Methodology and procedure for selecting an electric centrifugal pump for a well. The main provisions of the methodology for selecting ESP to an oil well

The power transformer is suitable.

We check the transformer for current, we find the current in the secondary winding:

, (2.12) where

For normal operation, the following conditions must be met:

I dv< I ном (2.13)

25.5A<35,29А

Current transformer is suitable. We choose the transformer TMPN 63/3 UHL1.

The table below shows the passport data of the selected transformer.

Table 2.3

2.3 Feasibility study of the selected engine type

1. Calculate the reduced losses of the first engine:

We find the active power losses I of the engine according to the formula:

, (2.14)

The reactive load is determined by the formula:

Due to the fact that reactive power compensation is required, the economic equivalent of reactive power K eq, kW / kvar is found by the formula:

, (2.16)

where - specific reduced losses;

The value of the coefficient of deductions (for static

capacitors p=0.225);

Capital investment for the installation of capacitors

(K uk = 616.9 rub/kvar);

The cost of 1 kW/year of electricity;

Specific losses ();

,

(2.17) where is the cost of 1 kWh of electricity ( );

T g - the number of hours of operation of the installation per year (for a three-shift

work );

The reduced active power losses are found by the formula:

, (2.18)

2. Calculate the reduced losses of the second engine:

We find active power losses:

Determine the reactive load:

We find the reduced active power losses:

3. Determine the annual costs:

4. Determine the degree of efficiency:

; (2.20) where р and –

normalized efficiency ratio;

Consequently, the PED32-117LV5 engine is more economical with the given well and pump parameters, it requires less money to maintain, and its energy performance is better. So, we choose the PED32-117LV5 engine.

We check the power transmitted from the ground:

; (2.21) where - sweat

ri power in the cable, kW;

30.77 kW 32 kW

This means that the selected engine is suitable for power losses transmitted from the ground.

We draw up a table of a feasibility study for the selected type of engine.

Table 2.4

Under the selection of pumping units for oil wells, we mean the determination of the standard size or standard sizes of installations that provide a given production of reservoir fluid from a well at optimal or close to optimal performance (delivery, pressure, power, MTBF, etc.). In a broader sense, selection refers to the determination of the main performance indicators of the interconnected system "oil reservoir - well - pumping unit" and the choice of optimal combinations of these indicators. Optimization can be carried out according to various criteria, but in the end they should all be aimed at one end result.

Minimization of unit cost of production - tons of oil.

The method of selecting ESPs for wells is based on knowledge of the laws of reservoir fluid filtration in the reservoir and near-wellbore zone of the reservoir, on the laws of movement of the water-gas-oil mixture along the well casing string and along the tubing string, on the dependences of the hydrodynamics of a centrifugal submersible pump. In addition, it is often necessary to know the exact temperature values ​​of both the fluid being pumped and the elements of the pumping unit, therefore, in the selection procedure, an important place is occupied by the thermodynamic processes of interaction between the pump, the submersible motor and the current-carrying cable with the pumped multicomponent reservoir fluid, the thermodynamic characteristics of which vary depending on the surroundings. conditions.

It should be noted that with any ESP selection method, there is a need for some assumptions and simplifications that allow creating more or less adequate models of the operation of the "reservoir - well - pumping unit" system.

In the general case, such forced assumptions that do not lead to significant deviations of the calculated results from real field data include the following provisions:

1. The process of reservoir fluid filtration in the bottomhole formation zone during the equipment selection process is stationary, with constant values ​​of pressure, water cut, gas factor, productivity factor, etc.

2. The inclinogram of the well is a time-invariant parameter.

The general methodology for selecting ESPs under the selected assumptions is as follows:

1. According to the geophysical, hydrodynamic and thermodynamic data of the formation and bottomhole zone, as well as the planned (optimal or limiting depending on the selection task) well flow rate, downhole values ​​are determined - pressure, temperature, water cut and gas content of the formation fluid.

2. According to the laws of expansion (changes in the current pressure and saturation pressure, temperature, compressibility factors of gas, oil and water) of the formation fluid flow, as well as according to the laws of the relative movement of the individual components of this flow along the casing string in the "bottom hole - pump intake" section the required depth of pump descent is determined, or, which is practically the same, the pressure at the pump intake, which ensures the normal operation of the pump unit. As one of the criteria for determining the pump suspension depth, the pressure at which the free gas content at the pump intake does not exceed a certain value can be chosen. Another criterion may be the maximum allowable temperature of the pumped liquid at the pump intake.

In the case of a real and satisfying consumer result of calculating the required depth of descent of the pump, a transition is made to paragraph 3 of this methodology.

If the calculation result turns out to be unrealistic (for example, the depth of the pump descent turns out to be greater than the depth of the well itself), the calculation is repeated from paragraph 1 with changed initial data - for example, with a decrease in the planned flow rate, with an increased well productivity factor (after the planned treatment of the bottomhole formation zone) , when using special upstream devices (gas separators, demulsifiers), etc.

The estimated depth of the pump suspension is checked for possible bending of the pumping unit, for the angle of deviation of the well axis from the vertical, for the curvature build-up rate, after which the adjusted suspension depth is selected.

3. Based on the selected suspension depth, standard size of casing and tubing, as well as the planned flow rate, water cut, gas-oil ratio, formation fluid viscosity and density, and wellhead conditions, the required pump head is determined.

4. According to the planned flow rate and required head, pumping units are selected, whose performance characteristics lie in close proximity to the calculated flow rate and head values. For the selected standard sizes of pumping units, their "water" performance characteristics are recalculated for real formation fluid data - viscosity, density, gas content.

5. According to the new "oil" characteristic of the pump, the number of operating stages is selected that satisfy the specified parameters - flow and pressure. Based on the recalculated characteristics, the pump power is determined and the drive motor, current-carrying cable and ground equipment (transformer and control station) are selected.

6. The temperature of the main elements of the pumping unit is determined by the temperature of the reservoir fluid at the pump intake, by the power, efficiency and heat transfer of the pump and the submersible motor - the motor winding, the oil in the hydraulic protection, the current lead, the current-carrying cable, etc. After calculating the temperatures at characteristic points, the design of the cable is specified in terms of heat resistance (building length and extension), as well as the design of the SEM, its winding wire, insulation and hydraulic protection oil.

If the calculated temperature turns out to be higher than the maximum allowable for the elements of pumping units used in this particular region or it is not possible to order high-temperature expensive ESP units, the calculation must be carried out for other pumping units (with modified pump and motor characteristics, for example, with higher efficiency, with a greater external motor diameter, etc.).

7. After the final selection of the ESP in terms of flow, pressure, temperature and overall dimensions, the possibility of using the selected unit for the development of an oil well after drilling or underground repair is checked. In this case, heavy killing fluid or other fluid (foam) used in this well is taken as the pumped fluid for calculation. The calculation is carried out for changed density and viscosity, as well as for other dependencies of heat removal from the pump and submersible motor to the pumped liquid. In many cases, this calculation determines the maximum possible time of non-stop operation of the submersible unit during well development until the critical temperature is reached on the stator windings of the submersible motor.

8. After completing the selection of the ESP, the installation, if necessary, is checked for the possibility of working on formation fluid containing mechanical impurities or corrosive elements. If it is impossible to order a special version of a wear- or corrosion-resistant pump for this particular well, the necessary geological, technical and engineering measures are determined to reduce the impact of undesirable factors.

The selection of ESP can be carried out both "manually" and using a computer. Many oil companies have installed computer programs for the selection of downhole pumping units, the use of which allows you to accurately select the best options for downhole equipment according to field data. In this case, it becomes possible not only to speed up the selection, but also to increase its accuracy due to the rejection of many simplifications required for manual selection.

The selection of the ESP to the well is carried out by means of calculations when entering from drilling, transferring to fur. production, optimization and intensification according to the methodology adopted in the oil and gas production department, which does not contradict the specifications for the operation of the ESP.

Calculations are based on the information available in NGDU:

 productivity factor of the given well (according to the results of hydrodynamic studies of the well);

 inclinometry data;

 gas factor;

 pressure

o reservoir,

o saturation pressure;

 water cut of produced products;

 Concentration of carried out particles.

Responsibility for the reliability of this information lies with the leading geologist of the oil production shop

When using in the calculations "Technology for checking the production string and the use of ESPs in directional wells" RD 39-0147276-029, VNII-1986, for wells with a curvature build-up rate in the ESP suspension zone of more than 3 minutes per 10 meters, it is necessary to set a mark on the application of this technique in the passport-form.

In the selection process, it is necessary to be guided by the methodology adopted in NGDU. In this case, the maximum free gas content at the pump intake should not exceed 25% for installations without gas separators. If the well is expected to carry out significant fur. impurities or salt deposits in the pump, it is prohibited to run the ESP without a sludge trap.

Selection results:

 estimated daily debit,

 pump pressure,

 internal minimum diameter of the production string,

 depth of descent,

 calculated dynamic level,

 maximum curvature build-up rate in the descent zone and in the ESP suspension section;

special operating conditions:

 high fluid temperature in the suspension area,

 Estimated percentage of free gas at the pump intake,

 the presence of carbon dioxide and hydrogen sulfide in the pumped liquid entered in the passport form.

Dangerous zones in the column, where the rate of curvature increase exceeds the permissible norms (more than 1.5° per 10 meters), are entered in the passport-form when applying for "EPU-SERVICE".

The determination of the test gauge and its length is made on the basis of tables No. 1 and No. 2.

Table #1

SUBMERSIBLE MOTORS

Length from flange to flange:

o pump module 3 - 3365 mm;

o pump module 4 - 4365 mm;

o pump module 5 - 5365 mm.

All types of pumps can be made:

 with flangeless connection of sections (rope connection);

 wear and corrosion resistant (ETsNMK-ETsND);

 with a receiving net and a fishing head on the section.

When selecting an ESP for a well, it is necessary to take into account the decrease in the power of the submersible motor due to an increase in the temperature of the surrounding formation fluid, in accordance with the current specifications of the manufacturers.

After receiving the results of the ESP selection for the well, EPU-Service accepts an application for the installation of this ESP and determines the type of engine, hydraulic protection, cable, gas separator and surface equipment required for completion in accordance with the current specifications and the ESP operation manual. The length of the heat-resistant extension of the cable line is determined by specialists in the ESP of NGDU and entered into the passport-form. Information about the type of component equipment for wells where additional preparation work (templates) is to be carried out is provided by EPU-Service to TTND OGPD prior to the commencement of work.

Well preparation is carried out in accordance with the “Work Plan” issued by the production department, taking into account the following requirements, regardless of whether they are included in the work plan:

In accordance with the project for the arrangement of well clusters approved for this oil and gas production department, at a distance of at least 25 m from the well, a site should be prepared for the placement of ground electrical equipment (LEO) of the ESP with a ground loop connected by a metal conductor to the ground loop of a transformer substation (TP 6 / 0.4 ) and well conductor. The service of the chief power engineer of the NGDU must transfer to EPU-Service an act of measuring the resistance of the ground loop before the submersible equipment is brought to the cluster, and during the operation of the ESP, carry out such measurements and transmit acts to the EPU at least once a year. Conductors must be welded to the ground loop in accordance with the PUE for grounding control stations (CS) and transformers (TMPN) of the ESP. The site for placement of the NET should be located in horizontal plane protected from flooding during the flood period. The entrances to the site should allow for the free assembly and dismantling of the NEO using a Fiskars unit or a truck crane. Responsible for the good condition of the sites is the head of the TsDNG.

A terminal box (SHP) should be installed 10-25 m from the wellhead. Power cables from the external connection cabinet (SHVP) to the control station (CS) of the ESP and from the transformer substation (TP) 6/0.4 to the CS are laid by the NGDU. Connection of cables in the control station (CS), ball screws and grounding of ground equipment is carried out by EPU-Service. Cables must be laid along the overpass or buried at least 0.5 m into the ground. Responsible for the normal condition of the cable racks is the foreman of the TsDNG mining team.

It is forbidden to operate the ESP with non-compliance with the requirements of the EMP and TB of sites for the placement of LEW, cable racks, ball screws and grounding. Responsibility for the implementation of this paragraph lies with the head of the rolling department of EPU-Service.

P.S. In addition, the answer to the question "The course of the basic production" section of the ESP.

The method of selecting ESPs for wells is based on knowledge of the laws of reservoir fluid filtration in the reservoir and bottomhole formation zone, on the laws of movement of the water-gas-oil mixture along the well casing string and along the tubing string, on the dependences of the hydrodynamics of a centrifugal submersible pump. In addition, it is often necessary to know the exact temperature values ​​of both the fluid being pumped and the elements of the pumping unit, therefore, in the selection procedure, an important place is occupied by the thermodynamic processes of interaction between the pump, the submersible motor and the current-carrying cable with the pumped multicomponent reservoir fluid, the thermodynamic characteristics of which vary depending on the surroundings. conditions.

It should be noted that with any ESP selection method, there is a need for some assumptions and simplifications that allow creating more or less adequate models of the “reservoir-well-pumping unit” system operation.

In the general case, such forced assumptions that do not lead to significant deviations of the calculated results from real field data include the following provisions:

• 1. The process of reservoir fluid filtration in the bottomhole formation zone during the equipment selection process is stationary, with constant values ​​of pressure, water cut, gas factor, productivity factor, etc.
• 2. The inclinogram of the well is a time-invariant parameter.

The general methodology for selecting ESPs under the selected assumptions is as follows:

• 1. According to the geophysical, hydrodynamic and thermodynamic data of the formation and bottomhole zone, as well as the planned (optimal or limiting depending on the selection task) well flow rate, downhole values ​​are determined - pressure, temperature, water cut and gas content of the formation fluid.
• 2. According to the laws of degassing (changes in the current pressure and saturation pressure, temperature, compressibility factors of gas, oil and water) of the formation fluid flow, as well as according to the laws of the relative movement of the individual components of this flow along the casing string in the “bottomhole - pump intake” section the required depth of pump descent is determined, or, which is almost the same, the pressure at the pump intake, which ensures the normal operation of the pump unit. As one of the criteria for determining the pump suspension depth, the pressure at which the free gas content at the pump intake does not exceed a certain value can be chosen. Another criterion may be the maximum allowable temperature of the pumped liquid at the pump intake.

In the case of a real and satisfying consumer result of calculating the required depth of descent of the pump, a transition is made to paragraph 3 of this methodology.

If the result of the calculation turns out to be unrealistic (for example, the depth of the pump descent turns out to be greater than the depth of the well itself), the calculation is repeated from paragraph 1 with changed initial data - for example, with a decrease in the planned flow rate, with an increased well productivity factor (after the planned treatment of the bottomhole formation zone) , when using special upstream devices (gas separators, demulsifiers), etc.

The estimated depth of the pump suspension is checked for possible bending of the pumping unit, for the angle of deviation of the well axis from the vertical, for the curvature build-up rate, after which the adjusted suspension depth is selected.

• 3. According to the chosen suspension depth, standard size of casing and tubing, as well as the planned flow rate, water cut, gas factor, viscosity and density of the reservoir fluid and wellhead conditions, the required pump pressure is determined.
• 4. According to the planned flow rate and required head, pumping units are selected, whose performance characteristics lie in close proximity to the calculated flow rate and head values. For the selected standard sizes of pumping units, their “water” performance characteristics are recalculated for real formation fluid data - viscosity, density, gas content.
• 5. According to the new "oil" characteristic of the pump, the number of operating stages is selected that satisfy the specified parameters - flow and pressure. Based on the recalculated characteristics, the pump power is determined and the drive motor, current-carrying cable and ground equipment (transformer and control station) are selected.
• 6. The temperature of the main elements of the pumping unit is determined by the temperature of the reservoir fluid at the pump intake, by the power, efficiency and heat transfer of the pump and the submersible motor - the motor winding, the oil in the hydraulic protection, the current lead, the current-carrying cable, etc. After calculating the temperatures at characteristic points, the design of the cable is specified in terms of heat resistance (building length and extension), as well as the design of the SEM, its winding wire, insulation and hydraulic protection oil.

If the calculated temperature turns out to be higher than the maximum allowable for the elements of pumping units used in this particular region or it is not possible to order high-temperature expensive ESP units, the calculation must be carried out for other pumping units (with modified pump and motor characteristics, for example, with higher efficiency, with a greater external motor diameter, etc.).

• 7. After the final selection of the ESP in terms of flow, pressure, temperature and overall dimensions, the possibility of using the selected unit for the development of an oil well after drilling or underground repair is checked. In this case, heavy killing fluid or other fluid (foam) used in this well is taken as the pumped fluid for calculation. The calculation is carried out for changed density and viscosity, as well as for other dependencies of heat removal from the pump and submersible motor to the pumped liquid. In many cases, this calculation determines the maximum possible time of non-stop operation of the submersible unit during well development until the critical temperature is reached on the stator windings of the submersible motor.
• 8. After completing the selection of the ESP, the installation, if necessary, is checked for the possibility of working on formation fluid containing mechanical impurities or corrosive elements. If it is impossible to order a special version of a wear- or corrosion-resistant pump for a particular well, the necessary geological, technical and engineering measures are determined to reduce the impact of undesirable factors.
• 2. Algorithm for “manual” selection of ESP to the well.

When selecting ESP units for oil wells, carried out using a "manual" account (calculator, EXCEL, ACCESS shell programs), it is necessary to use some additional assumptions and simplifications in the selection methodology to reduce data entry time and calculation time.

Chief among these assumptions are:

• 1) Uniform distribution of small gas bubbles in the liquid phase at pressures below saturation pressure.
• 2) Uniform distribution of oil and water components in the pumped liquid column in the section "bottom hole - pump intake" at any values ​​of well flow rates.
• 3) Neglect of "sliding" of oil in water when the fluid moves through the casing string and tubing string.
• 4) The identity of saturation pressures in static and dynamic modes.
• 5) The process of fluid movement from the bottom of the well to the pump intake, accompanied by a decrease in pressure and the release of free gas, is isothermal.
• 6) The temperature of the submersible motor is considered not to exceed the normal operating temperature if the speed of the coolant along the walls of the SEM is not less than recommended in the technical specifications for the SEM or in the ESP Units Operation Manual.
• 7) Loss of head (pressure) during the movement of fluid from the bottom of the well to the intake of the pump and from the injection zone of the pump to the wellhead is negligible compared to the pump head.

For the selection of ESPs, the following initial data are required:

1. Density, kg/cu.m.:

separated oil;

gas under normal conditions;

2. Viscosity, m2 / s:

• 3. Planned well flow rate, cubic meters per day.
• 4. Water cut of reservoir production, fractions of a unit.
• 5. GOR, cubic meters/cubic meters
• 6. Oil volume factor, units
• 7. Depth of formation location (perforation holes), m.
• 8. Reservoir pressure and saturation pressure, MPa.
• 9. Reservoir temperature and temperature gradient, С, С/m.
• 10. Productivity coefficient, cubic meters / MPa * day.
• 11. Buffer pressure, MPa.
• 12. Geometric dimensions of the casing string (outer diameter and wall thickness), tubing string (outer diameter and wall thickness), pump and submersible motor (outer diameter), mm.

The selection of the ESP installation is carried out in the following sequence:

1. We determine the density of the mixture in the section "bottom hole - pump intake" taking into account simplifications:

where n is the density of separated oil, kg/cu.m.

c - formation water density,

d is the density of the gas under standard conditions;

Г - current volumetric gas content;

b- formation fluid water cut.

2. We determine the bottom hole pressure at which the given well flow rate is provided:

Rzab \u003d Rpl - Q / Kprod

where Рpl - formation pressure;

Q - given well flow rate;

Kprod - well productivity factor.

3. Determine the depth of the dynamic level at a given fluid flow rate:

Ndin \u003d Lsv - Pzab / cm g

4. We determine the pressure at the pump intake, at which the gas content at the pump inlet does not exceed the maximum allowable for this region (for example, G = 0.15):

Ppr \u003d (1 - G) Rnas

(with the exponent depending on the degassing of the reservoir fluid m = 1.0).

where: Pnas - saturation pressure.

5. Determine the depth of the pump suspension:

L \u003d Ndyn + Ppr / cm g

6. Determine the formation fluid temperature at the pump intake:

T \u003d Tpl - (Lskv - L) * Gt;

where Tm - formation temperature;

Gt - temperature gradient.

7. Determine the volumetric coefficient of the liquid at the pressure at the inlet to the pump:

where: B is the volumetric coefficient of oil at saturation pressure;

b - volumetric water cut of production;

Ppr - pressure at the inlet to the pump;

Psat - saturation pressure.

8. Calculate the fluid flow rate at the pump inlet:

9. Determine the volumetric amount of free gas at the pump inlet:

Gpr \u003d G [ 1- (Ppr / ...

where F = 0.785 (D2 - d2) - area of ​​the annular section,

D - inner diameter of the casing string,

d is the outer diameter of the SEM.

If the flow rate of the pumped liquid W is greater than [W] (where [W] is the minimum allowable speed of the pumped liquid), the thermal condition of the submersible motor is considered normal.

If the selected pumping unit is not able to take the required amount of killing fluid at the selected suspension depth, it (suspension depth) is increased by L= 10 - 100 m, after which the calculation is repeated, starting from paragraph 5. The value of L depends on the availability of time and the capabilities of the consumer's computer technology.

After determining the depth of suspension of the pumping unit according to the inclinogram, the possibility of installing the pump at the selected depth is checked (by the rate of curvature increase per 10 m of penetration and by the maximum angle of deviation of the well axis from the vertical). At the same time, the possibility of running the selected pumping unit into this well and the most dangerous sections of the well, the passage of which requires special care and low descent rates during DR, is checked.

Table 2.1 Initial data

Table 2.2 Calculations

SubPUMP assists in ESP selection by creating the optimal operating mode for current well conditions or by analyzing the performance of an existing ESP system. This analysis is usually carried out by a production engineer. Wellbore configuration, fluid analysis, inflow characteristics, these are the parameters that are used as the basis for the performance analysis and selection of underground equipment by the SubPUMP program.

The selection of pumping units for oil wells, in a narrow, specific sense, refers to the determination of the standard size or standard sizes of installations that provide a given production of reservoir fluid from a well at optimal or close to optimal performance indicators (delivery, pressure, power, time between failures, etc.) . In a broader sense, selection refers to the determination of the main performance indicators of the interconnected system "oil reservoir - well - pumping unit" and the choice of optimal combinations of these indicators. Optimization can be carried out according to various criteria, but in the end, all of them should be aimed at one end result - minimizing the cost of a unit of production - a ton of oil.

The selection of centrifugal pump installations for oil wells is carried out according to algorithms, which are based on the provisions and results of works repeatedly tested in the oil industry, devoted to the study of liquid and gas filtration in the formation and the bottomhole formation zone, the movement of the gas-water-oil mixture through non-casing pipes, the laws of change in gas content, pressure, density, viscosity, etc., the study of the theory of operation of centrifugal submersible units, primarily downhole centrifugal pumps, on a real formation fluid.

This chapter discusses the main provisions of the methodology for selecting ESPs for oil wells.

Work on the creation of methods for selecting ESPs for wells began almost simultaneously with the creation of the ESP units themselves.

The main principle of selecting an ESP for an oil well is to ensure a normalized well flow rate with minimal costs, taking into account both capital and operating costs and equipment reliability.

When creating this methodology, the experience gained by oilmen during many years of operation of electric pumps was studied and, if possible, used. A number of original studies were carried out, which eventually made it possible to give an analytical description of the "well-pump - lift-liquid" system.

Reliability is taken into account according to the calculated temperature of the SEM. Thus, the most appropriate option for choosing a pump is one for which the gas content is high, and the costs and temperature of the SEM are low.

In some cases, it may be appropriate to give preference to the option with high costs, but with a lower temperature of the SEM, which in the end can lead to cost reduction due to a sharp increase in the reliability of the installation.

The selected size of the pump must meet the conditions for the development of a well that is drowned out by water. This condition is determined by the decrease in water level necessary for well excitation and the pressure that the pump can develop at the minimum required for well development and motor cooling during fluid withdrawal.

Obviously, the pressure required for the development of the well will exceed the pressure in the steady state operation of the well, especially when pumping anhydrous carbonated oil. The coincidence of the steady state operation of the well with the optimal mode of the pump ensures maximum efficiency. pump. The coincidence of the optimal mode of the pump with the mode of development leads to a shift of the steady state mode to the right from the optimum and to a decrease in efficiency. pump.

For the range of pump sizes used, the ratio of the maximum head to the optimal one on the water is within 1.2-1.5.

Where - the decrease in the water level in the well from the mouth, necessary for development; - filter depth; - reservoir pressure; - the minimum required drawdown on the reservoir, ensuring the development of the well; - pressure on the well buffer; k - coefficient depending on the specific size ()

With the use of cut-off packers, which exclude the killing of the well with water, this limitation can be removed.

All required initial characteristics of the fluid, well, lift, pump and collection system are presented in Table 10.1. Pump characteristics are given in Table 10.2.

1. Determine the specific gravity of the reservoir fluid

where is the specific gravity of separated oil, t/m3; - specific gravity of gas, t/m3; - reservoir GOR, m3/m3; - specific gravity of water, t/m3; - volumetric water cut; grandfather.; - oil volume factor

2. Determine bottomhole pressure

where - formation pressure, atm; - design liquid flow rate, m3/day; - productivity factor, m3/day;

3. Determine the work of the gas in the elevator

where is the diameter of the tubing, inch; - buffer pressure, atm.

4. Determine the pressure developed by the pump

where - formation depth, m; - buffer pressure, atm; - gas work in tubing, m3/m2;

5. Determine the pressure ratio

where is a correction factor that takes into account the change in the pressure coefficient from the number of stages Z.

• - optimal pressure on the water of the selected pump, kg/cm2;
• 6. Determine the relative flow of the pump in the liquid phase under the conditions of the measuring tank

where is the optimal water supply of the selected pump, m3/day;

• 7. For a given water cut b = 0.8, we determine the gas content at the pump inlet using the relative flow obtained in paragraph 6 and the pressure coefficient calculated in paragraph 6.
• * The value must lie at a given value of the supply coefficient within the field corresponding to the supply by water in the range of 0.7 ÷ 1.2 (from the optimal one).

In the absence of a solution in this area, it is allowed to take the values ​​​​of the supply coefficient, giving the value of the pressure coefficient in the area limited by dashed lines, corresponding to the supply on water in the range of 0.5 h 1.4 (from optimal)

We find the gas content value equal to 0.07.

• 8. Determine the coefficient M, which takes into account the change in gas content with water cut.
• 9. Find the value of the coefficient from the expression:

where is the saturation pressure, atm; - atmospheric pressure, atm;

Solving this equation, we find equal to 0.441.

• 10. Determine the pressure at the pump inlet
• 11. Determine the suspension of the pump, based on the condition of the absence of a "water cushion" at the bottom

where is the pressure at the pump inlet, atm

Based on the calculations, I choose UETsN5-130-600, since it is optimal for the Uzen field.

Table 10.1 - Initial data for the selection of ESP

	Measured and reported data	Designation	Dimension	Meaning
	Specific gravity of separated oil
	Viscosity of oil in the reservoir
	Volumetric water cut
	GOR
	Specific gravity of water
	Oil volume factor
	saturation pressure
	Reservoir pressure
	Reservoir depth (for vertical wells filter depth)
	Productivity factor
	buffer pressure
	Liquid flow rate design
	Elevator diameter
	Formation temperature
	Specific gravity of gas
ESP pump type
	Feeding at the optimum mode on the water
	Pressure at the optimum mode on the water
	Number of steps

Table 10.2 - Characteristics of pumps