A quantitative evaluation method for in-situ gas content and occurrence state in shale / coal based on multi-method coupling

Abstract

A quantitative evaluation method for in-situ gas content and occurrence state in shale / coal formations based on multi-method coupling includes the following steps: 1. Establishing an in-situ analytical experimental setup; 2. Implementing the in-situ analytical experimental procedure; 3. Data processing and parameter summarization; 4. Evaluating in-situ gas content using the USBM method; 5. Evaluating in-situ gas content using the polynomial method; 6. Evaluating in-situ gas content using the ACF method; 7. Evaluating in-situ gas content using the MCF method; 8. Evaluating in-situ gas content using the isotope fractionation method (CIF method); 9. Comparative analysis and comprehensive evaluation of the results from multiple methods. This method establishes a novel approach for the quantitative identification of adsorbed / free gas based on the isotope fractionation mechanism, achieving accurate quantitative characterization of in-situ gas content and gas occurrence state in deep unconventional reservoirs. It provides a scientific basis for reserve assessment, selection of favorable targets, and optimization of development schemes, and is applicable to both deep shale gas and deep coal gas.

Description

Technical Field

[0001] This invention relates to the field of unconventional shale oil and gas field exploration and development technology, specifically to a quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling. Background Technology

[0002] Deep coalbed methane (buried at a depth greater than 1500 meters) is gradually becoming an important source of natural gas supply. Deep unconventional reservoirs have special geological conditions such as high temperature, high pressure, and high ground stress. Their gas occurrence characteristics and development mechanisms are significantly different from those of shallow and medium-depth reservoirs, which places higher demands on reservoir evaluation technology.

[0003] Deep shale / coal gas reservoirs exhibit complex geological characteristics. Under the high temperature and pressure environment of deep formations, gas exists simultaneously in both adsorbed and free states, with the proportion varying significantly with depth, pressure, and temperature. Studies show that when the pressure reaches 50 MPa, the ratio of adsorbed to free gas in deep shale can vary between 23% and 74%. Reservoir space ranges from nanoscale pores to micrometer-millimeter-scale microfractures, with pore sizes spanning several orders of magnitude. Deep reservoirs are characterized by ultra-low porosity and ultra-low permeability, with porosity mostly below 10%, matrix permeability at the nanodarcy level, and strong vertical heterogeneity. Gas content is a core parameter for shale / coal gas resource evaluation and development planning, directly affecting the accuracy of reserve calculations, the selection of favorable targets, and the optimization of development plans. It is particularly important to emphasize that in the development of deep shale / coal gas, it is not only necessary to accurately determine the total gas content, but also to clarify the ratio of adsorbed gas to free gas, because the desorption mechanisms, flow characteristics and exploitability of the two are fundamentally different.

[0004] In-situ analysis is an important method for obtaining gas content and is widely used in the exploration and development of coalbed methane and shale gas. This method involves rapidly loading the extracted core into a sealed desorption container and performing gas desorption under simulated formation temperature conditions. The total gas content is obtained by measuring the volume of desorbed gas and calculating the lost and remaining gas volumes. However, the traditional USBM (United States Bureau of Mine) method for calculating gas loss has significant limitations. Studies have shown that this method is not suitable for the deep burial characteristics of shale formations in China, and the gas escape velocity exhibits nonlinear characteristics when the core is pulled up in the wellbore. 0.5Since the linear segment of cumulative desorption does not pass through the origin, the USBM method introduces additional gas loss. For gas reservoirs with normal pressure coefficients, the gas loss is often underestimated; for abnormally high-pressure gas reservoirs, the loss may be underestimated. Furthermore, the measurement period for desorbed gas is long, ranging from 2 weeks to 4 months, and is affected by various factors such as drilling fluid properties, coring process, and core preservation conditions, resulting in poor reproducibility. Most importantly, while traditional analytical methods can determine total gas content, adsorbed gas flows together with free gas after desorption, making it difficult to directly obtain the individual contents of each and thus unable to accurately assess the gas occurrence state.

[0005] Isothermal adsorption experiments measure the amount of gas adsorbed under different pressures at a constant temperature and calculate the adsorbed gas content based on the Langmuir model. This method requires pulverizing samples to a particle size of 0.150-0.425 mm, severely damaging the original pore structure and mineral composition, resulting in significant discrepancies with actual reservoir conditions. The adsorption behavior of deep shale gas under high-pressure conditions differs from conventional low-pressure adsorption; high-pressure isothermal adsorption curves exhibit a maximum excess adsorption capacity, which the traditional Langmuir model cannot accurately describe. Under the same temperature and pressure conditions, the desorption curve lags significantly behind the adsorption curve. Since shale gas production involves desorption, using adsorption data to predict production capacity will introduce systematic biases. More importantly, isothermal adsorption experiments can only measure the adsorbed gas content and cannot obtain information on free gas. While well logging interpretation methods can continuously calculate reservoir gas content, they require a large number of petrophysical parameters as input. Deep reservoirs are highly heterogeneous, making it difficult to establish a unified interpretation model, often resulting in significant errors compared to in-situ desorption methods.

[0006] In recent years, isotope geochemistry has shown great promise in assessing the state of gas occurrence. Natural gas undergoes carbon isotope fractionation during migration, adsorption, and desorption. 13 CH4 ratio 12 CH4 has a greater adsorption capacity. Studies have found that methane carbon isotope fractionation during shale gas desorption exhibits distinct stage characteristics: the free gas pressure difference seepage stage δ 13 The C1 value remained essentially unchanged, and the δ value during the adsorption-free conversion stage remained relatively constant. 13 The C1 value gradually decreases, and the δ value during the adsorbed gas desorption stage increases. 13 The C1 value gradually increases, indicating the concentration gradient diffusion stage δ 13 The C1 value decreased again and eventually stabilized. The carbon isotope evolution patterns differed among shale facies: the δ¹⁺ value of argillaceous-siliceous mixed shale... 13 The change in C1 from heavy to light indicates that the desorbed gas is mainly free gas, and the δ¹⁺ of silica-rich shale... 13 The change in C1 density from light to heavy indicates that the desorbed gas is predominantly adsorbed gas. This provides a scientific basis for quantitatively evaluating the adsorbed gas / free gas ratio using isotopic fractionation effects. Isotopic methods can evaluate gas content close to the original state of the formation, and based on well-defined physicochemical principles, the results are more reliable.

[0007] Existing methods for determining gas content all have limitations: the USBM method suffers from systematic biases in calculating gas loss; isothermal adsorption experiments damage sample structure and can only evaluate adsorbed gas; well logging interpretation methods have large uncertainties in model parameters; and while isotope methods show potential, a systematic evaluation framework has not yet been established. Relying on a single method is insufficient for accurately and comprehensively evaluating the gas content and gas occurrence state of deep shale / coal formations. Therefore, there is an urgent need to establish a comprehensive evaluation system that integrates multiple methods. Summary of the Invention

[0008] Based on the background technology, the purpose of this invention is to propose a quantitative evaluation method for in-situ gas content and occurrence state in shale / coal formations based on multi-method coupling. This application constructs a standardized field analytical experimental setup and process, combines cross-comparison of various gas loss calculation methods such as the USBM method, polynomial method, ACF method, and MCF method, introduces isotope fractionation to verify the gas occurrence state from a geochemical perspective, and establishes a quantitative calculation model for the adsorbed gas / free gas ratio based on the evolution characteristics of desorbed gas volume and isotopic composition. Ultimately, this achieves accurate quantitative characterization of in-situ gas content and gas occurrence state in deep unconventional reservoirs.

[0009] The technical solution provided by this invention is:

[0010] A quantitative evaluation method for in-situ gas content and occurrence state in shale / coal based on multi-method coupling includes the following steps:

[0011] (1) Establishing an on-site analytical experimental device: The device includes an analytical tank, the lower part of which is located in a constant temperature water bath heating system. The upper end cover of the analytical tank is connected to the gas metering system, the data recording system and auxiliary equipment respectively. The gas metering system is connected to the gas sampling system.

[0012] (2) Implementation of field analysis experiment procedure: The standardized operation procedure for field analysis experiment is as follows: a. Core preparation; b. Analysis system assembly; c. Analysis experiment; d. Gas sampling; e. Analysis termination; f. Residual gas measurement; h. Isotope testing;

[0013] (3) Data processing and parameter summarization: a. Cumulative analytical gas volume data; b. Isotope data; c. Basic parameters;

[0014] (4) Evaluate in-situ gas content using the USBM method;

[0015] (5) Apply the polynomial method to evaluate in-situ gas content;

[0016] (6) Evaluate in-situ gas content using the ACF method;

[0017] (7) Evaluate in-situ gas content using the MCF method;

[0018] (8) Evaluation of in-situ gas content using isotope fractionation (CIF method);

[0019] (9) Comparative analysis and comprehensive evaluation of results from multiple methods: The evaluation results of the above five methods are systematically compared and comprehensively analyzed. The evaluation results of the five methods are listed in the form of bar charts to intuitively compare the differences in in-situ gas content evaluated by various methods. Only the isotope method can directly evaluate the ratio of adsorbed gas to free gas. Therefore, the final evaluation result of the ratio of adsorbed gas to free gas is based on the isotope method.

[0020] In step (1) above: the upper cover of the analytical tank is provided with a pressure sensor interface, a temperature sensor interface, a gas outlet and an auxiliary equipment connection port;

[0021] The constant temperature water bath heating system includes a constant temperature water bath chamber and a temperature control unit; the analytical tank is placed inside the constant temperature water bath chamber;

[0022] The gas metering system includes a wet gas flow meter, and the inlet of the wet gas flow meter is connected to the gas outlet of the desorption tank via a pipeline.

[0023] The gas sampling system is located at the rear end of the gas metering system. The gas sampling system includes a gas collection tank and a glass saline bottle. The outlet of the wet gas flow meter is located in the gas collection tank, and the inlet of the glass saline bottle is located in the gas collection tank.

[0024] The data recording system includes a pressure sensor, a temperature sensor, and a data acquisition unit. The pressure sensor is installed at the top interface of the analysis tank, the temperature sensor probe extends into the analysis tank or is close to the inner wall of the analysis tank, and the data acquisition unit is electrically connected to the pressure sensor and the temperature sensor respectively.

[0025] The auxiliary equipment includes a vacuum pump, a nitrogen cylinder, a balance, and vernier calipers; the vacuum pump and nitrogen cylinder are connected to the top interface of the analytical tank via pipelines.

[0026] In step (2) above: core preparation: after the core is lifted to the ground, the core is taken out of the core tube as soon as possible; a complete core segment without obvious cracks is selected as the analytical sample;

[0027] The analytical system assembly includes: connecting a gas metering system, a gas sampling system, and a data recording system; using a vacuum pump to evacuate the analytical tank; after evacuation, placing the core sample into the analytical tank, sealing it, and then turning on the constant temperature water bath heating system to heat the analytical tank;

[0028] The analytical experiment is as follows: Open the gas discharge valve of the analytical tank to start the analytical experiment; during the analytical process, keep the analytical temperature relatively stable, and the temperature fluctuation shall not exceed ±2℃;

[0029] The gas sampling process involves collecting the produced gas using a glass saline bottle; after sampling, the analysis experiment continues.

[0030] The analysis is considered to be basically completed when the gas production per unit time is less than 1% of the initial gas production rate, or the cumulative gas production over 24 hours is less than 0.5% of the total gas production.

[0031] The residual gas determination: After the analysis experiment, the core was taken out of the analysis tank and immediately put into the grinding tank. The core was crushed to a particle size of <0.25mm by ball milling and crushing. The amount of gas released during the crushing process was measured under closed conditions.

[0032] The isotope test involves sending the collected gas sample to the laboratory and using a gas chromatography-isotope ratio mass spectrometer to determine the carbon isotope composition of methane, with a test accuracy of ±0.2‰.

[0033] In step (3) above: the cumulative analytical gas volume data: processing time (t, hour) and the corresponding cumulative analytical gas volume (Q) g_mea (t),m 3 / t or mL / g) data pairs; convert cumulative gas volume to gas volume per unit mass of core, in m³. 3 / t;

[0034] The isotope data mentioned: Sampling time (t) i ) and the corresponding methane carbon isotope value (δ 13 C 1_mea (t i ),‰) data pairs;

[0035] The basic parameters mentioned include: core radius r, core length H, core mass m, and core apparent density ρ. rock , Parsing start time t0, Parsing end time t end Total analytical gas volume Q total Residual gas volume Q residual Reservoir burial depth h Depth Pressure coefficient α p Initial reservoir pressure P o Reservoir temperature T, core removal time t coring Ground exposure time t exposure Drilling fluid density ρ mud parameter.

[0036] In step (4) above: the USBM method is based on the theory of gas diffusion in rocks, and it is believed that in the initial stage of desorption, the cumulative desorption gas volume Q(t) is proportional to the square root of time (t). 0.5 A linear relationship exists:

[0037] (1);

[0038] Q d (t) represents the cumulative degassing content in the analyzer at time t, m 3 / t;Q l_USBM For calculating the loss gas content using the USBM method, m 3 / t;K l It is the slope of the regression line; t l Known as "gas loss time", it is defined as follows:

[0039] (2);

[0040] Where t coring It is the time it takes for the core sample to be lifted from the bottom of the well to the surface; t exposure This refers to the exposure time of the core sample in the atmosphere before it is loaded into the degassing tank.

[0041] In step (5) above: the polynomial method is used to describe the nonlinear variation characteristics in the gas desorption curve; a quadratic polynomial is used to express the relationship between the cumulative desorption gas volume and the square root of time:

[0042] (3);

[0043] Where a l b is the coefficient of the quadratic term in the polynomial method; l Q is the coefficient of the linear term in the polynomial method; l_Poly For the polynomial method to calculate the loss gas content, m 3 / t.

[0044] In step (6) above: the ACF method is based on a gas diffusion model with a single pore structure, assuming that the gas undergoes Fick diffusion in a homogeneous porous medium; unlike the USBM method and the polynomial method, the ACF method fits and inverts all the field degassing data; the ACF method describes the relationship between the lost gas volume, the cumulative desorbed gas volume, and the total gas content:

[0045] (4);

[0046] Q t It is the total degassed gas content in the tank plus the lost gas content, m 3 / t; D is the diffusion coefficient, m 2 / s;r p Q is the diffusion length, m; n is the upper limit of the series summation; l_ACF For calculating the loss gas content using the ACF method, m 3 / t.

[0047] In step (7) above: the MCF method is based on a bidispersive pore structure model, which divides the pore system of coal / shale into two types of pores: macropores and micropores; the MCF method is similar to the ACF method, which fits and inverts all field degassing data; the MCF method describes the relationship between lost gas volume, cumulative desorbed gas volume and total gas content.

[0048] (5);

[0049] Where D a and D i These are the diffusion coefficients for macropores and micropores, respectively, m. 2 / s;r a and r i These are the diffusion lengths of macropores and micropores, respectively, in meters. 2 / s; α and β are dimensionless parameters.

[0050] In step (8) above: the isotope fractionation method is based on 12 CH4 and 13 The differential behavior of CH4 during adsorption / desorption and diffusion processes; an isotopic fractionation model under a dual-medium porous structure was established, simultaneously fitting the cumulative desorbed gas volume and the δ-value of the produced gas. 13 The C1 value allows for the simultaneous determination of in-situ gas content and the ratio of adsorbed gas to free gas; the specific process is as follows:

[0051] (A) Establish 12 CH4 and 13 The partial differential equations for the mass transfer process of CH4 in a dual-pore structure are as follows:

[0052] (6);

[0053] In the formula, To determine the sign of the partial derivative; and They are respectively 12 CH4 and 13 The apparent diffusion coefficient of CH4 in the matrix pores; B1, B2, C1 and C2 are respectively expressed as

[0054] (7);

[0055] In the formula P m and P m * They are respectively 12 CH4 and 13 Gas pressure of CH4 in the matrix pores; P f and P f * They are respectively12 CH4 and 13 Gas pressure of CH4 in cleavage / fracture; D m_app ϕ is the apparent diffusion coefficient of the matrix pores; N is the number of cleavage / fracture groups; l is the cleavage / fracture spacing; f For cleavage / crack porosity; k f Permeability of cleavage / fracture; μ f ϕ is the gas viscosity in the cleavage / fracture; K is the Langmuir constant; m_eff ρ is the effective matrix porosity; c is the mass balance constant. rock Density of rock; V L Z represents the volume of Langmuir; m is the gas compressibility factor in the matrix pores; R is the universal gas constant, 8.3145 J / mol / K; T is the core temperature; V std V is the volume of 1 mol of gas under standard conditions. std =22.4 L / mol; K and K * They are respectively 12 CH4 and 13 Langmuir constant of CH4; with superscript * The for 13 The physical quantity of CH4, without superscript. * The for 12 Physical quantities of CH4;

[0056] (B) Considering the adsorption thermodynamics and heat conduction within the core; in deep coal and shale, heat is mainly transferred through heat conduction, described by the heat conduction equation:

[0057] (8);

[0058] In the formula λ rock The thermal conductivity of the rock is W·m. -1 ·K -1 ; Density of rock, kg / m³ 3 ;c rock Specific heat capacity of rock, J·m -3 ·K -1 ;

[0059] Langmuir pressure P L It exhibits a clear temperature dependence, which is jointly controlled by the adsorption enthalpy change ΔH and the entropy change ΔS:

[0060] (9);

[0061] Where P 0 It is the standard pressure, P 0=0.1MPa; ΔS 0 ΔH is the standard molar integral entropy at saturation, defined as when the surface coverage is nearly complete, in J / mol / K; ΔH is the differential enthalpy of adsorption, in kJ / mol. The universal gas constant is 8.3145 J / mol / K;

[0062] (C) Considering the influence of the adsorption layer and the real gas effect; in equation (6), the influence of the adsorption layer on the average pore size and porosity of the matrix pores and the real gas effect are considered. The influence of the adsorption layer on the average pore size and porosity of the matrix pores can be expressed as:

[0063] (10);

[0064] (11);

[0065] In the formula r eff r0 is the average pore size of the matrix pores affected by the adsorption layer; r0 is the initial average pore size of the matrix pores not affected by the adsorption layer; d m Let ϕ be the diameter of a methane molecule, taken as 0.38 nm; m0 The initial porosity of the matrix pores before they are affected by the adsorption layer; and They are respectively 12 CH4 and 13 CH4 adsorption gas surface coverage;

[0066] The gas compressibility factor affected by temperature and pressure can be expressed as:

[0067] (12);

[0068] Z m and Z f These are the gas compressibility factors in the matrix porosity and cleavage / fracture systems, respectively; a T ~g T It is a temperature-dependent function, and its explicit expression is as follows:

[0069] (13);

[0070] The density of a gas affected by temperature and pressure can be expressed as:

[0071] (14);

[0072] Where ρ m It is the gas density within the matrix pores, kg / m³ 3 ;ρ f It is the gas density within the cleavage / fracture, kg / m³ 3M is the molar mass of methane, g / mol; the gas viscosity affected by temperature and pressure can be expressed as:

[0073] (15);

[0074] Where μ m It is the gas viscosity within the matrix pores, Pa·s; μ f is the gas viscosity within the cleavage / fracture, Pa·s; M is the molar mass of methane, g / mol; , and These are the temperature-related functions in the viscosity calculation formula;

[0075] (D) Considering multi-gas transport mechanisms, Equation (6) incorporates a multi-gas transport mechanism involving the coupling of viscous flow, Knudsen diffusion, and surface diffusion:

[0076] (16);

[0077] In the formula, kv is the inherent permeability of the rock within the matrix pores, m 2 Kn is the Knudsen number; D s The function of coverage can be expressed as:

[0078] (17);

[0079] In the formula D s0 θ is the surface diffusion coefficient when the gas coverage is 0; θ is the adsorbed gas coverage; κ is the blocking rate constant, κ=0.5;

[0080] (E) Set initial and boundary conditions; the initial conditions for the core are:

[0081] (18);

[0082] In the formula P o The initial reservoir pressure is Pa; n * (t0) / n(t0) is 13 CH4 and 12 Initial molar ratio of CH4; initial methane carbon isotope value of δ0; R st The methane carbon isotope value is the standard sample; T0 is the initial reservoir temperature, in °C.

[0083] The boundary conditions for the core sample are:

[0084] (19);

[0085] In the formula and These represent the x and y directions in the Cartesian coordinate system, respectively; rtube Pipeline radius, m; r, core radius, m; h, core height, m; P b (t) represents the pressure as a function of time, in Pa; T b (t) represents the pressure as a function of time, in °C;

[0086] (F) Solve the equations to calculate the cumulative desorbed gas volume and methane carbon isotope value; substitute the established equations and the parameters in formulas (6) to (17) into mathematical calculation software such as MATLAB or COMSOL to solve the dependent variable of the equation system with time and space, that is, to obtain the pressure field distribution inside the core; perform volume integration on the pressure field obtained by the solution to calculate the free state in the matrix pores at any time. 12 CH4, free state 13 CH4, adsorbed state 12 CH4, adsorbed state 13 CH4 and cleavage / fractures 12 CH4 and 13 The cumulative desorption gas volume of CH4; the specific formula for the volume integral method is:

[0087] (20);

[0088] In the formula, For volume differential, The volume of 1 mol of gas under standard conditions is 22.4 L / mol. For core mass; Q m_free (t i ) and Q * m_free (t i ) represent the free state in the matrix pores 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q m_ads (t i ) and Q * m_ads (t i ) represent the adsorbed states in the matrix pores 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q f (t i ) and Q * f (t i ) are respectively in cleavage / fracture 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q g_cal (t i () represents the cumulative gas volume calculated from the core sample;

[0089] The carbon isotope values ​​of gaseous methane from core analysis can be calculated as follows:

[0090] (twenty one);

[0091] In the formula The carbon isotope ratio of methane in the standard substance is 0.0112372;

[0092] (H) History Fitting and Gas Content Evaluation: The cumulative analytical gas volume Q calculated by the isotope model is used as the basis for the evaluation. g_cal (t i ) and methane carbon isotope value δ 13 C 1_cal (t i The cumulative desorption gas volume Q measured in the on-site desorption experiment in step (3) is... g_mea (t) and methane carbon isotope value δ 13 C 1_mea (t i By performing historical fitting, the undetermined parameters of the model are determined, and the key undetermined parameters in the model are obtained; by substituting these parameters into the model and integrating the pressure field at the initial time, the in-situ gas content can be obtained.

[0093] (twenty two);

[0094] GIP in the formula CIF This refers to the in-situ gas content calculated using the isotope method; in addition to the in-situ gas content, the isotope fractionation model can also calculate the proportions of free gas and adsorbed gas in the in-situ gas content.

[0095] (twenty three);

[0096] FGR and AGR are the proportions of in-situ free gas and adsorbed gas calculated by the isotope method, respectively.

[0097] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0098] 1. This application obtains high-quality cumulative gas content data and produced gas isotope data based on field analysis experimental data. Then, it combines multiple methods, including USBM, polynomial, ACF, MCF, and isotope fractionation, to comprehensively evaluate the in-situ gas content and adsorbed / free gas ratio in deep shale / coal formations. Finally, through cross-validation and comparative analysis of multi-method results, the in-situ gas content and adsorbed / free gas ratio are comprehensively determined, achieving accurate quantitative characterization of the in-situ gas content and gas occurrence state of deep unconventional reservoirs. This provides a scientific and reliable technical means for the evaluation of deep unconventional reservoirs and provides a scientific basis for reserve assessment, selection of favorable targets, and optimization of development schemes.

[0099] 2. This application, based on field analysis experimental data and combining multiple methods in synergistic application, presents a comprehensive evaluation method for in-situ gas content and adsorbed / free gas ratio in deep shale / coal formations. It is the first to systematically integrate traditional analytical methods with isotope geochemical methods, constructing a multi-method synergistic verification technical system that overcomes the limitations of single methods. This method establishes a novel quantitative identification method for adsorbed / free gas based on the isotope fractionation mechanism, solving the technical challenge of distinguishing gas occurrence states using traditional methods. It achieves accurate quantitative characterization of in-situ gas content and gas occurrence states in deep unconventional reservoirs, providing a scientific basis for reserve assessment, favorable target selection, and development scheme optimization. This method is applicable to both deep shale gas and deep coal gas, possessing significant scientific value and broad application prospects. Attached Figure Description

[0100] Figure 1 This is a diagram of the on-site water analysis experimental apparatus of the present invention;

[0101] Figure 2 This is a linear fitting plot of the cumulative analytical gas volume of in-situ gas content evaluated by the USBM method;

[0102] Figure 3 This is a linear fitting plot of the cumulative analytical gas volume in in-situ evaluated using the polynomial method.

[0103] Figure 4 This is a linear fitting plot of the cumulative analytical gas volume of in-situ gas content evaluated by the ACF method;

[0104] Figure 5 This is a linear fitting plot of the cumulative analytical gas volume of in-situ gas content evaluated by the MCF method;

[0105] Figure 6 This is the boundary condition diagram of the rock core;

[0106] Figure 7 This is a linear fitting plot of the cumulative analytical gas volume in in-situ for evaluating gas content using the isotope fractionation method (CIF method).

[0107] Figure 8 This is a graph showing the results of in-situ gas content comparison analysis and the gas ratio calculation results using the isotope method. Detailed Implementation

[0108] The technical solution of the present invention will now be clearly and completely described with reference to the accompanying drawings and embodiments. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0109] Example: A quantitative evaluation method for in-situ gas content and occurrence state in shale / coal based on multi-method coupling is implemented according to the following steps:

[0110] This embodiment selects deep shale samples (numbered #1 and #2) from the Lower Silurian Longmaxi Formation in the Luzhou area of ​​the Sichuan Basin and deep coal samples (numbered #3 and #4) from the Shanxi Formation on the eastern edge of the Ordos Basin for testing. The shale sample well area is located in the gentle tectonic zone of southern Sichuan Basin, with sample burial depths of 3771.96 m and 3776.26 m. The lithology is organic-rich black shale with high silica content and well-developed bedding. The coal sample well area is located in the western Shanxi flexural belt, with sample burial depths of 1822.15 m and 1885.39 m. The coal seam thickness is approximately 4–12 m, and the coal body structure is mainly bright coal.

[0111] Step 1: Establish the on-site analytical experimental setup. The on-site analytical experimental setup consists of the following parts (as per the instruction manual). Figure 1 As shown):

[0112] (1) Analysis vessel: The analysis vessel is a pressure-resistant and airtight container made of stainless steel or aluminum alloy, with a volume of 5 to 20 L and a design pressure range to meet the experimental requirements of 0.5 to 2.0 MPa. The top of the analysis vessel is equipped with a pressure sensor interface, a temperature sensor interface and a gas outlet. The vessel cover and the vessel body adopt a high-strength sealing structure to ensure airtightness during the experiment.

[0113] (2) Constant temperature water bath heating system: including constant temperature water bath and temperature control unit. The analytical tank is placed in the constant temperature water bath, and the analytical tank is uniformly heated and kept warm through water bath circulation. The temperature control system can simulate the formation temperature or set the standard experimental temperature (usually controlled within the range of 20 to 80℃). The temperature control accuracy needs to reach ±1℃ to ensure that the analytical experiment is carried out under constant temperature conditions and to eliminate the influence of ambient temperature fluctuations on the analytical results.

[0114] (2) Gas metering system:

[0115] It mainly includes wet gas flow meters or high-precision mass flow meters, with a measurement accuracy of not less than ±1%. The inlet of the flow meter is connected to the gas outlet of the desorption tank via a pipeline for real-time monitoring and recording of the volume or mass of the produced gas. For long-term continuous desorption experiments, the device is equipped with an automatic data acquisition system that can automatically record the cumulative gas production at set time intervals (such as 1 minute, 5 minutes, or 10 minutes), avoiding errors from manual readings.

[0116] (3) Gas sampling system: Located at the rear end of the gas metering system. A gas sampling interface is installed at the outlet of the wet gas flow meter or high-precision mass flow meter, and connected to the gas collection tank via pipeline. The desorbed gas sample is collected using the drainage gas collection method. The sampling container is selected according to the experimental requirements, using an aluminum gas collection bag or a glass saline bottle for subsequent gas component and isotope analysis.

[0117] (4) Data recording system: integrates pressure sensor, temperature sensor and multi-channel data acquisition unit. The pressure sensor is installed at the top interface of the desorption tank to monitor the pressure change inside the tank in real time; the temperature sensor probe extends into the tank or is close to the tank wall to monitor the desorption temperature; the data acquisition unit is connected to each sensor and records the time, tank pressure, temperature and cumulative flow data synchronously at a set frequency to realize digital monitoring of the experimental process.

[0118] (5) Auxiliary equipment: including vacuum pump (used to remove air from the tank before analysis), nitrogen cylinder (used to check the air tightness of the analysis tank before the end of analysis), balance (accuracy 0.01g, used to weigh the core mass), vernier caliper (used to measure the core size), etc.

[0119] Step Two: Implement the on-site analytical experiment procedure. The standardized operating procedure for the on-site analytical experiment is as follows:

[0120] (1) Core preparation: After the core is raised to the ground, it should be removed from the core cylinder as soon as possible. For pressure-holding core sampling, record the initial pressure and temperature inside the core cylinder; for conventional core sampling, record the core removal time (t). coring Time taken to hoist from the bottom of the well to the wellhead and time exposed to the surface (t) exposure (Time from core exiting the core tube to loading into the analysis vessel). The radius and height of the core were measured using vernier calipers, and the core mass was weighed using a balance. Intact core segments without obvious cracks were selected as analysis samples. The recorded data are shown in Table 1.

[0121] (2) Assembly of the analysis system: Connect the gas metering system, sampling system, and data recording system. Use a vacuum pump to evacuate the analysis vessel (vacuum degree ≤100Pa) to remove air from the vessel and avoid interference from nitrogen and oxygen in the air on subsequent gas composition testing. After completion, place the core into the analysis vessel and seal the lid. Turn on the water bath heating system to heat the analysis vessel. Considering the temperature sensitivity of deep shale, the experiment adopts a stepped heating mode: first heat to the first stage temperature (58℃), and after the gas production rate stabilizes, heat to the original reservoir temperature (91℃) to continue analysis. For deep coal and rock samples, the constant temperature water bath temperature is usually set to 60℃ (simulating reservoir temperature).

[0122] Table 1

[0123]

[0124] (3) Desorption Experiment: Open the gas discharge valve of the desorption tank to start the desorption experiment. Record the desorption start time (t0, unit: hour). The data acquisition device automatically records the time (t, unit: hour), tank pressure (P, unit: kPa), tank temperature (T, unit: ℃), and cumulative desorption gas volume (Q, unit: mL or m³) at the set frequency. 3 Gas samples were collected and analyzed for methane carbon isotopes (δ¹²). 13 C1) test. The results are shown in Table 5. During the analysis process, the analysis temperature was kept relatively stable, with temperature fluctuations not exceeding ±2℃. Experimental records show that after the temperature was stepped up to 91℃, the cumulative analysis gas volume increased significantly, and the isotope values ​​exhibited a special non-isothermal fractionation characteristic of "rapidly becoming heavier - briefly becoming lighter - continuously becoming heavier". The recorded data are shown in Table 2.

[0125] Table 2

[0126]

[0127] (4) Gas Sampling: According to the predetermined sampling schedule, close the main gas path valve and open the sampling valve at the corresponding time to collect the produced gas using a sampling bottle. The recommended sampling volume is 100-200 mL. After sampling, close the sampling valve, open the main gas path valve, and continue the analysis experiment. After sampling, label each glass saline bottle with the sample number, sampling time, corresponding cumulative analysis gas volume, and analysis tank pressure. See Appendix Table 2.

[0128] (5) Termination of analysis: When the gas production per unit time is less than 1% of the initial gas production rate, or the cumulative gas production over 24 hours is less than 0.5% of the total gas production, the analysis can be considered basically completed. Record the analysis termination time (t). end ) and final cumulative desorbed gas volume (Q total The results are shown in Table 3.

[0129] Table 3

[0130]

[0131] (6) Residual Gas Measurement: After the desorption experiment, the core was removed from the desorption vessel and immediately placed into a dedicated grinding jar. The core was crushed to a particle size <0.25 mm using methods such as ball milling and crushing. The amount of gas released during the crushing process was measured under sealed conditions; this amount is the residual gas volume (Q). residual The results are shown in Table 4.

[0132] Table 4

[0133]

[0134] (7) Isotope testing: The collected gas samples were sent to the laboratory, and the carbon isotope composition (δ¹²) of methane was determined using gas chromatography-isotope ratio mass spectrometry (GC-IRMS). 13 C1), compared to the PDB standard, has a test accuracy of ±0.2‰. The test results are shown in Table 5.

[0135] Table 5

[0136]

[0137] Step 3: Data Processing and Parameter Summarization. The raw data obtained from the field analysis experiment are organized to generate the following dataset:

[0138] (1) Cumulative analytical gas volume data: processing time (t, hour) and corresponding cumulative analytical gas volume (Q) g_mea (t),m 3 ( / t or mL / g) data pairs. The cumulative gas volume is converted to gas volume per unit mass of core, in m³. 3 / t (standard conditions). Data is shown in Table 2.

[0139] (2) Isotope data: Sampling time (t) i ) and the corresponding methane carbon isotope value (δ 13 C 1_mea (t i (),‰) data pairs. Data is shown in Table 5.

[0140] (3) Basic parameters; summarizing core radius r, core length H, core mass m, and core apparent density ρ rock , Parsing start time t0, Parsing end time t end Total analytical gas volume Q total Residual gas volume Q residual Initial reservoir pressure P o Reservoir temperature T, drilling fluid density ρ mud Parameters. The results are shown in Table 6.

[0141] Table 6

[0142]

[0143] Step 4: Evaluate in-situ gas content using the USBM method. The USBM (US Bureau of Mines) method is based on the theory of gas diffusion in rocks, assuming that in the initial stage of analysis, the cumulative gas content Q(t) is proportional to the square root of time (t). 0.5 A linear relationship exists:

[0144] 1)

[0145] Q d(t) represents the cumulative degassing content in the analyzer at time t, m 3 / t;Q l_USBM For calculating the loss gas content using the USBM method, m 3 / t;K l It is the slope of the regression line; t l Known as "gas loss time", it is defined as follows:

[0146] 2)

[0147] Where t coring It is the time it takes for the core sample to be lifted from the bottom of the well to the surface; t exposure This refers to the exposure time of the core sample in the atmosphere before it is loaded into the degassing tank.

[0148] The square root of time ((t+t) l ) 0.5 (Q) is the cumulative degassing content, represented by the x-axis. d (t) is plotted as the ordinate. Measured data of the linear segment are selected, and the data of this segment is linearly fitted using equation (1), as follows: Figure 2 As shown, the slope K of the regression line is obtained. l and the content of lost gas Q l_USBM In-situ gas content GIP calculated by the USBM method USBM =Q l_USBM +Q total +Q residual The results are shown in Table 8.

[0149] Step 5: Evaluate in-situ gas content using the polynomial method. The polynomial method is used to describe the nonlinear characteristics of gas desorption curves. A quadratic polynomial is used to express the relationship between the cumulative desorbed gas volume and the square root of time:

[0150] 3)

[0151] Where a l b is the coefficient of the quadratic term in the polynomial method; l Q is the coefficient of the linear term in the polynomial method; l_Poly For the polynomial method to calculate the loss gas content, m 3 / t.

[0152] The square root of time ((t+t) l ) 0.5 (Q) is the cumulative degassing content, represented by the x-axis. d (t) is plotted as the ordinate. Measured data of the quadratic function curve segment are selected, and linear fitting of this segment is performed using equation (3). Figure 3 As shown, the coefficient a of the quadratic term is obtained. l coefficient b of the linear term land the content of lost gas Q l_Poly In-situ gas content (GIP) calculated using the polynomial method Poly =Q l_Poly +Q total +Q residual (Q) total Q represents the total analytical gas volume. residual (This refers to the residual gas volume). The results are shown in Table 8.

[0153] Step Six: Evaluate in-situ gas content using the ACF method. The ACF (Amoco Curve Fit) method is based on a gas diffusion model with a single pore structure, assuming that the gas undergoes Fick diffusion in a homogeneous porous medium. Unlike the USBM method and the polynomial method, the ACF method fits and inverts all in-situ degassing data. The ACF method describes the relationship between lost gas volume, cumulative desorbed gas volume, and total gas content:

[0154] 4)

[0155] Q t It is the total degassed gas content in the tank plus the lost gas content, m 3 / t; D is the diffusion coefficient, m 2 / s;r p Q is the diffusion length, m; n is the upper limit of the series summation; l_ACF For calculating the loss gas content using the ACF method, m 3 / t.

[0156] The parsing time (t+t) l (Q) is the cumulative degassing content, represented by the x-axis. d (t) is plotted as the ordinate, and a linear fit is performed on all cumulative analytical gas volume data using equation (4), as follows: Figure 4 As shown, the diffusion coefficient D and diffusion length r are obtained. p and the content of lost gas Q l_ACF In-situ gas content (GIP) calculated using the polynomial method ACF =Q l_ACF +Q total +Q residual The results are shown in Table 8.

[0157] Step 7: Evaluate in-situ gas content using the MCF method. The MCF (Modified Curve Fit) method is based on a bidispersive pore structure model, classifying the pore system of coal / shale into macropores and micropores. Similar to the ACF method, the MCF method fits and inverts all in-situ degassing data, such as... Figure 5 As shown. The MCF method describes the relationship between gas loss, cumulative desorption gas volume, and total gas content:

[0158] 5)

[0159] Where D a and D i These are the diffusion coefficients for macropores and micropores, respectively, m. 2 / s;r a and r i These are the diffusion lengths of macropores and micropores, respectively, in meters. 2 / s; α and β are dimensionless parameters.

[0160] The parsing time (t+t) l (Q) is the cumulative degassing content, represented by the x-axis. d Plotting (t) as the ordinate, and performing linear fitting on all cumulative analytical gas volume data using equation (5), as follows: Figure 5 As shown, the macroporous diffusion coefficient D is obtained. a , pore diffusion coefficient D i Macropore diffusion length r a , aperture diffusion length r a Dimensionless parameters α and β, and the amount of gas lost Q l_MCF In-situ gas content (GIP) calculated using the polynomial method MCF =Q l_MCF +Q total +Q residual The results are shown in Table 8.

[0161] Step 8: Evaluate in-situ gas content using the isotope fractionation method (CIF method). The isotope fractionation method is based on... 12 CH4 and 13 The differential behavior of CH4 during adsorption / desorption and diffusion processes was investigated. An isotopic fractionation model was established under a dual-medium porous structure to simultaneously fit the cumulative desorbed gas volume and the δ¹⁸O values ​​of the produced gas. 13 The C1 value allows for the simultaneous determination of in-situ gas content and the adsorbed gas / free gas ratio. The specific process is as follows:

[0162] (1) Establish 12 CH4 and 13 The partial differential equations for the mass transfer process of CH4 in a dual-pore structure are as follows:

[0163] 6)

[0164] In the formula, To determine the sign of the partial derivative; and They are respectively 12 CH4 and 13 The apparent diffusion coefficient of CH4 in the matrix pores; B1, B2, C1 and C2 are respectively expressed as

[0165] 7)

[0166] In the formula P m and P m * They are respectively 12 CH4 and 13 Gas pressure of CH4 in the matrix pores; P f and P f * They are respectively 12 CH4 and 13 Gas pressure of CH4 in cleavage / fracture; D m_app ϕ is the apparent diffusion coefficient of the matrix pores; N is the number of cleavage / fracture groups (usually 1, 2, or 3); l is the cleavage / fracture spacing; ϕ f For cleavage / crack porosity; k f Permeability of cleavage / fracture; μ f ϕ is the gas viscosity in the cleavage / fracture; K is the Langmuir constant; m_eff c is the effective matrix porosity; c is the mass balance constant (c=(ρ rock V L Z m RT) / V std ,ρ rock Density of rock; V L Z represents the volume of Langmuir; m is the gas compressibility factor in the matrix pores; R is the universal gas constant, 8.3145 J / mol / K; T is the core temperature; V std V is the volume of 1 mol of gas under standard conditions. std =22.4 L / mol); K and K * They are respectively 12 CH4 and 13 The Langmuir constant (K) of CH4 * / K=exp(A / T 2 -B / T), where A=95.17K 2 (B=0.125 K); with superscript * The for 13 The physical quantity of CH4, without superscript. * The for 12 The physical quantity of CH4.

[0167] (2) Consider the adsorption thermodynamics and heat conduction within the core. In deep coal and shale, heat is mainly transferred through heat conduction, which can be described by the heat conduction equation:

[0168] 8)

[0169] In the formula λrock The thermal conductivity of the rock is W·m. -1 ·K -1 ; Density of rock, kg / m³ 3 ;c rock Specific heat capacity of rock, J·m -3 ·K -1 .

[0170] Langmuir pressure P L (or its reciprocal Langmuir constant, V) L =1 / P L It exhibits a clear temperature dependence, which is jointly controlled by the adsorption enthalpy change ΔH and the entropy change ΔS:

[0171] 9)

[0172] Where P 0 It is the standard pressure, P 0 =0.1MPa; ΔS 0 ΔH is the standard molar integral entropy at saturation, defined as when the surface coverage is nearly complete, in J / mol / K; ΔH is the differential enthalpy of adsorption, in kJ / mol. The universal gas constant is 8.3145 J / mol / K.

[0173] (3) Considering the effects of the adsorption layer and the real gas effect. In equation (6), considering the effects of the adsorption layer on the average pore size and porosity of the matrix pores and the real gas effect (the viscosity, compressibility factor, and density of the gas are affected by temperature and pressure), the effect of the adsorption layer on the average pore size and porosity of the matrix pores can be expressed as:

[0174] 10)

[0175] 11)

[0176] In the formula r eff r0 is the average pore size of the matrix pores affected by the adsorption layer; r0 is the initial average pore size of the matrix pores not affected by the adsorption layer; d m Let ϕ be the diameter of a methane molecule, taken as 0.38 nm; m0 The initial porosity of the matrix pores before they are affected by the adsorption layer; and They are respectively 12 CH4 and 13 CH4 adsorption gas surface coverage.

[0177] The gas compressibility factor affected by temperature and pressure can be expressed as:

[0178] 12)

[0179] Z m and Z f These are the gas compressibility factors in the matrix porosity and cleavage / fracture systems, respectively; a T ~g T It is a temperature-dependent function, and its explicit expression is as follows:

[0180] 13)

[0181] The density of a gas affected by temperature and pressure can be expressed as:

[0182] 14)

[0183] Where ρ m It is the gas density within the matrix pores, kg / m³ 3 ;ρ f It is the gas density within the cleavage / fracture, kg / m³ 3 M is the molar mass of methane, in g / mol.

[0184] The viscosity of a gas affected by temperature and pressure can be expressed as:

[0185] 15)

[0186] Where μ m It is the gas viscosity within the matrix pores, Pa·s; μ f is the gas viscosity within the cleavage / fracture, Pa·s; M is the molar mass of methane, g / mol; , and These are the temperature-related functions in the viscosity calculation formula.

[0187] (4) Considering multi-gas transport mechanisms. Equation (6) considers a multi-gas transport mechanism involving the coupling of viscous flow, Knudsen diffusion, and surface diffusion:

[0188] 16)

[0189] In the formula, kv is the inherent permeability of the rock within the matrix pores, m 2 Kn is the Knudsen number; it can be expressed as (Kn = πZ). m ·R·T·μ m / (2M·P m ·r m ) 0.5 ); D s The function of coverage can be expressed as:

[0190] 17)

[0191] In the formula Ds0 θ is the surface diffusion coefficient when the gas coverage is 0; θ is the adsorbed gas coverage; κ is the blocking rate constant, κ=0.5.

[0192] (5) Set initial and boundary conditions. The initial conditions for the core are:

[0193] 18)

[0194] In the formula P o The initial reservoir pressure is Pa; n * (t0) / n(t0) is 13 CH4 and 12 Initial molar ratio of CH4; initial methane carbon isotope value of δ0; R st is the methane carbon isotope value of the standard sample; T0 is the initial reservoir temperature, ℃.

[0195] The boundary conditions of the core are (e.g.) Figure 6 (as shown)

[0196] 19)

[0197] In the formula and These represent the x and y directions in the Cartesian coordinate system, respectively; r tube Pipeline radius, m; r, core radius, m; h, core height, m; P b (t) represents the pressure as a function of time, in Pa; T b (t) represents the pressure as a function of time, in °C.

[0198] (6) Solve the equations to calculate the cumulative desorbed gas volume and methane carbon isotope value. Substitute the established equations and the expressions for the parameters therein (Equations (6) to (17)) into mathematical calculation software such as MATLAB or COMSOL to solve for the dependent variable (P) of the equation system. m P m * P f and P f * The pressure field distribution inside the core is obtained by varying the pressure field over time and space. By integrating the volume of the obtained pressure field, the free state in the matrix pores at any given time can be calculated. 12 CH4, free state 13 CH4, adsorbed state 12 CH4, adsorbed state 13 CH4 and cleavage / fractures 12 CH4 and 13 The cumulative desorbed gas volume of CH4; optionally, the specific formula for the volume integration method is:

[0199] 20)

[0200] In the formula, For volume differential, The volume of 1 mol of gas under standard conditions is 22.4 L / mol. For core mass; Q m_free (t i ) and Q * m_free (t i ) represent the free state in the matrix pores 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q m_ads (t i ) and Q * m_ads (t i ) represent the adsorbed states in the matrix pores 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q f (t i ) and Q * f (t i ) are respectively in cleavage / fracture 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q g_cal (t i ) represents the cumulative gas volume calculated from the core sample.

[0201] The carbon isotope values ​​of gaseous methane from core analysis can be calculated as follows:

[0202] twenty one)

[0203] middle The carbon isotope ratio of methane in the standard substance is 0.0112372.

[0204] (6) Historical fitting and gas content evaluation. The cumulative desorbed gas volume Q calculated by the isotope model is used. g_cal (t i ) and methane carbon isotope value δ 13 C 1_cal (t i The cumulative desorption gas volume Q measured in the on-site desorption experiment in step three is compared with that in step three. g_mea (t) and methane carbon isotope value δ 13 C 1_mea (t i Historical data fitting was performed to determine the undetermined parameters of the model and obtain the key undetermined parameters in the model. (As shown in Table 7)

[0205] Table 7 Undetermined Parameters

[0206]

[0207] After determining the parameters in Table 7, we substitute these parameters into the model and calculate the in-situ gas content by integrating the pressure field at the initial moment: the results are shown in Table 8.

[0208] twenty two)

[0209] GIP in the formula CIF This represents the in-situ gas content calculated using the isotope method.

[0210] In addition to in-situ gas content, the isotope fractionation model can also calculate the proportion of free gas and adsorbed gas in the in-situ gas content (which cannot be evaluated by the four traditional gas content evaluation methods mentioned above):

[0211] twenty three)

[0212] FGR and AGR are the proportions of in-situ free gas and adsorbed gas calculated by the isotope method, respectively.

[0213] Step Nine: Comparative Analysis and Comprehensive Evaluation of Results from Multiple Methods. The evaluation results of the five methods are systematically compared, and the cumulative analytical gas volume is historically fitted and comprehensively analyzed. The results are as follows: Figure 7 As shown. The five methods are USBM method (step four), polynomial method (step five), ACF method (step six), MCF method (step seven), and the isotope fractionation method proposed in this invention (CIF method, step eight). The in-situ gas content comparison analysis is presented in a bar chart (results are shown in...). Figure 8 a) shows the gas ratio results calculated by the isotope method (the results are as follows). Figure 8 (b) A direct comparison of the differences in in-situ gas content evaluated by various methods. The calculation results of each method are compared with the true values ​​measured by pressure holding core (PHC), and the results are shown in Table 8. Pressure holding core data are then added to verify the accuracy of various methods. Only the isotope method can directly evaluate the adsorbed gas / free gas ratio; therefore, the final evaluation result of the adsorbed gas / free gas ratio is based on the isotope method.

[0214] Table 8

[0215]

[0216] GIP in the formula PHC In-situ gas content obtained by pressure-holding coring; GIP CIF GIP USBM GIP Poly GIP ACF and GIP MCFThe values ​​are the in-situ gas content calculated by the isotope method, USBM method, polynomial method, ACF method, and MCF method, respectively. STP represents the standard state at 0℃ and 101kPa. AGR represents the adsorbed gas ratio calculated by the isotope method.

[0217] This embodiment verifies the applicability of the method of the present invention in deep shale and coal formations, with a calculation error of less than 5%. Simultaneously, the present invention successfully reveals the essential differences in gas occurrence mechanisms between deep coal formations (dominated by adsorbed gas) and deep shale formations (dominated by free gas), providing a scientific basis for the formulation of subsequent differentiated development schemes.

Claims

1. A quantitative evaluation method for in-situ gas content and occurrence state in shale / coal based on multi-method coupling, comprising the following steps: (1) Establishing an on-site analytical experimental device: The device includes an analytical tank, the lower part of which is located in a constant temperature water bath heating system. The upper end cover of the analytical tank is connected to the gas metering system, the data recording system and auxiliary equipment respectively. The gas metering system is connected to the gas sampling system. (2) Implementation of field analysis experiment procedure: The standardized operation procedure for field analysis experiment is as follows: a. Core preparation; b. Analysis system assembly; c. Analysis experiment; d. Gas sampling; e. Analysis termination; f. Residual gas measurement; h. Isotope testing; (3) Data processing and parameter summarization: a. Cumulative analytical gas volume data; b. Isotope data; c. Basic parameters; (4) Evaluate in-situ gas content using the USBM method; (5) Apply the polynomial method to evaluate in-situ gas content; (6) Evaluate in-situ gas content using the ACF method; (7) Evaluate in-situ gas content using the MCF method; (8) Evaluate in-situ gas content using isotope fractionation; (9) Comparative analysis and comprehensive evaluation of results from multiple methods: The evaluation results of the above five methods are systematically compared and comprehensively analyzed. The differences in in-situ gas content evaluated by various methods are directly compared. Only the isotope method can directly evaluate the ratio of adsorbed gas to free gas. Therefore, the final evaluation result of the ratio of adsorbed gas to free gas is based on the isotope method. In step (8) above: Isotope fractionation method based on 12 CH4 and 13 Differential behavior of CH4 during adsorption / desorption and diffusion processes; By establishing an isotopic fractionation model under a dual-medium porous structure, the cumulative desorbed gas volume and the δ-value of the produced gas are simultaneously fitted. 13 The C1 value allows for the simultaneous determination of in-situ gas content and the ratio of adsorbed gas to free gas; the specific process is as follows: (A) Establish 12 CH4 and 13 The partial differential equations for the mass transfer process of CH4 in a dual-pore structure are as follows: (6)； In the formula, To determine the sign of the partial derivative; and They are respectively 12 CH4 and 13 The apparent diffusion coefficient of CH4 in the matrix pores; B1, B2, C1 and C2 are respectively expressed as (7)； In the formula P m and P m * They are respectively 12 CH4 and 13 Gas pressure of CH4 in the matrix pores; P f and P f * They are respectively 12 CH4 and 13 Gas pressure of CH4 in cleavage / fracture; D m_app ϕ is the apparent diffusion coefficient of the matrix pores; N is the number of cleavage / fracture groups; l is the cleavage / fracture spacing; f For cleavage / crack porosity; k f Permeability of cleavage / fracture; μ f ϕ is the gas viscosity in the cleavage / fracture; K is the Langmuir constant; m_eff ρ is the effective matrix porosity; c is the mass balance constant. rock Density of rock; V L Z represents the volume of Langmuir; m is the gas compressibility factor in the matrix pores; R is the universal gas constant, 8.3145 J / mol / K; T is the core temperature; V std V is the volume of 1 mol of gas under standard conditions. std =22.4 L / mol; K and K * They are respectively 12 CH4 and 13 Langmuir constant of CH4; with superscript * The for 13 The physical quantity of CH4, without superscript. * The for 12 Physical quantities of CH4; (B) Considering the adsorption thermodynamics and heat conduction within the core; in deep coal and shale, heat is mainly transferred through heat conduction, described by the heat conduction equation: (8)； In the formula λ rock The thermal conductivity of the rock is W·m. -1 ·K -1 ; Density of rock, kg / m³ 3 c rock Specific heat capacity of rock, J·m -3 ·K -1 ; Langmuir pressure P L It exhibits a clear temperature dependence, which is jointly controlled by the adsorption enthalpy change ΔH and the entropy change ΔS: (9)； Where P 0 It is the standard pressure, P 0 =0.1MPa; ΔS 0 ΔH is the standard molar integral entropy at saturation, defined as when the surface coverage is nearly complete, in J / mol / K; ΔH is the differential enthalpy of adsorption, in kJ / mol. The universal gas constant is 8.3145 J / mol / K; (C) Considering the influence of the adsorption layer and the real gas effect; in equation (6), the influence of the adsorption layer on the average pore size and porosity of the matrix pores and the real gas effect are considered. The influence of the adsorption layer on the average pore size and porosity of the matrix pores can be expressed as: (10)； (11)； In the formula r eff r0 is the average pore size of the matrix pores affected by the adsorption layer; r0 is the initial average pore size of the matrix pores not affected by the adsorption layer; d m Let ϕ be the diameter of a methane molecule, taken as 0.38 nm; m0 The initial porosity of the matrix pores before they are affected by the adsorption layer; and They are respectively 12 CH4 and 13 CH4 adsorption gas surface coverage; The gas compressibility factor affected by temperature and pressure can be expressed as: (12)； Z m and Z f These are the gas compressibility factors in the matrix porosity and cleavage / fracture systems, respectively; a T ~g T It is a temperature-dependent function, and its explicit expression is as follows: (13)； The density of a gas affected by temperature and pressure can be expressed as: (14)； Where ρ m It is the gas density within the matrix pores, kg / m³ 3 ; ρ f It is the gas density within the cleavage / fracture, kg / m³ 3 M is the molar mass of methane, g / mol; the gas viscosity affected by temperature and pressure can be expressed as: (15)； Where μ m It is the gas viscosity within the matrix pores, Pa·s; μ f is the gas viscosity within the cleavage / fracture, Pa·s; M is the molar mass of methane, g / mol; , and These are the temperature-related functions in the viscosity calculation formula; (D) Considering multi-gas transport mechanisms, Equation (6) incorporates a multi-gas transport mechanism involving the coupling of viscous flow, Knudsen diffusion, and surface diffusion: (16)； In the formula, kv is the inherent permeability of the rock within the matrix pores, m 2 Kn is the Knudsen number; D s As a function of coverage, it can be expressed as: (17)； In the formula D s0 θ is the surface diffusion coefficient when the gas coverage is 0; θ is the adsorbed gas coverage; κ is the blocking rate constant, κ=0.5; (E) Set initial and boundary conditions; the initial conditions for the core are: (18)； In the formula P o The initial reservoir pressure is Pa; n * (t0) / n(t0) is 13 CH4 and 12 Initial molar ratio of CH4; initial methane carbon isotope value of δ0; R st The methane carbon isotope value is the standard sample; T0 is the initial reservoir temperature, in °C. The boundary conditions for the core sample are: (19)； In the formula and These represent the x and y directions in the Cartesian coordinate system, respectively; r tube Pipeline radius, m; r, core radius, m; h, core height, m; P b (t) represents the pressure as a function of time, in Pa; T b (t) represents the pressure as a function of time, in °C; (F) Solve the equations to calculate the cumulative desorbed gas volume and methane carbon isotope value; substitute the established equations and the parameters in formulas (6) to (17) into mathematical calculation software such as MATLAB or COMSOL to solve the dependent variable of the equation system with time and space, that is, to obtain the pressure field distribution inside the core; perform volume integration on the pressure field obtained by the solution to calculate the free state in the matrix pores at any time. 12 CH4, free state 13 CH4, adsorbed state 12 CH4, adsorbed state 13 CH4 and cleavage / fractures 12 CH4 and 13 The cumulative desorption gas volume of CH4; the specific formula for the volume integral method is: (20)； In the formula, For volume differential, The volume of 1 mol of gas under standard conditions is 22.4 L / mol. For core mass; Q m_free (t i ) and Q * m_free (t i ) represent the free state in the matrix pores 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q m_ads (t i ) and Q * m_ads (t i ) represent the adsorbed states in the matrix pores 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q f (t i ) and Q * f (t i ) are respectively in cleavage / fracture 12 CH4 and 13 The cumulative desorption gas volume of CH4; Q g_cal (t i () represents the cumulative gas volume calculated from the core sample; The carbon isotope values ​​of gaseous methane from core analysis can be calculated as follows: (21)； In the formula The carbon isotope ratio of methane in the standard substance is 0.0112372; (H) History Fitting and Gas Content Evaluation: The cumulative analytical gas volume Q calculated by the isotope model is used as the basis for the evaluation. g_cal (t i ) and methane carbon isotope value δ 13 C 1_cal (t i The cumulative desorption gas volume Q measured in the on-site desorption experiment in step (3) is... g_mea (t) and methane carbon isotope value δ 13 C 1_mea (t i Perform historical fitting to determine the undetermined parameters of the model and obtain the key undetermined parameters in the model; By substituting these parameters into the model and integrating the pressure field at the initial moment, the in-situ gas content can be obtained. (22)； GIP in the formula CIF This refers to the in-situ gas content calculated using the isotope method; in addition to the in-situ gas content, the isotope fractionation model can also calculate the proportions of free gas and adsorbed gas in the in-situ gas content. (23)； FGR and AGR are the proportions of in-situ free gas and adsorbed gas calculated by the isotope method, respectively.

2. The quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling according to claim 1, characterized in that: In step (1): The upper cover of the analytical tank is equipped with a pressure sensor interface, a temperature sensor interface, a gas outlet, and an auxiliary equipment connection port; The constant temperature water bath heating system includes a constant temperature water bath chamber and a temperature control unit; the analytical tank is placed inside the constant temperature water bath chamber; The gas metering system includes a wet gas flow meter, and the inlet of the wet gas flow meter is connected to the gas outlet of the desorption tank via a pipeline. The gas sampling system is located at the rear end of the gas metering system. The gas sampling system includes a gas collection tank and a glass saline bottle. The outlet of the wet gas flow meter is located in the gas collection tank, and the inlet of the glass saline bottle is located in the gas collection tank. The data recording system includes a pressure sensor, a temperature sensor, and a data acquisition unit. The pressure sensor is installed at the top interface of the analysis tank, the temperature sensor probe extends into the analysis tank or is close to the inner wall of the analysis tank, and the data acquisition unit is electrically connected to the pressure sensor and the temperature sensor respectively. The auxiliary equipment includes a vacuum pump, a nitrogen cylinder, a balance, and vernier calipers; the vacuum pump and nitrogen cylinder are connected to the top interface of the analytical tank via pipelines.

3. The quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling according to claim 1, characterized in that: In step (2): Core preparation: After the core is lifted to the ground, it should be removed from the core cylinder as soon as possible; a complete core segment without obvious cracks should be selected as the analytical sample; The analytical system assembly includes: connecting a gas metering system, a gas sampling system, and a data recording system; using a vacuum pump to evacuate the analytical tank; after evacuation, placing the core sample into the analytical tank, sealing it, and then turning on the constant temperature water bath heating system to heat the analytical tank; The analytical experiment is as follows: Open the gas discharge valve of the analytical tank to start the analytical experiment; during the analytical process, keep the analytical temperature relatively stable, and the temperature fluctuation shall not exceed ±2℃; The gas sampling process involves collecting the produced gas using a glass saline bottle; after sampling, the analysis experiment continues. The analysis is considered to be basically completed when the gas production per unit time is less than 1% of the initial gas production rate, or the cumulative gas production over 24 hours is less than 0.5% of the total gas production. The residual gas determination: After the analysis experiment, the core was taken out of the analysis tank and immediately put into the grinding tank. The core was crushed to a particle size of <0.25mm by ball milling and crushing. The amount of gas released during the crushing process was measured under closed conditions. The isotope test involves sending the collected gas sample to the laboratory and using a gas chromatography-isotope ratio mass spectrometer to determine the carbon isotope composition of methane, with a test accuracy of ±0.2‰.

4. The quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling according to claim 1, characterized in that: In step (3): The cumulative analytical gas volume data includes the processing time (t, hour) and the corresponding cumulative analytical gas volume Q. g_mea (t),m 3 / t or mL / g data pairs; convert cumulative gas volume to gas volume per unit mass of core, in m³. 3 / t; The isotope data mentioned: Sampling time (t) i ) and the corresponding methane carbon isotope value (δ 13 C 1_mea (t i ),‰) data pairs; The basic parameters mentioned include: core radius r, core length H, core mass m, and core apparent density ρ. rock , Parsing start time t0, Parsing end time t end Total analytical gas volume Q total Residual gas volume Q residual Reservoir burial depth h Depth Pressure coefficient α p Initial reservoir pressure P o Reservoir temperature T, core removal time t coring Ground exposure time t exposure Drilling fluid density ρ mud parameter.

5. The quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling according to claim 1, characterized in that: In step (4): The USBM method is based on the theory of gas diffusion in rocks, which posits that in the initial stage of desorption, the cumulative desorption gas volume Q(t) is proportional to the square root of time (t). 0.5 A linear relationship exists: (1)； Q d (t) represents the cumulative degassing content in the analyzer at time t, m 3 / t;Q l_USBM For calculating the loss gas content using the USBM method, m 3 / t;K l It is the slope of the regression line; t l Known as "gas loss time", it is defined as follows: (2)； Where t coring It is the time it takes for the core sample to be lifted from the bottom of the well to the surface; t exposure This refers to the exposure time of the core sample in the atmosphere before it is loaded into the degassing tank.

6. The quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling according to claim 1, characterized in that: In step (5): The polynomial method described above is used to describe the nonlinear variation characteristics in the gas desorption curve; a quadratic polynomial is used to express the relationship between the cumulative desorption gas volume and the square root of time. (3)； Where a l b is the coefficient of the quadratic term in the polynomial method; l Q is the coefficient of the linear term in the polynomial method; l_Poly For the polynomial method to calculate the loss gas content, m 3 / t.

7. The quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling according to claim 1, characterized in that: In step (6): The ACF method is based on a gas diffusion model with a single pore structure, assuming that the gas undergoes Fick diffusion in a homogeneous porous medium. Unlike the USBM method and the polynomial method, the ACF method fits and inverts all field degassing data. The ACF method describes the relationship between lost gas volume, cumulative desorbed gas volume, and total gas content. (4)； Q t It is the total degassed gas content in the tank plus the lost gas content, m 3 / t; D is the diffusion coefficient, m 2 / s;r p Q is the diffusion length, m; n is the upper limit of the series summation; l_ACF For calculating the loss gas content using the ACF method, m 3 / t.

8. The quantitative evaluation method for in-situ gas content and occurrence state of shale / coal based on multi-method coupling according to claim 1, characterized in that: In step (7): The MCF method described above is based on a bidispersive pore structure model, which classifies the pore system of coal / shale into two pore types: macropores and micropores. Similar to the ACF method, the MCF method fits and inverts all in-situ degassing data, describing the relationship between gas loss, cumulative desorbed gas volume, and total gas content. (5)； D a and D i These are the diffusion coefficients for macropores and micropores, respectively, m. 2 / s;r a and r i These are the diffusion lengths of macropores and micropores, respectively, in meters. 2 / s; α and β are dimensionless parameters.

Images