A method for identifying the origin of tight oil and gas based on molecular markers and lithology

Abstract

The present application relates to oil and gas exploration technology field, specifically disclose a kind of based on molecular marker and lithology tight oil and gas genesis identification method, comprising the following steps: synchronous acquisition and pretreatment hydrocarbon source rock, tight reservoir core and oil and gas sample;Oil and gas and hydrocarbon source rock sample are tested to organic molecular marker, obtain parent material type, maturity and oil-source correlation parameter;Oil and gas and hydrocarbon source rock sample are tested to inorganic molecular marker, obtain inorganic element content and stable isotope composition;Tight reservoir is analyzed to lithology and diagenesis, determine lithology type, diagenetic sequence, densification time sequence and pore throat structure characteristics;Organic molecular marker parameter, inorganic molecular marker parameter and lithology diagenetic constraint condition are coupled, and tight oil and gas genesis identification chart is established;The method solves the problem that traditional through parent material and sedimentary environment to judge unknown oil and gas to subsequent exploration less.

Description

Technical Field

[0001] This application relates to the field of oil and gas exploration technology, and specifically discloses a method for identifying the genesis of tight oil and gas based on molecular markers and lithology. Background Technology

[0002] Tight oil and gas, as an important component of my country's unconventional oil and gas resources, directly determines exploration direction and well location deployment based on its genesis type, source attribution, and accumulation mechanism. Tight oil and gas is characterized by complex reservoir compaction sequences, diverse source rock-reservoir configurations, and strong multi-stage oil and gas charging and secondary stimulation, making conventional genetic identification methods insufficient for accurate identification.

[0003] Current hydrocarbon gene identification and source correlation mainly rely on organic geochemical indicators such as biomarkers, light hydrocarbon composition, and carbon isotopes. However, in tightly packed hydrocarbon reservoirs that are highly mature, heavily modified, and mixed-source, organic molecules are easily affected by thermal cracking, biodegradation, migration and fractionation, and water-rock reactions, resulting in significant changes in characteristic parameters. This leads to highly ambiguous source correlation results and low accuracy in gene gene identification.

[0004] To compensate for the shortcomings of traditional organic indicators, existing technologies propose using lithium isotopes for oil source comparison, such as authorized publication numbers CN110412110B, CN110412111B, CN110412112B, and CN110412108B. All of these methods establish oil reservoir type identification charts for different sedimentary environments by measuring the inorganic element content and corresponding isotopic composition in crude oil and source rocks, thus achieving a preliminary judgment on the source and origin of oil and gas.

[0005] This method has significant drawbacks in tight oil and gas scenarios, specifically as follows: Firstly, inferring unknown oil sources from the value range established in conventional oilfields introduces substantial errors. Secondly, the isotopes used are easily affected by clay adsorption, diagenetic alteration, and formation water mixing, leading to distorted results. Thirdly, relying solely on a single isotope indicator without considering biomarkers, carbon isotopes, and light hydrocarbons renders it completely ineffective for complex mixed-source reservoirs. Most critically, directly using source rocks of varying maturity to obtain isotopes fails to incorporate lithology, diagenetic sequence, compaction strength, pore-throat structure, and compaction time into the identification system, making it impossible to distinguish whether isotopic shifts originate from parent material differences, diagenetic fractionation, or water-rock reactions.

[0006] In summary, current technologies have not yet formed a comprehensive system for identifying the genesis of tight hydrocarbons by combining organic and inorganic molecular markers with lithological and diagenetic constraints. This makes it difficult to solve the technical challenges of multiple possible genesissances, unclear origins, and ambiguous formation mechanisms in complex tight hydrocarbon reservoirs. Therefore, there is an urgent need to establish a precise, stable, and suitable genetic identification method for tight hydrocarbons. Summary of the Invention

[0007] The purpose of this invention is to solve the problem that traditional methods of determining unknown oil and gas through parent material and sedimentary environment have limited impact on subsequent exploration.

[0008] To achieve the above objectives, the present invention provides the following basic solution. A method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology includes the following steps: Step S1: Simultaneously collect and preprocess source rock, tight reservoir core, and oil and gas samples; Step S2: Conduct organic molecular marker tests on oil and gas and source rock samples to obtain parent material type, maturity, and oil source comparison parameters; Step S3: Perform inorganic molecular marker tests on oil and gas and source rock samples to obtain the content of inorganic elements and stable isotope composition; Step S4: Conduct lithological and diagenetic analysis on tight reservoirs to determine lithological type, diagenetic sequence, compaction time sequence, and pore throat structure characteristics; Step S5: Couple organic molecular marker parameters and inorganic molecular marker parameters with lithological and diagenetic constraints to establish a tight hydrocarbon gene generation identification chart; Step S6: Determine the source, genetic type, and accumulation mode of tight oil and gas based on the identification map.

[0009] Furthermore, in step S1, the synchronous acquisition and preprocessing specifically include: First: Hydrocarbon source rock sample collection: Shale cores are drilled from the core well, and the weathered layer, contaminated layer, quartz veins and calcite veins are removed. Fresh samples without oxidation, oil seepage and structural fragmentation are selected, crushed to 200 mesh, and divided into three parts: one part for organic geochemical analysis, one part for inorganic molecular marker testing, and one part for backup. Secondly, core sample collection from tight reservoirs: core samples are continuously taken from the target layer, and cores with uniform oil content and no obvious crack contamination are selected. 200-mesh powder samples are prepared along the bedding direction for organic carbon and inorganic testing, and columnar samples are retained for lithology, diagenesis and pore structure analysis. Next, crude oil sample collection: samples are taken at the wellhead or separator site, using brown light-proof bottles, anhydrous ethanol is added to inhibit degradation, and the samples are sealed, stored at low temperature and protected from light. The samples are divided into two parts: one part is used for organic molecular marker analysis, and the other part is used for inorganic molecular marker separation and enrichment. Finally, natural gas sample collection: samples were collected online using high-pressure aluminum foil sampling bags and used for component and carbon isotope testing.

[0010] Furthermore, in step S2: specifically including: Step S21: Crude oil is directly used for group component separation; source rock and reservoir powder are extracted with chloroform Soxhlet for 68-72 hours, concentrated by rotary evaporation, and separated by column chromatography to obtain saturated hydrocarbons, aromatics, non-hydrocarbons and asphaltenes; Step S22: Use GCMS to test saturated hydrocarbon biomarkers to obtain data including n-alkanes, steranes, terpenes, gammaceranes, hopanes, pterostilbene, and phytanes; Step S23: According to The ratio of sterane, pterostilbene, and phytane, gammacerane, and Distribution characteristics of hopane and terpenoids are used to determine the type of parent material and the depositional environment; Step S24: Based on sterane S / R, The maturity stage was determined by hopane 22S / 22R, methylphenanthrene index, heptane number, isoheptane number, and Rc equivalent reflectance. Step S25: Determine the homology of oil sources, the proportion of mixed sources, and the degree of migration and fractionation by carbon isotopes, sterol fingerprints, feature ratio pairing, and similarity calculation.

[0011] Further, in step S3, the specific steps include: Step S31: Weigh the crude oil sample and place it in a high-pressure digestion vessel, add HNO3 and carbonize at 160℃~180℃ for 24h~30h; then add HNO3+HF and digest in a sealed container at 240℃ for 48h; after cooling, evaporate to dryness until wet salt state, remove HF with HNO3; after conversion with HCl, load onto a column; use cation exchange resin to separate and purify inorganic ions and metal elements, and after evaporating the receiving liquid to dryness, convert it into a 2% HNO3 medium for analysis; Step S32: Weigh 200-mesh powder of source rock and reservoir samples and place them in a high-pressure digestion vessel. Add HNO3+HF and digest at 240℃ in a sealed container for 48 hours. After cooling, evaporate to dryness until wet salt state, remove HF with HNO3. After conversion with HCl, load onto column. Purify with cation exchange resin, evaporate the receiving solution to dryness and convert to 2% HNO3 medium for analysis. Step S33: Using Rh as an internal standard, ICPMS was used to determine the content of inorganic molecular markers in the sample and establish an inorganic molecular marker fingerprint. Step S34: Using a multi-receiver inductively coupled plasma mass spectrometer, the mass fractionation of the standard sample cross-correction method is used to determine the isotopic composition of inorganic molecular markers for tracing the source and deposition environment.

[0012] Furthermore, the inorganic molecular markers include alkali metal elements, alkaline earth metal elements, transition metal elements, rare dispersed elements, and their corresponding stable isotopes.

[0013] Furthermore, in step S4, the specific steps are as follows: Step S41: Prepare thin sections of the tight reservoir core and observe them under a microscope to identify the rock name, color, structure and texture; use either X-ray diffraction or energy dispersive spectroscopy to determine the content and composition of quartz, feldspar, calcite, dolomite and clay minerals and other debris or interstitial materials, and determine the lithology type based on the above content and composition. Step S42: Determine the development intensity, occurrence, and distribution location of various diagenetic processes by using any one or more methods, such as thin section, scanning electron microscopy, and cathodoluminescence observation; Step S43: Arrange minerals in chronological order according to their formation sequence, cutting relationship, and inclusion relationship to establish a complete diagenetic sequence; Step S44: Use any one or more of the following methods to determine reservoir porosity and permeability: high pressure mercury intrusion, nitrogen adsorption, field emission scanning electron microscopy, and nano-CT; identify pore types; measure pore throat size, distribution, sorting, and connectivity; determine the proportion of nanopores and micropores; and clarify the reservoir compactness. Step S45: Determine the strength of reservoir densification based on the values ​​of compaction rate, cementation rate, porosity, and permeability; combine fluid inclusion homogenization temperature, cement dating, burial history and thermal evolution history simulation to determine the geological time when the reservoir changes from a conventional porous reservoir to a dense reservoir, i.e., the densification sequence. Step S46: Finally, obtain the diagenesis and hydrocarbon accumulation time sequence relationship.

[0014] Furthermore, step S46 includes at least the following: densification followed by hydrocarbon accumulation, hydrocarbon accumulation followed by densification, and hydrocarbon accumulation and densification occurring simultaneously.

[0015] Furthermore, in step S5, the specific steps are as follows: the parent material type, maturity, and oil source comparison parameters of organic molecular markers, the elemental content and isotopic composition of inorganic molecular markers, as well as lithological type, diagenetic sequence, compaction time, and pore-throat structure are coupled in multiple dimensions; a three-dimensional identification coordinate system is constructed with organic maturity as the X-axis, inorganic indicators as the Y-axis, and lithological diagenetic constraints as the Z-axis; known genetic samples are projected onto the coordinate system to form a tight oil and gas genetic identification chart.

[0016] Furthermore, the tight oil and gas genesis identification chart includes at least in-situ autogenic oil and gas, exogenous migration-type tight oil and gas, and ancient reservoir rift-type tight oil and gas.

[0017] The principle and effect of this solution are as follows: 1. Compared with the existing technology, the present invention couples organic molecular markers, inorganic molecular markers, lithology and diagenesis, overcoming the shortcomings of traditional single organic or single inorganic indicators that are easily modified and have strong ambiguity, and the identification results are more stable and reliable.

[0018] 2. Compared with the existing technology, the present invention introduces constraints of lithology type, diagenetic sequence, densification time sequence and pore throat structure, which can accurately distinguish three key hydrocarbon accumulation time sequences: first densification and then hydrocarbon accumulation, first hydrocarbon accumulation and then densification, and hydrocarbon accumulation and densification occurring simultaneously, truly conforming to the hydrocarbon accumulation law of tight reservoirs.

[0019] 3. Compared with existing technologies, it significantly improves the accuracy of exploration deployment, generating in-situ self-generated, exogenous migration, and ancient reservoir fracture types. In-situ self-generated types guide large-scale exploration near the source; exogenous migration types guide the search for high-yield sweet spots along the transport system; ancient reservoir fracture types guide exploration in deep, ancient structural, high-temperature, and high-pressure areas. It can directly serve zonal evaluation, well location selection, reserve estimation, and development plan formulation.

[0020] 4. Compared with existing technologies, this method has a wider range of applications and stronger anti-interference capabilities. It is suitable for complex tight oil and gas reservoirs such as highly mature, strongly modified, mixed-source, and multi-layered reservoirs. It can still accurately identify reservoirs even when conventional geochemical indicators fail. It is applicable to a wider range of basin and reservoir types. The method is standardized and highly scalable. The sample collection, pretreatment, testing, and identification processes are complete and standardized. The data is repeatable and comparable, meeting the needs of industrial exploration and easy to promote and apply in major oil and gas fields. Attached Figure Description

[0021] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0022] Figure 1 The diagram shows a flowchart of a tight oil and gas genesis identification method based on molecular markers and lithology proposed in an embodiment of this application. Detailed Implementation

[0023] To further illustrate the technical means and effects of the present invention in achieving its intended purpose, the following detailed description of the specific implementation methods, structures, features, and effects of the present invention, in conjunction with the accompanying drawings and preferred embodiments, is provided below.

[0024] A method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology, specifically as follows: Figure 1 As shown: Includes the following steps: Step S1: Simultaneously collect and preprocess source rock, tight reservoir core, and oil and gas samples; In step S1, the synchronous acquisition and preprocessing specifically include: First, source rock sample collection: Shale cores are drilled from the core well, and weathered layers, contaminated layers, quartz veins and calcite veins are removed. Fresh samples without oxidation, oil seepage and structural fragmentation are selected, crushed to 200 mesh, and divided into three parts: one part for organic geochemical analysis, one part for inorganic molecular marker testing, and one part for backup.

[0025] Secondly, core samples were collected from tight reservoirs: core samples were continuously taken from the target layer, and cores with uniform oil content and no obvious crack contamination were selected. 200-mesh powder samples were prepared along the bedding direction of the cores for organic carbon and inorganic testing, and columnar samples were retained for lithology, diagenesis and pore structure analysis.

[0026] Next, crude oil sample collection: samples are taken at the wellhead or separator site, using brown light-proof bottles, anhydrous ethanol is added to inhibit degradation, and the samples are sealed, stored at low temperature and protected from light. The samples are divided into two parts: one part is used for organic molecular marker analysis, and the other part is used for inorganic molecular marker separation and enrichment.

[0027] Finally, natural gas sample collection: samples were collected online using high-pressure aluminum foil sampling bags and used for component and carbon isotope testing.

[0028] Step S2: Conduct organic molecular marker tests on oil and gas and source rock samples to obtain the parent material type, maturity, and oil source comparison parameters.

[0029] Specifically, step S2 includes: Step S21: Crude oil is directly used for group component separation; source rock and reservoir powder are extracted with chloroform Soxhlet for 68-72 hours, concentrated by rotary evaporation, and separated by column chromatography to obtain saturated hydrocarbons, aromatics, non-hydrocarbons and asphaltenes; Step S22: Use GCMS to test saturated hydrocarbon biomarkers to obtain data including n-alkanes, steranes, terpenes, gamma-acetylene, hopane, pterostilbene, and phytane.

[0030] Specifically: Saturated hydrocarbons were tested using GCMS: the initial temperature was 50℃~80℃ and held for 1min~5min, then increased to 290℃~310℃ at 3℃ / min~5℃ / min and held for 15min~30min. Data on n-alkanes, steranes, terpenes, gamma-ceranes, hopanes, pterostilbene, and phytanes were detected.

[0031] Step S23: According to The ratio of sterane, pterostilbene, and phytane, gammacerane, and Distribution characteristics of hopane and terpenoids can be used to determine the type of parent material and the depositional environment.

[0032] This embodiment discloses the following types of parent material: Pterosine / Phytane <1: Strong reducing environment; 1-2: Weak reducing environment; >2: Oxidizing environment, Gammacerane / Hobane: High values: saline water, stratified lacustrine / marine environments; Low values: freshwater environments.

[0033] Sterane ratio: High: Primarily composed of phytoplankton, i.e., saprophytic matrix, which mainly produces oil. High: Primarily terrestrial higher plants, i.e., humic parent material. Humic parent material mainly produces gas. Terpenoid distribution characteristics: If orane is high: Terrestrial input; if tricyclic terpenoid is high: Marine or deep-water environment. Based on the above parameters, the parent material type is automatically determined: saprophytic, humic, or mixed. At the same time, the sedimentary environment is determined based on the parent material type: Marine, terrestrial lacustrine basin, or coal-bearing.

[0034] Step S24: Determine the maturity stage of tight oil and gas based on data such as sterane S / R, C31 hopane 22S / 22R, methyl phenanthrene index, heptane number, isoheptane number, and Rc equivalent reflectance. Specifically, a higher sterane S / R and C31 hopane 22S / 22R ratio indicates higher maturity; the methyl phenanthrene index can be used to calculate Rc equivalent reflectance, and higher heptane and isoheptane numbers indicate higher maturity; regarding aromatics, a decrease in high molecular weight aromatics content and an increase in low molecular weight aromatics content represent higher maturity.

[0035] Specifically: The homology, mixed-source ratio, and migration fractionation degree of oil sources are determined through carbon isotope analysis, sterol fingerprinting, characteristic ratio pairing, and similarity calculation. Specific determination methods are as follows: Carbon isotope analysis: If the carbon isotope values ​​of the crude oil and a certain source rock are close, they are considered to be from the same source; Sterol fingerprinting: If the morphology of the sterane distribution curves highly overlaps, they are considered to be from the same source; large differences in the curves indicate different sources; n-alkane characteristics: If the peak shape, main peak carbon, and odd / even dominance of n-alkanes are completely identical, they are considered to be from the same source; Similarity calculation: The similarity between the crude oil and the parameters of each source rock set is calculated. A similarity > 90% indicates homology, a moderate similarity indicates mixed-source, and a similarity < 60% indicates different sources.

[0036] Regarding maturity: The Rc equivalent reflectance is calculated using the methylphenanthrene index, which is existing technology and the algorithm will not be disclosed in detail here.

[0037] Step S3: Perform inorganic molecular marker tests on oil and gas and source rock samples to obtain the content of inorganic elements and stable isotope composition; Step S3 specifically includes: Step S31: Weigh the crude oil sample and place it in a high-pressure digestion vessel, add HNO3 and carbonize at 160℃~180℃ for 24h~30h; then add HNO3+HF and digest in a sealed container at 240℃ for 48h; after cooling, evaporate to dryness until wet salt state, remove HF with HNO3; add HCl for conversion and then load onto a column; use cation exchange resin to separate and purify inorganic ions and metal elements, and after evaporating the receiving liquid to dryness, convert it into a 2% HNO3 medium for analysis; Step S32: Weigh 200-mesh powder of source rock and reservoir samples and place them in a high-pressure digestion vessel. Add HNO3+HF and digest at 240℃ in a sealed container for 48 hours. After cooling, evaporate to dryness until wet salt state, remove HF with HNO3. After conversion with HCl, load onto column. Purify with cation exchange resin, evaporate the receiving solution to dryness and convert to 2% HNO3 medium for analysis. Step S33: Using Rh as an internal standard, ICPMS was used to determine the content of inorganic molecular markers in the sample and establish an inorganic molecular marker fingerprint. Step S34: Using a multi-receiver inductively coupled plasma mass spectrometer, the mass fractionation of the standard sample cross-correction method is used to determine the isotopic composition of inorganic molecular markers for tracing the source and deposition environment.

[0038] The inorganic molecular markers include alkali metal elements, alkaline earth metal elements, transition metal elements, rare dispersed elements, and their corresponding stable isotopes.

[0039] Step S4: Conduct lithological and diagenetic analysis on tight reservoirs to determine lithological type, diagenetic sequence, compaction time sequence, and pore throat structure characteristics; In step S4, the specific steps are as follows: Step S41: Prepare thin sections of the tight reservoir core and observe them under a microscope to identify the rock name, color, structure and texture; use either X-ray diffraction or energy dispersive spectroscopy to determine the content and composition of quartz, feldspar, calcite, dolomite and clay minerals and other debris or interstitial materials, and determine the lithology type based on the above content and composition. Step S42: Determine the development intensity, occurrence, and distribution location of various diagenetic processes by using any one or more methods, such as thin section, scanning electron microscopy, and cathodoluminescence observation; Step S43: Arrange minerals in chronological order according to their formation sequence, cutting relationship, and inclusion relationship to establish a complete diagenetic sequence; Step S44: Use any one or more of the following methods to determine reservoir porosity and permeability: high pressure mercury intrusion, nitrogen adsorption, field emission scanning electron microscopy, and nano-CT; identify pore types; measure pore throat size, distribution, sorting, and connectivity; determine the proportion of nanopores and micropores; and clarify the reservoir compactness. Step S45: Determine the strength of reservoir densification based on the values ​​of compaction rate, cementation rate, porosity, and permeability; combine fluid inclusion homogenization temperature, cement dating, burial history and thermal evolution history simulation to determine the geological time when the reservoir changes from a conventional porous reservoir to a dense reservoir, i.e., the densification sequence. Step S46: Finally, the diagenesis and hydrocarbon accumulation time sequence relationship is obtained. Step S46 includes at least the following: first densification followed by hydrocarbon accumulation, first hydrocarbon accumulation followed by densification, and hydrocarbon accumulation and densification occurring simultaneously.

[0040] Step S5: Couple organic molecular marker parameters and inorganic molecular marker parameters with lithological and diagenetic constraints to establish a tight hydrocarbon gene generation identification chart; In step S5, the specific steps are as follows: Multi-dimensional data coupling is performed on the parent material type, maturity, and source comparison parameters of organic molecular markers, the elemental content and isotopic composition of inorganic molecular markers, as well as lithological type, diagenetic sequence, compaction time, and pore-throat structure; a three-dimensional identification coordinate system is constructed with organic maturity as the X-axis, inorganic indicators as the Y-axis, and lithological constraints as the Z-axis; known genetic samples are projected onto the coordinate system to form a tight oil and gas genetic identification map. This map includes at least in-situ authigenic oil and gas, exogenous migration-type tight oil and gas, and paleoreservoir fracture-type tight oil and gas. Step S6: Based on the identification map, the source attribution, genetic type, and reservoir formation model of the tight oil and gas are determined.

[0041] Specifically: First, regarding multi-dimensional data coupling, the obtained data on parent material type, maturity, oil source correlation parameters, inorganic element content, inorganic isotope composition, lithology type, diagenetic sequence, densification time series, and pore throat structure are uniformly organized and normalized to form a multi-dimensional coupled dataset.

[0042] Secondly, using organic maturity parameters, such as Rc, MPI, and sterane S / R, as the X-axis, inorganic molecular marker parameters, i.e., the ratio of elemental ratio to the corresponding isotopic value, as the Y-axis, and lithological constraints, such as compaction time, pore-throat structure, and diagenetic intensity, as the Z-axis, a three-dimensional genetic identification coordinate system is constructed. Tight oil and gas samples with known genesis are projected onto the three-dimensional coordinate system to delineate the distribution areas of three types of samples: in-situ authigenic, exogenous migration, and paleoreservoir fracture, and to determine the boundary thresholds for each category.

[0043] Within a three-dimensional coordinate system, a coupled identification chart for organic, inorganic, and lithological diagenesis is formed that can be directly used for identification. The chart clearly marks: the distribution range and determination threshold of in-situ authigenic tight oil and gas; the distribution range and determination threshold of exogenous migration tight oil and gas; and the distribution range and determination threshold of ancient reservoir fractured tight oil and gas.

[0044] It is important to note that multiple sets of known oil source samples are needed to verify the identification chart, correct the boundary thresholds and partition intervals, and ensure that the identification accuracy meets the requirements of exploration applications.

[0045] Example 1: Twelve groups of tight oil samples, confirmed to be of in-situ authigenic type from a certain basin, were selected and tested according to the above steps. The boundary thresholds and partitioning intervals were corrected using these 12 groups of in-situ authigenic tight oil samples to obtain the organic parameters. High values ​​indicate saprophytic parent material, Pr / Ph (phallane / phytane) < 1, and maturity Rc = 0.9%-1.1%; inorganic parameters: inorganic element fingerprint consistent with source rocks, no obvious isotopic fractionation; lithology and diagenesis: tight sandstone, nanopore throat ratio > 70%, hydrocarbon accumulation and densification occurring simultaneously. Projecting the above data onto a three-dimensional X (maturity) - Y (inorganic) - Z (lithology and diagenesis) coordinate system delineates the in-situ authigenic distribution area.

[0046] Example 2: Establishing an identification map based on known genetic samples. Twelve groups of tight oil and gas samples confirmed to be of exogenous migration type were selected. Following the steps described above, the boundary thresholds and zoning intervals were corrected using these 12 groups of exogenous migration type tight oil samples. Organic parameters: mixed parent material, maturity Rc = 1.1%-1.3%, migration fractionation present; Inorganic parameters: significant fractionation shift in isotopes and elements; Lithology and diagenesis: development of dissolution pores and fractures, prior to reservoir formation followed by tightening. After projection, the exogenous migration type region was delineated. Test results of the unknown oil and gas samples to be tested: S2 parent material: mixed type, Pr / Ph = 1.5; Maturity: Rc = 1.21%, high maturity; Source comparison: 82% similarity to deep source rocks, fractionation present; significant isotopic shift compared to source rocks; development of fractures and dissolution pores in lithology and diagenesis, indicating prior to reservoir formation followed by tightening.

[0047] Example 3: 12 sets of tight gas samples confirmed to be from ancient oil reservoirs were selected: Following the above steps, the boundary threshold and partition interval were corrected using the 12 sets of tight oil samples from ancient oil reservoirs. Organic parameters were obtained: high indicates over-maturity, Rc=1.6%-2.0%, and severe cracking of sterols; Inorganic parameters: heavy isotopes and enrichment of characteristic elements; Lithology and diagenesis: the reservoir contains pyrophage, and compaction occurred earlier than the peak of hydrocarbon generation.

[0048] Examples 1-3 delineated the in-situ autogenic distribution area, the exogenous migration area, and the ancient reservoir rifting area.

[0049] In-situ autogenic type: Inorganic indicators are highly matched with source rocks, organic indicators are homologous, densification and hydrocarbon generation occur simultaneously, and nanopores and throats are dominant; Exogenous migration type: Inorganic indicators exhibit migration and fractionation, organic indicators show distant source characteristics, and the reservoir develops transport channels and dissolution pores; Paleo-reservoir pyrolysis type: Inorganic indicators are enriched / heavier, organic indicators are highly mature and pyrolyzed, the reservoir contains bitumen, and densification occurs earlier than the peak of hydrocarbon generation.

[0050] Next, if unknown oil and gas are found, oil and gas samples are obtained according to the above method. By obtaining the organic parameters, inorganic parameters and lithological parameters of the unknown oil and gas sample, it is determined which of the above-mentioned in-situ autogenic distribution areas, exogenous migration areas and ancient reservoir fracture areas the oil and gas sample falls into, and thus the type of the unknown oil and gas sample is determined.

[0051] This method is beneficial for the exploration of this unknown oil field and subsequent construction, because existing methods only determine the parent material and sedimentary environment: marine, continental, coal-bearing, and can only answer what environment the oil was formed in. This method can determine the unique formation mechanism of tight oil and gas: in-situ retention, distant migration, and ancient reservoir rifting, and directly answer: how oil and gas enter the tight reservoir, when they are injected, and how they are preserved.

[0052] From the perspective of practicality in exploration deployment, the identification chart of this invention is far superior to the identification charts of parent material and sedimentary environment.

[0053] This invention, based on reservoir formation mechanisms and enrichment patterns, classifies tight oil and gas into three categories: in-situ autogenic, exogenous migration, and ancient reservoir fracture. It directly clarifies exploration direction, migration paths, enrichment zone types, well placement principles, and sweet spot identification criteria. This effectively guides zone evaluation, target selection, and well placement, better meeting the practical needs of tight oil and gas exploration and development. It possesses significant technical advantages and practicality, as this invention can determine enrichment patterns. These enrichment patterns directly determine: well spacing, whether to drill vertical or horizontal wells, whether to perform fracturing operations, and which segment to prioritize for development, etc.

[0054] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology, characterized in that, Includes the following steps: Step S1: Simultaneously collect and preprocess source rock, tight reservoir core, and oil and gas samples; Step S2: Conduct organic molecular marker tests on oil and gas and source rock samples to obtain parent material type, maturity, and oil source comparison parameters; Step S3: Perform inorganic molecular marker tests on oil and gas and source rock samples to obtain the content of inorganic elements and stable isotope composition; Step S4: Conduct lithological and diagenetic analysis on tight reservoirs to determine lithological type, diagenetic sequence, compaction time sequence, and pore throat structure characteristics; Step S5: Couple organic molecular marker parameters and inorganic molecular marker parameters with lithological and diagenetic constraints to establish a tight hydrocarbon gene generation identification chart; Step S6: Determine the source, genetic type, and accumulation mode of tight oil and gas based on the identification map.

2. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 1, characterized in that, In step S1, the synchronous acquisition and preprocessing specifically include: First: Hydrocarbon source rock sample collection: Shale cores are drilled from the core well, and the weathered layer, contaminated layer, quartz veins and calcite veins are removed. Fresh samples without oxidation, oil seepage and structural fragmentation are selected, crushed to 200 mesh, and divided into three parts: one part for organic geochemical analysis, one part for inorganic molecular marker testing, and one part for backup. Secondly, core sample collection from tight reservoirs: core samples are continuously taken from the target layer, and cores with uniform oil content and no obvious crack contamination are selected. 200-mesh powder samples are prepared along the bedding direction for organic carbon and inorganic testing, and columnar samples are retained for lithology, diagenesis and pore structure analysis. Next, crude oil sample collection: samples are taken at the wellhead or separator site, using brown light-proof bottles, anhydrous ethanol is added to inhibit degradation, and the samples are sealed, stored at low temperature and protected from light. The samples are divided into two parts: one part is used for organic molecular marker analysis, and the other part is used for inorganic molecular marker separation and enrichment. Finally, natural gas sample collection: samples were collected online using high-pressure aluminum foil sampling bags and used for component and carbon isotope testing.

3. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 2, characterized in that, In step S2: Specifically, it includes: Step S21: Crude oil is directly used for group component separation; source rock and reservoir powder are extracted with chloroform Soxhlet for 68-72 hours, concentrated by rotary evaporation, and separated by column chromatography to obtain saturated hydrocarbons, aromatics, non-hydrocarbons and asphaltenes; Step S22: Use GCMS to test saturated hydrocarbon biomarkers to obtain data including n-alkanes, steranes, terpenes, gammaceranes, hopanes, pterostilbene, and phytanes; Step S23: According to The ratio of sterane, pterostilbene, and phytane, gammacerane, and Distribution characteristics of hopane and terpenoids can be used to determine the type of parent material and the depositional environment. Step S24: Based on sterane S / R, The maturity stage was determined by hopane 22S / 22R, methylphenanthrene index, heptane number, isoheptane number, and Rc equivalent reflectance. Step S25: Determine the homology of oil sources, the proportion of mixed sources, and the degree of migration and fractionation by carbon isotopes, sterol fingerprints, feature ratio pairing, and similarity calculation.

4. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 3, characterized in that, Step S3 specifically includes: Step S31: Weigh the crude oil sample and place it in a high-pressure digestion vessel, add HNO3 and carbonize at 160℃~180℃ for 24h~30h; then add HNO3+HF and digest in a sealed container at 240℃ for 48h; after cooling, evaporate to dryness until wet salt state, remove HF with HNO3; add HCl for conversion and then load onto a column; use cation exchange resin to separate and purify inorganic ions and metal elements, and after evaporating the receiving liquid to dryness, convert it into a 2% HNO3 medium for analysis; Step S32: Weigh 200-mesh powder of source rock and reservoir samples and place them in a high-pressure digestion vessel. Add HNO3+HF and digest at 240℃ in a sealed container for 48 hours. After cooling, evaporate to dryness until wet salt state, remove HF with HNO3. After conversion with HCl, load onto column. Purify with cation exchange resin, evaporate the receiving solution to dryness and convert to 2% HNO3 medium for analysis. Step S33: Using Rh as an internal standard, ICPMS was used to determine the content of inorganic molecular markers in the sample and establish an inorganic molecular marker fingerprint. Step S34: Using a multi-receiver inductively coupled plasma mass spectrometer, the mass fractionation of the standard sample cross-correction method is used to determine the isotopic composition of inorganic molecular markers for tracing the source and deposition environment.

5. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 4, characterized in that, The inorganic molecular markers include alkali metal elements, alkaline earth metal elements, transition metal elements, rare dispersed elements, and their corresponding stable isotopes.

6. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 4, characterized in that, In step S4, the specific steps are as follows: Step S41: Prepare thin sections of the tight reservoir core and observe them under a microscope to identify the rock name, color, structure and texture; use either X-ray diffraction or energy dispersive spectroscopy to determine the content and composition of quartz, feldspar, calcite, dolomite and clay minerals and other debris or interstitial materials, and determine the lithology type based on the above content and composition. Step S42: Determine the development intensity, occurrence, and distribution location of various diagenetic processes by using any one or more methods, such as thin section, scanning electron microscopy, and cathodoluminescence observation; Step S43: Arrange minerals in chronological order according to their formation sequence, cutting relationship, and inclusion relationship to establish a complete diagenetic sequence; Step S44: Use any one or more of the following methods to determine reservoir porosity and permeability: high pressure mercury intrusion, nitrogen adsorption, field emission scanning electron microscopy, and nano-CT; identify pore types; measure pore throat size, distribution, sorting, and connectivity; determine the proportion of nanopores and micropores; and clarify the reservoir compactness. Step S45: Determine the strength of reservoir densification based on the values ​​of compaction rate, cementation rate, porosity, and permeability; combine fluid inclusion homogenization temperature, cement dating, burial history and thermal evolution history simulation to determine the geological time when the reservoir changes from a conventional porous reservoir to a dense reservoir, i.e., the densification sequence. Step S46: Finally, obtain the diagenesis and hydrocarbon accumulation time sequence relationship.

7. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 6, characterized in that, Step S46 includes at least the following: densification followed by hydrocarbon accumulation, hydrocarbon accumulation followed by densification, and hydrocarbon accumulation and densification occurring simultaneously.

8. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 6, characterized in that, In step S5, the specific steps are as follows: Multi-dimensional data coupling is performed on the parent material type, maturity, and oil source comparison parameters of organic molecular markers, the elemental content and isotopic composition of inorganic molecular markers, as well as lithological type, diagenetic sequence, compaction time, and pore-throat structure; a three-dimensional identification coordinate system is constructed with organic maturity as the X-axis, inorganic indicators as the Y-axis, and lithological diagenetic constraints as the Z-axis; known genetic samples are projected onto the coordinate system to form a tight oil and gas genetic identification chart.

9. The method for identifying the genesis of tight hydrocarbons based on molecular markers and lithology according to claim 8, characterized in that, The tight oil and gas genesis identification chart includes at least in-situ autogenic oil and gas, exogenous migration-type tight oil and gas, and ancient reservoir rift-type tight oil and gas.

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