Device and method for replacing shale oil and gas under pressure maintaining condition

Abstract

The invention discloses a device for replacing shale oil gas under a pressure maintaining condition. The problem that free gas escapes when shale is taken out of a shaft is mainly solved. The device is characterized in that a pressure-maintaining rock core container is arranged in the pressure-maintaining rock core heating instrument; the gas-liquid storage container is connected with the gas-liquid drying separator; the top and the bottom of the gas-liquid drying separator are respectively connected with the flow measuring device and the liquid separation tank; the top of the gas-liquid storage container is connected with an outlet of the pressure-maintaining core container; the inlet of the pressure-maintaining rock core container is sequentially connected with a flow controller and a fluid pressurizing instrument; the fluid pressurizing instrument is respectively connected with the CO2 gas cylinder and the slickwater pool; the shale oil and gas replacement method comprises the steps that fracturing fluid injection is conducted under the simulated formation pressure condition; metering the displacement oil-gas quantity in the fluid injection process; desorbing adsorbed gas in the rock core through in-situ heating; and measuring the total content of oil and gas displaced under the formation condition. The device can accurately and effectively test the content of free gas, adsorbed gas and recoverable shale oil in shale, and more accurately know the potential of oil-gas-containing resources in underground shale.

Description

Technical Field:

[0001] The present invention relates to the technical field of oil and gas field development, and particularly relates to a device and method for replacing shale oil and gas under pressure maintaining conditions. Background Art:

[0002] Shale oil and gas are enriched in shale reservoirs. There are large differences in temperature and pressure conditions between underground and surface. The PVT characteristics of fluids in shale are complex. Under underground conditions, shale gas mainly exists in two forms: adsorbed state and free state. Part of the free state shale gas is dissolved in shale oil. During the exploitation process, the free gas escapes, and it is impossible to test the oil and gas resource amount stored in per unit mass of shale through core experiments under normal pressure conditions, thus it is difficult to accurately evaluate the overall shale oil and gas resource content in the development block.

[0003] Currently, hydraulic fracturing is mainly used for effective development of shale oil and gas. The commonly used hydraulic fracturing method is to inject conventional slickwater in stages after pre-injecting CO2.

[0004] Currently, the experimental replacement of shale oil and gas is mainly divided into two categories: pressure maintaining tests and laboratory condition tests. Among them, the pressure maintaining test means that the core passes through a special container and is tested while maintaining the formation pressure during coring and experimentation; the laboratory condition test means that the core under normal pressure restores the underground temperature and pressure conditions through specific means for testing. Since part of the gas has escaped during normal pressure coring, it is difficult to effectively calculate the actual content of underground high-temperature and high-pressure shale oil and gas under laboratory conditions. Due to high costs and great operation difficulties under pressure maintaining conditions, the free gas volume is often tested on-site, and then the adsorbed gas volume is tested by heating through indoor experimental equipment, without achieving integrated and convenient testing. The problem that free gas is prone to escape during the process of taking shale out of the wellbore still cannot be solved. Summary of the Invention:

[0005] The technical problem to be solved by the present invention is to solve the problem that free gas is prone to escape during the process of taking shale out of the wellbore in the background art, and to provide a device for replacing shale oil and gas under pressure maintaining conditions. This device for replacing shale oil and gas under pressure maintaining conditions can simulate the process of fracturing fluid replacing shale oil and gas under actual formation pressure conditions, accurately and effectively test the contents of free gas, adsorbed gas, and recoverable shale oil in shale, reduce the problem of free gas escape during the process of taking shale out of the wellbore from the source, and more effectively evaluate the adsorbed gas content through in-situ heating desorption, so as to more accurately understand the potential of oil and gas resources in underground shale. The present invention also provides a method for replacing shale oil and gas under pressure maintaining conditions.

[0006] The problem of the present invention can be solved by the following technical solutions: The device for replacing shale oil and gas under pressure maintenance conditions includes a gas-liquid storage container and a pressure-maintaining core heating instrument, and a pressure-maintaining core container is arranged in the center of the pressure-maintaining core heating instrument; the gas-liquid storage container is connected to a gas-liquid drying and separation instrument through a gas-liquid storage container outlet valve; the top of the gas-liquid drying and separation instrument is connected to a flow measurement device, and the bottom is connected to a liquid separation tank; the pipeline at the top of the gas-liquid storage container is connected to the outlet end of the pressure-maintaining core container in the pressure-maintaining core heating instrument; the inlet pipeline of the pressure-maintaining core container is sequentially connected to a pressure gauge, a flow control instrument, and a fluid pressurizing instrument; the fluid pressurizing instrument is also respectively connected to a CO2 gas cylinder through a first branch pipeline and a slippery water tank through a second branch pipeline.

[0007] Further, the pressure-maintaining core container is fixed by wire clamping; a heating instrument with a temperature control system is installed in the pressure-maintaining core heating instrument, and the heating instrument with the temperature control system, the pressure-maintaining core container for storage, and the wire for clamping and fixing the pressure-maintaining core container together form the pressure-maintaining core heating instrument.

[0008] Further, a CO2 gas cylinder outlet valve and a slippery water outlet valve are respectively connected to the first branch pipeline and the second branch pipeline.

[0009] Further, the fluid pressurizing instrument is connected to a pressure pump; the liquid separation tank is respectively connected to a crude oil separation tank and a mud sewage tank; a pressure reducing valve and a pressure gauge are connected to the pipeline at the top of the gas-liquid storage container.

[0010] The present invention also provides a method for replacing shale oil and gas under pressure maintenance conditions, including the following steps:

[0011] The first step: Preparation work before the experiment

[0012] The second step: Injection of fracturing fluid under simulated formation pressure conditions

[0013] The third step: Measuring the amount of oil and gas displaced during the fluid injection process

[0014] The fourth step: In-situ heating to desorb the adsorbed gas in the core

[0015] The fifth step: Measuring the total content of oil and gas displaced under formation conditions

[0016] Further, the preparation work before the experiment in step 1 includes:

[0017] (1) Install the device for replacing shale oil and gas under pressure maintenance conditions; check that the pressure reducing valve is in the open state, check that the pressure in the pressure-maintaining core container for storage is the formation pressure, check that the CO2 gas cylinder outlet valve, the slippery water outlet valve, and the gas-liquid storage container outlet valve are in the closed state, and connect the instrument pipelines;

[0018] (2) Fix the pressure - maintaining core container taken out from the wellbore to the heating instrument with wire; observe that the obtained shale core is a shale core with natural fractures and a shale core without natural fractures.

[0019] Further, the method for injecting fracturing fluid under simulated formation pressure conditions in step 2 includes the following steps:

[0020] 2.1 For shale cores with natural fractures:

[0021] (1) Open the outlet valve of the CO2 gas cylinder, and inject CO2 gas into the fluid pressurizer;

[0022] (2) By adjusting the pressure pump, control the outlet pressure of the fluid pressurizer to the preset inlet pressure value during fracturing;

[0023] (3) Adjust the pressure reducing valve to make the reading of the pressure gauge at the outlet of the pressure - maintaining core heating instrument the preset outlet pressure value;

[0024] (4) Adjust the flow controller to keep the CO2 flow rate at the outlet of the flow controller at the set flow rate;

[0025] (5) Continuously observe whether there is a deviation in the reading of the pressure gauge at the outlet of the flow controller, and adjust the reading of the pressure gauge within the allowable error range;

[0026] (6) After injecting CO2 gas according to the set time, record the total CO2 outlet gas volume in the flow controller, close the outlet valve of the CO2 gas cylinder, and open the outlet valve of the slickwater;

[0027] (7) Adjust the flow controller to keep the slickwater flow rate at the outlet of the flow controller at the set flow rate;

[0028] (8) Continuously observe whether there is a deviation in the reading of the pressure gauge at the outlet of the flow controller, and repeatedly adjust the reading of the pressure gauge within the allowable error range;

[0029] (9) After injecting slickwater according to the set time, close the outlet valve of the slickwater. Since the liquid is not easy to seep through the shale core, record the actual injected volume of the slickwater in the flow controller;

[0030] 2.2 For shale cores without natural fractures:

[0031] If the obtained shale core does not contain natural fractures, it is necessary to reduce the injection flow rates of CO2 and slickwater, increase the injection time of CO2 and slickwater, and increase the preset pressure during fracturing to achieve the replacement purpose.

[0032] Further, the specific method for measuring the amount of oil and gas displaced during the fluid injection process in step 3 includes:

[0033] During the entire fracturing fluid injection process under simulated formation pressure conditions in the second step, synchronously measure the amount of oil and gas displaced during the injection process.

[0034] (1) Open the outlet valve of the gas-liquid storage container, and collect CO2 gas, slickwater, oil, and mud through the gas-liquid storage container.

[0035] (2) Inject the gas-liquid mixture into the gas-liquid drying separator through the outlet of the gas-liquid storage container.

[0036] (3) Through the gas-liquid drying separator, separate the dry gas into the flow measurement device, measure the total volume of the separated gas, and collect the mixed liquid into the liquid separation pool.

[0037] (4) Separate the mixed liquid in the liquid separation pool into the crude oil separation pool and the mud sewage pool.

[0038] Furthermore, the method for in-situ heating and desorbing the adsorbed gas in the core in step 4 includes the following steps:

[0039] (1) Adjust the temperature control system of the heater to the formation temperature, and continuously heat the core at the formation temperature.

[0040] (2) Close the outlet valve of the CO2 gas cylinder, close the outlet valve of the slickwater, adjust the pressure reducing valve so that the pressure gauge reading at the outlet of the pressure-maintaining core heater is within 0.5 MPa, and open the outlet valve of the gas-liquid storage container.

[0041] (3) Record the current time as the 0 time point, continuously measure the volume V3 of the adsorbed gas desorbed by heating, and draw a curve of heating time versus the cumulative volume of the adsorbed gas desorbed.

[0042] (4) When the increase in V3 is less than 0.5 cm 3 / min, turn off the temperature control system of the heater, stop heating, record the volume of the adsorbed gas at this time, and measure the mass of the crude oil in the crude oil separation pool.

[0043] Furthermore, the method for measuring the total content of oil and gas displaced under formation conditions in step 5 includes the following steps:

[0044] (1) After the temperature returns to normal temperature of 20 °C, take out the full-diameter pressure-maintaining core in the pressure-maintaining core container.

[0045] (2) Wash the surface with clean water, dry it, weigh the total mass, and measure the radius and height of the full-diameter core.

[0046] (3) Crush the full-diameter core thoroughly and measure the volume of its rock matrix.

[0047] (4) Calculate the oil and gas content displaced per unit mass of the core:

[0048]

[0049] In the formula, V d - Content of free gas in rock per unit mass, m 3 / t; V2 - Total volume of separated gas, m 3 ; V1 - Total volume of injected CO2, m 3 ; m - Total mass of full - diameter core, t;

[0050]

[0051] In the formula, V a - Content of adsorbed gas in rock per unit mass, m 3 / t; V 31 - Volume of desorbed adsorbed gas, m 3 ; m - Total mass of full - diameter core, t;

[0052]

[0053] In the formula, V o - Mass of recoverable oil in rock per unit mass, g / t; m o - Mass of separated crude oil, g; m - Total mass of full - diameter core, t;

[0054] (5) Calculate the difference in free gas between experimental conditions and theoretical conditions:

[0055]

[0056] In the formula, △V d - Difference in free gas between experimental conditions and theoretical conditions, m 3 / t; V d - Content of free gas in rock per unit mass, m 3 / t; φ - Shale porosity, dimensionless; S g - Gas saturation of shale gas, obtained by downhole logging, dimensionless; r - Radius of full - diameter core, m; l - Height of full - diameter core, m; B g - Gas volume factor, obtained by gas sampling analysis, dimensionless; m - Total mass of full - diameter core, t; V s - Volume of rock matrix, m 3 .

[0057] The present invention can have the following beneficial effects compared with the above - mentioned background technology:

[0058] 1. Through the method of direct measurement by pressure - maintaining coring, the present invention integrally measures the content of free gas, adsorbed gas and recoverable oil mass in shale, avoiding inaccurate test results caused by oil and gas escape during the coring process;

[0059] 2. The present invention heats the pressure-maintained core to ensure that the core is restored to its original underground state during the experiment, avoiding stress damage caused by re-applying pressure to the core in the atmospheric pressure experiment;

[0060] 3. The present invention measures the amount of oil and gas displaced per unit mass of shale through experimental tests, simulates the displacement effect during the fracturing process, and quantitatively evaluates the recoverable oil and gas resources in the shale around the underground wellbore;

[0061] 4. The present invention can evaluate the gas saturation of underground shale gas from an experimental perspective by calculating the difference in free gas between the experimental conditions and the theoretical conditions, thereby correcting the logging data. BRIEF DESCRIPTION OF THE DRAWINGS

[0062] Figure 1 is a schematic structural diagram of the device for displacing shale oil and gas under pressure-maintained conditions of the present invention;

[0063] Figure 2 is a schematic diagram of the pressure-maintained core heating instrument of the present invention;

[0064] Figure 3 is the curve of heating time and cumulative desorbed adsorbed gas volume in the embodiment of the present invention.

[0065] In the figure: 1. Pressure pump, 2. Flow controller, 3. Pressure gauge, 4. Pressure-maintained core heating instrument, 4-1. Heating instrument with temperature control system, 4-2. Container for storing pressure-maintained core, 4-3. Steel wire for clamping and fixing the container for storing pressure-maintained core, 5. Flow measurement device, 6. Crude oil separation tank, 7. Fluid pressurizer, 8. Gas-liquid drying and separation instrument, 9. CO2 gas cylinder outlet valve, 10. Slickwater outlet valve, 11. Pressure reducing valve, 12. Pressure gauge, 13. CO2 gas cylinder, 14. Slickwater tank, 15. Gas-liquid storage container, 16. Gas-liquid storage container outlet valve, 17. Liquid separation tank, 18. Mud sewage tank. DETAILED DESCRIPTION OF THE INVENTION:

[0066] The present invention will be further described below in conjunction with the drawings:

[0067] As shown in the attached Figure 1 . Figure 2As shown in the figure, the device for displacing shale oil and gas under pressure-maintaining conditions includes a gas-liquid storage container 15 and a pressure-maintaining core heater 4. A pressure-maintaining core container 4-2 is placed in the center of the pressure-maintaining core heater 4. The pressure-maintaining core container 4-2 is clamped and fixed by a steel wire 4-3. The pressure-maintaining core heater 4 is equipped with a heater 4-1 with a temperature control system. The heater 4-1 with a temperature control system, the pressure-maintaining core container 4-2 for storing the core, and the steel wire 4-3 for clamping and fixing the pressure-maintaining core container together form the pressure-maintaining core heater 4. The gas-liquid storage container 15 is connected to a gas-liquid drying and separation instrument 8 through a gas-liquid storage container outlet valve 16. The top of the gas-liquid drying and separation instrument 8 is connected to a flow measurement device 5, and the bottom is connected to a liquid separation tank 17. The liquid separation tank 17 is respectively connected to a crude oil separation tank 6 and a mud sewage tank 18. The pipeline at the top of the gas-liquid storage container 15 is connected to the outlet end of the pressure-maintaining core container 4-2 in the pressure-maintaining core heater 4. A pressure reducing valve 11 and a pressure gauge 12 are connected to the pipeline at the top of the gas-liquid storage container 15. The inlet pipeline of the pressure-maintaining core container 4-2 is successively connected to a pressure gauge 3, a flow control instrument 2, and a fluid pressurizer 7. The fluid pressurizer 7 is connected to a pressure pump 1. The fluid pressurizer 7 is also respectively connected to a CO2 gas cylinder 13 through a first branch pipeline and a slippery water tank 14 through a second branch pipeline. A CO2 gas cylinder outlet valve 9 and a slippery water outlet valve 10 are respectively connected to the first branch pipeline and the second branch pipeline.

[0068] The present invention also provides a method for displacing shale oil and gas under pressure-maintaining conditions, including the following steps:

[0069] The first step: Preparation work before the experiment;

[0070] (1) Install the device for displacing shale oil and gas under pressure-maintaining conditions; check that the pressure reducing valve is in the open state, check that the pressure in the pressure-maintaining core container for storing the core is the formation pressure, check that the CO2 gas cylinder outlet valve, the slippery water outlet valve, and the gas-liquid storage container outlet valve are in the closed state, and connect the instrument pipelines;

[0071] (2) Fix the pressure-maintaining core container taken out from the wellbore to the heater with a steel wire; observe that the obtained shale core is a shale core with natural fractures and a shale core without natural fractures.

[0072] The second step: Injecting fracturing fluid under simulated formation pressure conditions;

[0073] 2.1 For shale cores with natural fractures:

[0074] (1) Open the CO2 gas cylinder outlet valve and inject CO2 gas into the fluid pressurizer;

[0075] (2) By adjusting the pressure pump, control the outlet pressure of the fluid pressurizer to be the preset inlet pressure value during fracturing;

[0076] (3) Adjust the pressure reducing valve so that the reading of the pressure gauge at the outlet of the pressure maintaining core heater is the preset outlet pressure value;

[0077] (4) Adjust the flow control instrument to keep the CO2 flow rate at the outlet of the flow control instrument at the set flow rate;

[0078] (5) Continuously observe whether there is a deviation in the reading of the pressure gauge at the outlet of the flow control instrument, and adjust the reading of the pressure gauge within the allowable error range;

[0079] (6) After injecting CO2 gas according to the set time, record the total outlet gas volume of CO2 in the flow control instrument, close the outlet valve of the CO2 gas cylinder, and open the outlet valve of the slickwater;

[0080] (7) Adjust the flow control instrument to keep the slickwater flow rate at the outlet of the flow control instrument at the set flow rate;

[0081] (8) Continuously observe whether there is a deviation in the reading of the pressure gauge at the outlet of the flow control instrument, and repeatedly adjust the reading of the pressure gauge within the allowable error range;

[0082] (9) After injecting slickwater according to the set time, close the outlet valve of the slickwater. Since the liquid is not easy to seep through the shale core, record the actual injection volume of the slickwater in the flow control instrument;

[0083] 2.1 For shale cores without natural fractures:

[0084] If the obtained shale core does not contain natural fractures, it is necessary to reduce the injection flow rates of CO2 and slickwater, increase the injection time of CO2 and slickwater, and increase the preset pressure during fracturing to achieve the replacement purpose.

[0085] The third step: Measure the amount of oil and gas displaced during the fluid injection process;

[0086] During the fracturing fluid injection process under the simulated formation pressure conditions in the entire second step, synchronously measure the amount of oil and gas displaced during the injection process;

[0087] (1) Open the outlet valve of the gas-liquid storage container, and collect CO2 gas, slickwater, oil, and mud through the gas-liquid storage container;

[0088] (2) Inject the gas-liquid mixture into the gas-liquid drying and separation instrument through the outlet of the gas-liquid storage container;

[0089] (3) Through the gas-liquid drying and separation instrument, separate the dry gas into the flow measurement device, measure the total volume of the separated gas, and collect the mixed liquid into the liquid separation pool;

[0090] (4) Separate the mixed liquid in the liquid separation pool into the crude oil separation pool and the mud sewage pool.

[0091] Step 4: In-situ heating to desorb the adsorbed gas in the core;

[0092] (1) Adjust the temperature control system of the heating instrument to the formation temperature and continuously heat the core at the formation temperature;

[0093] (2) Close the outlet valve of the CO2 gas cylinder, close the outlet valve of the slickwater, adjust the pressure reducing valve so that the reading of the outlet pressure gauge of the pressure-maintaining core heating instrument is within 0.5 MPa, and open the outlet valve of the gas-liquid storage container;

[0094] (3) Record the current time as the 0 time point, continuously measure the volume V3 of the adsorbed gas desorbed by heating, and plot the curve of heating time vs. the cumulative volume of the adsorbed gas desorbed;

[0095] (4) When the increase in V3 is less than 0.5 cm 3 / min, turn off the temperature control system of the heating instrument, stop heating, record the volume of the adsorbed gas at this time, and measure the mass of the crude oil in the crude oil separation tank.

[0096] Step 5: Measure the total content of the displaced oil and gas under formation conditions;

[0097] (1) After the temperature returns to normal temperature of 20 °C, take out the full-diameter pressure-maintaining core in the pressure-maintaining core container;

[0098] (2) Wash the surface with clean water, dry it and weigh the total mass, and measure the radius and height of the full-diameter core;

[0099] (3) Crush the full-diameter core thoroughly and measure the volume of its rock matrix;

[0100] (4) Calculate the oil and gas content displaced per unit mass of the core:

[0101]

[0102] Where: V d - Free gas content in unit mass of rock, m 3 / t; V2 - Total volume of separated gas, m 3 ; V1 - Total volume of injected CO2, m 3 ; m - Total mass of the full-diameter core, t;

[0103]

[0104] Where: V a - Adsorbed gas content in unit mass of rock, m 3 / t; V 31 - Volume of desorbed adsorbed gas, m 3 ; m - Total mass of the full-diameter core, t;

[0105]

[0106] In the formula: V o - Mass of recoverable oil in rock per unit mass, g / t; m o - Mass of separated crude oil, g; m - Total mass of full-diameter core, t;

[0107] (5) Calculate the difference in free gas between experimental conditions and theoretical conditions:

[0108]

[0109] In the formula: △V d - Difference in free gas between experimental conditions and theoretical conditions, m 3 / t; V d - Free gas content in rock per unit mass, m 3 / t; φ - Shale porosity, dimensionless; S g - Gas saturation of shale gas, obtained by downhole logging, dimensionless; r - Radius of full-diameter core, m; l - Height of full-diameter core, m; B g - Gas volume factor, obtained by gas sampling analysis, dimensionless; m - Total mass of full-diameter core, t; V s - Volume of rock matrix, m 3 .

[0110] Example 1

[0111] Taking the shale oil and gas reservoir in the Lianggaoshan Formation of Sichuan as an example, the method for replacing shale oil and gas under pressure maintenance conditions of the present invention is specifically described as follows, including the following steps:

[0112] The first step: Preparation work before the experiment

[0113] (1) Install the device for replacing shale oil and gas under pressure maintenance conditions; check that the pressure reducing valve 11 is in the open state, check that the pressure in the pressure-maintained core container 4-2 is the formation pressure of 33 MPa, check that the outlet valves 9 of the CO2 gas cylinder, 10 of the slickwater outlet, and 16 of the gas-liquid storage container outlet are in the closed state, and connect the instrument pipelines;

[0114] (2) Fix the pressure-maintained core container 4-2 taken out from the wellbore to the heating instrument using the steel wire 4-3;

[0115] The second step: Injection of fracturing fluid under simulated formation pressure conditions

[0116] (1) Open the outlet valve 9 of the CO2 gas cylinder and inject CO2 gas into the fluid pressurizer 7;

[0117] (2) Control the outlet pressure of the fluid pressurizer 7 to be the preset inlet pressure value of 45 MPa during fracturing by adjusting the pressure pump 1;

[0118] (3) Adjust the pressure reducing valve 11 so that the reading of the pressure gauge 12 at the outlet of the pressure maintaining core heating instrument is the preset outlet pressure value of 30 MPa;

[0119] (4) Adjust the flow control instrument 2 to keep the CO2 flow rate at the outlet of the flow control instrument 2 at the set flow rate of 4 cm 3 / s;

[0120] (5) Continuously observe whether there is a deviation in the reading of the pressure gauge 3 at the outlet of the flow control instrument. If the reading of the pressure gauge 3 is less than 44.9 MPa, increase the input pressure of the pressure pump 1; if the reading of the pressure gauge 3 is greater than 45.1 MPa, decrease the input pressure of the pressure pump 1. Adjust repeatedly until the reading of the pressure gauge 3 is 45 ± 0.1 MPa;

[0121] (6) After injecting CO2 gas for 10 minutes according to the set time, record that the total outlet gas volume of CO2 in the flow control instrument 2 is 2374 cm 3 , close the outlet valve 9 of the CO2 gas cylinder, and open the outlet valve 10 of the slickwater;

[0122] (7) Adjust the flow control instrument 2 to keep the slickwater flow rate at the outlet of the flow control instrument 2 at the set flow rate of 6 cm 3 / s;

[0123] (8) Continuously observe whether there is a deviation in the reading of the pressure gauge 3 at the outlet of the flow control instrument. If the reading of the pressure gauge 3 is less than 44.9 MPa, increase the input pressure of the pressure pump 1; if the reading of the pressure gauge 3 is greater than 45.1 MPa, decrease the input pressure of the pressure pump 1. Adjust repeatedly until the reading of the pressure gauge 3 is 45 ± 0.1 MPa;

[0124] (9) After injecting slickwater for 20 minutes according to the set time, close the outlet valve 10 of the slickwater. Since the liquid is not easy to percolate through the shale core, record that the actual injection volume of the slickwater in the flow control instrument 2 is 3815 cm 3 ;

[0125] Preferably, the shale core obtained in this embodiment contains natural fractures. If the obtained shale core does not contain natural fractures, it is necessary to reduce the injection flow rates of CO2 and slickwater, increase the injection time of CO2 and slickwater, and increase the preset pressure during fracturing to achieve the replacement purpose.

[0126] The third step: Measure the amount of oil and gas displaced during the fluid injection process

[0127] During the fracturing fluid injection process under the simulated formation pressure conditions in the entire second step, synchronously measure the amount of oil and gas displaced during the injection process.

[0128] (1) Open the outlet valve 16 of the gas-liquid storage container, and collect CO2 gas, slickwater, oil, and mud through the gas-liquid storage container 15;

[0129] (2) Inject the gas-liquid mixture into the gas-liquid drying and separation instrument 8 through the outlet of the gas-liquid storage container;

[0130] (3) Through the gas-liquid drying and separation instrument 8, separate the dry gas into the flow measurement device 5, and measure the total volume of the separated gas 43211 cm 3 , and collect the mixed liquid into the liquid separation tank 17;

[0131] (4) Separate the mixed liquid in the liquid separation tank 17 into the crude oil separation tank 6 and the mud sewage tank 18.

[0132] Step 4: In-situ heating to desorb the adsorbed gas in the core

[0133] (1) Adjust the temperature control system of the heater 4-1 to the formation temperature of 90 °C, and continuously heat the core at the formation temperature;

[0134] (2) Close the outlet valve 9 of the CO2 gas cylinder, close the outlet valve 10 of the slickwater, adjust the pressure reducing valve 11 so that the reading of the pressure gauge 12 at the outlet of the pressure-maintaining core heater 4 is within 0.5 MPa, and open the outlet valve 16 of the gas-liquid storage container;

[0135] (3) Record this moment as the 0 time point, continuously measure the volume V3 of the desorbed adsorbed gas during heating, and draw a curve of heating time vs. the cumulative desorbed adsorbed gas volume, as Figure 3 shown;

[0136] (4) When the increase in V3 is less than 0.5 cm 3 / min, turn off the temperature control system of the heater, stop heating, record the adsorbed gas volume 27693 cm at this time 3 , and measure the mass of the crude oil in the crude oil separation tank as 35.04 g;

[0137] Step 5: Measure the total content of oil and gas displaced under formation conditions

[0138] (1) After the temperature returns to normal temperature of 20 °C, take out the full-diameter pressure-maintaining core in the pressure-maintaining core container 4-2;

[0139] (2) Wash the surface with clean water, dry it, and weigh the total mass as 15.47 kg. Measure the radius of the full-diameter core as 0.0398 m and the height as 1.2 m;

[0140] (3) Crush the full-diameter core thoroughly and measure the volume of its rock matrix as 0.00569 m 3 ;

[0141] (4) Calculate the oil and gas content displaced per unit mass of the core:

[0142]

[0143] In the formula: V d - Free gas content in unit mass of rock is 2.64, m 3 / t; V2 - Total volume of separated gas is 0.043211, m 3 ; V1 - Total volume of injected CO2 is 0.002374, m 3 ; m - Total mass of the full-diameter core is 0.01547, t.

[0144]

[0145] In the formula: V a - Adsorbed gas content in unit mass of rock is 1.79, m 3 / t; V 31 - Volume of desorbed adsorbed gas is 0.027693, m 3 ; m - Total mass of the full-diameter core is 0.01547, t.

[0146]

[0147] In the formula: V o - Mass of recoverable oil in unit mass of rock is 2265.68, g / t; m o - Mass of separated crude oil is 35.05, g; m - Total mass of the full-diameter core is 0.01547, t.

[0148] (5) Calculate the difference in free gas between experimental conditions and theoretical conditions:

[0149]

[0150] In the formula: △V d - Difference in free gas between experimental conditions and theoretical conditions is 0.069, m 3 / t; V d - Free gas content in unit mass of rock is 2.64, m 3 / t; φ - Shale porosity is 0.04717, dimensionless; S g - Gas saturation of shale gas is 0.48, obtained by downhole logging, dimensionless; π, pi, with a value of 3.14159; r - Radius of the full-diameter core is 0.0398, m; l - Height of the full-diameter core is 1.2, m; B g - Gas volume factor is 0.0034, obtained by gas sampling analysis, dimensionless; m - Total mass of the full-diameter core is 0.01547, t; V s - Volume of the rock matrix is 0.00569, m3 。

[0151] Finally, it should be noted that the above content is only used to illustrate the technical solution of the present invention, rather than a limitation on the protection scope of the present invention. Any simple modification or equivalent replacement made by those of ordinary skill in the art to the technical solution of the present invention shall not depart from the essence and scope of the technical solution of the present invention.

Claims

1. An apparatus for replacing shale oil and gas under pressure maintaining conditions, comprising a gas-liquid storage container (15) and a pressure maintaining core heater (4), characterized in that: A pressure-holding core heating apparatus (4) has a pressure-holding core container (4-2) at its center; the gas-liquid storage container (15) is connected to a gas-liquid drying and separation apparatus (8) through a gas-liquid storage container outlet valve (16); the top of the gas-liquid drying and separation apparatus (8) is connected to a flow measurement device (5), and the bottom is connected to a liquid separation tank (17); the top pipeline of the gas-liquid storage container (15) is connected to the outlet end of the pressure-holding core container (4-2) inside the pressure-holding core heating apparatus (4); the inlet pipeline of the pressure-holding core container (4-2) is sequentially connected to a pressure gauge (3), a flow controller (2), and a fluid pressurizer (7); the fluid pressurizer (7) is also respectively connected to a CO2 gas cylinder (13) through a first branch pipeline and a slippery water tank (14) through a second branch pipeline.

2. The device and method for replacing shale oil and gas under pressure holding conditions according to claim 1, characterized in that: The pressure-holding core container (4-2) holds and fixes the pressure-holding core container through a steel wire (4-3); the pressure-holding core heating apparatus (4) is equipped with a heating apparatus (4-1) with a temperature control system. The heating apparatus (4-1) with a temperature control system, the pressure-holding core container (4-2), and the steel wire (4-3) that holds and fixes the pressure-holding core container together constitute the pressure-holding core heating apparatus (4).

3. The device and method for replacing shale oil and gas under pressure maintaining conditions according to claim 1, characterized in that: A CO2 gas cylinder outlet valve (9) and a slippery water outlet valve (10) are respectively connected to the first branch pipeline and the second branch pipeline.

4. The device and method for replacing shale oil and gas under pressure holding conditions according to claim 1, characterized in that: The fluid pressurizer (7) is connected to a pressure pump (1); the liquid separation tank (17) is respectively connected to a crude oil separation tank (6) and a mud sewage tank (18); a pressure reducing valve (11) and a pressure gauge (12) are connected to the top pipeline of the gas-liquid storage container (15).

5. A method for replacing shale oil and gas under pressure maintaining conditions by using the device according to any one of claims 1 to 4, characterized in that: It includes the following steps: Step 1: Preparation work before the experiment; Step 2: Injection of fracturing fluid under simulated formation pressure conditions; Step 3: Measurement of the amount of oil and gas displaced during the fluid injection process; Step 4: In-situ heating to desorb the adsorbed gas in the core; Step 5: Measurement of the total content of oil and gas displaced under formation conditions.

6. The method according to claim 5, wherein: The preparation work before the experiment in Step 1 includes: (1) Install the device for displacing shale oil and gas under pressure-holding conditions; check that the pressure reducing valve (11) is in the open state, check that the pressure in the pressure-holding core container (4-2) is the formation pressure, check that the CO2 gas cylinder outlet valve (9), the slippery water outlet valve (10), and the gas-liquid storage container outlet valve (16) are in the closed state, and connect the instrument pipelines; (2) Fix the pressure-holding core container (4-2) taken out from the wellbore to the heating apparatus using a steel wire (4-3); observe whether the obtained shale core is a shale core with natural fractures or a shale core without natural fractures.

7. The method according to claim 5, wherein: The method for injecting fracturing fluid under simulated formation pressure conditions in Step 2 includes the following steps: 2.1 For shale cores with natural fractures: (1) Open the CO2 gas cylinder outlet valve (9) and inject CO2 gas into the fluid pressurizer (7); (2) By adjusting the pressure pump (1), control the outlet pressure of the fluid pressurizer (7) to be the preset inlet pressure value during fracturing; (3) Adjust the pressure reducing valve (11) so that the reading of the pressure gauge (12) at the outlet of the pressure-holding core heating apparatus is the preset outlet pressure value; (4) Adjust the flow control instrument (2) to keep the CO2 flow rate at the outlet of the flow control instrument (2) at the set flow rate; (5) Continuously observe whether there is any deviation in the reading of the pressure gauge 3 at the outlet of the flow control instrument, and adjust the reading of the pressure gauge (3) within the allowable error range; (6) After injecting CO2 gas according to the set time, record the total outlet gas volume of CO2 in the flow control instrument (2), close the outlet valve (9) of the CO2 gas cylinder, and open the outlet valve (10) of the slickwater; (7) Adjust the flow control instrument (2) to keep the slickwater flow rate at the outlet of the flow control instrument (2) at the set flow rate; (8) Continuously observe whether there is any deviation in the reading of the pressure gauge (3) at the outlet of the flow control instrument, and adjust the reading of the pressure gauge within the allowable error range; (9) After injecting slickwater according to the set time, close the outlet valve (10) of the slickwater. Since the liquid is not easy to seep through the shale core, record the actual injection volume of the slickwater in the flow control instrument (2); 2.2 For shale cores without natural fractures: If the obtained shale core does not contain natural fractures, it is necessary to reduce the injection flow rates of CO2 and slickwater, increase the injection time of CO2 and slickwater, and increase the preset pressure during fracturing to achieve the replacement purpose.

8. The method according to claim 5, wherein: The specific method for measuring the amount of oil and gas displaced during the injection process of the metered fluid in step 3 includes: During the injection process of the fracturing fluid under the simulated formation pressure conditions in the whole step 2, synchronously measure the amount of oil and gas displaced during the injection process; (1) Open the outlet valve (16) of the gas-liquid storage container, and collect CO2 gas, slickwater, oil, and mud through the gas-liquid storage container (15); (2) Inject the gas-liquid mixture into the gas-liquid drying and separation instrument (8) through the outlet of the gas-liquid storage container; (3) Through the gas-liquid drying and separation instrument (8), separate the dry gas into the flow measurement device (5), measure the total volume of the separated gas, and collect the mixed liquid into the liquid separation tank (17); (4) Separate the mixed liquid in the liquid separation tank (17) into the crude oil separation tank (6) and the mud sewage tank (18).

9. The method according to claim 5, characterized in that: The method for in-situ heating and desorbing the adsorbed gas in the core in step 4 includes the following steps: (1) Adjust the temperature control system of the heater (4-1) to the formation temperature, and continuously heat the core at the formation temperature; (2) Close the outlet valve (9) of the CO2 gas cylinder, close the outlet valve (10) of the slickwater, adjust the pressure reducing valve (11) to make the reading of the pressure gauge (12) at the outlet of the pressure maintaining core heater (4) within 0.5 MPa, and open the outlet valve (16) of the gas-liquid storage container; (3) Record this moment as the 0 time point, continuously measure the volume V3 of the adsorbed gas desorbed by heating, and draw a curve of heating time vs. the cumulative desorbed volume of the adsorbed gas; After the increase in V3 is less than 0.5 cm 3 / min, turn off the temperature control system of the heating instrument, stop heating, record the adsorbed gas volume at this time, and measure the mass of crude oil in the crude oil separation tank.

10. The method according to claim 5, characterized in that: The method for measuring the total content of oil and gas displaced under formation conditions in step 5 includes the following steps: (1) After the temperature returns to normal temperature of 20 °C, take out the full-diameter pressure-maintaining core in the pressure-maintaining core container (4-2); (2) Wash the surface with clean water, dry it, weigh the total mass, and measure the radius and height of the full-diameter core; (3) Crush the full-diameter core thoroughly and measure the volume of its rock matrix; (4) Calculate the oil and gas content displaced from the core per unit mass: where, V d - free gas content in rock per unit mass, m 3 / t; V2 - total volume of separated gas, m 3 ; V1 - total volume of injected CO2, m 3 ; m - total mass of full-diameter core, t; Where, V a - Adsorbed gas content in rock per unit mass, m 3 / t; V 31 - Volume of desorbed adsorbed gas, m 3 ; m - Total mass of full-diameter core, t; where, V o - mass of recoverable oil in per unit mass of rock, g / t; m o - mass of separated crude oil, g; m - total mass of full-diameter core, t; (5) Calculate the free gas difference between the experimental conditions and the theoretical conditions: Where, △V d - Difference in free gas between experimental conditions and theoretical conditions, m 3 / t; V d - Free gas content in unit mass of rock, m 3 / t; φ - Shale porosity, dimensionless; S g - Gas saturation of shale gas, obtained by downhole logging, dimensionless; r - Radius of full-diameter core, m; l - Height of full-diameter core, m; B g - Gas volume factor, obtained by gas sampling analysis, dimensionless; m - Total mass of full-diameter core, t; V s - Volume of rock matrix, m 3 .

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