METHOD OF OPERATING OIL WELL USING ELECTRIC CENTRIFUGAL PUMP UNIT

Abstract

The invention relates to the field of mining, specifically to oil extraction using electric centrifugal pump units having a frequency-controlled electric motor, and serves to fully automate oil well operations using an electric centrifugal pump. A method of operating an oil well using an electric centrifugal pump unit, wherein temperature is regulated by means of changing the rotational speed of a pump shaft, which is a novel use of operating temperature as feedback for monitoring the state of the centrifugal pump. Using the invention allows for fully automating the process of launching, putting into an operational mode, and monitoring the operation of the oil well using the electric centrifugal pump unit, which, in turn, increases the overall reliability of the equipment (electric centrifugal pump unit).

Claims

1. A method for operating an oil well by installing an electrical submersible pump (ESP), comprising: installing the ESP in the oil well with a 25% allowance in a pump head at a respective installation depth; determining and entering operating parameters into a control station; checking an integrity of the ESP; setting initial AC frequency .sub.in at 50 H, setting a ESP temperature limit in such a way that ESP temperature is lower than an admissible temperature T.sub.p<T.sub.adm; recording operating parameters: initial ESP inlet pressure P.sub.inlet, initial ESP temperature T.sub.w0, current intensity I; putting the ESP into operation while recording ESP inlet pressure P.sub.inlet, ESP surface temperature T.sub.w, and ESP inlet temperature T.sub.f; operating the ESP up to the ESP's inlet pressure being higher or equal to a bubble-point pressure P.sub.inletP.sub.bpp; when ESP inlet pressure becomes equal to the bubble-point pressure P.sub.inlet=P.sub.bpp, recording temperatures T.sub.f and T.sub.w, defining a well-production rate Q.sub.f0, stabilizing ESP rate at constant or increasing (by no more than 10%) ESP inlet pressure over one or more hours; recording the following parameters: production rate Q.sub.f, ESP inlet pressure P.sub.inlet, ESP inlet temperature T.sub.f, ESP surface temperature T.sub.w, current intensity I.sub.oper, wherein difference between ESP surface temperature T.sub.w and ESP inlet temperature T.sub.f remains constant or drops by no more than 10% and stabilizes; when ESP inlet pressure P.sub.inlet is below the bubble-point pressure P.sub.bpp and difference T.sub.wT.sub.f is increasing, measuring the following: a bottomhole pressure P.sub.bh1, Kwell productivity factor (m3/day/atm), pressure of a fluid column from bottomhole to a level of ESP suction P.sub.fl.column, initial ESP inlet pressure P.sub.inlet0, reservoir pressure P.sub.res. equal to the bottomhole pressure in an idle well, and define increase in well-production rate using the following formula:
Q.sub.1=k(P.sub.resP.sub.bh1) at the pressure of P.sub.bh1=P.sub.inlet1+P.sub.fl,column, where P.sub.bh1bottomhole pressure, P.sub.fl,column=P.sub.inlet0, Kwell productivity factor (m3/day/atm) defined using the formula Q.sub.2=k(P.sub.resP.sub.bh2) at the pressure of P.sub.bh2 P.sub.inlet2+P.sub.fl,column, where P.sub.bh2bottomhole pressure after operation time t.sub.1; defining difference in increase in well production rate:
Q=Q.sub.2Q.sub.1=k(P.sub.inlet1P.sub.bh2), defining Z ratio: $Z=\frac{Q_{\mathrm{opt}}+.Math..Math.Q}{Q_{\mathrm{opt}}},$ reducing a ESP speed by Z, and stabilizing unit rate with ESP inlet pressure P.sub.inlet above bubble-point pressure, increasing centrifugal ESP speed based on the following relationship:
Q.sub.f=k(P.sub.inlet1P.sub.bpp); calculating AC frequency and current intensity along with measuring of ESP temperature T.sub.f, continuing ESP operation with values of most optimal production rate Q.sub.f,optimal, dynamic level H.sub.d, current intensity of unit I.sub.oper and ESP surface temperature T.sub.w.

2. The method according to claim 1, wherein the following operating parameters are entered into the control station: kwell productivity factor, m.sup.3/day*MPa; initial reservoir pressureP.sub.res., MPa; ESP operating temperatureT.sub.w.

3. The method according to claim 1, wherein for purposes of an ESP leak-off test, it is necessary to open a valve, set a rotation direction, close an flowline valve at an X-tree and start up the ESP, pressurize up to 40 atm at the X-tree, switch off the ESP and then check pressure at the X-tree over a course of 15 minutes.

4. The method according to claim 1, wherein temperatures T.sub.f and T.sub.w are recorded, and process of a unit start-up is repeated, provided ESP temperature T.sub.w is equal to ESP inlet temperature T.sub.f and current intensity I.sub.oper is equal to 1.

5. The method according to claim 1, wherein the ESP speed is reduced by Z.

6. The method according to claim 1, wherein ESP's operation continues with a reduced difference (T.sub.wT.sub.f) by more than 10% due to an increase in flow temperature at ESP inlet T.sub.f, with the values of T.sub.f, T.sub.w, well production rate Q.sub.f, dynamic level H.sub.d, ESP suction pressure P.sub.suction, current intensity I.sub.oper, voltage U.sub.oper, AC frequency.

7. The method according to claim 1, wherein the ESP is shut down for accumulation at decreasing ESP suction pressure and increasing ESP temperature up to a value of operating temperature of an extension cable until ESP suction pressure value reaches P.sub.suction=1.2 P.sub.bpp and provided $H_{\mathrm{curr}.\mathrm{head}}=\frac{H_{\mathrm{head}\left(.Math..Math.\mathrm{st}\right)}}{Z^2}.Math..Math.\mathrm{at}.Math..Math.T_w{T}_{\mathrm{adm}}$ where H.sub.curr.headcurrent head, H.sub.head(st)head of the ESP at a standard AC frequency (50 Hz), at the value of P.sub.suction=1.2 P.sub.bpp the ESP is put into operation with accumulation time t.sub.acc; pumping-out time t.sub.pump-out, operating current I.sub.oper, voltage U.sub.oper, initial and final ESP surface temperature T.sub.w, initial, T.sub.w, final.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0028] The details, attributes and advantages of the present invention will follow from the below description of the embodiments of the technical solution containing the drawings that show:

[0029] FIG. 1electrical submersible pump unit with a variable frequency drive;

[0030] FIG. 2a graph of pressure changes at the pump inlet;

[0031] FIG. 3a graph of the temperature of the pump T.sub.w over time;

[0032] FIG. 4a graph of the temperature of the pump T.sub.f over time;

[0033] FIG. 5a graph of the temperature of the pump over time;

[0034] FIG. 6motor temperature vs. time curve;

[0035] FIG. 7pump temperature vs. current frequency.

[0036] The following items are numbered in the figures:

[0037] 1submersible electrical motor; 2seal section; 3centrifugal pump; 4pump section; 5pump section; 6pump temperature gage; 7pump inlet temperature gage; 8pump inlet pressure gage; 9cable line; 10control station; 11tubing strings; 12valve with pressure gauge; 13X-tree; 14centrifugal pump suction.

DETAILED DESCRIPTION OF THE INVENTION

[0038] The electrical submersible pump unit (ESP) (FIG. 1) consists of the following: submersible electrical motor (1), seal section (2), centrifugal pump (3), pump section (4, 5), pump surface temperature gage (6), pump inlet temperature gage (7), pump inlet pressure gage (8), cable line (9), control station (10), tubing strings (11), valve with gage (12), X-tree (13), centrifugal pump suction (14).

[0039] The ESP is activated by the submersible AC electrical motor fed from the control station with AC frequency over the cable line (9) and rotates the centrifugal units in the pump mounted on the shafts of the centrifugal pump and sections (4, 5) coupled with the electrical motor shaft.

[0040] The centrifugal force that's created pumps the gas-and-fluid mixture through the openings in the bottom part of the pump, pumping it from vessel to vessel and further via tubing string to the oil gathering system. The ESP is installed in the well production string, and hung from the tubing string secured to the X-tree. The X-tree is tightly connected to the oil gathering system. The cable line (9) feeding the electrical motor is secured to the tubing string and connected to the control station (10) via a tight slot in the X-tree.

[0041] The control station is designed for start-up (shutdown), uninterrupted supply of alternating current over the cable line to the submersible electrical motor, serves for uninterrupted control of the cable line's insulation resistance, the measuring of AC frequency, the receipt of information from the sensors (6, 7, 8) transmitted via the cable line.

[0042] Automatic control of the ESP is only possible through the thermal state of the centrifugal pump. Therefore, the only parameter enabling definitive control for the entire ESP is the rate of change of the pump's relative temperature. The pump's relative temperature depends on the thermal parameters of the pump, the properties of the produced fluid.

[0043] Depending on the gas content at the pump suction, the pump's relative temperature changes definitively: it depends on the free gas content in the gas-and-fluid mixture at the pump suction. Gas content at the pump suction depends on the gas-oil ratio, bubble-point pressure, pump inlet pressure, water cut. Therefore, the pump's relative temperature can serve as feedback for automatic control of the ESPthe creation of unmanned technology.

[0044] The pump surface's relative temperature is calculated using the following formula:

[00003]$\begin{array}{cc}.Math..Math.T=T_w-T_f=\frac{.Math..Math.q_0.Math.R_2.Math.P_{\mathrm{inlet}}.Math.P_{\mathrm{bpp}}}{1-.Math..Math.2.Math.\left(1-W\right).Math.{\mathrm{hP}}_{\mathrm{atm}}.Math.G}.Math..Math.\left\{\frac{1}{}+\frac{{}_{\mathrm{ins}}}{{}_{\mathrm{ins}}}\right\}& \left(1\right)\end{array}$

where:
gas content at the pump inlet, unit fraction; q.sub.0thermal capacity of the pump, kW/m.sup.3; R.sub.2-radius of the external surface of the pump enclosure, m; P.sub.inletpump inlet pressure, atm; P.sub.bppbubble-point pressure, atm; W water content in the well product, unit fraction; hhead of one pump unit with respective gas content in the mixture, atm; Ggas-oil ratio, m3/m3; P.sub.atm-atmospheric pressure, atm; metal pump enclosure heat-transfer factor, W/m.sup.2* C.; .sub.ins-thermal-conductivity factor of the gas layer at the external pump surface, W/m.sup.2* C.; .sub.insgas thickness at the external pump surface, m; T.sub.fmixture temperature at the pump inlet, C.; T.sub.wpump surface temperature, C.

[0045] For the purposes of well operation, it is first necessary to select the ESP unit suitable for a production rate with a pump head allowance of 25% and depth of installation in the well.

[0046] The following operating parameters are entered into the control station: kwell productivity factor, m3/day*MPa (from 0.1 to 1 or more, depending on location in the well); initial reservoir pressureP.sub.res, MPa; pump operating temperatureT.sub.w.

[0047] Allowable temperature T.sub.adm (this temperature can be equal to the operating temperature of the cable line, for Russian cable lines less than 230 C.), C.; initial AC frequency.sub.in, Hz; optimal ESP capacityQ.sub.opt(ESP capacity at a frequency of .sub.in=50 Hz for Russian units), m3/day; current intensity of the motor I.sub.oper, A; voltage U.sub.oper, V; head created by the ESP at a standard frequency of 50 HzH.sub.head(); P.sub.bppbubble-point pressure.

[0048] Before ESP start-up, one has to make sure that the flow line is open (valve 12), rotation direction is straight and clockwise, pressure and rotation direction is right-handed. It is necessary to close the flow-line valve (12) at the X-tree, start up the pump, pressurize to 40 atm at the X-tree and shut down the pump. X-tree pressure will remain constant (pressure drop to 38 atm over 15 minutes is allowed)the unit is tight. Otherwise, the unit is not tight.

[0049] Thereafter, initial frequency coin, pump temperature limits T.sub.p<T.sub.adm are set. Temperature T.sub.adm (e.g. operating temperature of the cable line adjacent to the pump-allowable temperature (130 C.) 230 C. for Russian ESPs, (standard) thermal-resistant flat part adjacent to the centrifugal pump). ESP is put into operation; at the same time, pressure P.sub.inlet at ESP inlet, pump surface temperature T.sub.w and pump inlet temperature T.sub.f are recorded. At the same time, pump inlet pressure (FIG. 2), temperature T.sub.w (FIG. 3) and inlet temperature T.sub.f(FIG. 4) curves are built. Before start-up, initial pressure P.sub.inlet0, initial pump temperature T.sub.w0 are recorded. At the same time, current intensity I is recorded.

[0050] 1. The pump remains in operation until the following value is reached:

P.sub.inletP.sub.bpp(2)

[0051] 2. When the following equation is attained:

P.sub.inlet=P.sub.bpp(3)

[0052] T.sub.f and T.sub.w temperatures are recorded, the curves of dependence of P.sub.inlet, T.sub.f, T.sub.w and current intensity I on time are built, and the well production rate Q.sub.f0 is determined.

[0053] 3. That said, if the pump inlet pressure remains unchanged for one or more hours or increases slightly (by no more than 10%), the process of ESP start-up is considered completed. At the same time, the production rate Q.sub.f, pump inlet pressure P.sub.inlet, pump inlet temperature T.sub.f, pump surface temperature T.sub.w, current intensity I.sub.oper are recorded as the current parameters to be communicated to the company's process engineer (geologist).

[0054] 4. At the same time, the difference T.sub.wT.sub.f remains constant or reduces to a certain extent (by no more than 10%) and stabilizes.

[0055] 5. If the condition T.sub.f=T.sub.w is met during unit start-up, the current intensity I.sub.oper is checked: if the current intensity is equal to 0, the unit start-up process is repeated. Otherwise, it is necessary to check the unit's integrity.

[0056] 6. If the difference (T.sub.wT.sub.f) reduces by more than 10% due to growth in flow temperature T.sub.f at the pump inlet, operation of the centrifugal pump is continued: the process engineer receives the values of T.sub.f, T.sub.w, well-production rate Q.sub.f, dynamic level H.sub.d (pump suction pressure P.sub.suction), current intensity I.sub.oper, voltage U.sub.oper, AC frequency.

[0057] 7. If the pump inlet pressure P.sub.inlet continues dropping to become lower than the bubble-point pressure P.sub.bpp, so that the difference T.sub.wT.sub.f grows, then, based on the formula:

Q1=k(P.sub.res.P.sub.bh1) at the pressure of P.sub.bh1=P.sub.inlet1+P.sub.fl.col(4)

Q.sub.1fluid production rate (m3/day) at the bottomhole pressure of P.sub.bh1, where kwell productivity factor, m3/day*PMa; P.sub.bh1bottomhole pressure, P.sub.fl.col=P.sub.inlet0, P.sub.fl.colpressure of the fluid column from the bottomhole to the level of the pump suction, P.sub.inlet0 initial pump suction pressure, P.sub.res.-reservoir pressure equal to the bottomhole pressure of the idle well.
If the pump inlet pressure drops:

Q2=k(P.sub.res.P.sub.bh2) at the pressure of P.sub.bh2P.sub.inlet2+P.sub.fl.col(5)

where Q.sub.2fluid-production rate (m3/day) at P.sub.bh2bottomhole pressure after operation time t.sub.1. After we define the difference Q (increase in well production rate) between (5) and (4), we have:

Q=Q.sub.2-Q.sub.1=k(P.sub.inlet1-P.sub.inlet2)(6)

[0058] 8. Z ratio is further defined:

[00004]$\begin{array}{cc}Z=\frac{Q_{\mathrm{opt}}+.Math..Math.Q}{Q_{\mathrm{opt}}}& \left(7\right)\end{array}$

[0059] 9. The pump speed is reduced by Z:

[00005]$\begin{array}{cc}{}_1=\frac{{}_{\mathrm{st}}}{Z}& \left(8\right)\end{array}$

[0060] Further, the pump temperature is checked, and the dependency curves are built (FIG. 6).

[0061] 11. The dependency curves are built (FIG. 7) T.sub.w=f().

[0062] 12. Current ESP head is checked:

[00006]$\begin{array}{cc}{H}_{\mathrm{curr}.\mathrm{head}}\frac{H_{\mathrm{head}\left(.Math..Math.\mathrm{st}\right)}}{Z^2}& \left(9\right)\end{array}$

where: H.sub.curr.headcurrent ESP head at the frequency of .sub.i (i takes the values of process steps 1, 2, 3, etc.)

[0063] 13. By repeating items 6-8 i times, i.e. checking items 6-8 until

[00007]$\frac{.Math..Math.T_w}{}=00.05$

is reached and checking for the presence of condition (9), we see that:

[00008]$\begin{array}{cc}\frac{.Math..Math.T_w}{}=00.05& \left(10\right)\end{array}$

where
T.sub.wchange in the pump's surface temperature, change in current frequency.

[0064] 14. Then, we consider the process of the unit's rate stabilization completed.

[0065] 15. The process engineer (geologist) receives: the new frequency .sub.1, new production rate Q.sub.1, new pump inlet pressure P.sub.inlet, current intensity I.sub.oper1.

[0066] Intermittent Operation (Short-Term ESP Operation)

If the pump's suction pressure drops, and the pump's temperature increases to the allowable value, e.g. to the allowable temperature of the cable line attached to the pump enclosure, and the following condition is met:

[00009]$\begin{array}{cc}{H}_{\mathrm{curr}.\mathrm{head}}=\frac{H_{\mathrm{head}\left(.Math..Math.\mathrm{st}\right)}}{Z^2}.Math..Math.\mathrm{at}.Math..Math.T_w{T}_{\mathrm{adm}}& \left(11\right)\end{array}$

H.sub.curr.headcurrent head, H.sub.head(st)head of the centrifugal pump at a standard AC frequency (50 Hz). Then, ESP is shut down for the period of t.sub.accaccumulation time where the pump's suction pressure becomes

P.sub.suction=1.2P.sub.bpp.(12)

When P.sub.suction=1.2 P.sub.bpp, the pump unit is put into operation, and the dependency curve is built:

T.sub.w=f(t)(13)

[0067] At the pump temperature:

T.sub.w=T.sub.p,adm(14)

the ESP is shut down for accumulation.

[0068] The process engineer receives: accumulation time t.sub.acc; pumping-out time t.sub.pump-out, operating current I.sub.oper, voltage U.sub.oper, pump surface temperature T.sub.w, initial, T.sub.w,final (initial and final pump surface temperature).

[0069] At this point, we complete the process of ESP rate stabilization in short-term operation mode.

[0070] Optimizing ESP type and size

[0071] It is not uncommon that, in the process of ESP design for a specific well, some errors are made due to the unreliability of well data.

[0072] Therefore, after ESP start-up and its rate stabilization, the pump inlet pressure P.sub.inlet turns out to be higher than the bubble-point pressure. This means that there is a possibility of increasing oil production. For this purpose, it is necessary to increase the centrifugal pump's speed.

Q.sub.f=k(P.sub.inlet1-P.sub.bpp)(6.1)

[0073] We calculate the alternating current frequency using the following formula:

[00010]$\begin{array}{cc}Z=\frac{.Math..Math.Q_f+Q_f}{Q_f}& \left(7.1\right)\end{array}$

Q.sub.ffluid production rate until the frequency changes, m3/day, Q.sub.ffluid production rate increase after a change in pump speed, Znon-dimensional value.
Q.sub.ffluid production rate until the frequency changes, Q.sub.ffluid production rate, Zratio.

[0074] At the same time, the current intensity will increase and become equal to:

I.sub.z=Z.sup.3I.sub.oper

I.sub.opercurrent intensity at the production rate of Q.sub.f, Izcurrent intensity after an increase in production rate by Q.sub.f, i.e. with the cubic dependency of Z factor.

[0075] Therefore, a further change in alternating-current frequency will take place simultaneously with measuring the pump temperature T.sub.w with the following inequation:

T.sub.wT.sub.adm

[0076] At this point, we complete the process of testing well capabilities, the process engineer receives the following parameters: the most optimal production rate Q.sub.f, optimal, dynamic level N.sub.d, current intensity I.sub.oper and the pump's surface temperature T.sub.w.

[0077] 1. Case study of ESP ratestabilization

[0078] 1.1. As an example, let's review well No. 236 at field N.

[0079] The expected production rate is 18 m.sup.3/day at the dynamic-fluid level in the well (measured depth) N.sub.d-1600 m (TVD 1420 m). Pressure in the oil-gathering line is 14 atm. Friction resistance in the tubing is assumed to be equal to 5 atm (with a friction allowance of 10 atm). Total required head is 1900 m. Considering the head allowance of 25%, the necessary head is 2350 m. Based on the well productivity factor, we select ESP 5-20-2350. Let's assume that the bubble-point pressure is equal to 110 atm. GOR is equal to 140 m.sup.3/m.sup.3. Vertical depth of the well Hv=2680 m. Density of oil from the well is assumed to be equal to 752 kg/m.sup.3. Reservoir water density is 1004 kg/m.sup.3, reservoir temperature is 82 C., downhole gradient pressure is 0.03 C. per 1 m of hole. Well productivity factor is equal to k=0.11 m.sup.3/day/atm.

[0080] Optimal pump suction pressure P.sub.opt.suct=P.sub.bpp=110 atm. Then, the fluid column in the well is equal to:

[00011]$\begin{array}{cc}{H}_{\mathrm{column}}=\frac{{}_{\mathrm{oil}}}{g.Math..Math.{}_{\mathrm{mix}}}& \left(16\right)\\ {}_{\mathrm{mix}}=({}_{\mathrm{oil}}+\left(1-W\right).Math.{}_w.Math..Math.g=9.8.Math..Math.m.Math.\text{/}.Math.c^2& \left(17\right)\end{array}$

where .sub.mixmixture density; .sub.oiloil density; .sub.wwater density; W water content in the product.

[0081] Let's assume that .sub.oil-852 kg/m3; .sub.w-1004 kg/m3; W0.23

[0082] Mixture density: .sub.mix=(852*(1-0.23)+0.23*1004)=656+231+887

[0083] Fluid column:

[00012]$\begin{array}{cc}{H}_{\mathrm{column}}=\frac{110*101325.Math.\frac{}{{}^2}}{9.8*887}=\frac{12135650}{8692}=1396.Math..Math.m& \left(18\right)\end{array}$

[0084] 101325 n/m.sup.2=1 atmreduction factor.

[0085] By deducting from the vertical depth of the hole H.sub.column=1396 m, we have the dynamic vertical level:

H.sub.d=H.sub.wellH.sub.column=26801396=1284 m

[0086] or measured depth:

H.sub.d.md=H.sub.d+160=1284+160=1444 m

[0087] where 160 m is defined based on the directional log; H.sub.d.mddynamic level, measured depth (production string). Directional log is the difference between the measured hole depth from the vertical depth (defined by directional survey tool) and is constant for each well.

[0088] To define the depth for ESP installation, let's assume that the unit has no separator and conforms to the Operating procedure . . . applied by oil-production companies, that a gas content of 25% (=0.25) is allowed at the pump inlet.

[0089] Then, the gas content at the pump suction is equal to:

[00013]$\begin{array}{cc}=\frac{V_{\mathrm{pump}.Math..Math.\mathrm{inlet}}}{V_{\mathrm{pump}.Math..Math.\mathrm{inlet}}+Q_f}& \left(19\right)\end{array}$

[0090] where V.sub.pump inletgas volume at the pump inlet in normal conditions calculated based on the following formula:

V.sub.pump inlet=(Q.sub.f*G*(1W)*(1P.sub.inlet/P.sub.bpp)*(P.sub.atm/P.sub.inlet(20)

[0091] Let's assume that the production rate proportionally depends on the dynamic level, and according to formula (6) define the change in the production rate with the change in dynamic level H.sub.d to H.sub.d.md:

Q.sub.f=k*{(H.sub.d-H.sub.d.md)*.sub.mix*g}(21)

[0092] When we substitute the values, we define the well-production rate:

Q.sub.f=0.11*((16001444)*852*9.8)/101325=1.4 m.sup.3/day

where 101325 n/m.sup.2=1 atm (reduction factor).
At the dynamic level of 1444 m the production rate will decrease by 1.4 m3/day and amount to 16.6 m3/day.

[0093] Let's calculate the free-gas volume at the pump inlet based on (19):

[00014]$\begin{array}{cc}{V}_{\mathrm{pump}.Math..Math.\mathrm{inlet}}=\frac{}{1-}.Math..Math.Q_f=\frac{0.25}{1-0.25}.Math.16.6=5.5& \left(22\right)\end{array}$

Then, based on (20) we define the pump inlet pressure P.sub.inlet:

[00015]$\begin{array}{cc}{V}_{\mathrm{inlet}}=\frac{Q_f.Math.G\left(1-W\right).Math.P_{\mathrm{bpp}}.Math.P_{\mathrm{atm}}}{V_{\mathrm{inlet}}.Math.P_{\mathrm{bpp}}+Q_f.Math.G\left(1-W\right).Math.P_{\mathrm{atm}}}=\frac{16.6*140*\left(1-0.23\right)*110*1}{5.5*110+16.6*140*\left(1-0.23\right)*1}=82.Math..Math.\mathrm{atm}& \left(23\right)\end{array}$

[0094] ESP installation depth depending on dynamic level:

[00016]$H_{\mathrm{depth}}=\frac{82*9.8}{0.852}=943.Math..Math.m$

[0095] ESP hanger depth (vertical, from WH):

H.sub.depth=1444+943=2227 m

[0096] Based on the directional survey (according to the directional survey log):

H.sub.meas.depth=2227+230=2457 m

[0097] (230 m according to the directional survey log)

[0098] Relative pump temperature in case of operation with a gas content of 0.25 (25%), production rate of 18.6 m3/day at a dynamic level of 1444 m (with the pressure of 82 atm) will be equal to:

[0099] a) let's calculate relative pump temperature using the formula (1)

[00017]$.Math..Math.T=T_w-T_f=\frac{.Math..Math.q_0.Math.R_2.Math.P_{\mathrm{inlet}}.Math.P_{\mathrm{bpp}}}{1-.Math..Math.2.Math.\left(1-W\right).Math.{\mathrm{GP}}_{\mathrm{atm}}}.Math..Math.\left\{\frac{1}{a}+\frac{{}_{\mathrm{ins}}}{{}_{\mathrm{ins}}}\right\}$

[0100] For this purpose, let's calculate q.sub.0: thermal capacity of ESP vessels spent for heat generation. For this purpose:

[0101] a) let the nominal capacity of submersible electrical motor N.sub.nom=16 kW, efficiency factor of the whole ESP unit be equal to .sub.ESP=0.36;

[0102] But in the process of pumping-over the gas-and-fluid mixture with a freegas content at pump inlet of 25%, the efficiency factor drops to 0.2.

[0103] Then, the amount of heat generated by the unit is equal to:

Q=N.sub.nom*(1-0.2)=16 kW*0.8=12.8 kW(24)

[0104] b) let's calculate the number of vessels in the ESP unit; it is equal to:

[00018]$\begin{array}{cc}k=\frac{H}{h}=\frac{2350}{4}=587.Math..Math.\mathrm{vessels}& \left(25\right)\end{array}$

[0105] Of these, the number of vessels pumping over the heavily-gassed mixture to complete gas dissolving in oil (from an inlet pressure of 82 atm to a bubble-point pressure of 110 atm) is equal to:

[00019]$k_p=\frac{110-82}{0.08}=350$

[0106] Here, we assume that the average head in the range of 82 to 110 atm is equal to 0.08 atm (20% of nominal head equal to 4 m).

[0107] Having assumed that capacity is equally consumed by all of the ESP's operating elements (capacity attributable to 350 pump elements)

[00020]$\begin{array}{cc}{N}_p=\frac{12.8.Math..Math.\mathrm{kW}}{587}.Math.350=7.63.Math..Math.\mathrm{kW}& \left(26\right)\end{array}$

[0108] c) we will define the thermal capacity q.sub.0 per 350 elements, taking into account that the height of one element is 6 cm, diameter is 10 cm, and that the heat is distributed all over the pump 21 m long (350 elements). Then, the heat-source capacity of 350 elements is equal to:

[00021]$\begin{array}{cc}{q}_0=\frac{\mathrm{.4}.Math.N_p}{.Math..Math.d^2.Math.l}=\frac{7630*4}{3.14*0.01*21}=46284.Math..Math.W.Math.\text{/}.Math.m^3& \left(27\right)\end{array}$

[0109] where dpump diameter, lpump length, =3.14.

[0110] d) then, the relative temperature (temperature increase in the pump) is equal to:

[00022]$\begin{array}{cc}.Math..Math.T=T_w-T_f=\frac{0.25}{1-0.25}.Math.\frac{46285*0.05*82*110}{2.Math.\left(1-0.23\right)*0.08*140*1}.Math.\left\{\frac{1}{3800}+\frac{0.001}{8}\right\}=155.Math..Math..Math.C.& \left(28\right)\end{array}$

[0111] Let's calculate the absolute temperature of the pump, assuming that the geothermal factor is equal to 0.03 C./m.

[0112] For this purpose, let's calculate the mixture temperature at the pump inlet; it is equal to:

T.sub.f=82(26802227)*0.03=68 C. at the pump inlet.(29)

[0113] Then, the absolute pump surface temperature will be equal to:

T.sub.w=155+68=223 C.(30)

[0114] A temperature of 223 C. is close to the admissible temperature (admissible 230 C.).

[0115] A production rate of 16.6 for ESP 5-20-2350 is not acceptable, because for such an inflow, it is necessary to install a wellhead choke at the X-tree, which will result in inefficient power consumption.

Therefore, let's define the ratio:

[00023]$\begin{array}{cc}Z=\frac{20}{16.6}=1.2& \left(31\right)\end{array}$

[0116] Let's reduce the AC frequency of the submersible electrical motor Z times.

[0117] The frequency is equal to:

[00024]$\begin{array}{cc}=\frac{{}_{\mathrm{st}}}{Z}=\frac{50}{1.2}=41.7=42.Math..Math.\mathrm{Hz}& \left(32\right)\end{array}$

[0118] Then, the production rate will amount to 16.6 m3/day. The head will drop to:

[00025]$\begin{array}{cc}H=\frac{2350}{{1.2}^2}=1632.Math..Math.m.& \left(33\right)\end{array}$

[0119] Head balance: 1632 m=1444 m+50 m+138 m

[0120] Total required head is 1900 m. It is evident that a head of 1632 m is insufficient. Therefore, a further reduction in AC frequency is inadmissible.

Let's calculate the change in pump temperature with a reduction in AC frequency.
The consumed capacity will drop to:

[00026]$\begin{array}{cc}N=\frac{N_p}{{1.2}^3}=\frac{16}{1.44}=11.1.Math..Math.\mathrm{kW}& \left(34\right)\end{array}$

[0121] Thermal-source capacity is equal to:

[00027]$\begin{array}{cc}{N}_p=\frac{11,\text{:}.Math..Math.\mathrm{kW}}{587}.Math.350=6.61.Math..Math.\mathrm{kW}& \left(35\right)\end{array}$

[0122] Then, the capacity of the heat source in the pump according to ( ) amounts to:

[00028]$\begin{array}{cc}.Math.q_o=\frac{6610*4}{3.14*0.01*21}=40097& \left(36\right)\\ .Math..Math.T=T_w-T_f=\frac{0.25}{1-0.25}.Math.\frac{40097*0.05*82*110}{2.Math.\left(1-0.23\right)*0.08*140*1}.Math.\left\{\frac{1}{3800}+\frac{0.001}{8}\right\}=134.Math..Math..Math.C.& \left(37\right)\end{array}$

[0123] Absolute pump temperature is equal to:

T.sub.w=134+68=202(38)

[0124] By comparing the temperature gage's (6) and (8) readings, we find the difference T.sub.t: if

T.sub.tT(39)

[0125] with an accuracy of 5%, then we consider the process of well-rate stabilization completed.

[0126] Intermittent Operation:

[0127] If, in the process of ESP operation, relative pump temperature increases so that the head drops below the required head:

H.sub.oper<H.sub.d+H.sub.dH.sub.reg+H.sub.ogs(40)

[0128] where H.sub.operoperating pressure of the centrifugal pump, P.sub.inlet-pump inlet pressure, H.sub.ogs-pressure in the oil gathering system. That said, it is necessary to shut down the ESP, build the P.sub.inlet, vs. time curve. Define the time T.sub.acc of fluid accumulation in the well to the value of inlet pressure P.sub.inlet P.sub.bpp. The pump is put into operation with a pump temperature of up to T.sub.wT.sub.adm; at the same time, we take into account the unit operation time T.sub.oper. At the same time, we record the current intensity at the initial stage of pumping-out I.sub.in and I.sub.fin, define the initial well-production rate Q.sub.in and well production rate before shutdown Q.sub.fin (final production rate value). Let's calculate the volume of the lifted fluid as an arithmetic mean:

[00029]$\begin{array}{cc}Q=\frac{Q_{i.Math..Math.n}+Q_{\mathrm{fin}}}{2}.Math.T_{\mathrm{oper}}& \left(42\right)\end{array}$

The unit's operating parameters are provided to the process engineer: volume of produced fluid Q; unit operation time T.sub.oper; accumulation time (downtime)T.sub.acc.
All process parameters are communicated to the company's process engineer (geologist).

Optimization Mode.

[0129] If, after start-up, the pump's inlet pressure becomes constant and higher than the bubble-point pressure, it is necessary to define the additional well-production rate using the following formula:

Q=k(P.sub.bppP.sub.bh2)(43)

[0130] Let's calculate the change in pump speed (AC frequency) using the following formula:

[00030]$\begin{array}{cc}Z=\frac{Q_f+.Math..Math.Q}{Q_f}& \left(44\right)\end{array}$

[0131] We increase the current frequency from 50 Hz by 50 Z, define relative temperature. If it is not higher than admissible T.sub.n,add., we increase the speed stepwise:

=Z.sub.i(45)

[0132] With a further reduction in pump inlet pressure P.sub.inlet, it is advised to increase AC frequency based on (1).

[0133] All process parameters are communicated to the company's process engineer (geologist).

[0134] Scalinq Inhibition

[0135] To inhibit scaling, we reduce pump temperature to the condition of the beginning of the scaling process T.sub.salt.

[0136] The whole process of rate stabilization will take place according to items 9.1, 9.2, 9.3.

[0137] E.g. if the relative temperature of scaling beginning in the well is equal to 46 C., then T.sub.p,adm.=46 C.

[0138] All process parameters are communicated to the company's process engineer (geologist).