When selecting ESP installations for oil wells, carried out using “manual” calculations (calculator, EXCEL, ACCESS shell programs), it is necessary to use some additional assumptions and simplifications in the selection methodology to reduce data entry and calculation time.
Key among these assumptions are:
1. Uniform distribution of small gas bubbles in the liquid phase at pressures below the saturation pressure.
2. Uniform distribution of oil and water components in the column of pumped liquid in the section “well bottom - pump intake” at any well flow rate.
3. Neglect of the “slip” of oil in water when the fluid moves along the casing and tubing string.
4. Identity of saturation pressure values 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 electric motor is considered not to exceed the normal operating temperature if the speed of movement of the coolant along the walls of the submersible motor is not less than that recommended in the technical specifications for the submersible motor or in the Operation Manual for ESP installations.
7. Head (pressure) losses when fluid moves from the bottom of the well to the pump intake and from the pump injection zone to the wellhead are negligible compared to the pump pressure.
To select an ESP, the following initial data are required:
1. Density, kg/m 3:
Separated oil;
Gas under normal conditions.
2. Viscosity, m 2 /s (or Pa s):
3. Planned well production, m 3 /day.
4. Water cut of formation production, fractions of a unit.
5. Gas factor, m 3 / m 3.
6. Volumetric coefficient of oil, units.
7. Depth of formation (perforation holes), m.
8. Reservoir pressure and saturation pressure, MPa.
9. Reservoir temperature and temperature gradient, °C, °C/m.
10. Productivity coefficient, m 3 / MPa day.
11. Buffer pressure, MPa.
12. Geometric dimensions of the casing (outer diameter and wall thickness), tubing string (outer diameter and wall thickness), pump and submersible motor (outer diameter), mm.
The selection of an ESP installation is carried out in the following sequence;
1. The density of the mixture is determined in the section “well bottom - pump intake”, taking into account simplifications:
Where ρ n is the density of separated oil, kg/m3;
ρ c - density of formation water,
ρ g - gas density under standard conditions;
G - current volumetric gas content;
b- water cut of formation fluid,
2. The bottomhole pressure at which the specified well flow rate is ensured is determined:
,
Where R pl - reservoir pressure;
Q- specified well flow rate;
TO prod - well productivity coefficient.
3. The depth of the dynamic level is determined at a given liquid flow rate:
.
4. The pump inlet pressure is determined at which the gas content at the pump inlet does not exceed the maximum permissible for a given region and a given type of pump (for example - G = 0.15):
,
(with an exponent depending on the degassing of the formation fluid m = 1,0).
Where: R us - saturation pressure.
5. The pump suspension depth is determined:
6. The temperature of the formation fluid at the pump intake is determined:
Where T pl - reservoir temperature; G t - temperature gradient.
7. The volumetric coefficient of the liquid is determined at the pressure at the pump inlet:
,
Where IN- volumetric coefficient of oil at saturation pressure; b- volumetric water cut of products; R pr - pressure at the pump inlet; R us - saturation pressure.
8. The fluid flow rate at the pump inlet is calculated:
.
9. The volumetric amount of free gas at the pump inlet is determined:
,
Where G- gas factor.
10. The gas content at the pump inlet is determined:
.
11. Calculate the gas flow at the pump inlet:
.
12. Calculate the reduced gas velocity in the section of the casing at the pump inlet:
Where f well - cross-sectional area of the well at the pump intake.
13. The true gas content at the pump inlet is determined:
,
Where WITH n is the rate of ascent of gas bubbles, depending on the water cut of the well production ( WITH n = 0.02 cm/s at b < 0,5 или С п = 0,16 см/с при b > 0,5).
14. The work of gas in the section “face - pump intake” is determined:
.
15. The work of gas in the section “pump injection - wellhead” is determined:
,
Where 
;
.
Values with the “buffer” index refer to the section of the wellhead and are “buffer” pressure, gas content, etc.
16. The required pump pressure is determined:
Where L din is the depth of the dynamic level; R buf - buffer pressure; P g1 - gas operating pressure in the section “bottom hole - pump intake”; P g2 is the gas operating pressure in the section “pump discharge - wellhead”.
17. Based on the pump flow at the inlet, the required pressure (pump pressure) and the internal diameter of the casing, the standard size of the submersible centrifugal pump is selected and the values that characterize the operation of this pump in the optimal mode (flow, pressure, efficiency, power) and in the supply mode are determined. equal to “0” (pressure, power).
18. The coefficient of change in pump flow when operating on an oil-water-gas mixture relative to the water characteristic is determined:
Where ν - effective viscosity of the mixture;
Q oB - optimal pump flow on water.
19. The coefficient of change in pump efficiency due to the influence of viscosity is calculated:
.
20. The gas separation coefficient at the pump inlet is calculated:
,
Where f well - the area of the ring formed by the inner wall of the casing and the pump casing.
21. The relative fluid flow at the pump inlet is determined:
Where Q oV - supply in optimal mode according to the “water” characteristics of the pump.
22. The relative flow at the pump inlet is determined at the corresponding point in the water characteristics of the pump:
.
23. The gas content at the pump intake is calculated taking into account gas separation:
.
24. The coefficient of change in pump pressure due to the influence of viscosity is determined:
.
To determine changes in pressure and other performance indicators of centrifugal submersible pumps with a liquid viscosity significantly different from the viscosity of water and the viscosity of Devonian oil in reservoir conditions (more than 0.03-0.05 cm 2 /s), and an insignificant gas content at the first stage intake pump to take into account the influence of viscosity, you can use the P.D. nomogram. Lyapkova (Fig. 5.162).
The nomogram was constructed to convert the pump characteristics obtained when pumping water to the characteristics when pumping a homogeneous viscous liquid. The dotted line on the nomogram shows the curves for recalculating the pump characteristics to operate with emulsions of different viscosities. The dotted curves were obtained by V.P. Maximov.
The limitation on the use of the nomogram for the gas content in the liquid is not the same for different standard sizes of pumps. But we can say that when the gas content is 5 - 7% or less at the first stage of the pump, the influence of gas on the operation of the pump can be ignored and a nomogram can be used.
25. The coefficient of change in pump pressure is determined taking into account the influence of gas:
,
Where 
.
26. The pump pressure on water is determined at optimal mode:
Rice. 5.162. Nomogram for determining conversion factors for ESP characteristics taking into account liquid viscosity
27. The required number of pump stages is calculated:
Where h st - pressure of one stage of the selected pump.
The Z number is rounded to a higher integer value and equalized to the standard number of stages of the selected pump size. If the estimated number of stages turns out to be greater than that specified in the technical documentation for the selected pump size, then you must select the next standard size with a larger number of stages and repeat the calculation starting from point 17
If the estimated number of stages turns out to be less than that specified in the technical specifications, but their difference is no more than 5%, the selected pump size is left for further calculation. If the standard number of stages exceeds the calculated one by 10%, then a decision is necessary to disassemble the pump and remove the extra stages. Another option may be to consider using a choke in the wellhead equipment.
Further calculations are carried out from paragraph 18 for new values of the operating characteristic.
28. The pump efficiency is determined taking into account the influence of viscosity, free gas and operating mode:
,
Where η oB - maximum efficiency of the pump for water characteristics.
29. The pump power is determined:
30. The power of the submersible motor is determined:
.
31. Checking the pump for the ability to withdraw heavy liquid.
In wells with possible flow or release of liquid when changing the well pump, killing is carried out by pouring heavy liquid (water, water with weighting agents). When lowering a new pump, it is necessary to pump out this “heavy liquid” from the well so that the installation begins to operate at optimal mode when extracting oil. In this case, you must first check the power consumed by the pump when the pump pumps heavy liquid. The formula for determining power includes the density corresponding to the heavy liquid being pumped (for the initial period of its selection).
At this power, possible engine overheating is checked. An increase in power and overheating determines the need to equip the installation with a more powerful engine.
Upon completion of heavy fluid withdrawal, the displacement of heavy fluid from the tubing by the formation fluid in the pump is checked. In this case, the pressure created by the pump is determined by the characteristics of the pump's operation on the formation fluid, and the backpressure at the discharge is determined by the column of heavy fluid.
It is also necessary to check the pump operation option, when heavy liquid is pumped not into the drain, but to the spout, if this is permissible according to the location of the well.
Checking the pump and submersible motor for the possibility of pumping out heavy liquid (killing liquid) during well development is carried out according to the formula:
Where ρ hl - density of the killing fluid.
In this case, the pump pressure during well development is calculated:
.
Magnitude N gl is compared with pressure N passport water characteristics of the pump.
The pump power is determined during well development:
.
Power consumed by a submersible electric motor during well development:
.
32. The installation is checked for the maximum permissible temperature at the pump intake:
where [T] is the maximum permissible temperature of the pumped liquid at the intake of the submersible pump.
33. The installation is checked for heat removal at the minimum permissible speed of the coolant in the annular section formed by the inner surface of the casing at the installation site of the submersible unit and the outer surface of the submersible motor, for which we calculate the flow rate of the pumped out liquid:
Where F = 0,785 (D 2 – d 2) - annular cross-sectional area;
D- internal diameter of the casing;
d- outer diameter of the motor.
If the flow rate of the pumped liquid W turns out to be greater than the minimum permissible speed of the pumped liquid [ W], the thermal regime of the submersible motor is considered normal.
If the selected pumping unit is not able to extract the required amount of kill fluid at the selected suspension depth, it (suspension depth) is increased by Δ L= 10 - 100 m, after which the calculation is repeated starting from point 5. Value Δ L depends on the availability of time and computing capabilities of the calculator.
After determining the suspension depth of the pump unit using an inclinogram, check the possibility of installing the pump at the selected depth (by the rate of curvature gain 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 lowering the selected pumping unit into a given well and the most dangerous sections of the well, the passage of which requires special care and low lowering speeds during PRS, are checked.
The data required for the selection of installations on the complete set of installations, characteristics and main parameters of pumps, motors and other components of installations are given both in this book and in specialized literature.
To indirectly determine the reliability of a submersible electric motor, it is recommended to evaluate its temperature, since overheating of the motor significantly reduces its operating life. An increase in winding temperature by 8 -10 °C above that recommended by the manufacturer reduces the service life of some types of insulation by 2 times. The following calculation procedure is recommended. Calculate the power loss in the engine at 130 °C:
, (5.1)
Where b 2 , With 2 and d 2 - calculated coefficients (see); N n and η Doctor of Science - rated power and efficiency of the electric motor, respectively. Engine overheating is determined by the formula:
. (5.2)
Where b 3 and With 3 - design coefficients.
Due to cooling, losses in the engine decrease, which is taken into account by the coefficient K t.
Where b 5 - coefficient (see appendix 3).
Then the energy loss in the engine (Σ N) and its temperature ( t dc) will be equal:
(5.6)
The temperature of the stator windings of most motors should not exceed 130 °C. If the power of the selected engine does not match that recommended in the picking list, an engine of a different size of the same size is selected. In some cases, it is possible to select a motor with a larger diameter, but in this case it is necessary to check the transverse dimension of the entire unit and compare it with the internal diameter of the well casing.
When choosing a motor, it is necessary to take into account the temperature of the surrounding fluid and its flow rate. The engines are designed to operate in environments with temperatures up to 90 °C. Currently, only one type of engine allows a temperature increase of up to 140 ° C, and a further increase in temperature will reduce the service life of the engine. This use of the engine is permissible in special cases. It is usually desirable to reduce its load to reduce overheating of the winding wires. Each engine has a recommended minimum flow rate based on its cooling conditions. This speed needs to be checked.
c) errors in the selection of equipment due to insufficient geological information.
The periodic stock for UNP-1 decreased by 18 wells
At 3 wells, they were brought into constant mode using NPS, at 15 wells, by changing the standard size of the ESP, and 34 wells were transferred to PPD.
Measures to reduce the periodic fund in 2005
1) Formation of a flooding system (transfer of 20 wells to reservoir pressure maintenance.
2) Optimization of the operating mode of wells with ESP (lowering of low-capacity units.).
3) Introduction of imported screw pumps.
4) Continue the implementation of ESP with TMS to prevent errors in equipment selection
The ESP feed coefficient varies from 0.1 to 1.7 (Table 5.5.). About 75% of installations operate in close to optimal mode (Capacity = 0.6–1.2).
Table 5.5. Distribution of ESP feed coefficient at the Khokhryakovskoye field
Of the 49 wells operating with a flow rate of 0.1 to 0.4, the main number (25 wells) are in periodic operation. For wells Nos. 154, 278, 1030, 916, 902 and 3503, it is recommended to audit underground equipment and tubing.
The list of wells operating with a flow rate greater than 1.2 is given in table 3.6.7. Of these, wells No. 130, 705, 163, 785, 1059 were optimized for a larger ESP size.
Table 5.6. List of wells with K supply more than 1.2
| Well No. | Pump type | To submit | Q liquid | P layer, MPa | N din, m | Pump release depth |
| 702 | ESP 50–2100 | 1,7 | 65 | 20,5 | 1683 | 2300 |
| 130 | TD-650–2100 | 1,4 | 100 | 17,9 | 1332 | 2380 |
| 705 | ESP-160– 2100 | 1,6 | 123 | 18,3 | 2167 | 2400 |
| 707 | TD-850–2100 | 1,5 | 114 | 16,5 | 1124 | 2260 |
| 163 | ESP-160–2150 | 1,5 | 82 | 18,2 | 1899 | 2350 |
| 185 | ESP 25–2100 | 1,4 | 29 | 20,0 | 1820 | 2245 |
| 818 | ESP 80–2100 | 1,4 | 87 | 18,2 | 2192 | 2340 |
| 166 | ESP 50–2100 | 1,4 | 42 | 19,5 | 1523 | 2150 |
| 834 | ESP 30–2100 | 1,6 | 23 | 23,0 | 1870 | 2250 |
| 785 | ESP 125–2100 | 1,3 | 11 | 16,5 | 2320 | 2400 |
| 389 | ESP 50–2100 | 1,4 | 42 | 22,9 | 1623 | 2200 |
| 1059 | ESP 160–2100 | 1,4 | 144 | 16,5 | 2328 | 2400 |
| 1025 | ESP 80–2100 | 1,4 | 72 | 16,1 | 1762 | 2080 |
In general, for the Khokhryakovskoye field, the utilization rate of wells equipped with ESPs, like a year ago, is within 0.87. The main indicator of reliability - time between failures for a rolling year from January 1, 2003 to January 1, 2004, according to the ESP fund, changed from 303 days to 380 days, while in general for OJSC NNP this indicator is lower and is in the within 330–350 days. The growth of this indicator indicates a fairly high level of work of the production department in selecting the standard size of the ESP, well repair, bringing installations into operation and monitoring during operation.
At the field, 74 wells (17% of the stock producing production) are subject to paraffin deposits. According to the “dewaxing” schedule, all wells are usually flushed with hot oil once a month.
In 2003, there were 208 failures in the field of wells equipped with ESP. The failure rate was 0.85 units. (the current stock is 303 wells). In 2004, 229 failures were recorded at the field, with a larger operating stock of 332 wells, and the failure rate positively decreased to 0.79 units. In general, OJSC NNP K refused. The ESP at this time was 0.85 units.
5.2 Analysis of the causes of ESP failures
An analysis of the causes of premature failures of wells equipped with ESPs shows the following picture, see Fig. 5.1.4.
Up to 17% of failures are due to poor quality work of underground well repair teams. Where the regulations for hoisting operations are violated. As a consequence, this leads to cable damage, poor-quality installation of the ESP, tubing leaks, and poor well cleaning.
18% of failures occur in wells operating intermittently, caused by poor inflow, as well as the pump size not matching the operating conditions.
In 13% of refusals, the reasons were not identified, because the investigation regulations were violated.
1. 10% of failures occur due to deposits of hard asphalt-resin-paraffin deposits along with scale, sand, clay particles and rust.
2. 9% of failures due to the removal of proppant in wells after hydraulic fracturing, which leads to jamming of shafts and failure of pumps.
3. 8% of failures occur due to uncontrolled operation - this is a violation of the dewaxing schedule, lack of control over the removal of EHF, etc.
4. 6% of failures occur due to lack of control over the installation of settings.
5. In 5% of cases, the failure occurred due to manufacturing defects, hidden defects, and poor-quality components of submersible and surface pumping equipment.
In 2004, thermal indicators were installed on submersible equipment components, including the submersible cable, to determine the well temperature in the ESP operating area. Five installations with thermal indicators were lowered into wells with heavy starts, with the removal of mechanical impurities to determine critical heating areas. The installations worked on average up to 100 days, but failed due to a decrease in insulation resistance to 0 along the construction length of the cable. In all cases, cable defect detection revealed melting of core insulation in the area of 150 m from the extension cord splice at a temperature of 130 °C.
Based on the results obtained in 2004, when repairing high-yield wells, the length of the heat-resistant extension cable KRBK was increased to 120 m and a 500 m insert from group 3 cable was used
To improve the operation of a stock of wells equipped with ESPs, it is recommended:
Wells should be developed and brought into operation using a mobile installation of a frequency converter type UPPC (Electon-05"). The installation allows, under certain technical conditions (the depth of the ESP, there is a power reserve of the submersible electric motor), to reduce the time of well production in gentle starting modes, to increase the drawdown on the formation, to eliminate jamming of the ESP by creating increased torques;
When choosing the standard size of installations and the depths of drawdown (depression), special attention should be paid to the stock of wells where hydraulic fracturing was carried out. When developing wells after hydraulic fracturing using jet pumps on sand-producing reserves, wear-resistant ESP units of the ARH type should be used, designed for pumping EHF fluids up to 2 g/l. In addition, this foundation should be used to develop technologies for securing the ESP, to use underground devices to protect the pump from solid impurities (filters and sludge traps for ESPs - ZAO Novomet, Prem);
In the intermittent stock, use mainly high-pressure, low-performance pumps of the ESP type 20, 25 and evaluate the possibility of increasing the depth of descent of the ESP, as well as transferring low-yield wells to USP and jet pumping units.
To reduce accidents due to ESP dismemberment, it is recommended to use devices that reduce vibration of installations - pump shaft centralizers, shock absorbers, safety couplings - (JSC TTDN, Tyumen);
A significant share of failures is due to the quality of work performed by the workover and workover crews. The use of highly qualified teams and control during non-routine work will significantly increase the reliability of the mining stock.
The principle of operation of the production stock of wells equipped with ESPs, depending on the depth of descent of the pumping equipment
In 2004, the distribution of the stock of wells equipped with ESPs by pump run depth and the characteristics of their operation at the Khokhryakovskoye field is as follows, see Table 5.7. and Figure 5.1.5. – 5.1.8.
An analysis of the stock of wells equipped with ESPs from the point of view of reliability and efficiency depending on the descent depths at the Khokhryakovskoye field showed that ESPs are descended to depths from 1200 to 2400 m. The entire working interval of descent depths is divided into six groups, each of which employs from 15 to 120 wells equipped with ESP.
Table 5.7. Main technological performance indicators of wells equipped with ESPs
| ESP lowering depth, m. | 1200-1400 | 1800-2000 | 2000-2200 | 2200-2300 | 2300-2400 | More than 2400 |
| Number of wells, units | 15 | 55 | 65 | 120 | 40 | 25 |
| Liquid flow rate, m 3 /day | 190 | 120 | 100 | 95 | 75 | 67 |
| Water cut, % | 96 | 86 | 66 | 54 | 47 | 35 |
| Wed. well worked time per year, days | 342 | 329 | 350 | 346 | 338 | 337 |
The highest liquid flow rates are observed in two groups of wells - in the range of ESP lowering from 1200–1400 m and 1800–2000 m. In the same ranges, pumping equipment operates for a greater number of days, 346–350 days.
Lower percentages of water cut are observed when operating ESPs with a running depth of more than 2000 m.
That. The results of the analysis of the dependence of the main characteristics of the operation of wells equipped with ESPs show that reducing the descent depths to 2200–2400 m does not significantly deteriorate the operation of the ESP. As shown in Figure 5.1.8. dynamic levels are reduced due to the change from smaller size units to large size type and decrease in reservoir pressure and uneven waterflooding system.
Energy state of the deposit
The lag in the development of the reservoir pressure maintenance system from the current state of fluid extraction has led in recent years to a decrease in reservoir pressure in the extraction zone.
As of January 1, 2004, the pressure in the extraction zone decreased to 19.5 MPa (Fig. 5.8), the difference between the initial and current reservoir pressures was 4.2 MPa.
The decrease in reservoir pressure was also affected by intensive drilling, which was carried out during 2000–2001. in the eastern part of the field, not provided for by the project. As a consequence of this, in the eastern part there is a lag in the formation of the RPM system, which, with forced extractions, immediately affects the energy state of the areas.
OIL PRODUCTION ESP
4.3.1. General information about well operation,
equipped with electric submersible installations
centrifugal pumps (ECP)
Installations of electric submersible centrifugal pumps belong to the class of rodless installations and play a decisive role in the Russian oil industry in terms of the volume of oil produced. They are designed for the operation of production wells of different depths with different properties of the produced products: anhydrous low-viscosity and medium-viscosity oil; water cut oil; a mixture of oil, water and gas. Naturally, the operating efficiency of ESP wells can vary significantly, because the properties of the pumped product affect the output parameters of the installation.
In addition, ESPs have undeniable advantages over rod units, not only due to the transfer of the drive motor to the bottom hole and the elimination of the rod string, which significantly increases the efficiency of the system, but also due to a significant range of working feeds (from several tens to several hundred m3/day ) and pressures (from several hundred to several thousand meters) with a relatively high installation mean time between failures.
The selection of the standard size and configuration of the ESP for a specific well, the calculation of the expected technological operating mode of the well and the parameters of the submersible equipment are carried out both by a software package integrated into the corporate database of NPK ALPHA, and according to the methodology chosen by the chief technologist (head of the technical and technical department) of the NGDU and adapted to conditions of a given field (formation).
Calculation of the optimal operating mode of the well is carried out by the geological service of the NGDU. Based on the parameters specified by the geologist, the technological service selects the standard size of the ESP and the parameters of the submersible equipment in the Autotechnological PC, adapted to the conditions of the oil and gas production management fields.
Responsibility for calculating the expected flow rate at the expected dynamic level, the reliability of the information and the completeness of entering the results of well testing into the NPK Alfa database lies with the leading geologist of the CDNG. Responsibility for the correct selection of the pump size and determination of the descent depth lies with the TsDNG technologist.
When calculating the selection of an electric submersible pump, it is necessary to take into account:
– use of the actual productivity coefficient, optimal fluid extraction from the well, subject to the condition of not exceeding the maximum permissible drawdown on the reservoir and the field development project;
– the specific gravity of pumping out the kill fluid when putting it into operation to ensure the supply of reservoir fluid at the expected dynamic level, buffer pressure and friction losses in the lift and oil-gathering manifold to the booster station, ESP operation in the optimal mode zone (0.8÷1.2 Q nom);
^t
Possibility of changing ESP performance using
control stations with frequency converter (CSCP).
For wells with a water content in the produced product of more than 90%, the immersion under the dynamic level of the ESP should be no more than 400 meters.
The critical flow rates (depressions) of each specific well in waterfloat and gas-oil deposits are determined by the development department of the Oil and Gas Production Department (geologist of the Center for Oil and Gas Production) based on the experience of operating wells with identical geological and technical characteristics of the bottomhole zone.
At the location where the submersible unit is suspended, the curvature of the wellbore should not exceed:
For ESP-5 size according to the formula: a = 2arcsin ^P s: ,
where: a is the curvature of the wellbore at the location where the ESP is suspended, degrees/10 m;
S- the gap between the internal diameter of the casing and the maximum diametrical dimension of the installation, m;
L- installation length from the lower end of the compensator to the upper end of the pump, m;
For ESP-5, with a production string diameter of 146 mm - 6 minutes per 10 meters, with a production string diameter of 168 mm - 12 minutes per 10 meters;
For ESP-5A, with a production string diameter of 146 mm - 3 minutes per 10 meters, with a production string diameter of 168 mm - 6 minutes per 10 meters;
If there are no areas with the specified curvature intensity, a section with the minimum value for a given well is selected and agreed upon with the chief engineer of the oil and gas department.
If there are areas in the well with a curvature intensity exceeding 20/10 m, the weekly application from the oil and gas production department must indicate the need to equip an ESP for this well with a submersible motor with a diameter of 103 mm (for submersible motors with a power of up to 45 kW, inclusive).
In the operating area of the submersible installation, the deviation of the wellbore from the vertical should not exceed 60 degrees.
The maximum hydrostatic pressure in the ESP operating area should not exceed 20 MPa (200 kgf/cm2).
The design of the tubing string must ensure the strength of the suspension at a given running depth and well design.
The immersion of the pump under the dynamic level is determined by the content of free gas in the well production (in the formation fluid) under pump intake conditions: up to 25% - without a gas separator, 25-55% - with a gas separator, up to 68% - with a gas separator-dispersant, up to 75 % - with a domestic or imported multiphase system.
Technical requirements for the pumped medium - formation fluid (mixture of oil, produced water, mineral impurities and petroleum gas):
The maximum density of the water-oil mixture is 1,400 kg/m 3 ;
Gas factor (Gf) - up to 110 m 3 /m 3;
– maximum content of produced water – 99%;
– pH value of produced water (pH) – 6.0–8.5;
– temperature of the pumped liquid:
– for standard execution – up to +90 °С;
– for heat-resistant version – up to +140 °C;
– for standard version – up to 100 mg/l;
– for wear-resistant design – up to 500 mg/l;
In the ESP suspension kit, it is allowed to use additional auxiliary elements only factory-made or manufactured according to the standards of Surgutneftegaz OJSC.
The maximum temperature of the pumped liquid in the operating area of the submersible unit should not exceed the rating data of the motor and cable extensions used at Surgutneftegas OJSC. With the calculated expected values of operating conditions at the pump intake at a temperature of more than +120 °C, the TsDNG technologist in the application for TsBPO EPU equipment indicates the necessary equipment for heat resistance.
The main provisions for selecting an ESP are given below:
1. Density of the mixture in the section “well bottom - pump intake”:
■ With
(p b + p(1 - b)) (1 - F) + pF.
where: ρ n– density of separated oil, kg/m3, ρ V– formation water density, ρ G– gas density under standard conditions, G– current volumetric gas content, b– water cut of formation fluid.
2. Bottomhole pressure at which the specified well flow rate is ensured:
Where: R pl- reservoir pressure,
Q– specified well flow rate,
K prod– well productivity coefficient.
3. Depth of dynamic level at a given fluid flow rate:
Oil production equipment and technology
4. Pressure at the pump intake, at which the gas content at the pump inlet does not exceed the maximum permissible for a given region (for example: F = 0.15):
P = P. (I - G).,
Where To - degree of degassing curve.
5. Pump suspension depth:
Where: B– volumetric coefficient of oil at saturation pressure, b– volumetric water cut of products,
14. Gas work in the “bottomhole – pump intake” section:
Quantities with the index " boof" refer to the section of the wellhead and are "buffered" by pressure, gas content, etc.
16. Required pump pressure:
Where: L din– depth of location of the dynamic level;
P buffer– buffer pressure;
P G1– gas operating pressure in the section “bottom hole – pump intake”;
P G2– gas operating pressure in the “pump discharge – wellhead” section.
17. Based on the pump flow at the inlet, the required pressure (pump pressure) and the internal diameter of the casing, we select the standard size of a submersible centrifugal (or screw, diaphragm) pump and determine the values that characterize the operation of this pump in optimal mode (flow, pressure, efficiency, power ) and in supply mode equal to 0 (pressure, power).
18. Coefficient of change in pump flow when operating on an oil-water-gas mixture relative to the water characteristic:
where: ν – effective viscosity of the mixture;
Q o IN– optimal pump flow on water.
24. Coefficient of change in pump pressure due to the influence of viscosity:
Where h- pressure of one stage of the selected pump.
WithG
The Z number is rounded to a higher integer value and compared to the standard number of stages of the selected pump size. If the calculated number of stages turns out to be greater than that specified in the technical documentation for the selected pump size, then you must select the next standard size with a larger number of stages and repeat the calculation starting from point 17.
If the estimated number of stages turns out to be less than that specified in the technical specifications, but their difference is no more than 5%, the selected pump size is left for further calculation. If the standard number of stages exceeds the calculated one by 10%, then a decision is necessary to disassemble the pump and remove the extra stages. Further calculations are carried out from paragraph 18 for new values of the operating characteristic.
28. Pump efficiency taking into account the influence of viscosity, free gas and operating mode:
V - /Ci." K w " fCijr,
Where ri o6- maximum pump efficiency for water characteristics.
Oil production equipment and technology
29. Pump power:
where: η PED– efficiency of the submersible electric motor,
cosϕ – engine power factor at operating temperature.
31. We check the pump and submersible motor for the possibility of pumping out heavy liquid (killing liquid) during well development:
Rgl=Rgl
1_. р +р +р
■- P buff G zab^ PL"
where ρ GL– density of the killing fluid.
We calculate the pump pressure when developing a well:
Magnitude N GL is compared with the passport water characteristics. We determine the pump power when developing a well:
Power consumed by a submersible electric motor during well development:
32. We check the installation for the maximum permissible temperature at the pump intake:
T> [T]
Where [ T] – maximum permissible temperature of the pumped liquid at the intake of the submersible pump.
^t Master's Guide to Oil, Gas and Condensate Production
33. We check the heat sink installation according to the minimum permissible coolant velocity in the annular section formed by the inner surface of the casing at the installation site of the submersible unit and the outer surface of the submersible motor, for which we calculate the flow rate of the pumped out liquid:
Where: F = 0.785 ■ - annular area; D- internal diameter of the casing; cf is the outer diameter of the motor.
If the flow rate of the pumped liquid is greater [W](Where [W]- minimum permissible speed of the pumped liquid), the thermal regime of the submersible motor is considered normal.
If the selected pumping unit is not able to extract the required amount of kill fluid at the selected suspension depth, it (the suspension depth) is increased by liters! = 10 - 100 m, after which the calculation is repeated starting from step 5. Magnitude &L depends on the availability of time and computing capabilities of the consumer.
After determining the suspension depth of the pump unit using an inclinogram, the possibility of installing the pump at the selected depth is checked (by the rate of curvature gain 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 lowering the selected pumping unit into a given well and the most dangerous sections of the well, the passage of which requires special care and low lowering speeds during PRS, are checked.
After the final selection of the depth of descent of the downhole unit, the type of cable (based on operating current and temperature of the pumped out liquid) and the size of the transformer (based on operating current and voltage) are selected. After completing the selection of equipment, the power consumed by the installation is determined:
NnoTP = N n s n + AN KAB + AN Tp,
where: aWjus= - ~ "" : - cable power loss
/ - operating current of the motor, L; L- length of current-carrying cable, m;
p t- resistance of a linear meter of cable at operating temperature, Ohm/m ■ mm 2 ;
S- cross-sectional area of the cable cores, mm 2;
D L/t = (1 - Ti) (L/tp + A AL) - power losses in the transformer,
g]tr - Transformer efficiency.
The selection of ESPs for oil wells, in a narrow, specific sense, means the determination of the standard size or standard sizes of installations that ensure a given production of formation fluid from a well at optimal or close to optimal performance indicators (flow rate, pressure, power, mean time between failures, etc.). In a broader sense, selection refers to the determination of the main operating indicators of the interconnected system “oil reservoir - well - pumping unit” and the selection of optimal combinations of these indicators. Optimization can be carried out according to various criteria, but ultimately they should all be aimed at one final result - minimizing the cost of a unit of production - a ton of oil. First, the necessary initial data are established: the inflow equation is selected; determine the properties of oil, water, gas and their mixtures that are supposed to be pumped out of the well; design of the production casing. The pump lowering depth LH is determined taking into account the gas content of the oil and gas flow at the inlet p in using a method similar to the method for determining the lowering depth of a sucker rod pump. To do this, plot distribution curves of pressure and gas flow rate p along the casing pipes in steps from the bottom up, starting from a given bottomhole pressure, determined by the inflow equation for a known flow rate (curves / and 3 in Fig. VIII. 18). Flow gas content - volumetric flow ratio V gas on the site to the total flow rate of the mixture of gas and liquid q- determined by the formula β=V/(V+q). Along the curve 3 (see Fig. VIII.18) estimate the preliminary depth of pump descent (based on the permissible values of the volumetric gas content at the pump intake; p BX = 0.05-f-0.25) and pressure rv x(along the curve /). The mentioned limits for the gas content at the pump inlet are established based on testing data from the ESP during pumping out a carbonated liquid. If βin = 0÷0.05, then the gas has little effect on the operation of the pump; if βin = 0.25÷0.3, then the pump supply is interrupted. It is practically advisable to have a pump inlet pressure of at least 1-1.5 MPa. To determine the pressure at the pump discharge p„yk, i.e. in the lowest section of the tubing, the pressure distribution in the pipes is also calculated in steps from top to bottom from the known wellhead pressure RU, equal to the pressure in the collection system (see Fig. VIII.18, curve 2). In this case, partial gas separation is taken into account * at the pump inlet, which moves up the annular space, bypassing the pump, and is discharged into the flow line through a check valve.
When calculating the pressure distribution in the tubing, their diameter d set taking into account the flow rate:
It should be noted that according to the found values r s and for a given flow rate Ql, under standard conditions, it is still impossible to select an appropriate pump characteristic with sufficient accuracy, because the factory characteristics, based on data from the water pumping process, do not take into account the influence of the properties of gas-liquid mixtures and the thermodynamic operating conditions of pumping units. The actual fluid flow through the pump will differ from the specified values Qlsu due to the fact that a large amount of gas can dissolve in the liquid pumped out by the pump. The liquid, washing the electric motor, heats up. In addition, it contains a certain amount of free gas and these factors contribute to a significant increase in the volume of the gas-liquid mixture (GLM) passing through the pump (compared to the given flow rate under standard conditions QLSU ). It should be taken into account that the flow rate of gas liquid along the length of the pump due to an increase in discharge pressure and a decrease in the amount of free gas in the liquid is not constant. In turn, the properties of the liquid and its viscosity affect the pressure characteristics of the pump. Also due to the rapid expansion of the areas of their application in the oil industry - in systems for maintaining reservoir pressure (with a supply of up to 3000 m 3 / day at a pressure of up to 2000 m), for lifting water from water intake and artesian wells, for separate exploitation of several layers with one network of wells.
Development system. Basic development concepts.
Oil field development– a multi-parameter process, each technological link of this process must operate in an optimal mode, which in turn creates a hierarchy of optimization criteria. In such conditions, it is necessary to identify strategic success in the field development process and determine the main criteria. Development systems– a set of interrelated engineering solutions that determine the development object, the sequence and pace of their drilling and development, the presence or absence of impact on the formation, the number, ratio and location of production and injection wells, the number of reserve wells, management of the development process, protection of subsoil and the environment. Any development system can be classified according to 2 main characteristics:1).According to the presence or absence of impact on the formation. 2) According to the well placement system. Each development system can be characterized by the following parameters: 1) Well pattern density coefficient – Sс, Sс =F/n.[ha/KV]; F – area of the deposit; n – number of wells; 2).Krylov parameter Ncr.= Vinit.recovery./n, [t.tons], i.e. recoverable reserves per 1 well; 3) Development system intensity parameter Wint.=n INJECTION/n PRODUCTION. (1;0.5;0.3); 4). Parameter of reserve wells Wres.=n RES./n TOTAL (0.1-0.3). Selecting a development system. The choice depends on the following factors: 1. Natural and climatic conditions; 2. Size and configuration of the oil reservoir; H. Geological feature of the structure; 4. Heterogeneity of productive formations; 5. Physical state of hydrocarbons; 6. Availability of working agent resources; 7. Natural regime of deposits; 8.Properties of oil.
Development system without affecting the formation. Development is carried out in the following cases: 1). When the natural energy balance of the deposit is replenished naturally and development is effectively carried out using natural energy sources; 2). No working agent. Z). When impact development is not effective. When developing a deposit without affecting the formation in the depletion mode (elastic, dissolved gas mode), production wells are located on the area in uniform grids, rectangular or square.
The selection of pumping units for oil wells, in a narrow, specific sense, means the determination of the standard size or standard sizes of installations that ensure a given production of formation fluid from a well at optimal or close to optimal performance indicators (flow rate, pressure, power, time between failures, etc.) . In a broader sense, selection refers to the determination of the main operating indicators of the interconnected system “oil reservoir - well - pumping unit” and the selection of optimal combinations of these indicators. Optimization can be carried out according to various criteria, but ultimately they should all be aimed at one final 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 provisions that have been repeatedly tested in the oil industry and the results of work devoted to the study of the filtration of liquid and gas in the formation and the bottom-hole zone of the formation, the movement of the gas-water-oil mixture through casing pipes, laws of changes in gas content, pressure, density, viscosity, etc., studying the theory of operation of centrifugal submersible units, primarily borehole centrifugal pumps, on real reservoir fluid.
This chapter discusses the main provisions of the methodology for selecting ESPs for oil wells.
Work on creating methods for selecting ESP units for wells began almost simultaneously with the creation of ESP units themselves.
The basic principle of selecting an ESP for an oil well is to ensure the well’s normalized flow rate with minimal costs, taking into account both capital and operating costs and equipment reliability.
When creating this methodology, the experience accumulated by oil workers during many years of operation of electric pumps was studied and, if possible, used. A number of original studies were carried out, which ultimately made it possible to provide an analytical description of the “well-pump-lift-fluid” system.
Reliability is taken into account based on the calculated temperature of the motor. Thus, the most appropriate option for choosing a pump is the one for which the gas content is high, and the costs and temperature of the motor are low.
In some cases, it may be advisable to give preference to an option with higher costs, but with a lower temperature of the motor, which can ultimately result in lower costs due to a sharp increase in the reliability of the installation.
The selected pump size must meet the conditions for developing a well that is plugged with water. This condition is determined by the decrease in water level necessary to excite the well and the pressure that the pump can develop at the minimum required for development of the well and cooling of the electric motor when withdrawing liquid.
Obviously, the pressure required to develop the well will exceed the pressure in the steady state of the well, especially when pumping anhydrous carbonated oil. The coincidence of the steady operating mode of the well with the optimal pump mode ensures maximum efficiency. pump The coincidence of the optimal pump mode with the development mode leads to a shift of the steady state to the right of the optimum and to a decrease in efficiency. pump
For the range of pump sizes used, the ratio of the maximum pressure to the optimal pressure on water is within the range of 1.2 to 1.5.
Where is the reduction in water level in the well from the mouth necessary for development; - filter depth; - reservoir pressure; - the minimum required drawdown on the formation, ensuring the development of the well; - pressure on the well buffer; k - coefficient depending on the specific standard size ()
When using shut-off packers that prevent killing the well with water, this limitation can be lifted.
All necessary initial characteristics of the fluid, well, elevator, pump and collection system are presented in Table 10.1. The characteristics of the pumps are given in Table 10.2.
1. Determine the specific gravity of the formation fluid
where is the specific gravity of separated oil, t/m3; - specific gravity of gas, t/m3; - reservoir gas factor, m3/m3; - specific gravity of water, t/m3; - volumetric water cut; grandfather.; - volumetric coefficient of oil
2. Determine bottomhole pressure
where is reservoir pressure, atm; - design fluid flow rate, m3/day; - productivity coefficient, m3/day;
3. Determine the work of gas in the elevator
where is the diameter of the pump and compressor pipes, inch; - buffer pressure, atm.
4. Determine the pressure developed by the pump
where is the depth of the formation, m; - buffer pressure, atm; - gas work in the tubing, m3/m2;
5. Determine the pressure coefficient
where is a correction factor that takes into account the change in pressure coefficient depending on the number of stages Z.
- - optimal water pressure of the selected pump, kg/cm2;
- 6. Determine the relative pump flow for the liquid phase under meter conditions
where is the optimal water supply of the selected pump, m3/day;
- 7. For a given water cut b=0.8, using the relative flow obtained in step 6 and the pressure coefficient calculated in step 6, we determine the gas content at the pump inlet.
- * The value must lie at a given value of the feed coefficient within the field corresponding to the water feed in the range of 0.7 h1.2 (from the optimal one).
In the absence of a solution in this area, it is allowed to take values of the supply coefficient that give the value of the pressure coefficient in the area limited by the dotted lines, corresponding to the supply on water in the range of 0.5-1.4 (from the optimal)
We find the gas content value to be 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 saturation pressure, atm; - atmospheric pressure, atm;
Solving this equation, we find it equal to 0.441.
- 10. Determine the pressure at the pump inlet
- 11. Determine the pump suspension 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 ESP5-130-600, since it is optimal for the Uzen field.
Table 10.1 - Initial data for selecting an ESP
|
Measured and reported data |
Designation |
Dimension |
Meaning |
|
|
Specific gravity of separated oil |
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|
Viscosity of oil in reservoir |
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|
Volumetric water cut |
||||
|
GOR |
||||
|
Specific gravity of water |
||||
|
Oil volumetric coefficient |
||||
|
Saturation pressure |
||||
|
Reservoir pressure |
||||
|
Reservoir depth (for vertical wells, filter depth) |
||||
|
Productivity factor |
 |
|||
|
Buffer pressure |
||||
|
Design fluid flow rate |
||||
|
Elevator diameter |
||||
|
Reservoir temperature |
||||
|
Gas Specific Gravity |
||||
|
ESP pump type |
||||
|
Delivery at optimal mode on water |
||||
|
Pressure at optimal mode on water |
||||
|
Number of steps |
Table 10.2 - Pump characteristics
|
Standard size |
Number of steps |
Water supply at optimal mode |
Pressure at optimal mode |
|
|
ESP5-130-1200 |
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|
2ETSN5-130-1200 |
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|
ESP5A-160-1100 |
||||
|
ESP5A-360-600 |
||||
|
1ETSN6-100-900рх |
||||
|
ESP6-100-1500 |
||||
|
ESP6-160-1100 |
||||
|
1ETSN6-160-1450 |
||||
|
2ETSN6-250-1050рх |
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|
ESP6-250-1400 |
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