A method for identifying tight oil sources in argillaceous carbonate reservoirs

Abstract

This invention provides a method for identifying tight oil sources in argillaceous carbonate reservoirs, comprising the following steps: First, selecting samples for experimentation; second, conducting hydrocarbon generation thermal simulation experiments to obtain the relationship between liquid hydrocarbon production rate and temperature at different heating rates; third, conducting hydrocarbon generation chemical kinetic simulations to obtain the oil conversion rate under different burial depth conditions; fourth, calculating the oil generation pressure under different geological conditions; fifth, calculating the capillary pressure of the argillaceous carbonate rock, comparing the difference in oil generation pressure between mudstone and argillaceous carbonate rock with the magnitude of the capillary pressure, and determining whether the mudstone has the potential to become a tight oil source in argillaceous carbonate reservoirs. This invention makes identification from the perspective of reservoir formation kinetics, avoiding the risks and limitations arising from the application of biomarker compounds, and quantitatively comparing the difference in oil generation pressure with the capillary pressure of argillaceous carbonate rocks. The quantification of parameters during the calculation process avoids the influence of unnecessary subjective factors.

Description

Technical Field

[0001] This invention relates to the field of tight oil research technology in argillaceous carbonate reservoirs, specifically to a method for identifying the source of tight oil in argillaceous carbonate reservoirs. Background Technology

[0002] Tight oil refers to oil accumulations formed in tight clastic or carbonate rock reservoirs within a hydrocarbon source rock stratum, which have only undergone brief migration, resulting in oil being discharged from the source rock and then migrated to reservoirs adjacent to the source rock strata. Generally, it has no natural production capacity and requires reservoir modification through large-scale fracturing technology to form industrial production capacity.

[0003] Influenced by the sedimentary environment, argillaceous carbonate reservoirs contain abundant argillaceous clastic material within their carbonate layers, thus possessing strong hydrocarbon generation capabilities. This unique reservoir condition leads to two possible types of tight oil accumulation within argillaceous carbonate reservoirs: self-generated and self-storing tight oil, and exogenously supplied tight oil. These two possibilities result in different accumulation models for tight oil in argillaceous carbonate reservoirs. An accumulation model is a high-level summary of the characteristics of a tight oil and gas reservoir, including its source, charging process, and enrichment patterns. It serves as a genetic explanation model for oil and gas reservoir groups with similar accumulation processes and conditions. Identifying the source of tight oil and thus determining the accumulation model of argillaceous carbonate rocks is of great significance for subsequent research on tight oil enrichment patterns and resource assessment.

[0004] Currently, biomarker compounds are the most widely used and applicable method in oil source correlation. Due to the stability of their chemical properties, biomarker compounds are basically unaffected by secondary effects during thermal evolution and can still effectively preserve the original information of organic organisms. They can provide information on various aspects such as the source of organic matter, sedimentary environment, and thermal evolution maturity. Therefore, source rocks and crude oils with kinship relationships have certain similarities in the composition and distribution of biomarker compounds. This similarity can be directly displayed on chromatograms or mass spectrometry, and can also be reflected through the abundance relationship of certain parameters.

[0005] However, biomarker compounds are easily affected by water washing, biodegradation and organic matter maturity. The compositional parameters of biomarker compounds are complex and variable. Therefore, when comparing oil sources, any single indicator has certain limitations and risks. It is necessary to use multiple parameters in a comprehensive comparison, and the applicability of the selected parameters in different regions or different target strata must be fully considered. Summary of the Invention

[0006] The purpose of this invention is to provide a method for identifying the source of tight oil in argillaceous carbonate reservoirs based on the difference between oil generation and pressure. This method identifies the source of tight oil in argillaceous carbonate reservoirs from the perspective of reservoir formation dynamics, thereby avoiding the risks and limitations caused by the complexity and variability of biomarker compound characteristics in the process of source comparison.

[0007] To achieve the above objectives, the method for identifying tight oil sources in argillaceous carbonate reservoirs in this invention adopts the following technical solution: A method for identifying tight oil sources in argillaceous carbonate reservoirs includes the following steps: The first step involved selecting two types of rock samples: a tight oil reservoir made of argillaceous carbonate rock with low organic matter thermal maturity that could represent the basic geochemical characteristics of the study strata, and the underlying mudstone. Total organic carbon content, rock pyrolysis, wetting angle, and mercury intrusion porosimetry were then tested to obtain parameters such as total organic carbon content, hydrogen index, wetting angle, and pore radius. The second step is to conduct an open-system thermal simulation experiment on the selected sample to determine the relative contents of gas and liquid components at each temperature range from the gas chromatogram obtained from the experiment. Then, the amount of liquid hydrocarbons and gaseous hydrocarbons at each temperature point under different heating rates is obtained. The relationship between hydrocarbon production rate and temperature is transformed into the relationship between liquid hydrocarbon production rate and temperature, and the relationship between liquid hydrocarbon production rate and temperature under different heating rates is obtained. The third step involves conducting a hydrocarbon generation chemical kinetics simulation based on the relationship between the liquid hydrocarbon production rate and temperature at different heating rates in step two, to obtain the oil generation conversion rate of mudstone and argillaceous carbonate rocks under different burial depths in the study area. The fourth step involves using the total organic carbon content and hydrogen index obtained in step one, as well as the oil generation conversion rate obtained in step three, to perform oil generation pressure calculations on the mudstone and argillaceous carbonate rocks of the target strata in the study area according to the oil generation pressure calculation formula, and obtaining the oil generation pressure values ​​of the target strata under different geological conditions. The fifth step involves calculating the capillary pressure of argillaceous carbonate rocks based on the Young-Laplace equation. By comparing the difference between the oil generation pressure of mudstone and the oil generation pressure of argillaceous carbonate rocks with the magnitude of the capillary pressure, it can be determined whether mudstone has the potential to become a source of tight oil in argillaceous carbonate rocks.

[0008] The beneficial effects of the above technical solution are as follows: This invention conducts open-system hydrocarbon generation thermal simulation experiments on the selected samples, and uses the relationship between the liquid hydrocarbon production rate and temperature obtained from the experiment to perform hydrocarbon generation chemical kinetic simulation. From the perspective of reservoir formation kinetics, it identifies the source of tight oil in argillaceous carbonate reservoirs, thereby avoiding the risks and limitations of applying biomarker compounds. Furthermore, this invention uses hydrocarbon generation chemical kinetic simulation to obtain the oil conversion rate of mudstone and argillaceous carbonate rocks under different burial depths in the study area. Using the total organic carbon content and hydrogen index obtained in step one, and according to the oil generation pressurization calculation formula, it performs quantitative calculation of oil generation pressurization for mudstone and argillaceous carbonate rocks in the target strata of the study area. It simulates oil generation pressurization for mudstone and argillaceous carbonate rocks, and quantitatively compares the oil generation pressurization difference with the capillary pressure of argillaceous carbonate rocks to determine whether mudstone has the potential to become a source of tight oil in argillaceous carbonate rocks. The quantification of each parameter in the calculation process avoids the influence of unnecessary subjective factors.

[0009] Furthermore, in step three, the chemical kinetics of hydrocarbon generation revealed by the hydrocarbon generation thermal simulation experiment are dynamically and quantitatively described based on the discrete hydrocarbon generation kinetic model of parallel first-order reaction. A penalty function that meets the actual problem is constructed to calibrate the model, and finally the chemical kinetic parameters of the initial cracking of mudstone and argillaceous carbonate rocks for oil generation are obtained.

[0010] The beneficial effects of the above technical solution are as follows: by using a discrete hydrocarbon generation kinetic model to simulate the chemical kinetics of hydrocarbon generation, the chemical kinetic process in the hydrocarbon generation process can be dynamically and quantitatively described, and a penalty function that meets the actual problem can be constructed to calibrate the model, ensuring that the obtained chemical kinetic parameters are accurate and easy to operate.

[0011] Furthermore, by combining the thermal history and burial history of the study area, the obtained chemical kinetic parameters were applied in actual geological studies to determine the oil conversion rate of mudstone and argillaceous carbonate rocks under different burial depths.

[0012] The beneficial effect of the above technical solution is that it ensures the accuracy of the calculation results.

[0013] Furthermore, in step one, the organic matter thermal maturity Ro is selected to be <0.5%.

[0014] The advantages of the above technical solution are: it facilitates the experiment and ensures the research value of the experiment.

[0015] Furthermore, in step two, during the hydrocarbon generation thermal simulation experiment, the sample was heated to 630°C with an initial temperature of 200°C and two heating rates of 5°C / min and 20°C / min. The pyrolysis products under the same experimental conditions were collected at 30°C intervals for gas chromatography analysis.

[0016] The advantages of the above technical solution are: it facilitates the conduct of thermal simulation experiments of open systems, eliminates secondary cracking during the experimental process, and provides accurate calculation parameters for chemical kinetic simulation.

[0017] Furthermore, the formula for calculating the booster pressure in step four is as follows: P = AF [αD(1 - P)] h C o )-1] / [C w Φρ k / ρ bulk M k +(1-AF)C k +αAFDC o ], where △P is the oil production pressure boost; A is the hydrogen index / 1000; F is the organic matter oil production conversion rate; α is the crude oil residue coefficient; P h C is the hydrostatic pressure; k C w and C o ρ represents the compressibility coefficients of kerogen, water, and petroleum, respectively. k ρ o and ρ bulk Here, D = ρ represents the density of kerogen, petroleum, and source rock, respectively. k / ρ o M k The mass of the kerogen is calculated from the measured total organic carbon content; Φ represents the porosity of the rock.

[0018] The beneficial effect of the above technical solution is that it facilitates the calculation of the oil pressure boost value.

[0019] Furthermore, the porosity is calculated using the normal compaction porosity model, and the calculation formula is as follows: Φ=Φ0×е (-CH) Where Φ0 is the original porosity; C is the compaction coefficient; and H is the burial depth.

[0020] The beneficial effects of the above technical solution are: porosity takes into account the influence of burial depth and is not a constant value, which ensures that the calculation results of the oil generation pressure value are more accurate.

[0021] Furthermore, without considering crude oil leakage, the crude oil residue coefficient α is set to 1.

[0022] The beneficial effect of the above technical solution is that it facilitates the calculation of the oil pressure boost value.

[0023] Furthermore, the kerogen in the study area was predominantly type I, with an average chemical formula of Ck. 251 H 385 O 13N7S3, the mass M of kerogen is determined by its chemical formula and total organic carbon content. k .

[0024] The beneficial effect of the above technical solution is that it facilitates the calculation of the mass M of kerogen. k This makes it easier to calculate the boost pressure value of the raw oil.

[0025] Furthermore, in step five, when making the judgment, if the difference between the oil generation pressure value of mudstone and the oil generation pressure value of argillaceous carbonate rock is greater than the capillary pressure, then mudstone contributes to the tight oil in the argillaceous carbonate rock reservoir, that is, the tight oil in the argillaceous carbonate rock reservoir is exogenously supplied tight oil; if the difference between the oil generation pressure value of mudstone and the oil generation pressure value of argillaceous carbonate rock is less than the capillary pressure, then mudstone does not contribute to the tight oil in the argillaceous carbonate rock reservoir, that is, the tight oil in the argillaceous carbonate rock reservoir is self-generated and self-storage type tight oil.

[0026] The beneficial effect of the above technical solution is that it makes it easier to determine whether the tight oil in the argillaceous carbonate reservoir is self-generated and self-storage type tight oil or exogenously supplied type tight oil. Attached Figure Description

[0027] Figure 1 This is a flowchart illustrating the principle of the method for identifying tight oil sources in argillaceous carbonate reservoirs in this invention. Figure 2 This is a graph showing the conversion rate of kerogen to oil from mudstone at different heating rates in this invention. Figure 3 This is a graph showing the conversion rate of kerogen to oil from argillaceous carbonate rocks at different heating rates in this invention. Figure 4 This is a diagram showing the distribution of activation energy for kerogen extraction from mudstone in this invention. Figure 5 This is a diagram showing the distribution of kerogen activation energy in argillaceous carbonate rocks in this invention. Figure 6 This is a graph showing the oil conversion rate of mudstone and argillaceous carbonate rocks under different burial depth conditions in the study area of ​​this invention. Figure 7 This is a diagram showing the oil generation and pressurization of mudstone and argillaceous carbonate rocks under different geological conditions in the study area of ​​this invention. Figure 8 This is a schematic diagram of the oil-generating pressurization model in this invention; Figure 9 This is a capillary pressure distribution diagram of argillaceous carbonate rock in this invention. Detailed Implementation

[0028] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are only for explaining the invention and are not intended to limit the invention; that is, the described embodiments are merely some embodiments of the invention, and not all embodiments. The components of the embodiments of the invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0029] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0030] It should be noted that relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.

[0031] The features and performance of the present invention will be further described in detail below with reference to embodiments.

[0032] An embodiment of the method for identifying tight oil sources in argillaceous carbonate reservoirs in this invention: Due to the unique geological conditions of the study area, tight oil in argillaceous carbonate reservoirs may be either self-generated or exogenously supplied. Identifying the source of tight oil and determining the accumulation model of argillaceous carbonate rocks is of great significance for subsequent research on tight oil enrichment patterns and resource evaluation. However, the complexity and variability of biomarker compound characteristics introduce risks and limitations in the oil source comparison process. Therefore, this invention is a method for determining the source of petroleum in argillaceous carbonate tight oil reservoirs based on the difference between oil generation and pressure.

[0033] like Figure 1 As shown, the method for identifying tight oil sources in argillaceous carbonate reservoirs in this invention includes the following steps: The first step involved selecting one sample each of a tight oil reservoir made of argillaceous carbonate rock and its underlying mudstone, both of which had low organic matter thermal maturity (Ro<0.5%) and could represent the basic geochemical characteristics of the study strata. Sample preparation work was carried out before the experiment. Then, experiments were conducted to determine the total organic carbon content, pyrolysis of rocks, wetting angle, and mercury intrusion porosimetry. All of the above experiments were carried out in accordance with national standards.

[0034] The total organic carbon content (TOC) of the sample was obtained through a total organic carbon content determination experiment; the hydrogen index (HI) of the sample was obtained through a rock pyrolysis experiment; the oil wetting angle parameter of the rock was obtained through a wetting angle experiment; and the pore size distribution of the carbonate reservoir was obtained through a high-pressure mercury intrusion porosimetry experiment, thus obtaining the pore radius parameter. The obtained wetting angle parameter and the pore size distribution of the tight reservoir can be used to calculate the capillary resistance.

[0035] The second step involves conducting an open-system hydrocarbon generation kinetics simulation experiment on the selected samples. This open-system approach eliminates the possibility of secondary cracking during the experiment. Starting at 200℃, the samples were heated to 630℃ using two heating rates: 5℃ / min and 20℃ / min. Pyrolysis products were collected at 30℃ intervals under the same experimental conditions for gas chromatography-mass spectrometry (PY-GC) analysis. The gas (C1-C5) and liquid (C6-C7) components in each temperature range were determined from the obtained gas chromatograms. + The relative content of the components is used to determine the amount of liquid and gaseous hydrocarbons at different temperature points under different heating rates. This transforms the hydrocarbon production rate-temperature relationship into a liquid hydrocarbon production rate-temperature relationship, thus obtaining the relationship between the liquid hydrocarbon production rate and temperature at different heating rates. Figure 2 and Figure 3 As shown, this represents the kerogen oil conversion rate of mudstone at different heating rates and the kerogen oil conversion rate of argillaceous carbonate rocks at different heating rates, thus providing necessary calculation parameters for chemical kinetic simulation.

[0036] The third step involves performing a hydrocarbon generation chemical kinetic simulation based on the relationship between the liquid hydrocarbon production rate and temperature at different heating rates, as described in step two. Specifically, a discrete hydrocarbon generation kinetic model based on parallel first-order reactions is applied to dynamically and quantitatively describe the chemical kinetics of the hydrocarbon generation process revealed by the thermal simulation experiment. A penalty function that satisfies the actual problem is constructed to calibrate the model, ultimately obtaining the chemical kinetic parameters for the initial pyrolysis and oil generation from mudstone and argillaceous carbonate rocks, i.e., as shown in the figure. Figure 4 and Figure 5 The diagram shows the kerogen activation energy distribution of mudstone and argillaceous carbonate rocks. It can be seen from the figure that argillaceous carbonate rocks have a certain hydrocarbon generation capacity, but the hydrocarbon generation peak of mudstone is more concentrated, which provides the possibility that the target mudstone in the study area can become the oil source of argillaceous carbonate rocks.

[0037] Then, combining the thermal and burial history of the study area, the obtained chemical kinetic parameters were applied in actual geological studies to determine the oil conversion rates of mudstone and argillaceous carbonate rocks at different geological ages (and different burial depths) in the study area, such as... Figure 6 As shown, this is for subsequent calculations of hydrocarbon generation and pressurization.

[0038] The fourth step involves using the total organic carbon content and hydrogen index obtained in step one, as well as the oil generation conversion rate obtained in step three, to calculate the oil generation pressure of the mudstone and argillaceous carbonate rocks in the target strata of the study area according to the oil generation pressure calculation formula. Combined with the thermal history and burial history of the study area, the oil generation pressure values ​​of the target strata under different geological conditions are obtained, such as... Figure 7 As shown, this is the oil generation and pressurization history of the target strata in the study area.

[0039] In this model, since the source rock is under normal compaction before oil generation begins, a comparison is made between the normal compaction state without hydrocarbon generation and the established oil generation pressurization model (e.g., Figure 8 As shown), the formula for calculating the booster pressure of the oil is as follows: △P=AF[αD(1-P h C o )-1] / [C w Φρ k / ρ bulk M k +(1-AF)C k +αAFDC o ], where △P is the oil production pressure boost; A is the hydrogen index / 1000; F is the organic matter oil production conversion rate; α is the crude oil residue coefficient; P h C is the hydrostatic pressure; k C w and C o ρ represents the compressibility coefficients of kerogen, water, and petroleum, respectively. k ρ o and ρ bulk Here, D = ρ represents the density of kerogen, petroleum, and source rock, respectively. k / ρ o M k The mass of the kerogen is calculated from the measured total organic carbon content; Φ represents the porosity of the rock.

[0040] The porosity calculation uses the normal compaction porosity model, and the calculation formula is as follows: Φ=Φ0×е (-CH) Where Φ0 is the original porosity; C is the compaction coefficient; and H is the burial depth.

[0041] The key to calculating the compression ratio of petroleum lies in determining the various parameters. Total organic carbon (TOC) and hydrogen index (HI) can be obtained through relevant experiments. The compressibility coefficients of petroleum, water, and kerogen are 2.2 × 10⁻⁶. -3 MPa -1 0.44×10 - 3 MPa -1 1.4×10 -3 MPa -1 Based on the well logging interpretation results of the study area, the rock density of mudstone and carbonate rock was taken as 2300 kg / m³. 3 and 2400kg / m 3 The density of kerogen, oil, and water is 1200 kg / m³. 3 900kg / m 3 and 1000kg / m 3 The porosity of the source rocks was calculated based on normal compaction. The original porosity and rock compaction coefficient of mudstone and argillaceous carbonate rocks in the study area were 57% and 0.672 × 10⁻⁶, respectively. -3 m -1 and 30%, 0.41×10 -3 m -1 The kerogen in the study area is predominantly type I, with an average chemical formula of Ck. 251 H 385 O 13 N7S3, the mass M of kerogen is determined by its chemical formula and total organic carbon (TOC). k Without considering crude oil leakage, the crude oil residue coefficient α is set to 1.

[0042] like Figure 7 As shown in the figure, when the burial depth exceeds 3000m, the oil generation pressure value of mudstone begins to be greater than that of argillaceous carbonate rock. That is, the tight oil in the argillaceous carbonate rock reservoir in the shallow area below 3000m is self-generated and self-storage type tight oil, while mudstone in the deep area above 3000m has the potential to become the source of argillaceous carbonate rock tight oil.

[0043] Fifth, using the wetting angle and tight reservoir pore size parameters obtained in step one, the capillary pressure of the argillaceous carbonate rock is calculated based on the Young-Laplace equation, resulting in a histogram of the capillary pressure distribution in the target layer, as shown below. Figure 9 The figure shows the capillary pressure distribution of tight oil reservoirs. It can be seen from the figure that the capillary resistance of 0.08-0.8 MPa is dominant. Therefore, in this study, 0.08 MPa is taken as the capillary resistance of argillaceous carbonate rocks.

[0044] The Young-Laplace equation is as follows: Pc = (2×σ×cosθ) / r, where P c σ represents the capillary resistance encountered by oil and gas entering the reservoir; σ is the oil-water interfacial tension; θ is the wetting angle; and r is the pore size of the tight reservoir.

[0045] Finally, by comparing the difference between the oil generation pressure values ​​of mudstone and argillaceous carbonate rocks with the capillary pressure, we can determine whether mudstone has the potential to become a source of tight oil in argillaceous carbonate reservoirs. If the difference between the oil generation pressure values ​​of mudstone and argillaceous carbonate rocks is greater than or equal to the capillary pressure, then mudstone contributes to the tight oil in argillaceous carbonate reservoirs, meaning the tight oil in argillaceous carbonate reservoirs is exogenously supplied. If the difference between the oil generation pressure values ​​of mudstone and argillaceous carbonate rocks is less than the capillary pressure, then mudstone does not contribute to the tight oil in argillaceous carbonate reservoirs, meaning the tight oil in argillaceous carbonate reservoirs is endogenously generated and stored.

[0046] This invention presents a method for identifying tight oil sources based on the difference in pressure between source rock and organic matter. The method is primarily derived through hydrocarbon generation thermal simulation experiments and calculations based on chemical kinetics principles, with a focus on determining the conversion rate of organic matter to oil. In implementing this method, a normal compaction state without hydrocarbon generation is used as a comparison object, and a source rock pressure equation is established. The key to calculating the source rock pressure lies in determining parameters such as the mass of the source rock, hydrogen index, permeability coefficient, and conversion rate of organic matter to oil. Without considering existing permeability, the petroleum residue coefficient α is set to 1; the kerogen mass and hydrogen index can be obtained through experiments evaluating the organic matter abundance of the source rock.

[0047] This invention identifies the source of tight oil in argillaceous carbonate reservoirs from the perspective of hydrocarbon accumulation dynamics, thereby avoiding the risks and limitations associated with the application of biomarker compounds. Furthermore, this invention performs quantitative calculations of oil generation and pressurization in the target strata of the study area, quantitatively comparing the difference in oil generation and pressurization with the capillary pressure of the argillaceous carbonate rocks to determine whether the mudstone has the potential to become a source of tight oil in the argillaceous carbonate reservoirs. The quantification of parameters in the calculation process avoids the influence of unnecessary subjective factors.

[0048] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, when the difference between the oil generation pressure value of mudstone and the oil generation pressure value of argillaceous carbonate rock is equal to the capillary pressure, it can also be determined that mudstone does not contribute to the tight oil in argillaceous carbonate reservoirs.

[0049] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, the kerogen in the study area may also be predominantly type II.

[0050] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, the crude oil residue coefficient α can be other values ​​when considering crude oil leakage.

[0051] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, the porosity Φ of the rock can also be a constant value, independent of the burial depth.

[0052] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, the formula for calculating oil generation and pressurization can also be other formulas known in the prior art.

[0053] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, the initial temperature, heating rate, and temperature interval for interval collection can also be other values ​​when conducting hydrocarbon generation thermal simulation experiments.

[0054] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, the organic matter thermal maturity Ro selected in step one can also be greater than 0.5%.

[0055] In other embodiments of the method for identifying tight oil sources in argillaceous carbonate reservoirs, hydrocarbon generation chemical kinetics simulations may also employ models from other existing technologies.

[0056] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. The scope of patent protection of the present invention shall be determined by the claims. Similarly, any equivalent structural changes made based on the description and drawings of the present invention shall also be included within the scope of protection of the present invention.

Claims

1. A method for identifying tight oil sources in argillaceous carbonate rock reservoirs, characterized in that, Includes the following steps: The first step involved selecting two types of rock samples: a tight oil reservoir made of argillaceous carbonate rock with low organic matter thermal maturity that could represent the basic geochemical characteristics of the study strata, and the underlying mudstone. Total organic carbon content, rock pyrolysis, wetting angle, and mercury intrusion porosimetry were then tested to obtain parameters such as total organic carbon content, hydrogen index, wetting angle, and pore radius. The second step is to conduct an open-system thermal simulation experiment on the selected sample to determine the relative content of gas and liquid components at each temperature range from the gas chromatogram obtained from the experiment. Then, the amount of liquid hydrocarbons and gaseous hydrocarbons at each temperature point under different heating rates is obtained. The relationship between hydrocarbon production rate and temperature is converted into the relationship between liquid hydrocarbon production rate and temperature, and the relationship between liquid hydrocarbon production rate and temperature under different heating rates is obtained. The third step involves performing a chemical kinetic simulation of hydrocarbon generation based on the relationship between the liquid hydrocarbon production rate and temperature at different heating rates in the second step, to obtain the oil conversion rate of mudstone and argillaceous carbonate rocks under different burial depths in the study area. The fourth step involves using the total organic carbon content and hydrogen index of mudstone and argillaceous carbonate rocks obtained in the first step, as well as the oil generation conversion rate obtained in the third step, to perform oil generation pressure calculations on mudstone and argillaceous carbonate rocks respectively, and to obtain the oil generation pressure values ​​of mudstone and argillaceous carbonate rocks under different geological conditions. Fifth, based on the wetting angle and pore radius parameters of the argillaceous carbonate rock obtained in the first step, the capillary pressure of the argillaceous carbonate rock is calculated using the Young-Laplace equation. The sixth step involves comparing the difference between the oil generation pressure values ​​of mudstone and argillaceous carbonate rocks obtained in the fourth step with the relationship between the capillary pressure obtained in the fifth step. This comparison helps determine whether mudstone has the potential to become a source of tight oil in argillaceous carbonate rocks. If the difference is greater than the capillary pressure, the mudstone is considered to contribute to the tight oil in the argillaceous carbonate rock reservoir, indicating an exogenous supply type of tight oil. If the difference is less than the capillary pressure, the mudstone is considered to not contribute to the tight oil in the argillaceous carbonate rock reservoir, indicating a self-generated and self-storing type of tight oil.

2. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to claim 1, characterized in that, In step three, a discrete hydrocarbon generation kinetic model based on parallel first-order reactions is used to dynamically and quantitatively describe the chemical kinetics of hydrocarbon generation revealed by the hydrocarbon generation thermal simulation experiment. A penalty function that meets the actual problem is constructed to calibrate the model, and finally the chemical kinetic parameters of the initial cracking of mudstone and argillaceous carbonate rocks for oil generation are obtained.

3. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to claim 2, characterized in that, By combining the thermal history and burial history of the study area, the obtained chemical kinetic parameters were applied in actual geological studies to determine the oil conversion rate of mudstone and argillaceous carbonate rocks under different burial depths.

4. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to any one of claims 1 to 3, characterized in that, In step one, the organic matter thermal maturity degree Ro is selected as <0.5%.

5. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to any one of claims 1 to 3, characterized in that, In step two, during the hydrocarbon generation thermal simulation experiment, the sample was heated to 630℃ with an initial temperature of 200℃ and two heating rates of 5℃ / min and 20℃ / min. The pyrolysis products under the same experimental conditions were collected at 30℃ intervals for gas chromatography analysis.

6. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to any one of claims 1 to 3, characterized in that, The formula for calculating the boost pressure in step four is as follows: △P=AF[αD(1-P h C o )-1] / [C w Φρ k / ρ bulk M k +(1-AF)C k +αAFDC o ], where △P is the oil production pressure boost; A is the hydrogen index / 1000; F is the organic matter oil production conversion rate; α is the crude oil residue coefficient; P h C is the hydrostatic pressure; k C w and C o ρ represents the compressibility coefficients of kerogen, water, and petroleum, respectively. k ρ o and ρ bulk Here, D = ρ represents the density of kerogen, petroleum, and source rock, respectively. k / ρ o M k The mass of the kerogen is calculated from the measured total organic carbon content; Φ represents the porosity of the rock.

7. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to claim 6, characterized in that, Porosity is calculated using the normal compaction porosity model, and the calculation formula is as follows: Φ=Φ0×е (-CH) Where Φ0 is the original porosity; C is the compaction coefficient; and H is the burial depth.

8. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to claim 6, characterized in that, Without considering crude oil leakage, the crude oil residue coefficient α is set to 1.

9. The method for identifying tight oil sources in argillaceous carbonate reservoirs according to claim 6, characterized in that, The kerogen in the study area is predominantly type I, with an average chemical formula of Ck. 251 H 385 O 13 N7S3, the mass M of kerogen is determined by its chemical formula and total organic carbon content. k .

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