CN115749703A - CO injection 2 Method for improving extraction degree of heterogeneous bottom water gas reservoir through huff and puff - Google Patents
CO injection 2 Method for improving extraction degree of heterogeneous bottom water gas reservoir through huff and puff Download PDFInfo
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- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 2
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- 238000005380 natural gas recovery Methods 0.000 description 2
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Abstract
The invention relates to a CO injection method 2 The method for improving the extraction degree of the heterogeneous bottom water-gas reservoir by huff and puff comprises the following steps: (1) Respectively placing high-permeability rock core and low-permeability rock core into holders, connecting two holders in parallel to form rock core parallel system, connecting the middle section of the system with confining pressure pump, respectively connecting the inlet end with formation water intermediate container and natural gas intermediate container, and connecting the outlet end with CO 2 The outlet ends of the high-permeability core and the low-permeability core are respectively connected with a back pressure pump and a separator through back pressure valves, and the separator is connected with a gas meter and a gas chromatograph; (2) establishing original formation conditions; (3) calculating geological reserves; (4) performing constant-pressure bottom water flooding; (5) injecting CO2 for huff and puff; (6) calculating the accumulated recovery ratio; (7) Calculating CO 2 The produced volume, the free gas volume and the dissolved gas volume. Original matter of the inventionReliable management and simple and convenient operation, and CO injection is carried out in the later period of water channeling of the bottom water gas reservoir through evaluation 2 Feasibility of huff and puff, injecting CO into the bottom water gas reservoir at the later stage 2 Development provides technical support and simultaneously solves CO 2 The problem of gas burial.
Description
Technical Field
The invention relates to the technical field of oil and gas field development, in particular to a CO injection device 2 An experimental method for improving the extraction degree of a heterogeneous bottom water gas reservoir by huff and puff.
Background
Most of the gas reservoirs developed at present belong to water drive gas reservoirs with different degrees, wherein the gas reservoir with active side water and bottom water accounts for 40-50%, and particularly in Sichuan basins, the water and gas reservoir accounts for more than 80% of the total reservoir. Once pore water flows or edge 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; and for the heterogeneous gas reservoir, the high-permeability area is a main water invasion channel, water is difficult to enter the low-permeability high-pressure pores and bypasses the low-permeability pore zone, and the water is quickly propelled along the high-permeability area to form a low-permeability high-pressure dead gas area in the gas reservoir, so that the gas reservoir extraction degree is greatly reduced.
In recent years, a large number of scholars conduct physical simulation exploration research aiming at water invasion of bottom water gas reservoirs. The invention discloses an experimental device and method for simulating water invasion of a gas reservoir (CN 105604545A), which adopts an artificial fracture core to simulate the water invasion process of the gas reservoir, knows the distribution characteristics of residual gas after water invasion, but has the highest pressure bearing capacity of 0.8MPa, and cannot simulate the water invasion process under the real reservoir conditions. The invention discloses a physical simulation experiment system and a physical simulation experiment method for multi-well production water invasion of an edge and bottom water gas reservoir (CN 107905769A), which can simulate the water invasion process of a heterogeneous edge and bottom water gas reservoir but cannot simulate the state of the gas reservoir after water invasion. The invention discloses a gas reservoir simulation development device and a gas reservoir simulation development method (CN 112065376A), which scan a simulated gas reservoir corresponding to a simulated rock core through a ray scanning system, determine the migration condition of the edge part or the bottom water body of the simulated gas reservoir, and further know the water invasion characteristics of the edge part or the bottom water body in the gas reservoir development process. The method is characterized in that the influence of different permeability level differences and different well arrangement 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 (square flying, liu Hua, xiao Qian, and the like, physical simulation experimental research on the water invasion rule 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 gas reservoir is flooded.
At present, research aiming at heterogeneous bottom water gas reservoirs mainly focuses on water invasion rules and production dynamic changes, and how to improve the output degree by reasonably and effectively developing the bottom water gas reservoir. However, the research on how to inject gas to improve the gas reservoir extraction degree is less in the water invasion later stage of the bottom water gas reservoir, and especially, the CO injection is performed at home and abroad 2 And improving the recovery ratio of the bottom water gas reservoir. CO injection 2 The combination of improving the oil gas recovery ratio and geological storage is the development trend of future oil gas reservoir development, and CO is injected 2 On one hand, oil gas exploitation is strengthened, and on the other hand, carbon capture, carbon utilization and carbon sequestration are promoted to be realized. But due to CO 2 Easy to dissolve in water, bottom water gas reservoir CO injection 2 The huff and puff can not form effective displacement to formation fluid, which causes energy loss, and results in low degree of enhanced recovery ratio and poor economic benefit. Thus injecting CO into the bottom water gas reservoir 2 Development of throughput and evaluation of CO 2 The extraction amount, the free amount and the dissolution amount are very important in the development process.
Disclosure of Invention
The invention aims to provide a CO injection method 2 Throughput enhancementThe method for the extraction degree of the heterogeneous bottom water gas reservoir has reliable principle and simple and convenient operation, and CO injection is carried out by evaluating the water channeling later stage of the bottom water gas reservoir 2 Feasibility of huff and puff, injecting CO into the bottom water gas reservoir at the later stage 2 Development provides technical support.
In order to achieve the technical purpose, the invention adopts the following technical scheme.
CO injection 2 The method for improving the extraction degree of the heterogeneous bottom water-gas reservoir by huff and puff sequentially comprises the following steps of:
(1) Selecting plunger cores of different permeabilities, wherein the hypertonic core length L High (a) Total pore volume V Height of Length L of low permeability core Is low in Total pore volume V Is low in (ii) a Respectively placing a high-permeability core and a low-permeability 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 rock core parallel system is connected with a confining pump, the inlet end of the rock core parallel system is respectively connected with a formation water intermediate container and a natural gas intermediate container, and the outlet end of the rock core parallel system is connected with CO 2 The middle containers, the core parallel system and each middle container are all arranged in a constant-temperature oven; the outlet ends of the high-permeability core and the low-permeability core are respectively connected with a back-pressure pump and a separator through back-pressure valves, 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 a formation temperature T, and setting the back pressure as a formation pressure P; setting confining pressure to P 0 (P 0 Is about 2MPa greater than P), the pressure of a constant pressure pump connected with the formation water intermediate container is set to be P 0 Water in the formation water intermediate container enters the rock core parallel system along the pipeline until water is produced at the outlet end;
(2) enabling formation water to only pass through the high-permeability core until water is uniformly discharged from a separator at the outlet end of the high-permeability core; enabling formation water to only pass through the low-permeability core until water is uniformly discharged from a separator at the outlet end of the low-permeability core; setting the pressure of the constant pressure pump to be P, and stabilizing the pressure of a formation water intermediate container at P until water is not produced at the outlet ends of the hypertonic rock core and the hypotonic rock core;
(3) using intermediate volumes of natural gasThe displacement pump connected with the device injects natural gas into the high-permeability core until the separator at the outlet end of the high-permeability core does not discharge water any more, and measures the water volume V w is high (ii) a Injecting natural gas into the low-permeability rock core by using the displacement pump until the separator at the outlet end of the low-permeability rock core does not discharge water any more, and measuring the water volume V w is low ；
(3) Calculating geological reserves
Under the formation pressure, the volume coefficient of the formation water is B w Volume coefficient of natural gas of B g Then:
effective hydrocarbon pore volume V of high permeability core Height of P ＝V W is high B W Original geological reserve
Effective hydrocarbon pore volume V of low-permeability core P is low ＝V w is low B w Original geological reserve
Total effective hydrocarbon pore volume V of core parallel system P ＝V P is high +V P is low Total original geological reserve G = G Height of +G Is low in ；
(4) Performing constant pressure bottom water drive (separately mining)
Stabilizing confining pressure at P 0 The pressure of the formation water intermediate container is kept constant at the formation pressure P by using a constant pressure pump connected with the formation water intermediate container, and the volume V of the constant pressure pump is read 1 (ii) a Synchronously using a back pressure pump to control the back pressure at the outlet ends of the high-permeability rock core and the low-permeability rock core to slowly decrease from P until the outlet ends of the high-permeability rock core and the low-permeability rock core produce all water, and respectively metering the accumulated gas production G of the high-permeability rock core and the low-permeability rock core High yield 、G Low yield Cumulative water yield W p is high 、W p is low ；
(5) CO2 throughput injection (Hecai)
Connecting the outlet end of the high-permeability core and the outlet end of the low-permeability core together, resetting the back pressure of the outlet ends to be P, and passing CO 2 Intermediate container connected theretoThe displacement pump of (A) pumps CO 2 Slowly injecting CO into the core parallel system each time 2 The amount is 0.1V P (ii) a Controlling the back pressure at the outlet end to slowly reduce by 2MPa from P, separating the produced gas and water by a separator, and measuring the water yield W at the stage p1 Gas production volume G In 1. Sup. (ii) a Analyzing the gas components extracted at the stage by adopting a gas chromatograph to obtain the content N of the natural gas 1 (ii) a Repeating the steps n times, and measuring the water yield W of each stage pi (i =1,2,3 \8230n), gas generation volume G Hei i (i =1,2,3 \8230n) up to N n < 0.1%, the displacement pump volume V is read 2 ；
(6) Calculated cumulative recovery
Constant pressure bottom water flooding stage:
high permeability core recovery
Low permeability core recovery
Constant pressure bottom water drive stage recovery
CO injection 2 Volume of natural gas produced in huff and puff stage
CO injection 2 Recovery in huff and puff phase
The cumulative recovery ratio R (%) is:
(7) Calculating CO 2 The produced amount, free gas amount and dissolved gas amount
At formation pressure P, formation temperature T, CO 2 Volume coefficient of B gc (ii) a According to the material balance equation, the injection amount is the sum of the sequestration amount and the extraction amount, namely under the ground condition:
CO injection 2 Total W = CO 2 Sealing amount W 1 + CO production 2 Quantity W 2
CO 2 CO injection into the intermediate vessel 2 Total amount (under ground conditions)
CO production 2 Measurement of
CO 2 Sealing amount
Effective hydrocarbon pore volume V of parallel core system at the beginning of experiment p All occupied by natural gas, at the end of the experiment, V p By formation water, free CO 2 And natural gas occupation, under formation conditions:
V p water intrusion amount W e + free CO 2 Quantity G c + amount of unextracted natural gas G res
Water invasion of gas reservoir W e (subsurface volume) is:
W e ＝W inj -W P B w
wherein W inj -gas reservoir water injection (underground volume); w is a group of p -gas reservoir water production (above ground volume);
W inj ＝V 1 -V 2
the volume of unproductive natural gas below the formation is:
i.e. free CO 2 Volume G measured below the formation c Comprises the following steps:
under the ground condition, the free gas quantity W of the rock core 3 Comprises the following steps:
CO 2 the amount of the sealed storage is divided into the free gas amount W of the core 3 And the gas solubility W of stratum water 4 Namely:
W 1 ＝W 3 +W 4
i.e. formation water dissolves CO under surface conditions 2 Quantity W 4 Comprises the following steps:
W 4 ＝W 1 -W 3
compared with the prior art, the method is simple, convenient and applicable, can simulate the water invasion process of the heterogeneous bottom water gas reservoir under the real reservoir condition (high-temperature and high-pressure environment), and can simulate the CO injection in the later stage of water invasion of the gas reservoir 2 Development and evaluation of CO injection 2 The feasibility of the extraction degree of the bottom water gas reservoir is improved. CO injection at water invasion later stage of bottom water heterogeneous gas reservoir 2 Huff and puff, CO 2 The ratio of the produced amount to the free amount to the dissolved amount is about 3 2 The gas reservoir recovery ratio can be improved while the gas is buried.
Drawings
FIG. 1 shows a schematic view of aTo inject CO 2 And the throughput is improved.
Fig. 2 is a plot of natural gas recovery versus pressure for a constant pressure bottom waterflood stage.
FIG. 3 shows CO injection 2 The natural gas production degree change chart is improved by the throughput.
FIG. 4 shows CO 2 And comparing the gas production amount with the gas storage amount to obtain a histogram.
In the figure: 1-enclosing and pressing pump; 2-a constant pressure pump; 3. 4-displacement pump; 5. 6-a back pressure pump; 7-formation water intermediate container; 8-natural gas intermediate vessel; 9-CO 2 An intermediate container; 10-a low permeability core holder; 11-hypertonic core holder; 12-confining pressure gauge; 13. 14-outlet pressure gauge; 15. 16-a back pressure gauge; 17. 18-a back pressure valve; 19. 20-a separator; 21. 22-cold water bath; 23. 24-gas meter; 25. 26-gas chromatography; 27. 28, 29, 30, 31, 32, 33, 34, 35, 36-valves; 37-constant temperature oven.
Detailed Description
The invention is further illustrated below with reference to figures and examples in order to facilitate the understanding of the invention by a person skilled in the art. It is to be understood that the invention is not limited in scope to the specific embodiments disclosed, but that various changes in form and detail will be suggested to one skilled in the art and are to be included within the spirit and purview of this application and scope of the appended claims.
CO injection 2 The method for improving the extraction degree of the heterogeneous bottom water gas reservoir through huff and puff is completed through an experimental device, the structure of the device is shown in figure 1, a core parallel system is formed by connecting a low-permeability core holder 10 and a high-permeability core holder 11 in parallel, and the core parallel system is used for simulating a heterogeneous stratum; the core parallel system is connected with the confining pressure pump 1 in the middle section, the inlet end is respectively connected with the formation water intermediate container 7 (the bottom water intermediate container is connected with the constant pressure pump 2) and the natural gas intermediate container 8 (the natural gas intermediate container is connected with the displacement pump 3), and the outlet end is connected with the CO 2 Intermediate container 9 (CO) 2 The intermediate container is connected with a displacement pump 4), a rock core parallel system and each intermediate container are arranged in a constant-temperature oven 37; the outlet ends of the low-permeability rock core and the high-permeability rock core are respectively connected with a back pressure pump through back pressure valves 17 and 185. 6 and separators 19, 20 connected to gas meters 23, 24 and gas chromatographs 25, 26.
CO injection 2 The method for improving the extraction degree of the heterogeneous bottom water gas reservoir by huff and puff sequentially comprises the following steps of:
1. preparation of the experiment
(1) Selecting plunger cores with different permeability, and selecting high permeability core length L Height of =82 (cm), pore volume V Height of ＝44.14(cm 3 ) (ii) a Low permeability core length L Is low with =83 (cm), pore volume V Is low in ＝34.75(cm 3 )。
(2) Mixing formation water, natural gas and CO 2 Respectively transferring the core holders into intermediate containers 7, 8 and 9, respectively placing low-permeability cores and high-permeability cores into the core holders 10 and 11, respectively placing the cores into a constant temperature oven 37, setting the temperature of the constant temperature oven 37 to be the formation temperature T =92 (DEG C), and keeping all valves in a closed state.
(2) The back pressure valves 17, 18 are back pressure set using the back pressure pumps 5 and 6, respectively, to the formation pressure P =31 (MPa).
2. Establishing original formation conditions
(3) Hydraulic oil is injected into the rock core parallel system by using the confining pressure pump 1, and the confining pressure is increased to P 0 ＝33(MPa)。
(4) The valves 27, 29, 30, 31, 33, 35, 36 are opened, the constant pressure pump 2 is fed, and the pressure of the constant pressure pump is set to P 0 =33 (MPa), the water in the formation water intermediate reservoir is piped into long core parallel system until water is produced in separators 19 and 20.
(5) Closing the valve 29 to make the formation water only pass through the hypertonic rock core 11 until the water is uniformly discharged from the separator 20; closing the valve 30 and opening the valve 29 to make the formation water only pass through the low permeability core 10 until the water is uniformly discharged from the separator 19; the valve 30 is opened and the pressure of the constant pressure pump 2 is set to P =31 (MPa), allowing the formation water intermediate vessel pressure to stabilize at P =31 (MPa) until no more water is produced in the separators 19 and 20.
(6) The valves 27, 30 are closed, the valve 28 is opened, and the natural gas in the natural gas intermediate container 8 is injected into the natural gas intermediate container by using the displacement pump 3Measuring the volume V of water in the low-permeability core 10 until no water is discharged from the separator 19 w is low ＝24.3(cm 3 ) (ii) a The valve 29 is closed, the valve 30 is opened, the natural gas in the natural gas intermediate container 8 is injected into the high-permeability rock core 11 by using the displacement pump 3 until water does not flow out of the separator 20 any more, and the water volume V is measured w is high ＝32.1(cm 3 ). And closing all valves, and finishing the establishment of the original state of the rock core.
3. Geological reserve calculation
(7) The volume coefficient of the formation water is B under the formation pressure w =1.03, natural gas volume coefficient B g =0.00253, hypertonic long core 11 effective hydrocarbon pore volume V p is high (cm 3 )
V P is high ＝V W is high B W ＝32.1×1.03＝33.06
The original geological reserve of the hypertonic core 11 is G Height of (cm 3 )
Effective hydrocarbon pore volume V of the hypotonic core 10 p is low (cm 3 )
V Plow ＝V w is low B w ＝24.3×1.03＝25.03
The original geological reserve of the low permeability core 10 is G Is low in (cm 3 )
Total effective hydrocarbon pore volume V of parallel long cores P (cm 3 )
V P ＝V P is high +V P is low ＝33.06+25.03＝58.09
Total geological reserve G (cm) 3 ) Comprises the following steps:
G＝G high (a) +G Is low in ＝13067.2+9893.3＝22960.5。
4. Constant pressure bottom water drive (fen cai)
(8) Using confining pressure pump 1 to stabilize confining pressure at P 0 =33 (MPa), the formation water intermediate container 7 was kept at the formation pressure P =31 (MPa) using the constant pressure pump 2, and the constant pressure pump volume V was read 1 ＝10(cm 3 )。
(9) The valves 27, 29, 30, 31, 33, 35, 36 are opened, the pressure of the back- pressure valves 17, 18 is controlled by synchronously using the back-pressure pumps 5, 6 to slowly drop from P =31 (MPa) to P =1 (MPa/h) at a speed of X =1 (MPa/h) 1 =29 (MPa), the gas and water are separated by separators 19 and 20, and the gas volume G of the accumulated gas is respectively measured by gas meters 23 and 24 Low yield ＝3363.7(cm 3 )、G High yield ＝7317.8(cm 3 ) Reading out the cumulative water yield W p is low ＝12.6(cm 3 ) And W p is high ＝8.4(cm 3 ). Until all water is produced at the outlet end, valves 31, 33, 35, 36 are closed. The data of the constant-pressure bottom water flooding experiment are shown in the table 1, and the change curve of the natural gas recovery factor along with the pressure is shown in the figure 2.
TABLE 1 constant pressure bottom Water flooding Experimental data
5. CO injection 2 Huff and puff (Hecai)
(10) And opening valves 32, 33 and 34, connecting the inlet ends and the outlet ends of the high-permeability core and the low-permeability core to form a long core parallel system, and resetting the pressure of the back-pressure valve 18 to be P =31 (MPa) by using the back-pressure pump 6. Using a displacement pump 4 to pump the CO at formation pressure P =31 (MPa) 2 CO in the intermediate vessel 9 2 Slowly injecting CO into the core parallel system 2 The amount is 0.1V P ＝5.8(cm 3 )。
(11) Closing valve 34, opening valve 36, using back pressure pump 6 to control back pressure to slowly decrease from P =31 (MPa) to 29 (MPa) at X =1 (MPa/h), and produce gas and waterAfter separation in separator 20 until all water is produced at the outlet, valve 36 is closed. Reading the accumulated water yield W of the stage pi ＝12.4(cm 3 ) (i =1,2,3 \8230n), gas volume G was measured using a gas meter Hei i (cm 3 ) (i =1,2,3 \8230n), and the gas components are analyzed by a gas chromatograph 26 to obtain the natural gas content N i (%) (i =1,2,3 \8230;). Repeating steps 10-11, repeating N =6 times until N i Is less than 0.1 percent. All valves are closed, and the volume V of the constant pressure pump is read 2 ＝75.3(cm 3 ) The experiment was stopped. CO injection 2 The experimental data of huff and puff commingled production are shown in Table 2, CO injection 2 The throughput runs increase the variation in the extent of natural gas production as shown in figure 3.
TABLE 2 CO injection 2 Experimental data of combined production
| Gas injection throughput run | The extracted natural gas amount/cm 3 | CO production 2 Amount/cm 3 | Degree of enhanced oil recovery/% | Water yield per |
| 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 factor calculation
CO injection 2 The production stage of the experiment for improving the water cut later extraction degree of the bottom water gas reservoir comprises a constant-pressure bottom water drive stage and CO injection 2 The huff and puff stage, i.e. the accumulated recovery ratio R (%) is the recovery ratio R in the constant-pressure bottom water flooding stage 1 (%) and CO injection 2 Throughput recovery ratio R 2 The sum of (%).
Recovery ratio R of low-high-permeability long core barrel in constant-pressure bottom water flooding stage Height of (%) is:
recovery ratio R of low-permeability long core barrel in constant-pressure bottom water flooding stage Is low in (%) is:
simulation of total gas reservoir recovery ratio R in constant-pressure bottom water flooding stage 1 (%) is:
CO injection 2 Volume G of natural gas produced in huff and puff stage Combination of Chinese herbs (cm 3 )
CO injection 2 Recovery ratio R of huff and puff stage flooding stage 2 (%) is:
namely, the cumulative recovery ratio R (%) is:
7. CO injection 2 Seal stock quantity calculation
CO at a raw gas reservoir pressure P =31 (MPa), temperature T =92 (. Degree. C.) 2 Volume coefficient of B gc =0.00397; according to a material balance equation, the injection amount is the sum of the sequestration amount and the extraction amount, namely under the ground condition:
CO injection 2 Total amount W (cm) 3 )＝CO 2 Sealing amount W 1 (cm 3 ) + CO production 2 Quantity W 2 (cm 3 )
CO 2 Intermediate vessel 9 injecting CO 2 Total amount W (cm) (under ground conditions) 3 ) Comprises the following steps:
CO production 2 Quantity W 2 (cm 3 ) Comprises the following steps:
i.e. CO 2 Amount of sealing W 1 (cm 3 ) Is composed of
8. CO2 2 Calculation of free and dissolved gases
At the beginning of the experiment, the effective pore volume V of the parallel core p ＝58.09(cm 3 ) All occupied by natural gas; at the end of the experiment, V p (cm 3 ) By formation water, free CO 2 And natural gas occupation, at formation conditions:
V p (cm 3 ) = water intrusion (W) e ) + free CO 2 Quantity (G) c ) + the amount of natural gas not produced (G) res )
Water invasion of gas reservoir W e (subsurface volume) is:
W e ＝W inj -W P B w
wherein: w inj Gas reservoir water injection (underground volume), cm 3 ；W p Water production (above ground volume) in cm for gas reservoir 3 ；
W inj ＝V 1 -V 2 ＝75.3-10＝65.3
W e ＝65.3-33.4×1.03＝33.9
The volume of undelivered natural gas below the formation is:
namely free CO 2 Volume G measured under the formation c (cm 3 ) Comprises the following steps:
G c ＝V P -W e -G res ＝58.09-33.9-20.54＝3.65
under the ground condition, the free gas quantity W of the rock core 3 (cm 3 ) Comprises the following steps:
CO injection 2 The amount of the sealed storage is divided into the free gas amount W of the core 3 (cm 3 ) And the amount of water dissolved in the formation W 4 (cm 3 ) Namely:
W 1 ＝W 3 +W 4
i.e. formation water dissolves CO under surface conditions 2 Quantity W 4 (cm 3 ) Comprises the following steps:
W 4 ＝W 1 -W 3 ＝6164.3-919.4＝5244.9。
CO 2 the produced gas amount, free gas amount and dissolved gas amount are shown in the graph of fig. 4.
Claims (3)
1. CO injection 2 The method for improving the extraction degree of the heterogeneous bottom water gas reservoir by huff and puff sequentially comprises the following steps of:
(1) Selecting plunger rocks of different permeabilitiesCore, wherein the hypertonic core length L Height of Total pore volume V High (a) Length L of low permeability core Is low with Total pore volume V Is low with (ii) a Respectively placing a high-permeability core and a low-permeability 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 rock core parallel system is connected with a confining pressure pump, the inlet end of the rock core parallel system is respectively connected with a formation water intermediate container and a natural gas intermediate container, and the outlet end of the rock core parallel system is connected with CO 2 The middle containers, the core parallel system and each middle container are all arranged in a constant-temperature oven; the outlet ends of the high-permeability core and the low-permeability core are respectively connected with a back pressure pump and a separator through back pressure valves, 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 confining pressure to P 0 ，P 0 Is 2MPa greater than P, and the pressure of the constant pressure pump connected with the formation water intermediate container is set to be P 0 Water in the formation water intermediate container enters the rock core parallel system along the pipeline until water is produced at the outlet end;
(2) enabling formation water to only pass through the high-permeability core until water is uniformly discharged from a separator at the outlet end of the high-permeability core; enabling formation water to only pass through the low-permeability core until water is uniformly discharged from a separator at the outlet end of the low-permeability core; setting the pressure of the constant pressure pump to be P, and stabilizing the pressure of a formation water intermediate container at P until water is not produced at the outlet ends of the hypertonic rock core and the hypotonic rock core;
(3) injecting natural gas into the high-permeability rock core by using a displacement pump connected with a natural gas intermediate container until a separator at the outlet end of the high-permeability rock core does not discharge water any more, and measuring the water volume V w is high (ii) a Injecting natural gas into the low-permeability rock core by using the displacement pump until the separator at the outlet end of the low-permeability rock core does not discharge water any more, and measuring the water volume V w is low ；
(3) Calculating geological reserves
Under the formation pressure, the volume coefficient of the formation water is B w Volume coefficient of natural gas of B g And then:
high permeability core effective hydrocarbon porosityVolume V P is high ＝V W is high B W Original geological reserve
Effective hydrocarbon pore volume V of low permeability core Plow ＝V w is low B w Original geological reserve
Total effective hydrocarbon pore volume V of core parallel system P ＝V Height of P +V P is low Total original geological reserve G = G Height of +G Is low in ；
(4) Performing constant-pressure bottom water drive
Stabilizing confining pressure at P 0 The pressure of the formation water intermediate container is kept constant at the formation pressure P by using a constant pressure pump connected with the formation water intermediate container, and the volume V of the constant pressure pump is read 1 (ii) a Synchronously using a back pressure pump to control the back pressure at the outlet ends of the high-permeability rock core and the low-permeability rock core to slowly decrease from P until the outlet ends of the high-permeability rock core and the low-permeability rock core produce all water, and respectively metering the accumulated gas production G of the high-permeability rock core and the low-permeability rock core High yield 、G Low yield Cumulative water production W p is high 、W p is low ；
(5) CO2 injection for treating huff and puff
Connecting the outlet end of the high-permeability core and the outlet end of the low-permeability core together, resetting the back pressure of the outlet ends to be P, and passing CO 2 The displacement pump connected with the intermediate container pumps CO 2 Slowly injecting CO into the core parallel system each time 2 The amount is 0.1V P (ii) a Controlling the back pressure at the outlet end to slowly reduce by 2MPa from P, separating the produced gas and water by a separator, and measuring the water yield W at the stage p1 Gas generation volume G In 1. Sup. (ii) a Analyzing the gas components extracted at the stage by adopting a gas chromatograph to obtain the content N of the natural gas 1 (ii) a Repeating the steps n times, and measuring the water yield W of each stage pi (i =1,2,3 \8230n), gas generation volume G He i (i =1,2,3 \8230n) up to N n Less than 0.1%, and the volume V of the displacement pump is read 2 ；
(6) Calculating the accumulated recovery ratio:
the accumulated recovery rate is the recovery rate in the constant-pressure bottom water drive stage and CO injection 2 The sum of the recovery factors in the huff and puff phase;
(7) Calculating CO 2 Produced volume, free gas volume and dissolved gas volume.
2. A CO injection as claimed in claim 1 2 The method for improving the extraction degree of the heterogeneous bottom water gas reservoir through huff and puff is characterized in that the accumulated recovery ratio is calculated in the step (6) and the process is as follows:
constant pressure bottom water drive stage recovery
CO injection 2 Volume of natural gas produced in huff and puff stage
CO injection 2 Recovery in huff and puff phase
The cumulative recovery ratio R (%) is:
3. a CO injection system as claimed in claim 1 2 The method for improving the extraction degree of the heterogeneous bottom water gas reservoir through huff and puff is characterized in that the step (7) is used for calculating CO 2 The process comprises the following steps of (1) producing amount, free gas amount and dissolved gas amount:
at formation pressure P, formation temperature T, CO 2 Volume coefficient of B gc (ii) a The injection amount is the sum of the sealing stock amount and the extraction amount, namely under the ground condition:
CO injection 2 Total amount W =CO 2 Amount of sealing W 1 + CO production 2 Quantity W 2
CO 2 CO injection into the intermediate vessel 2 Total amount of
CO production 2 Measurement of
CO 2 Sealing amount
Effective hydrocarbon pore volume V of parallel core system p Occupied by natural gas, injected with CO 2 After taking in and taking out, V p By formation water, free CO 2 And natural gas occupation, i.e. under formation conditions:
V p = water intrusion W e + free CO 2 Quantity G c + amount of unextracted natural gas G res
W e ＝W inj -W P B w
Wherein W inj -gas reservoir water injection rate (subsurface volume); w p -gas reservoir water production (above ground volume);
W inj ＝V 1 -V 2
the volume of undelivered natural gas below the formation is:
i.e. free CO 2 Volume G measured under the formation c Comprises the following steps:
under the ground condition, the free gas quantity W of the rock core 3 Comprises the following steps:
CO 2 the amount of the sealed storage is divided into the free gas amount W of the core 3 And the amount of water dissolved in the formation W 4 Namely:
W 1 ＝W 3 +W 4
i.e. formation water dissolves CO under surface conditions 2 Quantity W 4 Comprises the following steps:
W 4 ＝W 1 -W 3
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