns’ – where the reason for an automatic shutdown was not a threat to fail the equipment. They are not, however, a substitute for an alarm system – they do not alert anyone to the potential problem and the delay is not long enough to react to a problem. ######## 62.1.5 Data and event recording Motor controllers and electronic data collection devices (e.g. ISP) always record data. If properly setup, they should record ‘events’ as well, such as parameters that exceeded alarm or trip values or changes in settings. These records are invaluable when trying to determine historical surveillance trends and issues with an individual well. They should be the first information to retrieve when setting up new surveillance settings or investigating an incident (e.g. a shutdown). ######## 62.1.6 Stabilization time Surveillance guidelines routinely instruct the operator to wait until amperage stabilizes. So how long is this? The answer is different for every well: the specifics depend on well depth, deviation profile, casing size, well productivity, target production rate, and target drawdown. Some wells may take days to reach fully stabilized conditions, while others may stabilize in less than an hour. Obviously, it is impractical and irresponsible to wait for hours or days to set the current surveillance points. When you expect a long stabilization time, you must wait for relative stability from the amperage – 5 to 10- minutes – and then periodically re-check and adjust your current settings until you are satisfied that the well is stable. The DesignPro software has a nice tool that helps estimate stabilization time. Go to Plots → Intake → Well Stabilization Time to see a calculated estimate of when flow through the pump and flow from the reservoir. When these two flows are equal, the well is stabilized. ######## 62.1.7 Current/Amperage (primary switchboard or VSD surveillance) Amperage receives its own section due mainly to the fact that it is: - The most common method for ESP surveillance - The most difficult system to setup properly in order to protect an ESP system - The most commonly misapplied surveillance method (often using blind percentages without checking if they are valid). With that established, this document will cover how to use amperage, its limitations for catching changes in flow rate, and the special circumstances of start-up and changing frequency. | Property | How Used | High | Low | |--------------------|-------------------------------------------------------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Current (amperage) | Monitor to catch unexpected changes in flow rate or density | Generally set 5 to 20 percent above stabilized operating current or nameplate, used to detect a large increase in flow rate or a potential operating problem (debris production, pump wear, etc.). | Generally set 5 to 20 percent below stabilized operating current, used to detect a large decrease in flow rate, potential gas- lock problems in the pump, or pump-off. | ######## 62.1.8 Complications when using amperage surveillance Whether or not a change in flow rate will set off current surveillance settings depends on: - the present operating point (flow rate) of the pump and the shape of the pump curve - the motor load and the motor voltage - and the ‘gassiness’ of the well. ######## 62.1.9 Flowrate and pump power curve First, the operator should double check that a large change in flow rate will activate current surveillance settings. For example, if the ‘shut-in’ power is approximately 90 percent of the power at the operating point, then the low setting for alarms and/or trips should be 90 percent of the operating current, or greater, in order to catch a shut-in condition. As an example of the importance of the power curve, consider the SN2600 power curve, which has a very large change from shut-in to run-out power requirements. This pump would work well with amperage limits for detecting abnormal flow rates: **Figure A-6: SN2600 Catalog Pump Curve** There will be many circumstances, however, where the shut-in or run-out power requirement is so close to the operating power that the low or high (or both) current settings cannot be used to catch abnormal flow rate. This is one large disadvantage of using only current surveillance to catch ESP operational problems. For example, the S5000N power curve has a very flat profile and it might be difficult to use any sort of amperage surveillance: **Figure A-7: S5000N Catalog Pump Curve** ######## 62.1.10 Motor load and voltage Second, when considering ESP surveillance using amperage, you need to consider the motor as well as the pump. As you know, the motor amperage does not vary linearly with motor load. Therefore, you cannot assume that a decrease of 10% in required power will result in a decrease in 10 percent of motor amperage – it will certainly be less than that. To be thorough, the change in motor amperage is a complex relationship depending on the motor loading and the motor voltage. For highly loaded motors, the change in amperage due to a change in load is close to a linear relationship. This relationship becomes less linear as the motor loading decreases (this is one reason behind the minimum limit of 50 percent motor load). In addition, if the motor is not properly de-rated for the given operating condition, the relationship between current and load becomes even less linear. For very lightly loaded motors with full nameplate voltage, there may be very little change in motor amperage for a 10 to 20 percent change in motor load. ######## 62.1.11 Gassy wells Finally, you must consider that gassy wells may have special amperage traits. High gas, as a percentage of total flow, will decrease the density of the produced fluid – decreasing the amperage. During start-up – particularly after a workover – and during a shut-in, this may change: - Directly following a work over, the gas may take time to ‘come in’ to the well. This results in a higher density than typical operation and therefore higher amperage than fully stabilized operation. This may happen to a lesser degree after a regular start-up. - If the flow is stopped with an ESP operating (e.g. shut surface or downhole valve), no more gas will pass through pump and therefore the density should increase above normal operation. This will counter the expected decrease in amperage due to a normal pump power curve shape. To summarize, amperage surveillance is complicated and the operator must pay attention to the individual details of each installation to make sure it will work. ######## 62.1.12 Special circumstances for amperage protection: - **Start-up** Though you can estimate the power and amperage for a pump during its expected operating condition, it is far better to let the current stabilize and then setup the current limits. Follow this procedure to setup your current limits. | High | You do not want to disable the overcurrent setting completely because you still want to have some form of automatic ESP protection, so temporarily put your overcurrent limit at 115% of you motor nameplate amperage rating. Use a short overcurrent disable, such as 15 to 30-seconds, to avoid an immediate shut down during the high current at start-up. Many motor controllers have this function built-in. Once the current has stabilized, you can set your overcurrent alarms and trips. | |--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------| | Low | Do not set a low current limit during start-up. Many motor controllers have a delay function on the underload setting. Once the current has stabilized, use the stabilized value to set your alarms and trips. | ######## 62.1.13 Change in frequency on a VSD Changing the frequency on a VSD will change the operating amperage for the ESP. This means that any time you change the frequency, you will need to change the current alarms and trips as well. Follow these procedures to do so: **Increasing frequency** - Temporarily set your overcurrent settings to 115 percent of your motor nameplate. - Do not modify your lo current limits from the present values. - Change your operating frequency as desired. - Once the current has stabilized at the new frequency setting, reset your alarms and trips for both high and low limits. **Decreasing frequency** - Temporarily set the undercurrent alarms and trips to 0 to avoid any undercurrent problems. - Do not change the present overcurrent settings. - Change your operating frequency as desired. - Once the current has stabilized at the new frequency setting, reset your alarms and trips for both high and low limits. ######## 62.1.14 Setting overcurrent based on running amps or motor nameplate Standard practice allows the choice to set the overcurrent limit to 115 percent of running amps or 115 percent of nameplate amps. Either choice is acceptable if it is agreed upon. As a rule of thumb, it is typically preferable to use running amps unless: - The stabilized amperage is less than 30-A. Below this, a 15 percent increase in amperage will result in a relatively small cushion of 5-A or less. You must use your judgment, however, because a small running amperage (e.g. 20-A) compared to a high overcurrent setting based on nameplate amperage (e.g. 30-A) could result in ineffective protection. - Amperage fluctuations cause frequent shut-downs when the overcurrent limit of 115 percent of running amps is used. If this is the case, you may want to increase the overcurrent setting – to as high as 115 percent of nameplate amps, but no higher – assuming that these short current fluctuations will not harm the motor. ######## 62.1.15 Other motor controller data for potential surveillance In addition to amperage, motor controllers may offer several other potential options for data surveillance. These are mainly designed to detect abnormal electrical conditions downhole (current imbalance) or abnormal electrical supply problems (voltage). Whether or not these are available depend on the type of controller. | Property | How Used | High | Low | |-------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------------------------------| | Current Imbalance | Monitor to catch improper electrical function | When imbalance passes (typically) 20 percent | Not used | | Voltage (over or under) | Monitor to avoid operational problems from undervoltage (overcurrent) and overvoltage (magnetic saturation) | When voltage exceeds expected incoming by (typically) 10 percent | When voltage is less than expected incoming by (typically) 10 percent. Often used with variable time delay. | | Voltage imbalance | Monitor to catch undesirable power delivery, which can potentially harm the equipment. | When imbalance is greater than (typically) 4 percent. Often used with variable time delay. | Not used | | Backspin Relay | Monitored to avoid starting a pump turning in reverse | Yes, spinning | N/A | | Stall | High amperage, short time delay trip to disconnect power from a ‘stalled’ (non- starting) ESP. Cannot be disabled at start-up. Switchboards only. | Set at approximately 300 percent of the overcurrent setting with a delay of 0.4 to 0.5-seconds. | N/A | | Short Circuit | High amperage immediate shut down for short- circuit detection. Switchboard only. | Set at approximately 600 percent of the overcurrent setting | N/A | | Supply Voltage | Control-circuit protection for motor controllers. Generally to protect the control | Typically 130 V, depending on normal supply and potential problems | 100V, depending on normal supply and potential problems. Often used with time delay. | | Property | How Used | High | Low | |--------------|-----------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------------------------------------------------------------| | | equipment and to ensure proper contactor operation. | | | | Power Factor | ESP trip to stop ESP operating with poor power factor | Not used | Set at minimum acceptable power factor. | | Frequency | Used to ensure proper VSD operation or proper operation on generator supply with switchboard. | Set hi alarm to ensure that operators are not operating a VSD outside a safe range (e. g. max. safe speed). Avoid setting a trip which may unexpectedly shut-off a VSD during some sort of well site procedure. Use with switchboard on generator to ensure proper speed. | Set low alarm to make sure alarm is appropriate. Do not set low trip with VSD. Use with switchboard on generator to ensure proper operating speed. | ######## 62.1.16 Surface measurements In some circumstances, the properties at the surface are available for surveillance. In order for this to work, then the measurement in question must be electronic and have some sort of output into a data delivery system (such as SCADA) or data monitoring system (such as an analog input on a Phoenix ISP). In order for a trip to work, the monitoring system must have a connection with the motor controller, such as a Phoenix ISP connected to the VSD. Tubing pressure can be particularly useful for catching shut surface valves very quickly. | Property | How Used | High | Low | |-------------------------|-----------------------------------|--------------------------------------------------------------------------------------------------------------------------------------|-------------------------------------------------| | Tubing Head Pressure | Monitor for unexpected conditions | A certain level above normal may indicate a (partially or fully) shut valve | Zero or near-zero may indicate no flow. | | Casing Head Pressure | Monitor for unexpected conditions | A high value in a casing- vented situation may indicate a closed valve and decreasing fluid level. Very rarely used for surveillance | Not Used | | Tubing Head Temperature | Monitor for change in flowrate | Not generally used for surveillance | Not generally used for surveillance | | Flow Meter | Indication or measurement of flow | Can indicate an increase in flow, not often used as an alarm or trip. | Indicates problem with flow (often ‘yes or no’) | ######## 62.1.17 Downhole ESP monitor An ESP monitor is the best way to protect your ESP equipment: - Rather than rely on surface electrical performance only, a downhole monitor allows surveillance of downhole pressure, downhole temperature, mechanical data (vibration), and electrical data (voltage and current leakage), where problems can result in failures. - ESP monitors offer measurements that no other methods can offer, such as motor winding temperature. - ESP monitors offer measurements that are invaluable for troubleshooting purposes in the case of an alarm situation. For more information on this subject, see the troubleshooting guide. The table below lists the common measurements and how to use them with surveillance. | Property | How Used | High | Low | |-------------------------------------------|--------------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------| | Gauge Pressure or Pump Intake Pressure(1) | To avoid pump-off | Not Used | Set alarm or trip when P6 becomes too low. | | Gauge Temperature | To catch abnormal temperature increase | Set a few degrees above normal operating temperature | Not Used | | Motor Winding Temperature | To catch abnormal ESP operation | Set an alarm a few degrees above normal operation, set a trip a few degrees above the alarm. DO NOT set at motor insulation limit – it will be too late. | Not used | | Pump Discharge Pressure | To catch a pump running against a closed valve To diagnose gas problems (not for alarm purposes) | Set an alarm with an appropriate safety factor above normal PD, be careful about using a trip. | Not used | | Pump Vibration (acceleration) | To detect resonant frequency excitation, pump wear, or debris production | Use hi limit alarms to signal unusual vibration. Be careful about using trips. | Not used | | Pump Vibration (frequency) | To diagnose resonant frequency problems | Not used for alarms or trips | Not used for alarms or trips | | Property | How Used | High | Low | |--------------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------|--------------------------------------------------| | Current Leakage | Can detect insulation breakdown or deterioration (due to general wear or elevated temperatures) | High current leakage may signal an alarm, but avoid trips because the problem is rarely curable. | Not used | | Monitor Functional | Most surface units have ‘normally open’ vs. ‘normally closed’ digital outputs for recognizing a problem. Through proper selection, you can effectively detect a malfunctioning monitor | Not used | Zero means gauge or surface unit not functional. | (1) ESP Monitors will always measure the pressure at the monitor itself, generally below the motor. This is sometimes referred to as ‘pump intake pressure’, even though technically incorrect. New gauge technology can measure real pump intake pressure, which can lead to some confusion. For surveillance, we can assume that they are interchangeable. ######## 62.1.18 Permanent gauge (ESP independent gauge) In certain instances, an oil company may use ESP-independent monitoring with an ESP. These types of gauges can offer some advantages over ESP monitors, such as not being affected by an electrical insulation fault, higher resolution on pressure and temperature (especially with Quartz technology), and faster data transfer. For surveillance, however, they are less useful than an ESP monitor because they offer less ESP-related information. Using a permanent gauge with trips is somewhat rare, since the permanent gauge surface unit is not specifically designed to be easily compatible with the motor controller, unlike ESP monitor surface units. Therefore, most independent gauges will need to use a SCADA system and have someone receiving and reacting to alarms. The typically available data from a permanent gauge are summarized in the table below | Property | How used | High | Low | |------------------------------|--------------------------------------------|------------------------------------------------------|--------------------------------------------| | Casing Pressure above ESP | Use like gauge pressure on ESP monitor | Not used | Set alarm or trip when PG becomes too low. | | Casing Temperature above ESP | Use like intake temperature on ESP monitor | Set a few degrees above normal operating temperature | Not used | | Property | How used | High | Low | |------------------------------|--------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------|----------| | Tubing Pressure above ESP | Use like discharge pressure on ESP monitor | Set an alarm with an appropriate safety factor above normal PD, be careful about using a trip. | Not Used | | Tubing Temperature above ESP | Use like intake temperature on ESP monitor (will be identical to casing temperature) | Same as casing temperature | Not Used | ######## 62.1.19 How to choose an appropriate alarm or trip value The most important issue for proper ESP surveillance is what values to use for alarms and/or trips on the available data. This is more important than which data to use because using improper limits renders the selected surveillance useless. Therefore, always pay special attention to the values you use when setting up your surveillance system. Use these rules when setting alarms or trips: ######## 62.1.20 Alarm and limit values When using alarms, always set the alarm closer to the nominal operating value than the trip. This should be self-evident, since an alarm is useless if is not triggered before a trip. Obviously, you want to have some reaction time as well. ######## .15.1.8.1.2 Set alarms and limits relative to normal operating values When setting alarms and trips, use values that can catch abnormal operating conditions, DO NOT USE THE RATINGS OR LIMITS OF THE EQUIPMENT. It is impossible to overemphasize this point. This method requires that you consider the value of the parameter when the ESP equipment is not operating and the normal operating value for the equipment. For example, consider this monitoring situation for a well that had a problem. In this case, the ESP operated against a closed valve for several hours. The well had an independent downhole monitor that delivered pressure and temperature from the casing and tubing. The graph below shows the ESP operating normally, then a short shut down, then operating against a closed valve. The data interval is one-hour: **Figure A-8: Example of Permanent Monitoring Data During Shut-in** *.15.1.8.1.3* For temperature, you can see that the non-operating temperature was about 63 degC and the normal operating temperature around 66 degC. During the shut-in, the temperature increased to over 120 degC yet failed to shut down the system or notify anyone about the problem. An alarm at even 5 to 10 degC above normal operating temperature would be appropriate here. A trip at 20 degC above normal operating temperature would have shut down the equipment within an hour of the problem. *.15.1.8.1.4* For pressure, the static discharge pressure is somewhere around 90-bar and the normal operating discharge pressure was around 150-bar. The shut in resulted in an increase in discharge pressure to over 200-bar almost immediately. Even a conservative alarm or trip at 200-bar would have caught the problem in less than one hour. ######## 62.1.21 Give thought to margins Use an appropriate safety margin to determine a good value. In our example above, determining appropriate limits is relatively simple because we have the benefit of knowing how fast the monitored data will increase above normal operating conditions – information that will rarely be available. In general you will need to use your own judgment on what value is appropriate. For temperature, compare non-operating pressure with operating pressure. For pressure, you may want to calculate the theoretical maximum discharge pressure based on the shut-in head from the pump and the static intake pressure. For discharge pressure, use a value higher than normal operating differential pressure but lower than the shut-in pressure. ######## 62.1.22 Document Always document how you set up your limits. For any given parameter there may be more than one acceptable method to determine an appropriate limit. Whatever you choose, make sure write down how you chose that value. You will not remember when it comes time to change the parameter or investigate an incident. ######## 62.1.23 Respect ratings When setting trips using the rules above, make sure that the trips are not set above the ratings and limits of your equipment. For example, you never want to set a motor winding temperature trip above the insulation rating. The one exception is that the overcurrent setting may be above the motor nameplate current rating. ######## 62.1.24 Watch out for nuisance alarms For alarm systems, such as espWatcher, be careful not to set alarm limits that result in frequent alarms when no real problem exists. You might remember this as the ‘never cry wolf’ rule. Frequent erroneous alarms result in complacency in the person receiving the alarms and may mask a real problem. ######## 62.1.25 Initial Start-up The most critical period for any installation is the first time the ESP is started. The first time an ESP is started, there is no basis for comparison between ‘normal data’ and data that might indicate a problem. There is no automated system that can help you diagnose an operating problem in these instances. You will need to use your skill as an artificial lift engineer to determine if and when a problem occurs. **Table A-16: Abbreviations** | Abbr. | Full Name | |---------|----------------------------------------------------------| | ALSSFSM | Artificial Lift Submersible Systems Field Service Manual | | ESP | Electric Submersible Pump | | HMI | Human Machine Interface | | PG | Gauge Pressure (or Pump Intake Pressure) | | PD | Discharge Pressure | | SCADA | Supervisory Control And Data Aquisition | | VSD | Variable Speed Drive | **Table A-17: Appendix A: Summary of measured parameters** | Controller | Parameter | How Used | High | Low | |----------------------------------------|----------------------|--------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------| | Controller | Amperage (Current) | Monitor to catch changes in flow or density | Set 5 to 20 percent above operating current or motor nameplate. Used to catch major problems. | Set 5 to 20 percent below stabilized current to catch large flow decrease (shut-in), gas- lock, or pump-off. Double check value vs. pump curve and motor load. | | Controller | Current Unbalance | Detect improper electrical function | When imbalance passes 20 percent | Not used | | Controller | Voltage | Avoid operational problems from undervoltage (overcurrent) and overvoltage (magnetic saturation) | When voltage exceeds expected incoming voltage by what 10 percent | When voltage is less than expected incoming voltage by 10 percent | | Controller | Voltage Unbalance | Avoid undesirable power delivery. | When imbalance passes 4 percent | Not used | | Controller | Backspin Relay | Avoid starting a pump when it’s turning in reverse. | Disable restart when spinning | N/A | | Controller | Stall | Disconnect power from a locked motor during start-up | Set at 345 percent of nameplate current with a delay of 0.4 to 0.5 seconds | Not used | | Controller | Short Circuit | Disconnect power in the case of a short circuit in the electrical system | Immediate shut down if amperage exceeds 700 percent nameplate | Not used | | Controller | Supply Voltage | Ensure proper voltage to control circuit. Protects control circuit and also | Typically set at 10V above standard control supply | Typically set 20V below standard control supply | | Controller | Power Factor | ESP trip to stop ESP operating with a poor power factor | Not used | Shut down when power factor decreases below a minimum acceptable level. | | Controller | Frequency | Ensure proper VSD operation | Set hi lmits to catch unauthorized or unexpected operating frequency | Set low limits to catch unauthorized or unexpected operating frequency | | Surface | Tubing Head Pressure | Monitor for shut valves or no-flow | Use calculations to set appropriate values to detect partially or fully closed valve. | Zero may indicate no flow. Do not use trip | | | Parameter | How Used | High | Low | |--------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------| | | Casing Head Pressure | Monitor for shut valve | Set to catch shut casing vent | Not used | | | Tubing Head Temperature | Can indicate a change in flowrate. Very rarely used for surveillance | Not used | Not used | | | Surface Flowmeter | flowrate measurement. Sometimes inaccurate. | Not used | May use to catch no flow condition | | ESP Monitor or Independent Gauge | ESP Monitor Pressure (a.k. a. Intake Pressure )2 | To avoid pump-off | Not used | Set at a minimum acceptable value to avoid pump-off | | ESP Monitor or Independent Gauge | ESP Monitor Temperature (a.k.a. Intake Temperature) | Catch abnormal temperature increase | Set a few degrees above normal operating temperature | Not used | | ESP Monitor or Independent Gauge | Motor Winding Temperature | Catch abnormal ESP operation | Set an alarm a few degrees above normal operation; set a trip a few degrees above alarm. DO NOT set at motor insulation rating. | Not used | | ESP Monitor or Independent Gauge | Discharge Pressure | To catch no flow; Also used for data validation | Calculate an appropriate high value that will indicate a shut valve. | Not used | | ESP Monitor or Independent Gauge | Pump Differential Pressure | To catch no flow; Also used for troubleshooting | Set above normal operating differential but below shut-in differential. | Not used | | ESP Monitor or Independent Gauge | Vibration Amplitude | Detect resonant frequency excitation, pump wear, debris. | Use high alarm to signal unusual vibration. Careful about using trips. | Not used | | ESP Monitor or Independent Gauge | Vibration Frequency | Diagnose resonant frequency excitation | Not used | Not used | | ESP Monitor or Independent Gauge | Current Leakage | Detect electrical insulation breakdown | Use alarm to indicate the beginning of insulation breakdown. Don’t use trip. | Not used | | ESP Monitor or Independent Gauge | Monitor Functional | Ensure monitor is functional | Not used | Indicate Monitor malfunction | | 2 For independent gauges: monitor pressure ≉ Casing pressure; ESP Monitor temperature ≉ casing AND tubing temperature; Discharge pressure ≉ Tubing pressure. | 2 For independent gauges: monitor pressure ≉ Casing pressure; ESP Monitor temperature ≉ casing AND tubing temperature; Discharge pressure ≉ Tubing pressure. | 2 For independent gauges: monitor pressure ≉ Casing pressure; ESP Monitor temperature ≉ casing AND tubing temperature; Discharge pressure ≉ Tubing pressure. | 2 For independent gauges: monitor pressure ≉ Casing pressure; ESP Monitor temperature ≉ casing AND tubing temperature; Discharge pressure ≉ Tubing pressure. | 2 For independent gauges: monitor pressure ≉ Casing pressure; ESP Monitor temperature ≉ casing AND tubing temperature; Discharge pressure ≉ Tubing pressure. | | | | | Stat- ic | 10 min | 30 min | Stabilized | Low Trip | Low Alarm | High Alarm | High Trip | |--------------------------------------------------|---------|----|------------|----------|----------|--------------|------------|-------------|--------------|-------------| | Amperage | | | | | | | | | | | | Current Unbalance | percent | 0 | | | | | | | | | | Voltage | | | | | | | | | | | | Voltage Unbalance | percent | 0 | | | | | | | | | | Backspin Relay | | | | | | | | | | | | Stall | | | | | | | | | | | | Short Circuit | | | | | | | | | | | | Supply Voltage | | | | | | | | | | | | Power Factor | percent | | | | | | | | | | | Frequency | Hz | | | | | | | | | | | Tubing Head Pressure | | | | | | | | | | | | Casing Head Pressure | | | | | | | | | | | | Tubing Head Temperature | | | | | | | | | | | | Surface Flowmeter | | | | | | | | | | | | ESP Monitor Pressure (aka Intake Pressure) | | | | | | | | | | | | ESP Monitor Temperature (aka Intake Temperature) | | | | | | | | | | | | Motor Winding Temperature | | | | | | | | | | | | Discharge Pressure | | | | | | | | | | | | Pump Differential Pressure | | | | | | | | | | | | Vibration Amplitude | G | | | | | | | | | | | Vibration Frequency | Hz | | | | | | | | | | |-----------------------------|-----------------------------|-----------------------------|-----------------------------|-----------------------------|-----------------------------|-----------------------------|-----------------------------|-----------------------------|-----------------------------|-----------------------------| | Current Leakage | mA | 0 | | | | | | | | | | Monitor Functional | | | | | | | | | | | | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | 3 From design calculations. | ##### Advanced ESP Lifting Service - [**Advanced ESP lifting service B-1**](.) - [**How it works B-1**](.) - [**Case Studies B-2**](.) ##### B Advanced ESP Lifting Service ###### 63 Advanced ESP lifting service The advanced ESP lifting service involves optimization of wells through the application of surveillance and diagnostic methodologies that include - complete range of REDA ESPs - phoenix artificial lift system instrumentation - espWatcher surveillance and control (remote in real-time) and - lifting system and reservoir diagnostics to identify, diagnose and optimize lift and reservoir performance. Surveillance is an automated methodology that identifies wells operating outside their optimum range providing: - management of large volumes of data - proactive monitoring of trends, anticipate failures/ workovers - the opportunity to find the wells with potential for production improvement - easily populated field reservoir models to optimize field production - by continuous comparison of measured data to reference. Diagnostics is an episodic service using wellsite and reservoir measurements to optimize well performance. This is optimize the total system, the outflow system and the reservoir – field optimization. [InTouch Content 4135419](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4135419) provides a detailed presentation on the Advanced ESP Lifting Service and all its components. ###### 64 How it works Advanced Lifting Service uses espWatcher Monitoring and espWatcher Surveillance as data applications and in the field a Site Communication Box to acquire and transmit all the information. For a description on how Site Communication Box (SCB) works go to SCB Site Communication Box explained, [InTouch Content ID 4020728](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4020728) , or to the [Reference Page at content 3839179 Artificial Lift -](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3839179) [Site Communications Box (SCB)](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=3839179) . Monitoring is the application used to get the data from the field (FDExec) and uses InterAct Production services. To get a complete specification about this service, download it from InterAct Production Web page at [http://www.sedalia.nam.slb.com/IAProd/](http:\www.sedalia.nam.slb.com\IAProd) . There are other important documents available like: - InterACT Production User Manual V1.0 - espWatcher Datasheet v6 - espWatcher I/O List V9.10 - espWatcher Specification V3.1. espWatcher Surveillance is the application where AE normally makes optimization, prepares reports for the clients, and can control ESP remotely. As part of his role, ALPEs and AEs should configure alarms using guidelines like 10.1 Chapter and Alarms Setup in espWatcher [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4390989) [4390989](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4390989) . For a complete information and training go to *espWatcher V3 Training Material* [InTouch Content ID](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4327542) [4327542](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4327542) . The Advanced ESP Lifting Service involves optimization of wells through the application of Surveillance and Diagnostic Methodologies that include: - Complete range of REDA ESPs, - Phoenix Artificial Lift System instrumentation, - espWatcher Surveillance and control (remote in real-time) and - Lifting System and Reservoir Diagnostics to Identify diagnose and optimize lift and reservoir performance. Surveillance is an automated methodology that identifies wells operating outside their optimum range providing: - management of large volumes of data - proactive monitoring of trends, anticipate failures/ workovers - the opportunity to find the wells with potential for production improvement - easily populated field reservoir models to optimize field production - by continuous comparison of measured data to reference. [InTouch Content ID 4135419](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4135419) and [InTouch Content ID 4315634](http:\intouchsupport.com\intouch\methodinvokerpage.cfm?caseid=4315634) provides a detailed presentation on the Advanced ESP Lifting Service, its components and the workflow. ###### 65 Case Studies In SAIL and in InTouch, brochures could be found and there exists a lot of case studies that could be used as reference on how Advanced Lift Service and espWatcher make a Real Time Surveillance for ESP applications. ##### Advanced Material Selection - [**Gather the Data and Specifications C-1**](.) - [**Material Selection C-1**](.) ##### C Advanced Material Selection ###### 66 Gather the Data and Specifications Placeholder for section/content under development. Updates to this section will be published in subsequent revisions. ###### 67 Material Selection Placeholder for section/content under development. Updates to this section will be published in subsequent revisions.