Shale reservoir fracturing flowback simulation system and method and flowback efficiency evaluation method

Abstract

The present invention belongs to the technical field of shale reservoir development, and specifically relates to a shale reservoir fracturing flowback simulation system and method and a flowback efficiency evaluation method. The system of the present invention includes a core holder, and the core holder is connected to a confining pressure pump, an axial pressure pump, a gas piston container, a liquid piston container, a flowback simulation control and measurement system and a back pressure system; and also includes a CT scanning device. The shale reservoir fracturing flowback simulation method includes core preparation, core evacuation and saturation, core fracturing, well blocking simulation, and flowback simulation. The shale reservoir fracturing flowback efficiency evaluation method includes: recording the total amount of liquid injected from fracturing to well blocking stage; measuring the amount of fracture fluid and the amount of output fluid at different times in the flowback stage; calculating the change in matrix liquid volume by subtracting the change in fracture liquid volume from the output liquid volume; and calculating the total flowback rate, the flowback rate of fracturing fluid in the matrix, and the flowback rate of fracturing fluid in the fracture respectively. The present invention provides a shale reservoir fracturing flowback simulation system and method and a flowback efficiency evaluation method.

Description

Technical Field

[0001] The invention belongs to the technical field of shale reservoir development, and in particular relates to a shale reservoir fracturing flowback simulation system and method and a flowback efficiency evaluation method. Background Art

[0002] Shale gas reservoirs require the help of horizontal well volume fracturing technology to achieve economic and efficient development. During the fracturing process, a large amount of fracturing fluid and proppant are injected into the shale formation. After fracturing, a complex fracture network system of natural fractures, induced fractures and artificial fractures is formed. The gas and water distribution characteristics in shale reservoirs are very complex. It is very important to clarify the gas and water distribution characteristics in matrix fractures during the well blocking and flowback stages and accurately evaluate the flowback efficiency of gas wells for the rational development of shale gas reservoirs.

[0003] Indoor physical experiments are an important means to study the mechanism of gas well blockage and backflow and evaluate the backflow efficiency. However, the existing experimental technology still has the following problems:

[0004] First, only the end face fractures or core cutting fractures can be simulated. The fracture morphology is usually relatively simple, and the influence of the complexity of the fracture network is not considered. In addition, the initiation and expansion process of the fracture during the fracturing process cannot be simulated.

[0005] Second, the original temperature and pressure state of the formation is usually not restored, and the actual underground situation cannot be truly reflected.

[0006] Third, the impact of reservoir heterogeneity on the flowback law of the well is not considered.

[0007] Fourth, it is difficult to accurately obtain the gas-water distribution characteristics at different times during the well blocking and flowback stages.

[0008] Fifth, the fracturing fluid flowback rate is usually used to evaluate the flowback efficiency. This evaluation index is too single and cannot quantitatively evaluate the fracturing fluid flowback rate in the matrix and the liquid flowback rate in the fracture. Summary of the invention

[0009] In order to solve the above-mentioned problems existing in the prior art, the purpose of the present invention is to provide a shale reservoir fracturing and flowback simulation system and method, as well as a flowback efficiency evaluation method, which can reliably simulate the shale reservoir fracturing, well blocking and flowback processes, and obtain the gas-water distribution characteristics in the well blocking and flowback stages.

[0010] The technical solution adopted by the present invention is:

[0011] The shale reservoir fracturing flowback simulation system comprises a core holder for placing cores, the core holder is connected to a confining pressure pump through a pipeline, and one end of the core holder is connected to an axial pressure pump through a pipeline; one end of the core holder is connected to a gas piston container through a pipeline, the gas piston container is connected to a gas pressurization system through a pipeline, and the middle of the core holder is connected to a liquid piston container through a pipeline; the middle of the core holder is also connected to a flowback simulation control and measurement system through a pipeline, and the other end of the core holder is connected to a back pressure system through a pipeline; and also comprises a CT scanning device arranged around the core holder.

[0012] After the gas boosting system boosts the gas, the high-pressure gas enters the gas piston container, and the injection pump injects the high-pressure gas in the gas piston container into the core holder from one end of the core holder. The back pressure system is used to increase a certain back pressure at the end of the core holder away from the injection end, and increase the confining pressure and axial pressure to ensure that the core is fully saturated. When the core is saturated, when the fracturing fluid is injected into the middle of the core holder through the liquid piston container, the high pressure after the liquid is injected into the hole drilled by the core causes the core to be fractured, simulating the real shale reservoir fracturing. During the fracturing process, the CT scanning device monitors the crack expansion law and the change of fracturing fluid saturation in the crack in real time. During the well blocking process, the computer collects the pressure at various locations of the core holder in real time, and uses the CT scanning device to monitor the change of fluid saturation in the crack in real time. The backflow simulation control and measurement system can control the production pressure difference to change, so as to simulate the process of the oil nozzle gradually getting bigger and the oil nozzle gradually getting smaller during the actual backflow process. During the flowback process, the flowmeter and CT scanning device of the flowback simulation control and measurement system are used to monitor the gas and water produced during the flowback process, the gas and water remaining in the core, and the gas and water distribution in real time. In summary, the system of the present invention can reliably simulate the core fracturing stage, the well blocking stage and the flowback stage under the formation temperature and pressure conditions, so as to facilitate the monitoring of the gas and water distribution characteristics in the above process, and also facilitate the evaluation of the flowback efficiency through the gas and water distribution characteristic data.

[0013] As a preferred embodiment of the present invention, the flowback simulation control and measurement system includes a first back pressure valve connected to the middle of the core holder through a pipeline, and the first back pressure valve is connected to a first flow meter and a first back pressure pump through pipelines. In the flowback stage, the control pressure of the first back pressure valve is controlled by the first back pressure pump, thereby changing the pressure difference between the middle and the two ends of the core holder, which is used to simulate the process of the oil nozzle gradually becoming larger and the oil nozzle gradually becoming smaller during the actual flowback process. In this process, the first flow meter is used to monitor the flow change.

[0014] As a preferred embodiment of the present invention, an injection pump is also included, and the output end of the injection pump is connected to one end of the gas piston container away from the core holder and one end of the liquid piston container away from the core holder through pipelines. When injecting gas into the core holder in the evacuation and saturation stage and injecting fracturing fluid into the core holder in the fracturing stage, both are operated by the injection pump, which is convenient for controlling constant pressure.

[0015] As a preferred embodiment of the present invention, the back pressure system includes a second back pressure valve, which is connected to the end of the core holder away from the gas piston container through a pipeline, and the second back pressure valve is respectively connected to a second flow meter and a second back pressure pump through pipelines. In the vacuum saturation stage, a certain back pressure is added to the end of the core holder away from the injection end by the second back pressure pump to ensure that the core is fully saturated. In the vacuum saturation stage, the temperature of the thermostat is first increased to the experimental target formation temperature, and then gas is injected into the core holder. The second flow meter monitors the gas flow at the end of the core holder away from the injection end. When the gas flow no longer changes, the valve there is closed, the gas injection pressure is increased to the target experimental formation pressure, and the gas is continuously injected into the core in a constant pressure manner. When the pressure at both ends of the holder is consistent and no longer changes, the core is saturated and restored to the formation temperature and pressure conditions.

[0016] As a preferred embodiment of the present invention, the gas boosting system includes a gas source, the gas source is connected to a gas boosting pump through a pipeline, the gas boosting pump is connected to a high-pressure storage tank through a pipeline, and the high-pressure storage tank is connected to a gas piston container through a pipeline. The gas boosting pump can pressurize the gas and store it in the high-pressure storage tank. A safety valve is connected to the high-pressure storage tank to avoid excessive pressure in the pipeline. High-pressure gas is injected into the gas piston container through the gas boosting system to ensure that the gas has sufficient pressure when the gas piston container is used to inject gas into the core clamp.

[0017] The shale reservoir fracturing flowback simulation method comprises the following steps:

[0018] S1: Core preparation: Drill a hole at one end of the core and place the core in the core holder.

[0019] S2: Core evacuation and saturation: Vacuum the core from one end of the core holder; apply confining pressure to the middle section of the core holder and axial pressure to one end of the core holder. Apply back pressure and then inject fluid into the core at a constant pressure. When the flow rate at the outlet is stable, the core is saturated. At this time, close the outlet valve, increase the pressure to the formation pressure, and continue to inject fluid into the core holder at a constant pressure. When the pressure at both ends of the core holder is balanced, the formation pressure is restored. The core gas saturation state is simulated by vacuuming the core and then injecting gas to prepare for the fracturing stage.

[0020] S3: Core fracturing: Inject fracturing fluid from the middle of the core holder, and stop injecting fracturing fluid after the core breaks; scan the core fracturing process through CT, and monitor the pressure at both ends of the core holder, the middle pressure, the axial pressure and the confining pressure during the fracturing process. By evacuating and saturating the core in advance, and increasing the confining pressure and axial pressure, the core can reliably simulate the fracturing process when the fracturing fluid is injected from the middle of the core holder during the fracturing process, avoiding the situation where the existing technology can only simulate the end face cracks or core cutting cracks, the crack morphology is usually simple, and the crack initiation and expansion process during the fracturing process cannot be simulated.

[0021] S4: Well blocking stage: Keep the confining pressure and axial pressure unchanged and block the well; monitor the change law of fluid saturation in the matrix and fractures in real time through CT scanning, and monitor the pressure at both ends and the middle pressure of the core holder during the well blocking process. By monitoring the change of fluid saturation in the matrix and fractures during the well blocking stage, the coefficients of the matrix imbibition equation can be fitted, so as to calculate the amount of liquid absorbed into the matrix from the matrix fracture contact surface at the mine scale.

[0022] S5: Flowback stage: flowback is carried out from the middle of the core holder, and the flowback pressure is adjusted during the flowback process; the flowback flow and pressure are monitored during the flowback process, and the produced gas and water volume, the remaining gas and water volume in the core, and the gas and water distribution are monitored in real time. By monitoring the flowback flow and pressure, and monitoring the produced gas and water volume, the remaining gas and water volume in the core, and the gas and water distribution in real time, the gas and water distribution characteristics of the flowback stage can be obtained, and can be used to calculate the flowback efficiency.

[0023] As a preferred solution of the present invention, in step S3, before injecting the fracturing fluid into the core holder, the fracturing fluid is first injected into the pipeline in front of the valve in the middle of the core holder, and the valve is opened after the fracturing fluid pressure in the pipeline is equal to the initial equilibrium pressure in the core holder. Injecting the fracturing fluid into the core holder after the fracturing fluid pressure in the pipeline is equal to the initial equilibrium pressure in the core holder can simulate the actual fracturing situation and avoid the situation where the core cannot be fractured due to too low pressure during injection.

[0024] The method for evaluating the efficiency of shale reservoir fracturing flowback includes the following steps:

[0025] T1: record the total amount of fluid injected from fracturing to well shut-down ;

[0026] T2: Real-time measurement of the liquid volume in the fracture during the well blocking stage by CT scanning device , , and then calculate the amount of liquid absorbed into the matrix at different times during the well blocking stage:

[0027]

[0028] T3: Measuring the amount of liquid in the fracture at different times during the flowback phase The amount of liquid produced during different time periods during the flowback phase , ;

[0029] T4: Calculate the amount of liquid in the matrix at different times during the flowback phase:

[0030] ;

[0031] T5: Calculate the total flowback rate: , ;

[0032] The flowback rate of fracturing fluid in the matrix is: , ;

[0033] The flowback rate of fracturing fluid in the fracture is: , .

[0034] The present invention can respectively calculate the total flowback efficiency, the flowback rate of the fracturing fluid in the matrix and the flowback rate of the fracturing fluid in the fracture at any time during the flowback stage, and comprehensively evaluate the flowback effect.

[0035] As a preferred embodiment of the present invention, the following steps are also included:

[0036] Y1: Experimental measurement at the core scale After the relationship, according to , the fitting coefficients are and ;in, is the crack area;

[0037] Y2: and Substituting into the matrix imbibition equation, the amount of liquid absorbed into the matrix from the matrix fracture interface at the mine scale can be obtained: .

[0038] The present invention also measures the amount of liquid in the cracks during the well blocking stage in real time, and calculates the amount of liquid infiltrated into the matrix at different times during the well blocking stage, thereby fitting the matrix infiltration equation and obtaining the matrix infiltration equation coefficient, which facilitates the calculation of the amount of liquid infiltrated into the matrix by the matrix crack contact surface at the mine field scale.

[0039] The beneficial effects of the present invention are:

[0040] 1. After the gas boosting system of the present invention boosts the gas, the high-pressure gas enters the gas piston container, and the high-pressure gas enters the gas piston container to saturate the core. When the core is saturated, when the fracturing fluid is injected into the middle of the core holder through the liquid piston container, the core is fractured to simulate the real shale reservoir fracturing situation. During the fracturing process, the CT scanning device monitors the crack expansion law and the change law of the fracturing fluid saturation in the crack in real time. During the well blocking process, the computer collects the pressure at various locations of the core holder in real time. The backflow simulation control and measurement system can control the production pressure difference to change, so as to simulate the process of the oil nozzle gradually becoming larger and the oil nozzle gradually becoming smaller during the actual backflow process. In summary, the system of the present invention can reliably simulate the core fracturing stage, the well blocking stage and the backflow stage under the formation temperature and pressure conditions, so as to facilitate the monitoring of the gas-water distribution characteristics in the above process, and also facilitate the backflow efficiency evaluation through the gas-water distribution characteristic data.

[0041] 2. The fracturing flowback simulation method of the present invention simulates the core fracturing stage, the well-clogging stage and the flowback stage under the formation temperature and pressure conditions. The core gas saturation state is simulated by vacuuming the core and then injecting gas to prepare for the fracturing stage. By evacuating the core to saturation in advance and increasing the confining pressure and axial pressure, the core can reliably simulate the fracturing process when the fracturing fluid is injected from the middle of the core holder during the fracturing process, avoiding the situation that the existing technology can only simulate the end face cracks or core cutting cracks, the crack morphology is usually simple, and the crack initiation and expansion process during the fracturing process cannot be simulated. By monitoring the changes in the fluid saturation in the matrix and cracks during the well-clogging stage, the coefficients of the matrix infiltration equation can be fitted, so that the amount of liquid infiltrated into the matrix by the matrix fracture contact surface at the mine scale can be calculated. The gas or liquid output in the flowback stage is monitored by a flow meter, and the gas or liquid volume and gas-water distribution of the core fractures are scanned by a CT device, so that the gas-water distribution characteristics of the flowback stage can be obtained, and can be used to calculate the flowback efficiency.

[0042] 3. The present invention monitors the output liquid volume and the liquid volume in the core fractures during the flowback stage, and deducts the liquid volume in the fractures from the output liquid volume to obtain the liquid volume in the core matrix at any time during the flowback stage. Similarly, the present invention can calculate the gas volume in the core matrix at any time during the flowback stage. Then, by respectively calculating the total flowback efficiency, the flowback rate of the fracturing fluid in the matrix, and the flowback rate of the fracturing fluid in the fractures at any time during the flowback stage, the flowback effect is comprehensively evaluated. The present invention also measures the liquid volume in the fractures during the well-clogging stage in real time, and calculates the liquid volume infiltrated into the matrix at different times during the well-clogging stage, thereby fitting the matrix infiltration equation and obtaining the matrix infiltration equation coefficient, which is convenient for calculating the liquid volume infiltrated into the matrix by the matrix fracture contact surface at the mine field scale. BRIEF DESCRIPTION OF THE DRAWINGS

[0043] Figure 1 It is a structural schematic diagram of the present invention.

[0044] In the figure, 1-core holder; 2-confining pressure pump; 3-axial pressure pump; 4-gas piston container; 5-gas booster system; 6-liquid piston container; 7-flowback simulation control and measurement system; 8-back pressure system; 9-CT scanning device; 41-injection pump; 51-gas source; 52-gas booster pump; 53-high pressure storage tank; 71-first back pressure valve; 72-first flow meter; 73-first back pressure pump; 81-second back pressure valve; 82-second flow meter; 8 3-second back pressure pump; a1-first valve; a2-second valve; a3-third valve; a4-fourth valve; a5-fifth valve; a6-sixth valve; a7-seventh valve; a8-eighth valve; a9-ninth valve; a10-tenth valve; a11-eleventh valve; a12-twelfth valve; a13-thirteenth valve; a14-fourteenth valve; a15-fifteenth valve; a16-sixteenth valve; a21-safety valve. DETAILED DESCRIPTION

[0045] Embodiments of the present invention are described in detail below, examples of which are shown in the accompanying drawings, wherein the same or similar reference numerals throughout represent the same or similar elements or elements having the same or similar functions. The embodiments described below with reference to the accompanying drawings are exemplary and are intended to be used to explain the present invention, and should not be construed as limiting the present invention.

[0046] like Figure 1 As shown, the shale reservoir fracturing backflow simulation system of this embodiment includes a core holder 1 for placing a core, the middle section of the core holder 1 is connected to a confining pressure pump 2 through a pipeline, and one end of the core holder 1 is connected to an axial pressure pump 3 through a pipeline; one end of the core holder 1 is connected to a gas piston container 4 through a pipeline, and a gas booster system 5 is connected to the gas piston container 4 through a pipeline, and the middle part of the core holder 1 is connected to a liquid piston container 6 through a pipeline; the middle part of the core holder 1 is also connected to a backflow simulation control and measurement system 7 through a pipeline, and the other end of the core holder 1 is connected to a back pressure system 8 through a pipeline; and also includes a CT scanning device 9 arranged around the core holder 1. The core holder 1 is placed in a constant temperature system to simulate the formation temperature.

[0047] After the gas boosting system 5 boosts the gas pressure, the gas piston container 4 injects the high-pressure gas from one end of the core holder 1. The back pressure system 8 is used to increase a certain back pressure at the end of the core holder 1 away from the injection end, and increase the confining pressure and axial pressure to ensure that the core is fully saturated. When the core is saturated, when the fracturing fluid is injected into the middle of the core holder 1 through the liquid piston container 6, the core is fractured to simulate the actual shale reservoir fracturing. During the fracturing process, the CT scanning device 9 monitors the crack expansion law and the saturation change law of the fracturing fluid in the crack in real time. During the well blocking process, the computer collects the pressure at various locations of the core holder 1 in real time, and uses the CT scanning device 9 to monitor the saturation change law of the matrix and the fluid in the crack in real time. The backflow simulation control and measurement system 7 can control the production pressure difference to change, so as to simulate the process of the oil nozzle gradually becoming larger and the oil nozzle gradually becoming smaller during the actual backflow process. During the flowback process, the flow meter and CT scanning device 9 of the flowback simulation control and measurement system 7 are used to monitor in real time the amount of gas and water produced during the flowback process, as well as the amount of gas and water remaining in the core and the gas-water distribution. In summary, the system of the present invention can reliably simulate the core fracturing stage, the well blocking stage and the flowback stage under the formation temperature and pressure conditions, so as to facilitate the monitoring of the gas-water distribution characteristics in the above process and the evaluation of the flowback efficiency through the gas-water distribution characteristic data.

[0048] The flowback simulation control and measurement system 7 includes a first back pressure valve 71 connected to the middle of the core holder 1 through a pipeline, and the first back pressure valve 71 is connected to a first flow meter 72 and a first back pressure pump 73 through pipelines. In the flowback stage, the control pressure of the first back pressure valve 71 is controlled by the first back pressure pump 73, thereby changing the pressure difference between the middle and the two ends of the core holder 1, which is used to simulate the process of the oil nozzle gradually becoming larger and the oil nozzle gradually becoming smaller during the actual flowback process. In this process, the first flow meter 72 is used to monitor the flow change.

[0049] The present invention further comprises an injection pump 41, the output end of which is connected to one end of the gas piston container 4 away from the core holder and one end of the liquid piston container 6 away from the core holder through pipelines. When injecting gas into the core holder in the evacuation and saturation stage and injecting fracturing fluid into the core holder 1 in the fracturing stage, both are operated by the injection pump 41, which facilitates the control of constant pressure.

[0050] The back pressure system 8 includes a second back pressure valve 81, which is connected to the end of the core holder 1 away from the gas piston container 4 through a pipeline, and the second back pressure valve 81 is respectively connected to a second flow meter 82 and a second back pressure pump 83 through pipelines. In the vacuum saturation stage, a certain back pressure is added to the end of the core holder 1 away from the injection end through the second back pressure pump 83, so that the gas can fully enter the core to ensure that the core is fully saturated. In the vacuum saturation stage, the second flow meter 82 monitors the gas flow at the end of the core holder 1 away from the injection end. When the gas flow no longer changes, the valve there is closed to ensure that the core is fully saturated.

[0051] The gas boosting system 5 includes a gas source 51, the gas source 51 is connected to a gas boosting pump 52 through a pipeline, the gas boosting pump 52 is connected to a high-pressure storage tank 53 through a pipeline, and the high-pressure storage tank 53 is connected to the gas piston container 4 through a pipeline. The gas boosting pump 52 can boost the gas and store it in the high-pressure storage tank 53. The high-pressure storage tank 53 is connected to a safety valve a21 to prevent excessive pressure in the pipeline. High-pressure gas is injected into the gas piston container 4 through the gas boosting system 5 to ensure that the gas has sufficient pressure when the gas piston container 4 is used to inject gas into the core clamp 1.

[0052] The experimental rock sample consists of two full-diameter shale cores with a core size of 100mm (D)*150mm (L). Holes with a diameter of 89mm and a length of 30mm are drilled at the center of the cross section of the two cores (simulating the perforation state under real formation conditions). For oil-bearing cores, the experimental cores must be cleaned first, placed in a heating oven for drying, and then the two cores are placed oppositely in the core holder 1 (the holes are aligned).

[0053] A first valve a1 is provided on the pipeline at the gas injection end of the core holder 1, a second valve a2 is provided on the pipeline between the second flow meter 82 and the second back pressure valve 81, a third valve a3 is provided on the pipeline between the gas piston container 4 and the core holder 1, a fourth valve a4 and a fifth valve a5 are provided in sequence on the pipeline between the liquid piston container 6 and the middle of the core holder 1, a sixth valve a6 is provided on the pipeline between the first flow meter 72 and the first back pressure valve 71, a seventh valve a7 is provided on the pipeline between the gas source 51 and the gas booster pump 52, and an eighth valve a8 and a ninth valve a9 are provided in sequence on the pipeline between the gas booster pump 52 and the high pressure storage tank 53. A safety valve a21 and a tenth valve a10 are also provided on the pipeline between the high-pressure storage tank 53 and the gas piston container 4, an eleventh valve a11 is provided on the pipeline between the injection pump 41 and the gas piston container 4, a twelfth valve a12 is provided on the pipeline between the injection pump 41 and the liquid piston valve, a thirteenth valve a13 is provided on the pipeline between the first back-pressure pump 73 and the first back-pressure valve 71, a fourteenth valve a14 is provided on the pipeline between the axial pressure pump 3 and the core clamp 1, a fifteenth valve a15 is provided on the pipeline between the confining pressure pump 2 and the core clamp 1, and a sixteenth valve a16 is provided on the pipeline between the second back-pressure pump 83 and the second back-pressure valve 81.

[0054] Electronic pressure gauges are installed on the pipes at both ends of the core clamp 1, the pipe between the axial pressure pump 3 and the core clamp 1, the pipe between the confining pressure pump 2 and the core clamp 1, the pipe between the liquid piston container 6 and the core clamp, the pipe between the first back pressure valve 71 and the core clamp, the pipe between the gas piston container 4 and the high pressure storage tank 53, the pipe between the gas booster pump 52 and the high pressure storage tank 53, and the pipe between the gas source 51 and the gas booster pump 52. The electronic pressure gauge is electrically connected to the computer. The first flow meter 72 and the second flow meter 82 are both electrically connected to the computer. The first flow meter 72 and the second flow meter 82 both include a gas flow measurement unit and a liquid flow measurement unit.

[0055] The shale reservoir fracturing flowback simulation method comprises the following steps:

[0056] S1: Core preparation:

[0057] Select two cores of the same length (the first core and the second core), and drill a hole at the center of the cross section of the first core and the second core respectively (simulating the perforation state under real formation conditions). The hole diameter and length can be adjusted according to the diameter and length of the core. For example, when the core size is 100mm in diameter × 150mm in length (the core size is designed according to needs, and the specific value can be unlimited), the hole diameter is 89mm and the length is 30mm (the size is designed according to needs, and it is not necessary to limit a fixed value). For oil-bearing cores such as shale oil and tight oil, the experimental cores need to be washed with oil first.

[0058] S2: Core evacuation and saturation:

[0059] 1) Placing the core into the core holder 1: Place the first core and the second core into the core holder 1 facing each other and keep the holes aligned.

[0060] 2) Vacuuming: close the fifth valve a5, the sixth valve a6, and the second valve a2, and evacuate the inside of the core holder 1 through the first valve a1. After the evacuation is completed, close the first valve a1.

[0061] 3) Fill the intermediate gas container with high-pressure gas: open the seventh valve a7, the eighth valve a8, the ninth valve a9 and the safety valve a21 (all valves of the gas boosting system 5), open the tenth valve a10 on the intermediate container containing gas and ensure that the third valve a3 is closed. It should be noted that all valves under the intermediate container, including valve 11 and valve 12, are in the open state. Inject high-pressure gas into the gas piston container 4 through the gas boosting system 5, stop injecting when the pressure reaches the design pressure, and then close the tenth valve a10.

[0062] 4) Core saturation: Add a certain back pressure (not limited to a fixed value, designed according to experimental needs) at the C end through the second back pressure pump 83. Load the confining pressure that matches the overlying formation pressure, and load the axial pressure that matches the horizontal stress of the formation. Open the third valve a3, the first valve a1, and the second valve a2 (the fourth valve a4 and the fifth valve a5 are closed at this time). Use the injection pump 41 to inject the gas in the gas piston container 4 into the core holder 1 from the B end in a constant pressure injection mode. When the gas flow at the C end does not change, close the second valve a2, and then increase the displacement pressure to the experimental simulated formation pressure to inject gas into the core holder 1 in a constant pressure mode. When the pressure displayed on the right side of valve a1 is equal to the pressure balance on the left side of valve a2, close the first valve a1, the second valve a2, and the third valve a3, and record the injected gas volume and the pressure displayed on the electronic pressure gauge at this time.

[0063] S3: Core fracturing stage:

[0064] Open the fourth valve a4, keep the fifth valve a5 closed, and inject the fracturing fluid into the pipeline in front of the fifth valve a5 through the gas piston container 4. After the fracturing fluid pressure in the pipeline is equal to the initial equilibrium pressure in the core clamp 1, open the fifth valve a5, and inject the fracturing fluid into the core system from end A at the experimentally designed pumping pressure. After the pressure reaches the peak and the core breaks, close the fifth valve a5 and stop pumping the fracturing fluid. During the whole process, the computer collects the pressure changes at various locations in real time. Use the CT scanning device 9 to monitor the crack expansion law and the saturation change law of the fracturing fluid in the crack in real time during the cracking process.

[0065] S4: Stifling well stage:

[0066] After the fracturing is completed, the confining pressure and axial pressure are kept unchanged, and the on-site well blocking process is simulated. The well blocking experiment is designed according to the experimental needs. By simulating different well blocking times, the depth of fracturing fluid infiltration into the matrix, gas-liquid distribution characteristics, etc. under different well blocking time conditions are studied, so as to clarify the reasonable well blocking time. During the well blocking process, the computer collects the pressure data of the A, B, and C ends in real time, and uses the CT scanning device 9 to monitor the change law of the fluid saturation in the matrix and the fracture in real time.

[0067] S5: Flowback stage:

[0068] After the well is blocked, flowback is carried out from end A. During the flowback process, the production pressure difference (pressure difference between BA / CA, B and C represent the remote formation) is controlled to gradually increase and decrease to simulate the process of the oil nozzle gradually increasing and decreasing during the flowback process. During the flowback process, the flow meter and CT scanning device 9 are used to monitor the produced gas and water volume, the remaining gas and water volume in the core, and the gas-water distribution in real time during the flowback process.

[0069] During the experiment, two cores with different physical properties can be selected to study the changes in fracture initiation and fluid saturation in the first and second cores during fracturing, well blocking and flowback, and determine the impact of reservoir heterogeneity on fracturing, well blocking and flowback. However, only CT scanning can be used to monitor the changes in fluids in the matrix and fractures. Considering the accuracy of CT scanning, the changes in fluids in fractures are accurate, and the absolute value of the changes in fluids in the matrix may not be accurate, but the relative changes can be compared.

[0070] By applying different axial pressures (horizontal formation stress), the conductivity of the fractures formed by fracturing will be different, so that the influence of horizontal stress on fracturing, well blocking and flowback processes can be studied.

[0071] In addition to fracturing and creating fractures in cores, this device can also directly simulate well shut-down and flowback on matrix cores and cores with artificial regular and complex fractures, that is, directly saturating the cores with gas to the original formation conditions and then starting fracturing, well shut-down and flowback. In addition, for unconventional reservoirs of shale oil and tight oil, the saturated fluid is changed from gas to simulated oil, and no gas booster system is required5.

[0072] Data processing method:

[0073] 1) Gas output evaluation:

[0074] The outlet flow meter is used to monitor the gas production under different flowback pressure differences, well blocking time, and seam network complexity in real time.

[0075] ① Saturation stage: The total amount of gas injected into the core is (Under standard conditions), it can be obtained by the difference in the amount of pumped gas before and after saturation.

[0076] ②Flowback stage:

[0077] Real-time monitoring of output gas through the outlet flow meter The change of the gas output ratio at different times is:

[0078] .

[0079] 2) Evaluation of flowback efficiency:

[0080] The CT scanning device 9 has a higher accuracy in identifying fluid changes in fractures, and uses online CT non-destructive testing to monitor the gas and liquid distribution status and saturation change law in core fractures in real time. For the matrix, considering that the micron CT scanning accuracy is relatively low, the fluid saturation in the matrix and its change law are calculated using an indirect method. The mass of the produced liquid in the backflow stage is obtained by weighing the balance. The backflow efficiency calculation method is as follows:

[0081] ① Fracturing stage: Since the matrix permeability is extremely low and the fracturing process is shorter than the wellbore process, it can be assumed that the liquid is in the fractures. The total amount of liquid injected from fracturing to the initial wellbore is .

[0082] ② Well blocking stage :

[0083] Real-time monitoring of fluid volume in fractures using CT scanning , :

[0084]

[0085] The amount of fluid absorbed into the matrix for:

[0086] ;

[0087] According to the literature [1], and Satisfies the following relationship: ;in is the crack area, and is the fitting coefficient.

[0088] [1] Makhanov K, Habibi A, Dehghanpour H, et al. Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods afterfracturing operations[J]. Journal of Unconventional Oil&Gas Resources, 2014,7:22-32.

[0089] The experimental results show that the core scale After fitting the relationship, the fitting coefficient can be obtained and ,Will and Substituting into the matrix imbibition equation, the amount of liquid absorbed into the matrix from the matrix fracture interface at the mine scale can be obtained: .

[0090] ;

[0091] in, is the number of cracks, For half the length of the crack, is the reservoir thickness.

[0092] At core scale:

[0093] ;

[0094] Taking the logarithm of both sides gives:

[0095] ;

[0096] At the mine scale:

[0097] .

[0098] The experimental results show that the core scale After fitting the relationship, the fitting coefficient can be obtained and ,Will and Substituting into the mine-scale equation, the amount of liquid absorbed into the matrix from the matrix fracture contact surface at the mine-scale can be obtained: .

[0099] ③ Flowback stage ( ,in , that is, the flowback phase begins after the wellbore phase ends)

[0100] Gas output:

[0101] The gas volume produced at different times can be obtained through the gas flow meter at the outlet , .

[0102] Return fluid volume:

[0103] The amount of flowback produced is weighed using a balance:

[0104]

[0105] According to the law of conservation of mass, the mass of produced fluid = the mass change of liquid in the matrix + the mass change of liquid in the fracture. Considering that the density of fracturing fluid does not change much at different temperatures, it is assumed that the density of fracturing fluid is a constant, and we can get:

[0106] ;

[0107] in, , It can be obtained through testing during the experiment.

[0108] The above formula can be transformed into:

[0109] .

[0110] According to the above formula, we can get The relationship between the volume of matrix water and time during the flowback stage .

[0111] The total return rate is: , .

[0112] The flowback rate of fracturing fluid in the matrix is: , .

[0113] The flowback rate of fracturing fluid in the fracture is: , .

[0114] and, .

[0115] The present invention monitors the amount of liquid produced during the flowback stage and the amount of liquid in the core fractures, and calculates the amount of liquid change in the matrix between two adjacent moments by subtracting the amount of liquid change in the fractures from the amount of liquid produced between the previous moment and the present moment, and obtains the amount of liquid in the matrix at the present moment by adding the amount of liquid in the matrix at the previous moment to the amount of liquid change in the matrix. Similarly, the present invention can calculate the amount of gas in the core matrix at any moment during the flowback stage. The total flowback efficiency, the flowback rate of the fracturing fluid in the matrix, and the flowback rate of the fracturing fluid in the fractures are calculated at any moment during the flowback stage to comprehensively evaluate the flowback effect. The amount of liquid infiltrated into the matrix at different moments during the well-clogging stage is calculated, and the matrix imbibition equation is fitted to obtain the matrix imbibition equation coefficient, which is convenient for calculating the amount of liquid infiltrated into the matrix by the matrix fracture contact surface at the mine field scale.

[0116] The present invention is not limited to the above-mentioned optional implementation modes. Anyone can derive other various forms of products under the inspiration of the present invention. However, no matter what changes are made in the shape or structure, all technical solutions that fall within the scope defined by the claims of the present invention fall within the protection scope of the present invention.

Claims

1. A shale reservoir fracturing flowback simulation method, characterized in that: The steps include: S1: Core preparation: select a first core and a second core of the same length, drill a hole at the center of the cross section of each of the first core and the second core, and place the cores in a core holder (1); S2: core evacuation and saturation: the first core and the second core are placed opposite to each other in the core holder (1), and the holes are kept aligned; the cores are evacuated from one end of the core holder (1); confining pressure is applied to the middle section of the core holder, axial pressure is applied to one end of the core holder (1), and gas is injected from one end of the core holder (1) to the pressure balance at both ends of the core holder (1) by constant pressure injection; S3: Core fracturing: inject fracturing fluid from the middle of the core holder (1), and stop injecting fracturing fluid after the core is fractured; scan the core fracturing process by CT to monitor the pressure at both ends of the core holder, the middle pressure, the axial pressure and the confining pressure during the fracturing process; S4: Well blocking stage: Keep the confining pressure and axial pressure unchanged and block the well; monitor the changes in fluid saturation in the matrix and fractures in real time through CT scanning, and monitor the pressure at both ends and the middle of the core holder during the well blocking process; S5: Flowback stage: Flowback is performed from the core holder (1), and the flowback pressure or flowback pressure difference is adjusted during the flowback process; the flowback flow rate and pressure are monitored during the flowback process, and the produced gas and water volume, the remaining gas and water volume in the core, and the gas-water distribution are monitored in real time.

2. The shale reservoir fracturing flowback simulation method according to claim 1, characterized in that: In step S2, before injecting gas from one end of the core holder (1), a certain back pressure is first increased at the other end of the core holder (1); when injecting gas from one end of the core holder (1), the valve at the other end of the core holder (1) is closed when the flow rate at the other end of the core holder (1) does not change.

3. The shale reservoir fracturing flowback simulation method according to claim 1, characterized in that: In step S3, before injecting the fracturing fluid into the core holder (1), the fracturing fluid is first injected into the pipeline in front of the valve in the middle of the core holder (1), and the valve is opened after the pressure of the fracturing fluid in the pipeline is equal to the initial equilibrium pressure in the core holder (1).

4. A shale reservoir fracturing flowback simulation system, used for the shale reservoir fracturing flowback simulation method according to claim 1, characterized in that: The invention comprises a core holder (1) for placing a core, wherein the middle section of the core holder (1) is connected to a confining pressure pump (2) via a pipeline, and one end of the core holder (1) is connected to an axial pressure pump (3) via a pipeline; one end of the core holder (1) is connected to a gas piston container (4) via a pipeline, and the gas piston container (4) is connected to a gas pressurizing system (5) via a pipeline; the middle section of the core holder (1) is connected to a liquid piston container (6) via a pipeline; the middle section of the core holder (1) is also connected to a flowback simulation control and measurement system (7) via a pipeline, and the other end of the core holder (1) is connected to a back pressure system (8) via a pipeline; and also comprises a CT scanning device (9) arranged around the core holder (1).

5. The shale reservoir fracturing flowback simulation system according to claim 4, characterized in that: The flowback simulation control and measurement system (7) comprises a first back pressure valve (71) connected to the middle of the core holder (1) via a pipeline, and the first back pressure valve (71) is connected to a first flow meter (72) and a first back pressure pump (73) via pipelines.

6. The shale reservoir fracturing flowback simulation system according to claim 4, characterized in that: It also includes an injection pump (41), the output end of which is connected to one end of the gas piston container (4) away from the core holder and one end of the liquid piston container (6) away from the core holder through pipelines.

7. The shale reservoir fracturing flowback simulation system according to claim 4, characterized in that: The back pressure system (8) comprises a second back pressure valve (81), the second back pressure valve (81) being connected to an end of the core holder (1) away from the gas piston container (4) via a pipeline, and the second back pressure valve (81) being connected to a second flow meter (82) and a second back pressure pump (83) via pipelines.

8. The shale reservoir fracturing flowback simulation system according to claim 4, characterized in that: The gas boosting system (5) comprises a gas source (51), the gas source (51) being connected to a gas boosting pump (52) via a pipeline, the gas boosting pump (52) being connected to a high-pressure storage tank (53) via a pipeline, and the high-pressure storage tank (53) being connected to a gas piston container (4) via a pipeline.

9. The method for evaluating shale reservoir fracturing flowback efficiency according to claim 1, characterized in that: The steps include: T1: record the total amount of fluid injected before fracturing starts ; T2: Real-time measurement of the amount of liquid in the fracture during the wellbore stage using a CT scanning device (9) , , and then calculate the amount of liquid absorbed into the matrix at different times during the well blocking stage: ； T3: Measuring the amount of liquid in the fracture at different times during the flowback phase The amount of liquid produced during different time periods during the flowback phase , ; T4: Calculate the amount of liquid in the matrix at different times during the flowback phase: ； T5: Calculate the total flowback rate: , ; The flowback rate of fracturing fluid in the matrix is: , ; The flowback rate of fracturing fluid in the fracture is: , ; The following steps are also included: Y1: The amount of fluid absorbed by the matrix at the core scale calculated during the well-clogging experiment With time After the relationship, according to , the fitting coefficients are and ;in, is the crack area; Y2: and Substituting into the matrix imbibition equation, the amount of liquid absorbed into the matrix from the matrix fracture interface at the mine scale can be obtained: .

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