11S4 Recommended Practice for Sizing and Selection of Electric Submersible Pump Installations API RECOMMENDED PRACTICE 11S4 THIRD EDITION, JULY 2002 REAFFIRMED, OCTOBER 2013 Recommended Practice for S[.]
Nomenclature
B o Oil formation volume factor (bbl/STB)
B w Water formation volume factor (bbl/STB)
H D Vertical fluid head measured from the well- head to the working fluid level (ft) [m]
H F Tubing head loss due to friction (ft) [m]
H T Head equivalent to wellhead pressure (ft) [m]
J Productivity index (bbl/day/psi) [m 3 /day/kPa] KVA Transformer power rating (kilowatts-volts- amperage)
MD pump Measured pump intake setting depth (ft) [m]
P bhs Bottomhole static pressure (psig) [kPa]
P wf Wellbore flowing pressure (psig) [kPag]
P wh Wellhead flowing pressure (psig) [kPag] PIP Pump intake pressure (psig) [kPa] q Desired flow rate of fluid into the wellbore
(bbl/day) [m 3 /day] q intake flow rate at the pump intake (bbl/day)
SCF Standard cubic feet SSU Saybolt Seconds Universal viscosity STB Stock tank barrels
TDH Total dynamic head needed to pump fluid at a certain rate (ft) [m]
VD pump Vertical pump intake setting depth (ft) [kPa]
The vertical depth of a reservoir, indicated by VD, is measured at the midpoint of perforations in feet or meters In the petroleum industry, the API gravity term, denoted as γ, is commonly used to describe oil density The specific gravity of fluid, γ f, is measured relative to pure water, which has a specific gravity of 1.000 Similarly, the specific gravity of oil, γ o, and the specific gravity of brine, γ w, are also measured relative to water, with both having a reference value of 1.000.
Conversion Formulas
Gas-oil or gas-water ratio: m 3 /m 3 = (SCF/STB)/5.615
Pressure: kPa(g) = 6.894757 psi(g) bar(g) = 14.7 psi(g)
The flow chart below provides an overview of the ESP design procedure, depicted as a linear process in Figure 1 However, the design may necessitate several iterations, as changes in one component can affect previously chosen equipment For instance, an increase in horsepower (HP) for the seal section may prompt a reassessment of the motor selection Additionally, conducting multiple design runs can help optimize equipment choices and assess the sensitivity of the design to critical input parameters Detailed descriptions of each step are provided in the referenced section.
10.0 Select switchboard/VSD and transformer
R ECOMMENDED P RACTICE FOR S IZING AND S ELECTION OF E LECTRIC S UBMERSIBLE P UMP I NSTALLATIONS 3
Data is essential for defining the operational environment of the ESP It is crucial to perform quality checks on data from all available sources to ensure accuracy The main limitation affecting data quality must be addressed to enhance overall performance.
The quality of data used in ESP design is crucial, as it directly impacts the performance characteristics of the pumping system, fluid flow through piping, and fluid PVT properties, all of which can be mathematically modeled However, feeding inaccurate data into these models can result in incorrect outcomes, leading to improper sizing of pumps, motors, and other system components This can ultimately cause premature equipment failure, workovers, and deferred production.
The appendix includes a data input sheet essential for collecting information needed for designing an ESP installation The data elements necessary for this design are categorized into six distinct groups.
1 General Information: Identifies the well and who col- lected the data on what date.
2 Wellbore Geometry: Describes well trajectory and completion equipment details.
3 Surface Information: Describes surface equipment and conditions.
4 Fluid Properties: Describes the fluid produced by the well and chemicals introduced for deposition prevention and corrosion.
Inflow characteristics provide essential data elements that detail a well's productivity, which is crucial for effective ESP design Ensuring the accuracy of this data is vital for optimal performance.
6 Design Criteria specifies the desired performance from the ESP installation.
The first five categories define the environment in which the ESP will operate The sixth category defines the operating parameters desired by the well operator
The data input sheet is essential for ESP design, containing the minimum required information Additional useful data for the ESP designer includes wellbore schematics, PVT reports, gas and oil composition reports, and water analysis reports Valuable insights can also be gained from ESP failure analyses, amp charts, and workover reports from the well of interest or nearby offset wells When including offset well information, it is crucial to specify the completion reservoir for both the well of interest and the offset wells.
A description of the data elements that comprise each cate- gory can be found in the appendix.
Estimate ESP Operating Requirements
To effectively select a pump, it is essential to estimate well performance, which determines the additional energy required, such as volumetric flow rate and differential pressure, to achieve the desired stock tank flow rate This assessment should incorporate current well data and anticipate future changes in reservoir or system performance over the expected lifespan of the Electric Submersible Pump (ESP), typically 3 to 5 years Key factors to consider include anticipated variations in average reservoir pressure, water cut, gas-oil ratio, required wellhead pressure, and inflow performance.
Nodal analysis techniques are highly effective for assessing well performance and evaluating sensitivity to temporal changes or fluctuations in available data These methods can be applied both numerically and graphically, offering valuable insights into the differential pressure or head required by the pump across a wide range of surface flow rates and varying conditions.
To select a pump for a specified stock tank production rate, it is essential to know the in-situ flow rate, as well as the inlet and discharge pressures at that rate Additionally, the fluid's specific gravity must be determined Once the differential pressure requirement is established, it can be converted to an equivalent head using the composite fluid specific gravity This information, along with the in-situ flow rate, aids in selecting the appropriate pump design and the number of stages needed to lift the fluid at the desired rate This method is applicable for both single-phase and multi-phase fluid applications, and utilizing computers for complex inflow performance and fluid property calculations is recommended in such cases.
Single operating point calculations can be effective for defining operating requirements, provided data is good, well behavior is stable over time and the produced fluid is a single phase fluid
In various applications, the procedure is often simplified by consolidating the additional energy required from the pump into a single term known as Total Dynamic Head (TDH) TDH represents the total of the net vertical distance the fluid must be lifted from the well's operating fluid level, the frictional pressure drop in the tubing, and the desired wellhead pressure By utilizing TDH along with the in-situ flow rate, one can effectively determine the suitable pump stage design and the necessary number of stages.
Pump intake pressure can be estimated using Productivity Index calculations derived from well tests or Inflow Performance Relationships These calculations are applicable in single-phase fluid scenarios or in multi-phase applications where the flowing bottomhole pressure exceeds the fluid's bubble point pressure However, caution is advised if free gas is present at the pump intake, as this occurs when the pressure falls below the bubble point, or if emulsions are involved.
4 API R ECOMMENDED P RACTICE 11S4 fluid is highly viscous (less than 40 SSU), use applicable computer software as hand calculations are not recom- mended
Pump inlet pressure is dependent on pump setting depth.
Pump inlet pressure refers to the flowing bottomhole pressure modified for variations caused by the static fluid gradient, which is influenced by the vertical distance from the pump inlet to the reservoir or pressure datum Additionally, it accounts for the minor frictional pressure drop in the casing between the perforations and the pump inlet, although this drop is typically negligible and often disregarded.
In ESP applications, the pump setting depth is often chosen arbitrarily, ensuring adequate submergence based on well deviation Alternatively, when a specific pump inlet pressure is required, the depth is calculated to achieve this pressure at the operating stock tank flow rate.
In most single-phase fluid applications, 100 psi inlet pres- sure is sufficient For unusual flow characteristics (such as high volume), pump Net Positive Suction Head requirements should be checked.
In gas applications, positioning the pump inlet at a greater depth is essential to maintain high inlet pressure, which minimizes gas evolution from the fluid prior to reaching the pump.
A simplified procedure for calculating pump inlet pressure is as follows:
Calculate Well Fluid Composite Gravity
[Fluid gradient] = [Water gradient x γ f ] where
[Water gradient] = 0.433 psi/ft or 9.8 kPa/m
Calculate Well Flowing Pressure at Desired Flow Rate (P wf )
P wf = P bhs – [q/J ] Calculate Pump Intake Pressure (PIP)
PIP = P wf –{[VD res – VD pump ] x [Fluid gradient]}
Calculate Intake volume at pump (q intake ) q intake = [Surface volume water xB w at pump depth]
+ [Surface volume oil xB o at pump depth]
Note: The total intake volume when below the bubble point must include the free gas volume.
Total Dynamic Head (TDH) is a crucial metric for applications involving the pumping of a single-phase fluid It represents the differential pressure or head that a pump needs to generate in order to elevate the fluid from its operating level in the well to the surface, while maintaining a specified flow rate.
Calculate Net Vertical Dynamic Lift (H D )
H D = VD pump – [PIP/Fluid Gradient]
Determine Friction Loss (H F )—refer to Hazen-Williams chart in Appendix E.
H F = MD pump /1000 x [Friction loss for given tubing size and production rate]
Calculate Wellhead Tubing Pressure Head (H T )
Calculate Total Dynamic Head (TDH)
6 Select Pump and Intake (see API RP 11S2)
When selecting a pump, it is essential to choose one that matches the desired production capacity of the well, relying on performance data from the manufacturer's catalog Additionally, various operating constraints must be considered, such as casing size, housing burst pressure limits, shaft strength, and the presence of corrosive, abrasive, or gassy environments.
Match Pump Performance to Well Performance
Submersible multistage centrifugal pumps feature rotating impellers attached to a shaft and stationary diffusers within an outer housing Each matched set of an impeller and diffuser is known as one stage The pump operates by rotating the impeller, which imparts kinetic energy to the fluid The stationary diffuser then redirects the fluid back to the shaft and the next impeller, converting kinetic energy into potential energy, resulting in increased head or pressure This process continues through multiple stages, with the head increase from each stage being independent of fluid density, while the pressure increase is proportional to the fluid's density or specific gravity.
The geometry of a pump design (e.g., number of vanes, vane angle, vane height, diameter, vane length, etc.) controls f w ×γ w
When sizing and selecting electric submersible pump installations, it is essential to consider the pump's performance, which is typically represented in a pump performance curve This curve illustrates the relationship between head (differential pressure), power requirements, mechanical efficiency, and volumetric flow rate, whether for a single-stage or multi-stage pump configuration.
Pump performance curves typically depict flow rate as the independent variable, while head, power, and efficiency are considered dependent variables However, it's important to recognize that this relationship can also be viewed in reverse The flow capacity of a specific pump, determined by its number of stages, is influenced by the differential pressure applied to it.
When selecting a pump, it is crucial to choose the right pump stage design that matches the desired flow rate Additionally, determining the appropriate number of stages is essential to achieve the necessary head or differential pressure, ensuring the well flows at the intended rate.
Care should be taken to insure that in-situ pump flow rates and not stock tank rates are used to properly select stage type and number of stages.
A simple process for pump selection consists of the follow- ing steps:
When selecting a pump stage type, it is essential to consider the casing size and desired flow rate, as multiple options may be available for a specific application The primary criterion for selection should be the pump's efficiency at the intended operating flow rate Ideally, the chosen pump should operate as close as possible to its best efficiency point and, at the very least, within the manufacturer's recommended operating range While many pumps can function outside this range, optimal performance is achieved within it, and this is where pumps are typically tested according to API RP11S2 Recommended Practices.
Determine Number of Stages Required
To determine the number of pump stages needed for a specific flow rate, first identify the Total Dynamic Head (TDH) and the type of pump stage Next, consult the head per stage that corresponds to the desired pump flow rate The required number of stages can then be calculated by dividing the TDH by the head per stage at the specified flow rate.
Number of stages = TDH/[Head per stage from pump curve at pump flow rate]
Pumps are typically available in a limited number of stages with specific housing lengths, allowing for assembly to meet the required total stages However, the available stages may not always align perfectly with the needs, often resulting in minimal error There are two main pump configurations: the floating stage design, where impellers float axially on the shaft and their thrust is absorbed by pads on the diffuser, and the fixed impeller design, where impellers are secured to the shaft, transferring thrust to the thrust bearing in the seal chamber It is advisable to consult with your pump manufacturer to determine the most suitable design for your application.
To determine the total motor horsepower needed for the pump, first, read the horsepower per stage from the curve at the desired flow rate Then, calculate the total horsepower by multiplying the horsepower per stage by the number of stages and the specific gravity of the composite fluid.
[HP required] = [HP per stage] x [Number of stages] x γ f
This information should be used in selecting a proper motor HP size.
Limitations and Considerations
Besides hydraulic performance, several other physical lim- itations must be considered, even in simple applications.
It is essential to verify that the horsepower transmitted by the pump shaft, which is determined by the torque at a specific speed, remains within the acceptable limits specified in the manufacturer's catalog Surpassing these limits may lead to premature failure of the pump.
To ensure safety, it is crucial to monitor the pump differential pressure during both operating and shut-in conditions, ensuring it remains within burst pressure limits The maximum pump head can be calculated by taking the shut-in head per stage from the zero flow rate point on the pump head capacity curve and multiplying it by the number of stages For applications involving extremely high differential pressures, various designs are available Exceeding the specified limits may lead to premature equipment failure, so it is advisable to consult your ESP manufacturer for accurate equipment ratings.
[Shut-in pump head] = [zero flow head per stage] x
[Differential pressure] = [Shut-in pump head] x
Calculating the pump shaft thrust is essential for selecting the appropriate thrust bearing design in the seal chamber section The thrust originates from the pump and varies based on the number of stages and the mechanical configuration of the pumps A common type of pump is the floating impeller pump, where the impellers can move axially, allowing individual diffusers to carry the thrust generated by each impeller Additionally, the differential pressure acting on the pump shaft's cross-sectional area creates a separate thrust load that the seal chamber section thrust bearing must accommodate It is crucial to calculate this load under worst-case, shut-in conditions.
[Floater pump thrust] = [Pump differential pressure] x
[Shaft area from manufacturers catalog]
Thrust calculations for fixed or compression type pumps should be based on data provided by pump manufacturers and worst case operation (e.g., shut-in).
Variable speed drives enhance the flexibility of ESP installations but complicate pump selection They leverage the behavior of centrifugal pumps at varying speeds, guided by affinity law equations It's essential to start the design at the highest frequency to ensure the equipment can manage scenarios like lifting kill fluid during start-up The optimal efficiency should be aimed for the frequency expected for the longest operational duration Although manual calculations are possible, utilizing computer software is advisable for converting pump performance data across variable speeds.
6.2.5 Gassy Wells/High Vapor-liquid Ratios
Hand calculations are insufficient for fluid flow streams with significant vapor content at the pump inlet In such cases, it is essential to utilize computer software for complex inflow, multiphase flow calculations, and pump performance assessments based on PVT data and correlations Care must be taken to ensure that pumps are not sized solely for normal operating conditions, as they must also be capable of handling heavy kill fluids or completion fluids during startup.
When managing gas in fluid systems, there are two primary design options: utilizing a pump or separating the gas from the flow before it enters the pump Specialized pumps are available to accommodate high levels of free gas, so it's essential to consult with the manufacturer regarding the equipment's free gas limitations Another effective design is the tapered pump, which features multiple volumetric stages, allowing for large flow capacity at the bottom and smaller flow capacity at the top As the compressible fluid moves through the pump, its volume decreases.
Gas separators are essential components, and it's important to consult your manufacturer to identify the most suitable type for your specific application Additionally, users should assess whether the separator necessitates extra horsepower for operation, as this information is crucial for accurately sizing the motor.
When selecting an abrasion-resistant pump trim, it is crucial to consider the presence of abrasive solids like sand, as well as their grain size and shape Various designs are available, and manufacturers can assist in determining the appropriate bearing and material options to reduce abrasive wear The type and volume of sand significantly influence the required materials and their arrangement within the pump.
Checklist
To optimize pump performance, first select the appropriate pump stage design based on the desired flow rate Next, calculate the number of stages needed and the horsepower required for the pump It's crucial to verify that the pump shaft and housing strengths meet acceptable standards Finally, ensure that the metallurgy chosen is suitable for the produced well fluid.
When selecting a motor for a pump, it is crucial to ensure it provides the necessary horsepower to operate the pump, seal chamber, and gas and water separator, if applicable Key factors to consider include temperature limitations, casing size, cable length and size, motor terminal voltage, motor current, and the specific operating conditions of the well It is essential to analyze the horsepower requirements alongside the well conditions against catalog listings to determine the most suitable option, whether that be a smaller catalog horsepower, a de-rated larger horsepower, or the closest catalog horsepower Each choice will have varying cost implications.
When selecting the motor nameplate voltage, it is essential to consider cable selection, as varying motor voltage ratings necessitate different current levels, affecting cable loss and overall running costs Additionally, a realistic estimate of runtime should be calculated to combine running and initial costs, enabling a comprehensive cost comparison for each scenario evaluated.
R ECOMMENDED P RACTICE FOR S IZING AND S ELECTION OF E LECTRIC S UBMERSIBLE P UMP I NSTALLATIONS 7
Checks should be made for each case to ensure the motor will start and attain its proper running speed.
Match Motor Performance to Pump/Well Performance
Submersible pump motors have many similarities and many differences from a “standard” surface motor A detailed description can be found in Appendix C
To determine the necessary motor horsepower for your application, first calculate the required pump horsepower and, if applicable, the horsepower for the gas separator Additionally, estimate the horsepower needed for the seal section as outlined in Section 8 Combine these values to find the total motor horsepower required Collaborate with your ESP vendor and consider the limitations and factors discussed in the following sections to select the appropriate motor for your specific needs.
Limitations and Considerations
7.2.1 Motor OD vs Casing ID
Generally speaking, the motor outside diameter is limited by the casing I.D or in some cases by the pump type selected.
When operating a motor in deviated wells, it is crucial to account for the well deviation radii, also known as dogleg severity, as well as the motor's length Additionally, it is important to ensure that the selected motor can navigate bends during installation, taking into consideration the motor's outer diameter in relation to the casing.
The ID ratio is essential for determining the optimal fluid rate around the motor To ensure effective motor cooling, it is advisable to maintain a minimum fluid velocity of 1 ft/s, while also adhering to a maximum value for efficiency.
In abrasive environments, a speed of 12 ft/s (or 7 ft/s) is recommended to avoid housing erosion, especially when dealing with gassy or poorly conductive fluids Once the motor diameter is determined, it is rare for the required horsepower to align with the manufacturer's catalog specifications Therefore, a choice must be made between selecting a motor with a higher or lower horsepower rating than what is actually needed.
7.2.2 Well Temperature vs Motor Cooling
When selecting a submersible motor, it's crucial to pay attention to the bottom hole temperature (BHT) specified by manufacturers, as it indicates the maximum ambient temperature for operation However, the internal operating temperature of the motor, which includes the temperature rise during load conditions combined with the ambient temperature, is the most critical factor to consider for optimal performance.
Excessive operating temperatures in motors can significantly reduce the lifespan of insulation and bearings, leading to mechanical issues due to thermal expansion Manufacturers typically determine the expected temperature rise through tests conducted in controlled factory settings, which often do not accurately reflect actual well conditions.
The operating temperature of a motor in a well is influenced by several key factors, including the required horsepower, bottom hole temperature (both flowing and static), water cut, and the API gravity of the oil Additionally, the rate of fluid flow and gas flow through the motor, the use of a variable speed drive and its frequency, the presence of scale, special coatings on the motor housing, voltage unbalance, and the motor's efficiency at the operating load point all play significant roles in determining the motor's temperature.
To optimize the ESP design, users should collaborate with the manufacturer to integrate necessary correction factors In benign well conditions, the manufacturer may propose a lower catalog horsepower rating than calculated Conversely, for severe or uncertain well conditions, a higher catalog horsepower rating may be recommended to ensure the motor operates effectively in a derated condition.
7.2.3 Motor Terminal Voltage (Nameplate Voltage) and Cable Size
Submersible motors operate at their specified nameplate voltage, necessitating the calculation of voltage drop in the connecting cable using the nameplate amps This voltage drop must be added to the motor terminal voltage to ascertain the surface voltage Choosing the appropriate cable size involves balancing cost considerations and the motor's ability to reach operational speed Users should conduct a cost analysis that includes cable loss expenses over the system's expected lifespan, initial costs of various cable sizes, and any additional costs associated with higher voltage motors, switchgear, or transformers After selecting the cable size, it is crucial to verify that the motor can achieve the required speed.
When starting a motor, the initial current can be several times greater than the current during normal operation, leading to a significant voltage drop in the cables This drop can result in the motor terminal voltage being too low to generate sufficient torque for starting or reaching operational speed Generally, a minimum of 50% of the nameplate voltage at the motor terminal is necessary for successful starting This issue is more prevalent in high amperage motors or those with long cable runs Therefore, it is essential to verify the starting capabilities under actual conditions with the motor manufacturer.
To overcome starting limitations, consider three effective strategies: first, utilize a larger diameter cable to minimize voltage drop during startup, although this may increase cable costs; second, opt for a higher voltage motor, which allows for lower current at the same horsepower; and third, implement a Variable Speed Drive (VSD) that provides adequate voltage boost, enabling higher starting torque with reduced current at lower frequencies.
To assess motor starting capability, it is essential to conduct an electrical system study that includes an analysis of the surface transformer and the generator, if applicable, to identify any limitations.
A long cable provides the advantage of a "soft start" by minimizing the inrush or starting current, allowing the motor to reach operational speed rapidly due to the low inertia of the motor and pump Utility companies frequently recognize this benefit of using longer cables.
“soft start” alternative in lieu of installing a standard soft start package.
Checklist
To ensure optimal motor performance, first calculate the total horsepower needed by summing the required horsepower for the pump, gas separator, and seal sections Next, ascertain the appropriate motor diameter and verify the fluid flow velocity to facilitate effective motor cooling It's crucial to confirm that the estimated winding temperature remains within the manufacturer's specified limits Finally, evaluate the motor's starting capability to ensure reliable operation.
8 Select Seal Chamber Section (see API
When selecting the seal chamber section from the manufacturer's catalog, it is essential to consider compatibility with the pump and motor, casing clearance during cable installation, and the choice between labyrinth or bladder type designs Additionally, factors such as fluid expansion capacity, temperature ratings, and chemical exposure ratings play a crucial role in the selection process.
In a standard ESP setup, the motor is positioned beneath the assembly, with the seal chamber situated between the motor and the pump Alternatively, pressure equalization and volume change accommodation can be placed in different locations, such as at the bottom of the motor in a "water well" type motor configuration.
In an inverted ESP system where the motor is positioned above the pump, it is essential to place the seal section between the motor and the pump To effectively manage volume changes and pressure equalization, it may be beneficial to incorporate a device above the motor Special installation procedures are necessary to prevent motor oil loss during the installation of these systems.
The seal chamber section is typically chosen to match the nominal diameter of the pump However, an alternative diameter for the seal chamber may be utilized if the shaft, thrust, and oil expansion capacity are sufficient.
Match Seal Chamber to Pump/Motor/Well Performance
Selecting the appropriate seal chamber section is crucial and should be done after specifying the pump and motor, ensuring it aligns with the application requirements Key considerations include proper head and base flange designs for connection, adequate clearance for the motor flat cable, and sufficient shaft strength to handle maximum torque Additionally, the chamber must accommodate thermal cycling, house a thrust bearing capable of managing axial thrust and high temperatures, and contain the necessary number of durable shaft seals For bag-type seals, elastomers must resist the application's temperature and chemicals, while the chamber should be filled with the correct motor oil Finally, the design must be compatible with the application, providing the desired level of protection based on cost and severity.
Limitations/Considerations
When selecting materials for seal chambers, it is crucial to consider the operating temperature, which should align with the intended application Several factors influence the actual operating temperature, including bottom hole temperature, motor temperature rise, heat transfer characteristics of the well fluid, fluid velocity through the seal chamber, and the temperature increase of the fluid as it moves past the motor Typically, the operating temperature of the seal chamber section, excluding the thrust bearing, is 25°F to 50°F higher than the well temperature.
Applications involving heavy crude, high oil cuts, low fluid flow velocity, or extended motor lengths can elevate the operating temperature of the seal chamber section It is advisable to consult the ESP manufacturer to determine the approximate operating temperature for each specific application.
When selecting materials, it is crucial to consider the full range of temperatures they will encounter throughout their lifecycle, including storage, shipping, testing, and installation Additionally, it's important to note that an elastomer designed for high temperatures may not be suitable for applications involving low temperatures.
There are many different formulations with widely diver- gent properties and performance Generally, ESP manufactur-
When selecting and sizing electric submersible pump installations, it is crucial to consider the elastomer formulation used in various components, as different formulations are available to accommodate varying well conditions The typical maximum service temperatures for several elastomers should be taken into account to ensure optimal performance.
It is important to ensure that the specific formulations selected are compatible with the operating environment Each application should be reviewed with the ESP manufacturer for specific recommendations.
When choosing oil for the seal chamber, it's crucial to consider the operating temperature, as higher temperatures lead to decreased oil viscosity At the operating temperature, the oil must maintain adequate viscosity to ensure proper lubrication of the seal chamber bearings.
Selection of oil types used to accommodate a range of operat- ing temperatures should be based on the ESP manufacturer’s recommendations to ensure proper bearing operation.
All phases of operation must be considered when evaluat- ing the required shaft torque capacity Maximum torque may occur during start-up or when pumping heavy fluids.
Shaft strength is dependent on the smallest cross-section
(usually the spline root) and material yield strength Select a seal chamber section with a shaft design according to manu- facturers’ recommendations.
8.2.3 Thrust Bearing Load Rating vs Thrust
The required thrust bearing capacity will be determined primarily from the thrust characteristics of the pump, which is unique to each application
The thrust load rating for the seal chamber section should be greater than the highest possible thrust load for the application.
Typical pumps use floating impeller designs The primary thrust load produced which the seal chamber section must carry is given below.
Down Thrust = [pump discharge pressure – PIP] x pump shaft cross-sectional area
Evaluate the worst case scenario when the flow rate is zero to simulate producing against a closed production valve.
Note: The shaft thrust load will be greatly increased if impellers seize to the shaft
Fixed Impeller Pumps Consult ESP manufacturer for down thrust values.
When considering thrust operations, it is essential to account for all phases, including the pumping of heavy fluids Thrust bearings come in various configurations and materials, as outlined in API RP 11S Commonly used materials for bearing surfaces include Babbitt, which is suitable for temperatures up to 300°F (149°C), and bronze alloys for applications exceeding 250°F Additionally, several plastic formulations have been developed for thrust bearings, capable of handling high loads and temperatures It's important to note that the capacity of a thrust bearing may decrease at elevated temperatures or if rotated in the opposite direction of its design Always consult the manufacturer for specific recommendations.
8.2.4 Protecting Against Corrosion and Erosion
When selecting materials for the wetted components of the seal chamber section, it is essential to consider fluids such as water, oil, gas, and brine The wetted parts include housings, heads, bases, shafts, and shaft seals, which are typically made from carbon steel or high chrome alloys to enhance corrosion resistance Additionally, special coatings can be applied for further protection For shafts, corrosion-resistant materials like monel and stainless steel are commonly utilized, while metallic components of mechanical face seals are generally made from stainless steel and bronze, with monel available for extra corrosion resistance.
Stainless steel is commonly utilized for ancillary components such as bladder clamps and relief valves, while Inconel® is favored for its excellent corrosion resistance, making it ideal for actuating springs in relief and check valves, as well as rotating seals.
The metal components of the seal chamber section should be selected so that destructive galvanic corrosion cells are not formed between adjacent components.
When selecting materials, it is crucial to evaluate the impact of produced and treating fluids, including corrosion inhibitors and acids For instance, certain amines found in inhibitors can significantly accelerate the degradation of specific elastomers.
In well fluids containing solids, it is essential to use hard mechanical seal faces to prevent excessive wear For abrasive conditions, tungsten carbide and silicon carbide seal faces are commonly recommended.
8.2.5 Bladder and Labyrinth Seal Sections
Tandem seal chamber sections consist of multiple seal chambers arranged in series to enhance motor protection by increasing the number of protective barriers These units are particularly beneficial in harsh environments, where installation and maintenance costs are high, or in applications where extended operational lifespans are anticipated.
10 API R ECOMMENDED P RACTICE 11S4 tion has a thrust bearing, the upper unit will carry the pump thrust unless special consideration is given to shaft spacing or shimming.
The frequency of starts and stops (cycles) in an ESP operation directly impacts the thermal cycles that the seal chamber section must endure For applications with expected frequent cycling, bladder-type seal chamber sections are recommended.
In certain applications, bladder and labyrinth seal chamber sections are utilized together For deviated wells, it is essential to position the bladder seal chamber section on top to safeguard the labyrinth seal chamber motor oil from contamination Conversely, in vertical wells, placing the bladder seal chamber section at the bottom enhances its protection against chemical damage from the well fluid.
Seal chamber section designs can incorporate multiple chambers within a single unit to perform the functions of tandem seal chamber sections The arrangement of labyrinth and bladder chambers in these designs follows the same criteria as that of tandem seal chamber sections.
In deviated wells, the effective oil expansion capacity of a labyrinth seal chamber section diminishes For wells with any section deviating more than 30 degrees from vertical, bladder-type seal chamber sections are recommended.
Checklist
To ensure optimal performance, first determine the seal chamber section outer diameter and flange size according to the pump and motor specifications Next, assess the expansion volume needs based on the motor horsepower and the well's temperature conditions It's essential to evaluate the required shaft torque capacity and approximate operating temperature Additionally, consider any special conditions and operating temperatures to select appropriate elastomers, shaft seals, and materials Calculate the operating and no-flow thrust loads to choose the suitable thrust bearing Finally, select the design style and configuration based on the specific application and desired level of protection redundancy.
9 Select Cable (See API RPs 11S5 and 11S6)
The selection of cable conductor size is determined by the voltage and amperage needs of the down hole motor, as well as voltage losses along the cable length and the well-bore clearance Additionally, the cable insulation must be suitable for the harsh conditions within the well, while the armor is chosen to safeguard and encase the cable core.
The selection of cable type is crucially influenced by specific well conditions, making accurate well information essential The bottom hole temperature is vital for calculating the cable's operating temperature, which in turn dictates the necessary insulation and jacket materials Additionally, the composition of fluids and gases in the well affects its corrosiveness; for instance, the presence of H₂S may necessitate the use of leaded cable.
When sizing and selecting electric submersible pump installations, it is crucial to consider the use of special alloys in wells with highly corrosive fluids Additionally, in wells with a high gas-to-oil ratio (GOR), special containment may be necessary to prevent cable insulation or jacket decompression failure caused by fluctuations in well pressure.
An economic comparison should be made between the cable conductor size and the cost of the cable power losses.
This analysis should evaluate whether lower power costs over the life of the cable will offset the higher initial purchase price of a cable with larger conductors.
Match Cable to Pump/Motor/Well Performance
To simplify the complex process of matching cables, pumps, and motors during unit sizing, various programs have been developed These tools are offered by both pump manufacturers and select third-party vendors.
API RPs 11S5 and 11S6 also provide detailed information to help select cables, with explanations, tables and charts to guide a person through the basic steps of cable selection.
Limitations/Considerations
Well temperature refers to the ambient temperature surrounding the cable at the bottom hole, while conductor temperature is the surface temperature of the current-carrying conductors The cable operating temperature is influenced by both well temperature and conductor temperature, and it can exceed the bottom hole temperature by over 30°F It is crucial to ensure that the conductor or cable operating temperature does not surpass the manufacturer's specified temperature rating when selecting cable.
Section 7.2.3 highlights the importance of selecting the appropriate cable size to minimize power loss and ensure adequate voltage at motor terminals during startup In addition to voltage constraints, temperature limitations also play a crucial role, influenced by the cable's operating temperature and insulating material The operating temperature is determined by ambient conditions and the cable's temperature rise due to copper losses Manufacturers provide curves that illustrate the relationship between cable current, bottom hole temperature, and operating temperature, which may necessitate using a larger cable size than what cost analysis alone would suggest.
9.2.2 Cable Size vs Voltage Loss
Smaller conductor sizes lead to higher voltage drops per unit length and increased power losses due to heat, which can significantly raise operational costs, particularly when kilowatt prices are high Excessive voltage drops may prevent motor startup, necessitating a careful consideration of the trade-off between the higher initial costs of larger conductors and the available space within the casing's drift diameter for accommodating these larger cables.
9.2.3 Cable Dimensions vs Diametrical Clearances
When dealing with highly deviated wells, it is essential to consider additional clearance The implementation of protective cable clamps is advisable, particularly if there has been previous cable damage There are two available cable configurations: flat and round While round cables offer superior electrical balance, flat cables are typically preferred in wellbores with restricted diametrical clearances.
As temperature increases, the lifespan of cables decreases The two primary types of insulation are thermoplastic and thermoset materials Polypropylene, the most widely used thermoplastic, typically operates up to 205°F, but can reach 225°F with lead extrusion protection In contrast, thermosetting insulation compounds, primarily made from EPDM (ethylene propylene diene monomer), can endure temperatures of 400°F or more, depending on their specific properties Nitrile rubber jackets are limited to 280°F, while EPDM jackets can withstand temperatures up to 400°F.
Exposed cables can suffer from decompression damage due to rapid pressure changes in wells, particularly during pump operations This damage occurs when gases dissolve into the insulation and jacket, expanding quickly as pressure decreases, leading to tears and micro-voids To mitigate this risk, it is essential to use special containment methods such as braids, tapes, or armor.
Polypropylene insulation is adversely affected by various well conditions, including exposure to light ends of crude oil and aromatic treatment chemicals, which can soften the material and increase its vulnerability to degradation under high temperatures and pressures Additionally, the presence of carbon dioxide, along with temperature and other hydrocarbon gases, can result in premature stress cracking, particularly in CO2 floods with high gas-to-oil ratios External forces from clamps or tight well conditions near upper temperature limits can lead to deformation and early failure To mitigate accelerated aging from contact with copper, it is essential to incorporate stabilizers in the insulation and apply tin coating to the copper.
Thermoset Cables: EPDM is the most common ther- moset insulating compound used in ESP cables EPDM mate-
EPDM cables are recommended for their broad service temperature range, maintaining flexibility in sub-zero conditions and effectively functioning in geothermal applications Although gases do not degrade EPDM, it is crucial to ensure proper containment to avoid explosive decompression While EPDM exhibits good chemical resistance, exposure to oil and aromatic hydrocarbons can lead to softening and swelling The longevity of EPDM cables largely depends on their environmental protection.
Cable Jackets: Jackets are protective coverings used to mechanically shield the insulation from the downhole envi- ronment The most common cable jacketing compounds are
Nitrile and EPDM are two materials chosen for their economic viability and performance characteristics Nitrile compounds provide exceptional oil resistance but may experience embrittlement over time In contrast, EPDM maintains its flexibility and structural integrity in extreme temperatures, including subzero and geothermal conditions, although it has lower resistance to oil and various chemicals compared to Nitrile.
Tapes and braids serve as supplemental layers that enhance the strength and protection of cable components, with tapes applied directly over insulation in round cables and over jackets in flat cables Barrier materials like extruded PVDF and FEP provide fluid barriers, chemical resistance, decompression resistance, and increased electrical strength Additionally, lead sheathing offers excellent protection against fluids and gases, particularly in H₂S applications, though it is heavy, can work-harden and crack, and is vulnerable to mechanical damage For comprehensive details on these materials, consult API RP 11S5.
Armor serves as the protective outer layer for cables, ensuring mechanical safety during their installation and removal from wells In round cable designs, it offers essential strength to prevent cable swelling during decompression as the cable is extracted The most prevalent materials for armor in oil well applications include galvanized steel, stainless steel, and Monel.
In harsh environments with high levels of CO₂, H₂S, and brine, Monel armor is recommended Although 316L stainless steel is suitable for many corrosive well applications, it may experience stress cracking in chloride concentrations exceeding 30,000 ppm at temperatures above 160°F Galvanized steel is typically the preferred initial choice due to its cost-effectiveness, but thicker galvanized metal should be evaluated before opting for more expensive armor in corrosive settings.
Section 7, provides detailed information on cable armor
9.2.5 Motor Lead Extension and Pothead
Potheads serve as electrical connectors for the motor, effectively isolating the motor oil from the well fluid The motor lead extension is a specialized power cable that runs from the pothead on the motor to the area above the pump, where it connects with the main power cable Due to the restricted space between the pump housing and the well casing, a low-profile flat cable is typically required in this section.
Checklist
To ensure optimal performance in cable installation, first, identify the necessary cable configuration, whether flat or round Next, select the appropriate jacket materials Collaborate with the ESP vendor to determine the most economical conductor size It is crucial to verify that the cable's voltage and temperature limitations are not exceeded, and to ensure that the voltage drop does not hinder the motor's starting capability.
10 Select Switchboard/VSD and Transformer (see API RPs 500 and 11S3)
When selecting surface equipment like switchboards, variable speed drives (VSD), transformers, and surface cables, it is crucial to ensure they can provide the necessary voltage and amperage for the downhole motor Factors such as operating in offshore or desert environments also play a significant role in the choice of equipment.
Match Surface Electrical Equipment to Motor/Pump/Well Performance
Primary power received at the well site will be in the form of high voltage (i.e., 7200, 12470, 14400, 24950, etc.) or low volt- age (380, 440, 460, 480, etc.) A constant frequency of 60 Hz
In various countries, a power supply of 50 Hz is commonly used, but voltage and frequency can differ by region It is crucial for the power source and surface equipment to deliver three-phase power and the necessary surface voltage to the ESP motor, as indicated in Equation 10.1a Supplying the correct voltage ensures that the motor receives the required current, which is vital for maintaining high efficiency.
Surface Voltage = Motor Voltage + Cable Voltage Drop
When high voltage power is supplied, a step-down trans- former is required to provide the proper voltage at the motor.
A low voltage power supply necessitates the installation of transformers to elevate the primary voltage to meet surface voltage requirements Transformers are primarily rated in Kilowatts-Volts-Amperage (KVA), and it is crucial that the calculated KVA value does not surpass the transformer’s rating.
R ECOMMENDED P RACTICE FOR S IZING AND S ELECTION OF E LECTRIC S UBMERSIBLE P UMP I NSTALLATIONS 13 phase transformers have a total KVA rating of the sum of their individual ratings.
Limitations/Considerations and Definitions
To supply the appropriate voltage to a motor, a step-down transformer is essential when high voltage power is provided There are three configurations available for transformers, including three single-phase and one three-phase standard, all of which are dual wound and designed for step-down applications It is important to avoid overloading transformers, and specific ratings are necessary for use in desert conditions Additionally, offshore applications may necessitate the use of special non-flammable oil to comply with safety standards.
Class 1 Division 2 requirements for transformers Dry type transformers are sometimes used in offshore applications.
Low voltage power requires transformers that will increase the primary voltage to match the surface voltage requirement.
When the primary power is at a low voltage of 480V and the control panel also operates at low voltage, but the motor requires a higher voltage, a step-up transformer can be installed between the control panel and the downhole motor For variable speed controllers, both the input and output are typically low voltage (such as 480V), necessitating a specialized step-up transformer to elevate the voltage to the level required by the motor.
The three-phase autotransformer is utilized to step up distribution voltages of 440 or 480 V, specifically for applications that require 1000 V or less and do not involve downhole monitoring systems It is important to avoid overloading transformers, and special ratings are necessary for desert environments Additionally, offshore applications may necessitate the use of non-flammable oil to comply with Class 1 Division 2 transformer requirements, while dry type transformers are occasionally employed in these settings.
10.2.3 Fixed Speed Controller, “Control Panel” or
All applications, except where variable speed drives are used, will require a control panel Control panels provide four basic functions:
1 Switchgear to start and stop the motor.
2 Current overload and underload motor shut-down protection.
3 Current monitoring for predicting downhole conditions.
For high voltage applications, it is essential that the control panel is positioned on the secondary side of the step-down transformer This panel must have a rating that meets or exceeds the calculated surface voltage and amperage needed by the motor.
When supplying low voltage power, it is crucial to position the control panel on the primary side of a step-up transformer and ensure it is rated for the necessary higher amperage For generators paired with switchboards, the KVA rating must meet or exceed the sum of the motor's full load KVA, surface load KVA, transformer loss KVA, and cable loss KVA However, a generator capable of handling the full load continuously may not provide sufficient starting KVA to accelerate the motor to full speed Traditional thumb rules based on motor horsepower for determining the required generator kW rating are no longer reliable due to the varying design characteristics of modern generators Therefore, consulting the ESP manufacturer for an evaluation is essential, as generator selection should be tailored to its specific electrical characteristics.
There are two main types of switchboards: electromechanical and solid state The electromechanical switchboard features a manual disconnect switch, magnetically operated motor controller, and various relays for protection, while a Bristol recording ammeter tracks operational metrics In contrast, the solid state switchboard offers enhanced protective functions, operating parameters, and SCADA capability Notably, the electromechanical version supports a DC control scheme, potentially allowing for a smaller generator in certain applications Both switchboard types deliver equal reliability when properly maintained and can be customized with various accessory packages.
10.2.4 Variable Speed Control Panels or “VSD”
Flexibility in flow and lift can be realized through the use of a variable speed motor controller When a variable speed controller is used, a fixed speed controller is not required A
Variable speed controllers typically require an input of 460 – 480 V at 60 Hz or 380 – 400 V at 50 Hz, with the frequency directly affecting the voltage output and motor RPM This adjustment also alters the pump's capacity, as detailed in Appendix D regarding the affinity laws A Variable Speed Drive (VSD) modifies the fixed frequency of incoming AC power to a range of 30 – 90 Hz, thereby enhancing pump performance; higher frequencies result in improved operational efficiency.
KVA 1.732 Surface volts( )(Actual Motor AmpLoad)
Figure 2—Electrical Configuration Using a Step-up Transformer
Figure 3—Electrical Configuration Using a Fixed Speed Controller
When sizing and selecting electric submersible pump installations, it's important to consider the pump speed, as higher speeds can lead to increased flow and head However, this also results in a higher horsepower requirement The performance variations in centrifugal pumps can be estimated using the affinity laws, which relate to the revolutions per minute (RPM) of the pump.
Since the ratio of the RPM is the same as the ratio of the frequency,
The affinity laws relate directly to electrical parameters like frequency in Hertz, allowing for the adjustment of pump performance from a known value at 60 Hz to other frequencies.
Variable Speed Drives (VSDs) provide significant flexibility in the application of Electric Submersible Pumps (ESPs) to wells As illustrated in Figure 4, adjusting the frequency or speed of the pump can substantially influence its performance Consequently, a single pump and motor configuration can effectively accommodate a broader spectrum of operational conditions when utilizing a VSD.
Variable Speed Drives (VSDs) can enhance well productivity, especially when the output is uncertain or when adapting to fluctuating well conditions over time By integrating a downhole pressure sensor with an Electric Submersible Pump (ESP) and utilizing a VSD, operators can optimize well production through closed-loop pressure control, ensuring a consistent pump intake pressure.
Adjusting the frequency of the ESP motor directly influences its horsepower output, with an increase in frequency leading to a proportional rise in horsepower A higher frequency results in faster motor rotation, enabling the motor to produce greater horsepower.
This happens because the VSD output maintains a constant volts-to-hertz ratio.
Graphically it would look like this for a 200-HP, 60-Hz motor:
The pump's required brake horsepower (BHP) rises with the cube of the frequency ratio, leading to a specific frequency at which the BHP demand surpasses the horsepower (HP) provided by the motor This critical threshold is known as the maximum limiting frequency (F max), as illustrated in Figure 6.
Operating the ESP above F max will overload the motor and cause it to overheat, shortening its life
The conversion process from AC to DC and back to AC using a Variable Speed Drive (VSD) can lead to voltage and current signal distortions known as "harmonics" and "ringing," which is a form of voltage overshoot Unlike the smooth curve of sine wave power, the output from a VSD may not provide a consistent waveform However, there are models available that incorporate filters to emulate sine wave output, effectively eliminating these harmonics.
Special considerations should be made when running a VSD on a generator set because harmonics can damage the
Figure 4—Fixed Frequency and Variable Frequency Pump Performance Curves
H Hz = H 60×(Hz 60⁄ ) 2 BHPHz = BHP60×(Hz 60⁄ ) 3
To ensure optimal performance and safety, it is crucial to implement recommended practices for API 16, particularly regarding control circuits and generator overload While power systems typically manage excess current effectively, generators are often designed with a capacity that closely aligns with actual load demands.
Optimization and Economics
Table 1—Comparison of VSDs vs Fixed Controllers
Flexibility It provides the means to match the well inflow within a wider operating range by changing the operating frequency.
It operates at the fixed frequency of the power supply grid (no flexibility).
Optimizing well production involves utilizing closed loop pressure control to maintain the pump intake pressure at a minimum level, while also offering various frequency and current operating modes.
The system features a soft start mechanism that initiates operation smoothly, gradually increasing to the designated operating frequency Operators can adjust the ramp speed rate to suit specific applications.
It is a DOL start which can place more stress on the motor, power system and cable during start- up.
Electrical disturbances, such as harmonics and ringing, are generated in current and voltage signals, affecting both the power supply and the downhole system The operation of an Electric Submersible Pump (ESP) with a Variable Speed Drive (VSD) produces these disturbances, even at the standard frequency of 60 Hz Additionally, harmonic heating from VSD operation contributes to the overall increase in the internal motor operating temperature.
It does not generate electrical disturbances except during starts and stops Power system disturbances (sags, surges and voltage imbal- ances) are passed on to the motor.
Under normal operating conditions, systems utilizing a permanent Variable Speed Drive (VSD) experience higher power consumption due to two main factors: the inherent inefficiency of the VSD compared to a switchboard, as it converts input AC power to DC and then back to AC at a new frequency, and the additional harmonics generated by the VSD, which lead to increased heat production Furthermore, if the power supply for the Electric Submersible Pump (ESP) is an isolated generator set, it must be oversized to accommodate the demands of VSD operation.
All the energy lost against a choke can be reclaimed by a VSD.
In typical scenarios, a switchboard is the more cost-effective choice for operations However, under specific conditions like choked or back-pressured tubing at the surface, the operating costs associated with a switchboard can exceed those of a Variable Speed Drive (VSD).
If the power supply for the ESP is an isolated gen- set, it needs to be oversized for VSD operation.
Qualified personnel from both the Operating Company and the Service Company must undergo specialized training in Variable Speed Drive (VSD) operation Maintenance of VSDs should only be conducted by certified technicians to ensure optimal performance and safety.
Most Operating Company Electrical Techni- cians are generally accustomed to switchboards.
Only qualified technicians should perform main- tenence of switchboards.
The initial investment for a Variable Speed Drive (VSD) is significantly greater than that of a traditional switchboard When a high voltage power supply grid is accessible at a well site utilizing a VSD, both a step-down transformer and a step-up transformer are necessary, with the step-up transformer needing to be rated for VSD applications.
When the design frequency exceeds 60 Hz, the expenses associated with the pump and the larger motor needed for equivalent flow and head will be lower compared to those required for a 60 Hz switchboard.
The initial expense of a switchboard is lower than that of a Variable Speed Drive (VSD) Utilizing a switchboard typically necessitates only a single set of transformers, unless local regulations, such as those in California, mandate the use of low voltage switchboards and an additional set of transformers.
In the absence of grid power at the well site, an oversized generator set (gen-set) is required to supply power, accommodating either a variable speed drive (VSD) or a switchboard, each necessitating this sizing for distinct reasons.
The choice of a switchboard or Variable Speed Drive (VSD) as the permanent starter and control system for Electric Submersible Pumps (ESP) is influenced by various factors, including the location of the wells, the operating policies of the company, the available power supply, the operating environment, and the availability of well information such as productivity index (PI).