CN115749703B - CO injection2Method for improving extraction degree of heterogeneous bottom water and gas reservoir through huff and puff - Google Patents
CO injection2Method for improving extraction degree of heterogeneous bottom water and gas reservoir through huff and puff Download PDFInfo
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- 238000000605 extraction Methods 0.000 title claims abstract description 20
- 239000007789 gas Substances 0.000 claims abstract description 110
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- 239000003345 natural gas Substances 0.000 claims abstract description 42
- 238000011084 recovery Methods 0.000 claims abstract description 35
- 238000002347 injection Methods 0.000 claims abstract description 30
- 239000007924 injection Substances 0.000 claims abstract description 30
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 27
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- 239000008398 formation water Substances 0.000 claims description 22
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- 239000004215 Carbon black (E152) Substances 0.000 claims description 15
- 238000006073 displacement reaction Methods 0.000 claims description 15
- 229930195733 hydrocarbon Natural products 0.000 claims description 15
- 150000002430 hydrocarbons Chemical class 0.000 claims description 15
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- 230000009545 invasion Effects 0.000 description 19
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- 229910052799 carbon Inorganic materials 0.000 description 2
- 238000004090 dissolution Methods 0.000 description 2
- 238000009826 distribution Methods 0.000 description 2
- 238000005065 mining Methods 0.000 description 2
- 238000005380 natural gas recovery Methods 0.000 description 2
- 102000010637 Aquaporins Human genes 0.000 description 1
- 108010063290 Aquaporins Proteins 0.000 description 1
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Abstract
The invention relates to a method for improving the extraction degree of a heterogeneous bottom water and gas reservoir by injecting CO 2 throughout, which comprises the following steps: (1) Respectively placing a hypertonic core and a hypotonic core into holders, connecting the two holders in parallel to form a core parallel system, connecting the middle section of the system with a surrounding pressure pump, respectively connecting the inlet end with a stratum water middle container and a natural gas middle container, respectively connecting the outlet end with a CO 2 middle container, respectively connecting the outlet ends of the hypertonic core and the hypotonic core with a pressure return pump and a separator through a back pressure valve, and connecting the separator with a gas meter and a gas chromatograph; (2) establishing original formation conditions; (3) calculating a geological reserve; (4) constant-pressure bottom water flooding is carried out; (5) CO2 injection throughput; (6) calculating the cumulative recovery ratio; (7) The amount of CO 2 extracted, the amount of free gas and the amount of dissolved gas were calculated. The invention has reliable principle and simple and convenient operation, provides technical support for the development of the post-injection CO 2 of the bottom water and gas reservoir by evaluating the feasibility of handling the post-injection CO 2 of the water and gas reservoir, and simultaneously solves the problem of burying CO 2 gas.
Description
Technical Field
The invention relates to the technical field of oil and gas field development, in particular to an experimental method for improving the extraction degree of a heterogeneous bottom water and gas reservoir by injecting CO 2 throughout.
Background
Most of the gas reservoirs developed at present belong to water flooding gas reservoirs with different degrees, wherein the gas reservoirs with active side and bottom water account for 40% -50%, and particularly in Sichuan basin, the water and gas reservoirs account for more than 80% of the total reserves. Once pore water flows or side bottom water invades in the development process of the gas reservoir, gas-water two-phase seepage is formed in the reservoir, and seepage resistance is greatly increased; in addition, for a heterogeneous gas reservoir, the hypertonic area is a main water intrusion channel, water is difficult to enter the hypotonic high-pressure pores, but bypasses the hypotonic pore bands and rapidly advances along the hypertonic area to form a hypotonic high-pressure dead gas area in the gas reservoir, so that the extraction degree of the gas reservoir is greatly reduced.
In recent years, a large number of students have conducted physical simulation research on water invasion of bottom reservoirs. The invention patent relates to an experimental device and a method for simulating gas reservoir water invasion (CN 105604545A), which are used for simulating the gas reservoir water invasion process by adopting an artificial fracture-cavity core, so that the distribution characteristics of residual gas after water invasion are known, but the highest bearing pressure of a model is 0.8MPa, and the water invasion process under the condition of a real reservoir cannot be simulated. The invention relates to a physical simulation experiment system and a physical simulation experiment method for water invasion of multi-well production of a side and bottom water reservoir (CN 107905769A), which can simulate the water invasion process of a heterogeneous side and bottom water reservoir, but cannot simulate the state of the water-flooded gas reservoir. The invention relates to a simulated development device and a simulated development method of a gas reservoir (CN 112065376A), which are used for scanning a simulated gas reservoir corresponding to a simulated rock core through a ray scanning system and determining the migration condition of a side part or a bottom water body of the simulated gas reservoir, so that the water invasion characteristics of the side part or the bottom water body in the gas reservoir development process are known. The influence of different permeability level differences and different well distribution modes on the development effect of the heterogeneous gas reservoir is evaluated by simulating the water invasion and production dynamic change process of the heterogeneous gas reservoir (the water invasion law of the heterogeneous gas reservoir is simulated by the flying, liu Huaxun, shouqihua, and the like. The physical simulation experiment research of the water invasion law of the heterogeneous gas reservoir [ J ]. Laboratory research and exploration, 2019,38 (3): 5), but no guidance is provided for how to improve the extraction degree after the flooding of the gas reservoir.
Currently, research on heterogeneous bottom reservoirs is mainly focused on water invasion laws, production dynamic changes, and how to improve the production degree by reasonably and effectively developing the bottom reservoirs. However, in the later stage of water invasion of the bottom water gas reservoir, few researches on how to improve the recovery degree of the gas reservoir by gas injection are carried out, and particularly, researches on improving the recovery rate of the bottom water gas reservoir by CO 2 injection are carried out at home and abroad. The combination of CO 2 injection to improve the oil gas recovery ratio and geological sequestration is a development trend of future oil gas reservoir development, and CO 2 injection is used for enhancing oil gas exploitation on one hand and promoting carbon capture, carbon utilization and carbon sequestration on the other hand. However, since CO 2 is readily soluble in water, the injection of CO 2 into the bottom water reservoir does not result in efficient displacement of formation fluids, resulting in energy loss and low recovery efficiency. Therefore, the method is particularly important for the throughput development of the bottom water gas reservoir CO 2 and the evaluation of the extraction amount, the free amount and the dissolution amount of the CO 2 in the development process.
Disclosure of Invention
The invention aims to provide a method for improving the extraction degree of a heterogeneous bottom water and gas reservoir by injecting CO 2 throughout, which is reliable in principle and simple and convenient to operate, and provides technical support for the development of the bottom water and gas reservoir later-stage CO 2 injection by evaluating the feasibility of injecting CO 2 throughout of the bottom water and gas reservoir later-stage water channeling.
In order to achieve the technical purpose, the invention adopts the following technical scheme.
A method for improving the extraction degree of a heterogeneous bottom hydrocarbon reservoir by injecting CO 2 in throughput, which sequentially comprises the following steps:
(1) Selecting plunger cores with different permeabilities, wherein the length L High height of the hypertonic core, the total pore volume V High height , the length L Low and low of the hypotonic core and the total pore volume V Low and low ; respectively placing the hypertonic core and the hypotonic core into holders, and connecting the two holders in parallel to form a core parallel system for simulating a heterogeneous stratum; the middle section of the core parallel system is connected with a surrounding pressure pump, the inlet end of the core parallel system is respectively connected with a stratum water intermediate container and a natural gas intermediate container, the outlet end of the core parallel system is connected with a CO 2 intermediate container, and the core parallel system and each intermediate container are arranged in a constant-temperature oven; the outlet ends of the high-permeability core and the low-permeability core are respectively connected with a return pressure pump and a separator through a return pressure valve, and the separator is connected with a gas meter and a gas chromatograph;
(2) Establishing original formation conditions
① Setting the temperature of the constant temperature oven as the formation temperature T, and setting the back pressure as the formation pressure P; setting the confining pressure to be about 2MPa larger than P 0(P0, setting the pressure of a constant pressure pump connected with the formation water intermediate container to be P 0, and enabling water in the formation water intermediate container to enter a core parallel system along a pipeline until water is produced at an outlet end;
② Allowing stratum water to pass through the hypertonic core only until the separator at the outlet end of the hypertonic core uniformly discharges water; allowing stratum water to pass through the hypotonic core only until the separator at the outlet end of the hypotonic core uniformly discharges water; setting the pressure of the constant pressure pump as P, and stabilizing the pressure of the stratum water intermediate container at P until the outlet ends of the hypertonic core and the hypotonic core are no longer produced by water;
③ Injecting natural gas into the hypertonic core by using a displacement pump connected with the natural gas intermediate container until the separator at the outlet end of the hypertonic core is no longer discharged, and measuring the water volume V w High height ; injecting natural gas into the hypotonic rock core by using the displacement pump until the separator at the outlet end of the hypotonic rock core does not discharge water any more, and measuring the water volume V w Low and low ;
(3) Calculating geological reserves
At formation pressure, the formation water volume coefficient is B w, and the natural gas volume coefficient is B g, then:
effective hydrocarbon pore volume V P High height ＝VW High height BW of hypertonic core and original geological reserve
Effective hydrocarbon pore volume V P Low and low ＝Vw Low and low Bw of hypotonic core and original geological reserve
The total effective hydrocarbon pore volume V P＝VP High height +VP Low and low of the core parallel system, total original geological reserve g=g High height +G Low and low ;
(4) Constant pressure bottom water drive (separate mining)
Stabilizing the confining pressure at P 0, using a constant pressure pump connected with the stratum water intermediate container to ensure that the pressure of the stratum water intermediate container is constant at the stratum pressure P, and reading the volume V 1 of the constant pressure pump; controlling the back pressure of the outlet ends of the hypertonic core and the hypotonic core to slowly decrease from P by using a back pressure pump synchronously until the outlet ends of the hypertonic core and the hypotonic core produce water completely, and respectively measuring the accumulated gas production G High yield 、G Low yield of and the accumulated water production W p High height 、Wp Low and low of the hypertonic core and the hypotonic core;
(5) CO2 throughput (He Cai)
Connecting a hypertonic core outlet end and a hypotonic core outlet end together, resetting the back pressure of the outlet end to P, and slowly injecting CO 2 into a core parallel system through a displacement pump connected with a CO 2 intermediate container, wherein the CO 2 amount injected each time is 0.1V P; controlling the back pressure of the outlet end to slowly reduce by 2MPa from P, separating produced gas and water by a separator, and measuring the water yield W p1 and the gas yield G Closing device 1 of the stage; analyzing the gas components produced in the stage by adopting a gas chromatograph to obtain natural gas content N 1; this step is repeated N times, the water production W pi (i=1, 2,3 … N) of each stage is metered, the gas production volume G Closing device i (i=1, 2,3 … N) is metered until N n < 0.1%, and the displacement pump volume V 2 is read out;
(6) Calculating cumulative recovery
Constant pressure bottom water flooding stage:
high permeability core recovery ratio
Low permeability core recovery ratio
Constant pressure bottom water flooding stage recovery ratio
CO 2 injection and throughput stage for extracting natural gas volume
Recovery ratio of CO 2 injection in throughput stage
The cumulative recovery ratio R (%) is:
(7) Calculating the extraction amount, the free gas amount and the dissolved gas amount of CO 2
At the formation pressure P and the formation temperature T, the volume coefficient of CO 2 is B gc; from the mass balance equation, the injection amount is the sum of the occlusion amount and the extraction amount, namely under the ground condition:
Total injected CO 2 w=co 2 sequestration W 1 + extracted CO 2 W 2
CO 2 intermediate Container injection of total amount of CO 2 (under ground conditions)
CO 2 production
CO 2 sequestration quantity
At the beginning of the experiment, the effective hydrocarbon pore volume V p of the parallel core system was fully occupied by natural gas, and at the end of the experiment, V p was occupied by formation water, free CO 2 and natural gas under formation conditions:
v p = water intrusion W e + free CO 2 G c + natural gas amount G not extracted res
The gas reservoir water invasion W e (subsurface volume) is:
We＝Winj-WPBw
Wherein W inj is the water injection rate (underground volume) of the gas reservoir; w p -gas reservoir Water yield (above ground volume);
Winj＝V1-V2
The volume of natural gas not produced below the formation is:
I.e., the volume G c of free CO 2 in the subsurface of the formation is:
under the ground condition, the free air volume W 3 of the core is as follows:
The CO 2 sealing quantity is divided into a core free gas quantity W 3 and a formation water dissolved gas quantity W 4, namely:
W1＝W3+W4
namely, under the ground condition, the formation water dissolves CO 2 by an amount W 4:
W4＝W1-W3
Compared with the prior art, the method is simple, convenient and applicable, can simulate the water invasion process of the heterogeneous bottom water and gas reservoir under the real reservoir condition (high-temperature and high-pressure environment), can simulate the development of CO 2 injection in the later stage of gas reservoir water invasion, and evaluates the feasibility of CO 2 injection to improve the extraction degree of the bottom water and gas reservoir. The method has the advantages that the throughput of CO 2 is injected in the later stage of water invasion of the bottom water heterogeneous gas reservoir, the ratio of the extraction amount, the free amount and the dissolution amount of CO 2 is about 3:1:6, and meanwhile, the extraction degree of natural gas is improved by 18.07%, so that the method can improve the recovery ratio of the gas reservoir while solving the problem of burying CO 2 gas.
Drawings
FIG. 1 is a diagram of an apparatus for improving the recovery of a heterogeneous bottom reservoir by injecting CO 2 through-put.
FIG. 2 is a graph of natural gas recovery as a function of pressure for a constant pressure bottom water drive stage.
Fig. 3 is a graph of the variation of CO 2 injection throughput to enhance natural gas production.
FIG. 4 is a bar graph of CO 2 produced gas versus occluded gas.
In the figure: 1-a pressure surrounding pump; 2-constant pressure pump; 3. 4-displacement pumps; 5. 6-a return pressure pump; 7-a formation water intermediate container; 8-a natural gas intermediate vessel; 9-CO 2 intermediate vessel; 10-hypotonic core holder; 11-hypertonic core holder; 12-confining pressure gauge; 13. 14-an outlet pressure gauge; 15. 16-back pressure gauge; 17. 18-back pressure valve; 19. a 20-separator; 21. 22-cold water bath; 23. 24-gas meter; 25. 26-gas chromatograph; 27. 28, 29, 30, 31, 32, 33, 34, 35, 36-valves; 37-constant temperature oven.
Detailed Description
The present invention is further described below with reference to the drawings and examples to facilitate the understanding of the present invention by those skilled in the art. It should be understood that the invention is not limited to the precise embodiments, and that various changes may be effected therein by one of ordinary skill in the art without departing from the spirit or scope of the invention as defined and determined by the appended claims.
The method for improving the extraction degree of the heterogeneous bottom water and gas reservoir by injecting CO 2 in throughout is completed through an experimental device, the structure of the device is shown in figure 1, and a core parallel system is formed by connecting a low-permeability core holder 10 and a high-permeability core holder 11 in parallel so as to simulate a heterogeneous stratum; the middle section of the core parallel system is connected with a confining pressure pump 1, the inlet end of the core parallel system is respectively connected with a stratum water intermediate container 7 (a bottom water intermediate container is connected with a constant pressure pump 2) and a natural gas intermediate container 8 (a natural gas intermediate container is connected with a displacement pump 3), the outlet end of the core parallel system is connected with a CO 2 intermediate container 9 (a CO 2 intermediate container is connected with a displacement pump 4), and the core parallel system and each intermediate container are arranged in a constant temperature oven 37; the outlet ends of the low-permeability core and the high-permeability core are respectively connected with the back pressure pumps 5 and 6 and the separators 19 and 20 through the back pressure valves 17 and 18, and the separators are connected with the gasmeters 23 and 24 and the gas chromatographs 25 and 26.
A method for improving the extraction degree of a heterogeneous bottom hydrocarbon reservoir by injecting CO 2 in throughput, which sequentially comprises the following steps:
1. preparation of experiments
(1) Plunger cores with different permeabilities are selected, the length of the hypertonic core is L High height = 82 (cm), and the pore volume is V High height ＝44.14(cm3); hypotonic core length L Low and low = 83 (cm), pore volume V Low and low ＝34.75(cm3.
(2) And (3) transferring the stratum water, the natural gas and the CO 2 into the intermediate containers 7, 8 and 9 respectively, putting the low-permeability core and the high-permeability core into the core holders 10 and 11 respectively, putting the low-permeability core and the high-permeability core into the constant-temperature oven 37 together, setting the temperature of the constant-temperature oven 37 to be the stratum temperature T=92 (DEG C), and keeping all valves in a closed state.
(2) Back pressure setting was performed on the back pressure valves 17, 18 using the back pressure pumps 5 and 6, respectively, and the back pressure was set to the formation pressure p=31 (MPa).
2. Establishing original formation conditions
(3) Hydraulic oil was injected into the core parallel system using the confining pressure pump 1, raising the confining pressure to P 0 =33 (MPa).
(4) Valves 27, 29, 30, 31, 33, 35, 36 are opened, the constant pressure pump 2 is entered, the constant pressure pump pressure is set to P 0 =33 (MPa), and water in the formation water intermediate container is led into the long core parallel system along the pipeline until water is produced in separators 19 and 20.
(5) Closing the valve 29 to allow the formation water to pass through the hypertonic core 11 until the water is uniformly discharged from the separator 20; closing valve 30 and opening valve 29 to allow formation water to pass through the hypotonic core 10 until water is evenly discharged from the separator 19; valve 30 is opened and the pressure of constant pressure pump 2 is set to p=31 (MPa) to stabilize the pressure of the formation water intermediate vessel at p=31 (MPa) until no more water is produced in separators 19 and 20.
(6) Closing valves 27, 30, opening valve 28, injecting natural gas in the natural gas intermediate vessel 8 into the hypotonic core 10 using the displacement pump 3 until no more water is discharged in the separator 19, metering the water volume V w Low and low ＝24.3(cm3); valve 29 is closed, valve 30 is opened, and the displacement pump 3 is used to inject natural gas from the natural gas intermediate vessel 8 into the hypertonic core 11 until no more water is exiting the separator 20, and the water volume V w High height ＝32.1(cm3 is measured. Closing all valves, and finishing the establishment of the original state of the core.
3. Geological reserve calculation
(7) At formation pressure, the volume coefficient of formation water is B w =1.03, the volume coefficient of natural gas is B g = 0.00253, and the effective hydrocarbon pore volume V p High height (cm3 of the hypertonic long core 11 is as follows
VP High height ＝VW High height BW＝32.1×1.03＝33.06
The original geological reserve of the hypertonic core 11 is G High height (cm3
Effective hydrocarbon pore volume V p Low and low (cm3 of hypotonic core 10
VP Low and low ＝Vw Low and low Bw＝24.3×1.03＝25.03
The original geological reserve of the hypotonic core 10 is G Low and low (cm3
Total effective hydrocarbon pore volume V P(cm3 for parallel long cores
VP＝VP High height +VP Low and low ＝33.06+25.03＝58.09
The total geological reserve G (cm 3) is:
G＝G High height +G Low and low ＝13067.2+9893.3＝22960.5。
4. constant pressure bottom water drive (separate mining)
(8) The confining pressure was stabilized at P 0 =33 (MPa) using the confining pressure pump 1, the formation water intermediate tank 7 pressure was stabilized at p=31 (MPa) using the constant pressure pump 2, and the constant pressure pump volume V 1＝10(cm3 was read.
(9) The valves 27, 29, 30, 31, 33, 35, 36 are opened, the back pressure pumps 5, 6 are synchronously used to control the pressures of the back pressure valves 17, 18 to slowly decrease from P=31 (MPa) to P 1 =29 (MPa) at the speed of X=1 (MPa/h), the separators 19, 20 are used for separating gas and water, the gas volumes G Low yield of ＝3363.7(cm3)、G High yield ＝7317.8(cm3 are respectively measured by the gas meters 23, 24, and the accumulated water production amounts W p Low and low ＝12.6(cm3) and W p High height ＝8.4(cm3 are read. Until the outlet end has produced water, the valves 31, 33, 35, 36 are closed. The constant pressure bottom water flooding experimental data are shown in table 1, and the change curve of the natural gas recovery ratio with the pressure is shown in fig. 2.
Table 1 constant pressure bottom water drive experimental data
5. CO 2 throughput (He Cai)
(10) The valves 32, 33, 34 are opened, the inlet and outlet ends of the hypertonic and hypotonic cores are connected together to form a long core parallel system, and the back pressure valve 18 pressure is reset to p=31 (MPa) using the back pressure pump 6. CO 2 in CO 2 intermediate vessel 9 was slowly injected into the core parallel system using displacement pump 4 at formation pressure p=31 (MPa), with an amount of CO 2 of 0.1V P＝5.8(cm3.
(11) Valve 34 is closed, valve 36 is opened, the back pressure is controlled to slowly decrease from p=31 (MPa) to 29 (MPa) at a speed of x=1 (MPa/h) by using back pressure pump 6, the produced gas and water are separated by separator 20 until the outlet end produces water completely, and valve 36 is closed. The cumulative water yield W pi＝12.4(cm3 at this stage was read out (i=1, 2,3 … N), the gas volume G Closing device i(cm3 was measured using a gas meter (i=1, 2,3 … N), and the gas composition was analyzed with the gas chromatograph 26 to give the natural gas content N i (%) (i=1, 2,3 …). Repeating steps 10-11, and repeating n=6 times until N i is less than 0.1%. Closing all valves and reading the constant pressure pump volume V 2＝75.3(cm3). The CO 2 injection and production combined experimental data are shown in table 2, and the change of improving the natural gas production degree by injecting the CO 2 injection and production rotation is shown in fig. 3.
Table 2 CO 2 throughput combined production experimental data
| Gas injection throughput round | Natural gas production/cm 3 | CO 2/cm recovery 3 | Enhanced recovery degree/% | Cumulative water yield/cm 3 |
| 1 | 1520 | 13 | 6.62 | 0.8 |
| 2 | 1253 | 100 | 5.46 | 2 |
| 3 | 740 | 303 | 3.22 | 3.8 |
| 4 | 430 | 434 | 1.87 | 6.1 |
| 5 | 197 | 770 | 0.86 | 8.9 |
| 6 | 10 | 995 | 0.04 | 12.4 |
6. Recovery calculation
The production stage of the experiment of improving the water invasion later extraction degree of the bottom water and gas reservoir by injecting CO 2 is divided into a constant-pressure bottom water flooding stage and a CO 2 huff-and-puff stage, namely the cumulative recovery ratio R (%) is the sum of the recovery ratio R 1 (%) of the constant-pressure bottom water flooding stage and the huff-and-puff recovery ratio R 2 (%) of CO 2.
The recovery ratio R High height (%) of the low-high permeability long core barrel in the constant pressure bottom water flooding stage is as follows:
the recovery ratio R Low and low (%) of the low-permeability long core tube in the constant-pressure bottom water flooding stage is as follows:
The simulated gas reservoir total recovery ratio R 1 (%) in the constant pressure bottom water flooding stage is as follows:
CO 2 injection throughput stage for extracting natural gas volume G Closing device (cm3
The recovery ratio R 2 (%) of the CO 2 throughput stage drive is as follows:
Namely, the cumulative recovery ratio R (%) is:
7. Injection CO 2 inventory calculation
At the original gas reservoir pressure p=31 (MPa), temperature t=92 (°c), CO 2 volume coefficient is B gc = 0.00397; from the mass balance equation, the injection amount is the sum of the occlusion amount and the extraction amount, namely under the ground condition:
Total amount of injected CO 2 W (cm 3)＝CO2 occlusion W 1(cm3) +extracted CO 2 W 2(cm3)
The total amount W (cm 3) of CO 2 (under ground conditions) injected into the CO 2 intermediate vessel 9 is:
Produced CO 2 amount W 2(cm3) is:
namely the CO 2 sealing quantity W 1(cm3) is
8. CO 2 free gas and dissolved gas calculation
At the beginning of the experiment, the parallel core effective pore volume V p＝58.09(cm3) is fully occupied by natural gas; at the end of the experiment, V p(cm3) was occupied by formation water, free CO 2 and natural gas under formation conditions:
V p(cm3) =water intrusion (W e) +free CO 2 (G c) +natural gas amount not extracted (G res)
The gas reservoir water invasion W e (subsurface volume) is:
We＝Winj-WPBw
Wherein: w inj -gas reservoir water injection rate (underground volume), cm 3;Wp -gas reservoir water yield (above-ground volume), cm 3;
Winj＝V1-V2＝75.3-10＝65.3
We＝65.3-33.4×1.03＝33.9
The volume of natural gas not produced below the formation is:
i.e., the volume of free CO 2 in the subsurface of the formation G c(cm3) is:
Gc＝VP-We-Gres＝58.09-33.9-20.54＝3.65
under ground conditions, the core free air volume W 3(cm3) is:
The injected CO 2 sealing amount is divided into a core free gas amount W 3(cm3) and a formation water dissolved gas amount W 4(cm3), namely:
W1＝W3+W4
namely, under ground conditions, formation water dissolves CO 2 amount W 4(cm3) as:
W4＝W1-W3＝6164.3-919.4＝5244.9。
the CO 2 produced gas quantity, free gas quantity and dissolved gas quantity pairs are shown in FIG. 4.
Claims (3)
1. A method for improving the extraction degree of a heterogeneous bottom hydrocarbon reservoir by injecting CO 2 in throughput, which sequentially comprises the following steps:
(1) Selecting plunger cores with different permeabilities, wherein the length L High height of the hypertonic core, the total pore volume V High height , the length L Low and low of the hypotonic core and the total pore volume V Low and low ; respectively placing the hypertonic core and the hypotonic core into holders, and connecting the two holders in parallel to form a core parallel system for simulating a heterogeneous stratum; the middle section of the core parallel system is connected with a surrounding pressure pump, the inlet end of the core parallel system is respectively connected with a stratum water intermediate container and a natural gas intermediate container, the outlet end of the core parallel system is connected with a CO 2 intermediate container, and the core parallel system and each intermediate container are arranged in a constant-temperature oven; the outlet ends of the high-permeability core and the low-permeability core are respectively connected with a return pressure pump and a separator through a return pressure valve, and the separator is connected with a gas meter and a gas chromatograph;
(2) Establishing original formation conditions
① Setting the temperature of the constant temperature oven as the formation temperature T, and setting the back pressure as the formation pressure P; setting the confining pressure to be P 0,P0 to be 2MPa larger than P, setting the pressure of a constant pressure pump connected with the formation water intermediate container to be P 0, and enabling water in the formation water intermediate container to enter a core parallel system along a pipeline until water is produced at an outlet end;
② Allowing stratum water to pass through the hypertonic core only until the separator at the outlet end of the hypertonic core uniformly discharges water; allowing stratum water to pass through the hypotonic core only until the separator at the outlet end of the hypotonic core uniformly discharges water; setting the pressure of the constant pressure pump as P, and stabilizing the pressure of the stratum water intermediate container at P until the outlet ends of the hypertonic core and the hypotonic core are no longer produced by water;
③ Injecting natural gas into the hypertonic core by using a displacement pump connected with the natural gas intermediate container until the separator at the outlet end of the hypertonic core is no longer discharged, and measuring the water volume V w High height ; injecting natural gas into the hypotonic rock core by using the displacement pump until the separator at the outlet end of the hypotonic rock core does not discharge water any more, and measuring the water volume V w Low and low ;
(3) Calculating geological reserves
At formation pressure, the formation water volume coefficient is B w, and the natural gas volume coefficient is B g, then:
effective hydrocarbon pore volume V P High height ＝VW High height BW of hypertonic core and original geological reserve
Effective hydrocarbon pore volume V P Low and low ＝Vw Low and low Bw of hypotonic core and original geological reserve
The total effective hydrocarbon pore volume V P＝VP High height +VP Low and low of the core parallel system, total original geological reserve g=g High height +G Low and low ;
(4) Constant pressure bottom water driving
Stabilizing the confining pressure at P 0, using a constant pressure pump connected with the stratum water intermediate container to ensure that the pressure of the stratum water intermediate container is constant at the stratum pressure P, and reading the volume V 1 of the constant pressure pump; controlling the back pressure of the outlet ends of the hypertonic core and the hypotonic core to slowly decrease from P by using a back pressure pump synchronously until the outlet ends of the hypertonic core and the hypotonic core produce water completely, and respectively measuring the accumulated gas production G High yield 、G Low yield of and the accumulated water production W p High height 、Wp Low and low of the hypertonic core and the hypotonic core;
(5) CO 2 injection throughput
Connecting a hypertonic core outlet end and a hypotonic core outlet end together, resetting the back pressure of the outlet end to P, and slowly injecting CO 2 into a core parallel system through a displacement pump connected with a CO 2 intermediate container, wherein the CO 2 amount injected each time is 0.1V P; controlling the back pressure of the outlet end to slowly reduce by 2MPa from P, separating produced gas and water by a separator, and measuring the water yield W p1 and the gas yield G Closing device 1 of the stage; analyzing the gas components produced in the stage by adopting a gas chromatograph to obtain natural gas content N 1; this step is repeated N times, the water production W pi (i=1, 2,3 … N) of each stage is metered, the gas production volume G Closing device i (i=1, 2,3 … N) is metered until N n < 0.1%, and the displacement pump volume V 2 is read out;
(6) Calculating the cumulative recovery ratio:
the accumulated recovery ratio is the sum of the recovery ratio of the constant-pressure bottom water flooding stage and the recovery ratio of the CO 2 huff and puff stage;
(7) The amount of CO 2 extracted, the amount of free gas and the amount of dissolved gas were calculated.
2. The method for improving the recovery of a heterogeneous bottom hydrocarbon reservoir by injecting CO 2 through-put according to claim 1, wherein said step (6) calculates the cumulative recovery ratio by the following steps:
Constant pressure bottom water flooding stage recovery ratio
CO 2 injection and throughput stage for extracting natural gas volume
Recovery ratio of CO 2 injection in throughput stage
The cumulative recovery ratio R (%) is:
3. The method for improving the recovery of a heterogeneous bottom gas reservoir by injecting CO 2 through-put according to claim 1, wherein the step (7) calculates the recovery of CO 2, the free gas amount and the dissolved gas amount by the following steps:
At the formation pressure P and the formation temperature T, the volume coefficient of CO 2 is B gc; the injection amount is the sum of the sealing amount and the extraction amount, namely under the ground condition:
Total injected CO 2 w=co 2 sequestration W 1 + extracted CO 2 W 2
Total amount of CO 2 injected into CO 2 intermediate vessel
CO 2 production
CO 2 sequestration quantity
The effective hydrocarbon pore volume V p of the parallel core system is occupied by natural gas, and after CO 2 injection, V p is occupied by formation water, free CO 2 and natural gas, i.e., under formation conditions:
v p = water intrusion W e + free CO 2 G c + natural gas amount G not extracted res
We＝Winj-WPBw
W inj is the water injection quantity of the gas reservoir; w p, gas reservoir water yield;
Winj＝V1-V2
The volume of natural gas not produced below the formation is:
I.e., the volume G c of free CO 2 in the subsurface of the formation is:
under the ground condition, the free air volume W 3 of the core is as follows:
The CO 2 sealing quantity is divided into a core free gas quantity W 3 and a formation water dissolved gas quantity W 4, namely:
W1＝W3+W4
namely, under the ground condition, the formation water dissolves CO 2 by an amount W 4:
W4＝W1-W3
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