System and method for evaluating fluid occurrence and fracturing fluid water block damage in tight gas reservoirs

Abstract

The application discloses a tight gas reservoir fluid occurrence and fracturing fluid water lock damage evaluation system and method, wherein the tight gas reservoir fluid occurrence and fracturing fluid water lock damage evaluation method comprises the following steps: taking out a core sample from a tight gas reservoir; through a series of treatments on the core sample and by using a nuclear magnetic resonance T1-T2 spectrum technology, a fluid occurrence chart capable of distinguishing different fluid types in the core is established; fracturing fluid is injected into the core sample to simulate water lock damage, then gas displacement is carried out under different injection pressure differences, and nuclear magnetic resonance T1-T2 spectrum is analyzed based on the fluid occurrence chart, so that the residence state of the fracturing fluid is qualitatively evaluated. The water lock damage evaluation method based on the nuclear magnetic resonance T2 and T1-T2 technologies can realize accurate quantification of the degree of water lock damage by analyzing the distribution and migration characteristics of the fluid in the reservoir core sample, and provides a theoretical basis and experimental means for formulating a plugging removal measure.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of fracturing flowback technology in oil and gas field development, and particularly relates to a system and method for evaluating fluid occurrence and fracturing fluid water block damage in a tight gas reservoir. BACKGROUND

[0002] Due to its low permeability and complex pore structure, the tight gas reservoir often adopts hydraulic fracturing technology to increase the permeability of the reservoir and the gas production in the development process. In the development process of the tight gas reservoir, the hydraulic fracturing technology is a key means to improve the percolation capacity of the gas reservoir and increase the gas production. However, the injection of the fracturing fluid may cause water block damage, that is, the fracturing fluid remains in the reservoir, hinders the flow of the gas, and thus reduces the production capacity of the gas reservoir. The water block damage is a major problem in the development of the tight gas reservoir. In the prior art, how to accurately identify and quantify the water block damage and optimize the fracturing fluid formula and the injection process has become a research focus to improve the production efficiency of the gas reservoir.

[0003] Currently, there are still the following problems in the evaluation method of water lock damage of fracturing fluid: first, the existing method is mostly to measure the change of gas permeability before and after the invasion of fracturing fluid to indirectly calculate the water lock damage rate. This method can only reflect the macro damage result, and cannot reveal the specific retention position of fracturing fluid in the pore, the phase distribution and the interaction between fracturing fluid and formation water. Therefore, the micro mechanism of water lock damage is not well understood. For example, patent publication CN114594033A discloses a method for evaluating water sensitivity, water lock and solid phase damage of oil and gas reservoir. It quantitatively evaluates the water lock damage of fracturing fluid by measuring the gas permeability. For example, patent publication CN110566174A discloses a water lock damage physical simulation method and device. It simulates the fracturing fluid invasion and flowback process for coalbed methane water lock damage. It calculates the damage rate based on the change of gas permeability. Second, the existing technology has poor fluid identification ability. Even if nuclear magnetic resonance technology is introduced, the existing method is mostly limited to using one-dimensional T2 spectrum for pore structure analysis or fluid total amount calculation. For example, patent publication CN117269224B discloses an evaluation method and system for water lock damage of gas layer. It obtains the first water lock damage rate and the second water lock damage rate through nuclear magnetic resonance T2 spectrum, and comprehensively calculates the final water lock damage rate. However, one-dimensional T2 spectrum cannot effectively distinguish the inherent formation water in the core from the invading fracturing fluid, because the T2 relaxation time intervals overlap, resulting in insufficient accuracy and pertinence of water lock damage evaluation. Third, the existing physical simulation device or method can simulate some link of fracturing fluid invasion and flowback, but cannot truly reflect the dynamic evolution law of water lock damage with the flowback process, and cannot provide accurate guidance for optimizing the flowback system. For example, patent publication CN218496648U discloses a fracturing fluid damage simulation device and evaluation system. It simulates the actual damage of fracturing fluid to the formation core by changing the dynamic parameters including fracturing fluid temperature and fracturing fluid flow rate. It focuses on simulating the physical damage of fracturing fluid to the core. For example, patent publication CN110566174A discloses a water lock damage physical simulation method and device. It can simulate the invasion and flowback process for coalbed methane water lock damage, but does not involve the identification of fracturing fluid retention state and the dynamic simulation of multi-pressure difference flowback.

[0004] Therefore, there is an urgent need in the art for an experimental evaluation system and method that can qualitatively identify and accurately quantify the retention of fracturing fluid from a microscale, and can simulate the dynamic evolution process, to deeply reveal the mechanism of water lock damage, and to provide a scientific basis for efficient development of tight gas reservoirs. SUMMARY

[0005] This application provides a system and method for evaluating the fluid occurrence and fracturing fluid water-locking damage in tight gas reservoirs. This solves the problem that the existing technology uses gas phase permeability to evaluate water-locking damage, resulting in insufficient comprehensive evaluation capability for water-locking damage. Furthermore, the existing technology fails to utilize nuclear magnetic resonance technology to perform high-precision analysis of the fine occurrence state of reservoir fluids, thus making it impossible to comprehensively analyze the multi-scale effects of fracturing fluid intrusion and water-locking damage.

[0006] In a first aspect, embodiments of the present invention provide a tight gas reservoir fluid occurrence and fracturing fluid water lock damage assessment system, including a displacement subsystem and a nuclear magnetic resonance (NMR) testing subsystem; the displacement subsystem includes a core holder, a forward displacement device, and a reverse displacement device; the forward displacement device includes a gas storage tank and a first intermediate container; the reverse displacement device includes a second intermediate container; a core sample is placed in the core holder; the output end of the gas storage tank is connected to the gas input end of the core holder via a first pipeline; the output end of the first intermediate container is connected to the first pipeline, and the first intermediate container is configured to supply gas to the core holder... The gas in a pipeline is pressurized; the output of the second intermediate container is connected to the liquid input of the core holder via a second pipeline; the second intermediate container contains fracturing fluid filtrate and is configured to deliver the fracturing fluid filtrate to the core sample; the core holder is heated; the core holder is provided with confining pressure simulating reservoir pressure, and the back pressure at the first output of the core holder is adjusted; the first output of the core holder is connected to a first graduated cylinder; the nuclear magnetic resonance testing subsystem is configured to perform nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests on the core sample.

[0007] In conjunction with the first aspect, one possible implementation also includes a core drying oven and a vacuum pressurization saturation device; the core sample can be dried in the core drying oven; the vacuum pressurization saturation device is configured to evacuate the core sample and pressurize and saturate the core sample to simulate formation water.

[0008] With reference to the first aspect, in a possible implementation manner, the displacement subsystem further includes a temperature controller, a first heating protective sleeve, a confining pressure pump, a back pressure pump, a back pressure valve, and a second measuring cylinder; the first heating protective sleeve is sleeved outside the core holder; a signal output end of the temperature controller is connected with the first heating protective sleeve through a third pipeline, and the first heating protective sleeve is configured to heat the core holder under control of the temperature controller; the confining pressure pump is connected with a confining pressure input end of the core holder through a fourth pipeline, and the confining pressure pump is configured to provide confining pressure to the core holder to simulate reservoir pressure; the back pressure pump is connected with a second output end of the core holder through a fifth pipeline; the fifth pipeline is provided with the back pressure valve, an output end of the back pressure valve is connected with the second measuring cylinder, and the back pressure pump is configured to adjust back pressure of the core holder.

[0009] With reference to the first aspect, in a possible implementation manner, the forward displacement device further includes a first working liquid, a first constant flow pump, and a second heating protective sleeve; the first working liquid is connected with the first intermediate container through a sixth pipeline; the sixth pipeline is provided with the first constant flow pump, the first working liquid is delivered to one side of the first intermediate container through the first constant flow pump, and the first working liquid delivered to the one side of the first intermediate container can increase gas pressure of another side of the first intermediate container; the second heating protective sleeve is sleeved outside the first intermediate container; a signal output end of the temperature controller is connected with the second heating protective sleeve through a seventh pipeline, and the second heating protective sleeve is configured to heat the first intermediate container under control of the temperature controller.

[0010] With reference to the first aspect, in a possible implementation manner, the reverse displacement device includes a second working liquid, a second constant flow pump, and a third heating protective sleeve; the second working liquid is connected with the second intermediate container through an eighth pipeline; the eighth pipeline is provided with the second constant flow pump, the second working liquid is delivered to one side of the second intermediate container through the second constant flow pump, the other side of the second intermediate container is provided with the fracturing fluid filtrate, and the second working liquid delivered to the one side of the second intermediate container can deliver the fracturing fluid filtrate to the core sample; the third heating protective sleeve is sleeved outside the second intermediate container; a signal output end of the temperature controller is connected with the third heating protective sleeve through a ninth pipeline, and the third heating protective sleeve is configured to heat the second intermediate container under control of the temperature controller.

[0011] With reference to the first aspect, in a possible implementation manner, the forward displacement device further comprises a first valve and a first pressure gauge; the reverse displacement device further comprises a second valve and a second pressure gauge; the first valve is arranged on the first pipeline and located between the first intermediate container and the core holder; the first pressure gauge is arranged on the first valve; the second valve is arranged on the second pipeline; and the second pressure gauge is arranged on the second valve.

[0012] With reference to the second aspect, an embodiment of the present application provides a method for evaluating fluid occurrence and fracturing fluid water block damage in a tight gas reservoir, which comprises the following steps:

[0013] S1: core sample preparation: taking a core sample from the tight gas reservoir;

[0014] S2: fluid occurrence chart establishment: through a series of treatments on the core sample and by using the nuclear magnetic resonance T1-T2 spectrum technology, a fluid occurrence chart capable of distinguishing different fluid types in the core is established;

[0015] The fluid occurrence chart establishment comprises:

[0016] S21: performing nuclear magnetic resonance T2 and T1-T2 tests on the core sample in a dry state to obtain background signals; S22: performing nuclear magnetic resonance T2 and T1-T2 tests on the core sample after being saturated with simulated formation water; S23: performing nuclear magnetic resonance T2 and T1-T2 tests on the core sample after establishing a bound water state; S24: comprehensively comparing and analyzing the nuclear magnetic resonance T2 and T1-T2 spectra in different states, and demarcating the distribution areas of different fluids on the T1-T2 spectrum chart, so as to establish the fluid occurrence chart;

[0017] S3: fracturing fluid water block damage evaluation: injecting a fracturing fluid into the core sample to simulate water block damage, then performing gas displacement under different injection pressure differentials, and based on the fluid occurrence chart, analyzing the nuclear magnetic resonance T1-T2 spectrum to qualitatively evaluate the retention state of the fracturing fluid, and based on the quantitative change of the nuclear magnetic resonance T2 spectrum, calculating the degree of water block damage.

[0018] With reference to the second aspect, in a possible implementation manner, the fracturing fluid water block damage evaluation comprises:

[0019] S31: initial water block state establishment: under simulated formation temperature, injecting fracturing fluid filtrate reversely from the outlet end of the core sample and standing, then performing gas displacement from the injection end of the core sample, establishing an initial fracturing fluid water block state, and performing nuclear magnetic resonance T2 and T1-T2 tests;

[0020] S32: flowback simulation: set different injection pressure differentials, perform forward gas displacement on the core sample in the initial water lock state from the injection end of the core sample, simulate the flowback process, and perform nuclear magnetic resonance T2 and T1-T2 tests on the core sample under each pressure differential.

[0021] In combination with the second aspect, in a possible implementation manner, the water lock damage degree is calculated by the following formula:

[0022]

[0023] In the formula, η represents the water lock degree under different injection pressure differentials, %; A0 is the area enclosed by the nuclear magnetic resonance T2 spectrum and the X axis under the initial fracturing fluid water lock state; B i is the area enclosed by the nuclear magnetic resonance T2 spectrum and the X axis under different injection pressure differentials.

[0024] The one or more technical solutions provided in the embodiments of the present application have at least the following technical effects:

[0025] The embodiments of the present application provide a tight gas reservoir fluid occurrence and fracturing fluid water lock damage evaluation system and method, which includes a fluid occurrence evaluation system and a fracturing fluid water lock damage evaluation system, wherein the fluid occurrence evaluation system includes a core drying oven, a vacuum pressurized saturation device, a forward displacement device, and a nuclear magnetic resonance test subsystem; the fracturing fluid water lock damage evaluation system uses a displacement subsystem and a nuclear magnetic resonance test subsystem. By introducing the nuclear magnetic resonance T1-T2 two-dimensional spectrum technology, a fluid occurrence chart capable of clearly distinguishing different fluids such as fracturing fluid, bound water, and movable formation water is established, thereby realizing intuitive and qualitative identification of the retention position of the fracturing fluid, and fundamentally solving the fluid distinguishing problem. Moreover, based on the signal area change of the nuclear magnetic resonance T2 spectrum, the present application proposes quantitative calculation of the water lock damage degree. The method directly relates to the retention amount of the fracturing fluid, avoids the indirectness of macroscopic permeability measurement, and reduces the error, thereby making the evaluation result more accurate. Furthermore, the system and method of the present application completely cover the whole process from core preparation and establishment of fluid occurrence characteristics to fracturing fluid invasion and fracturing fluid retention, and to flowback simulation under different injection pressure differentials. It can evaluate the effect of different flowback pressure differentials on the removal of water lock damage, thereby providing direct and dynamic data support for optimizing the fracturing fluid formula and flowback system on site. The present application proposes an analysis logic of "establishing a fluid occurrence chart first, and then diagnosing damage", effectively eliminates the interference of the original formation fluid, and thereby realizes accurate quantification of the net damage caused by the fracturing fluid. In addition, the system integrates forward and reverse displacement functions, completely simulates the whole process from fracturing fluid invasion to flowback on site, and provides direct data support for optimizing the flowback system in combination with different injection pressure differential experiments.

[0026] The application solves the problem of insufficient comprehensive evaluation of water block damage in the prior art by evaluating water block damage through gas phase permeability, and the prior art fails to use nuclear magnetic resonance technology to analyze the fine occurrence state of reservoir fluid with high precision, so as to comprehensively analyze the multi-scale effect of fracturing fluid invasion and water block damage. The water block damage evaluation method based on nuclear magnetic resonance T2 and T1-T2 technology can analyze the distribution and migration characteristics of fluid in the reservoir core sample, provide accurate water block damage quantification results, and provide a theoretical basis and experimental means for the development of low-damage fracturing fluid and the formulation of targeted plugging removal measures. BRIEF DESCRIPTION OF DRAWINGS

[0027] In order to more clearly illustrate the technical solutions of the embodiments of the application, the drawings needed in the description of the embodiments of the application will be briefly introduced as follows. Obviously, the drawings in the following description are some embodiments of the application, and other drawings can also be obtained by those skilled in the art without creative labor on the basis of these drawings.

[0028] Figure 1 The system diagram of the tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation system provided by the embodiments of the application is shown in the figure.

[0029] Figure 2 The schematic diagram of the nuclear magnetic resonance testing device provided by the embodiments of the application is shown in the figure.

[0030] Figure 3 The schematic diagram of the core drying oven provided by the embodiments of the application is shown in the figure.

[0031] Figure 4 The schematic diagram of the vacuum pressurized saturation device provided by the embodiments of the application is shown in the figure.

[0032] Figure 5 The T2 spectrum and cumulative curve diagram of the core sample in different states provided by the embodiments of the application is shown in the figure.

[0033] Figure 6 The 2D NMR T1-T2 fluid distribution diagram provided by the embodiments of the application is shown in the figure.

[0034] Figure 7 The 2D NMR T1-T2 fluid occurrence chart provided by the embodiments of the application is shown in the figure.

[0035] Figure 8 The core fracturing fluid retention T1-T2 spectrum diagram under different injection pressure differentials provided by the embodiments of the application is shown in the figure.

[0036] Figure 9 The core fracturing fluid retention T2 spectrum diagram under different injection pressure differentials provided by the embodiments of the application is shown in the figure.

[0037] Figure 10 The flow chart of the method for evaluating the fluid hosting and water blockage damage of the tight gas reservoir provided in the embodiments of the present application is shown in FIG. 1.

[0038] Figure 11 The flow chart of the method for establishing the fluid hosting chart provided in the embodiments of the present application is shown in FIG. 2.

[0039] Figure 12 The flow chart of the method for evaluating the water blockage damage of the fracturing fluid provided in the embodiments of the present application is shown in FIG. 3.

[0040] Icon: 1-core holder; 2-forward displacement device; 21-gas storage tank; 22-first intermediate container; 23-first working liquid; 24-first constant flow pump; 25-second heating protection sleeve; 26-first valve; 27-first pressure gauge; 3-reverse displacement device; 31-second intermediate container; 32-second working liquid; 33-second constant flow pump; 34-third heating protection sleeve; 35-second valve; 36-second pressure gauge; 4-first pipeline; 5-second pipeline; 6-first measuring cylinder; 7-temperature controller; 8-first heating protection sleeve; 9-surrounding pressure pump; 10-back pressure pump; 11-second measuring cylinder; 12-third pipeline; 13-fourth pipeline; 14-fifth pipeline; 15-sixth pipeline; 16-seventh pipeline; 17-eighth pipeline; 18-ninth pipeline; 19-temperature control switch; 191-third pressure gauge; 192-fourth pressure gauge; 193-nuclear magnetic resonance testing device; 194-low temperature unit; 195-control module; 196-back pressure valve; 197-core drying oven; 198-vacuum pressurized saturation device. DETAILED DESCRIPTION

[0041] The technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application. Obviously, the described embodiments are only part of the embodiments of the present application, rather than all the embodiments of the present application. Based on the embodiments in the present application, all the other embodiments obtained by those skilled in the art without creative work fall within the scope of protection of the present application.

[0042] In the description of the embodiments of this application, it should be noted that the terms "center," "upper," "lower," "left," "right," "vertical," "horizontal," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing the embodiments of this application and for simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this application. The terms "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance. Furthermore, the terms "installed," "connected," and "linked" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in the embodiments of this application according to the specific circumstances.

[0043] This application can completely simulate the state of fracturing fluid intrusion and retention during field operations, and then simulate the complete process of backflow under different production pressure differentials.

[0044] This invention provides a system for evaluating the fluid presence and water-locking damage of tight gas reservoirs and fracturing fluids, such as... Figures 1-4 As shown, it includes a displacement subsystem and a nuclear magnetic resonance (NMR) testing subsystem; the displacement subsystem includes a core holder 1, a forward displacement device 2, and a reverse displacement device 3; the forward displacement device 2 includes a gas storage tank 21 and a first intermediate container 22; the reverse displacement device 3 includes a second intermediate container 31; the core sample is placed in the core holder 1; the output end of the gas storage tank 21 is connected to the gas input end of the core holder 1 through a first pipeline 4; the output end of the first intermediate container 22 is connected to the first pipeline 4, and the first intermediate container 22 is configured to apply pressure to the gas in the first pipeline 4; the second intermediate container 22 is connected to the first pipeline 4. The output end of the second intermediate container 31 is connected to the liquid input end of the core holder 1 via the second pipeline 5; the second intermediate container 31 is filled with fracturing fluid filtrate and is configured to deliver the fracturing fluid filtrate to the core sample; the core holder 1 is heated; confining pressure is provided to the core holder 1 to simulate reservoir pressure, and the back pressure at the first output end of the core holder 1 is adjusted; the first output end of the core holder 1 is connected to the first measuring cylinder 6; the nuclear magnetic resonance testing subsystem is configured to perform nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests on the core sample.

[0045] For example, the fracturing fluid water lock damage assessment system uses a displacement subsystem and a nuclear magnetic resonance testing subsystem.

[0046] For example, the purpose of providing confining pressure for the core holder 1 is to simulate the pressure of surrounding rock at a depth of several kilometers underground, so as to restore the true physical state of the core.

[0047] For example, the purpose of adjusting the back pressure of the first output end of the core holder 1 is to accurately control the pressure at the outlet end of the core, so as to simulate the production pressure difference required when oil and gas flows from the formation to the wellbore, and to ensure that the fluid remains liquid at the outlet end.

[0048] In the embodiment of the present application, as shown in Figures 1-4 The core drying oven 197 and the vacuum pressurized saturation device 198 are further included; the core sample can be dried in the core drying oven 197; the vacuum pressurized saturation device 198 is configured to vacuumize the core sample and pressurize and saturate the core sample to simulate formation water.

[0049] For example, the fluid occurrence evaluation system uses the core drying oven 197, the vacuum pressurized saturation device 198, the forward displacement device 2 and the nuclear magnetic resonance test subsystem.

[0050] In the embodiment of the present application, as shown in Figures 1-4 The displacement subsystem further includes a temperature controller 7, a first heating protective sleeve 8, a confining pressure pump 9, a back pressure pump 10, a back pressure valve 196 and a second measuring cylinder 11; the first heating protective sleeve 8 is sleeved on the outside of the core holder 1; the signal output end of the temperature controller 7 is connected with the first heating protective sleeve 8 through a third pipeline 12, and the first heating protective sleeve 8 heats the core holder 1 under the control of the temperature controller 7; the confining pressure pump 9 is connected with the confining pressure input end of the core holder 1 through a fourth pipeline 13, and the confining pressure pump 9 is configured to provide confining pressure for the core holder 1 to simulate reservoir pressure; the back pressure pump 10 is connected with the second output end of the core holder 1 through a fifth pipeline 14; the back pressure valve 196 is arranged on the fifth pipeline 14, the output end of the back pressure valve 196 is connected with the second measuring cylinder 11, and the back pressure pump 10 is configured to adjust the back pressure of the core holder 1.

[0051] In the embodiment of the present application, as shown in Figures 1-4 The forward displacement device 2 further includes a first working liquid 23, a first constant flow pump 24 and a second heating protective sleeve 25; the first working liquid 23 is connected with the first intermediate container 22 through a sixth pipeline 15; the first constant flow pump 24 is arranged on the sixth pipeline 15, the first working liquid 23 is delivered to one side of the first intermediate container 22 through the first constant flow pump 24, and the first working liquid 23 delivered to one side of the first intermediate container 22 can increase the gas pressure on the other side of the first intermediate container 22; the second heating protective sleeve 25 is sleeved on the outside of the first intermediate container 22; the signal output end of the temperature controller 7 is connected with the second heating protective sleeve 25 through a seventh pipeline 16, and the second heating protective sleeve 25 heats the first intermediate container 22 under the control of the temperature controller 7.

[0052] In the embodiment of the present application, as shown in Figures 1-4 The reverse displacement device 3 comprises a second working liquid 32, a second constant flow pump 33 and a third heating protective sleeve 34. The second working liquid 32 is connected with the second intermediate container 31 through the eighth pipeline 17. The second constant flow pump 33 is arranged on the eighth pipeline 17, and the second working liquid 32 is delivered to one side of the second intermediate container 31 through the second constant flow pump 33. The other side of the second intermediate container 31 is provided with a fracturing fluid filtrate, and the second working liquid 32 delivered to one side of the second intermediate container 31 can deliver the fracturing fluid filtrate to the core sample. The third heating protective sleeve 34 is arranged outside the second intermediate container 31. The signal output end of the temperature controller 7 is connected with the third heating protective sleeve 34 through the ninth pipeline 18, and the third heating protective sleeve 34 heats the second intermediate container 31 through the temperature controller 7.

[0053] In the embodiment of the present application, as shown in Figures 1-4 The forward displacement device 2 further comprises a first valve 26 and a first pressure gauge 27. The first valve 26 is arranged on the first pipeline 4 and located between the first intermediate container 22 and the core holder 1. The first pressure gauge 27 is arranged on the first valve 26.

[0054] In the embodiment of the present application, as shown in Figures 1-4 The reverse displacement device 3 further comprises a second valve 35 and a second pressure gauge 36. The second valve 35 is arranged on the second pipeline 5. The second pressure gauge 36 is arranged on the second valve 35.

[0055] Exemplarily, the first constant flow pump 24 and the second constant flow pump 33 are both 2PB constant flow pumps.

[0056] Exemplarily, the first valve 26 and the second valve 35 are both six-way valves.

[0057] Exemplarily, the gas tank 21 provides nitrogen, and the nitrogen is pre-charged into one side chamber of the first intermediate container 22. The first working liquid 23 is pushed by the constant flow pump, so that the nitrogen in the first intermediate container 22 is stably pressurized. The stably pressurized nitrogen enters the core holder 1 through the six-way valve. In the experimental process, the core sample is placed in the core holder 1, and the core sample can be subjected to gas displacement test through the forward displacement device 2, so as to establish a bound water state or simulate a flowback process. The forward displacement device 2 can provide displacement gas with stable and accurately controllable pressure and flow rate, so as to ensure the repeatability and accuracy of the experiment.

[0058] Exemplarily, the prepared fracturing fluid filtrate is added to one side chamber of the second intermediate container 31. The second constant flow pump 33 pushes the second working fluid 32, so as to steadily inject the fracturing fluid filtrate into the core sample from the liquid input end of the core holder 1 to simulate the process of the fracturing fluid invading the reservoir in the wellbore, realizing the reverse, stable and low-speed injection of the fracturing fluid into the core sample, so as to accurately simulate the fracturing fluid invasion process under the formation condition, and then simulate the flowback process through the forward displacement device 2. The displacement subsystem can completely simulate the complete process of the fracturing fluid invading the fracturing fluid retention and then the flowback effect under different production pressure differentials in the field operation.

[0059] In the embodiment of the present application, as shown in Figures 1-4 The displacement subsystem further comprises a temperature control switch 19, a third pressure gauge 191 and a fourth pressure gauge 192. The temperature control switch 19 is arranged on the third pipeline 12, the seventh pipeline 16 and the ninth pipeline 18. The third pressure gauge 191 is arranged on the confining pressure input end of the core holder 1. The fourth pressure gauge 192 is arranged on the fifth pipeline 14 and between the back pressure pump 10 and the back pressure valve 196.

[0060] Exemplarily, the first heating protection sleeve 8, the second heating protection sleeve 25 and the third heating protection sleeve 34 are flexible heating protection sleeves.

[0061] Exemplarily, the flexible heating protection sleeves outside the first intermediate container 22, the second intermediate container 31 and the core holder 1 are connected with the temperature controller 7. The experimental fluid can be heated to the simulated formation temperature through the temperature controller 7, so that the experimental condition is closer to the reality.

[0062] In the embodiment of the present application, as shown in Figures 1-4 The nuclear magnetic resonance testing subsystem comprises a nuclear magnetic resonance testing device 193, a low-temperature unit 194 and a control module 195. The input end of the nuclear magnetic resonance testing device 193 is connected with the low-temperature unit 194. The signal output end of the nuclear magnetic resonance testing device 193 is connected with the control module 195. The low-temperature unit 194 is configured to reduce the temperature of the magnet.

[0063] Exemplarily, the control module 195 is a computer. The computer can record the data generated by the nuclear magnetic resonance testing device 193 and generate a data file.

[0064] The embodiment of the present application provides a compact gas reservoir fluid occurrence and fracturing fluid water lock damage evaluation method, and adopts a compact gas reservoir fluid occurrence and fracturing fluid water lock damage evaluation system, as shown in Figures 1-12 The method comprises the following steps:

[0065] S1: core sample preparation: taking a core sample from a compact gas reservoir;

[0066] S2: Fluid occurrence chart establishment: By a series of treatments on the core sample and by using the nuclear magnetic resonance T1-T2 spectrum technology, a fluid occurrence chart capable of distinguishing different fluid types in the core is established;

[0067] S3: Fracturing fluid water block damage evaluation: The fracturing fluid is injected into the core sample to simulate the water block damage, then the gas displacement is performed under different injection pressure differentials, and the nuclear magnetic resonance T1-T2 spectrum is analyzed based on the fluid occurrence chart to qualitatively evaluate the retention state of the fracturing fluid, and meanwhile, the water block damage degree is calculated based on the quantitative change of the nuclear magnetic resonance T2 spectrum.

[0068] For example, when the core sample preparation is performed, the sample is first cleaned, the diameter and length of the core sample are measured, and the core sample is dried and saturated to simulate the actual reservoir conditions in the reservoir.

[0069] In the embodiments of the present application, as shown in Figures 1-9 The fluid occurrence chart establishment includes:

[0070] S21: The nuclear magnetic resonance T2 and T1-T2 tests are performed on the core sample in the dry state to obtain the background signal;

[0071] S22: The nuclear magnetic resonance T2 and T1-T2 tests are performed on the core sample after being saturated with the simulated formation water;

[0072] S23: The nuclear magnetic resonance T2 and T1-T2 tests are performed on the core sample after the bound water state is established;

[0073] S24: The nuclear magnetic resonance T2 and T1-T2 spectra in different states are comprehensively analyzed and compared, the distribution regions of different fluids on the T1-T2 spectrum chart are demarcated, and thus the fluid occurrence chart is established.

[0074] For example, in step S21, the core sample is first placed in the core drying oven 197, the temperature is set to 100℃, and the core sample is dried for 24h, and then the nuclear magnetic resonance T2 and T1-T2 tests are performed on the dried core sample.

[0075] For example, in step S22, the simulated formation water is first configured, then the vacuum pressurized saturation device 198 is used to vacuumize the core sample, and the core sample is pressurized and saturated to simulate the formation water for 24h, after the saturation is completed, the water on the surface of the core is wiped, and the nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests are performed;

[0076] For example, the method for establishing the bound water state is that N2 is used to displace the core sample saturated with the simulated formation water until no liquid is produced from the first output end of the core holder 1.

[0077] In the embodiments of the present application, as shown in Figures 1-9The water lock damage evaluation of the fracturing fluid includes:

[0078] S31: Initial water lock state establishment: inject fracturing fluid filtrate from the outlet end of the core sample in reverse at simulated formation temperature, and then perform gas displacement from the injection end of the core sample to establish an initial fracturing fluid water lock state, and perform nuclear magnetic resonance T2 and T1-T2 tests;

[0079] S32: Flowback simulation: set different injection pressure differentials, perform forward gas displacement from the injection end of the core sample in the initial water lock state to simulate the flowback process, and perform nuclear magnetic resonance T2 and T1-T2 tests on the core sample under each pressure differential.

[0080] Illustratively, the system can establish a series of accurate and stable injection pressure differentials at both ends of the core sample by cooperatively adjusting the injection pressure of the first intermediate container 22 and the back pressure of the core holder 1, thereby simulating the flowback process under different production systems in the field.

[0081] Illustratively, in step S31: at simulated formation temperature, the fracturing fluid filtrate is injected from the outlet end, 10 PV of fracturing fluid filtrate is filled for 12 hours, N2 is used for gas displacement from the injection end to the first output end of the core holder 1 without liquid production, an initial fracturing fluid water lock state is established, and nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests are performed.

[0082] Illustratively, in step S32: different injection pressure and back pressure differentials are set, N2 is forwardly gas-displaced until there is no liquid production at the first output end of the core holder 1, and nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests are performed under different injection pressure differentials.

[0083] Illustratively, it further includes step S33: qualitative and quantitative evaluation of the fracturing fluid retention state and the degree of water lock damage based on the nuclear magnetic resonance T2 and T1-T2 spectrum.

[0084] Illustratively, the nuclear magnetic resonance T1-T2 test uses an SR-CPMG sequence.

[0085] Illustratively, in steps S1 and S2, the instrument used is a PQ001 type desktop nuclear magnetic resonance instrument, the magnetic field strength is 0.28±0.03T, the pulse frequency is 1MHz to 30MHz, the control accuracy is 0.1Hz, the probe diameter is 25mm, and it is suitable for core samples with a length greater than 25mm.

[0086] Exemplarily, the nuclear magnetic resonance T2 test is a CPMG sequence, and the T1-T2 test is an SR-CPMG sequence, and the detailed parameters in the experiment are as follows: the nuclear magnetic resonance T2 test is a CPMG sequence, the waiting time is 2500 ms, the echo time is 0.10 ms, the number of echoes is 5000, the peak shift is 0.008 ms, and the number of accumulations is 64.

[0087] Exemplarily, the nuclear magnetic resonance T1-T2 test is an SR-CPMG sequence, the waiting time is 10.00 ms, the echo time is 0.15 ms, the number of echoes is 5000, the peak shift is 0.004 ms, the number of inversion times is 25, and the number of accumulations is 32.

[0088] In the embodiment of the application, as shown in Figures 1-12 The water lock damage degree is calculated by the following formula:

[0089]

[0090] In the formula, η represents the water lock degree under different injection pressure differences, %; A0 is the area between the nuclear magnetic resonance T2 spectrum and the X axis under the initial fracturing fluid water lock state; B i is the area between the nuclear magnetic resonance T2 spectrum and the X axis under different injection pressure differences.

[0091] In the embodiment of the application, as shown in Figures 1-12 The fracturing fluid is fracturing fluid filtrate treated by gel breaking.

[0092] The core sample used in the embodiment is taken from a block of the Sulige gas field, the target layer of which is a Shan gas reservoir, and the specific process of using the evaluation system and method for fluid occurrence and fracturing fluid water lock damage of the tight gas reservoir is as follows:

[0093] S1: Core sample preparation

[0094] The core sample is taken out from the tight gas reservoir, the sample is cleaned, the diameter and length of the core sample are measured, and the core sample is dried and saturated to simulate the actual reservoir conditions in the reservoir.

[0095] S2: Fluid occurrence chart establishment

[0096] S21: Place the core in the core drying oven 197, set the temperature to 100 DEG C and dry for 24 h; perform nuclear magnetic resonance T2 and T1-T2 tests on the dried core sample;

[0097] S22: Configure simulated formation water, use the vacuum pressurized saturation device 198 to vacuum the core sample, and pressurize and saturate the core sample to simulate the formation water for 24 h, wipe off the water on the surface of the core after saturation, and perform nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests;

[0098] S23: drive with N2 gas until no liquid production at the first output end of the core holder 1, weigh to calculate the core irreducible water saturation, establish the core irreducible water state, and perform nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests;

[0099] S24: establish a tight gas reservoir fluid occurrence chart based on the scanning results of nuclear magnetic resonance T2 and T1-T2 spectrum.

[0100] S3: Fracturing fluid water block damage evaluation

[0101] S31: inject fracturing fluid filtrate from the outlet end at simulated formation temperature, charge 10 PV of fracturing fluid filtrate for 12 hours, gas drive with N2 from the injection end of the core sample to the outlet end until no liquid production, establish the initial fracturing fluid water block state, and perform nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests;

[0102] S32: set different injection pressure and back pressure differentials, drive with N2 in the positive direction until no liquid production at the outlet end, and perform nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests under different injection pressure differentials;

[0103] S33: qualitatively and quantitatively evaluate the fracturing fluid retention state and the degree of water block damage based on nuclear magnetic resonance T2 and T1-T2 spectrum.

[0104] (1) As shown in the T2 spectrum of the core sample in different states obtained according to steps S1 and S2, wherein the core sample is in a dry state, a saturated state, and an irreducible state, the T2 spectrum and the cumulative curve are plotted, the different hydrogen signal demarcation limits are determined, the fluid distribution is divided in the T1-T2 spectrum, and thus the fluid occurrence chart of this type of reservoir is established. Figures 5-9 The different hydrogen signal demarcation limits are shown in the following table:

[0105]

[0106]

[0107] (2) Based on the fluid occurrence chart, qualitatively analyze the fracturing fluid retention based on the T1-T2 spectrum, quantitatively evaluate the fracturing fluid water block damage according to the nuclear magnetic resonance T2 spectrum, and the calculation formula is:

[0108]

[0109] In the formula, η represents the degree of water block under different injection pressure differentials, %; A0 is the area enclosed by the nuclear magnetic resonance T2 spectrum and the X axis under the initial fracturing fluid water block state; B i is the area enclosed by the nuclear magnetic resonance T2 spectrum and the X axis under different injection pressure differentials.

[0110] ​The water lock damage degree under different injection pressure differentials is calculated as shown in the following table:

[0111]

[0112] The present application provides a system and method for evaluating fluid occurrence in tight gas reservoirs and water lock damage caused by fracturing fluid. By measuring and analyzing the nuclear magnetic resonance T1-T2 spectrum, the system and method can accurately evaluate the fluid occurrence in tight gas reservoirs and the water lock damage caused by fracturing fluid retention, thereby quantifying the influence of water lock damage on the fluid mobility of gas reservoirs. The method is suitable for tight gas reservoirs with complex pore structure and low permeability, and can help optimize the fracturing fluid formulation, thereby reducing water lock damage and improving the production efficiency of gas reservoirs.

[0113] The various embodiments in the specification are described in a progressive manner, and the same or similar parts between the various embodiments can be referred to each other, and each embodiment mainly describes the difference from other embodiments.

[0114] The above examples are only used to illustrate the technical solutions of the present application, and are not limited to the present application; although the present application has been described in detail with reference to the foregoing examples, those skilled in the art should understand that the technical solutions recorded in the foregoing examples can still be modified, or some or all of the technical features can be replaced by equivalents; and these modifications or replacements do not make the essence of the corresponding technical solutions deviate from the scope of the technical solutions of the present application.

Claims

1. A method for evaluating water blockage damage of a compact gas reservoir fluid hosting and fracturing fluid, characterized in that, The system comprises a displacement subsystem and a nuclear magnetic resonance testing subsystem; The displacement subsystem comprises a core holder (1), a forward displacement device (2) and a reverse displacement device (3); The forward displacement device (2) comprises a gas storage tank (21) and a first intermediate container (22); The reverse displacement device (3) comprises a second intermediate container (31); The core sample is placed in the core holder (1); The output end of the gas storage tank (21) is connected to the gas input end of the core holder (1) through a first pipeline (4); The output end of the first intermediate container (22) is connected to the first pipeline (4), and the first intermediate container (22) is configured to apply pressure to the gas in the first pipeline (4); The output end of the second intermediate container (31) is connected to the liquid input end of the core holder (1) through a second pipeline (5); The second intermediate container (31) is provided with fracturing fluid filtrate, and the second intermediate container (31) is configured to deliver the fracturing fluid filtrate to the core sample; The core holder (1) is heated; The core holder (1) is provided with confining pressure to simulate reservoir pressure, and back pressure of the first output end of the core holder (1) is adjusted; The first output end of the core holder (1) is connected with a first measuring cylinder (6); The nuclear magnetic resonance testing subsystem is configured to perform nuclear magnetic resonance T2 and T1-T2 spectrum scanning tests on the core sample; The evaluation method comprises the following steps: S1: Core sample preparation: taking a core sample from a tight gas reservoir; S2: Fluid occurrence chart establishment: establishing a fluid occurrence chart capable of distinguishing different fluid types in the core sample by a series of treatments on the core sample and using nuclear magnetic resonance T1-T2 spectrum technology; The fluid occurrence chart establishment comprises: S21: performing nuclear magnetic resonance T2 and T1-T2 tests on the core sample in a dry state to obtain background signals; S22: performing nuclear magnetic resonance T2 and T1-T2 tests on the core sample after being saturated with simulated formation water; S23: performing nuclear magnetic resonance T2 and T1-T2 tests on the core sample after establishing a bound water state; S24: comprehensively comparing and analyzing the nuclear magnetic resonance T2 and T1-T2 spectra in different states, demarcating the distribution areas of different fluids on the T1-T2 spectrum chart, and thus establishing the fluid occurrence chart; S3: Fracturing fluid water block damage evaluation: injecting fracturing fluid into the core sample to simulate water block damage, then performing gas displacement under different injection pressure differentials, and analyzing the nuclear magnetic resonance T1-T2 spectrum based on the fluid occurrence chart to qualitatively evaluate the retention state of the fracturing fluid, and simultaneously calculating the degree of water block damage based on the quantitative change of the nuclear magnetic resonance T2 spectrum.

2. The method of tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation of claim 1, wherein, The fracturing fluid water block damage evaluation comprises: S31: Initial water lock state establishment: reverse injection of fracturing fluid filtrate from the outlet end of the core sample at simulated formation temperature and standing, then gas displacement from the injection end of the core sample to establish the initial water lock state, and nuclear magnetic resonance T2 and T1-T2 tests are performed; S32: Flowback simulation: set different injection pressure differences, and perform forward gas displacement from the injection end of the core sample in the initial water lock state to simulate the flowback process, and perform nuclear magnetic resonance T2 and T1-T2 tests on the core sample under each pressure difference.

3. The method of tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation of claim 1, wherein, The degree of water lock damage is calculated by the following formula: In the formula, η represents the degree of water block under different injection pressure differences; A0 represents the area between the nuclear magnetic resonance T2 spectrum and the X axis under the initial fracturing fluid water block state; B i represents the area between the nuclear magnetic resonance T2 spectrum and the X axis under different injection pressure differences.

4. The method of tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation of claim 1, wherein, The tight gas reservoir fluid occurrence and fracturing fluid water lock damage evaluation system further comprises a core drying oven (197) and a vacuum pressurized saturation device (198); The core sample can be dried in the core drying oven (197); The vacuum pressurized saturation device (198) is configured to vacuumize the core sample and pressurize and saturate the core sample to simulate formation water.

5. The method of tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation of claim 1, wherein, The displacement subsystem further comprises a temperature controller (7), a first heating protection sleeve (8), a confining pressure pump (9), a back pressure pump (10), a back pressure valve (196), and a second measuring cylinder (11); The first heating protection sleeve (8) is sleeved on the outside of the core holder (1); The signal output end of the temperature controller (7) is connected with the first heating protection sleeve (8) through a third pipeline (12), and the first heating protection sleeve (8) is configured to heat the core holder (1) controlled by the temperature controller (7); The confining pressure pump (9) is connected with the confining pressure input end of the core holder (1) through a fourth pipeline (13), and the confining pressure pump (9) is configured to provide confining pressure to the core holder (1) to simulate reservoir pressure; The back pressure pump (10) is connected with the second output end of the core holder (1) through a fifth pipeline (14); The fifth pipeline (14) is provided with a back pressure valve (196), and the output end of the back pressure valve (196) is connected with the second measuring cylinder (11), and the back pressure pump (10) is configured to adjust the back pressure of the core holder (1).

6. The method of tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation of claim 5, wherein, The forward displacement device (2) further comprises a first working liquid (23), a first constant flow pump (24), and a second heating protection sleeve (25); The first working liquid (23) is connected with the first intermediate container (22) through a sixth pipeline (15); The sixth pipeline (15) is provided with the first constant flow pump (24), and the first working liquid (23) is delivered to one side of the first intermediate container (22) through the first constant flow pump (24), and the first working liquid (23) delivered to one side of the first intermediate container (22) can increase the gas pressure on the other side of the first intermediate container (22); The second heating protection sleeve (25) is sleeved on the outside of the first intermediate container (22); The signal output end of the temperature controller (7) is connected with the second heating protection sleeve (25) through the seventh pipeline (16), and the second heating protection sleeve (25) heats the first intermediate container (22) under the control of the temperature controller (7).

7. The method of tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation of claim 5, wherein, The reverse displacement device (3) comprises a second working liquid (32), a second constant flow pump (33) and a third heating protection sleeve (34). The second working liquid (32) is connected with the second intermediate container (31) through the eighth pipeline (17). The second constant flow pump (33) is arranged on the eighth pipeline (17), and the second working liquid (32) is delivered to one side of the second intermediate container (31) through the second constant flow pump (33), and the other side of the second intermediate container (31) is provided with the fracturing fluid filtrate, and the second working liquid (32) delivered to one side of the second intermediate container (31) can deliver the fracturing fluid filtrate to the core sample. The third heating protection sleeve (34) is arranged outside the second intermediate container (31). The signal output end of the temperature controller (7) is connected with the third heating protection sleeve (34) through the ninth pipeline (18), and the third heating protection sleeve (34) heats the second intermediate container (31) under the control of the temperature controller (7).

8. The method of tight gas reservoir fluid occurrence and fracturing fluid water block damage evaluation of claim 1, wherein, The forward displacement device (2) further comprises a first valve (26) and a first pressure gauge (27). The reverse displacement device (3) further comprises a second valve (35) and a second pressure gauge (36). The first pipeline (4) is provided with the first valve (26), and the first valve (26) is located between the first intermediate container (22) and the core holder (1). The first valve (26) is provided with the first pressure gauge (27). The second pipeline (5) is provided with the second valve (35). The second valve (35) is provided with the second pressure gauge (36).

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