Method for determining relative permeability of artificial fracture oil-water based on two-dimensional nuclear magnetic resonance

Abstract

The present application relates to a method for determining artificial fracture oil-water relative permeability based on two-dimensional nuclear magnetic resonance, which comprises: oil-water nuclear magnetic signal calibration under reservoir temperature and pressure conditions; two-dimensional nuclear magnetic substrate signal test of shale matrix; artificial fracture filling with fracturing fluid, calculation of single-sided wall surface area of the fracture, estimation of fracture volume; making the conditions of the core and artificial fracture be the initial state of the reservoir after fracturing; nuclear magnetic resonance test of the initial state of the reservoir after fracturing; initial fracture width CT scan test; calculation of absolute permeability of the fracture; fracture fluid saturation test during flowback production process, calculation of water saturation and oil saturation in the fracture at t i ; fracture width test during flowback production process, calculation of fracture width at t 10 ; calculation of artificial fracture oil-water relative permeability; and drawing of a shale oil reservoir artificial fracture relative permeability curve. The present application can non-destructively, in-situ and in real time reveal the dynamic percolation behavior of artificial fractures in multiphase flow process.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir development technology, specifically to a method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance (NMR) technology. Background Technology

[0002] Shale reservoirs are diverse in type and abundant in quantity, with considerable resource scale and huge development potential. However, shale reservoirs are characterized by low porosity and low permeability, requiring artificial fracturing for development. The relative permeability of fractures is a core parameter characterizing the seepage law of multiphase fluids in the reservoir, and has a decisive impact on oil and gas reservoir numerical simulation, development scheme optimization, production prediction, and the formulation of enhanced oil recovery strategies.

[0003] Standard SY / T 5345-2007 provides an important method for obtaining the relative permeability of reservoirs with low porosity and low permeability. While this method is well-established in conventional reservoir applications, it is not suitable for evaluating the relative permeability of artificially fractured cores. Existing technologies (CN118258733A, CN116223176A) employ artificially created fractures and filled with proppant. The relative permeability of the fractured core is calculated using Darcy's formula. Another existing technology (CN 115753543 A) uses two identical rectangular shale slabs stacked together, with proppant placed at the contact surface. The relative permeability of the fractured core is then calculated using a formula. However, these methods cannot directly distinguish between fractured cores and cannot provide real-time fluid saturation; the calculation formulas are also complex. Existing technology (CN 105606517 A) involves placing a non-magnetic rock sample holder containing coal and rock in a low-field nuclear magnetic resonance (NMR) spectrometer to conduct displacement experiments, and then calculating the relative permeability and water saturation of the rock sample using the "JNB" method. Existing technology (CN206410978 U) uses the pressure pulse method to measure the relative permeability of tight rock cores, and uses an NMR device to monitor nitrogen displacement of water to obtain saturation. Existing technology (CN 110455688 A) calculates water saturation by measuring the volume of displaced water in shale using an NMR spectrometer; it also uses a carbon fiber core holder to improve the scanning effect of the NMR spectrometer. Existing technology (CN113984613 A) directly measures the distribution of water and water saturation in the rock core using NMR, and calculates the relative permeability of gas and water in the core using an integral formula. Existing technology (CN 113431537 A) uses nuclear magnetic resonance (NMR) to monitor water-driven gas displacement experiments in artificial large-scale cores, and derives water saturation and relative permeability of the gas and water phases based on Darcy's law and the law of conservation of energy. Existing technology (CN119198446 A) uses NMR to determine the characteristics of water occurrence in shale, classifies low-permeability shale pores, calculates the flow rates of the gas and water phases in different types of pores, and calculates the relative permeability of the gas and water phases using Darcy's law. Existing technology (CN 110296931 A) uses NMR to monitor heavy water displacement of oil in sandstone, and obtains oil-water phase permeability curves by analyzing the signal in the T2 spectrum of n-dodecane and the outflow rate at the port. However, heavy water and water have different properties, and n-dodecane also has different properties than oil; therefore, this method has certain limitations. Existing technology (CN 117269000 A) uses nuclear magnetic resonance (NMR) to monitor the displacement process of any two-phase fluid in a tight rock core and obtain the saturation; the relative permeability curves of the two phases are obtained by fitting the saturation distribution through numerical simulation. Existing technology (CN 110346258 A) divides a tight rock sample into three sections and conducts oil-water capillary pressure, constant-rate mercury intrusion porosimetry, physical property measurement experiments, and NMR tests on each section. Finally, the data are processed to obtain the relative permeability.The existing technology (CN 104634804 A) converts the nuclear magnetic resonance T2 spectrum into a pseudo relative permeability curve value, and establishes the conversion relationship between the nuclear magnetic resonance curve and the relative permeability curve by comparing the pseudo relative permeability curve with the actual experimental relative permeability curve. Summary of the Invention

[0004] The purpose of this invention is to provide a method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance. This method solves the problem of complex calculation formulas in existing methods for determining the relative permeability of oil and water, and overcomes the drawback of traditional methods that measure the saturation of oil and water together.

[0005] The technical solution adopted by this invention to solve its technical problem is as follows: This method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance includes the following steps: Step 1: Oil-water NMR signal calibration under reservoir temperature and pressure conditions. A core sample with artificial fractures is placed in the online NMR system of the NMR testing system using a non-metallic holder. Simulating reservoir temperature and pressure, fracturing fluid is injected into the core sample, and the injected volume is recorded as V. w Two-dimensional nuclear magnetic resonance (NMR) signal of fracturing fluid inside a non-metallic clamp was measured. w After cleaning, shale oil is injected again, and the tested volume is V. o Two-dimensional nuclear magnetic resonance (NMR) signal of shale oil o The nuclear magnetic resonance (NMR) signal quantities per unit volume of fracturing fluid and shale oil were calculated as follows: NMR w0 and NMR o0 ; Step 2, Two-dimensional NMR matrix signal testing of shale matrix: The proppant-filled artificial fracture core was subjected to two-dimensional NMR testing using the method in Step 1 to obtain the initial oil-water two-dimensional NMR matrix signal within the matrix pores. c ; Step 3: Inject fracturing fluid into the artificial fracture and calculate the area of ​​one side wall of the fracture as A. f Estimate the crack volume V f ; Step 4: Restore the reservoir to its initial state after fracturing, so that the core and artificial fractures are in the same condition as the reservoir after fracturing. Step 5: Initial NMR testing of the reservoir after fracturing: Two-dimensional NMR signal spectra of the entire core fracture system in its initial state are obtained using online NMR scanning. At this point, the water saturation within the fracture is 100%, and the oil saturation is 0%. These NMR signals are compared with the matrix pore NMR matrix signal from Step 2. c By comparison, the distribution location of the NMR signal of the fluid within the fracture on the T2 spectrum and the cutoff value of the transverse relaxation time T of the NMR signal within the fracture were obtained. NMR0 ; Step Six, Initial Crack Width CT Scan Test: Remove the non-metallic holder from the MRI testing system and place it in the CT scanner. Perform a high-resolution three-dimensional CT scan of the entire core fracture system to obtain the crack morphology. Quantitatively analyze the crack width W using image processing software. f ; Step 7, Calculation of absolute crack permeability: Connect the non-metallic holder to the online nuclear magnetic resonance testing system again, using a constant flow rate Q. w0 Injecting fracturing fluid, the pressure difference ΔP between the two ends of the core holder is obtained. w Calculate the cross-sectional area A of the crack and the absolute permeability K of the crack. w0 ; Step 8: Test the fluid saturation in the cracks during the return production process and calculate t. i Water saturation S within the crack at any given time wfi and oil saturation S ofi ; Step 9: Test the crack width during the return production process and calculate t1 to t2. 10 Crack width at any given moment; Step 10, Calculation of relative oil-water permeability in artificial fractures: Measure t i Pressure difference ΔP at both ends of the crack at any given time i Oil-water flow rate Q oi and Q wi Calculate t i The relative permeability of oil and water in the crack at any given moment; Step 11: Based on the test results of oil and water saturation in the fractures at different times and the calculation results of relative oil-water permeability, plot the relative permeability curve of artificial fractures in shale oil reservoirs.

[0006] The core preparation method in the above scheme is as follows: full-size cryogenic core sampling is performed under pressure from the oil and gas reservoir. A plunger core with a length of 4.984 cm and a diameter of 2.496 cm is drilled from the cryogenic full-size core using wire cutting technology. The core is then split along the axial direction to create artificial fractures and obtain a rough artificial fracture wall.

[0007] The above scheme describes the proppant preparation method as follows: Based on the specifications of the proppant used for on-site fracturing, a mixed particle size proppant with a ratio of 30 / 50 mesh: 40 / 70 mesh: 70 / 140 mesh = 1:3:6 is selected. The mesh sizes of the top and bottom sieves of the sieve group are determined to be 30 mesh and 140 mesh, respectively. The proppant sample is then screened, and all samples remaining in the top and bottom sieves are discarded. The fracturing fluid preparation method is as follows: Based on the on-site fracturing operation conditions, a μ... w The fracturing fluid was 0.8 mPa•s; the shale oil was simulated shale oil, prepared by mixing surface-produced shale oil and kerosene in a specific ratio based on a reservoir temperature of 90℃. oThe simulated shale oil was 1.08 mPa•s, ensuring that the simulated shale oil had the same viscosity as the reservoir crude oil.

[0008] Step one of the above scheme specifically involves: placing a core sample with artificial fractures into the nuclear magnetic resonance (NMR) testing system using a non-metallic holder; evacuating the non-metallic core holder using a vacuum pump; raising the temperature of the fluorinated oil in the confining pressure system to the reservoir temperature T; injecting fracturing fluid into the non-metallic holder using an ISCO pump; gradually increasing the injection pressure of the fracturing fluid to the reservoir pressure P; and consistently maintaining the confining pressure greater than the injection pressure by 2 MPa; and reading the injected fracturing fluid V using the ISCO pump. w Two-dimensional nuclear magnetic resonance (NMR) signal of fracturing fluid inside a non-metallic clamp was measured. w Clean the system; repeat this step to inject shale oil into the clamp, with a test volume of V. o Two-dimensional nuclear magnetic resonance (NMR) signal of shale oil o Calculate the NMR signal quantity per unit volume of fracturing w0 NMR signal quantity per unit volume of shale oil o0 : (Formula 1) (Formula 2) In the formula, NMR w0 The nuclear magnetic resonance (NMR) signal of fracturing fluid per unit volume under high temperature and high pressure conditions; o0 The nuclear magnetic resonance (NMR) signal of shale oil per unit volume under high temperature and high pressure conditions; w and NMR o These represent the nuclear magnetic resonance signal quantities when the non-metallic clamp is filled entirely with fracturing fluid or entirely with shale oil, respectively; V w and V o These refer to the volume of fracturing fluid when the non-metallic clamp is entirely filled with fracturing fluid or the volume of shale oil when the clamp is entirely filled with shale oil.

[0009] Step three in the above scheme specifically involves: setting the confining pressure of the non-metallic clamp to the initial effective stress P. e0 Initial effective stress P e0 The value is the minimum principal stress σ at the reservoir level. h With production well bottom flowing pressure P wf The difference is calculated by injecting fracturing fluid into the artificial fracture until approximately five times the fracture volume is produced at the outlet of the core holder. At this point, the fracture is filled with fracturing fluid. The area of ​​one side wall of the fracture is calculated as A using formulas (3) and (4). f Estimate the crack volume V f ; (Formula 3) (Formula 4) In the formula; V f A represents the crack volume; f L is the area of ​​one side wall of the fracture; D is the core length; W is the core diameter; fa This represents the crack width under conditions where no effective stress is applied.

[0010] Step four of the above scheme specifically involves: raising the temperature of the fluorinated oil in the confining pressure system to the reservoir temperature T and raising the pressure to the minimum principal stress σ. h Close the outlet of the clamp and use the ISCO pump to gradually increase the injection pressure of the fracturing fluid to the bottom-flow pressure P of the production well. wf During the pressurization process, the confining pressure σ is maintained at all times. c The difference between the injection pressure and the initial effective stress value P is equal to the initial effective stress value. e0 The flow rate at the inlet of the clamp remains zero for 4 hours. At this point, the core and artificial fractures are in the initial state of the reservoir after fracturing.

[0011] In the above scheme, step seven calculates the cross-sectional area A of the crack and the absolute permeability K of the crack. w0 Method: (Formula 5) (Formula 6) In the formula, K w0 Absolute permeability of proppant filling fractures; Q w0 μ is the fracturing fluid flow rate through the fracture. w ΔP is the fracturing fluid viscosity; A is the fracture cross-sectional area; ΔP w The pressure difference between the two ends of the core holder when the fracture is saturated with fracturing fluid; L is the length of the core.

[0012] Step eight in the above scheme specifically involves: using an ISCO pump at a constant flow rate q o Injecting shale oil, respectively at t i =0.25×2 i-1 Two-dimensional nuclear magnetic resonance imaging (NMR) tests were performed at (i=1, 2, ...) hours, and t values ​​were extracted. i Time greater than the cutoff value T NMR0 The NMR signals of the fracturing fluid and shale oil within the fracture were respectively NMR wi and NMR oi t is calculated using formulas (7) and (8). i The water saturation and oil saturation within the fracture at time S wfi and S ofi ; (Formula 7) (Formula 8) In the formula, Swfi and S ofi These represent the water saturation and oil saturation of the fracture at time i, respectively; NMR Wi and NMR oi , respectively, represent the two-dimensional nuclear magnetic resonance signals of fracturing fluid and shale oil within the fracture at time i.

[0013] Step nine in the above scheme specifically involves: [The steps are as follows:] [At T...] j =2×4 j-1 (j=1, 2, ...) Perform CT scan tests according to step ten for each hour, and extract t j The crack width at time t is plotted, and the curve showing the crack width changing with time is obtained using linear interpolation. i Crack width W at any moment fi ; calculate t1 to t using formulas (9) and (10) 10 Crack width at any given moment; (Formula 9) (Formula 10) ; In the formula, W fi W fctj They are respectively the tth i T j The crack width measured at time t; i T represents the time corresponding to the i-th two-dimensional NMR scan; j The time corresponding to j CT scan tests.

[0014] Step ten in the above scheme specifically involves measuring t. i Pressure difference ΔP at both ends of the crack at any given time i Oil-water flow rate Q oi and Q wi t is calculated using formulas (11)(12)(13)(14)(15). i The relative permeability of oil and water in the crack at any given moment; (Formula 11) (Formula 12) (Formula 13) (Formula 14) (Formula 15) In the formula, K oei For t i At any given moment, the effective permeability of the oil phase, Q oi For a unit of time (t) i-1 To t iThe volume of oil collected within the container; μ o To determine the viscosity of oil under experimental temperature and pressure; A i For t i The cross-sectional area of ​​the crack at any given moment; K wei For t i Time-phase effective permeability Q wi For a unit of time (t) i-1 To t i The volume of water collected within; μ w The viscosity of water was determined by pressure at the experimental temperature; K roi For t i The relative permeability of oil at any given time; K rwi For t i The relative permeability of water at any given time.

[0015] Beneficial effects: 1. This invention can non-destructively, in situ, and in real time reveal the dynamic seepage behavior of artificial fractures in multiphase flow processes, including oil and water phase flow velocities, fluid saturation within the fracture, and fracture pore volume. NMR's unique fluid differentiation capability allows for the separate quantitative determination of oil and water saturation in both the fracture system and the matrix pore system, and enables the measurement of oil and water saturation under varying fracture and pore volumes with time and stress.

[0016] 2. This invention utilizes nuclear magnetic resonance (NMR) technology to acquire key parameters such as oil and water saturation changes within fractures in real time and continuously without damaging the core or interrupting the experimental process. Saturation is directly calibrated and calculated using NMR signals, avoiding reliance on complex Darcy formulas for indirect estimation. Furthermore, it allows for separate and independent quantification of oil and water saturation in the "fracture system" and the "matrix pore system," overcoming the drawbacks of traditional methods that involve mixed measurements of both.

[0017] 3. This invention takes into account the actual situation of effective stress and crack width changes with time and stress during the production process, and measures crack width by CT scan in the experiment.

[0018] 4. This invention innovatively combines nuclear magnetic resonance monitoring system with CT scan crack morphology monitoring, realizing synchronous and correlated analysis of "fluid dynamics" and "crack width", providing a powerful experimental means to understand the relationship between crack width, fluid flow and relative permeability. Attached Figure Description

[0019] Figure 1 This is a schematic diagram of the nuclear magnetic resonance testing system of the present invention; Figure 2 The images show the initial two-dimensional NMR matrix signals of oil and water within the pores of the shale matrix and the initial two-dimensional NMR signals of the reservoir after fracturing.

[0020] Figure 3 The average width of the crack is shown in the CT scan at different times.

[0021] Figure 4 Two-dimensional NMR signal spectra of the crack at different times.

[0022] Figure 5 This is a graph showing the relative permeability of oil and water within the fracture.

[0023] In the diagram: 1 ISCO pump, 2 First valve, 3 First pressure gauge, 4 Simulated shale oil intermediate container, 5 Second valve, 6 Second pressure gauge, 7 Fluorine oil, 8 Non-magnetic clamp plug, 9 Online NMR system, 10 Core, 11 Third pressure gauge, 12 Confining pressure inlet valve, 13 Confining pressure pump, 14 Confining pressure outlet valve, 15 Temperature control device, 16 Fourth pressure gauge, 17 Third valve, 18 Back pressure valve, 19 Fluid collection device, 20 Back pressure pump, 21 Data collection system, 22 Fourth valve, 23 Fifth valve, 24 Fracturing fluid intermediate container, 25 NMR-specific core clamp, 26 Vacuum pump. Detailed Implementation

[0024] The present invention will be further described below with reference to the accompanying drawings: The method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance is as follows: Step 1, core preparation: Full-size cryogenic core sampling is performed from the oil and gas reservoir under pressure. A plunger core with a length of 4.984 cm and a diameter of 2.496 cm is drilled from the full-size cryogenic core using wire cutting technology. The core is then split along the axial direction to create artificial fractures and obtain a rough artificial fracture wall. Step 2, Prop preparation: Select a mixed particle size proppant with a ratio of 30 / 50 mesh: 40 / 70 mesh: 70 / 140 mesh = 1:3:6 according to the specifications of the proppant used for fracturing in the field. Determine the mesh size of the top sieve and bottom sieve of the sieve group to be 30 mesh and 140 mesh respectively. Screen the proppant sample and discard all the samples left in the top sieve and bottom sieve. Step 3, prepare fracturing fluid and simulated shale oil: Prepare μ according to the on-site fracturing conditions. w The fracturing fluid is a 0.8 mPa•s breaker fluid; based on a reservoir temperature of 90℃, a viscosity μ is prepared by mixing surface-produced shale oil and kerosene in a specific ratio. o The simulated shale oil was 1.08 mPa•s, making it have the same viscosity as the reservoir crude oil; Step 4, Oil-Water NMR Signal Calibration under High Temperature and High Pressure: A core sample with artificial fractures is placed in the online NMR system 9 of the NMR testing system using a dedicated NMR core holder 25. A vacuum pump 26 is used to evacuate the empty NMR core holder 25. The temperature of the fluorinated oil 7 in the confining pressure pump 13 is raised to the reservoir temperature of 90°C. Fracturing fluid is injected into the non-metallic holder (dedicated NMR core holder 25) using an ISCO pump 1. The injection pressure of the fracturing fluid is gradually increased to the bottom-hole flowing pressure of 21 MPa, while maintaining the confining pressure greater than the injection pressure by 2 MPa. The volume of injected fracturing fluid is read as V using the ISCO pump. w =2.486ml, two-dimensional nuclear magnetic resonance (NMR) signal of fracturing fluid in non-metallic holder was measured. w =2.6340PU. Cleaning system. Repeat this step to inject shale oil into the holder, with a test volume of V. o =2.563 ml shale oil two-dimensional nuclear magnetic resonance signal quantity NMR o =2.7370PU, the NMR signal quantities per unit volume of fracturing fluid and shale oil were calculated using formulas (1) and (2) respectively. w0 =1.0595PU and NMR o0 =1.0679PU; (Formula 1) (Formula 2) In the formula, NMR w0 and NMR o0 The NMR values ​​are PU and NMR, respectively, for fracturing fluid and shale oil per unit volume under high temperature and high pressure conditions. w and NMR o These represent the nuclear magnetic resonance (NMR) signals, PU and V, respectively, when the non-metallic clamp is filled entirely with fracturing fluid or entirely with shale oil. w and V o These represent the fracturing fluid volume when the non-metallic holder is entirely filled with fracturing fluid, or the shale oil volume when the holder is entirely filled with shale oil, respectively, in cm³. 3 .

[0025] Step 5, proppant filling: Pre-place support pads in the artificial fracture, wrap the core with thermoplastic film, then heat to compress the core with the thermoplastic film, and fill the artificial fracture with proppant while slowly pulling out the support pads; place the proppant-filled core in a non-metallic core holder, and use the core positioning auxiliary plug 8 to fix the core 10 in the middle position of the core holder; Step Six, Two-Dimensional NMR Matrix Signal Testing of Shale Matrix: A confining pressure of 2 MPa was applied to the proppant-filled artificial fracture core using fluorinated oil in the confining pressure system. Two-dimensional NMR testing was then performed on the core, and the results are as follows: Figure 2As shown in figure a. The initial oil-water two-dimensional NMR matrix signal within the matrix pores was obtained. c =1.8630PU; Step 7, Inject fracturing fluid into the artificial fracture: Set the confining pressure of the non-metallic holder to the initial effective stress P. e0 =34MPa, initial effective stress P e0 The value is the minimum principal stress σ at the reservoir level. h =55MPa and the bottom flow pressure of the production well P wf =21MPa difference, inject fracturing fluid into the artificial fracture until about 5 times the fracture volume of fracturing fluid is produced at the outlet of the core holder, indicating that the fracture is now filled with fracturing fluid. The area of ​​the fracture's single-sided wall is calculated as A using formulas (3) and (4). f =12.44cm², estimated crack volume is V f =3.98cm³; (Formula 3) (Formula 4) In the formula; V f A represents the crack volume in cm³. f L is the area of ​​one side wall of the fracture, cm²; L is the core length, cm; D is the core diameter, cm; W fa The crack width under no effective stress applied is 0.32 cm.

[0026] Step 8, restore the initial state of the reservoir after fracturing: raise the temperature of the fluorinated oil in the confining pressure system to the reservoir temperature of 90°C and the pressure to the minimum principal stress σ. h =55MPa, close the third valve 17 at the outlet of the clamp, and use the ISCO pump to gradually increase the injection pressure of the fracturing fluid to the bottom-of-well flowing pressure P. wf =21MPa, the confining pressure σ is maintained throughout the pressurization process. c The difference between the injection pressure and the initial effective stress value P is equal to the initial effective stress value. e0 =34MPa, until the flow rate of the fourth valve 22 at the inlet of the clamping device is zero for 4 hours. At this time, the core and artificial fracture are in the initial state of the reservoir after hydraulic fracturing. Step 9, Initial state NMR testing of the reservoir after fracturing: Two-dimensional NMR signal spectra of the entire core fracture system (matrix + fractures) in the initial state (matrix saturated with oil, fractures saturated with fracturing fluid) were obtained using online NMR scanning, as shown below. Figure 2 As shown in Figure b, the water saturation in the crack is 100% and the oil saturation is 0%. Figure 2 The test results after the matrix was saturated with oil showed that there was no fluid in the fracture at this point. This is compared with the NMR signal from the matrix pores in step six. cBy comparison, the distribution location of the NMR signal of the fluid within the fracture on the T2 spectrum and the cutoff value of the transverse relaxation time T of the NMR signal within the fracture were obtained. NMR0 =125.9ms (greater than the cutoff value T) NMR0 The signal originates from the fluid within the fracture system. Step 10, Initial Crack Width CT Scan Test: Close the inlet and outlet valves of the clamp, the confining pressure inlet valve 12, and the confining pressure outlet valve 14 to bring the entire system into a static closed state. Place the non-metallic clamp into the CT scanner and perform a high-resolution three-dimensional CT scan of the entire core fracture system to obtain the fracture morphology. The results are as follows: Figure 3 As shown in figure a, the crack width W is quantitatively analyzed using image processing software. f0 It is 2.737mm; Step 11, Calculation of absolute fracture permeability: Connect the non-metallic holder to the online nuclear magnetic resonance testing system again, open the holder's inlet and outlet ends, and set the pressure of the holder's outlet back pressure valve 18 to the bottom hole flowing pressure P. wf =21MPa, confining pressure is the minimum principal stress σ in the horizontal direction. h =55MPa, using an ISCO pump to inject fracturing fluid at a constant flow rate of 0.002ml / min, the pressure difference ΔPw =11.71Pa between the two ends of the core holder is obtained by the pressure sensor, the cross-sectional area of ​​the fracture A =0.6832cm2 is calculated by formula (5) (6), and the absolute permeability of the fracture Kw0 =1661.3mD; (Formula 5) (Formula 6) In the formula, K w0 Absolute permeability of proppant-filled fractures, mD; Q w0 The fracturing fluid flow rate through the fracture is expressed in mL / s; μ w A is the fracturing fluid viscosity, mPa·s; A is the fracture cross-sectional area, cm². 2 ;ΔP w The pressure difference across the core holder when the fracture is saturated with fracturing fluid is expressed in Pa.

[0027] Step 12, Fractured Fluid Saturation Test during Flowback Production: Shale oil is injected at a constant flow rate of 0.002 ml / min using an ISCO pump, and the saturation is measured at t... i =0.25×2 i-1 Two-dimensional nuclear magnetic resonance (NMR) tests were performed on (i=1, 2, ..., 10)h. t0 was extracted. i Time greater than the cutoff value T NMR0 The nuclear magnetic resonance signals of fracturing fluid and shale oil within the fracture were calculated using formulas (7) and (8). iThe water saturation and oil saturation within the fracture at specific times are shown in Table 1. The two-dimensional nuclear magnetic resonance (NMR) test results at 0.25h, 0.5h, 2h, 8h, 32h, and 128h are shown below. Figure 4 As shown in Figures a, b, c, d, e, and f; (Formula 7) (Formula 8) In the formula, S wfi and S ofi The values ​​represent the water saturation and oil saturation of the fracture at time i, respectively, in terms of %; NMR. Wi and NMR oi PU represents the two-dimensional nuclear magnetic resonance (NMR) signals of fracturing fluid and shale oil within the fracture at time i.

[0028] Table 1. Data on fluid saturation within the fracture over time. 0 (Initial) 0 100.0% 0 1 0.25 92.8% 7.2% 2 0.5 85.5% 14.5% 3 1 71.6% 28.4% 4 2 60.0% 40.0% 5 4 49.3% 50.7% 6 8 40.3% 59.7% 7 16 32.7% 67.3% 8 32 28.2% 71.8% 9 64 24.1% 75.9% 10 128 22.3% 77.7% Step 13, Crack width test during the return production process: (The text abruptly ends here, likely due to an incomplete sentence or a formatting error.) j =2×4 j-1 (j=1, 2, 3, 4) CT scans were performed according to step ten at 2h, 8h, 32h, and 128h, with results of 2.713mm, 2.693mm, 2.683mm, and 2.673mm, respectively. Figure 3 As shown in b, c, d, and e, Figure 3 In the image, 'a' represents the initial CT scan result. T0 is extracted. j Crack width at any moment Plot the curve showing the relationship between seam width and time. Using linear interpolation, the corresponding value for any time t can be obtained. i Crack width W at times (0.25 h, 0.5 h, 1 h, 4 h, 16 h, 64 h) fi Calculate t1 to t using formulas (9) and (10). 10 The crack widths at different times are shown in Table 2: (Formula 9) (Formula 10) ; In the formula, W fi W fctj They are respectively the tth i T j Crack width measured at time, cm; t i T represents the time corresponding to the i-th two-dimensional NMR scan, in h; j Let h be the time corresponding to j CT scan tests.

[0029] Table 2. Data on crack width variation over time 0 (Initial) 0 2.737 1 0.25 2.734 2 0.5 2.731 3 1 2.725 4 2 2.713 5 4 2.706 6 8 2.693 7 16 2.690 8 32 2.683 9 64 2.680 10 128 2.673 Step Fourteen, Calculation of relative oil-water permeability in artificial fractures: Measure t i Pressure difference ΔP at both ends of the crack at any given time i (Inlet pressure P) ii Subtract the export pressure P oi Oil-water flow rate Q oi and Q wi t is calculated using formulas (11)(12)(13)(14)(15). i The relative permeability of oil and water in the crack at any given time is shown in Table 3. (Formula 11) (Formula 12) (Formula 13) (Formula 14) (Formula 15) In the formula, K oei For t i Oil phase effective permeability at time, mD; Q oi For a unit of time (t) i-1 To t i The volume of oil collected within the container, in cm³ / s; μ o The viscosity of the oil was determined at the experimental temperature and pressure; mPa·s; A i For t i Cross-sectional area of ​​the crack at any given moment, in cm 2 ;K wei For t i Effective permeability of aqueous phase at any given time, mD; Q wi For a unit of time (t) i-1 To t i The volume of water collected within the container, in cm³ / s; μ w The viscosity of water was determined by pressure at the experimental temperature, in mPa·s; K. roi For t i The relative permeability of oil at any given time; K rwi For t i The relative permeability of water at any given time.

[0030] Table 3. Relative permeability of oil and water in core proppant-filled fractures at different injection times.

[0031] Step 15: Based on the test results of oil and water saturation in the fractures at different times, and the calculation results of the relative permeability of oil and water, plot the relative permeability curve of the artificial fractures in the shale oil reservoir, as shown below. Figure 5 As shown.

[0032] The nuclear magnetic resonance (NMR) testing system of this invention includes an online NMR system 9, a simulated shale oil intermediate container 4, a fracturing fluid intermediate container 24, a confining pressure pump 13, a back pressure pump 20, a temperature control device 15, a fluid collection device 19, and a data collection system 21. A core 10 with artificial fractures is embedded in the online NMR system 9 using a non-metallic holder (NMR-specific core holder 25). A vacuum pump 26 is connected to a third valve 17 at the outlet of the holder, and the vacuum pump 26 is used to evacuate the empty non-metallic core holder. An ISCO pump 1 is connected to the simulated shale oil intermediate container 4 and the fracturing fluid intermediate container 24, which are arranged in parallel, via a first pressure gauge 3. A second valve 5 is installed at the outlet of the simulated shale oil intermediate container. A fifth valve 23 is installed at the outlet of the fracturing fluid intermediate container. The second valve 5 and the fifth valve 23 are connected in parallel to the fourth valve 22. The fourth valve 22 is connected to the inlet end of the clamp. A second pressure gauge 6 is installed at the inlet end of the clamp. The confining pressure pump 13 is connected to the confining pressure chamber outside the core. A third pressure gauge 11 is installed in front of the confining pressure inlet valve 12. The confining pressure outlet valve 14 is installed after the confining pressure pump 13. The back pressure valve 18 is connected in parallel with the vacuum pump 26 after the third valve 17. The back pressure valve 18 is connected to the back pressure pump 20 and the fluid collection device 19. The online nuclear magnetic resonance system 9, the simulated shale oil intermediate container 4, the fracturing fluid intermediate container 24, the confining pressure pump 13, the back pressure pump 20, and the fluid collection device 19 are all installed in the temperature control device.

Claims

1. A method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance, characterized in that... Includes the following steps: Step 1: Oil-water NMR signal calibration under reservoir temperature and pressure conditions. A core sample with artificial fractures is placed in the online NMR system of the NMR testing system using a non-metallic holder. Simulating reservoir temperature and pressure, fracturing fluid is injected into the core sample, and the injected volume is recorded as V. w Two-dimensional nuclear magnetic resonance (NMR) signal of fracturing fluid inside a non-metallic gripper was measured. w After cleaning, shale oil is injected again, and the tested volume is V. o Two-dimensional nuclear magnetic resonance (NMR) signal of shale oil o The nuclear magnetic resonance (NMR) signal quantities per unit volume of fracturing fluid and shale oil were calculated as follows: NMR w0 and NMR o0 ; Step 2, Two-dimensional NMR matrix signal testing of shale matrix: The proppant-filled artificial fracture core was subjected to two-dimensional NMR testing using the method in Step 1 to obtain the initial oil-water two-dimensional NMR matrix signal within the matrix pores. c ; Step 3: Inject fracturing fluid into the artificial fracture and calculate the area of ​​one side wall of the fracture as A. f Estimate the crack volume V f ; Step 4: Restore the reservoir to its initial state after fracturing, so that the core and artificial fractures are in the same condition as the reservoir after fracturing. Step 5: Initial NMR testing of the reservoir after fracturing: Two-dimensional NMR signal spectra of the entire core fracture system in its initial state are obtained using online NMR scanning. At this point, the water saturation within the fracture is 100%, and the oil saturation is 0%. These NMR signals are compared with the matrix pore NMR matrix signal from Step 2. c By comparison, the distribution location of the NMR signal of the fluid within the fracture on the T2 spectrum and the cutoff value of the transverse relaxation time T of the NMR signal within the fracture were obtained. NMR0 ; Step Six, Initial Crack Width CT Scan Test: Remove the non-metallic holder from the MRI testing system and place it in the CT scanner. Perform a high-resolution three-dimensional CT scan of the entire core fracture system to obtain the fracture morphology. Quantitatively analyze the fracture width W using image processing software. f ; Step 7, Calculation of absolute crack permeability: Connect the non-metallic holder to the online nuclear magnetic resonance testing system again, using a constant flow rate Q. w0 Injecting fracturing fluid, the pressure difference ΔP between the two ends of the core holder is obtained. w Calculate the cross-sectional area A of the crack and the absolute permeability K of the crack. w0 ; Step 8: Test the fluid saturation in the cracks during the return production process and calculate t. i Water saturation S within the crack at any given time wfi and oil saturation S ofi ; Using an ISCO pump at a constant flow rate q o Injecting shale oil, respectively at t i =0.25×2 i-1 Two-dimensional nuclear magnetic resonance imaging (NMR) tests were performed at (i=1, 2, ...) hours, and t values ​​were extracted. i Time greater than the cutoff value T NMR0 The NMR signals of fracturing fluid and shale oil within the fractures were respectively NMR wi and NMR oi t is calculated using formulas (7) and (8). i The water saturation and oil saturation within the fracture at time S are respectively wfi and S ofi ; (Official 7) (Official 8) In the formula, S wfi and S ofi These represent the water saturation and oil saturation of the fracture at time i, respectively; NMR Wi and NMR oi These represent the two-dimensional nuclear magnetic resonance signals of the fracturing fluid and shale oil within the fracture at time i, respectively. Step 9: Test the crack width during the return production process and calculate t1 to t2. 10 The crack width at any given time is as follows: At T respectively j =2×4 j-1 (j=1, 2, ...) Perform CT scan tests according to step ten for each hour, and extract t j The crack width at time t is plotted, and the curve showing the crack width changing with time is obtained using linear interpolation. i Crack width W at any moment fi ; calculate t1 to t using formulas (9) and (10) 10 Crack width at any given moment; (Official 9) (Official 10) ； In the formula, W fi W fctj They are respectively the tth i T j The crack width measured at time t; i The time corresponding to the i-th two-dimensional NMR scan; T j The time corresponding to j CT scan tests; Step 10, Calculation of relative oil-water permeability in artificial fractures: Measure t i Pressure difference ΔP at both ends of the crack at any given time i Oil-water flow rate Q oi and Q wi Calculate t i The relative permeability of oil and water in the crack at any given moment; Measuring t i Pressure difference ΔP at both ends of the crack at any given time i Oil-water flow rate Q oi and Q wi t is calculated using formulas (11)(12)(13)(14)(15). i The relative permeability of oil and water in the crack at any given moment; (Official 11) (Official 12) (Official 13) (Official 14) (Official 15) In the formula, K oei For t i At any given moment, the effective permeability of the oil phase, Q oi For a unit of time (t) i-1 To t i The volume of oil collected within the container; μ o To determine the viscosity of oil under experimental temperature and pressure; A i For t i The cross-sectional area of ​​the crack at any given moment; K wei For t i Time-phase effective permeability Q wi For a unit of time (t) i-1 To t i The volume of water collected within; μ w The viscosity of water was determined by pressure at the experimental temperature; K roi For t i The relative permeability of oil at any given time; K rwi For t i The relative permeability of water at any given time; Step 11: Based on the test results of oil and water saturation in the fractures at different times and the calculation results of relative oil-water permeability, plot the relative permeability curve of artificial fractures in shale oil reservoirs.

2. The method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance according to claim 1, characterized in that: Core preparation method: Full-size cryogenic core sampling is performed under pressure from the oil and gas reservoir. A plunger core with a length of 4.984 cm and a diameter of 2.496 cm is drilled from the cryogenic full-size core using wire cutting technology. The core is then split along the axial direction to create artificial fractures and obtain a rough artificial fracture wall.

3. The method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance according to claim 2, characterized in that: Proppant preparation method: Select a mixed particle size proppant with a ratio of 30 / 50 mesh: 40 / 70 mesh: 70 / 140 mesh = 1:3:6 according to the specifications of the proppant used for in-situ fracturing. Determine the mesh size of the top and bottom sieves of the sieve set to 30 mesh and 140 mesh respectively. Screen the proppant sample, discarding all samples remaining in the top and bottom sieves. Fracturing fluid preparation method: Prepare μ... w The fracturing fluid was 0.8 mPa•s; the shale oil was simulated shale oil, prepared by mixing surface-produced shale oil and kerosene in a specific ratio based on a reservoir temperature of 90℃. o The simulated shale oil was 1.08 mPa•s, ensuring that the simulated shale oil had the same viscosity as the reservoir crude oil.

4. The method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance according to claim 3, characterized in that: Step one specifically involves: placing a core sample with artificial fractures into the nuclear magnetic resonance (NMR) testing system using a non-metallic holder; evacuating the non-metallic core holder using a vacuum pump; raising the temperature of the fluorinated oil in the confining pressure system to the reservoir temperature T; injecting fracturing fluid into the non-metallic holder using an ISCO pump; gradually increasing the injection pressure of the fracturing fluid to the reservoir pressure P, while always maintaining the confining pressure greater than the injection pressure by 2 MPa; and reading the injected fracturing fluid volume as V using the ISCO pump. w Two-dimensional nuclear magnetic resonance (NMR) signal of fracturing fluid inside a non-metallic gripper was measured. w Clean the system; repeat this step to inject shale oil into the clamp, with a test volume of V. o Two-dimensional nuclear magnetic resonance (NMR) signal of shale oil o Calculate the NMR signal quantity per unit volume of fracturing fluid. w0 NMR signal quantity per unit volume of shale oil o0 : (Official 1) (Official 2) In the formula, NMR w0 The nuclear magnetic resonance (NMR) signal of fracturing fluid per unit volume under high temperature and high pressure conditions; o0 The nuclear magnetic resonance (NMR) signal of shale oil per unit volume under high temperature and high pressure conditions; w and NMR o These represent the nuclear magnetic resonance signal quantities when the non-metallic clamp is filled entirely with fracturing fluid or entirely with shale oil, respectively; V w and V o These refer to the volume of fracturing fluid when the non-metallic clamp is entirely filled with fracturing fluid or the volume of shale oil when the clamp is entirely filled with shale oil.

5. The method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance according to claim 4, characterized in that: Step three specifically involves: setting the confining pressure of the non-metallic clamp to the initial effective stress P. e0 Initial effective stress P e0 The value is the minimum principal stress σ at the reservoir level. h With production well bottom flowing pressure P wf The difference is calculated by injecting fracturing fluid into the artificial fracture until approximately five times the fracture volume is produced at the outlet of the core holder. At this point, the fracture is filled with fracturing fluid. The area of ​​one side wall of the fracture is calculated as A using formulas (3) and (4). f Estimate the crack volume V f ; (Official 3) (Official 4) In the formula; V f A represents the crack volume; f L is the area of ​​one side wall of the fracture; D is the core length; W is the core diameter; fa This represents the crack width under conditions where no effective stress is applied.

6. The method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance according to claim 5, characterized in that: Step four specifically involves: raising the temperature of the fluorinated oil in the confining pressure system to the reservoir temperature T and increasing the pressure to the minimum principal stress σ. h Close the outlet end of the clamp and use the ISCO pump to gradually increase the injection pressure of the fracturing fluid to the bottom-flow pressure P of the production well. wf During the pressurization process, the confining pressure σ is maintained at all times. c The difference between the injection pressure and the initial effective stress value P is equal to the initial effective stress value P. e0 The flow rate at the inlet of the clamp remains zero for 4 hours. At this point, the core and artificial fractures are in the initial state of the reservoir after fracturing.

7. The method for determining the relative permeability of oil and water in artificial fractures based on two-dimensional nuclear magnetic resonance according to claim 6, characterized in that: Step seven involves calculating the cross-sectional area A of the crack and the absolute permeability K of the crack. w0 Method: (Official 5) (Official 6) In the formula, K w0 Absolute permeability of proppant filling fractures; Q w0 μ is the fracturing fluid flow rate through the fracture. w ΔP is the fracturing fluid viscosity; A is the fracture cross-sectional area; ΔP w The pressure difference between the two ends of the core holder when the fracture is saturated with fracturing fluid; L is the length of the core.

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