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GEOLOGICAL, COMMERCIAL AND TECHNOLOGICAL BASES FOR CHOOSING A METHOD OF DUAL COMPLETION EXPLOITATION TO INCREASE PRODUCTION AND ACCELERATED DEVELOPMENT OF MULTI-LAYER FIELDS
Deryaev Annaguly Rejepovich, Scientific Research Institute of Natural Gas of the State Concern Turkmengas, Ashgabat, Turkmenistan
E-mail: annagulyderyayew@gmail.com
Abstract. In order to successfully implement the method of simultaneous separate operation of gas reservoirs simultaneously in one and in another second elevator of oil reservoirs in one well, comparative laboratory analyses and field studies on the properties and compositions of oil, gas and condensate, which determine a significant role in the development of wells simultaneously-separate operation, were carried out.
The results of complex field studies of gas and oil wells and formations have been carried out in order to establish the gas dynamic parameters of the formation and well and study their gas condensate characteristics at the Altyguyi field. The main attention in the study of the well and the formation was paid to a more accurate determination of the value of the component composition of the formation gas required for the compilation of differential condensation isotherms, determined by sampling raw condensate. Based on laboratory studies, the substantiation of the scope, efficiency, reliability and the possibility of maximum extraction of oil reserves from multi-layer oil and gas horizons with a large depth of occurrence, composed of weakly cemented rocks, is given. The methodology of designing gas lift lifts, including the arrangement of starting and working valves, in accordance with standard ones, taking into account the properties of reservoir fluids and projected well flow rates, is also presented.
The main attention in the study of the well and reservoir was paid to a more accurate determination of the initial value of reservoir pressure, temperature, bottom-hole pressure, oil density and pressure recovery curve, which were carried out under various operating modes of wells, separation of condensate and water from products. As well as the work on measuring the determination of the amount of released condensate from 1 m3 of gas carried out at a complex field installation equipped with mobile block separators.
To a large extent, gas formations overlap oil formations by area, which creates favorable conditions for the implementation of methods of dual completion (DC) of oil and gas facilities with one well. Since most of the discovered fields contain several productive layers or horizons, the number of grids of production and injection wells,
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as well as flow rates, permissible depressions, the cost of producing tons of oil and other indicators depend primarily on the correct allocation of objects; consequently, the amount of material costs for drilling and operation of the field.
Based on the results of the calculations carried out, the justification of the implementation of the DC in the wells of a multi-layer gas condensate field was carried out.
Key words: flow rate, condensate, asphaltene, sulfur, paraffin, barometric, pressure gauge, pressure dynamics, downhole pressure, specific flow rate, gas lift valve, reservoir fluid.
Simultaneous development of several formations by one object is possible only with the same physical and chemical properties of oils in the combined formations, if the inflow of oil and gas is sufficient from each formation at an acceptable bottom-hole pressure in the well, with close values of reservoir pressure in the combined formations, excluding oil flows between the layers, and close values of reservoir waterlogging. If the above conditions are not met, then multidimensional deposits are developed by the DC method with one well [1].
At the Altyguyi deposit in the NK9 horizon, free gases contain 97.90% methane, up to 1.19% of its homologues, up to 0.70% nitrogen and 0.21% carbon dioxide.
In the NK7g horizon, free gases contain 97.20% methane, up to 1.54% of its homologues, 0.67% nitrogen and 40.17% carbon dioxide.
In the NK8 horizon, free gases contain 97.20% methane, up to 2.08% of its homologues, 0.55% nitrogen and 0.17% carbon dioxide. The oil of the NK9 horizon has a density of 0.9065 g / cm3, solidifies at a temperature of +33 °C, the viscosity at a temperature of 50 °C is 51.69 Pz, and at a temperature of 20 °C does not flow. Up to a temperature of 300 °C, it boils by 19%. The composition contains 4.7% asphaltenes, 16.7% resins, 21.4% paraffin and 0.41% sulfur.
According to the group hydrocarbon composition, they belong to the methane-naphthenic geochemical type (H: M 0.99), contain 13% aromatic, 43.3% naphthenic and 43.7% methane hydrocarbons.
The density of condensates of the NK7g horizon is 0.7 0.53 g / cm3, solidify -3 ° C, viscosity at a temperature of 20 °C 1.79 Pz. Up to a temperature of 300 °C, boil up to 77%.
According to the group hydrocarbon composition, they belong to the methane-naphthenic geochemical type. (H: M 0.83), contain 9.0% aromatic, 41.7% naphthenic and 49.3% methane hydrocarbons (Table 1.2).
The density of condensates of the NK9 horizon is 0.7971 g/cm3, they solidify at a temperature equal to +3 °C, the viscosity at a temperature of 20 °C is 1.8 s Pz. Up to a temperature of 300 °C, up to 76% is boiled off. The composition contains 1.4 resin, 3.5% paraffin and asphaltene is absent. By group composition, they belong to the methane-naphthenic geochemical type (H:0.84) and contain 9.9% aromatic, 41.2% naphthenic and 48.9% methane hydrocarbons.
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Table 1
Properties and composition of the gas (average value over the horizons)
Horizon Interval Perforations, (m) Density Quantity, % volume
g/l by air CO2 Nitrogen CH4 C2H6
Soluble gases
NK-9 3670-3680 0,742 0,574 0,21 0,70 97,90 1,60
Free gases
NK -7d 3512-3624 0,738 0,571 0,22 0,67 97,57 0,94
NK -8 3616-3625 0,737 0,570 0,17 0,55 97,20 1,14
Table 2
Properties and composition of the gas (average value over the horizons)
Horizon Interval Perforations, (m) Quantity, % volume
C3H8 C4H10 C5H12 C6+above
izo nor izo nor
Soluble gases
NK-9 3670-3680 0,32 0,06 0,07 0,02 0,01 -
Free gases
NK -7d 3512-3624 0,30 0,08 0,13 0,05 0,05 -
NK -8 3616-3625 0,62 0,07 0,17 0,05 0,05 -
According to the conducted studies from wells 1,2,5,6,7,8, and 9 samples of reservoir waters under laboratory conditions, their chemical and physical properties were determined. The selected reservoir water samples belong to depths of 3546-3771 m and correspond to the lower deposits of the red-colored strata of the NK7-NK9 horizons (Tables 3 and 4).
Table 3
Properties and composition of reservoir waters
Well number Horizon Depth interval, m Density g/cm3pH Composition mg/l, mg-equivalent/l
Cl SO4 HCO3
1 NK -8 3616-3625 1,016 15546 0 805
7,7 438 0 13
2 NK -8- NK -9 3546-3659 1,019 17753 1056 1763
8,1 500 22 29
5 NK -7d 3618-3624 1,010 8787 0 525
8,2 248 0 9
6 NK -9 3690-3694 3700-3703 1,039 31092 352 976
7,3 876 7 16
7 NK -9 3746-3750 1,027 21629 96 2135
7,1 609 2 35
7 NK -9 3768-3771 1,035 28389 96 1586
7,0 800 2 26
8 NK -7d 3660-3662 1,020 20277 1120 427
7,5 571 23 7
8 NK -8 3732-3734 1,015 14870 160 769
8,2 419 3 13
8 NK -9 1,040 20277 160 488
6,7 571 3 8
9 NK -8 1,036 29233 160 1403
7,5 823 3 23
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Formation waters with chlorine calcium have a hydrocorbonatrium and sulfonate sodium appearance and salinity properties from 15 to 50 g/l [2, 3].
The weakest mineralized sodium bicarbonate waters with a salt content of 15 g/l on the convex part of the structure, and highly mineralized chlorocalcium brines are found in the reclinal part of the structure.
Such hydrochemical properties of reservoir waters are also found in the approximate deposits of Altyguy. These patterns are associated with tectonic disturbances.
Table 4
Properties and composition of reservoir waters
Well number Horizon Depth interval, m Composition mg/l, mg-equivalent/l Amount mg/l Type of water
Ca Mg Na+K
1 NK -8 3616-3625 401 0 9913 26665 Oil+condensate
20 0 431
2 NK -8 NK -9 3546-3659 808 0 11753 33139 Water+Oil
40 0 501
5 NK -7d 3618-3624 90 18 5750 15170 Gas+condensate+Oil
5 2 250
6 NK -9 3690-3694 3700-3703 1202 730 17917 52269 Oil+condensate
60 60 779
7 NK -9 3746-3750 641 486 13202 38189 Oil+condensate
32 40 574
7 NK -9 3768-3771 882 632 16836 48421 Oil+condensate
44 52 732
8 NK -7d 3660-3662 801 291 12351 35267 Oil+condensate
40 24 537
8 NK -8 3732-3734 401 243 9085 25528 Oil+condensate
20 20 395
8 NK -9 3777-3781 3607 0 9246 33778 Oil+condensate
180 0 402
9 NK -8 3519-3521 1202 632 16951 49571 Oil+condensate
60 52 737
The hydrochemical properties of the structure of the Altyguyi deposit make it possible to assert a high degree of oil and gas content of the lower part of the red-colored strata and the underlying rocks.
The substantiation of the potential condensate content in the formation gas was carried out by the method of compiling isotherms of differential condensation of gas condensate systems based on the results of calculations. These isotherms were used to determine the pressure of the beginning of condensation and the potential condensate content in the formation gas [4].
When using this method, the component composition of reservoir gas required for the compilation of differential condensation isotherms, determined by sampling raw condensate into containers during product separation and its further degassing, debutanization in laboratory conditions, for all gas condensate systems is determined
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by summing cs5fabove (in separation gas) and c^ahove (content, in % of pentanes and above boiling in stable condensate), calculated from the output of stable condensate qst (cm3/m3, density p and molecular weight of stable condensate) by the expression:
st.c. _ 2,404 * p
C
5+Babove
M
-5
where qst is the output of stable condensate, g/m ; p is the density of stable condensate, g/m3; M is the molecular weight of the condensate.
The value of the molecular weight (M) was not indicated in the studies for condensate systems and was calculated by the formula:
M - 44,29
Ps,c.+ 0,004 1,034 -pst.c. '
The remaining components are accepted unchanged. Next, we calculate the composition of the reservoir gas:
1) rS-s - cst ■c ■ — CMres-S-
J 4 ^ 5+above - 4
2 )CS S - Cst.c. - CMres g■ ^ 5+above ^5+above 5+abo
The indicators of the constructed graph of differential condensation isotherms are given in Tables 5 and 6, and their results in Tables 7 and 8.
Table 5
Information for calculating the differential condensation isotherms for the gas condensate system by the PS/AT PC program
№ Horizon Perforation in- n2 CO2 H2S CH4 C2H6 C3H8 C4H10
well terval, (m) nor izo
2(III) NK-7d 3512-3522 0,87 0,25 - 96,7 0,71 0,29 0,1 0,08
1(II) NK -8 3616-3625 0,32 0,2 - 96,7 0,91 0,26 0,1 0,08
5(I) NK -7d 3618-3624 - 0,2 - 97,0 0,96 0,24 0,07 0,07
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Table 6
Information for calculating the differential condensation isotherms for the gas condensate system by the PS/AT PC program
№ well cs-g 5+above Stable condensate output T A res M Fractional composition of the condensate mixture %
begining of boiling C 10 50 90 end of boiling 0C remains
2(III) 0,87 0,25 - 96,72 0,71 0,29 0,1 0,08
1(II) 0,32 0,2 - 96,75 0,91 0,26 0,1 0,08
5(D - 0,2 - 97,02 0,96 0,24 0,07 0,07
Table 7
The results of the calculation of the differential condensation
isotherms for the gas condensate system by the PS/AT PC program
№ well Horizon Perforation interval, (m) Pressure kgf/s2
Formation (initial) The beginning of condensation Expedient condensation
2(III) NK 7d 3512-3522 510 518 50-80
1(II) NK -8 3616-3625 496 494 50-80
5(I) NK -7d 3618-3624 524 526 50-80
Table 8
The results of the calculation of the differential condensation isotherms for the gas condensate system by the PS/AT PC program
№ well Horizon Perforation interval, (m) Stable condensate output 3 3 (initial), cm /m Amount of potential condensate g/m3 Density of stable condensate g/cm3
2(III) NK -7d 3512-3522 86,2 69,5 0,7877
1(II) NK -8 3616-3625 118,4 93,2 0,7959
5(I) NK -7d 3618-3624 103 96,5 0,7910
Based on the constructed graphs of differential condensation isotherms for gas condensate systems of 3 wells, the pressure of the beginning of condensate separation from natural gas is determined, the values of which are equal to or close to the initial reservoir pressure of the well (see tables 7, 8 and Fig. 1-3).
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Fig. 1 Graph of isotherms of differential condensation of the gas condensate system of well № 2 (III) on the Altyguyi field
Fig. 2 Graph of isotherms of differential condensation of the gas condensate system of well № 1 (II) on the Altyguyi field
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* Fig. 3 Graph of isotherms of differential condensation of the gas
condensate system of well № 5 (I) on the Altyguyi field
From the constructed isotherms, the amount of condensate content in 1 m of reservoir gas for wells № 2 (III), №.1 (II) and 5 (I) respectively obtained 69.5 g/m3, 95.2g/m3 and 96.5g/m3. Potential stability of condensate, g/cm3
Therefore, in the composition of 1m3 reservoir gas, the amount of condensate content is assumed for the horizon for the horizon NK7d 80.5 g/m3 and the horizon NK8 95.2g/m3 [5].
Based on the results of the developed differential condensation isotherms, the beginning of the condensation pressure for the III well object №. 2 is 518 kg/cm2 (Pres=510 kg/cm2), for the II well object №.1 496 kg/cm2 (Pres=494 kg/cm2) and for the I well object №. 5 526 kg/cm2 (Pres =524 kg/cm2).
During the periods of gas-hydrodynamic studies and pilot operation of gas condensate deposits of the field, due to the absence of experimental installations UGK -3, UFR, thermodynamic studies to determine the recovery coefficient and condensate losses for gas condensate deposits of the Altyguyi field were not carried out. These parameters were determined from the equation:
a = 11,325 + 0J05P':
Presmit. - initial reservoir pressure, kgf/cm2; £ - condensate losses in the reservoir, %.
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The above expression is derived from the graph (see Fig. 4-5), plotted in
init\
coordinates 5 = f (Pres)
Fig. 4 Dependence of the initial reservoir pressure on the volume of condensate loss in the formations of the Gogerendag-Ekerem fields
Fig. 5 Dependence of the initial reservoir pressure on the volume of condensate loss in the reservoirs of the fields of South-Western Turkmenistan
It should be emphasized that this dependence was revealed on the basis of numerous experimental studies on the installations of RUT, UGK-3 systems of gas condensate deposits of Southwestern Turkmenistan, which have common specific features, as well as an undoubted genetic community.
This method has been sufficiently tested and is widely used in determining losses and the coefficient of condensate extraction from the subsurface [6].
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Certain values of the pressure of the beginning of condensation; the potential condensate content in the reservoir gas; reservoir losses and the condensate recovery coefficient obtained from the dependence:
o = f(P™) for all investigated objects.
o = film's ) the dependence of the specified volume of condensate loss in the reservoir and the coefficient of condensate recovery for the horizons NK7d and NK8 due to the proximity of the depth of occurrence (location) and the initial pressure, the value for the two horizons is assumed to be the same, respectively 65.6% and 0.344.
The determination of the initial indicators of wells and formations at the Altyguyi deposit was achieved using the method of steady-state sampling, which, even under steady-state filtration regimes in the bottom-hole zone of the formation, were carried out in order to establish the gas-dynamic parameters of the formation and wells, to study their gas-condensate characteristics.
The filtration mode was changed by selecting the diameter of the fitting at the wellhead.
The duration of operation in oil and gas wells for at least 24 hours and for gas condensate wells in each mode was from 5 to 24 hours. The measurement on each mode began after the full stabilization of the wellhead pressures of Pbuf and Pannui.
The measurement of reservoir and bottom-hole pressures and the recording of the pressure recovery curve were carried out with deep pressure gauges of the MGN2-800kgs/cm2 type and MSU-1-100-160 and in some places with electronic geophysical devices "Granite" and "Sakmar".
The necessary indicators for calculating the determination of the daily gas flow rate were carried out using a separator of the PBS-350/64 type with a measuring diaphragm with a diameter of 50 mm.
Measurements of the daily gas flow rate were carried out using a complex field installation equipped with a separator of the "Demag" type and flow meters of the DSP -0.063 and DPS-1.6 types.
The parameters for determining the gas flow rate were calculated using 4- or 2-inch diaphragm meters of critical gas flow (DICT) [7].
Wellhead pressures (Pbuf and PannuO were recorded with model pressure gauges of the MO type at 250, 400 and 600 kgf/cm2, accuracy class ± 1, ± 0.6% and ± 0.4%.
Bottom-hole and reservoir temperatures are determined by thermometers with mercury columns of the TP-7 type.
In some facilities, it was not possible to close the well to the reservoir pressure value due to technical reasons. In these circumstances, the reservoir pressure was determined by the experimental method [5].
Application of the method under steady-state filtration conditions of products in the bottom-hole zone of the formation for trial operation (with a change in mode),
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complex hydrodynamic studies were carried out in 17 objects, 16 wells, in an amount of 22 times. Only on 6 wells (№№12, 19, 107, 108, 111 and 112), measurements of the daily flow rate were carried out, and in 4 wells (№№. 7, 21, 105 and 107), a one-time measurement of reservoir and bottom-hole pressure was carried out. At oil well sites № 2 and №. 7, the study was carried out by the method of normalizing the fluid flow -pressure recovery curve (PRC). As a result of processing the obtained materials, the coefficient of hydroconductivity and permeability of the formation was calculated by the Horner method. The obtained results of the development, measurements and their definition are given in the table 9. Graphs of the pressure recovery curve are shown in Figures 6 and 7.
Table 9
The results of hydrodynamic studies at the wells of the Altyguyi field
Well number Fitting diameter (m) Coefficient
Horizon Perforation interval (m) Capacity (kg/cm2) Hydrocon-ductivity (sP) Permeability (mD) Note
Research in order
5 - - -
6 - - -
8 - - -
- 0,1807 4,4 14,52
Repeated research
6 - - -
5 - - -
1(I) nk9 3670-3680 4,8 - - -
5,6 - - -
6,4 0,264 6,43 21,2
4 - - -
5 - - -
2(I) NK 9 3608-3618 6 0,9043 10.1 on PRC 34,34 on PRC
4
3(I) NK 9 3732-3738 5
6 0,171 4,2 23,1
4,8
4 NK 9 3728-3740 5,6
6,4 1,1107 27,1 74,53
4 - - -
4,8 - - -
7(II) NK 9 3746-3750 3,1 0,8493 22,03 on PRC 93,4 on PRC
6,3 - - -
10(I) NK 9 3653-3662 8,0 - - -
4,8 0,4914 12,00 44,0
4 - - -
106(I) NK 9 3783-3792 5 - - -
6 1,3552 33,0 -
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80000
70000 60000 I 50000
at
i
30000 20000 10000
0 0,5 i 1,5 2 2,5 i 3,5 ¡g.c. 4 4,f
Fig. 6 Graph of the curve of recovery of bottom-hole pressure to reservoir pressure, during the study of production well № 2 of the Altyguyi field
0 12 3 4 'B-'T 5
Fig. 7 Graph of the curve of recovery of bottom-hole pressure to reservoir pressure, during the study of the II-th object of the exploration well № 7 of the Altyguyi field
The specific gravity of Altyguyi oil in comparison with the oil of other fields in the Southwestern part of Turkmenistan is very heavy (0.910 g/cm3) and has a lot of paraffin in its composition. In the process of oil extraction, the paraffin contained in the product freezes due to a decrease in temperature at a depth of 800-1000 meters. In this regard, the freezing of paraffin leads to a decrease in the inner diameter of the tubing, an increase in downhole pressure and a decrease in daily oil production [6]. This phenomenon has the opposite effect on determining the productivity coefficient of the well and the exact calculation of some reservoir indicators.
Before conducting hydro and gas dynamic studies, it is recommended to clean the inner walls of the tubing from the layers of paraffin.
Taking into account the above, the proposed values of the initial reservoir pressure and temperature of the NK9 oil horizon are assumed to be the values of the accurately performed measurements of the II-th object of well № 7 - 643 kgf/cm3 and 87 0C.
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To study the indicators of a gas condensate field and to determine the amount of condensate released from 1 m3 of gas, as well as conducting gas-hydrodynamic studies in productive wells and formations, were performed by methods and instruments that were used in gas-hydrodynamic studies in oil horizons.
In some wells, for technical reasons, the reservoir and bottom - hole pressure was determined by the barometric formula on uncovered and not lowered depth gauges:
Pb-h. _ Pb(annul) ' e
The separation of condensate and water from the products, as well as work on measuring the determination of the amount of separated condensate from 1 m3 of gas, was carried out at a complex field installation equipped with a mobile block separator of the PBS-350/64 type and a separator of the DEMAG type.
In general, during the period of exploratory drilling and testing of the productivity of drilled gas condensate wells, complex studies were carried out in 11 objects of 5 wells in the established modes of liquid or gas filtration (№ 2, 5, 102, 1, 20). In three wells (№1, 2 and 101), 4 comprehensive studies were carried out on unsteady filtration modes (pressure recovery curve) [8].
The result of working off the PRC for production well № 101 is shown in Fig. 8.
Fig. 8 Graph of the curve of recovery of bottom-hole pressure to reservoir pressure for production well № 101 at the Altyguyi field
To determine the initial reservoir pressure and temperature of the NK7d horizon, the average reservoir pressure values of 517 kgf/ cm2 and 87 °C are proposed, which were obtained during the study of the NK7d horizon of the II object of well № 2 and the I object of well №.5.
Considering the close location of the NK7d and NK8 horizons (about 30 m.), the reservoir pressure and temperature were assumed to be P = 517 kgf/cm2, T = 87 C.
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Work on the determination of condensate indicators and the study of thermodynamic characteristics of wells and reservoirs for both horizons was carried out jointly.
Gas condensate wells and reservoirs were studied in three stationary filtration modes [9].
The results of gas dynamic studies and determination of the amount of condensate released from 1 m3 of reservoir gas (gas condensate factor - GCF) are shown in Table 10.
Table 10
The results of field studies to study the gas condensate properties of wells and formations at the Altyguyi field
№ well Horizon Perforation interval, (m) Fitting diameter (mm) Operation in the mode (hour) Condensate output (cm3/m3) Molecular weight of condensate
1(II) NK8 3616-3625 12 24 241,9 181,4 -
10 15 157,4 118,4 -
- - - - 151,5
8 8 114,7 88,6 -
9,5 24 11,7 9,6 -
8 15 13,9 11,4 -
6 15 15,5 12,7 -
1(I+II) NK 8+ NK 9 3512-3522 3670-3680 - - - - 150
10 24 OKH productive -
8 18 -
6 16 -
- - -
6 24 OKH productive -
8 22 -
10 20 -
2(III) NKyd 3512-3522 8 24 64,6 56,2 -
- - - - -
12 24 - 60,5 159
8 22 - 29,6 -
10 18 - 46,3 -
2(III) NKyd 3512-3522 6,5 24 107,5 93,4 -
8 18 97,2 81,6 -
9 15 99,8 86,2 -
- - - - 159
9,5 22 14,3 13,1 -
8 17 12,9 12,0 -
6 15 23,4 21,5 -
- - - - -
5(I) NK 7d 3618-3624 10 20 111,8 102,8 -
8 21 118,6 104,4 -
6 15 113,1 101,8 -
- - - - 144,5
9,5 20 10,6 8,7 -
8 21 12,8 10,5 -
6 15 16,2 13,2 -
- - - - 153,5
8 24 50,9 43,8 -
- - - - 149
12 24 - 51,4
8 21 - 46,9
10 16 - 46,3
101 NK 8 3564-3566 12 24 - - -
10 24 - - -
8 16 - - -
20 (III) NK 8 3950-3958 - - - - -
9,5 22 - - -
8 17 - - -
6 15 - - -
- - - - -
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The results of hydro - gas dynamic studies of wells and formations of gas condensate deposits were processed using a two - term formula:
Pres. = P2-h = aQ2 + b • Q2,
where: Pres. and Pb-h - respectively, reservoir and bottom-hole pressure, kgf/cm ;
Qg is the flow rate of separation gas, thousand m3/day;
a and b, respectively, are the coefficients of filtration resistance, depending on the parameters of the bottom-hole zone of the formation and the design of the well bottom.
The flow rate of the reservoir fluid Qresfi is calculated using the following formula:
Q _ Q QCat + Ge,
Qres.fl. Qs.g. + 3
3
QjBs.fi - reservoir mixture, thousand m /day;
Qs.g - flow rate of separated gas, thousand m3/day;
Qcs at - saturated condensate flow rate, m3/day;
Geqv is the calculated gas equivalent of the transfer of the liquid phase (condensate) to the gas phase.
The gas equivalent is determined by the formula
Geqv= 23342 -pi M,
Here p and M are, respectively, the density and molecular weight of the C5+b fraction.
The value of the molecular weight of the C5+b fraction is calculated by the formula
M = 44,29(p'-+ 0,004) (1,034 -pf) '
where QC1 is the density of stable condensate.
Tables 11, 12 and 13 show the values of reservoir and well parameters determined when processing the results of gas-dynamic studies and the output of stable condensate for the studied objects.
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Table 11
The results of calculations of studies to study the gas condensate properties of wells and formations at the Altyguyi field
№ well Horizon Perforation interval, (m) Type of research Reservoir pressure (kgf/cm2) Reservoir temperature (0C) Stable condensate output (cm3/m3)
1(II) NK 8 3616-3625 initial 496 84 119
regular 452 89 11,4
1(I+II) NK 8+NK 9 3512-3522 3670-3680 regular 452 91 -
regular 308 88 -
2(111) NK 7d 3512-3522 regular 510 81 86,2
regular 490 87 12
regular 471 82 56,2
regular 270 81 60,5
5(I) NK 7d 3618-3624 regular 524 84 103
regular 487 90 8,7
regular 426 82 43,8
regular 274 84 51,4
20 NK 8 3950-3959 regular 400 96 4
regular 336 87 96,1
101 NK 8 3564-3566 regular 358 78 85,6
Table 12
The results of calculations of studies to study the gas condensate properties of wells and formations at the Altyguyi field
№ well Horizon Perforation interval, (m) Filtration resistance coefficient Absolutely free gas flow rate (thousand m3/day) Coefficient of gas conductivity (m/sP) Filtration coefficient (mD)
a b
1(II) NK 8 3616-3625 57,7 0,38 732,3 7,87 26,2
137,6 0,243 677 3,4 11,2
1(I+II) NK 8+ NK 9 3512-3522 3670-3680 86,1 0,411 713 5,37 8,1
11,0 0,423 460,7 41,7 65,9
2(III) NK 7d 3512-3522 92,5 0,1 1205,5 4,73 14,2
37,9 0,112 1304,3 12,1 36,3
- - - - -
67,8 0,0123 921,2 6,6 20,0
5(I) NK 7d 3618-3624 187,8 0,194 800,4 2,42 12,1
80,5 0,111 1144,6 5,74 28,7
- - - - -
93,1 0,0144 725,1 4,9 24,4
20 NK 8 3950-3959 - - - - -
134,4 0,784 303,2 3,4 12,8
101 NK 8 3564-3566 84,2 0,327 510,4 5,3 79,7
The proposed indicators of stable condensate yield are accepted along the horizon of NK 7g - 95 cm3/t3; along the horizon of NK8 - 118 cm3/t3.
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According to the results of measurements, an accelerated drop in reservoir pressure was revealed at the beginning of the operation period [10].
Despite the short period of the start of operation of gas condensate reservoirs, the results of measurements revealed an accelerated drop in reservoir pressure.
For example, well №2 was put into operation in 2009 with an initial reservoir pressure of 510 kgf/cm2. In 2010, the reservoir pressure was measured at 490 kgf/cm2, and in 2014 it was 270 kgf/cm2.
Table 13
The results of the study of the field determination of the properties of stable condensate
№ well Horizon Perforation interval, (m) Fitting diameter (mm) Condensate output from 1 m3 of reservoir gas, (cm3/ m3) The rate of entry of the mixture into the barrel is tubing (m/sec)
intense stable
1(II) NK 8 3616-3625 10 157 118 4,95
9,5 12 10 4,5
10 A light hydrocarbon is oil. The specific gravity is 0.8455 g/cm3. Due to the high gas factor, calculations were carried out on gas.
6
2(III) NK7d 3512-3522 8 97 82 4,1
8 13 12 4,3
8 65 56 3,5
10 - 60,5 4
5(I) NK7d 3618-3624 8 119 105 4,1
8 13 11 4
8 51 44 3,8
10 - 46 4
20 NK 8 3950-3959 8 - 4 -
12 - 55 4
101 NK 8 3564-3566 10 - 83 4
Well № 1 in the gas condensate facility of the NK8 horizon was put into operation during development with an initial reservoir pressure of 496 kgf/cm2 in 2009. In 2014, when measured, its readings amounted to a drop to 306 kgf/ cm2.
We believe that the reason for the low values obtained during the study is not the creation of an appropriate regime for the separation of products.
A number of geological and commercial, climatic and technological factors are manifested at the gas condensate field, which characterize the operation of wells as operation in complicated conditions.
The main features complicating the operation of oil wells of this field are:
- large depths of productive formations;
- high initial pressures drop sharply, respectively, the liquid level in the wells decreases;
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- operation of wells at pressures below saturation pressure;
- high values of gas factors;
- curvature and curvature of well pillars;
- oil formations have a sharp degree of cementation from dense sandstones and siltstones to loose sands and siltstones, which leads to sand formation;
- the extracted oil is highly paraffinic;
- productivity coefficients vary widely;
- increasing the estimated depth of gas input into the lift of gas lift wells from the mouth.
The choice of mechanized methods of oil production at a gas condensate field is carried out taking into account the above factors. In addition to them, relief climatic conditions, inter-repair periods, the presence of paraffin and mechanical impurities in the extracted liquid, the reliability of equipment, the need for maintenance personnel and repair equipment, ease of maintenance in the process of mechanized oil production, production capabilities, the need for energy resources are also taken into account [11].
In the multi-layer gas condensate field of Turkmenistan, by the nature of saturation, the presence of pure oil deposits, pure gas deposits and gas deposits with oil rims is noted. For most deposits, the mixed regime is characterized by the predominance of the energy of gas released from oil and the manifestation of the activity of contour waters at a later stage of development.
The development project does not provide for the maintenance of reservoir pressure, and therefore the exploitation of deposits will be carried out with a continuous drop in reservoir pressure, a decrease in static fluid levels in wells and an increase in the height of its rise.
In the fields of Turkmenistan, the gas lift method of oil production has been widely used.
The extraction capabilities, as well as the reliability of the use of gas lift operation, have shown that it is more efficient than other methods of mechanized extraction.
The conditions for lifting the liquid in a gas lift well mainly depend on the parameters of the lift itself, the pressure of the working agent and the parameters of the reservoir. The greatest role is played by the height of the liquid rise. In the field of the Western part of Turkmenistan, specific factors are: a high lifting height, low flow rates, an increase in the water content of products over time, the availability of working agent (gas) resources.
The practice of gas lift operation at the field of Turkmenistan proves the expediency of its use in both continuous and periodic lifting of liquid. For the purpose of the most efficient operation, wells with debits above 30 t/day are recommended to be operated with a continuous gas lift. Wells operating with debits below 30t/day should be operated with a periodic gas lift. In the conditions of a gas condensate field, a periodic gas lift is the most realistic, ensuring the design production volumes until the end of development [12].
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When studying the geological and operational characteristics of the field, it was revealed that oil and gas layers alternating in productive horizons are isolated from each other by impermeable layers having relatively large thicknesses. To a large extent, gas formations overlap oil formations by area, which creates favorable conditions for the implementation of methods of dual completion (DC) of oil and gas facilities with one well. At the same time, it is also advisable to partially use the technology of the downhole gas lift, the most efficient method of operation that does not require additional capital investments.
When choosing the gushing mode (the diameter of the fitting), it is necessary that the well has an optimal flow rate with a small gas factor, gives less water and sand, gushes calmly, without large pulsations. Only when these conditions are met, it is possible to ensure the most rational consumption of reservoir energy and long-term, uninterrupted gushing of the well.
When choosing the mode of operation of a fountain well, reservoir conditions are also taken into account - the proximity of contour water, the possibility of plug formation in wells, the mode of the field itself, etc.
The main reasons for the disruption of the normal operation of fountain wells are the waxing of fountain pipes, the formation of a sand plug, corroding of the fitting, clogging of the fitting or ejection of paraffin complications, etc. [6].
Measures to restore the operation mode of wells are carried out depending on the reason that caused its violation.
When a sand plug is formed in the fountain pipes, which caused the buffer pressure to drop to zero and the supply is stopped, a liquid (oil) pump is flushed into the annular space to restore circulation and eliminate the plug.
A significant decrease in pressure in the annular space indicates the formation of a plug at the bottom and the appearance of water, the latter is detected by taking a sample from the jet. When water appears, it is necessary to increase the pressure on the face by reducing the diameter of the fitting. To eliminate the downhole plug, the well is allowed to work without a fitting or oil is pumped into the annular space.
The pressure drop on the buffer while increasing the flow rate of the well indicates that the nozzle is corroded by sand, in this case it is necessary to transfer the fountain jet to another outlet and immediately change the nozzle.
If the specified method fails to eliminate sand jams in the lifting pipes or at the bottom, then the well is stopped for repair work, after which it is put into normal operation.
Dewaxing of the elevator is the main way to ensure the normal operation of fountain wells. The largest amount of paraffin is deposited in the upper part of the lifting pipes, at a length of 400 - 1000 m from the wellhead and in the field oil collection system, in which paraffin deposition increases during the cold season. Several methods are used against waxing of lifting pipes. First of all, these are regime measures: reduction of pulsation and frequency of gushing, regulation of the gas factor in order to reduce it as much as possible.
If these measures do not give results, then it is necessary to clean the lifting pipes from paraffin.
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There are 3 types of cleaning from paraffin: mechanical, thermal, chemical [13].
Mechanical cleaning of pipes from paraffin is carried out during the operation of wells without stopping them with scrapers of various designs.
When exposed to heat, the lifting pipes are heated with steam, hot oil pumped into the annulus of the well without stopping it. The melted paraffin is carried out by a jet of oil to the surface, while the paraffin melts in the switch line. The thermal method does not prevent the deposition of paraffin in pipes, it is used sporadically, under favorable conditions and when for some reason it is not possible to use other more effective methods.
As a solvent of paraffin, it is envisaged to use condensate (gasoline), which is extracted at the fields.
The most characteristic complications in gas lift mining are the appearance of sand and cork formation, the deposition of paraffin in lifting pipes and discharge lines.
Measures against sand entering the well are of a regime nature and are reduced to limiting depression, i.e. limiting fluid intake. The amount of liquid extraction from gas lift wells is regulated by changing the amount of injected working agent, the depth of immersion of lifting pipes or their diameter. To prevent the settling of sand during the periods of its greatest inflow from the reservoir, without interrupting operation, oil is pumped into the annulus in small portions by a mobile pump.
Sometimes the pressure of the gas injected into the well increases sharply when the liquid supply is stopped at the same time. This may occur due to the formation of a so-called cartridge sand plug in the lifting pipes, which blocks the section of the lifting pipes, preventing the mixture of oil and injected gas from reaching the surface. To destroy such a plug, the gas is pumped not into the annular space, but into the lifting pipes. If in this way it is not possible to push the plug from the pipes to the bottom of the well, then it is necessary to remove the pipes [14, 15].
When wells are equipped with a single-row lift, it is finished with a shank of a smaller diameter than the main tubing string. The descent of the lifting pipes with a shank to the filter facilitates the conditions for the removal of sand by the liquid to the surface and prevents the formation of sand jams.
Measures to prevent paraffin deposits in lifting pipes during gas lift operation of wells, and methods for cleaning pipes from paraffin are similar to those used in fountain operation.
With the drop in reservoir pressures and the flooding of reservoirs at some stages of development in the gas condensate fields of the western part of Turkmenistan, it is planned to improve the gas lift. It is proposed to install a column of lifting pipes equipped with borehole chambers with gas lift valves (starting and working) located in them in the production column on the packer. This eliminates the influence of the injected gas on the flow of liquid into the well. It is planned to conduct research on optimizing the operating modes of gas lift wells according to known methods to determine the optimal flow rate.
It is also necessary to equip the gas lift gas distribution system with regulating and measuring equipment.
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All the measures mentioned above are aimed at increasing and stabilizing gas lift production and reducing the volume of injected gas.
At the gas condensate fields under development, the number of gas lift wells will increase with the expiration of the operating time, since with the cessation of well gushing, the invisibility of their transfer to a mechanized method arises [16, 17].
Under the existing modes of gas lift lifts, the depth of the input of the working agent (gas) is in the range of 1400 - 3000 m, the gas input into the lift is carried out through holes (punchers) temporarily replacing the working valves.
The determination of well operation parameters and the forecast of development indicators was carried out on the basis of reserves of gas condensate horizons and areas for which the presence of oil rims was not detected.
It should be noted that there are a number of uncertainties in the estimation of individual parameters for the field that can affect the accuracy of the final calculation results. The main ones are:
- the degree of activity of the legal area of deposits and the prediction of its impact on the dynamics of drainage regimes in the future;
- insufficient number of measurements of reservoir pressure, the impossibility of establishing a pattern of its change over time for most horizons;
- insufficient number of definitions of filtration parameters "A" and "B" to average them across individual development objects;
- a small number of experimental determinations of the condensate recovery coefficient.
To maximize the use of available data on reservoir pressure measurements and to approximate the results of the forecast of reservoir pressure dynamics to real conditions, the following methodological technique was used.
Pre, = f(Qg.) (1)
P res - the ratio of the current value of reservoir pressure to its initial value;
(Qg) - the ratio of accumulated gas extraction to its initial recoverable reserves.
Based on the analysis of field data using available practical data on reservoir pressure measurements for horizons, graphs of changes in reservoir pressure from accumulated gas extraction are constructed in dimensionless form.
When determining the initial recoverable gas reserves, the expected final gas recovery coefficient equal to 0.85 was adopted.
According to the experience of developing gas condensate deposits in Western Turkmenistan, it is known that during their operation, along with the gas regime, the pressure of marginal and plantar waters appears, and its share increases over time [5].
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In the calculations, the isotherms of differential condensate in reservoir conditions given in [6; 18] were used. These data are preprocessed with polynomials for the convenience of performing calculations on a computer.
The calculation sequence is as follows.
1. For the lower reservoir, the annual and accumulated gas production, as well as the average flow rate of gas wells (qi) for the future for the option of developing it by an independent grid of wells, are preliminarily calculated.
With known accumulated selections (Q1), the dynamics of reservoir pressure along the lower formation is determined by the formula:
Pres.init.1 Pres.init. f( Q g.1 ) (2)
2. Using the filtration coefficients "A1" and "B1", with a known gas flow rate q1 and the value of reservoir pressure P1, the bottom-hole pressure Pb1 is determined.
Pbl = yjP2P - (A1q1 + B1q21) (3)
3. To lift the liquid to the surface, the wellhead pressure is determined by the following formula:
P, = e
_ -dfter
ry 2 rji 2
P12 -L377ki 7 avlls avl Q2mix.1(e2after -1)
Pid int.i
(4)
S0 = 0.0341^-PP^:p = y + (1 -y)-^
7 T
av av
P
g.op.
P
= PgPav.Tst. : g.op. = p T
:y< P =
liq.
(Qg .op. Qliq. )
q = Qg.PatTav. ,Q = Gg + Gliq Qg.(°p. p T ■ Qma. (n )
pav.Lst. ( HgJ
(5)
Gg = QsPs;P = = 2930k
rair
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/ry 2 rj-i 2
0 = 1,3772, av■ 5 av' (e2S -1) d5
pg. pair Pnq - density of gas, air and liquid, kg/m ;
Pg.op., Qgop - respectively, the density and flow rate of gas in the wellbore under operating conditions, kg/ m3 and thousand m3 day; Gliq, Gg, - mass flow of liquid and gas, t/day;
QmiX,Qliq,Qg - volume flow rate of the gas-liquid mixture, liquid and gas, respectively, at Pat and Tst, thousand m3/day.
The true volumetric gas content should be determined experimentally as the
<p= 4Vg
of the true volume of gas Vt in the well to the volume of the hole nD2L , However, due to the great difficulties of such measurements, it can be estimated by the consumable gas content P according to the above formula (5).
Since it is always 9 <P, using P instead of 9 leads to an underestimation of the downhole pressure as much as the difference between the amount of liquid in the well and the outflow of gas is greater. The coefficient of hydraulic resistance X must be determined based on the results of well studies in various modes. Due to the absence of such studies, its value is assumed according to [19; 20], for the pipe Xt = 0.025 and for the packer Xp = 0.0815.
All values (Zav, pgop, Qgop, P, etc.) depending on the Pav are calculated by the method of successive approximations.
When predicting the gas factor, oil and gas resources of the productive deposits of the field, characterized by very complex drainage regimes, serious problems are created. In addition, during the development of the field, there is a continuous change in specific types of energy that displace oil from the bottom of producing wells, which significantly affects the dynamics of the gas factor. At the same time, the dynamics of the gas factor was determined taking into account the experience of the development of the NK (lower red color) horizons of other fields.
Based on the analysis of field data using available practical data on reservoir pressure measurements for horizons, graphs of changes in reservoir pressure from accumulated gas extraction were constructed in dimensionless form (Fig. 9 and 10).
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500 450 400 350 300 5 250 200 150 100 50 0
V
500
1000
1500
2000
2500
3000
350
Total gas production« mln.m'
Fig. 9 Graph of changes in reservoir pressure from accumulated gas extraction in the Nk8 horizon
Fig. 10 Graph of changes in reservoir pressure from accumulated gas extraction in the horizon of NK7d.
The main economic indicators characterizing the effectiveness of the proposed development options are capital investments, operating costs, total costs, as well as the cost of oil production.
We take discounted annual cash flow (income-expenses) as the criterion for choosing development options.
The calculation of economic indicators was carried out in accordance with the projected levels and dynamics of technological indicators according to options using economic standards set depending on changes in technological factors.
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The volume and technological factors affecting the level and dynamics of economic indicators are: the volume of production drilling, the number of wells put into operation from drilling, the volume of oil, gas and condensate production, the fund of producing wells.
Using technological indicators and accepted economic standards, capital investments in drilling wells and in the areas of oilfield construction, depreciation charges for new wells, operating costs by cost items are calculated.
The need for capital investments for the long-term period is due to the commissioning of new wells and their arrangement.
The calculation of operating costs for the production of oil, gas and condensate for the long-term period according to the options was made in accordance with the current calculation methodology, depreciation rates and approved rates of deductions for geological exploration.
The upcoming costs represent the sum of capital and operating costs in the corresponding accounting year of the inventory development period under consideration.
The choice of mechanized methods of oil production at the Altyguyi field is carried out taking into account the above factors. In addition to them, relief climatic conditions, inter-repair periods, the presence of paraffin and mechanical impurities in the extracted liquid, the reliability of equipment, the need for maintenance personnel and repair equipment, ease of maintenance in the process of mechanized oil production, production capabilities, the need for energy resources are also taken into account [21].
The Altyguyi deposit is a multi-layer one. By the nature of saturation, the presence of pure oil deposits, pure gas deposits and gas deposits with oil rims is noted. For most deposits, the mixed regime is characterized by the predominance of the energy of gas released from oil and the manifestation of the activity of contour waters at a later stage of development. Under conditions when liquid is extracted from oil reservoirs, gas extraction is required, which serves as a working agent.
The development project does not provide for the maintenance of reservoir pressure, and therefore the exploitation of deposits will be carried out with a continuous drop in reservoir pressure, a decrease in static fluid levels in wells and an increase in the height of its rise.
In [6; 12], on the basis of laboratory research, the substantiation of the scope, efficiency, reliability and the possibility of maximum extraction of oil reserves from multi-layer oil and gas horizons with a large depth of occurrence, composed of weakly cemented rocks, is given. In these works, the criteria for choosing rational methods of mechanized oil production are given. The article also considers the possibility of using various methods of mechanized oil production in relation to the conditions of the Altyguyi field.
Analysis of the conditions of application of the ejector pump. The
inexpediency of using ejector pumps is explained by the fact that the interval of occurrence of productive layers is very deep. The depth of descent of ejector pumps is 1000-2000 meters, at the places of reception of products, the volume of free gas
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should be above 50-70%. The wells of the Altyguyi deposit do not meet these requirements.
Analysis of the conditions of application of the installation of an electric centrifugal pump (ESP). The main criterion that determines the inexpediency and impossibility of application is the large depth of wells - from 3600 to 3700m. The maximum depth of the ESP descent does not exceed 1600m. In addition to this limiting factor, there is also the presence of a high gas content in the pumped liquid and the planned flow rates, which are significantly lower than the minimum performance of the ESP. These factors are opposed to the possibility of using ESP in limited quantities at this field.
Analysis of the conditions of application of the installation of a rod depth pump (IRDP). In the conditions of the Altyguyi deposit, the use of IRDP has a very limited area. However, IRDP is distinguished by the perfection of its design, a wide range of manufactured equipment of the normal range, as well as ease of maintenance. Installations of rod depth pumps can be used up to a depth of 2300 meters and when pumping liquid from relatively shallow depths. They are inferior in developed pressure only to hydraulic piston installations, can be effectively used in low-flow wells up to 10 tons with high water content of products. Limiting factors of their application are: high gas factors, large depths, curvature of boreholes less than 7 degrees. With an increase in the depth of the pump descent, the reliability of its operation decreases, the degree of leakage through the gaps increases, and the repair period is also shortened [22].
The modern normal range of drives of the deep pump of the rocking machine (RM) and downhole pumps of the plug-in type allow theoretically lifting liquid from depths of 3500m.
However, with such a large pump descent, due to the insufficient operational reliability of the pumping pipes and rods, problems arise related to the provision of the repair base of the fields.
In the conditions of the fields of Turkmenistan, oil production by IRDP installations is provided from a maximum depth equal to 2300m. Due to the influence of various negative factors, the actual feed from a depth of 2300 m does not exceed 5.3 m / day with a feed ratio of no more than 0.17.
Thus, the use of IRDP installations at this field cannot be considered as promising. In addition to low productivity, when using the IRDP, irrational expenditure of material and energy resources is expected due to a significant decrease in the reliability of the IRDP equipment when pumping liquid from wells with sand, the formation of paraffin and salt deposits, rod breaks and other malfunctions. According to the existing experience of IRDP operation in such conditions, the operating coefficient is significantly reduced, which does not exceed 0.7 for similar fields in Turkmenistan. Based on the above, the use of the method of oil extraction by IRDP installations is not recommended at this field.
Analysis of the conditions for the use of ISHP (submersible piston pump with hydraulic drive). Block automated installations of hydraulic piston pumps (ISHP) are designed for the operation of 2-8 cluster directional and deep wells (over 4000m)
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with low dynamic levels (3000m) and with debits up to 100 m /day. The small dimensions of these pumps allow them to be lowered into wells with an internal diameter of the production column of 117.7-155.3 mm.
The principle of operation of the installation is based on the use of hydraulic energy of a liquid pumped under high pressure through a special channel into a hydraulic downhole reciprocating piston engine, which converts this energy into reciprocating motion of a piston pump rigidly connected to the engine.
These pumps have a high efficiency (0.65), which decreases slightly with a decrease in the dynamic level in the wells. The distinctive ability of hydraulic piston pumps is the possibility of using the same unit to work with different pressures, i.e. to operate wells with different depths and to take liquid in the right quantities.
As hydraulic piston installations, IHP 25-150-25, IHP 40-25 0-20, IHP 100-20018 are recommended.
Hydraulic piston units of the discharged type HP are recommended for pumping reservoir fluid from wells- 59-89-10-118, HP-59-89-25-25 , HP-59-89-40-20 .
According to their production characteristics, ease of operation, they fully meet the operating conditions of the Altyguyi deposit. However, at this stage, we do not envisage the use of these installations. For their use, it is necessary to carry out special work from the point of view of choosing rational technological schemes in relation to the conditions of this deposit. It is also necessary to study the energy technical and economic indicators, without which the choice of a rational method cannot be carried out. We consider it expedient to use them at the final stage, when wells will be operated with a water content of more than 90% and there is a need to transfer them from mechanized methods of oil production to ISHP [23].
Analysis of the conditions for the use of installations of submersible screw electric pumps. Installations of submersible screw electric pumps are designed for pumping reservoir fluid of increased viscosity from oil wells.
The most effective operation of these installations is wells with a low coefficient of productivity, high gas content, high viscosity of oil in reservoir conditions.
Installations of submersible screw electric pumps is produced for reservoir fluid with a temperature of up to 70 °C, the maximum viscosity of which is 1-10 m/s, the content of mechanical impurities is not more than 0.8 g/l, the volume content of free gas at the pump intake is not more than 50%, hydrogen sulfide is not more than 0.01 g/ l.
When operating installations in conditions other than those indicated (increased content of mechanical impurities, gas content, temperature of the pumped liquid, curvature of the borehole more than 17 degrees), the pump resource is reduced due to wear of the working elements, which leads to premature failure of it.
Pilot-industrial introduction of German-made electric screw pumps of the NTZ-240.DT16 brand is underway in the fields of Turkmenistan. Their theoretical supply is 15-30 m3 / day, the maximum depth of descent is 1900 m, the volume content of free gas at the pump intake is not higher than 50%.
Practice has shown the possibility of their use only in vertical wells and unreliability, impossibility of application in curved wells. The actual pump supply is
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not higher than 15 m /day, the content of mechanical impurities is undesirable, due to the poor quality of plastic, the elastomer quickly fails (within 1-1.5 months).
Thus, electric screw pumps, taking into account the above, have a very limited scope of application and can be used at the Altyguyi field in vertical, low-yield wells with a dynamic level of at least 1700m, at a reservoir temperature of the pumped liquid not higher than 70 °C and the volume content of free gas at the pump intake is not more than 50%.
Analysis of the conditions of application of the gas lift method of oil production
The gas lift method of oil production has been widely used in the fields of Turkmenistan, including Altyguyi.
The extraction capabilities, as well as the reliability of the use of gas lift operation, have shown that it is more efficient than other methods of mechanized extraction.
The conditions for lifting the liquid in a gas lift well mainly depend on the parameters of the lift itself, the pressure of the working agent and the parameters of the reservoir. The greatest role is played by the height of the liquid rise. At the Altyguyi field, specific factors are: a high lifting height, low flow rates, an increase in the water content of products over time, the availability of working agent (gas) resources.
The practice of gas lift operation at this field proves the expediency of its use both in continuous and periodic lifting of liquid. For the purpose of the most efficient operation, wells with debits above 30 t/day are recommended to be operated with a continuous gas lift. Wells operating with debits below 30t/day should be operated with a periodic gas lift. In the conditions of this field, a periodic gas lift is the most realistic, ensuring the design production volumes until the end of the field development.
When studying the geological and operational characteristics of the field, it was revealed that oil and gas layers alternating in productive horizons are isolated from each other by impermeable layers having relatively large thicknesses. To a large extent, gas formations overlap oil formations by area, which creates favorable conditions for the implementation of methods simultaneously-separate operation of oil and gas facilities by one well. At the same time, it is also advisable to partially use the technology of the downhole gas lift, the most efficient method of operation that does not require additional capital investments.
The calculation of continuous gas lift lifts is reduced to determining the length, diameter of lifting pipes and specific gas consumption.
The choice of the diameter of the lift pipes of the gas lift well is carried out in accordance with the volume of the filtered liquid in the area of the optimal operating mode of the lift. Practice shows that, depending on the flow rate of wells, the optimal sizes of lifts correspond to the data given in Table 14.
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Table 14
Optimal sizes of lifts
Well flow rate, t/day 20-40 40-60 60-200 200-300
Lift diameter, mm 40,3 50,3 62 76
In field conditions, from the point of view of technological and mechanical characteristics, pipes of the "M" brand with a bore diameter of 62 mm have an unlimited scope of application. It is recommended to use a universal lift scheme that provides both periodic and continuous lifting of liquid (Fig. 11.).
The above scheme is used in wells with a gas inlet depth of up to 3000 m. In wells with a depth of up to 4000 m or more, the lift layout shown in Figure 12 is used.
For maximum fluid extraction, it is necessary to create minimum pressures at the bottom. Therefore, the depth of the descent of the lifting pipes should be maximum, i.e.
L = H - (20 : 30)m
where H is the distance to the upper filter holes, m.
For an annular system (the working agent - gas is injected into the annular space), the required specific gas consumption during continuous lifting is determined from the expression:
R = "-388 ^ - (P -PP2)],m3/t
d0,5(P1 - P2)Lg-^ P
where: Pi is the working pressure, Pa (the working pressure is 8.5; 10.0; and 12 MPa);
P2 is the wellhead pressure (the minimum allowable under operating conditions), we take it to be equal to P2 = 1.2x106; 1.5x106 Mpa;
p - the density of oil is assumed to be equal to 861 kg/m3; g - acceleration of gravity (9.81 m/sec2 ); d - diameter of lifting pipes, m; L is the lifting height of the liquid, m.
The specific flow rate of the injected gas , taking into account the solubility of the gas is determined from the expression:
R ■ ■ = r -
inj. T"eq
Go -
Pi + P2
n -3
(l-^V/t 100
2
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•2
where: G0 is the gas factor (for oil), m /t; a is the solubility coefficient of gas in oil, a = 0.4031 m3/t. atm. nw is the water content of products, %.
Fig. 11 Diagram of a universal gas lift 1 - operational column; 2 - elevator pipes; 3 - starting valves; 4 - working valve; 5 - packer; 6 - check valve
Fig. 12 Diagram of a stepped gas lift 1- operational column; 2 - intermediate column; 3 - upper stage of the elevator; 4, 8 -check valves; 5 - starting valves; 6 - working valve; 7 - packer
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Fig. 13 Diagram of a lift for periodic lifting of a liquid with a replacement chamber
The optimal specific flow rate of the injected gas calculated at an input depth of + 2700, 3000m and 3500m (Pwork= 8.5; 15.0 MPa) is, respectively, 200, 300 and 500 m3/ t and at a gas input depth of 3000 - 3500m (Pwork = 10; 15 MPa) is, respectively, 150 ^ 400 m3/t.
Calculation of the installation of a periodic gas lift with a replacement chamber
For periodic gas lift, in relation to the operating conditions of the Altyguyi deposit, it is recommended to equip wells with a single-row replacement chamber with a packer and a check valve installed in the lower part of the tubing (Fig. 13). In this case, the annular space between the tubing and the casing acts as a replacement chamber [24].
Reducing the pressure of the injected gas for purging the liquid is provided by installing starting valves on the tubing string, and the lower (working) valve acts as a shut-off device that reduces the specific gas consumption [25].
The working pressure of the injected gas is determined from the expression:
P
hY,
work
10
oil + p
pip w.h
kgf/sni
The height of the column of liquid that can be forced into the lifting pipes with full use of the working pressure will be:
0,0064Lp
fP _P _P MO vwork" „, w. h)10 , (PWork ppip pw.b>10 d05
h=-—-=---,m
Toil
Toil
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where: L is the length of the lift, m;
d is the inner diameter of the lifting pipes, d = 62 mm (2.5") Pwork, Pw.h. - working and wellhead pressure, at; Yoii - the specific gravity of oil. Camera Length:
£ c =
d2
c d2
1c
where dc is the diameter of the camera, we take it equal to 4".
The volume of liquid raised in one cycle at the optimal flow rate of the injected
gas:
' 0,53/l2"'
lcyc.
h" d0,5y v
f Y,t
where d = 0.003 m is the area of the inner cross-section of 2.5" pipes.
The gas consumption during the injection period corresponding to the minimum specific consumption will be:
V0 = Ud2VL",m3/h
For a periodic gas lift with a gas cut-off at the chamber, the amount of gas required for one cycle, reduced to normal conditions, is determined from the expression:
V = /(L + h-ijpf^m3
Duration of the gas injection period:
60Vc 3 -.m3
P„
T =-c ,m-
Duration of the full cycle:
t =
qcyc.1440V
Q '
h
86
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where: Q is the flow rate of the liquid, t/day Duration of the liquid accumulation period:
T2 = T - Tj, min.
Number of cycles per day:
1440
n =-
T
Specific gas consumption per 1 ton of liquid:
v 3
R0 = —^,m3/t
—cyc.
The calculated values of the parameters of the periodic gas lift for wells with a lifting height from depths of 2500, 3000, 3500 m are given in Table 15.
The design of gas lift lifts, including the arrangement of starting and working valves, should be carried out in accordance with standard methods [26, 18], taking into account the properties of reservoir fluids and projected well flow rates.
Bellows valves of the G-38 and G-38R, G-25 and G-25R types, installed in the pockets of downhole chambers KT 73-25 and KT 73-38, K60-25 and K60-38, are recommended as gas lift valves. The minimum required number of valves per well is 5-6 [27; 28].
Table 15
Calculated parameters of the periodic gas lift
L, d, Pp^ PWOrk h, 1c, qcy^ V0, Vc Т1 Т ncyc, Q, Ro, V, m/
m mm MPa MPa MPa m m t m3 /h m3 min min cycle t/day m3/t day
2500 62 1,01 8,4 1,5 695 271,7 1,62 1266 884 41,89 116,6 12,35 20 546 10920
3000 62 1,21 10,0 1,5 898 350,7 2,12 1430 1064 44,65 152,6 9,4 20 501 10022
3000 62 1,42 12 1,5 1115 435,7 2,66 1584 1504 57,0 191,5 7,52 20 565 11314
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