Determination method of shale pore compressibility coefficient

Abstract

The invention belongs to the field of stratum elastic parameter analysis, and particularly relates to a shale pore compressibility coefficient measuring method. According to the determination method, alkane gas is used for replacing methane to serve as a saturated medium, the response of 1H in a magnetic field after shale cores are saturated with alkane is detected through nuclear magnetic resonance, and the pore space volumes of the shale under different confining pressures are quantitatively represented through a nuclear magnetic resonance T2 atlas and an ideal gas state equation. The saturation degree of the new saturated medium on the rock core is more sufficient, and the influence of shale micro-nano pores can be fully reflected; in the core saturation process, water swelling does not occur, and the influence of the pipeline blank volume does not need to be considered, so that the shale pore compressibility can be measured more accurately.

Description

Technical Field

[0001] This invention belongs to the field of formation elastic parameter analysis, specifically relating to a method for determining the pore compressibility coefficient of shale. Background Technology

[0002] Rock pore compressibility coefficient C p The pore compressibility coefficient refers to the change in unit pore volume when the formation pressure decreases by one unit. As formation pressure decreases, the pore volume shrinks, driving fluids within the reservoir pores towards the bottom of the well. Therefore, the magnitude of the rock pore compressibility coefficient represents the rock's elastic oil / gas displacement capacity and is an important parameter indicating the formation's elastic reserves and elastic energy.

[0003] The conventional method for determining the pore compressibility coefficient of rocks follows the industry standard SY / T 5815-2008. Its principle involves measuring the change in pore volume of rock samples under different net effective pressure conditions using saturated brine. In the experiment, at least five experimental pressure points are first established. Depending on the experimental requirements, the confining pressure is either kept constant while gradually increasing, or kept constant while gradually decreasing, to increase the net effective pressure and thus reduce the pore volume. The pore compressibility coefficient of the rock is then calculated.

[0004] Shale rich in clay minerals is prone to water absorption and swelling, leading to changes in pore space. Furthermore, shale pores are predominantly mesopores and micropores, making it difficult to inject liquids into shale cores. High-pressure liquid injection can also disrupt the original pore structure, affecting pore volume measurements and posing significant challenges to experimental research. Additionally, conventional experimental setups suffer from pipeline blank volumes, and their measurement accuracy is not suitable for the nano- and micro-pore structures of shale.

[0005] Chinese invention patent application CN116448643A, published on July 18, 2023, discloses a method for determining the core pore compressibility coefficient based on nuclear magnetic resonance (NMR) technology. The method involves fully saturating the core with formation water, scanning the core using T2 spectra to determine the rock porosity, recording the corresponding volume signal value to determine the pore volume of the core, and then determining the core compressibility coefficient based on a formula. However, this method still relies on saturating the core with formation water, which fails to address issues such as shale's tendency to absorb water and expand, leading to changes in pore space and difficulty for water to enter mesopores and micropores. Meanwhile, when determining the pore volume, it is necessary to use multiple standard samples with different porosities, measure the T2 spectrum of the corresponding standard samples, and use the SIRT method to numerically invert the collected attenuation data based on the attenuation curve of the T2 spectrum. The data fitting is then used to establish the relationship between pore volume and total signal. The overall testing process is quite complex, and whether the relationship established using standard samples with different porosities can represent the characteristics of the core sample to be tested is still open to discussion and further verification.

[0006] Therefore, there is an urgent need to explore a method that can accurately test and calculate the porosity compressibility of viscous shale. Summary of the Invention

[0007] The purpose of this invention is to provide a method for determining the pore compressibility coefficient of shale, so as to solve the problems that conventional methods are difficult to apply directly to shale and have insufficient experimental accuracy.

[0008] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0009] A method for determining the pore compressibility coefficient of shale, comprising the following steps:

[0010] S1: After vacuuming the shale core to be tested, perform nuclear magnetic resonance scanning to obtain the initial nuclear magnetic resonance T2 spectrum of the core;

[0011] S2: Alkane gas was injected into the core at the experimentally designed pore pressure. After the pressure stabilized under the initial confining pressure, nuclear magnetic resonance (NMR) scanning was performed to obtain the NMR T2 spectrum under the corresponding confining pressure conditions.

[0012] S3: Keep the pore pressure constant, gradually increase the confining pressure point according to the experimental design, and perform NMR scanning after the pressure stabilizes to obtain NMR T2 spectra under different confining pressure conditions; construct the curve of T2 peak area of ​​NMR T2 spectra as a function of net effective pressure; wherein the net effective pressure = confining pressure - pore pressure;

[0013] S4: Conduct alkane gas calibration experiments and determine the fitting relationship between the T2 peak area and the number of moles of alkane gas based on the ideal gas law;

[0014] S5: Based on S3 and S4, establish the calculation formulas for shale pore compressibility coefficient, net effective pressure, and T2 peak area, and determine the shale pore compressibility coefficient under different net effective pressures according to the calculation formulas.

[0015] This invention is groundbreaking, using alkane gas instead of methane as the saturating medium, and utilizing nuclear magnetic resonance to detect saturated alkane in shale cores. 1 The response of H in a magnetic field is used to quantitatively characterize the pore space volume of shale under different confining pressures by combining the ideal gas equation of state with nuclear magnetic resonance T2 spectra. The new saturating medium saturates the core more fully, which can fully reflect the influence of shale micro and nanopores; the core does not expand upon contact with water during saturation and there is no need to consider the influence of pipeline blank volume, thus enabling more accurate determination of the shale pore compressibility coefficient.

[0016] Preferably, in step S2, the alkane gas is methane. Nuclear magnetic resonance (NMR) detects... 1 Compared to hydrogen (H2) and other alkane gases, methane gas is more convenient, economical, and safer in terms of its response to a magnetic field.

[0017] More preferably, in step S4, the fitting relationship is a direct proportional relationship. Conducting nuclear magnetic resonance calibration experiments can establish the relationship between the nuclear magnetic signal response and the number of moles of experimental fluid. Fitting with a direct proportional relationship facilitates subsequent calculation formula conversion and has a high fitting correlation, with a correlation coefficient exceeding 0.999.

[0018] More preferably, in step S5, the calculation formula is:

[0019]

[0020] Among them, C p The rock pore compressibility coefficient is expressed in MPa. -1 Q1 and Q2 are the T2 peak areas corresponding to two adjacent confining pressure points, respectively; p1 and p2 are the net effective pressures corresponding to two adjacent confining pressure points, respectively, in MPa.

[0021] Preferably, the shale is a high-clay shale with a clay content of ≥40%.

[0022] Preferably, in steps S2 and S3, the experimental temperature is the formation temperature where the core is located.

[0023] Preferably, in steps S2 and S3, the pressure stabilization means that the pressure change within 0.0069 MPa within 5 minutes.

[0024] Preferably, in step S1, the vacuuming includes evacuating to a vacuum level of -0.101 MPa and then evacuating for at least 4 hours. Attached Figure Description

[0025] Figure 1 This is a schematic diagram of the experimental apparatus according to an embodiment of the present invention;

[0026] Figure 2 These are nuclear magnetic resonance T2 spectra under different confining pressure conditions in embodiments of the present invention;

[0027] Figure 3 This is a curve showing the change of peak area T2 with net effective pressure in an embodiment of the present invention;

[0028] Figure 4 This is the calibration curve of peak area T2 versus molar number of methane gas in an embodiment of the present invention;

[0029] Figure 5 This is a curve showing the variation of shale pore compressibility coefficient with net effective pressure in an embodiment of the present invention. Detailed Implementation

[0030] The technical concept of this invention is to use alkane gas as the experimental fluid in rock pore volume compression experiments, and to realize the rock pore compressibility coefficient C by utilizing the correlation between the nuclear magnetic resonance T2 spectrum of the experimental fluid and the rock pore volume. p The above measurement process, combined with the rock pore compressibility coefficient calculation formula (Formula 1) and the ideal gas state equation (Formula 2), can effectively solve the problems of core expansion caused by traditional measurement methods, inability to evaluate the experimental effects of micro and nanopores in the core, and the influence of pipeline blank volume, thereby improving the accuracy and reliability of shale pore compressibility coefficient testing.

[0031] Formula 1:

[0032] Formula 2: PV=ZnRT

[0033] In Formula 1, V p The pore volume of rock under each net effective pressure, m 3 ;dV p / dp represents the change in rock pore volume caused by a change in unit pressure, in m 3 / MPa.

[0034] In Formula 2, P is the pressure, MPa; V is the gas volume, m³. 3 T is temperature, K; n is the number of moles of gas, mol; R is the gas constant, R = 0.008314 MPa·m 3 / (kmol·K).

[0035] The implementation process of the present invention will be described in detail below with reference to specific embodiments.

[0036] I. Specific Embodiments of the Method for Determining the Pore Compressibility Coefficient of Shale of the Present Invention

[0037] Example 1

[0038] The method for determining the shale porosity compressibility coefficient in this embodiment uses the following experimental apparatus: Figure 1 As shown, the system includes a high-temperature, high-pressure core holder. The inlet of the core holder is connected to a gas injection system via an inlet pipeline, and the outlet is connected to a vacuum pump or a methane gas recovery device (used during the methane injection stage) via an outlet pipeline. Pressure sensors are installed on both the inlet and outlet pipelines. The high-temperature, high-pressure core holder is also connected to a confining pressure system and a nuclear magnetic resonance (NMR) spectrometer for core analysis. The high-temperature, high-pressure core holder should be compatible with the NMR spectrometer's requirements, made of ceramic material, and equipped with an NMR signal acquisition device.

[0039] The specific testing steps are explained below:

[0040] (1) Load the shale core to be tested into the high-temperature and high-pressure core holder, according to the attached... Figure 1 The experimental setup was connected, and the temperature was set to the formation temperature where the core was located. The confining pressure was set to the first experimental point in the design using the confining pressure system. A vacuum pump was used to evacuate the shale core sample, and the pressure stability criterion was determined according to SY / T 5815 (i.e., pressure change within 0.0069 MPa (1 psi) within 5 minutes). After pressure stabilization, nuclear magnetic resonance (NMR) scanning was performed to obtain the initial T2 NMR spectrum of the core. Because the rock skeleton of the core will also have... 1 The H-response method first measures the initial NMR T2 spectrum of the core sample, and then subtracts the initial NMR T2 data of the core sample from the NMR T2 data obtained under different confining pressure conditions to eliminate the error of the core sample itself.

[0041] The basic information of the core samples used in this example is shown in Table 1. The clay mineral content of the shale is 57.3%.

[0042] Table 1 Basic Information of Core Samples

[0043] Depth (m) Layer Lithology Porosity (%) Permeability (mD) 3383.48 Thousand One Section 3b Small Layer shale 3.19 0.0675

[0044] Specifically, the experimental temperature was set to 82.71℃. The confining pressure was set to 14MPa using a confining pressure system, and a vacuum pump was used to evacuate the rock sample. After the pressure gauge reading reached -0.101MPa, evacuation continued for 6 hours. Nuclear magnetic resonance (NMR) scanning was performed to obtain the initial T2 NMR spectrum of the core.

[0045] (2) Using a gas-phase injection system, methane was injected into the core at a constant pore pressure designed for the experiment, so that the rock sample was completely saturated with methane. Nuclear magnetic resonance (NMR) scans were performed to obtain the NMR T2 spectra under the corresponding confining pressure conditions.

[0046] Specifically, due to the extremely low porosity and permeability of shale cores, the pressure value for core permeation was set as the pore pressure value, based on the ability of methane gas to be injected into the core. Methane was injected into the core at a constant pressure of 11.63 MPa. When the pressure gauge reading changed by less than 0.0069 MPa within 5 minutes, the rock sample was completely saturated with methane. Nuclear magnetic resonance (NMR) scanning was performed, and the T2 NMR spectrum under a confining pressure of 14 MPa was obtained.

[0047] The pressure gauge reading at the outlet end is used to determine whether the core has been cleared. After vacuuming, the pressure gauge reading is -0.101 MPa. Once the core has been cleared, the reading will gradually increase until it matches the pressure gauge reading at the inlet end.

[0048] (3) Keep the pore pressure constant according to the experimental requirements, increase the confining pressure point by point, and perform NMR scanning after the pressure stabilizes to obtain NMR T2 spectra under different confining pressure conditions. Since net effective pressure = confining pressure - pore pressure, a curve of T2 peak area changing with net effective pressure can be constructed.

[0049] The confining pressure needs to be at least 1.38 MPa higher than the pore pressure. Considering the actual production pressure difference of 6 MPa, the minimum confining pressure corresponding to a pore pressure of 11.63 MPa is set to 18 MPa. The maximum pressure that the experimental equipment can withstand is 60 MPa; for experimental safety, the maximum confining pressure is set to 53 MPa. The net pressure corresponding to a confining pressure of 53 MPa is 41.37 MPa, which is close to the original formation pressure of 44.5 MPa.

[0050] In this embodiment, the pore pressure was kept constant at 11.63 MPa, and the confining pressure was increased to 18 MPa, 23 MPa, 28 MPa, 33 MPa, 38 MPa, 43 MPa, 48 MPa, and 53 MPa. After the pressure stabilized, NMR scans were performed to obtain the NMR T2 spectra under different confining pressure conditions, as shown in the appendix. Figure 2 .

[0051] The constructed curve of T2 peak area versus net effective pressure is shown below. Figure 3 As shown.

[0052] (4) Based on the ideal gas law PV=ZnRT, conduct methane calibration experiments according to the NMR calibration experimental specifications, and establish the relationship between the T2 peak area and the number of moles of methane gas (see appendix). Figure 4 The number of moles of methane gas in shale pores can be characterized by the T2 peak area.

[0053] n = 0.00002 * Q

[0054] In the formula, P is the pressure, MPa; V is the gas volume, m³. 3T is temperature, K; n is the number of moles of gas, mol; R is the gas constant, R = 0.008314 MPa·m 3 / (kmol·K); Q is the area of ​​the T2 peak, au.

[0055] The correspondence between the T2 peak area and the number of methane moles in the core pores was established by nuclear magnetic resonance calibration experiments. The relevant experimental specifications and operations are existing technologies. The technical principles and specific operation methods can be found in the following existing technologies: Oil and water dynamic calibration method and application based on LF-NMR in core displacement experiments [J]. Petroleum Drilling and Production Technology, 2020, 42(02):181-188.

[0056] The results of the methane calibration experiment are shown in Table 2.

[0057] Table 2. Methane calibration experimental data

[0058] Pressure (MPa) Compression factor (Z) <![CDATA[Peak area of T2]]> Number of moles of methane (mol) 6.00 0.9042 5050.226 0.1083 5.02 0.9175 4312.627 0.0893 4.00 0.9342 3431.729 0.0699 3.02 0.9493 2594.326 0.0519 2.00 0.9663 1711.160 0.0338 1.00 0.9828 849.943 0.0166

[0059] (5) The formula for calculating the rock pore compressibility coefficient is: The pore compressibility coefficient C of shale can be calculated by combining it with the ideal gas law PV=ZnRT. p (Appendix) Figure 5 ):

[0060]

[0061] In the formula, C p The rock pore compressibility coefficient is expressed in MPa. -1 V p The pore volume of rock under each net effective pressure, m 3 ;dV p / dp represents the change in rock pore volume caused by a change in unit pressure, in m 3 / MPa, where n is the number of gas moles, in mol; p Φ p represents pore pressure, in MPa. e The net effective pressure is expressed in MPa. In the final formula, Q1 and Q2 represent the T2 peak areas corresponding to two adjacent confining pressure points, respectively; p1 and p2 represent the net effective pressures corresponding to two adjacent confining pressure points, respectively, in MPa.

[0062] Using the method of this invention, the following can be obtained: Figure 5 The curve of shale pore compressibility is shown, and the corresponding experimental data of shale pore compressibility are shown in Table 3.

[0063] Table 3 Experimental data on shale porosity compressibility

[0064]

[0065] According to Table 3, for the Puluye 1HF well, the original formation pressure is 44.5 MPa, and the compressibility coefficient at a net effective pressure of 41.37 MPa is 0.09 × 10⁻⁶. -4 MPa -1 .

[0066] Based on the survey, the compressibility coefficients of common mineral particles and soils are shown in Table 4.

[0067] Table 4 Compression Coefficients of Common Mineral Particles and Soils

[0068]

[0069]

[0070] In Table 4, the compressibility coefficient of shale is 0.32-1.97×10. -4 MPa -1 The results are basically consistent with the calculation results of this embodiment. Furthermore, the method of this invention has been applied to the determination of core samples from the Qianfoya shale gas reservoir in Puguang, providing a basis and guidance for the evaluation of elastic production capacity and the calculation of dynamic geological reserves in shale reservoirs. This has enabled the rational and efficient development of the target gas reservoir, and the feasibility and reliability of the determination method have been proven in practice.

Claims

1. A method for determining the pore compressibility coefficient of shale, characterized in that, Includes the following steps: S1: After vacuuming the shale core to be tested, perform nuclear magnetic resonance scanning to obtain the initial nuclear magnetic resonance T2 spectrum of the core; S2: Alkane gas was injected into the core at the experimentally designed pore pressure. After the pressure stabilized under the initial confining pressure, nuclear magnetic resonance (NMR) scanning was performed to obtain the NMR T2 spectrum under the corresponding confining pressure conditions. S3: Keep the pore pressure constant, gradually increase the confining pressure point according to the experimental design, and perform NMR scanning after the pressure stabilizes to obtain NMR T2 spectra under different confining pressure conditions; construct the curve of T2 peak area of ​​NMR T2 spectra as a function of net effective pressure; wherein the net effective pressure = confining pressure - pore pressure; S4: Conduct alkane gas calibration experiments and determine the fitting relationship between the T2 peak area and the number of moles of alkane gas based on the ideal gas law; S5: Based on S3 and S4, establish the calculation formulas for shale pore compressibility coefficient, net effective pressure, and T2 peak area, and determine the shale pore compressibility coefficient under different net effective pressures according to the calculation formulas.

2. The method for determining the pore compressibility coefficient of shale as described in claim 1, characterized in that, In step S2, the alkane gas is methane.

3. The method for determining the pore compressibility coefficient of shale as described in claim 2, characterized in that, In step S4, the fitting relationship is a proportional relationship.

4. The method for determining the pore compressibility coefficient of shale as described in claim 3, characterized in that, In step S5, the calculation formula is: Among them, C p The rock pore compressibility coefficient is expressed in MPa. -1 Q1 and Q2 are the T2 peak areas corresponding to two adjacent confining pressure points, respectively; p1 and p2 are the net effective pressures corresponding to two adjacent confining pressure points, respectively, in MPa.

5. The method for determining the pore compressibility coefficient of shale as described in claim 1, characterized in that, The shale is a high-clay shale with a clay content of ≥40%.

6. The method for determining the pore compressibility coefficient of shale as described in claim 1, characterized in that, In steps S2 and S3, the experimental temperature is the temperature of the formation where the core is located.

7. The method for determining the pore compressibility coefficient of shale as described in claim 1, characterized in that, In steps S2 and S3, the pressure stabilization means that the pressure change is within 0.0069 MPa within 5 minutes.

8. The method for determining the pore compressibility coefficient of shale as described in claim 1, characterized in that, In step S1, the vacuuming includes evacuating to a vacuum level of -0.101 MPa and then evacuating for at least 4 hours.

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