CN115749703B - CO injection2Method for improving extraction degree of heterogeneous bottom water and gas reservoir through huff and puff - Google Patents

Abstract

The present invention relates to a method for improving the recovery degree of heterogeneous bottom water gas reservoir by injecting _CO2 , comprising: (1) placing a high permeability core and a low permeability core in a clamp respectively, connecting the two clamps in parallel to form a core parallel system, connecting a confining pressure pump to the middle section of the system, connecting the inlet end to a formation water intermediate container and a natural gas intermediate container respectively, and connecting the outlet end to a _CO2 intermediate container, the outlet ends of the high permeability core and the low permeability core are connected to a back pressure pump and a separator respectively through a back pressure valve, and the separator is connected to a gas meter and a gas chromatograph; (2) establishing original formation conditions; (3) calculating geological reserves; (4) performing constant pressure bottom water drive; (5) injecting CO2; (6) calculating cumulative recovery; (7) calculating _CO2 recovery, free gas volume and dissolved gas volume. The present invention has reliable principle and is easy to operate. By evaluating the feasibility of injecting _CO2 in the late stage of water channeling in bottom water gas reservoirs, the present invention provides technical support for the late stage of _CO2 injection development in bottom water gas reservoirs, and solves the problem of _CO2 gas burial.

Description

A method for improving the recovery of heterogeneous bottom water gas reservoirs by injecting CO2

Technical Field

The invention relates to the technical field of oil and gas field development, and in particular to an experimental method for improving the recovery degree of heterogeneous bottom water gas reservoirs by injecting _CO2 huff and puff.

Background technique

Most of the gas reservoirs currently under development are water-driven gas reservoirs to varying degrees, of which 40% to 50% are gas reservoirs with active edge and bottom water. In particular, in the Sichuan Basin, water-driven gas reservoirs account for more than 80% of the total reserves. Once pore water flows or edge and bottom water invade during the development of a gas reservoir, gas-water two-phase seepage will form in the reservoir, greatly increasing the seepage resistance; and for heterogeneous gas reservoirs, the high-permeability area is the main water invasion channel, and it is difficult for water to enter the low-permeability and high-pressure pores. Instead, it bypasses the low-permeability pore zone and advances rapidly along the high-permeability area, forming a low-permeability and high-pressure dead gas zone in the gas reservoir, which greatly reduces the recovery of the gas reservoir.

In recent years, a large number of scholars have conducted physical simulation exploration and research on water invasion in bottom water gas reservoirs. The invention patent "An experimental device and method for simulating water invasion in gas reservoirs" (CN 105604545 A) uses artificial fractured cores to simulate the water invasion process of gas reservoirs to understand the distribution characteristics of residual gas after water invasion, but the model has a maximum pressure of 0.8MPa and cannot simulate the water invasion process under real reservoir conditions. The invention patent "A physical simulation experimental system and method for multi-well production water invasion in edge and bottom water gas reservoirs" (CN107905769 A) can simulate the water invasion process of heterogeneous edge and bottom water gas reservoirs, but cannot simulate the state of gas reservoirs after flooding. The invention patent "Simulation development device and method for gas reservoirs" (CN 112065376 A) scans the simulated gas reservoir corresponding to the simulated core through a ray scanning system to determine the migration of the edge or bottom water body of the simulated gas reservoir, thereby understanding the water invasion characteristics of the edge or bottom water body during the development of the gas reservoir. Fang Feifei et al. evaluated the influence of different permeability differences and different well layout methods on the development effect of heterogeneous gas reservoirs by simulating the water invasion and production dynamic changes of heterogeneous gas reservoirs (Fang Feifei, Liu Huaxun, Xiao Qianhua, et al. Physical simulation experimental study on the water invasion law of heterogeneous gas reservoirs [J]. Laboratory Research and Exploration, 2019, 38(3):5), but did not provide guidance on how to improve the recovery rate after gas reservoir flooding.

At present, the research on heterogeneous bottom water gas reservoirs mainly focuses on water invasion rules, production dynamic changes, and how to improve the output degree by rationally and effectively developing bottom water gas reservoirs. However, there are few studies on how to inject gas to improve the recovery degree of gas reservoirs in the late stage of water invasion, especially on the research on _CO2 injection to improve the recovery rate of bottom water gas reservoirs at home and abroad. The combination of _CO2 injection to improve oil and gas recovery rate and geological storage is the development trend of oil and gas reservoir development in the future. On the one hand, _CO2 injection strengthens oil and gas production, and on the other hand, it promotes carbon capture, carbon utilization and carbon storage. However, since _CO2 is easily soluble in water, _CO2 injection in bottom water gas reservoirs cannot form an effective displacement of formation fluids, resulting in energy loss, resulting in low recovery rate and poor economic benefits. Therefore, for the development of _CO2 injection in bottom water gas reservoirs, it is particularly important to evaluate the production, free amount and dissolved amount of _CO2 during the development process.

Summary of the invention

The purpose of the present invention is to provide a method for improving the recovery degree of heterogeneous bottom water gas reservoirs by injecting _CO2 . The method has reliable principle and is easy to operate. By evaluating the feasibility of _CO2 injection in the late stage of water breakthrough in bottom water gas reservoirs, technical support is provided for the late stage _CO2 injection development of bottom water gas reservoirs.

In order to achieve the above technical objectives, the present invention adopts the following technical solutions.

A method for increasing the recovery of a heterogeneous bottom water gas reservoir by injecting _CO2 huff and puff, comprising the following steps in sequence:

(1) Selecting plunger cores with different permeabilities, wherein the high permeability core has a _long length L and _{a high} total pore volume V, and the low permeability core has a _short length L and _{a low} total pore volume V; placing the high permeability core and the low permeability core in a clamp respectively, and connecting the two clamps in parallel to form a core parallel system to simulate heterogeneous formations; the middle section of the core parallel system is connected to a confining pressure pump, the inlet end is respectively connected to a formation water intermediate container and a natural gas intermediate container, and the outlet end is connected to a _CO2 intermediate container, and the core parallel system and each intermediate container are placed in a constant temperature oven; the outlet ends of the high permeability core and the low permeability core are respectively connected to a back pressure pump and a separator through a back pressure valve, and the separator is connected to a gas meter and a gas chromatograph;

(2) Establishing original formation conditions

① Set the temperature of the constant temperature oven to the formation temperature T, set the back pressure to the formation pressure P; set the confining pressure to P ₀ (P ₀ is about 2MPa greater than P), set the pressure of the constant pressure pump connected to the formation water intermediate container to P ₀ , and let the water in the formation water intermediate container enter the core parallel system along the pipeline until water is produced at the outlet;

② Make the formation water pass only through the high permeability core until the separator at the outlet of the high permeability core produces water evenly; make the formation water pass only through the low permeability core until the separator at the outlet of the low permeability core produces water evenly; then set the pressure of the constant pressure pump to P, so that the pressure of the formation water intermediate container is stabilized at P, until no water is produced at the outlet of the high permeability core and the low permeability core;

③ Use the displacement pump connected to the natural gas intermediate container to inject natural gas into the high permeability core until the separator at the outlet of the high permeability core no longer produces water, and the measured water volume Vw _{is high} ; use the displacement pump to inject natural gas into the low permeability core until the separator at the outlet of the low permeability core no longer produces water, and the measured water volume Vw _{is low} ;

(3) Calculation of geological reserves

Under formation pressure, the volume coefficient of formation water is B _w , and the volume coefficient of natural gas is B _g , then:

Effective hydrocarbon pore volume in high permeability core V _{P high} = V _{W high} B _W , original geological reserves

The effective hydrocarbon pore volume of low permeability core V _{P low} = V _{w low} B _w , original geological reserves

The total effective hydrocarbon pore volume of the core parallel system V _P = V _{P high} + V _{P low} , and the total original geological reserves G = G _high + G _low ;

(4) Constant pressure bottom water drive (separate production)

The confining pressure is stabilized at P ₀ , and the pressure of the formation water intermediate container is kept constant at the formation pressure P using a constant pressure pump connected to the formation water intermediate container, and the volume V ₁ of the constant pressure pump is read; the back pressure at the outlet of the high permeability core and the low permeability core is controlled to slowly decrease from P using a back pressure pump until all the outlets of the high permeability core and the low permeability core produce water, and the cumulative gas production G _{high production} and G _{low production} of the high permeability core and the low permeability core are measured respectively, and the cumulative water production W _{p high} and W _{p low} ;

(5) CO2 injection and huff and puff (combined production)

Connect the high permeability core outlet and the low permeability core outlet together, reset the outlet back pressure to P, slowly inject CO ₂ into the core parallel system through the displacement pump connected to the CO ₂ intermediate container, and inject _{0.1V P} each time; control the outlet back pressure to slowly decrease from P to 2MPa, and the produced gas and water are separated by a separator, and the water production W _p1 and gas production volume G _{total 1} of this stage are measured; use a gas chromatograph to analyze the gas components produced in this stage, and obtain the natural gas content N ₁ ; repeat this step n times, measure the water production W _pi (i＝1,2,3…n) and gas production volume G _{total i} (i＝1,2,3…n) of each stage, until N _n <0.1%, and read the displacement pump volume V ₂ ;

(6) Calculation of cumulative recovery factor

Constant pressure bottom water drive stage:

High permeability core recovery rate

Low permeability core recovery

Recovery factor at constant pressure bottom water flooding stage

Volume of natural gas produced during _CO2 injection huff-and-puff phase

Recovery rate during CO ₂ injection huff-and-puff phase

The cumulative recovery factor R (%) is:

(7) Calculate _CO2 production, free gas volume and dissolved gas volume

At formation pressure P and formation temperature T, the CO ₂ volume coefficient is B _gc ; according to the material balance equation, the injection volume is the sum of the storage volume and the production volume, that is, under ground conditions:

Total amount of injected CO ₂ W = CO ₂ storage W ₁ + CO ₂ production W ₂

Total amount of CO ₂ injected into the CO ₂ intermediate container (under ground conditions)

CO ₂ produced

CO ₂ storage capacity

At the beginning of the experiment, the effective hydrocarbon pore volume _Vp of the parallel core system was completely occupied by natural gas. At the end of the experiment, _Vp was occupied by formation water, free _CO2 and natural gas. Under the formation conditions:

V _p = water intrusion _We + free CO ₂ G _c + unproduced natural gas _Gres

The water intrusion of gas reservoir _We (underground volume) is:

_We = _Winj - W _P B _w

Wherein, _Winj is the water injection volume of the gas reservoir (underground volume); _Wp is the water production volume of the gas reservoir (above ground volume);

_Winj = _V1 - _V2

The volume of unproduced natural gas beneath the formation is:

That is, the volume of free CO ₂ in the formation G _c is:

Under surface conditions, the free gas volume _W3 in the core is:

The _CO2 storage capacity is divided into the free gas volume in the core _W3 and the dissolved gas volume in the formation water _W4 , namely:

W ₁ =W ₃ +W ₄

That is, under ground conditions, the amount of CO ₂ dissolved in formation water W ₄ is:

_W4 ＝ _W1 - _W3

Compared with the prior art, the present invention is simple and applicable, and can not only simulate the water invasion process of heterogeneous bottom water gas reservoirs under real reservoir conditions (high temperature and high pressure environment), but also simulate the _CO2 injection development in the later stage of gas reservoir water invasion, and evaluate the feasibility of injecting _CO2 to improve the recovery degree of bottom water gas reservoirs. In the later stage of water invasion of bottom water heterogeneous gas reservoirs, _CO2 injection was injected, and the ratio of _CO2 recovery, free amount and dissolved amount was about 3:1:6, and the natural gas recovery degree was increased by 18.07%, indicating that this method can improve the recovery rate of gas reservoirs while solving the _CO2 gas storage problem.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG1 is a diagram of a device for injecting _CO2 to increase the recovery rate of a heterogeneous bottom water gas reservoir.

FIG2 is a curve showing the change of natural gas recovery rate with pressure during the constant pressure bottom water flooding stage.

Figure 3 shows the change in the degree of natural gas recovery increased by _CO2 injection.

Figure 4 is a bar chart comparing the _CO2 produced gas volume and the stored gas volume.

In the figure: 1-confining pressure pump; 2-constant pressure pump; 3, 4-displacement pumps; 5, 6-back pressure pumps; 7-formation water intermediate container; 8-natural gas intermediate container; 9- _CO2 intermediate container; 10-low permeability core holder; 11-high permeability core holder; 12-confining pressure gauge; 13, 14-outlet pressure gauge; 15, 16-back pressure gauge; 17, 18-back pressure valve; 19, 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 ways

The present invention is further described below with reference to the accompanying drawings and examples, so that those skilled in the art can understand the present invention. However, it should be clear that the present invention is not limited to the scope of the specific embodiments, and for those skilled in the art, as long as various changes are within the spirit and scope of the present invention defined and determined by the attached claims, they are all protected.

The method of injecting _CO2 to improve the recovery degree of heterogeneous bottom water gas reservoirs is completed by an experimental device. The structure of the device is shown in Figure 1. A low-permeability core clamp 10 and a high-permeability core clamp 11 are connected in parallel to form a core parallel system to simulate heterogeneous formations; the middle section of the core parallel system is connected to a confining pressure pump 1, and the inlet end is respectively connected to a formation water intermediate container 7 (the bottom water intermediate container is connected to a constant pressure pump 2) and a natural gas intermediate container 8 (the natural gas intermediate container is connected to a displacement pump 3), and the outlet end is connected to a _CO2 intermediate container 9 (the _CO2 intermediate container is connected to a displacement pump 4). The core parallel system and each intermediate container are placed in a constant temperature oven 37; the outlet ends of the low-permeability core and the high-permeability core are respectively connected to back pressure pumps 5, 6 and separators 19, 20 through back pressure valves 17, 18, and the separators are connected to gas meters 23, 24 and gas chromatographs 25, 26.

A method for increasing the recovery of a heterogeneous bottom water gas reservoir by injecting _CO2 huff and puff, comprising the following steps in sequence:

1. Experimental Preparation

(1) Plug cores with different permeabilities were selected. The high permeability core had a length _Lhigh = 82 (cm) and a pore volume _Vhigh = 44.14 (cm ³ ); the low permeability core had a length _Llow = 83 (cm) and a pore volume _Vlow = 34.75 (cm ³ ).

(2) Formation water, natural gas and _CO2 are transferred into intermediate containers 7, 8 and 9 respectively, low-permeability cores and high-permeability cores are placed in core holders 10 and 11 respectively, and are placed together in a constant temperature oven 37. The temperature of the constant temperature oven 37 is set to the formation temperature T = 92 (℃), and all valves are kept in a closed state.

(2) Use the back pressure pumps 5 and 6 to set the back pressure on the back pressure valves 17 and 18 respectively, and set the back pressure to the formation pressure P = 31 (MPa).

2. Establishing original formation conditions

(3) Use the confining pressure pump 1 to inject hydraulic oil into the core parallel system to increase the confining pressure to P ₀ =33 (MPa).

(4) Open valves 27, 29, 30, 31, 33, 35, and 36 to supply constant pressure pump 2. Set the pressure of the constant pressure pump to P ₀ = 33 (MPa) so that the water in the formation water intermediate container flows along the pipeline into the long core parallel system until water is produced in separators 19 and 20.

(5) Close valve 29 so that formation water can only pass through high-permeability core 11 until water is evenly discharged from separator 20; close valve 30 and open valve 29 so that formation water can only pass through low-permeability core 10 until water is evenly discharged from separator 19; open valve 30 and set the pressure of constant pressure pump 2 to P=31 (MPa) so that the pressure of the formation water intermediate container is stabilized at P=31 (MPa) until no more water is produced from separators 19 and 20.

(6) Close valves 27 and 30, open valve 28, and use displacement pump 3 to inject natural gas from the natural gas intermediate container 8 into the low permeability core 10 until no water is produced from the separator 19, and the measured water volume V _{w low} = 24.3 (cm ³ ); close valve 29, open valve 30, and use displacement pump 3 to inject natural gas from the natural gas intermediate container 8 into the high permeability core 11, until no water is produced from the separator 20, and the measured water volume V _{w high} = 32.1 (cm ³ ). Close all valves, and the original state of the core is established.

3. Calculation of geological reserves

(7) Under formation pressure, the volume coefficient of formation water is _Bw = 1.03, the volume coefficient of natural gas is _Bg = 0.00253, and the effective hydrocarbon pore volume Vp of high permeability long core 11 _{is high} ( ^cm3 )

V _{P high} = V _{W high} B _W = 32.1 × 1.03 = 33.06

The original geological reserves of high permeability core 11 are G _high (cm ³ )

The effective hydrocarbon pore volume V _{p low} of the low permeability core 10 (cm ³ )

V _{P low} = V _{w low} B _w = 24.3 × 1.03 = 25.03

The original geological reserves of low permeability core 10 are _Glow (cm ³ )

Total effective hydrocarbon pore volume V _P (cm ³ ) of the parallel long cores

V _P = V _{P high} + V _{P low} = 33.06 + 25.03 = 58.09

The total geological reserves G (cm ³ ) are:

G= _Ghigh + _Glow =13067.2+9893.3=22960.5.

4. Constant pressure bottom water drive (separate production)

(8) Use the confining pressure pump 1 to stabilize the confining pressure at P ₀ =33 (MPa), use the constant pressure pump 2 to keep the pressure of the formation water intermediate container 7 constant at the formation pressure P=31 (MPa), and read the constant pressure pump volume V ₁ =10 (cm ³ ).

(9) Open valves 27, 29, 30, 31, 33, 35, 36, and use back pressure pumps 5 and 6 to control the pressure of back pressure valves 17 and 18 to slowly decrease from P = 31 (MPa) to P ₁ = 29 (MPa) at a speed of X = 1 (MPa/h). Use separators 19 and 20 to separate gas and water. Use gas meters 23 and 24 to measure the cumulative gas production volume G _low production = 3363.7 (cm ³ ) and G _{high production} = 7317.8 (cm ³ ), respectively, and read the cumulative water production W _{p low} = 12.6 (cm ³ ) and W _{p high} = 8.4 (cm ³ ). Close valves 31, 33, 35, 36 until all water is produced at the outlet. The constant pressure bottom water flooding experimental data are shown in Table 1, and the curve of natural gas recovery rate changing with pressure is shown in Figure 2.

Table 1 Constant pressure bottom water drive experimental data

5. _CO2 injection and huff and puff (combined production)

(10) Open valves 32, 33, and 34, connect the inlet and outlet ends of the high-permeability core and the low-permeability core to form a long core parallel system, and use the back pressure pump 6 to reset the pressure of the back pressure valve 18 to P = 31 (MPa). Use the displacement pump 4 to slowly inject CO ₂ in the CO ₂ intermediate container 9 into the core parallel system at a formation pressure of P = 31 (MPa), and the injected CO ₂ amount is 0.1V _P = 5.8 (cm ³ ).

(11) Close valve 34, open valve 36, use back pressure pump 6 to control the back pressure to slowly decrease from P = 31 (MPa) to 29 (MPa) at a speed of X = 1 (MPa/h), the produced gas and water are separated by separator 20 until all water is produced at the outlet, and valve 36 is closed. Read the cumulative water production W _pi = 12.4 (cm ³ ) (i = 1, 2, 3 ... n) at this stage, use a gas meter to measure the gas volume G _{total i} (cm ³ ) (i = 1, 2, 3 ... n), use gas chromatograph 26 to analyze the gas components, and obtain the natural gas content _Ni (%) (i = 1, 2, 3 ...). Repeat steps 10-11, repeat n = 6 times, until _Ni < 0.1%. Close all valves, read the constant pressure pump volume V ₂ = 75.3 (cm ³ ) and stop the experiment. The experimental data of CO2 injection and huff _- and-puff combined production are shown in Table 2, and the changes in the degree of natural gas recovery improved by _CO2 injection and huff-and-puff cycles are shown in Figure 3.

Table 2 _CO2 injection huff-and-puff combined production experimental data

Gas injection rounds Produced natural gas volume/cm ³ CO ₂ produced/cm ³ Improved oil recovery rate/% Cumulative water production/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 factor calculation

The production stages of the experiment on improving the recovery degree of bottom water gas reservoirs in the late water invasion period by injecting CO ₂ are divided into the constant pressure bottom water drive stage and the CO ₂ injection huff and puff stage, that is, the cumulative recovery factor R (%) should be the sum of the recovery factor R ₁ (%) in the constant pressure bottom water drive stage and the CO ₂ injection huff and puff recovery factor R ₂ (%).

The recovery factor R _high (%) of low-high permeability long core tube in constant pressure bottom water flooding stage is:

The recovery factor _Rlow (%) of the low permeability long core tube in the constant pressure bottom water flooding stage is:

The total recovery factor R ₁ (%) of the simulated gas reservoir in the constant pressure bottom water flooding stage is:

Volume of natural gas produced during CO ₂ injection huff and puff stage _Gto (cm ³ )

The recovery factor R ₂ (%) of the CO ₂ injection and huff-and-puff stage is:

That is, the cumulative recovery factor R (%) is:

7. Calculation of injected _CO2 storage volume

At the original gas reservoir pressure P = 31 (MPa) and temperature T = 92 (℃), the CO ₂ volume coefficient is B _gc = 0.00397; according to the material balance equation, the injection volume is the sum of the storage volume and the production volume, that is, under ground conditions:

Total amount of injected CO ₂ W (cm ³ ) = CO ₂ storage W ₁ (cm ³ ) + CO ₂ production W ₂ (cm ³ )

The total amount of CO ₂ (under ground conditions) injected into the CO ₂ intermediate container 9 W (cm ³ ) is:

The amount of CO ₂ produced W ₂ (cm ³ ) is:

That is, the CO ₂ storage capacity W ₁ (cm ³ ) is

8. Calculation of _CO2 free gas and dissolved gas

At the beginning of the experiment, the effective pore volume of the parallel core _Vp = 58.09 ( ^cm3 ) was completely occupied by natural gas; at the end of the experiment, _Vp ( ^cm3 ) was occupied by formation water, free _CO2 and natural gas. Under the formation conditions:

V _p (cm ³ ) = water intrusion (W _e ) + free CO ₂ (G _c ) + unproduced natural gas (G _res )

The water intrusion of gas reservoir _We (underground volume) is:

_We = _Winj - W _P B _w

Where: _Winj —water injection volume of gas reservoir (underground volume), cm ³ ; _Wp —water production volume of gas reservoir (aboveground volume), cm ³ ;

_Winj = _V1 - _{V2 = 75.3 - 10} = 65.3

_We = 65.3-33.4 × 1.03 = 33.9

The volume of unproduced natural gas beneath the formation is:

That is, the volume G _c (cm ³ ) of free CO ₂ in the formation is:

G _c = _VP - _We - _Gres = 58.09 - 33.9 - 20.54 = 3.65

Under surface conditions, the free gas volume W ₃ (cm ³ ) in the core is:

The injected CO ₂ storage volume is divided into the free gas volume in the core W ₃ (cm ³ ) and the dissolved gas volume in the formation water W ₄ (cm ³ ), namely:

W ₁ =W ₃ +W ₄

That is, under ground conditions, the amount of CO ₂ dissolved in formation water W ₄ (cm ³ ) is:

W ₄ =W ₁ -W ₃ =6164.3-919.4=5244.9.

The comparison of _CO2 produced gas volume, free gas volume and dissolved gas volume is shown in Figure 4.

Claims (3)

1. A method for increasing the recovery of a heterogeneous bottom water gas reservoir by injecting _CO2 , comprising the following steps in sequence: (1) Selecting plunger cores with different permeabilities, wherein the high permeability core has a _long length L and _{a high} total pore volume V, and the low permeability core has a _short length L and _{a low} total pore volume V; placing the high permeability core and the low permeability core in a clamp respectively, and connecting the two clamps in parallel to form a core parallel system to simulate heterogeneous formations; the middle section of the core parallel system is connected to a confining pressure pump, the inlet end is connected to a formation water intermediate container and a natural gas intermediate container respectively, and the outlet end is connected to a _CO2 intermediate container, and the core parallel system and each intermediate container are placed in a constant temperature oven; the outlet ends of the high permeability core and the low permeability core are connected to a back pressure pump and a separator respectively through a back pressure valve, and the separator is connected to a gas meter and a gas chromatograph; (2) Establishing original formation conditions ① Set the temperature of the constant temperature oven to the formation temperature T, set the back pressure to the formation pressure P; set the confining pressure to P ₀ , P ₀ is 2MPa greater than P, set the pressure of the constant pressure pump connected to the formation water intermediate container to P ₀ , and let the water in the formation water intermediate container enter the core parallel system along the pipeline until water is produced at the outlet; ② Make the formation water pass only through the high permeability core until the separator at the outlet of the high permeability core produces water evenly; make the formation water pass only through the low permeability core until the separator at the outlet of the low permeability core produces water evenly; then set the pressure of the constant pressure pump to P, so that the pressure of the formation water intermediate container is stabilized at P, until no water is produced at the outlet of the high permeability core and the low permeability core; ③ Use the displacement pump connected to the natural gas intermediate container to inject natural gas into the high permeability core until the separator at the outlet of the high permeability core no longer produces water, and the measured water volume Vw _{is high} ; use the displacement pump to inject natural gas into the low permeability core until the separator at the outlet of the low permeability core no longer produces water, and the measured water volume Vw _{is low} ; (3) Calculation of geological reserves Under formation pressure, the volume coefficient of formation water is B _w , and the volume coefficient of natural gas is B _g , then: Effective hydrocarbon pore volume in high permeability core V _{P high} = V _{W high} B _W , original geological reserves The effective hydrocarbon pore volume of low permeability core V _{P low} = V _{w low} B _w , original geological reserves The total effective hydrocarbon pore volume of the core parallel system V _P = V _{P high} + V _{P low} , and the total original geological reserves G = G _high + G _low ; (4) Perform constant pressure bottom water drive The confining pressure is stabilized at P ₀ , and the pressure of the formation water intermediate container is kept constant at the formation pressure P using a constant pressure pump connected to the formation water intermediate container, and the volume V ₁ of the constant pressure pump is read; the back pressure at the outlet of the high permeability core and the low permeability core is controlled to slowly decrease from P using a back pressure pump until all the outlets of the high permeability core and the low permeability core produce water, and the cumulative gas production G _{high production} and G _{low production} of the high permeability core and the low permeability core are measured respectively, and the cumulative water production W _{p high} and W _{p low} ; (5) _CO2 injection and puffing Connect the high permeability core outlet and the low permeability core outlet together, reset the outlet back pressure to P, slowly inject CO ₂ into the core parallel system through the displacement pump connected to the CO ₂ intermediate container, and inject _{0.1V P} each time; control the outlet back pressure to slowly decrease from P to 2MPa, and the produced gas and water are separated by a separator, and the water production W _p1 and gas production volume G _{total 1} of this stage are measured; use a gas chromatograph to analyze the gas components produced in this stage, and obtain the natural gas content N ₁ ; repeat this step n times, measure the water production W _pi (i＝1,2,3…n) and gas production volume G _{total i} (i＝1,2,3…n) of each stage, until N _n <0.1%, and read the displacement pump volume V ₂ ; (6) Calculate the cumulative recovery factor: The cumulative recovery factor is the sum of the recovery factor in the constant pressure bottom water flooding stage and the recovery factor in the _CO2 injection huff-and-puff stage; (7) Calculate the _CO2 production, free gas volume and dissolved gas volume. 2. A method for improving the recovery of heterogeneous bottom water gas reservoirs by injecting _CO2 as claimed in claim 1, characterized in that the cumulative recovery factor is calculated in step (6), and the process is as follows: Recovery factor at constant pressure bottom water flooding stage Volume of natural gas produced during _CO2 injection huff-and-puff phase Recovery rate during CO ₂ injection huff-and-puff phase The cumulative recovery factor R (%) is: 3. A method for improving the recovery of heterogeneous bottom water gas reservoirs by injecting _CO2 as claimed in claim 1, characterized in that the step (7) calculates the _CO2 recovery, free gas volume and dissolved gas volume as follows: At formation pressure P and formation temperature T, the CO ₂ volume coefficient is B _gc ; the injection volume is the sum of the storage volume and the production volume, that is, under ground conditions: Total amount of injected CO ₂ W = CO ₂ storage W ₁ + CO ₂ production W ₂ Total amount of _CO2 injected into the _CO2 intermediate container CO ₂ produced CO ₂ storage capacity The effective hydrocarbon pore volume _Vp of the parallel core system is occupied by natural gas. After _CO2 injection, _Vp is occupied by formation water, free _CO2 and natural gas, that is, under formation conditions: V _p = water intrusion _We + free CO ₂ G _c + unproduced natural gas _{Gres We} = _Winj - W _P B _w Wherein, _Winj is the water injection volume of the gas reservoir; _Wp is the water production volume of the gas reservoir; _Winj = _V1 - _V2 The volume of unproduced natural gas beneath the formation is: That is, the volume of free CO ₂ in the formation G _c is: Under surface conditions, the free gas volume _W3 in the core is: The _CO2 storage capacity is divided into the free gas volume in the core _W3 and the dissolved gas volume in the formation water _W4 , namely: W ₁ =W ₃ +W ₄ That is, under ground conditions, the amount of CO ₂ dissolved in formation water W ₄ is: _W4 ＝ _W1 - _W3