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

Abstract

The present application belongs to the technical field of unconventional oil and gas resource development, and specifically discloses a method for evaluating in-situ modification reservoir properties of middle-low mature shale oil, which comprises the following steps: sample selection, diagenetic simulation, thermal simulation sample porosity test, quantitative identification of thermal simulation sample nuclear magnetic analysis pore structure and thermal simulation sample fracture development, final determination of in-situ conversion optimal heating temperature and heating rate parameters, evaluation of shale reservoir in-situ modification effect, and establishment of a quantitative evaluation scheme for reservoir in-situ modification. The method for evaluating in-situ modification reservoir properties of middle-low mature shale oil is fully combined with advanced current testing and in-situ characterization technology, solves the problem of in-situ observation in the evaluation of in-situ conversion shale reservoir of middle-low mature shale oil, effectively solves the problem of non-visualization of the physical process of thermal simulation experiment, realizes the visualized observation of in-situ, and has the advantages of rapidness, non-damage, sensitivity and the like compared with the traditional testing method.

Description

Technical Field

[0001] This invention belongs to the field of unconventional oil and gas resource development technology, and in particular relates to a method for evaluating the properties of in-situ upgraded shale oil reservoirs of medium and low maturity. Background Technology

[0002] Due to the ultra-low porosity and ultra-low permeability characteristics of medium- and low-maturity shale oil reservoirs, traditional extraction and reservoir evaluation technologies struggle to achieve the desired results. Therefore, developing an effective in-situ reservoir property evaluation method for medium- and low-maturity shale oil is of great significance for improving extraction efficiency and reservoir property assessment.

[0003] Shale reservoir evaluation is a crucial step in the in-situ conversion of medium- and low-maturity shale oil, and effective reservoir evaluation methods are fundamental to discussing the reservoir properties of medium- and low-maturity shale oil in-situ conversion. As oil and gas exploration and development targets shift towards shale oil, the characterization of structures such as pores and fractures has entered the micron stage, resulting in complex, small-scale shale reservoir systems. Accurate and reasonable evaluation methods for the properties of medium- and low-maturity shale oil in-situ upgraded reservoirs are of great significance for conducting fine-grained characterization of shale reservoirs.

[0004] Currently, research on in-situ upgrading technology for medium- and low-maturity shale oil mainly focuses on issues such as underground in-situ shale oil recovery rate and in-situ upgrading heating time. However, the simulation of in-situ transformation of medium- and low-maturity shale oil into lithology lacks quantitatively based evaluation standards for setting temperature and pressure conditions, heating rates, reservoir pore structure, porosity measurement, and fracture development. Shale reservoirs, as one of the key areas of shale research, are characterized by low porosity and low permeability, dominated by nanoscale pore-throat systems, and can serve as unconventional oil and gas reservoirs with continuous self-generated and self-storing distribution. Current methods for in-situ transformation of medium- and low-maturity shale oil mainly utilize the classical kerogen pyrolysis theory proposed by Tissot et al. (1974) and the temperature-time compensation principle proposed by Connan (1976) in the renowned petroleum journal AAPG to conduct thermal simulation experiments on samples. The main problems are as follows:

[0005] (1) Most thermal simulation experiments currently select powdered samples, which do not preserve the rock structure. During the thermal simulation experiment, the samples are easily affected by the confining pressure, and the simulation results differ from the actual underground conditions.

[0006] (2) The thermal simulation test samples have problems such as strong heterogeneity of shale samples and lack of visualization of thermal simulation physical processes, making it impossible to quantitatively observe the in-situ changes of shale reservoirs such as cracks in the same sample and the same field of view. Summary of the Invention

[0007] Currently, the main methods for measuring rock porosity include the drainage method, gas expansion method, nuclear magnetic resonance (NMR) method, X-ray tomography (XMT) method, and neutron logging method. Different methods measure different ranges of pore size. Because shale particles are extremely small and dense, the pore diameter range varies greatly, from nanometers to tens of micrometers, spanning 4-6 orders of magnitude. However, the pore diameter is concentrated above 2 nm. Currently, no holographic characterization method for shale porosity has been established, meaning no single method can measure it with absolute accuracy. This is a current technological bottleneck faced by both academia and industry. Nuclear magnetic resonance (NMR) is the industry-standard method for measuring shale porosity, capable of measuring the vast majority of shale pores larger than 2 nm.

[0008] This invention, taking into full account the diagenetic simulation process and the strong heterogeneity of shale, proposes an evaluation method for quantitative analysis of the properties of in-situ upgraded shale oil reservoirs under actual geological conditions. This method quantitatively analyzes and evaluates the pore structure, porosity, and fracture development of shale reservoirs. When measuring the porosity of shale after different temperature-treated shale, the same testing method is used to effectively compare the effects of shale reservoir treatment. This solves the technical problem in existing technologies where inaccurate evaluation is impossible due to insufficient precision of experimental equipment, outdated experimental methods, and susceptibility to interference.

[0009] This invention integrates diagenetic simulation conditions and techniques such as nuclear magnetic resonance (NMR) to perform fine characterization of shale reservoirs. The specific method is as follows:

[0010] Step S1: Sample Selection

[0011] Select organic-rich shale (TOC > 2%) suitable for in-situ transformation, and drill cylindrical samples perpendicular to the shale bedding using a benchtop mechanical drill, avoiding the use of water as much as possible to prevent micro-fractures caused by water-rock interaction. After preparing the above samples, take the remaining original rock samples, crush them, and perform mineralogy, petrological, and geochemical analyses such as rock pyrolysis, total organic carbon (TOC) content, and mineral X-ray diffraction (XRD).

[0012] Step S2: Diagenetic Simulation

[0013] To simulate the in-situ hydrocarbon generation and expulsion process of organic-rich, low-maturity shale underground as closely as possible, this step requires comprehensive consideration of experimental conditions such as the reaction system, heating rate, isothermal time, fluid medium, and pressure. Cylindrical samples without obvious cracks are selected, and quantitative analyses of shale oil yield are performed using equipment such as high-temperature, high-pressure reactors and Soxhlet extractors.

[0014] Step S3: Porosity test of thermally simulated sample

[0015] The porosity of shale samples was determined using nuclear magnetic resonance (NMR) technology. NMR is a rapid, non-destructive testing technique that can effectively reflect the "in-situ" nature of reservoir porosity.

[0016] In this step, the thermally simulated samples and original rock obtained in step 2 are dried for 24 hours after Soxhlet extraction. The dried samples are then saturated with oil (essentially, crude oil is injected into the core). To minimize other influences, all samples are pressurized and saturated together for 72 hours to ensure no core residue remains. The macroscopic magnetization vector of the saturated oil sample via nuclear magnetic resonance is proportional to the volume of fluid contained in the sample. The measured signal amplitude is then used to characterize the pore fluid volume, thereby determining the sample porosity.

[0017] Step S4: Thermal simulation of sample NMR analysis of pore structure

[0018] Conventional experimental testing methods such as mercury intrusion porosimetry, gas adsorption, CT, scanning electron microscopy, nitrogen intrusion, and small-angle X-ray diffraction cannot fully cover the different levels of pore size in shale reservoirs. Unlike these traditional methods, nuclear magnetic resonance (NMR) technology can identify the pore diameter distribution of samples at different thermal simulation temperatures, revealing the pore structure by studying transverse relaxation times and NMR signals. According to the classification scheme of the International Union of Pure and Applied Chemistry (IUPAC), pore size can be divided into three types: micropores (smaller than 2 nm), macropores (larger than 50 nm), and mesopores (pore sizes between the two).

[0019] Based on the data obtained in step 3, this step uses Excel to process the data and obtain an image of the sample signal amplitude versus relaxation time. By appropriately processing the T2 spectrum image, the sample pore radius can be obtained.

[0020] Step S5: Quantitative identification of crack development in thermally simulated samples

[0021] Images of in-situ heated fractures in medium- to low-maturity shale samples were captured using a Pco Edge 5.5 high-resolution camera and a diode laser heating system. In the experiment, synchrotron X-ray tomography, digital volume correlation (DVC) technology, and the Avizo 9.0 program were used to process the captured images, obtaining in-situ dynamic changes in the fractures of the thermally simulated samples.

[0022] Step S6: Establish a quantitative evaluation scheme for in-situ reservoir upgrading.

[0023] S61. Determine the optimal heating temperature and heating rate parameters for in-situ conversion.

[0024] This process requires the experimental test results of the diagenesis simulation process in step S2 to quantitatively determine the optimal heating temperature. The shale oil yield is taken as the direct result of the in-situ conversion of medium and low maturity shale oil. The highest value of the shale oil yield is taken as the optimal heating temperature point, and subsequent evaluation is based on this standard.

[0025] S62. Evaluating the effect of in-situ refining in shale reservoirs

[0026] This process requires using the shale reservoir porosity test results from step S3 and the changes in pore structure and dynamic changes in pyrolysis fractures from steps S4 and S5, combined with the diagenetic simulation results from step S2, and comparing them with the reservoir properties and shale oil yield of the proto-shale samples.

[0027] In existing technologies, in-situ conversion methods for medium- and low-maturity shale oil have consistently relied on the classical kerogen pyrolysis theory proposed by Tissot et al. (1974) and the temperature-time compensation principle proposed by Connan (1976) to conduct indoor high-temperature, high-pressure organic-inorganic interaction thermal simulation experiments. This method suffers from two drawbacks: firstly, the reservoir evaluation equipment is limited to single-function components; secondly, the physical characteristics of the thermal simulation experiments are not visualized, lagging behind current advanced in-situ characterization and quantitative analysis techniques, making it difficult to meet the research requirements for reservoir evaluation after in-situ upgrading of medium- and low-maturity shale oil. This invention, by fully integrating current advanced testing and in-situ characterization technologies, proposes a method for evaluating the properties of in-situ upgraded reservoirs of medium- and low-maturity shale oil, solving the problem of in-situ observation in the evaluation of shale reservoirs transformed from medium- and low-maturity shale oil.

[0028] The present invention has the following beneficial effects:

[0029] (1) The traditional sample selection is changed from powder sample to cylindrical sample. The thermal simulation experiment based on the cylindrical sample is more in line with the underground in-situ conditions.

[0030] (2) The porosity determination and fine characterization of pore throat structure of shale reservoirs based on nuclear magnetic resonance (NMR) technology have the advantages of being fast, non-destructive and sensitive compared with other testing methods.

[0031] (3) Based on the Pco edge 5.5 high-resolution camera and diode laser heating system, the in-situ dynamic change images of fractures in shale reservoirs were captured and processed, which made up for the bottleneck of the traditional high pressure vessel "black box", effectively solved the problem of the lack of visualization of the physical process of thermal simulation experiment, and realized "in-situ" visualization observation. Attached Figure Description

[0032] Figure 1 A sample image of the processed shale core from Well XX provided as an example of the present invention;

[0033] Figure 2 The nuclear magnetic resonance T2 spectrum of the sample from well XX provided as an example of this invention;

[0034] Figure 3 A plan view of the shale in-situ heating and observation device provided as an example of the present invention. Detailed Implementation

[0035] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0036] This implementation method focuses on a Paleogene shale formation in the Bohai Bay Basin, using the Liye XX well, which has complete data, as the research object for detailed explanation. This shale formation has low maturity and high TOC content, providing a good foundation for verifying the invention. The specific implementation steps are as follows:

[0037] Step S1: Sample processing

[0038] like Figure 1 As shown, this study first prepared samples of Paleogene organic-rich shale from the Liye XX well. The preparation process involved a bench drill, resulting in cylindrical samples with a diameter of 1 cm. After preparing the samples, the remaining protolith samples were crushed and subjected to mineralogy, petrology, and geochemistry tests, including rock pyrolysis, total organic carbon (TOC) content, and X-ray diffraction (XRD).

[0039] Organic carbon content was tested using a CS-239 carbon analyzer, according to the national standard GB / T 19145-2022 "Determination of Total Organic Carbon in Sedimentary Rocks"; rock pyrolysis was tested using a ROCK-EVAL 6 rock pyrolysis analyzer, according to the national standard GB / T 18602-2012 "Analysis of Rock Pyrolysis"; whole-rock XRD was performed using a Bruker D8AA25 X-ray analyzer, according to 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.

[0040] ;

[0041] Step S2: Diagenetic Simulation

[0042] To simulate the in-situ hydrocarbon generation and expulsion process of organic-rich, low-maturity shale underground as closely as possible, this step requires comprehensive consideration of experimental conditions such as the reaction system, heating rate, isothermal time, fluid medium, and pressure. Cylindrical samples without obvious cracks are selected, and quantitative analyses of shale oil yield are performed using equipment such as high-temperature, high-pressure reactors and Soxhlet extractors.

[0043] (1) Reaction system

[0044] Currently, based on different experimental systems, thermal simulation experiments are generally divided into open systems, semi-open systems, and closed systems. Under geological conditions, the hydrocarbon generation and expulsion process of source rocks is a system where generation and expulsion occur simultaneously. Therefore, a semi-open system is chosen for simulation experiments to more realistically reflect the in-situ geological conditions underground.

[0045] (2) Heating rate and isothermal time

[0046] Currently, in-situ conversion of shale oil typically employs a heating rate of 0.2-1.0℃ / d. Taking the Green River Formation shale in the United States as an example, Shell sets the heating rate for in-situ conversion to approximately 0.5℃ / d.

[0047] The experimental setup in this patent involves rapidly heating from room temperature to 200℃ at a rate of 40℃ / h. Above 200℃, the temperature is increased at a rate of 20℃ / h, and the temperature is then held constant for 12 hours after reaching the target temperature.

[0048] (3) Fluid medium

[0049] Considering that the water evaporates after the sample is extracted from the ground, while the main salts remain inside the sample, it is chosen to add 50% of the sample mass to replenish the lost water.

[0050] (4) Pressure

[0051] During the experiment, the cracking of oil into natural gas generates abnormally high pressures exceeding the static rock pressure, especially under confined, high-temperature conditions. No pressure was applied during the experiment.

[0052] The specific experimental results obtained from the above steps are shown in Table 2.

[0053] ;

[0054] Step S3: Porosity test of thermally simulated sample

[0055] The experimental instrument was a MicroMR20-025V NMR analyzer with a main frequency of 20MHz and a probe coil diameter of 25mm. The T2 spectrum experiment used the CPMG sequence with the following parameters: sampling frequency of 250kHz, main frequency value of video signal (SF) of 20MHz, video signal offset (O1) of 510432.56Hz, pulse width at 90° (P1) of 7.20μs, pulse width at 180° (P2) of 11.44μs, digital gain (DRG1) of 3, analog gain (RG1) of 10dB, data radius (DR) of 1, number of echoes (NECH) of 6000, and preamplifier level of 1.

[0056] Prior to testing, samples underwent Soxhlet extraction, drying, and oil saturation. Soxhlet extraction was performed on the thermally simulated samples using dichloromethane for 72 hours. The extracted samples were then dried for 24 hours at room temperature and in a dry environment. The dried samples were then saturated with oil (essentially, the process of injecting crude oil into the core). To minimize other influences, all samples were pressurized and saturated together for 72 hours to ensure no residue remained in the core.

[0057] The treated samples were tested using nuclear magnetic resonance (NMR) technology. 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 used to characterize the pore fluid volume, and then the porosity of the sample is obtained, as shown in Table 3.

[0058] ;

[0059] Step S4: Thermal simulation of sample NMR analysis of pore structure

[0060] Nuclear magnetic resonance (NMR) technology was used to identify the pore diameter distribution of shale reservoirs at different thermal simulation temperatures, and the pore structure of shale reservoirs was revealed by studying the transverse relaxation time and NMR signals.

[0061] Based on the data obtained in step S3, the data is processed using Excel to obtain images of the sample signal amplitude and relaxation time. Figure 2 The pore radius of the sample can be obtained by appropriately processing the T2 spectrum image.

[0062] The currently widely accepted relaxation model in pores (4-1) is: ;

[0063] In the formula, T2 is the relaxation time of the fluid in the pores, and T 2S It is the surface relaxation time, T 2B It is the volume relaxation time, T 2DIt is the diffusion relaxation time.

[0064] In low-field NMR experiments, the applied magnetic field is relatively uniform, and free relaxation is mainly determined by the fluid's physical properties, belonging to inherent relaxation characteristics. Diffusion relaxation is caused by the self-diffusion motion of hydrogen-containing molecules in the gradient magnetic field. This patent uses CPMG pulse sequence measurement, which can minimize the influence from diffusion relaxation. Therefore, T2 is generally contributed by surface relaxation, and the sample T2 distribution can be converted into pore size distribution according to Equation 4-2.

[0065] ;

[0066] In the formula, ρ2 is the surface relaxation coefficient in nm / ms; S is the total surface area of ​​the rock pores in nm. 2 V is the pore volume, in nm. 3 ; r is the pore radius, μm; FS is the pore shape factor.

[0067] As shown in Equation 4-2, T2 is positively correlated with pore volume and pore radius, and negatively correlated with pore area. Therefore, the T2 spectrum can be used to reflect other parameters such as pore radius, and the T2 spectrum can also reflect the number of pores with different radii using signal intensity.

[0068] Step S5: Quantitative identification of crack development in thermally simulated samples

[0069] Using a Pco edge 5.5 high-resolution camera and a diode heating system ( Figure 3 Images of in-situ heated fractures in medium- to low-maturity shale samples were captured using techniques such as synchrotron X-ray tomography, digital volume correlation (DVC) technology, and the Avizo 9.0 program. These images were then processed to obtain in-situ dynamic images of the fractures in the thermally simulated samples.

[0070] Step S6: Establish a quantitative evaluation scheme for in-situ reservoir upgrading.

[0071] Based on the evaluation scheme, the experimental results of step S2, etc., are used as the evaluation scheme for the in-situ conversion of medium and low maturity shale oil, and the temperature point corresponding to the highest shale oil yield is taken as the optimal heating temperature point for in-situ conversion.

[0072] The in-situ refining effect of shale reservoirs is comprehensively evaluated by comparing the porosity test results of the in-situ refining and the original shale reservoir obtained in step S3 with the dynamic changes of porosity and fractures in steps S4 and S5, and by comparing the changes of shale reservoir physical properties at different temperature points through thermal simulation, especially the images of the in-situ dynamic changes of fractures in step S5.

[0073] Comparing the evaluation results of this scheme with those of traditional thermal simulation experiments reveals that the physical characteristics of thermal simulation experiments are not visualized in the traditional scheme. Furthermore, different temperature points in the thermal simulation cannot allow for "in-situ" observation of the same sample and the same field of view, thus failing to support the detailed characterization of in-situ conversion of medium- and low-maturity shale oil into shale reservoirs. The evaluation scheme under this standard effectively addresses the lack of visualization of the physical processes in thermal simulation experiments and effectively determines the optimal heating temperature and other experimental setup conditions for in-situ conversion.

[0074] Those skilled in the art should understand that the above embodiments are merely illustrative and are not intended to imply that the scope of the invention (including the claims) is limited to these examples; within the framework of the invention, the technical features of the above embodiments or different embodiments can also be combined, the steps can be implemented in any order, and there are many other variations of the different aspects of the invention as described above, which are not provided in the details for the sake of brevity.

[0075] This 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 this invention should be included within the scope of protection of this invention.

Claims

1. A method for evaluating the properties of in-situ upgraded shale oil reservoirs of medium and low maturity, characterized in that, Includes the following steps: S1. Sample Selection Organic-rich shale suitable for in-situ transformation was selected, cylindrical samples were prepared, and the remaining protolith samples were crushed for mineral deposit geology, petrology and geochemistry analysis. S2, Diagenetic Simulation Taking into account the reaction system, heating rate, isothermal time, fluid medium, and pressure experimental conditions, the in-situ hydrocarbon generation and expulsion process of organic-rich, low-maturity shale was simulated underground. 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 were dried after Soxhlet extraction and then subjected to oil immersion and pressurization saturation. The porosity of the saturated oil sample was tested using nuclear magnetic resonance technology. S4. Pore structure analysis of thermally simulated samples using NMR spectroscopy. Based on the data obtained in step S3, a T2 spectrum curve of the sample signal amplitude and relaxation time is generated, and the sample pore structure is analyzed using the T2 spectrum curve. S5. Quantitative identification of crack development in thermally simulated samples Images of in-situ heated fractures in medium- to low-maturity shale samples were captured, and the captured images were processed to obtain in-situ dynamic change images of fractures in thermally simulated samples. S6. Establish a quantitative evaluation scheme for in-situ reservoir upgrading. The optimal heating temperature was determined based on the experimental test results of the diagenesis simulation process in step S2. Shale oil yield was used as the direct result of in-situ conversion of medium- and low-maturity shale oil. The highest value of shale oil yield was taken as the optimal heating temperature point. The porosity test results of the in-situ modified shale reservoir obtained in step S3 were compared with those of the original shale reservoir, and the dynamic changes of porosity and fractures in steps S4 and S5 were compared. By comparing the changes of shale reservoir properties at different temperature points in thermal simulation, especially the images of the in-situ dynamic changes of fractures in step S5, the effect of in-situ modification of shale reservoir was comprehensively evaluated.

2. A method for evaluating the properties of in-situ upgraded shale oil reservoirs of medium and low maturity, characterized in that, In step S1, when preparing cylindrical samples, water should be avoided to prevent the interaction between water and rock from causing microcracks.

3. A method for evaluating the properties of in-situ upgraded shale oil reservoirs of medium and low maturity, characterized in that... In step S1, the total organic carbon (TOC) of the organic-rich, low-maturity shale is greater than 2%. The mineral deposit geology, petrology, and geochemical analysis include rock pyrolysis, total organic carbon (TOC) content, and mineral X-ray diffraction (XRD) analysis.

4. A method for evaluating the properties of in-situ upgraded shale oil reservoirs of medium and low maturity, characterized in that... In step S2, a semi-open system is selected for the reaction system to truly reflect the in-situ geological conditions underground. The heating rate is 40℃ / h to rapidly increase the temperature to 200℃. When the temperature is above 200℃, the heating rate is increased to 20℃ / h. After reaching the target temperature point, the temperature is kept constant for 12 hours. The fluid medium is 50% of the sample mass to replenish the lost water, and no pressure is applied.

5. A method for evaluating the properties of in-situ upgraded shale oil reservoirs of medium and low maturity, characterized in that... In step S3, the drying time for the thermal simulation sample and the original rock is 24 hours, and the oil immersion pressure saturation time is 72 hours.

6. A method for evaluating the properties of in-situ upgraded shale oil reservoirs of medium and low maturity, characterized in that... In step S5, an in-situ heated crack image of a medium- to low-maturity shale sample is captured using a Pcoedge 5.5 high-resolution camera and a diode laser heating system.

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

Images