Method for evaluating properties of medium-low-maturity shale oil in-situ modified reservoir

Abstract

The invention belongs to the technical field of unconventional oil and gas resource development, and particularly discloses a medium-low-maturity shale oil in-situ modified reservoir property evaluation method which comprises the steps of sample selection, diagenesis simulation, thermal simulation sample porosity testing, thermal simulation sample nuclear magnetic analysis pore structure and quantitative identification of thermal simulation sample fracture development. And finally, determining the optimal heating temperature and heating rate parameters of in-situ conversion, evaluating the in-situ modification effect of the shale reservoir, and establishing a quantitative evaluation scheme for the in-situ modification of the reservoir. The present advanced testing and in-situ characterization technologies are fully combined, the method for evaluating the properties of the medium-low-maturity shale oil in-situ modified reservoir is provided, the problem of in-situ observation in evaluation of the medium-low-maturity shale oil in-situ modified reservoir is solved, the problem that the physical process of a thermal simulation experiment is not visual is effectively solved, and the method is suitable for the evaluation of the properties of the medium-low-maturity shale oil in-situ modified reservoir. Compared with a traditional test method, the method has the advantages of rapidness, no damage, sensitivity and the like.

Description

Technical Field

[0001] The present invention belongs to the technical field of unconventional oil and gas resource development, and in particular relates to a method for evaluating reservoir properties of low-mature shale oil in-situ modified reservoirs. Background Art

[0002] The development of low-middle-mature shale oil is difficult to achieve the expected goals due to the ultra-low porosity and ultra-low permeability of its reservoirs with traditional mining and reservoir evaluation technologies. Therefore, developing an effective method for evaluating the properties of low-middle-mature shale oil in-situ modified reservoirs is of great significance for improving mining efficiency and reservoir property evaluation.

[0003] The evaluation of shale reservoirs is a key link in the in-situ conversion of low-middle-mature shale oil. Effective reservoir evaluation methods are the basis for discussing the physical properties of in-situ conversion of low-middle-mature shale oil. With the shift of oil and gas exploration and development targets to shale oil, the characterization of structures such as pores and fractures has entered the micron stage, forming a shale reservoir system with complex structure and small scale. Accurate and reasonable evaluation methods for the properties of in-situ modified reservoirs of low-middle-mature shale oil are of great significance for the fine characterization of shale reservoirs.

[0004] At present, the research focus of in-situ modification technology for low-middle-mature shale oil is mainly on the underground in-situ shale oil recovery rate, in-situ modification heating time and other issues. However, the temperature and pressure conditions, heating rate and other settings in the in-situ transformation diagenesis simulation of low-middle-mature shale oil, reservoir pore structure, porosity determination and identification of fracture development lack evaluation standards based on quantitative analysis. Shale reservoirs, as one of the focuses of shale research, have the characteristics of low porosity and low permeability, and are dominated by nanoscale pore throat systems. They can be used as unconventional oil and gas reservoirs with continuous distribution of self-generation and self-storage. The current in-situ conversion methods for low-middle-mature shale oil mainly use the classic kerogen pyrolysis theory proposed by Tissot et al. (1974) and the temperature-time compensation principle proposed by Connan (1976) in the famous petroleum journal AAPG to conduct thermal simulation experiments on samples. The main problems are as follows: (1) Currently, most thermal simulation experiments use powdered samples without preserving the rock structure. These samples are easily directly affected by the confining pressure during the thermal simulation experiment, and the simulation results differ from the actual in-situ conditions underground.

[0005] (2) The thermal simulation experimental samples have problems such as strong shale sample heterogeneity and the lack of visualization of the thermal simulation physical process. It is impossible to quantitatively observe the in-situ changes of shale reservoirs such as fractures in the same sample and the same field of view. Summary of the invention

[0006] At present, the main methods for measuring rock porosity are drainage method, gas expansion method, nuclear magnetic resonance method, X-ray tomography method and neutron logging method. Different measurement methods have different ranges of pore size. Since shale particles are very small and very dense, the range of shale pore diameters varies greatly, from nanometers to tens of microns, spanning 4-6 orders of magnitude, and the pore diameters are concentrated above 2nm. At present, there is no holographic characterization method for shale pores, which means that there is no method that can measure absolutely accurately. This is also the technical bottleneck faced by the current academic and industrial circles. Nuclear magnetic technology is currently a common industry practice for measuring shale porosity. It can measure pores above 2nm, which account for the vast majority of shale pores.

[0007] The present invention, taking full account of the diagenetic simulation process and the strong heterogeneity of shale, proposes an evaluation method based on the quantitative analysis of reservoir properties of in-situ modified medium and low-maturity shale oil under the constraints of actual geological conditions, and quantitatively analyzes and evaluates the pore structure, porosity measurement and degree of fracture development of the shale reservoir. When measuring the porosity of shale after modification at different temperatures, the same test method is used to effectively compare the effects of shale reservoir modification, thereby solving the technical problem in the prior art that accurate evaluation cannot be made due to limitations such as insufficient precision of experimental equipment, obsolete experimental methods and susceptibility to interference.

[0008] The present invention integrates the setting of diagenetic simulation conditions and technologies such as nuclear magnetic resonance to perform fine characterization of shale reservoirs. The specific method is as follows: Step S1: Sample selection Organic-rich shales (TOC>2%) suitable for in-situ conversion were selected, and cylindrical samples were drilled vertically through the shale layers using a desktop mechanical drill. Water was avoided as much as possible to prevent microcracks from forming between water and rock. After the above samples were prepared, the remaining original rock samples were crushed for rock pyrolysis, total organic carbon content (TOC), mineral X-ray diffraction analysis (XRD), and other mineral deposit, petrology, and geochemical analyses.

[0009] Step S2: Diagenetic simulation In order to simulate the hydrocarbon generation and expulsion process of low-mature organic-rich shale in situ underground as much as possible, this step needs to comprehensively consider the experimental conditions such as reaction system, heating rate, constant temperature time, fluid medium, pressure, etc. Cylindrical samples without obvious cracks are selected, and quantitative analysis such as shale oil yield is carried out using high-temperature and high-pressure reactors, Soxhlet extractors and other equipment.

[0010] Step S3: Thermal simulation sample porosity test The porosity of shale samples is measured based on Nuclear Magnetic Resonance (NMR) technology. As a rapid non-destructive testing technology, NMR can also effectively reflect the "in-situ" nature of reservoir porosity.

[0011] In this step, the thermal simulation samples and original rocks obtained in step 2 are dried for 24 hours on the basis of Soxhlet extraction. The dried samples are saturated with oil (actually, the process of injecting crude oil into the core). To reduce other influences, all samples are pressurized and saturated for 72 hours to ensure that there is no residue in the core. The macroscopic magnetic vector of the nuclear magnetic resonance of the saturated oil sample is proportional to the volume of the fluid contained in the sample. The measured signal amplitude is characterized as the volume of pore fluid, and then the sample porosity is obtained.

[0012] Step S4: NMR analysis of pore structure of thermal simulation samples Conventional experimental testing methods such as mercury intrusion, gas adsorption, CT, scanning electron microscopy, nitrogen intrusion, and small-angle X-ray diffraction cannot fully cover the measurement of pores at different levels in shale reservoirs. Unlike the above traditional testing methods, the use of nuclear magnetic resonance (NMR) technology can identify the pore diameter distribution of samples at different thermal simulation temperature points, and reveal the pore structure of the sample by studying the transverse relaxation time and nuclear magnetic signals. According to the classification scheme of the International Union of Pure and Applied Chemistry (IUPAC), pore sizes can be divided into three types: micropores with a pore size of less than 2nm, macropores with a pore size of more than 50nm, and pore sizes between the two are called mesopores.

[0013] In this step, based on the data obtained in step 3, Excel is used to process the data to obtain an image of the sample signal amplitude and relaxation time. 2 The pore radius of the sample can be obtained by properly processing the spectrum curve image.

[0014] Step S5: Quantitative identification of crack development in thermal simulation samples The images of in-situ heating cracks of low-mature shale samples were captured using a Pco edge 5.5 high-resolution camera and a diode laser heating system. In the experiment, the captured images were processed using synchrotron X-ray tomography, digital volume correlation (DVC) technology, and Avizo 9.0 program to obtain in-situ dynamic change images of the cracks in the thermal simulation samples.

[0015] Step S6: Establishing a quantitative evaluation scheme for in-situ reservoir improvement S61. Determine the optimal heating temperature and heating rate parameters for in-situ conversion This process requires the use of the experimental test results of the diagenetic simulation process in step S2 to quantitatively determine the optimal heating temperature, taking the shale oil yield as the direct result of the in-situ conversion of medium- and low-maturity shale oil, and taking the highest value of shale oil yield as the optimal heating temperature point, and subsequent evaluation uses this as the standard.

[0016] S62. Evaluation of in-situ modification effect of shale reservoir This process requires the use of the shale reservoir porosity test results in step S3, the pore structure changes in steps S4 and S5, and the dynamic changes of pyrolysis cracks, combined with the diagenetic simulation results in step S2, to compare the reservoir properties and shale oil yield of the shale original rock sample.

[0017] In the prior art, the in-situ conversion method of low-middle-mature shale oil has always used the classic kerogen pyrolysis theory proposed by Tissot et al. (1974) and the temperature-time compensation principle proposed by Connan (1976) to carry out indoor high-temperature and high-pressure thermal simulation experiments of organic-inorganic interactions. On the one hand, this method has the disadvantage that the reservoir evaluation equipment is single-function; on the other hand, it has the disadvantage that the physical characteristics of the thermal simulation experiment are not visualized, which lags behind the current advanced in-situ characterization and quantitative analysis technology, and it is difficult to meet the research requirements of reservoir evaluation after in-situ modification of low-middle-mature shale oil. The present invention fully combines the current advanced testing and in-situ characterization technology, and proposes a method for evaluating the properties of in-situ modified reservoirs of low-middle-mature shale oil, which solves the problem of in-situ observation in the evaluation of shale reservoirs for in-situ conversion of low-middle-mature shale oil.

[0018] The present invention has the following beneficial effects: (1) The traditional sample selection is changed from powder samples to cylindrical samples, and thermal simulation experiments are carried out based on cylindrical samples, which are more in line with underground in-situ conditions.

[0019] (2) The nuclear magnetic resonance (NMR) technology is used to measure the porosity of shale reservoirs and characterize the pore throat structure. Compared with other testing methods, it has the advantages of being fast, non-destructive, and sensitive.

[0020] (3) Based on the Pco edge 5.5 high-resolution camera and the diode laser heating system, the in-situ dynamic change images of the cracks in the shale reservoir are captured and processed, which makes up for the bottleneck of the traditional high-pressure autoclave "black box", effectively solves the problem of the non-visualization of the physical process of the thermal simulation experiment, and realizes "in-situ" visual observation. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Figure 1 The sample image of the processed shale core of Liye XX well provided in the example of the present invention; Figure 2 The nuclear magnetic resonance T2 spectrum of the Liye XX well sample provided by the example of the present invention; Figure 3 A plan view of the shale in-situ heating observation device provided for an example of the present invention. DETAILED DESCRIPTION

[0022] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0023] This implementation method is aimed at a certain group of shale in the Paleogene of the Bohai Bay Basin, and the Liye XX well with complete data is selected as the research object for detailed description. The shale in this layer has low maturity and high TOC content, which provides a good basis for the verification of the invention. The specific implementation steps are as follows: Step S1: Sample processing

[0024] like Figure 1 As shown in the figure, this study first prepared samples of the Paleogene organic-rich shale from the Liye XX well. The preparation process was a benchtop mechanical drilling machine, and the finished cylindrical sample had a diameter of 1 cm. After the above samples were prepared, the remaining original rock samples were crushed and subjected to rock pyrolysis, total organic carbon content (TOC), mineral X-ray diffraction analysis (XRD) and other mineral deposit, petrology and geochemical tests.

[0025] The organic carbon content test was carried out using a CS-239 carbon analyzer in accordance with the national standard GB / T 19145-2022 Determination of total organic carbon in sedimentary rocks; the rock pyrolysis test was carried out using a ROCK-EVAL 6 rock pyrolyzer in accordance with the national standard GB / T 18602-2012 "Rock Pyrolysis Analysis"; the whole rock XRD test was carried out using a German Bruker D8AA25 X-ray analyzer in accordance with the CNPC standard SY / T 5163-2018 "X-ray Diffraction Analysis Method for Clay Minerals and Common Non-Clay Minerals in Sedimentary Rocks". The test results are shown in Table 1.

[0026] ;

[0027] Step S2: Diagenetic simulation In order to simulate the hydrocarbon generation and expulsion process of low-mature organic-rich shale in situ underground as much as possible, this step needs to comprehensively consider the experimental conditions such as reaction system, heating rate, constant temperature time, fluid medium, pressure, etc. Cylindrical samples without obvious cracks are selected, and quantitative analysis such as shale oil yield is carried out using high-temperature and high-pressure reactors, Soxhlet extractors and other equipment.

[0028] (1) Reaction system At present, thermal simulation experiments are usually divided into open systems, semi-open systems and closed systems according to different experimental systems. Under geological conditions, the hydrocarbon generation and expulsion process of source rocks is a system of simultaneous generation and expulsion, so the simulation experiment uses a semi-open system to more realistically reflect the underground in-situ geological conditions.

[0029] (2) Heating rate and constant temperature time At present, the heating rate of 0.2-1.0℃ / d is generally used for in-situ conversion of shale oil. Taking the Green River Formation shale in the United States as an example, the heating rate set by Shell in in-situ conversion is about 0.5℃ / d.

[0030] The patent experiment is set to quickly heat up from room temperature to 200°C at 40°C / h. When it is above 200°C, it is set at 20°C / h, and the temperature is kept constant for 12 hours after reaching the target temperature.

[0031] (3) Fluid medium Considering that the water evaporates after the sample is extracted from the underground, while the main salt remains inside the sample, it is chosen to add 50% of the sample mass to replenish the lost water.

[0032] (4) Pressure During the experiment, when oil is cracked into natural gas, abnormally high pressure will be generated and exceed the static rock pressure, especially under closed and high temperature conditions. During the experiment, no pressure was applied.

[0033] The specific experimental results obtained from the above steps are shown in Table 2.

[0034] ; Step S3: Thermal simulation sample porosity test

[0035] The experimental instrument is MicroMR20-025V nuclear magnetic analyzer, with a main frequency of 20MHz and a probe coil diameter of 25mm. 2 The spectrum experiment adopts CPMG sequence with the following sequence parameters: sampling frequency is 250kHz, main value of video signal frequency (SF) is 20MHz, video signal offset (O1) is 510432.56Hz, pulse width of 90° (P1) is 7.20μs, pulse width of 180° (P2) is 11.44μs, digital gain (DRG1) is 3, analog gain (RG1) is 10db, data radius (DR) is 1, number of echoes (NECH) is 6000, and preamplifier gear is 1.

[0036] Before testing, the samples were subjected to Soxhlet extraction, drying, and oil saturation. The samples after thermal simulation were subjected to Soxhlet extraction using dichloromethane, and the duration was set to 72 hours. The extracted samples were dried for 24 hours at room temperature and in a dry environment. The dried samples were saturated with oil (actually, the process of injecting crude oil into the core). To reduce other influences, all samples were pressurized and saturated for 72 hours to ensure that there was no residue in the core.

[0037] The treated samples were tested based on the nuclear magnetic resonance (NMR) technique. The macroscopic magnetization vector of the saturated oil sample is proportional to the volume of the fluid contained in the sample. The measured signal amplitude is characterized as the pore fluid volume, and the sample porosity is then obtained, as shown in Table 3.

[0038] ; Step S4: NMR analysis of pore structure of thermal simulation samples

[0039] The nuclear magnetic resonance (NMR) technique is used to identify the pore diameter distribution of shale reservoirs at different thermal simulation temperature points, and the pore structure of shale reservoirs is revealed by studying the transverse relaxation time and NMR signals.

[0040] Based on the data obtained in step S3, the data is processed using Excel to obtain images of sample signal amplitude and relaxation time ( Figure 2 ). Through the hole T 2 The spectral curve image is properly processed to obtain the pore radius of the sample.

[0041] It is generally believed that the relaxation model in the pore (4-1) is: ; Where, T 2 is the relaxation time of the fluid in the pore, T 2S is the surface relaxation time, T 2B is the volume relaxation time, T 2D is the diffusion relaxation time.

[0042] In the low-field NMR experiment, the external magnetic field is relatively uniform. Free relaxation is mainly determined by the physical properties of the fluid and is an inherent relaxation characteristic. Diffusion relaxation is caused by the self-diffusion movement of hydrogen molecules in the gradient magnetic field. This patent uses CPMG pulse sequence measurement to minimize the impact of diffusion relaxation. Therefore, T 2 The overall contribution is from surface relaxation. 2 The distribution can be converted into pore size distribution according to formula 4-2.

[0043] ; In the formula, ρ 2 is the surface relaxation rate coefficient, nm / ms; S is the total surface area of ​​rock pores, nm 2 ; V is the pore volume, nm 3 ; r is the pore radius, μm; FS is the pore shape factor.

[0044] From formula 4-2, we can see that T 2It is positively correlated with pore volume and pore radius, and negatively correlated with pore area. Therefore, T 2 spectrum to reflect other parameters such as pore radius, and T 2 The spectrum can also reflect the number of pores of different radii using signal intensity.

[0045] Step S5: Quantitative identification of crack development in thermal simulation samples Using Pco edge 5.5 model high resolution camera, diode heating system ( Figure 3 ) etc. to capture images of in-situ heated cracks in low-mature shale samples. The captured images were processed using synchrotron X-ray tomography, digital volume correlation (DVC) technology and Avizo 9.0 program etc. to obtain in-situ dynamic change images of cracks in thermal simulation samples.

[0046] Step S6: Establishing a quantitative evaluation scheme for in-situ reservoir improvement According to the evaluation scheme, the standards are formulated, and the experimental results of step S2 and other steps are used as the evaluation scheme for the in-situ conversion of low- and medium-maturity shale oil. The temperature point corresponding to the maximum shale oil yield is used as the optimal heating temperature point for in-situ conversion.

[0047] The porosity test comparison results of the shale reservoir after in-situ modification obtained in step S3 and the original rock and the dynamic changes of pores and fractures in steps S4 and S5 are compared. By comparing the changes in the physical properties of the shale reservoir at different temperature points of thermal simulation, especially the images of the in-situ dynamic changes of the fractures in step S5, the in-situ modification effect of the shale reservoir is comprehensively evaluated.

[0048] Comparing the evaluation results of this scheme with those of the traditional thermal simulation experimental scheme, it can be seen that in the traditional scheme, the physical characteristics of the thermal simulation experiment are not visualized, and the thermal simulation at different temperature points cannot achieve "in situ" observation of the same sample and the same field of view, and cannot support the fine characterization of the in situ conversion of low-mature shale oil to shale reservoirs. Under the evaluation scheme under this standard, the non-visualization of the physical process of the thermal simulation experiment is effectively solved, and the experimental setting conditions such as the optimal heating temperature for in situ conversion are effectively determined.

[0049] Those skilled in the art should understand that the discussion of the above embodiments is merely illustrative and is not intended to imply that the scope of the present invention (including the claims) is limited to these examples. Under the concept of the present invention, the technical features in the above embodiments or different embodiments may be combined, the steps may be implemented in any order, and there are many other variations of the different aspects of the present invention as described above, which are not provided in detail for the sake of simplicity.

[0050] The present invention is intended to cover all such substitutions, modifications and variations that fall within the broad scope of the appended claims. Therefore, any omissions, modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for evaluating reservoir properties of low-middle-mature shale oil in-situ modification, characterized in that: The following steps are involved: S1. Sample selection Select organic-rich shales suitable for in-situ conversion, prepare cylindrical samples, and use the remaining original rock samples to crush for mineral deposit, petrological and geochemical analysis; S2. Diagenetic simulation Taking into account the reaction system, heating rate, constant temperature time, fluid medium, and pressure experimental conditions, the hydrocarbon generation and expulsion process of low-mature organic-rich shale in situ was simulated, and cylindrical samples without obvious cracks were selected for quantitative analysis of shale oil yield. S3. Thermal simulation sample porosity test The thermal simulation sample and the original rock obtained in step S2 are dried on the basis of Soxhlet extraction, and are saturated with oil under pressure, and the porosity of the saturated oil sample is tested using nuclear magnetic resonance technology; S4. NMR analysis of pore structure of thermal simulation samples Generate a T2 spectrum curve of the sample signal amplitude and relaxation time based on the data obtained in step S3, and use the T2 spectrum curve to analyze the sample pore structure; S5. Quantitative identification of crack development in thermal simulation samples Capture images of in-situ heated cracks in low-mature shale samples, process the captured images, and obtain in-situ dynamic change images of cracks in thermal simulation samples; S6. Establish a quantitative evaluation scheme for in-situ reservoir modification The optimal heating temperature is determined by the experimental test results of the diagenetic simulation process in step S2, the shale oil yield is taken as the direct result of the in-situ conversion of low-mature shale oil, the highest value of the shale oil yield is taken as the optimal heating temperature point, the porosity test comparison results of the shale reservoir after in-situ modification obtained in step S3 and the original rock and the dynamic changes of pores and cracks in steps S4 and S5 are compared, and the changes in the physical properties of the shale reservoir at different temperature points of the thermal simulation are compared, especially the images of the in-situ dynamic changes of the cracks in step S5, and the in-situ modification effect of the shale reservoir is comprehensively evaluated.

2. A method for evaluating reservoir properties of low-middle-mature shale oil in-situ modification, characterized in that: In the step S1, when preparing the cylindrical sample, avoid using water to prevent the water from interacting with the rock to generate micro cracks.

3. A method for evaluating reservoir properties of low-middle-mature shale oil in-situ modification, characterized in that: In the step S1, the TOC of the low-maturity organic-rich shale is greater than 2%, and the mineral deposit, petrology and geochemistry analysis include rock pyrolysis, total organic carbon content TOC, and mineral X-ray diffraction analysis XRD.

4. A method for evaluating reservoir properties of low-middle-mature shale oil in-situ modification, characterized in that: In step S2, the reaction system uses a semi-open system to truly reflect the underground in-situ geological conditions. The heating rate is rapidly increased to 200°C at 40°C / h. When it is above 200°C, the temperature is continued to be increased at 20°C / h. After reaching the target temperature point, the temperature is kept constant for 12 hours. The fluid medium replenishes the lost water with 50% of the sample mass, and the pressure is selected not to apply pressure.

5. A method for evaluating reservoir properties of low-middle-mature shale oil in-situ modification, characterized in that: In step S3, the drying time of the thermal simulation sample and the original rock is 24 hours, and the oil immersion and pressurized saturation time is 72 hours.

6. A method for evaluating reservoir properties of low-middle-mature shale oil in-situ modification, characterized in that: In step S5, a Pcoedge 5.5 high-resolution camera and a diode laser heating system are used to capture images of in-situ heating cracks in low-mature shale samples.

7. A method for evaluating reservoir properties of low-middle-mature shale oil in-situ modification, characterized in that: In step S5, the captured images are processed using synchrotron X-ray tomography, digital volume correlation (DVC) technology and Avizo 9.0 program.

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