High-clay shale oil in-situ reservoir formation dynamic mechanism and mode evaluation method

Abstract

The invention relates to the technical field of unconventional oil-gas exploration, in particular to a high-clay shale oil in-situ accumulation dynamics mechanism and mode evaluation method. The method comprises the following steps: collecting fluid pressure, temperature data, displacement pressure, oiliness, brittleness index, hydrostatic pressure, vitrinite reflectivity and density value of a shale sample at each depth position point of an exploratory well of each exploration point; calculating abnormal sensitivity; further acquiring ground temperature evaluation credibility; obtaining a self-adaptive fitting weight; acquiring the actual fluid pressure of the exploratory well of each survey point at each depth; acquiring the pressure coefficient of the shale sample at each depth position point of the exploratory well of each survey point; obtaining a self-sealing reservoir forming mode and a retention reservoir forming mode of shale oil; based on the vitrinite reflectivity, the oiliness, the brittleness index and the pressure coefficient, a shale oil enrichment area evaluation comprehensive index is constructed, and the in-situ flow of the high-clay shale is evaluated. According to the method, the accuracy of in-situ self-sealing reservoir formation, retention reservoir formation and dynamic mechanism evaluation of the high-clay shale is improved.

Description

Technical Field

[0001] The present application relates to the field of unconventional oil and gas exploration technology, and specifically to the in-situ reservoir dynamics mechanism and model evaluation method of high-clay shale oil. Background Art

[0002] After more than 60 years of development, the Daqing Oilfield has entered the late stages of exploration for conventional oil and gas resources. Unconventional resources, such as the Gulong shale, are crucial for the field's high-quality development. The Gulong shale has an average clay content exceeding 35%, giving it a highly plastic reservoir. Furthermore, the complex lamellae inherent in the Gulong shale make horizontal lamellae highly advantageous channels for fracturing fluid flow. However, the combined effects of clay minerals and the complex lamellae morphology make horizontal fractures difficult to extend, making extraction relatively challenging.

[0003] At present, the research on oil and gas reservoir dynamics mainly focuses on conventional oil and gas and tight oil and gas. The research methods of the two are relatively similar, and both focus more on the analysis of reservoir microscopic pore throat structure, the analysis of the coupling relationship between charging power and pore throat resistance, and the characterization of the drainage system. However, for the Gulong shale oil reservoir, which is a source-reservoir integrated and a large-scale continuous accumulation of primary source and reservoir, there is still a lack of relevant research on the dynamic mechanism and model of self-sealing enrichment of high-clay continental shale oil. This restricts the formation mechanism, controlling factors and in-depth theoretical understanding of shale oil large-scale enrichment areas, large-scale exploration and reserve increase, and efficient mining. Therefore, in response to the above problems, this application proposes a method for evaluating the in-situ dynamic mechanism and model of high-clay shale oil reservoir. Summary of the Invention

[0004] In order to solve the above technical problems, this application provides a high-clay shale oil in situ accumulation dynamics mechanism and model evaluation method to solve the existing problems.

[0005] The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method of this application adopts the following technical solutions:

[0006] One embodiment of the present application provides a method for evaluating the in-situ reservoir dynamics mechanism and model of high-clay shale oil, the method comprising the following steps:

[0007] Collect fluid pressure, temperature data, displacement pressure, oil content, brittleness index, hydrostatic pressure, vitrinite reflectance and density values ​​of shale samples at various depths of exploration wells at each survey point;

[0008] Use curve fitting algorithm combined with mineral database to obtain the prediction curve of exploration wells at each survey point;

[0009] Obtain the abnormal sensitivity of each exploration well at each depth based on the prediction curve and fluid pressure;

[0010] Based on the correlation between the temperature data and fluid pressure of each shale sample and the temperature data and fluid pressure of other shale samples, the reliability of the geothermal assessment at each depth position of the exploration well at each survey point is obtained;

[0011] The depth and fluid pressure of all depth measurement points of the exploration well at each exploration point are processed using a curve fitting algorithm to obtain a measurement curve of the exploration well at each exploration point;

[0012] Based on the difference between the curvature radius of each survey point on the measured curve and the predicted curve, the reliability of the ground temperature assessment and the anomaly sensitivity, the adaptive fitting weight of each depth position point of the exploration well at each survey point is obtained;

[0013] Obtaining a fitting curve for the exploration well at each exploration point based on the depth, fluid pressure, adaptive fitting weight, and the predicted curve of the exploration well at each exploration point; obtaining the actual fluid pressure at each depth of the exploration well at each exploration point based on the fitting curve; and obtaining the pressure coefficient of the shale sample at each depth position of the exploration well at each exploration point based on the actual fluid pressure and hydrostatic pressure;

[0014] Evaluate the in-situ accumulation mode of high-clay shale oil based on the relationship between displacement pressure and actual fluid pressure, and obtain the self-sealing accumulation mode and retention accumulation mode of shale oil;

[0015] A comprehensive evaluation index for shale oil-rich areas was constructed based on vitrinite reflectance, oil content, brittleness index, and pressure coefficient, and the in-situ accumulation dynamics of high-clay shale oil was evaluated.

[0016] Furthermore, the method for obtaining the prediction curve is:

[0017] For the density values ​​of shale samples at various depth points of the exploration wells at each exploration point, the fluid pressure corresponding to the density value of each shale sample is obtained based on the mineral database of the area where each exploration point is located as the standard fluid pressure of the shale sample density value. A curve fitting algorithm is used to perform curve fitting on the depths at various depth points of the exploration wells at each exploration point and the standard fluid pressures of the shale samples at the depths to obtain a prediction curve for the exploration wells at each exploration point.

[0018] Furthermore, the abnormal sensitivity is obtained by:

[0019] Obtaining the tangent slope difference value of each depth position point of the exploration well at each survey point based on the slope of the tangent line of the depth position point on the prediction curve;

[0020] The calculation formula of the abnormal sensitivity is: h =k h ×Δd; where α h k represents the abnormal sensitivity of the fluid pressure at the hth depth position of the exploration well at each survey point; h-1and k h+1 They represent the slope of the tangent line at the h-1th depth point of the exploration well at each exploration point on the prediction curve and the slope of the tangent line at the h+1th depth point of the exploration well at each exploration point on the prediction curve, respectively. Δd represents the absolute value of the difference between the fluid pressure at the hth depth point of the exploration well at each exploration point and the standard fluid pressure of the shale sample at the hth depth point.

[0021] Furthermore, the method for obtaining the tangent slope difference value is:

[0022] For each depth position point of the exploration well at each survey point, the absolute value of the difference between the slope of the tangent line of the previous adjacent depth position point on the prediction curve of the exploration well and the slope of the tangent line of the next adjacent depth position point on the prediction curve of the exploration well is calculated as the difference value of the tangent slope of each depth position point of the exploration well at each survey point.

[0023] Furthermore, the method for obtaining the credibility of the ground temperature assessment is:

[0024] Obtaining characteristic vectors of shale samples at each depth position of the exploration well at each survey point based on temperature data and fluid pressure;

[0025] Obtain the neighborhood of each depth position point of the exploration well at each survey point;

[0026] The calculation formula for the ground temperature assessment credibility is: Where, β h is the reliability of the geothermal assessment of the shale sample at the hth depth position of the exploration well at each exploration point, N is the number of depth positions in the neighborhood of the hth depth position of the exploration well at each exploration point, cos() is the cosine similarity, T i represents the characteristic vector of the shale sample at the i-th depth position in the neighborhood of the h-th depth position of the exploration well at each survey point, T h The characteristic vector of the shale sample at the h-th depth position of the exploration well at each exploration point.

[0027] Furthermore, the method for obtaining the feature vector is:

[0028] For the shale samples at each depth position of the exploration well at each survey point, a vector consisting of the temperature data and fluid pressure of the shale samples is used as a characteristic vector of the shale samples at each depth position.

[0029] Furthermore, the neighborhood is obtained by:

[0030] For each depth position point of the exploration well at each survey point, the area between the depth position points of a preset number closest to the depth position point is taken as the neighborhood of each depth position point.

[0031] Furthermore, the method for obtaining the adaptive fitting weight is:

[0032] Based on the difference between the curvature radius of each survey point on the measured curve and the predicted curve, the credibility of the ground temperature assessment and the anomaly sensitivity, the adaptive fitting coefficient of each depth position point of the exploration well of each survey point is obtained, and the normalized value of the adaptive coefficient is used as the adaptive fitting weight of each depth position point of the exploration well of each survey point.

[0033] Furthermore, the calculation formula of the adaptive fitting coefficient is: Where, ω h represents the adaptive fitting weight of the h-th depth position of the exploration well at each survey point; β h represents the reliability of the geothermal assessment of the shale sample at the hth depth position of the exploration well at each survey point, α h Δρ represents the abnormal sensitivity of the fluid pressure at the hth depth position of each exploration point, h It represents the absolute value of the difference between the curvature radius of the measured curve and the predicted curve of the exploration well at each survey point at the hth depth position; δ is the preset parameter adjustment factor.

[0034] Furthermore, the method for obtaining the fitting curve is:

[0035] For the exploration well at each survey point, the depth, fluid pressure, adaptive fitting weight of all depth position points and the predicted curve of the exploration well at each survey point are used as inputs of the B-spline curve fitting algorithm to obtain the fitting curve of the exploration well at each survey point.

[0036] Furthermore, the actual fluid pressure is obtained by obtaining the fluid pressure at each depth of the exploration well at each survey point on the fitting curve as the actual fluid pressure at the depth of each depth position point.

[0037] Furthermore, the pressure coefficient is obtained by:

[0038] For the shale samples at each depth point of the exploration well at each survey point, the ratio of the actual fluid pressure to the hydrostatic pressure is calculated as the pressure coefficient of the shale samples at each depth point of the exploration well at each survey point.

[0039] Furthermore, the method for obtaining the retention accumulation mode is as follows:

[0040] For the exploration wells at each exploration point, the average of the actual fluid pressure and the average of the displacement pressure at all depth positions of the exploration wells are calculated. When the average of the actual fluid pressure is greater than or equal to the average of the displacement pressure, the exploration wells at the exploration point are in the retention accumulation mode.

[0041] Furthermore, the method for obtaining the self-enclosed reservoir formation mode is as follows:

[0042] When the average value of the actual fluid pressure is less than the average value of the displacement pressure, the exploration well at the survey point is in a self-sealing reservoir formation mode.

[0043] Furthermore, the characteristics of the shale oil in the retention accumulation mode are:

[0044] The average daily production of vertical and inclined wells that retain shale oil is 3.59t / d;

[0045] The retained shale oil is medium-quality oil with a density greater than 0.82 g / cm 3 , the average density is 0.843g / cm 3 ; Average viscosity is 16.24mm 2 / s; the average wax content is 26.48%; the average freezing point is 22.1℃, and the average molecular weight is 391.8g / moL; the saturated hydrocarbon content of the retained shale oil is greater than 70%, the average saturated hydrocarbon content is 79.8%, and the average aromatic hydrocarbon content is 13.5%.

[0046] Furthermore, the self-sealed shale oil reservoir is characterized by:

[0047] The average daily production of vertical wells in self-sealed shale reservoirs is 3.84t / d, the average daily production of horizontal wells is 21.49t / d, and the gas-oil ratio is greater than 100m 3 / m 3 ;

[0048] Self-sealed shale oil is a volatile oil-light oil with a density of less than 0.82g / cm 3 , the average density is 0.80g / cm 3 ;Viscosity less than 10mm 2 / s, average viscosity is 4.35mm 2 / s; wax content is less than 25%, and the average wax content is 20.11%; freezing point is less than 20℃, and the average freezing point is 13.7℃; molecular mass is less than 350g / moL, and the average molecular mass is 310.6g / moL; saturated hydrocarbon content is greater than 80%, and the average saturated hydrocarbon content is 90%; aromatic hydrocarbon content is less than 10%, and the average aromatic hydrocarbon content is 4.5%.

[0049] Furthermore, the formation and evolution characteristics of the self-enclosed and retained reservoir modes are as follows:

[0050] The formation and evolution characteristics of the self-sealed and retained reservoir modes are divided into three stages. The vitrinite reflectance in the first stage is less than 0.9%; the vitrinite reflectance in the second stage is greater than or equal to 0.9% and less than 1.6%; the vitrinite reflectance in the third stage is greater than or equal to 1.6%.

[0051] Furthermore, the occurrence state transformation process between the self-enclosed accumulation mode and the retention accumulation mode is as follows:

[0052] The storage state transformation process between the self-sealed accumulation mode and the retained accumulation mode is divided into two stages. The first stage is the medium-low evolution stage, when the vitrinite reflectance is less than or equal to 1.0%; the second stage is the medium-high evolution stage, when the vitrinite reflectance is greater than 1.0%.

[0053] Furthermore, the construction of a comprehensive evaluation index for shale oil-rich areas includes:

[0054] For shale samples at each depth of the exploration well at each survey point, the product of the vitrinite reflectance and its preset weight coefficient, the product of the oil content and its preset weight coefficient, the product of the brittleness index and its preset weight coefficient, and the product of the pressure coefficient and its preset weight coefficient are calculated respectively, and the sum of all products is used as the comprehensive index for evaluating the shale oil-rich zone of the shale samples at each depth of the exploration well at each survey point;

[0055] Furthermore, the in-situ flow evaluation of high-clay shale includes:

[0056] The comprehensive shale oil enrichment area evaluation index of shale samples at each depth point of the exploration wells at all survey points is normalized. If the value of the normalized shale oil enrichment area is greater than the preset threshold, the survey point is regarded as a favorable enrichment area of ​​Gulong shale oil; otherwise, the survey point is not a favorable enrichment area of ​​Gulong shale oil.

[0057] This application has at least the following beneficial effects:

[0058] This embodiment mainly utilizes shale oil exploration drilling coring, hydrocarbon generation, reservoir formation, and reservoir formation supporting geological experimental analysis methods. Through research on the characteristics of hydrocarbon generation, expulsion, and retention, the pore structure evolution and the coupling relationship between expulsion pressure, and the coupling relationship between formation fluid pressure and expulsion pressure, the formation model and dynamic mechanism of Gulong shale oil are revealed. In addition, based on the combination of oil test measurement and exploration well inference method, the fitting weights of different measured fluid pressures are obtained based on the difference between the measured values ​​and the inferred values, as well as the difference between the temperature distribution and fluid pressure at different well depths, and the fitting relationship between well depth and fluid pressure is obtained. At the same time, the relationship between expulsion pressure and maturity is obtained based on the capillary pressure curve method. The two methods use maturity as the medium to obtain the coupling relationship between fluid pressure and expulsion pressure. Therefore, this embodiment proposes for the first time that Gulong shale oil has two accumulation modes. When the fluid pressure is greater than or equal to the expulsion pressure, it is a shale oil retention accumulation mode, and when the fluid pressure is less than the expulsion pressure, it is a shale oil self-sealing accumulation mode. Based on different reservoir formation patterns, it can effectively guide the optimization, zoning and classification exploration and breakthrough of the "sweet spot" of Gulong continental shale oil in the Songliao Basin, and expand the lower limit of favorable exploration depth to 2600m, and the sweet spot area from 5800km 2 Expanded to 13,000 km2 , with proven reserves of 204 million tons and production of 465,000 tons of oil equivalent. BRIEF DESCRIPTION OF THE DRAWINGS

[0059] In order to more clearly illustrate the technical solutions and advantages of the embodiments of the present application or the prior art, the following is a brief introduction to the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are only some embodiments of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without any creative work.

[0060] Figure 1 Flowchart of the in-situ reservoir dynamics mechanism and model evaluation method for high-clay shale oil provided in this application;

[0061] Figure 2 A graph showing the relationship between the production of retained hydrocarbons and the reflectance of the vitrinite group provided in one embodiment of the present application;

[0062] Figure 3 A three-stage characteristic diagram of Gulong shale oil evolution provided in one embodiment of the present application;

[0063] Figure 4 Diagenetic evolution stage diagram provided for one embodiment of the present application;

[0064] Figure 5 A diagram showing the relationship between the maximum pore throat radius and the displacement pressure provided in one embodiment of the present application;

[0065] Figure 6 A schematic diagram of a fitting curve provided for one embodiment of the present application;

[0066] Figure 7 A porosity and frequency distribution diagram provided for one embodiment of the present application;

[0067] Figure 8 A diagram showing the relationship between drainage pressure and maturity provided in one embodiment of the present application;

[0068] Figure 9 A diagram showing the relationship between retained and self-sealed shale oil and its properties, provided for one embodiment of the present application;

[0069] Figure 10 A graph showing the relationship between Ro and gas-oil ratio provided for one embodiment of the present application;

[0070] Figure 11 A distribution map of favorable enrichment areas of retained and self-sealed shale oil provided for one embodiment of the present application. DETAILED DESCRIPTION

[0071] To further illustrate the technical means and effectiveness of this application to achieve its intended purpose, the following, in conjunction with the accompanying drawings and preferred embodiments, details the specific implementation, structure, features, and effectiveness of the high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method proposed in this application. In the following description, references to different "one embodiment" or "another embodiment" do not necessarily refer to the same embodiment. Furthermore, specific features, structures, or characteristics of one or more embodiments may be combined in any suitable manner.

[0072] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs.

[0073] The specific scheme of the high-clay shale oil in-situ accumulation dynamics mechanism and model evaluation method provided in this application is described in detail below with reference to the accompanying drawings.

[0074] An embodiment of the present application provides a high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method. Specifically, the following high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method are provided. Figure 1 , the method comprises the following steps:

[0075] Step S1, collecting fluid pressure, temperature data, displacement pressure, oil content, brittleness index, hydrostatic pressure, vitrinite reflectance and density values ​​of shale samples at each depth position of the exploration well at each survey point.

[0076] The Songliao Basin, located in northeastern China, covers an area of ​​26 million square kilometers and features a two-layer structure with a faulted lower layer and a depressed upper layer. The upper depression layer developed in the Late Cretaceous and represents a large continental freshwater-brackish depression-lake basin. From bottom to top, the Quantou, Qingshankou, Yaojia, Nenjiang, Sifangtai, and Mingshui Formations form. The Qingshankou and Nenjiang Formations are semi-deep to deep lacustrine facies with high clay content and rich organic matter, formed by two large-scale intrusions during the Late Cretaceous. The lithology is primarily laminated and layered shale, with minor intercalations of thin siltstone, shell limestone, and dolomite. The Qingshankou Formation shale is rich in organic matter, with an average TOC of 2.2% and a maximum of 13.2%. It also boasts high maturity, with Ro values ​​generally exceeding 0.75% and reaching a maximum of 1.67% in the Central Depression. It also generates significant oil, accounting for 89% of the total oil production in the entire depression, making it the primary source rock in the Songliao Basin. This dominant source rock, encompassing the Songliao Basin's depression layers, forms a comprehensive oil and gas system encompassing conventional oil and gas from the Sartu, Putaohua, and Gaotaizi formations above the source, shale oil from the Gulong formation within the source, and tight oil from the Fuyang-Yangdachengzi formation below the source.

[0077] Research on the proportion of oil source contribution shows that more than half of the oil and gas in Daqing Changyuan comes from the source rocks of the Qingshankou Formation in the Qijia-Gulong Depression; nearly half of the generated oil is retained in the shale of the Qingshankou Formation, forming the Gulong shale oil.

[0078] During the formation of shale oil, as the burial depth increases and the temperature rises, the organic matter in the shale begins to thermally evolve. This is helpful for analyzing the current state of Gulong shale oil in the area and is helpful for shale oil extraction. The following analysis is based on the exploration well at a single exploration point.

[0079] A capsule reactor hot pressure simulation experiment method (implemented in accordance with ZL201910207260.9 standard) was used to carry out a hot pressure hydrocarbon generation simulation experiment of shale containing water, expulsion, and retention. Plunger samples and a "sandwich" sample loading method (i.e., shale in the middle and quartz sand above and below) were used. A microscope photometer equipped with an oil-immersion objective was used to obtain the vitrinite reflectance of shale samples at various depth positions of the exploration wells at each survey point, so that the experimental conditions were closer to the conditions of formation generation, expulsion, and retention of hydrocarbons. The relationship between the generation, expulsion, and retention hydrocarbon production and the vitrinite reflectance Ro was obtained, as shown in the following figure. Figure 2 shown.

[0080] Analysis of the relationship between generation, expulsion, and retained hydrocarbon production and vitrinite reflectance (Ro) reveals that the Gulong shale's oil generation, expulsion, and retained oil windows (Ro) primarily range from 0.9% to 1.6%, with a main peak (Ro) of approximately 1.1% to 1.3%. Oil generation exceeds 2%, with a main peak of 6.12%; retained oil exceeds 1.8%, with a main peak of 4.9%; and expulsion exceeds 0.4%, with a main peak of 1.29%. This indicates that, compared with the classic Tissot oil generation model, the Gulong shale exhibits a wide range of maturity for its generation, expulsion, and retained oil windows, with oil generation potential remaining as low as 1.9% Ro, and oil generation reaching 22% of the peak value.

[0081] Shale oil occurs primarily in free and adsorbed states. Based on the conservation of matter principle during hydrocarbon generation, most free oil is formed by the cracking and conversion of adsorbed oil, while a small amount is generated as hydrocarbon generation products from kerogen cracking. The occurrence and evolution of shale oil are determined using rock pyrolysis analysis and chloroform bitumen "A" data. It should be noted that rock pyrolysis data were obtained using the national standard "Rock Pyrolysis Analysis" (GB / T18602-2012), and chloroform bitumen "A" data were obtained using the industry standard "Determination of Chloroform Bitumen in Rocks" (SY / T5118-2005).

[0082] The evolution of Gulong shale oil is divided into three stages based on the vitrinite reflectance Ro. The evolution of Gulong shale oil has three-stage characteristics ( Figure 3): (1) In the first stage, the reflectance of the vitrinite group Ro is less than 0.9%, and the oil is mainly generated by kerogen. The free oil accounts for 20% to 40% of the retained oil, and the adsorbed oil is the main one; (2) In the second stage, the reflectance of the vitrinite group Ro is 0.9% to 1.6%, and a large amount of adsorbed oil is converted into free oil. The free oil accounts for 40% to 80% of the retained oil. At the same time, due to the transformation of the occurrence state, the volume of shale oil expands and overpressure begins to form; (3) In the third stage, the reflectance of the vitrinite group Ro is greater than 1.60%, and the shale oil begins to crack into gas, but the amount of free oil is much higher than that of the conventional oil generation mode. Due to the large amount of shale oil converted into natural gas, the formation overpressure reaches the maximum, and the pressure coefficient is as high as about 1.6.

[0083] Furthermore, the quantitative results of free oil and adsorption in kerogen, mineral matrix and pores show that, with the vitrinite reflectance Ro1.0% as the boundary, the occurrence state of shale oil in Gulong has undergone two transformations: in the medium-low evolution stage, shale oil transforms from being mainly stored in kerogen to being mainly stored in rocks and organic pores (organic clay composite pores); in the medium-high evolution stage, shale oil transforms from adsorbed state to free state.

[0084] Different stages of shale diagenetic evolution determine the maturity of organic matter in the shale, which in turn affects the generation of shale oil. Therefore, shale diagenetic analysis helps to determine the period and potential of hydrocarbon generation. The pore structure directly determines the storage space size and storage capacity of shale oil. Therefore, studying the pore structure helps to understand the storage capacity and seepage patterns of shale oil in the reservoir. In addition, the evolution of displacement pressure reflects the changes in the dynamics of shale oil during the accumulation process. The magnitude of displacement pressure and its evolution process are important indicators for evaluating the dynamics of shale oil accumulation and the conditions for initial migration.

[0085] The current burial depth of Gulong shale oil is mainly between 1000m and 2600m, the measured vitrinite reflectance Ro is between 0.5% and 1.6%, and the maximum pyrolysis temperature (Tmax) is mostly between 435℃ and 460℃. According to the classification standard of clastic rock diagenesis stage, comprehensive clay mineral evolution, diagenesis and other indicators, the shale diagenesis evolution stage in this area is mainly in the early diagenetic late to middle diagenetic B stage, as shown in the following figure. Figure 4 At different evolutionary stages, diagenesis performance varies and reservoir space characteristics differ, and the two influence each other and evolve synergistically.

[0086] During the early diagenetic stage, shale is shallowly buried, matrix particles are relatively loosely contacted, and organic matter is of low maturity. Pore types are primarily intergranular and intercrystalline. During the intermediate diagenetic stage A, with increasing burial depth and temperature, mechanical compaction intensifies, matrix particles become closely contacted, and intergranular pores decrease in size. Simultaneously, compaction promotes the expulsion of water between clay mineral layers, transforming the illite-montmorillonite mixed layer into illite, and reducing the lattice spacing. During this stage, organic matter matures, and hydrocarbon generation releases organic pores. Simultaneously, acidic fluids such as organic acids and carbon dioxide dissolve the readily soluble feldspar and carbonate minerals in the reservoir, creating some micron-sized particle dissolution pores that increase porosity. During the intermediate diagenetic stage B, with increasing burial depth and ground temperature, organic matter overmatures, and solid asphaltene cracks to form gaseous hydrocarbons. This generates numerous nanoscale organic cracking pores, which become the primary reservoir space in the shale.

[0087] The Gulong shale is primarily composed of mud-grade felsic particles, clay minerals, carbonate minerals, and organic matter, forming a reservoir space system composed primarily of nanoscale pores, including intergranular pores, clay mineral intercrystalline pores, and organic pores. To investigate the unique nanopore structure of shale and clarify the evolution of pore throat size and formation displacement pressure, high-pressure mercury injection experiments were conducted. The results confirm that the shale pore throats are extremely small, with pore throat radii often less than 40 nm, and that the pore structure is closely related to shale maturity.

[0088] In the early diagenetic stage, the organic matter is at a low maturity stage. At this time, the shale pore throat radius distribution range is less than 100nm, mainly concentrated in the range of less than 40nm. The reservoir pore structure is relatively homogeneous and well connected. The displacement pressure of the formation is usually distributed in the range of 10-30MPa ( Figure 5 , point A).

[0089] In the middle diagenesis A stage, organic matter is at the maturity and hydrocarbon generation peak stage. At this stage, the shale pore structure is still dominated by throat radius less than 40nm, accounting for about 80% to 90% of the volume. However, due to the influence of organic matter hydrocarbon generation and organic acid dissolution, some micron-sized pores and throats appear in the shale, with the maximum throat radius reaching 500-600nm. The homogeneity of the reservoir pore structure deteriorates, and the maximum displacement pressure of the formation does not exceed 30MPa. The displacement pressure of the reservoir with developed dissolution pores is less than 15MPa. With the increase of thermal evolution degree, in the middle diagenesis B stage, organic matter is at a high maturity stage, and the shale storage space is dominated by nano-sized organic pores. The pore throat radius is even smaller, mainly concentrated in the range of <10nm. At this time, the displacement pressure of the shale reservoir is mostly higher than 50MPa ( Figure 5 , point B), which is mainly because the finer pore throat structure increases the resistance to fluid flow, requiring higher pressure to expel the fluid, resulting in the shale oil at this stage being confined in the shale reservoir.

[0090] Fluid pressure in shale reservoirs is a key driver of shale oil migration within the reservoir. After shale oil is generated, uneven pressure distribution within the reservoir creates a pressure differential, driving the oil from high-pressure areas to low-pressure areas. Therefore, analyzing shale reservoir fluid pressure can measure shale oil migration. Displacement pressure is the critical pressure at which shale oil begins to be expelled from shale pores and migrate. It determines the time and conditions for shale oil migration within the shale. Therefore, the magnitude and distribution of displacement pressure influence the optimization of shale oil migration paths.

[0091] In order to solve the enrichment and accumulation mechanism of high-clay terrestrial shale oil, for the exploration wells at each survey point, cores are drilled at depths of 1000m to 2600m, and shale samples are collected every 20m depth. The fluid pressure and temperature data at each depth point are obtained using a pressure gauge and a thermocouple. In addition, the density value of the shale sample at each depth point is obtained using a density exploration well method. The density exploration well method is a well-known technology and will not be described in detail in this embodiment.

[0092] The solvent extraction method is used to obtain the oil content of shale samples at each depth point of the exploration well at each exploration point, and the X-ray diffraction whole-rock analysis method is used to obtain the brittleness index of shale samples at each depth point of the exploration well at each exploration point. The solvent extraction method and the X-ray diffraction whole-rock analysis method are well-known technologies and are not described in detail in this embodiment.

[0093] The capillary pressure curve method is used to obtain the displacement pressure of the shale sample at each depth position of the exploration well at each survey point. The capillary pressure curve method is a well-known technology and will not be described in detail in this embodiment.

[0094] The hydrostatic pressure of the shale samples at each depth position of the exploration well at each survey point is calculated. The method for calculating the hydrostatic pressure is a well-known technology and will not be described in detail in this embodiment.

[0095] Step S2: using a curve fitting algorithm in combination with a mineral database to obtain a prediction curve for the exploration well at each exploration point; and obtaining the abnormal sensitivity of the exploration well at each exploration point at each depth position based on the prediction curve and the fluid pressure.

[0096] Fluid pressure, also known as formation pressure, refers to the pressure of the fluid in the pores of the formation. Currently, the main methods for studying reservoir fluid pressure are oil test measurement method and exploration well data inference method. Although the data accuracy of the oil test measurement method is relatively high, the pressure test data is limited. The exploration well data inference method infers the pressure data of the corresponding position based on the material conditions of the shale sample at each depth point. It is easily affected by the complex downhole environment, resulting in deviations in the inferred fluid pressure. Both methods have their own advantages and disadvantages. In order to obtain more accurate shale reservoir fluid pressure data, this application combines and supplements the oil test measurement method and the exploration well data inference method to obtain a relationship between well depth and fluid pressure close to the actual downhole depth. The specific implementation process is as follows:

[0097] In this embodiment, the deep data inference method is selected as the density exploration method. The basic principle is that when the formation fluid pressure changes, the density of the shale will change. When the fluid pressure increases, the rock pores are compressed and the rock density increases.

[0098] Specifically, for the density values ​​of shale samples at various depth positions of the exploration wells at each exploration point, the fluid pressure corresponding to the density value of each shale sample is obtained according to the mineral database of the area where each exploration point is located as the standard fluid pressure of the shale sample density value, and the least squares method is used to perform curve fitting on the depth of the exploration wells at each exploration point at each depth position and the standard fluid pressure of the shale samples at the depth to obtain a prediction curve for the exploration wells at each exploration point; the mineral database and the least squares method are well-known technologies and are not described in detail in this embodiment.

[0099] Furthermore, the actual fluid pressure data obtained by the oil test method is closer to the downhole fluid pressure data by directly placing the sensor at the corresponding depth. However, due to the characteristics of actual high-clay shale, there are many lamellae fractures in the corresponding downhole, which makes the shale heterogeneous. In other words, the rock properties of the shale reservoir vary greatly at different locations, resulting in uneven fluid distribution. The measurement value at a single location can only reflect the pressure value at a single depth location, and cannot reflect the overall relationship between well depth and fluid pressure. At the same time, it is easily affected by changes in temperature gradients, and there may be situations where the fluid pressure is underestimated or overestimated. Therefore, a comprehensive analysis combining actual measurement values ​​and estimated values ​​is required.

[0100] Ideally, for the same well, the fluid pressure data obtained through field testing and the fluid pressure estimated using density exploration methods are consistent. The greater the difference between the two data points at a given depth, the more abnormal the data at that depth point is, and the greater the impact of shale heterogeneity. Fluid pressure also increases with depth, and the relationship between the two is nonlinear. However, due to the close distribution of depth points, the change in measured fluid pressure at adjacent depth points is approximately linear. Large deviations in the change in measured fluid pressure at adjacent locations before and after a single depth point indicate a greater impact of shale heterogeneity at that location.

[0101] According to the above analysis, the abnormal sensitivity of each depth position point of each exploration well at each survey point is obtained based on the prediction curve and fluid pressure. The acquisition method is:

[0102] For each depth position point of the exploration well at each survey point, the absolute value of the difference between the slope of the tangent line of the previous adjacent depth position point on the prediction curve of the exploration well and the slope of the tangent line of the next adjacent depth position point on the prediction curve of the exploration well is calculated as the difference value of the tangent slope of each depth position point of the exploration well at each survey point.

[0103] Furthermore, the abnormal sensitivity of each depth position point of the exploration well at each survey point is calculated, and the calculation formula is: α h =k h ×Δd; where α h k represents the abnormal sensitivity of the fluid pressure at the hth depth position of the exploration well at each survey point; h-1 and k h+1 They represent the slope of the tangent line at the h-1th depth point of the exploration well at each exploration point on the prediction curve and the slope of the tangent line at the h+1th depth point of the exploration well at each exploration point on the prediction curve, respectively. Δd represents the absolute value of the difference between the fluid pressure at the hth depth point of the exploration well at each exploration point and the standard fluid pressure of the shale sample at the hth depth point.

[0104] It should be noted that for the initial and end depth positions, the anomaly sensitivity is set to zero.

[0105] It should be noted that if the current depth position is more affected by shale changes, the difference between the measured fluid pressure value and the standard fluid pressure value at the corresponding position on the prediction curve will be greater, and the value of Δd will be larger. At the same time, the correlation between the fluid pressures at adjacent positions at this position will be weaker, the difference in slope will be greater, and ultimately the abnormal sensitivity value of the depth position will be greater.

[0106] Step S3: Based on the correlation between the temperature data and fluid pressure of each shale sample and the temperature data and fluid pressure of other shale samples, the reliability of the geothermal assessment at each depth position of the exploration well at each survey point is obtained.

[0107] At the same time, in sedimentary basins, the ground temperature increases with increasing depth, and the two are approximately linearly correlated. As the ground temperature increases, the fluid expands, causing the fluid pressure value to increase.

[0108] According to the above analysis, for the shale samples at each depth point of the exploration well at each survey point, the vector composed of the temperature data and fluid pressure of the shale samples is used as the characteristic vector of the shale samples at each depth point. The characteristic vector can reflect the influence of shale properties on the shale samples at each depth point, such as natural fractures, fracture development, etc. Therefore, if the characteristic vector of the current single depth point is significantly different from that in the neighborhood, it means that the depth point is just located in the natural fracture, or at the influence of shale properties, indicating that the credibility of the depth point is low.

[0109] Furthermore, for each depth position point of the exploration well at each survey point, the area between the Nth depth position point closest to the depth position point is used as the neighborhood of each depth position point. In this embodiment, the value of N is 6, and the implementer can select other values ​​according to actual conditions.

[0110] According to the above analysis, the reliability of the geothermal assessment of shale samples at each depth of the exploration well at each exploration point is obtained based on the correlation between the eigenvectors. The calculation formula is: Where, β h is the reliability of the geothermal assessment of the shale sample at the hth depth position of the exploration well at each exploration point, N is the number of depth positions in the neighborhood of the hth depth position of the exploration well at each exploration point, cos() is the cosine similarity, T i represents the characteristic vector of the shale sample at the i-th depth position in the neighborhood of the h-th depth position of the exploration well at each survey point, T h The characteristic vector of the shale sample at the h-th depth position of the exploration well at each exploration point.

[0111] It should be noted that, ideally, the corresponding geothermal value increases linearly with depth. While this linear increase in geothermal temperature increases the fluid's expansion, the relationship between geothermal and fluid pressure remains essentially the same, resulting in closer eigenvectors at different depths and, consequently, a higher confidence level for the geothermal assessment at that depth. Conversely, if the current depth is affected by shale properties, the greater the difference between that depth and neighboring depths, the lower the confidence level for the geothermal assessment.

[0112] Step S4, using a curve fitting algorithm to process the depth and fluid pressure of all depth measurement points of the exploration well of each survey point to obtain the measurement curve of the exploration well of each survey point; based on the difference between the curvature radius of each survey point on the measurement curve and the prediction curve, the credibility of the ground temperature assessment and the abnormal sensitivity, obtain the adaptive fitting weight of each depth position point of the exploration well of each survey point.

[0113] The data obtained from measuring each depth position point can more accurately reflect the fluid pressure situation at the current position. However, the deviation of the overall well depth and fluid pressure distribution at some abnormal depth positions may be large. In the density exploration well estimation method, the shale density situation at a single depth position point may be directly related to the shale situation in a larger range. Therefore, the estimation method is more accurate in estimating the fluid pressure at the blank depth between adjacent depth positions. Therefore, it is necessary to obtain the relationship between the comprehensive well depth and fluid pressure based on the advantages of the two.

[0114] For shale samples at all depth points, if the distribution of the measured fluid pressure is close to that on the predicted curve, it means that the measured data at that depth point and the estimated data of the blank depth are closer to the truth; otherwise, it means that the gap between the estimated data at that depth point and the blank depth is greater than the truth.

[0115] Furthermore, the least square method is used to perform curve fitting on the depth and fluid pressure of all depth measurement points of the exploration well at each exploration point to obtain the measurement curve of the exploration well at each exploration point.

[0116] According to the above analysis, based on the difference in curvature radius between the measured curve and the predicted curve at each survey point, the credibility of the ground temperature assessment, and the anomaly sensitivity, the adaptive fitting weights of each depth position of the exploration well at each survey point are obtained. The acquisition method is:

[0117] Calculate the adaptive fitting coefficient of each depth position point of the exploration well at each survey point. The calculation formula is: Where, ω h represents the adaptive fitting weight of the h-th depth position of the exploration well at each survey point; β h represents the reliability of the geothermal assessment of the shale sample at the hth depth position of the exploration well at each survey point, α h Δρ represents the abnormal sensitivity of the fluid pressure at the hth depth position of each exploration point, h It represents the absolute value of the difference between the curvature radius of the measured curve and the predicted curve of the exploration well at each survey point at the hth depth position; δ is the preset parameter adjustment factor.

[0118] Furthermore, the normalized value of the adaptive coefficient is used as the adaptive fitting weight of each depth position point of the exploration well at each survey point.

[0119] The distribution trend between the measured and predicted curves at a particular depth is reflected by the radius of curvature. The closer the distribution, the smaller the difference in the radius of curvature, indicating that the data at that depth is closer to reality. Furthermore, if the depth is less affected by the shale material and the temperature gradient is more uniform, the geothermal assessment reliability at that depth will be greater, the anomaly sensitivity will be smaller, and ultimately the adaptive weight at that depth will be larger, indicating that the depth will be more attractive to the fitted curve when fitting depth and fluid pressure. Conversely, if the measured data is significantly affected and the difference between the assessment and reality is large, the adaptive fitting weight will be smaller, indicating that the depth will be less attractive to the fitted curve when fitting depth and fluid pressure.

[0120] At this point, the adaptive fitting weight of the h-th depth position point of the exploration well of each survey point is obtained.

[0121] Step S5, obtaining a fitting curve of the exploration well at each exploration point based on the depth, fluid pressure, adaptive fitting weight and the prediction curve of the exploration well at each exploration point, and obtaining the actual fluid pressure of the exploration well at each exploration point at each depth based on the fitting curve.

[0122] Furthermore, for the exploration wells at each survey point, the depths, fluid pressures, adaptive fitting weights of all depth positions and the predicted curves of the exploration wells at each survey point are used as inputs to the B-spline curve fitting algorithm to obtain the fitting curves of the exploration wells at each survey point. The B-spline curve fitting algorithm is a well-known technology and will not be described in detail in this embodiment. The fitting curve diagram is shown in FIG. Figure 6 The fitting curve more accurately obtains the fluid pressure at the depth of the exploration well at each survey point, and obtains the fluid pressure at each depth of the exploration well at each survey point as the actual fluid pressure at each depth.

[0123] Step S6: obtaining the pressure coefficient of the shale sample at each depth position of the exploration well at each survey point based on the actual fluid pressure and the hydrostatic pressure.

[0124] Based on the above results, all areas of the Gulong Shale were analyzed based on the actual fluid pressure at various depths in the exploration wells at each survey point. The results are shown in Table 1. Due to the different burial depths and thermal evolution histories experienced in different areas, the actual fluid pressure and pressure coefficient vary greatly.

[0125] For the shale samples at each depth point of the exploration well at each survey point, the ratio of the actual fluid pressure to the hydrostatic pressure is calculated as the pressure coefficient of the shale samples at each depth point of the exploration well at each survey point.

[0126] Among them, the Qijiagulong Depression has the largest burial depth, between 1900 and 2600m. The shales have generally experienced the peak of oil generation, and the actual fluid pressure of the shale reservoir is high, with the pressure coefficient reaching up to 1.8 and an average of 1.38. Since the Changyuan Formation experienced a large-scale uplift after deposition, the maturity and evolution degree is low. The shales have generally just entered the hydrocarbon generation stage, and the actual fluid pressure of the shale reservoir is basically at normal pressure. The maturity and evolution degree of the Sanzhao Depression is between the two, and the actual fluid pressure of the shale reservoir is between normal pressure and abnormally high pressure.

[0127] Table 1 Statistics of predicted pressure and pressure coefficient of Gulong shale exploration wells

[0128]

[0129]

[0130]

[0131] Displacement pressure is a key parameter characterizing reservoir properties. It reflects not only the rock's pore structure but also its permeability and reservoir performance. Under specific accumulation conditions, it is the controlling parameter that determines whether oil and gas can break through the reservoir interface and accumulate. This example uses the capillary pressure curve method to study the pore throat size and displacement pressure characteristics of the Gulong shale. The specific implementation method is based on the "Determination of Capillary Pressure Curves in Rocks" (GB / T29171-2023).

[0132] like Figure 7 As shown, the porosity of the Gulong shale is less than 10%, primarily distributed between 2% and 9%, accounting for 92% of the total, with an average of 5.1%. Its permeability is relatively low, with a dominant frequency between 0.001×10⁻³μm² and 0.01×10⁻³μm², accounting for 68% of the total, and permeability between 0.01×10⁻³μm² and 1×10⁻³μm², accounting for 25% of the total. This indicates that the Gulong shale has moderate porosity but low permeability. Research on the characteristics of shale displacement pressure is needed to analyze the shale oil accumulation process.

[0133] At the same time, based on the correlation analysis between displacement pressure and maturity evolution, such as Figure 8 As shown in the figure, when Ro is from 0.5% to 0.8%, the displacement pressure changes in a small range, with an average value between 9.65 and 13.78 MPa; when Ro is greater than 0.8%, the displacement pressure increases rapidly, and when Ro is from 0.8% to 1.3%, the average displacement pressure increases from 16.53 to 43.21 MPa, with a large displacement pressure change range; after Ro1.3%, the displacement pressure is greater than 20 MPa, with an average value basically greater than 40 MPa, and the highest reaches 50.3 MPa.

[0134] Step S7: Evaluate the in-situ accumulation mode of high-clay shale oil based on the relationship between the displacement pressure and the actual fluid pressure to obtain the self-sealing accumulation mode and the retention accumulation mode of the shale oil.

[0135] To investigate the reservoir-forming characteristics of Gulong shale oil, this example examines the coupling relationship between actual fluid pressure and displacement pressure. After Ro exceeds 0.7%, the fluid pressure in the Gulong shale increases significantly due to the onset of significant hydrocarbon generation, exceeding the hydrostatic pressure and continuing its steady increase. However, the displacement pressure remains close to the hydrostatic pressure and less than the fluid pressure until Ro reaches 1.2%. After Ro exceeds 1.2%, the displacement pressure begins to increase rapidly and soon exceeds the fluid pressure. Fluid pressure is the driving force behind reservoir formation, while displacement pressure is the resistance to it. Based on the fluid pressure envelope and displacement pressure trend lines of the Gulong shale, a coupling relationship between the two was discovered, controlling the two reservoir-forming patterns of Gulong shale oil.

[0136] The first type is the retention reservoir model. When Ro is between 0.7% and 1.3%, the Gulong shale generates significant oil. The actual fluid pressure exceeds the displacement pressure, and once the shale's adsorption capacity is met, the Gulong shale begins to discharge large quantities of oil, forming conventional reservoirs. This is the main force behind Daqing Oilfield's cumulative crude oil production exceeding 2.5 billion tons. The shale oil remaining in the Gulong shale forms a retention reservoir.

[0137] The second type is the self-sealed reservoir model. When Ro is greater than 1.3%, the Gulong shale continues to generate hydrocarbons. At this time, the actual fluid pressure is less than the displacement pressure, and the Gulong shale stops expelling hydrocarbons. A large amount of oil and gas is sealed in the Gulong shale, forming a self-sealed oil reservoir. That is, for the exploration wells at each survey point, the average of the actual fluid pressure and the average of the displacement pressure at all depth points of the exploration well are calculated. When the average of the actual fluid pressure is less than the average of the displacement pressure, the exploration well at the survey point is in a self-sealed reservoir model. Shale oil discovered in wells such as Guyeyouping 1 belongs to a self-sealed reservoir. This type of shale oil is the main force of Gulong shale oil, with a resource volume of approximately 5.4 billion tons and proven geological reserves of over 200 million tons.

[0138] The Gulong Shale is a typical continental shale oil, with oil concentrated in lamellar fractures and matrix pores. Clay mineral content exceeds 35%. Located in the lower parts of the first and second members of the Lower Cretaceous, the Gulong Shale formed during a transgressive period, in a semi-deep to deep lacustrine subfacies. During deposition, the paleo-lake basin experienced stable tectonic conditions and steady subsidence. The lithology is dominated by mudstone, accounting for over 85%, with thin layers of fine sandstone, siltstone, ostracod limestone, dolomite, and tuff. Lamination thicknesses are generally less than 0.01 m. Reservoirs are primarily located in matrix pores and fractures. Total porosity ranges from 2% to 15%, averaging 7.9%. Effective porosity ranges from 2% to 8%, averaging 3.7%. The Gulong Shale is an organic-rich black shale deposited during the global Late Cretaceous anoxic event. Its source material is monolithic, lacustrine type I, dominated by stratiform algae. It has a high organic matter abundance, averaging 2.69%, and an average S1 of 6.47 mg / g. The Gulong shale oil reservoirs, characterized by retention and self-sealing, formed at different stages of maturation. The differences in reservoir characteristics are primarily related to the oil and gas characteristics of shale formation at these different stages of maturation. This application utilizes 255 crude oil property data and well testing results from 35 Gulong shale oil wells to investigate the reservoir characteristics of these two reservoirs.

[0139] The retained shale oil reservoirs are mainly distributed in the Qijia Sag, Sanzhao Sag and Gulong Sag. The daily production of vertical or inclined wells is 1.36 to 6.72 tons, with an average of 3.59 tons / day. The daily production of horizontal wells is 10.2 to 13.2 tons. There is no water production and little gas. The retained shale oil is medium-quality oil ( Figure 9 ), density is generally greater than 0.82g / cm3, with an average of 0.843g / cm3; viscosity is an average of 16.24mm2 / s, with a main frequency between 10 and 20mm2 / s; wax content is relatively high, with an average of 26.48%; freezing point is an average of 22.1℃, with a main frequency between 15℃ and 30℃; molecular weight is an average of 391.8g / mol, with a main frequency between 370 and 410g / mol (Table 2).

[0140] Compared to crude oil from conventional sandstone reservoirs in the Qingshankou Formation, the distribution range of physical property parameters is similar, but the average and dominant frequency range values ​​are lower. This is primarily due to differences in crude oil composition. The retained shale oil has a higher saturated hydrocarbon content, exceeding 70%, with an average of 79.8%, and aromatics ranging from 8-18%, with an average of 13.5%. Crude oil from conventional sandstone reservoirs in the Qingshankou Formation has a dominant frequency of saturated hydrocarbons ranging from 55% to 75%, with an average of 65.31%, and aromatics ranging from 14% to 24%, with an average of 19.5%. This is because earlier-generated crude oil expelled hydrocarbons into conventional reservoirs, while the oil retained in the shale was generated later and is relatively more mature.

[0141] Table 2 Statistics of physical properties of Gulong shale oil

[0142]

[0143] * Minimum-maximum value

[0144] average value

[0145] Self-sealed shale oil reservoirs are mainly distributed in the Gulong Sag. The daily production of vertical wells is similar to that of retained shale oil wells, ranging from 1.95 to 5.472 t / d, with an average of 3.84 t / d. However, the daily production of horizontal wells is twice that of retained shale oil wells, ranging from 12.54 to 28.611 t / d, with an average of 21.49 t / d. Some wells produce water and gas, with a daily gas production of 180 to 11,506 m3, and a gas-oil ratio greater than 100 m 3 / m 3 ( Figure 10 The oil quality of self-sealed shale oil is light, belonging to volatile oil-light oil, and its density is generally less than 0.82g / cm 3 , average 0.80g / cm 3 ;Viscosity less than 10mm 2 / s, average, 4.35mm 2 / s; the wax content remains relatively high, less than 25%, averaging 20.11%; the freezing point is less than 20°C, averaging 13.7°C; and the molecular weight is less than 350 g / mol, averaging 310.6 g / mol. Physical properties are significantly lower than those of stagnant shale oil. The crude oil composition is high in saturated hydrocarbons, exceeding 80% and averaging 90%; and the aromatics content is less than 10%, averaging 4.5%.

[0146] Step S8: construct a comprehensive evaluation index for shale oil-rich areas based on vitrinite reflectance, oil content, brittleness index, and pressure coefficient to evaluate the in-situ accumulation dynamics of high-clay shale oil.

[0147] The above-mentioned studies on the formation, evolution, diagenesis, and pressure of shale oil revealed that when the Ro (Ro) of the Gulong shale exceeds 1.3%, the shale oil becomes light in quality, has a high gas-oil ratio, and the displacement pressure exceeds the fluid pressure, forming a self-sealing shale reservoir. Horizontal well test production in the inner zone of the self-sealing shale oil reservoir (Ro > 1.3%) exceeds 20 tons / day, while test production in the retained reservoir zone is less than 5 tons / day.

[0148] In addition to being affected by the shale oil accumulation dynamics mechanism, the Gulong shale oil production is also controlled by geological sweet spots such as oil content and nuclear magnetic resonance large pores, as well as engineering sweet spots such as brittle minerals and pressure coefficients.

[0149] Based on the above analysis, a multivariate nonlinear analysis of shale oil production of shale samples at each depth of the exploration well at each exploration point is performed using vitrinite reflectance Ro, oil content S1, brittleness index, and pressure coefficient to obtain a comprehensive shale oil enrichment zone evaluation index. The method for obtaining the index is as follows: for the shale samples at each depth of the exploration well at each exploration point, the product of the vitrinite reflectance and its preset weight coefficient, the product of the oil content and its preset weight coefficient, the product of the brittleness index and its preset weight coefficient, and the product of the pressure coefficient and its preset weight coefficient are calculated, and the sum of all these products is used as the comprehensive shale oil enrichment zone evaluation index for the shale samples at each depth of the exploration well at each exploration point. In this embodiment, the preset weight coefficients for oil content S, pressure coefficient, vitrinite reflectance Ro, and brittleness index are 0.4, 0.3, 0.2, and 0.1, respectively. The implementer may select other values ​​based on actual conditions.

[0150] Furthermore, the comprehensive index of shale oil enrichment area evaluation of shale samples at each depth position of the exploration wells of all survey points is normalized. If the value of the shale oil enrichment area after normalization is greater than the preset threshold, the survey point is evaluated as a favorable enrichment area of ​​Gulong shale oil; otherwise, the survey point is not a favorable enrichment area of ​​Gulong shale oil, such as Figure 11 As shown, the in-situ dynamic mechanism evaluation of high-clay shale is completed. In this embodiment, the preset threshold value is 0.8, and the implementer can select other values ​​according to actual conditions.

[0151] The above examples specifically illustrate the entire process of the method for evaluating the dynamic mechanism and model of self-sealing reservoir formation in high-clay shale according to the present invention. The results of the method for evaluating the dynamic mechanism and model of self-sealing reservoir formation in high-clay shale can be used for shale oil exploration and production.

[0152] It should be noted that the order in which the embodiments of the present application are presented is for illustrative purposes only and does not necessarily represent the superiority or inferiority of the embodiments. Furthermore, the above descriptions are of specific embodiments of the present application. Furthermore, the processes depicted in the accompanying drawings do not necessarily require the specific order or sequential sequence shown to achieve the desired results. In certain embodiments, multitasking and parallel processing are also possible or may be advantageous.

[0153] The various embodiments in this application are described in a progressive manner, and the same or similar parts between the various embodiments can be referred to each other. Each embodiment focuses on the differences from other embodiments.

[0154] The above-described embodiments are only used to illustrate the technical solutions of the present application, and not to limit them. Modifications to the technical solutions described in the aforementioned embodiments, or equivalent replacements of some of the technical features therein, do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present application, and should all be included in the scope of protection of the present application.

Claims

1. The in-situ reservoir formation dynamics mechanism and model evaluation method of high-clay shale oil is characterized by: The method comprises the following steps: Collect fluid pressure, temperature data, displacement pressure, oil content, brittleness index, hydrostatic pressure, vitrinite reflectance and density values ​​of shale samples at various depths of exploration wells at each survey point; Use curve fitting algorithm combined with mineral database to obtain the prediction curve of exploration wells at each survey point; Obtain the abnormal sensitivity of each exploration well at each depth based on the prediction curve and fluid pressure; Based on the correlation between the temperature data and fluid pressure of each shale sample and the temperature data and fluid pressure of other shale samples, the reliability of the geothermal assessment at each depth position of the exploration well at each survey point is obtained; The depth and fluid pressure of all depth measurement points of the exploration well at each exploration point are processed using a curve fitting algorithm to obtain a measurement curve of the exploration well at each exploration point; Based on the difference between the curvature radius of each survey point on the measured curve and the predicted curve, the reliability of the ground temperature assessment and the anomaly sensitivity, the adaptive fitting weight of each depth position point of the exploration well at each survey point is obtained; Obtaining a fitting curve for the exploration well at each exploration point based on the depth, fluid pressure, adaptive fitting weight, and the predicted curve of the exploration well at each exploration point; obtaining the actual fluid pressure at each depth of the exploration well at each exploration point based on the fitting curve; and obtaining the pressure coefficient of the shale sample at each depth position of the exploration well at each exploration point based on the actual fluid pressure and hydrostatic pressure; The in-situ accumulation model of high-clay shale oil is evaluated based on the relationship between displacement pressure and actual fluid pressure, and the self-sealing accumulation model and retention accumulation model of shale oil are obtained; A comprehensive evaluation index for shale oil-rich areas was constructed based on vitrinite reflectance, oil content, brittleness index, and pressure coefficient, and the in-situ accumulation dynamics of high-clay shale oil was evaluated.

2. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The method for obtaining the prediction curve is: For the density values ​​of shale samples at various depth points of the exploration wells at each exploration point, the fluid pressure corresponding to the density value of each shale sample is obtained based on the mineral database of the area where each exploration point is located as the standard fluid pressure of the shale sample density value. A curve fitting algorithm is used to perform curve fitting on the depths at various depth points of the exploration wells at each exploration point and the standard fluid pressures of the shale samples at the depths to obtain a prediction curve for the exploration wells at each exploration point.

3. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 2, characterized in that: The method for obtaining the abnormal sensitivity is: Obtaining the tangent slope difference value of each depth position point of the exploration well at each survey point based on the slope of the tangent line of the depth position point on the prediction curve; The calculation formula of the abnormal sensitivity is: h =k h ×Δd; where α h k represents the abnormal sensitivity of the fluid pressure at the hth depth position of the exploration well at each survey point; h-1 and k h+1 They represent the slope of the tangent line at the h-1th depth point of the exploration well at each exploration point on the prediction curve and the slope of the tangent line at the h+1th depth point of the exploration well at each exploration point on the prediction curve, respectively. Δd represents the absolute value of the difference between the fluid pressure at the hth depth point of the exploration well at each exploration point and the standard fluid pressure of the shale sample at the hth depth point.

4. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 3, characterized in that: The method for obtaining the tangent slope difference value is: For each depth position point of the exploration well at each survey point, the absolute value of the difference between the slope of the tangent line of the previous adjacent depth position point on the prediction curve of the exploration well and the slope of the tangent line of the next adjacent depth position point on the prediction curve of the exploration well is calculated as the difference value of the tangent slope of each depth position point of the exploration well at each survey point.

5. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The method for obtaining the credibility of the ground temperature assessment is: Obtaining characteristic vectors of shale samples at each depth position of the exploration well at each survey point based on temperature data and fluid pressure; Obtain the neighborhood of each depth position point of the exploration well at each survey point; The calculation formula for the ground temperature assessment credibility is: Where, β h is the reliability of the geothermal assessment of the shale sample at the hth depth position of the exploration well at each exploration point, N is the number of depth positions in the neighborhood of the hth depth position of the exploration well at each exploration point, cos() is the cosine similarity, T i represents the characteristic vector of the shale sample at the i-th depth position in the neighborhood of the h-th depth position of the exploration well at each survey point, T h The characteristic vector of the shale sample at the h-th depth position of the exploration well at each exploration point.

6. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 5, characterized in that: The method for obtaining the feature vector is: For the shale samples at each depth position of the exploration well at each survey point, a vector consisting of the temperature data and fluid pressure of the shale samples is used as a characteristic vector of the shale samples at each depth position.

7. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 5, characterized in that: The method for obtaining the neighborhood is: For each depth position point of the exploration well at each survey point, the area between the depth position points of a preset number closest to the depth position point is taken as the neighborhood of each depth position point.

8. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The method for obtaining the adaptive fitting weight is: Based on the difference between the curvature radius of each survey point on the measured curve and the predicted curve, the credibility of the ground temperature assessment and the anomaly sensitivity, the adaptive fitting coefficient of each depth position point of the exploration well of each survey point is obtained, and the normalized value of the adaptive coefficient is used as the adaptive fitting weight of each depth position point of the exploration well of each survey point.

9. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 8, characterized in that: The calculation formula of the adaptive fitting coefficient is: Where, ω h represents the adaptive fitting weight of the h-th depth position of the exploration well at each survey point; β h represents the reliability of the geothermal assessment of the shale sample at the hth depth position of the exploration well at each survey point, α h Δρ represents the abnormal sensitivity of the fluid pressure at the hth depth position of each exploration point, h It represents the absolute value of the difference between the curvature radius of the measured curve and the predicted curve of the exploration well at each survey point at the hth depth position; δ is the preset parameter adjustment factor.

10. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The method for obtaining the fitting curve is: For the exploration well at each survey point, the depth, fluid pressure, adaptive fitting weight of all depth position points and the predicted curve of the exploration well at each survey point are used as inputs of the B-spline curve fitting algorithm to obtain the fitting curve of the exploration well at each survey point.

11. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The actual fluid pressure is obtained by: obtaining the fluid pressure at each depth of the exploration well at each survey point on the fitting curve as the actual fluid pressure at the depth of each depth position point.

12. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The method for obtaining the pressure coefficient is: For the shale samples at each depth point of the exploration well at each survey point, the ratio of the actual fluid pressure to the hydrostatic pressure is calculated as the pressure coefficient of the shale samples at each depth point of the exploration well at each survey point.

13. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The method for obtaining the retention accumulation mode is as follows: For the exploration wells at each exploration point, the average of the actual fluid pressure and the average of the displacement pressure at all depth positions of the exploration wells are calculated. When the average of the actual fluid pressure is greater than or equal to the average of the displacement pressure, the exploration wells at the exploration point are in the retention accumulation mode.

14. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 13, characterized in that: The method for obtaining the self-enclosed reservoir formation mode is as follows: When the average value of the actual fluid pressure is less than the average value of the displacement pressure, the exploration well at the survey point is in a self-sealing reservoir formation mode.

15. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 13, characterized in that: The characteristics of shale oil in the retention accumulation mode are: The average daily production of vertical and inclined wells that retain shale oil is 3.59t / d; The retained shale oil is medium-quality oil with a density greater than 0.82 g / cm 3 , the average density is 0.843g / cm 3 ; Average viscosity is 16.24mm 2 / s; the average wax content is 26.48%; the average freezing point is 22.1℃, and the average molecular weight is 391.8g / moL; the saturated hydrocarbon content of the retained shale oil is greater than 70%, the average saturated hydrocarbon content is 79.8%, and the average aromatic hydrocarbon content is 13.5%.

16. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 14, characterized in that: The characteristics of the self-sealed shale oil reservoir are: The average daily production of vertical wells in self-sealed shale reservoirs is 3.84t / d, the average daily production of horizontal wells is 21.49t / d, and the gas-oil ratio is greater than 100m 3 / m 3 ; Self-sealed shale oil is a volatile oil-light oil with a density of less than 0.82g / cm 3 , the average density is 0.80g / cm 3 ;Viscosity less than 10mm 2 / s, average viscosity is 4.35mm 2 / s; wax content is less than 25%, and the average wax content is 20.11%; freezing point is less than 20℃, and the average freezing point is 13.7℃; molecular mass is less than 350g / moL, and the average molecular mass is 310.6g / moL; saturated hydrocarbon content is greater than 80%, and the average saturated hydrocarbon content is 90%; aromatic hydrocarbon content is less than 10%, and the average aromatic hydrocarbon content is 4.5%.

17. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The formation and evolution characteristics of the self-enclosed and retained reservoir modes are as follows: The formation and evolution characteristics of the self-sealed and retained reservoir modes are divided into three stages. The vitrinite reflectance in the first stage is less than 0.9%; the vitrinite reflectance in the second stage is greater than or equal to 0.9% and less than 1.6%; the vitrinite reflectance in the third stage is greater than or equal to 1.6%.

18. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The transformation process of the occurrence state between the self-sealed reservoir formation mode and the retention reservoir formation mode is as follows: The storage state transformation process between the self-sealed accumulation mode and the retained accumulation mode is divided into two stages. The first stage is the medium-low evolution stage, when the vitrinite reflectance is less than or equal to 1.0%; the second stage is the medium-high evolution stage, when the vitrinite reflectance is greater than 1.0%.

19. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 1, characterized in that: The construction of the comprehensive evaluation index for shale oil-rich areas includes: For the shale samples at each depth point of the exploration well at each survey point, the product of the vitrinite reflectance and its preset weight coefficient, the product of the oil content and its preset weight coefficient, the product of the brittleness index and its preset weight coefficient, and the product of the pressure coefficient and its preset weight coefficient are calculated respectively, and the sum of all products is used as the comprehensive index for evaluating the shale oil-rich area of ​​the shale samples at each depth point of the exploration well at each survey point.

20. The high-clay shale oil in-situ reservoir dynamics mechanism and model evaluation method according to claim 19, characterized in that: The in-situ flow evaluation of high-clay shale includes: The comprehensive shale oil enrichment area evaluation index of shale samples at each depth point of the exploration wells at all survey points is normalized. If the value of the normalized shale oil enrichment area is greater than the preset threshold, the survey point is regarded as a favorable enrichment area of ​​Gulong shale oil; otherwise, the survey point is not a favorable enrichment area of ​​Gulong shale oil.

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