A method for evaluating the genetic model of condensate gas in coal-bearing strata

Abstract

The present invention relates to the technical field of coal-bearing stratum condensate gas genesis analysis, and in particular to a coal-bearing stratum condensate gas genesis model evaluation method. 13 The error caused by the natural gas maturity calculated by C1 is used to study the origin of coal-bearing condensate gas efficiently and at low cost. 13 C1 and natural gas drying coefficient C1 / C 1‑5 Carry out natural gas source comparison in coal-bearing strata, conduct oil-source comparison through characteristic biomarker compounds, clarify the organic matter type and maturity distribution stage of coal-bearing source rocks, and clarify whether coal-bearing source rocks themselves can generate condensate gas. Based on the distribution characteristics of the PVT phase state of oil and gas reservoirs in the oil and gas reservoir profile, combined with the coal-bearing source rock type, oil-source comparison and whether the source rock itself can produce condensate gas, comprehensively evaluate the cause of condensate gas in coal-bearing strata.

Description

Technical Field

[0001] The present invention relates to the technical field of coal-bearing stratum condensate gas genesis analysis, and in particular to a coal-bearing stratum condensate gas genesis model evaluation method. Background Art

[0002] Research on the origin of oil and gas is a crucial component of oil and gas geological exploration. Clarifying its origin facilitates analysis of oil and gas enrichment patterns and reservoir formation mechanisms, providing theoretical support for the prediction of favorable exploration zones and sweet spots. Commonly used techniques for evaluating the origin of oil and gas are primarily based on assessing the abundance, type, maturity, and thickness distribution of organic matter in source rocks. These techniques are then combined with geological background, source rock generation patterns, oil and gas source correlation, oil and gas charging history, oil and gas phases, and oil and gas production to assess the origin of oil and gas.

[0003] Among them, the traditional view is that coal-bearing source rocks mainly form gas reservoirs and are difficult to form primary condensate gas reservoirs. However, in fact, studies have shown that the vitrinite reflectance of coal-bearing source rocks with rich shell groups is between 0.6% and 1.3%, which can simultaneously produce a large amount of natural gas and crude oil, forming primary condensate gas.

[0004] Existing research suggests that the coal hydrocarbon generation model has the following characteristics: When the vitrinite reflectance (Ro) of coal is between 0.5% and 0.7%, low-maturity oil is generated. From Ro > 0.7%, coal primarily generates natural gas, and as Ro increases, natural gas production gradually increases, exhibiting an overall "early oil, late gas" pattern. Based on these characteristics, researchers often interpret the origin of condensate gas in coal-bearing strata as the result of low-maturity oil reservoirs generated early in the coal, or reservoirs generated by source rocks in other strata, invaded by large amounts of natural gas generated later. However, the coal hydrocarbon generation model requires correlative analysis of oil and gas source materials and research on oil and gas injection phases. Existing techniques typically use fluid inclusions to study natural gas and crude oil injection phases. However, this method requires the preparation of reservoir inclusion thin sections, determination of the homogenization temperature of crude oil / natural gas inclusions, and reconstruction of the formation's burial and thermal history. This process is complex and costly, and the resulting natural gas and crude oil accumulation ages may be subject to error, thus hindering the accurate assessment of the origin of the condensate gas.

[0005] In actual research, to determine the injection period of natural gas and crude oil, it is necessary to calculate the maturity of crude oil and natural gas. 13 C1, and since the beginning of natural gas generation, δ 13 C1 is affected by migration, oxidation, etc., according to the natural gas δ 13 The natural gas maturity calculated by C1 may be biased. In addition, different scholars have proposed different 13 C1 is the formula for calculating the maturity of natural gas, which may also lead to errors in the calculated maturity of natural gas.

[0006] In summary, the existing methods cannot accurately reveal the composition of condensate gas in coal-bearing strata. Summary of the Invention

[0007] In view of the above-mentioned shortcomings of the prior art, the present invention aims to provide a method for evaluating the genetic pattern of coal-bearing condensate gas in formations to avoid the occurrence of natural gas δ 13 The error caused by the natural gas maturity calculated by C1 is used to study the origin of coal-bearing condensate gas efficiently and at low cost. 13 C1 and natural gas drying coefficient C1 / C 1-5 Carry out natural gas source comparison in coal-bearing strata, conduct oil source comparison through characteristic biomarker compounds, clarify the organic matter type and maturity distribution stage of coal-bearing source rocks, clarify whether coal-bearing source rocks themselves can generate condensate gas, and comprehensively analyze the cause of condensate gas based on the distribution characteristics of the PVT phase state of the oil and gas reservoir in the oil and gas reservoir profile.

[0008] In order to solve the above technical problems, the present invention adopts the following technical solutions:

[0009] A method for evaluating the genetic model of condensate gas in coal-bearing strata comprises the following steps:

[0010] Collect coal-bearing source rock samples, extract natural gas and crude oil from the coal-bearing source rock samples, and collect natural gas and crude oil production data.

[0011] Carbon isotope determination of natural gas yields δ 13 C1; Determine the component content of natural gas and obtain C1 / C 1-5 , plot δ 13 C1 and C1 / C 1-5 Intersection diagram; according to δ 13 C1 and C1 / C 1-5 The intersection diagram is used to judge the maturity and source of natural gas. If the natural gas comes from the original or nearby source, the condensate gas origin is primary condensate gas origin. If the natural gas comes from a distant source, the condensate gas origin is secondary condensate gas origin.

[0012] Among them, δ 13 C1 represents the carbon isotope content. Primary condensate gas refers to the natural gas produced by the coal-bearing strata themselves and the condensate gas formed by crude oil. Secondary condensate gas refers to the condensate gas formed by natural gas infiltration after the formation of early oil reservoirs. In situ means that the natural gas comes from the hydrocarbon source rock directly below the natural gas reservoir. Near-source means that the natural gas comes from the hydrocarbon source rock with a horizontal distance of 0 to 20 km from the natural gas reservoir. Far-source means that the natural gas comes from the hydrocarbon source rock with a horizontal distance of more than 20 km from the natural gas reservoir.

[0013] Biomarker compound determination was performed on coal-measure source rock samples and crude oil, respectively, to obtain characteristic biomarker compound spectra of the coal-measure source rock samples and crude oil. Oil-source comparison was performed through the characteristic biomarker compound spectra to clarify the organic matter type and maturity distribution stage of the coal-measure source rock samples. If the biomarker compound characteristics of the crude oil are similar to those of the coal-measure source rock samples, the origin of the condensate gas includes the generation of condensate gas by the coal-measure source rock itself.

[0014] PVT phase state tests are conducted on oil and gas reservoirs in coal-bearing source rock samples, and PVT phase state diagrams of oil and gas reservoirs are drawn to clarify the phase state of oil and gas reservoirs under formation conditions. A cross-sectional diagram of oil and gas reservoirs is established, and the dynamic change process of phase state under formation conditions of oil and gas reservoirs is analyzed. If the state of crude oil in the oil and gas reservoirs changes with changes in temperature and pressure, it means that the origin of condensate gas is controlled by temperature and pressure in formation conditions, and the origin of condensate gas includes the influence of the phase state of oil and gas reservoirs under formation conditions.

[0015] To avoid natural gas delta 13 The error caused by the natural gas maturity calculated by C1 is used to study the origin of coal-bearing condensate gas efficiently and at low cost. 13 C1 and natural gas drying coefficient C1 / C 1-5 Carry out natural gas source comparison in coal-bearing strata, conduct oil-source comparison through characteristic biomarker compounds, clarify the organic matter type and maturity distribution stage of coal-bearing source rocks, and clarify whether coal-bearing source rocks themselves can generate condensate gas. Based on the distribution characteristics of the PVT phase state of oil and gas reservoirs in the oil and gas reservoir profile, combined with the coal-bearing source rock type, oil-source comparison and whether the source rock itself can produce condensate gas, comprehensively evaluate the cause of condensate gas in coal-bearing strata.

[0016] In a preferred embodiment of the present invention, organic carbon content determination and rock pyrolysis experiment are carried out on coal-bearing source rock samples to obtain the total organic carbon content TOC and pyrolysis hydrocarbon S2 of the coal-bearing source rock samples. A TOC-HI intersection diagram is drawn based on the total organic carbon content TOC and pyrolysis hydrocarbon S2 of the coal-bearing source rock samples, where HI = pyrolysis hydrocarbon S2 / total organic carbon content TOC × 100%, to evaluate the lithology of the coal-bearing source rock.

[0017] In a preferred embodiment of the present invention, the lithology of the coal-bearing source rock includes mudstone, carbonaceous mudstone and coal.

[0018] In a preferred embodiment of the present invention, a rock pyrolysis experiment is performed on a coal-bearing source rock sample to obtain pyrolysis hydrocarbon S2 and the highest pyrolysis peak temperature Tmax. An intersection diagram of hydrogen index HI and Tmax is drawn based on the pyrolysis carbon S2 and the highest pyrolysis peak temperature Tmax, where HI = pyrolysis hydrocarbon S2 / total organic carbon content TOC × 100%, to evaluate the organic matter type of the coal-bearing source rock sample.

[0019] In a preferred embodiment of the present invention, the organic matter types of coal-bearing source rock samples include type I, type II1, type II2 and type III, among which type I-II1 are oil-prone source rocks, and type II2-III are gas-prone source rocks.

[0020] In a preferred embodiment of the present invention, Tmax<435 is the unripe stage, 435<Tmax<440 is the low-ripe stage, 440<Tmax<450 is the mature stage, 450<Tmax<580 is the high-ripe stage, and 580<Tmax is the over-ripe stage.

[0021] In a preferred embodiment of the present invention, the method further includes recording the depth and lithology information of the collected coal-bearing source rock samples, determining the microscopic component content and extracting vitrinite from the coal-bearing source rock samples, obtaining the microscopic component content and vitrinite reflectance Ro of different layers of the coal-bearing source rock samples, judging whether the coal-bearing source rock is an exinite group based on the microscopic component content of different layers, drawing an intersection diagram of the vitrinite reflectance Ro and the depth, and evaluating the maturity stage of the coal-bearing source rock based on the intersection diagram of the vitrinite reflectance Ro and the depth, and judging whether the condensate gas is originated from primary condensate gas.

[0022] In a preferred embodiment of the present invention, Ro < 0.5% is the unripe stage, 0.5% < Ro < 0.7% is the low-ripe stage, 0.7% < Ro < 1.3% is the mature stage, 1.3% < Ro < 2.0% is the high-ripe stage, and 2.0% < Ro is the over-ripe stage.

[0023] In a preferred embodiment of the present invention, it also includes calculating the crude oil maturity Rc and natural gas maturity Ro 计算 , judge the natural gas maturity Ro 计算 Is the maturity of crude oil Rc at the same stage? If the maturity of crude oil Rc is the same as that of natural gas Ro 计算 If the natural gas maturity Ro and crude oil maturity Rc are at the same stage, the condensate gas origin is primary condensate gas origin. If the natural gas maturity Ro and crude oil maturity Rc are not at the same stage, the condensate gas origin is secondary condensate gas origin.

[0024] In a preferred embodiment of the present invention, the crude oil maturity Rc is calculated as follows: Rc=0.55MPI1+0.44, where MPI1 is the methylphenanthrene index and natural gas maturity Ro is the maturity index of natural gas. 计算 The calculation formula is: 13 C1=25lgRo-37.5.

[0025] Oil and gas phase behavior results are all based on the phase behavior of wellhead samples. However, as oil and gas are extracted from the formation and brought to the surface, their phase behavior may change as temperature and pressure decrease. The phase behavior of surface samples does not necessarily represent the true phase behavior of the oil and gas reservoir in the formation, thus limiting the accurate evaluation of the oil and gas genetic model. Therefore, traditional methods for evaluating oil and gas genetic models cannot accurately reveal the true oil and gas genetic model in coal-bearing formations.

[0026] Condensate gas reservoirs are controlled by temperature and pressure in formation conditions. When the temperature and pressure decrease, the crude oil in the condensate gas reservoir will retrogradely condense to form oil reservoirs with gas caps, gas reservoirs with oil rings, or separate upper gas reservoirs and lower oil reservoirs, changing from a single gas state to a gas-liquid two-phase state. Therefore, a single oil reservoir or a single gas reservoir is not originally a single phase. Therefore, the origin of oil and gas needs to be comprehensively evaluated based on the phase state of the oil and gas reservoirs under real formation conditions. Single oil and gas source comparison and hydrocarbon generation model evaluation may not reflect the true condensate gas genesis model.

[0027] Compared with the prior art, the present invention has the following beneficial effects:

[0028] 1. Existing technologies usually determine whether coal-bearing source rocks can produce primary condensate gas by calculating reflectivity, and determine the charging period of natural gas and crude oil by calculating the maturity of natural gas. However, different scholars have proposed different methods based on δ 13 The formula for calculating natural gas maturity using C1 results in errors in the calculated natural gas maturity. To avoid the 13 The error caused by the natural gas maturity calculated by C1 is used to study the origin of coal-bearing condensate gas efficiently and at low cost. 13 C1 and natural gas drying coefficient C1 / C 1-5 Carry out natural gas source comparison in coal-bearing strata, conduct oil-source comparison through characteristic biomarker compounds, clarify the organic matter type and maturity distribution stage of coal-bearing source rocks, and clarify whether coal-bearing source rocks themselves can generate condensate gas. Based on the distribution characteristics of the PVT phase state of oil and gas reservoirs in the oil and gas reservoir profile, combined with the coal-bearing source rock type, oil-source comparison and whether the source rock itself can produce condensate gas, comprehensively evaluate the cause of condensate gas in coal-bearing strata.

[0029] 2. The present invention accurately reveals the genesis of condensate gas reservoirs in coal-bearing strata through the application of interdisciplinary parameters, providing theoretical guidance for predicting the distribution of oil and gas reservoirs in coal-bearing strata. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 It is the intersection diagram of total organic carbon content TOC and hydrogen index HI.

[0031] Figure 2 It is the intersection diagram of the highest pyrolysis peak temperature Tmax and the hydrogen index HI.

[0032] Figure 3 Figure 2 is a diagram of the content of microscopic components of source rocks in different layers.

[0033] Figure 4 This is the intersection diagram of source rock vitrinite reflectance Ro and depth.

[0034] Figure 5 is the carbon isotope δ of natural gas methane 13 C1 and drying coefficient C1 / C 1~5 Intersection diagram.

[0035] Figure 6 The graph shows the characteristic biomarker compound spectra of source rocks and crude oil.

[0036] Figure 7 is the PVT phase characteristic diagram of reservoir fluids of different types of oil and gas reservoirs, among which, P For pressure, T is the temperature, FP is the temperature and pressure condition of the producing layer, and C is the critical point.

[0037] Figure 8 This is a cross-section diagram of a typical gas reservoir PVT phase reservoir.

[0038] Figure 9 The crude oil Rc and natural gas Ro in the same condensate gas reservoir 计算 Intersection diagram. DETAILED DESCRIPTION

[0039] The following is a detailed description of the technical solutions in the embodiments of the present invention, using preferred embodiments and accompanying drawings in conjunction with the embodiments of the present invention. Obviously, the embodiments described are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0040] It should be noted that all professional terms used in the present invention are only for the purpose of describing specific embodiments and are not intended to limit the scope of protection of the present invention. Unless otherwise specified, the various raw materials, reagents, instruments and equipment used in the following embodiments of the present invention can be purchased from the market or prepared by existing methods.

[0041] A method for evaluating the genetic model of condensate gas in coal-bearing formations of the present invention comprises the following steps:

[0042] Collect coal-bearing source rock samples, record the depth and lithology information of the collected coal-bearing source rock samples, collect natural gas and crude oil samples, and collect natural gas and crude oil production data; measure the microscopic component content and extract vitrinite from the coal-bearing source rock to obtain the microscopic component content and vitrinite reflectance Ro of different layers of the coal-bearing source rock.

[0043] Organic carbon content determination and rock pyrolysis experiments were carried out on coal-bearing source rocks to obtain the total organic carbon content TOC and pyrolysis hydrocarbon S2 of the coal-bearing source rocks. A TOC-HI intersection diagram was drawn based on the total organic carbon content TOC and pyrolysis hydrocarbon S2 of the source rocks. HI = pyrolysis hydrocarbon S2 / total organic carbon content TOC × 100% to evaluate the lithology of the coal-bearing source rocks. The lithology of the coal-bearing source rocks includes mudstone, carbonaceous mudstone and coal.

[0044] Rock pyrolysis experiments were carried out on coal-bearing source rocks to obtain pyrolysis hydrocarbon S2 and the highest pyrolysis peak temperature Tmax. Based on the pyrolysis carbon S2 and the highest pyrolysis peak temperature Tmax, an intersection diagram of hydrogen index HI and Tmax was drawn, HI = pyrolysis hydrocarbon S2 / total organic carbon content TOC × 100%, to evaluate the organic matter type of source rock. The organic matter types of source rock include type I, type II1, type II2 and type III. Among them, type I-type II1 are oil-prone source rocks, and type II2-type III are gas-prone source rocks. Tmax < 435 is an immature stage, 435 < Tmax < 440 is a low-mature stage, 440 < Tmax < 450 is a mature stage, 450 < Tmax < 580 is a high-mature stage, and 580 < Tmax is an over-mature stage.

[0045] Carbon isotope determination of natural gas yields δ 13 C1, the component content of natural gas is measured to obtain C1 / C 1-5 , plot δ 13 C1 and C1 / C 1-5 Intersection diagram, according to δ 13 C1 and C1 / C 1-5 The intersection diagram is used to determine the source of natural gas. If the natural gas comes from the original source or a nearby source, the condensate gas is of primary origin. If the natural gas comes from a distant source, the condensate gas is of secondary origin formed by natural gas invasion after the formation of the early oil reservoir.

[0046] Biomarker compounds are measured in source rocks and crude oil to obtain characteristic biomarker spectra and relative contents. Oil-source correlation is performed using characteristic biomarker compounds to clarify the organic matter type and maturity distribution stage of coal-bearing source rocks. If the biomarker characteristics of crude oil are similar to those of source rocks, it indicates that coal-bearing source rocks themselves can generate condensate gas.

[0047] Conduct PVT phase state tests on oil and gas reservoirs, draw PVT phase state diagrams of oil and gas reservoirs, clarify the phase state of oil and gas reservoirs under formation conditions, establish oil and gas reservoir profiles, and analyze the dynamic change process of phase state under formation conditions of oil and gas reservoirs. If the state of crude oil in condensate gas reservoirs changes with changes in temperature and pressure, it means that the origin of condensate gas is controlled by temperature and pressure in formation conditions. The origin of condensate gas needs to be comprehensively evaluated based on the phase state of oil and gas reservoirs under formation conditions.

[0048] The evaluation method also includes judging whether the coal-bearing source rock is an exinite group based on the microscopic components of different layers, drawing an intersection diagram of vitrinite reflectance Ro and depth, and evaluating the maturity stage of the coal-bearing source rock based on the intersection diagram of vitrinite reflectance Ro and depth, and judging whether the coal-bearing source rock itself can form primary condensate gas. Ro < 0.5% is an immature stage, 0.5% < Ro < 0.7% is a low-mature stage, 0.7% < Ro < 1.3% is a mature stage, 1.3% < Ro < 2.0% is a high-mature stage, and 2.0% < Ro is an over-mature stage.

[0049] The evaluation method also includes calculating crude oil maturity Rc and natural gas maturity Ro 计算 , to determine whether the maturity of natural gas and crude oil are at the same stage. If the maturity of crude oil Rc is the same as that of natural gas Ro 计算 At the same stage, the condensate gas reservoir is the original cause. If the natural gas maturity Ro 计算 If the maturity of crude oil is not at the same stage as Rc, the condensate gas reservoir is formed by the invasion of high-maturity natural gas by the early oil reservoir. The calculation formula of crude oil maturity Rc is: Rc=0.55MPI1+0.44, where MPI1 is the methylphenanthrene index and natural gas maturity Ro 计算 The calculation formula is: 13 C1=25lgRo 计算 -37.5.

[0050] Combining the above methods, a comprehensive evaluation is made on the genesis of condensate gas in coal-bearing strata.

[0051] Example 1

[0052] Taking the oil and gas reservoir genesis of the Pinghu Formation and Huagang Formation in the Pinghu slope zone of the Xihu Sag as an example, the evaluation method includes the following steps:

[0053] (1) Based on the total organic carbon determination of the source rocks and the pyrolysis hydrocarbon S2 obtained from the rock pyrolysis experiment, a TOC-HI intersection diagram was drawn, HI = S2 / TOC × 100%. The lithology of the coal-bearing source rocks in the study area includes mudstone, carbonaceous mudstone and coal, all of which are mainly gas-generating. A small number of carbonaceous mudstones and coals can generate both oil and gas. Figure 1 shown.

[0054] (2) Based on the Tmax obtained from the rock pyrolysis experiment, the intersection diagram of Tmax and HI was drawn. The coal-bearing source rocks in the study area are mainly of type II2-III, with a small part of type II1, such as Figure 2 As shown in the figure, the maceral components in different layers show that the exinite has the highest content, followed by the vitrinite, sapropelite, and inertinite. Figure 3 As shown in the figure, comprehensive analysis shows that the coal-bearing source rocks in the study area are terrestrial humic source rocks.

[0055] (3) The intersection diagram of source rock Ro and depth shows that the Ro of the coal-bearing source rocks of the Pinghu Formation and Baoshi Formation in the study area is mainly distributed between 0.6% and 1.0%, such as Figure 4 As shown in the figure, existing technical research believes that in the coal-measure source rocks and terrestrial humic source rocks rich in exinite, the coal-measure source rocks with Ro between 0.5% and 1.3% can generate a large amount of condensate gas reservoirs themselves. Therefore, the coal-measure source rocks in the study area can form primary condensate gas reservoirs themselves.

[0056] (4) Plotting δ 13 C1 and C1 / C 1-5 Intersection diagram, such as Figure 5 As shown, generally, as natural gas migrates, the drying coefficient C1 / C 1-5 will increase, and at the same time, δ 13 C1 will become lighter; if controlled by maturity, natural gas δ 13 C1 and C1 / C 1-5 will increase simultaneously. The δ 13 C1With C1 / C 1-5 The natural gas in the western sub-sag and slope belts exhibits a typical two-stage pattern, indicating that the natural gas in the Pinghu slope belt does not originate from the western sub-sag. Since the slope belt itself has mature coal-bearing source rocks, comprehensive analysis suggests that the natural gas in the Pinghu slope belt originates from in-situ coal-bearing source rocks. The above gas source comparisons confirm that the natural gas in the Pinghu slope belt does not originate from the highly mature natural gas in the western sub-sag, and that the condensate gas in the Pinghu slope belt does not originate from the highly mature natural gas in the western sub-sag, as previously believed.

[0057] (5) The biomarker compounds of source rocks and crude oil were determined to obtain characteristic biomarker compound spectra. According to the biomarker compound spectra of source rocks and crude oil, the crude oil in the study area showed two characteristics: high C30Hdia, C27, C28, C29 steranes in reverse L type, and nomarane, isopmarane, and stylanes in "7" type; the other was low C30Hdia, C27, C28, C29 steranes in ascending type, and nomarane, isopmarane, and stylanes in reverse "V" type, which is very similar to the original source rocks, such as Figure 6 As shown, the crude oil is derived from in situ coal-bearing source rocks.

[0058] (6) Establish a typical oil and gas reservoir profile in the study area, such as Figure 7 and Figure 8 As shown, from Figure 7 、 Figure 8 It can be seen that condensate gas reservoirs are mainly distributed in the upper member of the PS Ping. Upward to the upper member of the HS Huashang member and the lower member of the HX Huaxia member, both oil and gas reservoirs can be seen. Taking Well N as an example, from deep to shallow, the PVT phase diagram changes from N-6, N-4 to N-3. As the reservoir depth becomes shallower and the temperature and pressure decrease, the condensate gas reservoir is close to the dew point envelope, but it is still a condensate gas reservoir. This is because the Pinghu Formation is the main development layer of coal-bearing source rocks in the study area, and the coal-bearing source rocks with rich shell formations can generate primary condensate gas reservoirs themselves. When the depth becomes shallower to the upper member of the HS Huashang member, the PTV phase diagram N-1 changes into a typical low-gas-bearing oil reservoir and differentiates into oil and gas reservoirs containing both oil and gas phases (O-2, K-1). This is because as the temperature and pressure of the condensate gas reservoir decrease again, the crude oil originally dissolved in the natural gas in the primary condensate gas reservoir generated by the terrigenous humic coal-bearing source rock retrogradely condenses to form a low-gas-bearing oil reservoir.

[0059] (7) In order to avoid the calculation error of natural gas Ro, this paper adopts the natural gas maturity Ro proposed by Chen Jianping et al. (2021) 计算 The calculation formula of δ 13 C1=25lgRo 计算 -37.5 Calculation of natural gas maturity Ro 计算 , the maturity of natural gas produced from the same condensate gas reservoir in the study area is Ro 计算 It has a good positive correlation with crude oil Rc, and the natural gas maturity Ro from the same condensate gas reservoir 计算 Equal to or close to the crude oil maturity Rc value, such as Figure 9 This also proves that the crude oil and natural gas in the condensate gas reservoirs in the study area were formed at the same maturity stage of the coal-bearing source rocks, which supports the conclusion that the condensate gas reservoirs in the coal-bearing strata in the study area are primary condensate gas reservoirs.

[0060] Based on the study of the microscopic components and maturity of coal-bearing source rocks, the present invention clearly defines the study area as coal-bearing exinyme source rocks, Ro 计算 : 0.5%~1.0%, it can generate primary condensate gas reservoirs, which are gaseous underground, with a large amount of natural gas and a small amount of crude oil on the surface; δ 13 C1 and C1 / C 1-5The intersection diagram shows that the natural gas in the Pinghu slope belt and the western sub-sag shows a typical two-stage structure, indicating that the natural gas in the slope belt comes from the source rocks of the slope belt itself rather than from the western sub-sag. The characteristics of C30Hdia, C30Hdia, C27, C28, C29 steranes, norpimarane, isopimarane, and stylopsidane in the crude oil and source rocks indicate that the crude oil comes from in situ source rocks. The oil and gas source comparison shows that both oil and gas come from in situ in the slope belt. The maturity of crude oil and natural gas in the same condensate gas reservoir is equal to or similar, indicating that the condensate gas reservoirs in the study area are mainly primary condensate gas reservoirs rather than early oil reservoirs filled with late natural gas. The PVT phase profile of the oil and gas reservoirs shows that the Pinghu Formation, where coal-bearing source rocks are developed, are all primary condensate gas reservoirs. They are gaseous underground. With decreasing burial depth and decreasing temperature and pressure, the crude oil in the condensate gas reservoir retrogradely condenses, forming gas reservoirs with oil rings, oil reservoirs with gas caps, and separate oil and gas reservoirs in the shallower layers.

[0061] It should be noted that when the present invention relates to numerical ranges, it should be understood that both endpoints of each numerical range and any value between the two endpoints can be selected. Since the steps and methods used are the same as those in the embodiments, in order to avoid redundancy, the present invention describes the preferred embodiments. Although the preferred embodiments of the present invention have been described, those skilled in the art may make additional changes and modifications to these embodiments once they understand the basic inventive concepts. Therefore, the attached protection scope is intended to be interpreted as including the preferred embodiments and all changes and modifications that fall within the scope of the present invention.

[0062] Obviously, those skilled in the art may make various changes and modifications to the present invention without departing from the spirit and scope of the present invention. Thus, if such changes and modifications fall within the scope of the present invention and its equivalents, the present invention is intended to include such changes and modifications.

Claims

1. A method for evaluating the genetic model of condensate gas in coal-bearing formations, characterized in that: The following steps are involved: Collect coal-bearing source rock samples and extract natural gas and crude oil from them; Carbon isotope determination of natural gas yields δ 13 C1; Determine the component content of natural gas and obtain C1 / C 1-5 , plot δ 13 C1 and C1 / C 1-5 Intersection diagram; according to δ 13 C1 and C1 / C 1-5 The intersection diagram is used to determine the source of natural gas. If the natural gas comes from the original source or a nearby source, the origin of the condensate gas includes primary condensate gas origin; If the natural gas comes from a distant source, the origin of the condensate includes secondary condensate origin; Biomarker compounds are measured on coal-measure source rock samples and crude oil respectively to obtain characteristic biomarker compound spectra of the coal-measure source rock samples and crude oil. The characteristic biomarker compound spectra of the coal-measure source rock samples and crude oil are compared. If the characteristic biomarker compounds of the crude oil are similar to those of the coal-measure source rock samples, the condensate gas is generated by the coal-measure source rock itself. Conduct PVT phase state tests on oil and gas reservoirs in coal-bearing source rock samples, draw PVT phase state diagrams of oil and gas reservoirs, clarify the phase state of oil and gas reservoirs under formation conditions, establish oil and gas reservoir profiles, and analyze the dynamic changes in phase state under formation conditions of oil and gas reservoirs. If the state of crude oil in the oil and gas reservoir changes with changes in temperature and pressure, then the origin of condensate gas is affected by the phase state of the oil and gas reservoir under formation conditions; The process also includes recording and collecting the depth and lithology information of coal-measure source rock samples, measuring the content of microscopic components and extracting vitrinite from the coal-measure source rock samples, obtaining the content of microscopic components and vitrinite reflectance Ro at different layers of the coal-measure source rock samples, determining whether the coal-measure source rock is exinite based on the content of microscopic components at different layers, plotting a graph of vitrinite reflectance Ro versus depth, and evaluating the maturity stage of the coal-measure source rock based on the graph of vitrinite reflectance Ro versus depth to determine whether the condensate gas is of primary origin. It also includes the calculation of crude oil maturity Rc and natural gas maturity Ro 计算 , judge the natural gas maturity Ro 计算 Is the maturity of crude oil Rc at the same stage? If the maturity of crude oil Rc is the same as that of natural gas Ro 计算 At the same stage, the condensate gas origin is primary condensate gas origin. If the natural gas maturity Ro 计算 If the maturity Rc of crude oil is not at the same stage, the origin of condensate gas is secondary condensate gas; The calculation formula for crude oil maturity Rc is: Rc=0.55MPI1+0.44, MPI1 is the methylphenanthrene index, and natural gas maturity Ro 计算 The calculation formula is: 13 C1=25lgRo 计算 -37.

5.

2. The method for evaluating the genetic model of coal-bearing stratum condensate gas according to claim 1, characterized in that: Organic carbon content determination and rock pyrolysis experiments were carried out on coal-measure source rock samples to obtain the total organic carbon content (TOC) and pyrolysis hydrocarbon S2 of the coal-measure source rock samples. A TOC-HI intersection diagram was drawn based on the total organic carbon content (TOC) and pyrolysis hydrocarbon S2 of the coal-measure source rock samples to evaluate the lithology of the coal-measure source rock, where HI = (pyrolysis hydrocarbon S2 / total organic carbon content (TOC)) × 100%.

3. The method for evaluating the genetic model of coal-bearing stratum condensate gas according to claim 2, characterized in that: The lithology of coal-bearing source rocks includes mudstone, carbonaceous mudstone and coal.

4. The method for evaluating the genetic model of coal-bearing stratum condensate gas according to claim 1, characterized in that: Rock pyrolysis experiments were conducted on coal-bearing source rock samples to obtain pyrolysis hydrocarbon S2 and the highest pyrolysis peak temperature Tmax. Based on the pyrolysis carbon S2 and the highest pyrolysis peak temperature Tmax, a hydrogen index HI and Tmax intersection diagram was drawn to evaluate the organic matter type of the coal-bearing source rock samples, where HI = (pyrolysis hydrocarbon S2 / total organic carbon content TOC) × 100%.

5. The method for evaluating the genetic model of coal-bearing stratum condensate gas according to claim 4, characterized in that: The organic matter types of coal-bearing source rock samples include type I, type II1, type II2 and type III; among them, type I and type II1 are oil-prone source rocks, and type II2 and type III are gas-prone source rocks.

6. The method for evaluating the genetic model of coal-bearing stratum condensate gas according to claim 4, characterized in that: Tmax<435 is the unripe stage, 435≤Tmax<440 is the low-ripe stage, 440≤Tmax<450 is the mature stage, 450≤Tmax<580 is the high-ripe stage, and 580≤Tmax is the over-ripe stage.

7. The method for evaluating the genetic model of coal-bearing stratum condensate gas according to claim 1, characterized in that: Ro<0.5% is the unripe stage, 0.5%≤Ro<0.7% is the low-ripe stage, 0.7%≤Ro<1.3% is the mature stage, 1.3%≤Ro<2.0% is the high-ripe stage, and 2.0%≤Ro is the over-ripe stage.

Images