Method and equipment for dynamically determining diffusion amount of natural gas in multiple storage cover combination

Abstract

The invention provides a method and equipment for dynamically determining the diffusion amount of natural gas in multiple reservoir cover combinations, and belongs to the field of petroleum and natural gas geological prospecting, and the method comprises the steps: dividing the geological evolution time from gas reservoir formation to current into a plurality of geological time periods; determining the natural gas diffusion amount in each geological time period; and adding the natural gas diffusion amounts in different geological time periods to obtain the accumulated natural gas diffusion amount of the gas reservoir. Wherein the lithologic stratums included in the gas reservoir overlying strata in different geological time periods are different, and weighted average calculation is carried out on the effective diffusion coefficient at each geological moment according to the thicknesses of the different lithologic stratums to obtain a comprehensive diffusion coefficient. By means of the method, the dynamic evolution process of the natural gas diffusion amount along with the geological time can be obtained, and the calculated diffusion amount error is small and conforms to the actual geological evolution process.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum and natural gas geological exploration, and in particular to a method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination, an electronic device and a computer-readable storage medium. Background Art

[0002] Diffusion is one of the important mechanisms of oil and gas migration. It plays a vital role in the migration, accumulation, accumulation, preservation and destruction of natural gas. For accumulated gas reservoirs, the diffusion capacity of caprock for natural gas is the most important factor affecting the later preservation and destruction of gas reservoirs. Studying the diffusion capacity of natural gas is of great significance for evaluating the preservation conditions of natural gas reservoirs and storage tanks.

[0003] At present, conventional natural gas diffusion evaluation generally adopts a single-layer model. The classic single-layer caprock model is often used to calculate the diffusion of gas reservoirs and quantitatively evaluate the dissipation process of gas reservoirs. For example, the mudstone and marl caprock in the Harlingen gas field in the Netherlands is 390 meters thick, and the methane loss of the gas reservoir is still relatively fast. It only takes 4.5Ma to diffuse half of the reserves. Deep gas reservoirs involve multiple reservoir-caprock combinations (that is, multiple sets of caprocks overlying the reservoir). A series model is usually used to describe the sealing effect of multiple caprocks. The single-layer caprock is connected in series and weighted averaged according to the thickness to obtain a comprehensive diffusion coefficient, so that the sealing effect of multiple sets of caprocks can be quantified.

[0004] However, the methods for evaluating natural gas diffusion in the prior art have the following disadvantages:

[0005] (1) The existing diffusion calculation model is static, that is, it can only calculate the diffusion of the gas reservoir from its formation to the present day based on the current gas reservoir burial depth, temperature, pressure, formation thickness, and formation diffusion coefficient as input parameters. It does not take into account the changes in various geological parameters caused by the burial depth and the deposition and compaction of the overlying formations after the formation of the gas reservoir. The calculated diffusion error is large and does not conform to the actual geological evolution process.

[0006] (2) Only the measured diffusion coefficient of the current strata can be used as the input parameter, without considering the change of the diffusion coefficient over geological time and the thickness of the overlying strata;

[0007] (3) The diffusion coefficient of natural gas in rocks currently measured in the laboratory is basically the diffusion coefficient at normal temperature and pressure, which is quite different from the actual diffusion coefficient under high temperature and high pressure conditions underground, and the calculated diffusion amount has a large error. Summary of the invention

[0008] In view of the technical problem that the existing technology cannot accurately calculate the diffusion amount of natural gas, the present invention provides a method for dynamically determining the diffusion amount of natural gas in multiple reservoir-cap combinations. This method can obtain natural gas diffusion data at different geological times and realize dynamic calculation of the diffusion amount of natural gas in multiple reservoir-cap combinations.

[0009] To achieve the above-mentioned purpose, the first aspect of the present invention provides a method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination, the method comprising the following steps: dividing the geological evolution time from the formation of the gas reservoir to the present into multiple geological time periods; determining the diffusion amount of natural gas in each geological time period based on the geological parameters corresponding to the overlying strata of the gas reservoir in each geological time period; adding the diffusion amounts of natural gas in different geological time periods to obtain the cumulative natural gas diffusion amount of the gas reservoir; wherein the geological time period refers to the time range between two adjacent geological moments; the overlying strata of the gas reservoir is composed of multiple different lithological strata, and the lithological strata contained in the overlying strata of the gas reservoir in different geological time periods are different, and the total thickness of the overlying strata of the gas reservoir is determined according to the thickness of the different lithological strata; the geological parameters include the burial depth of the gas reservoir, stratum thickness, temperature, pressure and diffusion coefficient.

[0010] In an exemplary embodiment of the present invention, determining the diffusion amount of natural gas in each geological time period may include: determining the diffusion amount per unit area of ​​the overlying strata of the gas reservoir in each geological time period; determining the area of ​​the gas reservoir in each geological time period; and determining the diffusion amount of natural gas in each geological time period based on the diffusion amount per unit area of ​​the overlying strata of the gas reservoir in each geological time period and the gas reservoir area.

[0011] In an exemplary embodiment of the present invention, determining the diffusion amount per unit area of ​​the overlying strata of the gas reservoir in each geological time period may include: determining the comprehensive diffusion coefficient of the overlying strata of the gas reservoir in each geological time period; and determining the diffusion amount per unit area of ​​the overlying strata of the gas reservoir in each geological time period based on the comprehensive diffusion coefficient and the total thickness of the overlying strata of the gas reservoir in each geological time period.

[0012] In an exemplary embodiment of the present invention, determining the comprehensive diffusion coefficient of the overlying strata of the gas reservoir in each geological time period may include: determining the effective diffusion coefficients of different lithological strata included in the overlying strata of the gas reservoir in each geological time period; calculating the weighted average of the effective diffusion coefficients at each geological moment according to the thicknesses of different lithological strata, to obtain the comprehensive diffusion coefficient of the overlying strata of the gas reservoir in each geological time period.

[0013] In an exemplary embodiment of the present invention, the calculation formula of the effective diffusion coefficient may be: ji =a×k i / (φ i ×μ i×1 / p i ), where D ji is the jth lithologic stratum overlying the gas reservoir at the i-th geological time t i The effective diffusion coefficient, m 2 / s; a is the correction coefficient of saturated water and dry sample, dimensionless; k i is the i-th geological moment t i Permeability of dry samples, 10 -3 μm 2 ; φ i is the i-th geological moment t i The porosity of the sample, %; μ i is the i-th geological moment t i Natural gas viscosity, Pa.s; p i is the i-th geological moment t i Gas reservoir pressure, MPa; i = 1, 2, 3...n, t 1 represents the current time, t n represents the time of gas reservoir formation, t i represents the i-th geological moment.

[0014] In an exemplary embodiment of the present invention, the correction coefficient may be determined based on natural gas diffusion coefficient test data of an actual sample and natural gas diffusion coefficient test data of a dry sample.

[0015] In an exemplary embodiment of the present invention, the calculation formula of the diffusion amount per unit area may be:

[0016]

[0017] c 1i =φ i ρ wi S gi ;

[0018] Among them, q i is the time from the i-th geological moment t i To the i+1th geological time t i+1 The diffusion amount per unit area, kg / m 2 ;D ei is the overlying stratum of the gas reservoir at the i-th geological time t i The comprehensive diffusion coefficient, 10 -10 m 2 / s;h ji is the jth lithologic stratum contained in the overlying strata of the gas reservoir at the i-th geological time t i Thickness, m; j = 1, 2, 3, ...; c 1i is the i-th geological moment t iGas concentration at the interface between the gas and the direct cap layer, kg / m 3 ; φ i is the i-th geological moment t i The porosity of the sample, %; ρ wi is the i-th geological moment t i Density of formation water, kg / m 3 ; S gi is the i-th geological moment t i Solubility of natural gas in formation water under actual temperature and pressure conditions, mol / kg.

[0019] In an exemplary embodiment of the present invention, the method may also include: obtaining a burial history map, a thermal history map and a pressure history map of the gas reservoir over the geological evolution time through basin simulation recovery; determining the burial depth of the overlying strata of the gas reservoir at different geological times and the thickness of different lithological strata contained in the overlying strata of the gas reservoir based on the burial history map; and determining the temperature and pressure of the overlying strata of the gas reservoir at different geological times based on the thermal history map and the pressure history map.

[0020] In an exemplary embodiment of the present invention, the geological evolution time from the formation of the gas reservoir to the present can be divided into a plurality of geological time periods according to different time intervals.

[0021] A second aspect of the present invention provides an electronic device, comprising a processor and a memory, wherein the memory stores at least one computer program, and the at least one computer program is loaded and executed by one or more of the above-mentioned processors to enable the processor to execute the above-mentioned method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination.

[0022] A third aspect of the present invention provides a computer-readable storage medium storing at least one program code, which is loaded and executed by a processor to enable a computer to execute the above-mentioned method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination.

[0023] Through the technical solution provided by the present invention, the present invention has at least the following technical effects:

[0024] (1) The method for determining the diffusion amount provided by the present invention obtains the diffusion amount data of gas reservoirs in multiple reservoir-cap combinations at different geological times since their formation based on the idea of ​​dynamic evolution, and can obtain the dynamic evolution process of natural gas diffusion amount over geological time;

[0025] (2) The present invention overcomes the drawback that the diffusion coefficient of the historical period is difficult to test, and the diffusion coefficient of different geological times is calculated using parameters such as porosity, permeability, gas viscosity and gas reservoir pressure;

[0026] (3) The present invention overcomes the defect that the existing diffusion calculation model only uses the measured diffusion coefficient of the current stratum as an input parameter, which leads to the neglect of the change of the diffusion coefficient with geological time and the thickness of the overlying stratum. It forms a new calculation method of the comprehensive diffusion coefficient, which can determine the comprehensive diffusion coefficient of the overlying reservoir and cap rock combination of the gas reservoir at different geological times;

[0027] (4) The present invention takes into account relevant geological parameters such as the burial depth of the gas reservoir, stratum thickness, temperature, pressure, diffusion coefficient, etc. at different geological times since the formation of the gas reservoir, and transforms the previous static calculation of diffusion into a dynamic calculation of diffusion. The calculation result of diffusion is closer to the actual geology and can be well combined with the basin simulation data.

[0028] (5) The present invention uses experimental test data to calibrate the current calculation results, ensuring the reliability of the input parameters of the diffusion calculation model.

[0029] Other features and advantages of the present invention will be described in detail in the following detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] The accompanying drawings are used to provide a further understanding of the embodiments of the present invention and constitute a part of the specification. Together with the following specific implementations, they are used to explain the embodiments of the present invention, but do not constitute a limitation on the embodiments of the present invention. In the accompanying drawings:

[0031] Figure 1 A flow chart of a method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination provided by an embodiment of the present invention;

[0032] Figure 2 A schematic diagram of the changes of gas reservoirs and overlying strata over geological time provided by an embodiment of the present invention;

[0033] Figure 3 A schematic diagram of the cumulative diffusion of natural gas over geological time provided by an embodiment of the present invention;

[0034] Figure 4 A schematic diagram of the structure of an electronic device provided by an embodiment of the present invention.

[0035] Description of Reference Numerals

[0036] 201 - processor, 202 - memory. DETAILED DESCRIPTION

[0037] The specific implementation of the embodiment of the present invention is described in detail below in conjunction with the accompanying drawings. It should be understood that the specific implementation described here is only used to illustrate and explain the embodiment of the present invention, and is not used to limit the embodiment of the present invention.

[0038] It should be noted that, in the absence of conflict, the embodiments of the present invention and the features in the embodiments may be combined with each other.

[0039] In the present invention, unless otherwise specified, the directional words used, such as "upper, lower, top, bottom", are usually used to describe the relative positional relationship of the components in terms of the directions shown in the drawings or in terms of the vertical, perpendicular or gravity directions. "First", "second", etc. are only used for the convenience of description and distinction, and cannot be understood as indicating or implying relative importance.

[0040] The natural gas diffusion calculation models in the prior art are all static calculation models, which can only use the current gas reservoir's burial depth, temperature, pressure, formation thickness, formation diffusion coefficient, etc. as model input parameters to calculate the cumulative diffusion of natural gas in the geological time from the formation of the gas reservoir to the present. However, in the actual geological evolution process, the geological time from the formation of the gas reservoir to the present often lasts for millions of years, and the burial depth of the gas reservoir and its overlying strata have changed many times during this period. This is bound to cause changes in various geological parameters caused by the burial depth and deposition and compaction of the overlying strata after the formation of the gas reservoir. Therefore, the diffusion data calculated by the existing diffusion calculation model has large errors and does not conform to the actual geological evolution process.

[0041] In order to solve the above technical problems, the present invention has formed a method for determining the diffusion amount of natural gas in multiple reservoir-cap combinations by using a dynamic diffusion calculation model. The overall technical concept of this method is: dividing the geological time from the formation of the gas reservoir to the present into multiple geological time periods, and dynamically calculating the diffusion data in different geological time periods by considering the changes in geological parameters such as the burial depth of the gas reservoir, stratum thickness, temperature, pressure, and diffusion coefficient in different geological time periods, thereby obtaining the dynamic evolution process of the diffusion amount with geological time.

[0042] The present invention will be described in detail below with reference to the accompanying drawings and in conjunction with embodiments.

[0043] Embodiment 1

[0044] Please refer to Figure 1 The first embodiment of the present invention provides a method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination, the method comprising the following steps:

[0045] Step S101: Divide the geological evolution time from the formation of the gas reservoir to the present into multiple geological time periods.

[0046] Step S102: Determine the natural gas diffusion amount G in each geological time period i .

[0047] Specifically, the diffusion amount of natural gas in each geological time period can be determined based on the geological parameters corresponding to the overlying strata of the gas reservoir in each geological time period. The overlying strata of the gas reservoir are composed of multiple lithological strata, and the lithological strata contained in the overlying strata of the gas reservoir in different geological time periods are different. The total thickness of the overlying strata of the gas reservoir is determined according to the thickness of the different lithological strata. The geological parameters include the burial depth of the gas reservoir, stratum thickness, temperature, pressure and diffusion coefficient.

[0048] Step S103: Add the natural gas diffusion amounts in different geological time periods to obtain the cumulative natural gas diffusion amount G of the gas reservoir. c .

[0049] Here, the geological time period refers to the time range between any two adjacent geological moments. For example, the geological evolution time from the formation of the gas reservoir to the present can be divided into n-1 time intervals using n geological moments, and each time interval corresponds to a geological time period. i represents a geological moment, then i = 1, 2, 3, ... n, t 1 represents the current time (now), t n represents the time of gas reservoir formation, [t i , t i+1 ] represents the time from geological time t i To geological time t i+1 The calculation formula for the cumulative natural gas diffusion in the gas reservoir is:

[0050] G c =G 1 +G 2 +G 3 ……+G i ……+G n-1 (1)

[0051] In the formula, G c is the cumulative natural gas diffusion volume of the gas reservoir, m 3 ; G 1 for [t 1 , t 2 ]Natural gas diffusion in geological time period, m 3 ; G 2 for [t 2 , t 3 ]Natural gas diffusion in geological time period, m 3 ; G 3 for [t 3 , t 4 ]Natural gas diffusion in geological time period, m 3 ; G i for [t i , t i+1]Natural gas diffusion in geological time period, m 3 ; G n-1 for [t n-1 , t n ]Natural gas diffusion in geological time period, m 3 .

[0052] It should be noted that n geological moments can be marked and divided at the same time interval on the geological evolution time from the formation of the gas reservoir to the present. At this time, the interval between any two geological moments is the same, and the time range between any two adjacent geological moments is also the same, that is, multiple geological time periods are equal. For example, if the main research purpose is to analyze the variation law of natural gas diffusion in multiple reservoir-cap combinations with geological time, the geological evolution time from the formation of the gas reservoir to the present can be divided into several geological time periods by using smaller time intervals (for example, 50,000 years, 100,000 years, etc.) under the premise of considering the computing power of the theoretical analysis model, so as to analyze and confirm the changes in geological parameters in each small geological time period, as well as the changes in natural gas diffusion caused by the changes in geological parameters, and then evaluate the loss process of the gas reservoir.

[0053] Of course, n geological moments can also be marked and divided according to different time intervals on the geological evolution time from the formation of the gas reservoir to the present. At this time, the intervals between any two geological moments can be different or different, and the time range formed between any two adjacent geological moments can also be the same or different, that is, multiple geological time periods are not completely equal. For example, if the main research purpose is to quantify the cumulative natural gas diffusion amount from the formation of the gas reservoir to the present geological evolution time, the typical lithology structure of the overlying strata of the gas reservoir can be used as a reference, and the geological evolution time from the formation of the gas reservoir to the present can be divided into multiple geological time periods according to certain rock geological characteristics (for example, lithology, thickness, or burial depth, etc.), so as to analyze and confirm the natural gas diffusion amount in each geological time period, and then determine the cumulative natural gas diffusion amount.

[0054] Furthermore, in step S102, the process of determining the natural gas diffusion amount in each geological time period includes but is not limited to the following sub-steps S1021 to S1023.

[0055] Sub-step S1021: Determine the diffusion amount per unit area q of the overlying strata of the gas reservoir in each geological time period i .

[0056] Sub-step S1022: Determine the gas reservoir area A in each geological time period i .

[0057] Sub-step S1023: Determine the natural gas diffusion amount G in each geological time period based on the diffusion amount per unit area of ​​the overlying strata of the gas reservoir in each geological time period and the gas reservoir area.i .

[0058] For example, from the i-th geological moment t i To the i+1th geological time t i+1 The amount of natural gas diffusion during this geological period can be calculated using the following formula (2) or formula (3).

[0059] Q i =q i A i (2)

[0060]

[0061] In the formula, Q i is the i-th geological moment t i To the i+1th geological time t i+1 The mass of natural gas diffusion during this geological period, kg; q i is the i-th geological moment t i To the i+1th geological time t i+1 Diffusion per unit area in this geological period, kg / m 2 ; A i is the i-th geological moment t i Gas reservoir area, m 2 ; G i is the i-th geological moment t i To geological time t i+1 The amount of natural gas diffusion during this geological period, m 3 ; M is the molar mass of natural gas, kg / mol; V m is the molar volume of gas under standard conditions, 22.4 L / mol.

[0062] From the i-th geological moment t i To the i+1th geological time t i+1 The diffusion per unit area in this geological time period can be calculated using the following equations (4) and (5).

[0063]

[0064] c 1i =φ i ρ wi S gi (5)

[0065] In the formula, q i is the time from the i-th geological moment t i To the i+1th geological time t i+1 The diffusion amount per unit area, kg / m 2 ;D eiis the overlying stratum of the gas reservoir at the i-th geological time t i The comprehensive diffusion coefficient, 10 -10 m 2 / s;h ji is the jth lithologic stratum contained in the overlying strata of the gas reservoir at the i-th geological time t i Thickness, m; j = 1, 2, 3, ...; c 1i is the i-th geological moment t i Gas concentration at the interface between the gas and the direct cap layer, kg / m 3 ; φ i is the i-th geological moment t i The porosity of the sample, %; ρ wi is the i-th geological moment t i Density of formation water, kg / m 3 ; S gi is the i-th geological moment t i Solubility of natural gas in formation water under actual temperature and pressure conditions, mol / kg.

[0066] Furthermore, in sub-step S1021, the process of determining the comprehensive diffusion coefficient of the overlying strata of the gas reservoir in each geological time period includes but is not limited to the following sub-steps S1021A to S1021B.

[0067] Sub-step S1021A: Determine the effective diffusion coefficient D of different lithological strata contained in the overlying strata of the gas reservoir in each geological time period ji .

[0068] Sub-step S1021B: Calculate the effective diffusion coefficient in each geological time period by weighted average according to the thickness of different lithological strata to obtain the comprehensive diffusion coefficient D of the overlying strata of the gas reservoir in each geological time period. ei .

[0069] The overlying strata of the gas reservoir are composed of multiple different lithological strata, including the overburden and reservoir overburden. Moreover, the lithological strata contained in the overburden of the gas reservoir are different at different geological times, and the total thickness of the overburden is determined according to the thickness of different lithological strata. This is because in the initial geological period when the gas reservoir is just formed, the burial depth of the gas reservoir is shallow, and the overburden may only contain the overburden; with the passage of geological time, the burial depth of the gas reservoir gradually increases, and the overburden will gradually evolve into multiple overburden and reservoir overburden. In other words, in different geological time periods, the geological structure changes, the types and quantities of cap and reservoir contained in the overburden of the gas reservoir are different, the thickness of the cap and reservoir are also different, and the geological parameters corresponding to different cap and reservoir are naturally different, and the corresponding effective diffusion coefficients are not completely the same. The changes of the effective diffusion coefficient with geological time and the thickness of the overburden should be considered.

[0070] Considering that in addition to the dense direct cap and regional cap, the overlying reservoir can also play a certain role in sealing even with high porosity, so all the strata overlying the gas field can be regarded as a set of thick cap. Each stratum overlying the gas reservoir has a certain sealing capacity, and the sealing capacity of different strata is distinguished by their respective diffusion coefficients. The comprehensive diffusion coefficient can be calculated based on the diffusion coefficient and thickness of each stratum. For example, from the i-th geological time t i To the i+1th geological time t i+1 The comprehensive diffusion coefficient within this geological time period can be calculated using the following formula (6).

[0071]

[0072] Where D ei is the overlying stratum of the gas reservoir at the i-th geological time t i The comprehensive diffusion coefficient, 10 -10 m 2 / s;h ji is the jth lithologic stratum contained in the overlying strata of the gas reservoir at the i-th geological time t i Thickness, m; j = 1, 2, 3, ...; h 1i is the first lithologic stratum overlying the gas reservoir (i.e., the direct cap rock overlying the gas reservoir) at the i-th geological time t i Thickness, m; D ji is the jth lithologic stratum contained in the overlying strata of the gas reservoir at the i-th geological time t i The effective diffusion coefficient, m 2 / s;D 1i is the first lithologic stratum overlying the gas reservoir (i.e., the direct cap rock overlying the gas reservoir) at the i-th geological time t i The effective diffusion coefficient, m 2 / s.

[0073] Preferably, in order to determine the true diffusion coefficient under high temperature and high pressure conditions underground, the diffusion coefficients of different lithological formations in different geological time periods can be calculated using parameters such as porosity, permeability, gas viscosity, gas reservoir temperature, and pressure. i The cap rock (reservoir) located in the jth lithologic stratum overlying the gas reservoir is taken as the actual sample, and the actual sample is processed into a saturated water sample and a dry sample, and the test data of the natural gas diffusion coefficient of the saturated water sample and the dry sample are obtained respectively. Finally, based on the test data, formula (7) is used to calculate the cap rock (reservoir) located in the jth lithologic stratum overlying the gas reservoir at the i-th geological time t i The effective diffusion coefficient D ji .

[0074] D ji =a×k i / (φ i ×μ i ×1 / p i ) (7)

[0075] Where D ji is the jth lithologic stratum overlying the gas reservoir at the i-th geological time t i The effective diffusion coefficient, m 2 / s; a is the correction coefficient of saturated water sample and dry sample, dimensionless; k i is the i-th geological moment t i Permeability of dry samples, 10 -3 μm 2 ; φ i is the i-th geological moment t i The porosity of the sample, %; μ i is the i-th geological moment t i Natural gas viscosity, Pa.s; p i is the i-th geological moment t i Gas reservoir pressure, MPa.

[0076] In order to ensure the reliability of the parameters, the natural gas diffusion coefficient test data of the actual sample saturated with water and the test data of the dry sample need to be corrected. For example, a set of diffusion coefficients can be calculated based on the test data of the dry sample and the saturated with water sample, and the ratio of the two sets of diffusion coefficients is determined as the correction coefficient a in the above formula (7).

[0077] Furthermore, in this embodiment, the method further comprises step S100: determining geological parameters in different geological time periods. Specifically, determining geological parameters in different geological time periods can be achieved through the following steps:

[0078] Sub-step S1001: Obtain the burial history map, thermal history map and pressure history map of the gas reservoir over the geological evolution time through basin simulation recovery.

[0079] Sub-step S1002: Determine the burial depth of the overlying strata of the gas reservoir at each geological moment and the burial depths d of different lithological strata included in the overlying strata of the gas reservoir based on the burial history diagram. ji and thickness h ji (i=1, 2, 3...n, j=1, 2, 3...).

[0080] Sub-step S1003: Determine the temperature T of the overlying strata of the gas reservoir at each geological moment based on the thermal history map and the pressure history map. ji and pressure P ji (i=1, 2, 3,…n).

[0081] In addition, the implementation environment of this embodiment includes at least one terminal and a server, and the method is executed on the terminal or the server respectively. The terminal and the server can be connected in communication to realize the interactive transmission of information.

[0082] Among them, the terminal can be any electronic product that can interact with the user through one or more methods such as keyboard, touchpad, touch screen, voice interaction, etc., such as PC (Personal Computer), PPC (Pocket Personal Computer), tablet computer, etc.

[0083] The server can be a single server or a server cluster composed of multiple servers. It can also be a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communications, middleware services, domain name services, security services, CDN (Content Delivery Network), as well as big data and artificial intelligence platforms.

[0084] Embodiment 2

[0085] Taking a natural gas reservoir as an example, the second embodiment of the present invention provides a method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination, the method comprising the following steps:

[0086] Step S201: Restore the burial history, thermal history and pressure history of the gas reservoir at different geological times based on basin simulation technology.

[0087] Step S202: Mark n geological moments in the geological evolution time from the formation of the gas reservoir to the present according to different geological time intervals, thereby dividing it into n-1 geological time periods.

[0088] Step S203: Obtain the cap layers and reservoir layers overlying the gas reservoir at geological time t according to the burial history map. i The burial depth d ji and thickness h ji (i=1, 2, 3...n, j=1, 2, 3...).

[0089] Figure 2 The graph shows the changes of gas reservoirs and overlying strata over geological time, where "01" represents cap layer 1 (mudstone), "02" represents reservoir 1 (sandstone), "03" represents cap layer 2 (mudstone), "04" represents reservoir 2 (sandstone), "05" represents cap layer 3 (mudstone), and "06" represents gas reservoir. Figure 2 As shown in the figure, five geological moments (t 1 ,t 2 ,t 3 ,t 4 and t 5 ), thus dividing the geological time periods into four periods (10 million years, 5 million years, 10 million years, and 5 million years).

[0090] It can be seen that at geological time t 5 (i.e. when the gas reservoir was formed), there was only one cap rock 3 (mudstone) covering the gas reservoir; at geological time t 4 , the gas reservoir is covered by a cap layer 3 (mudstone) and a reservoir layer 2 (sandstone) in sequence; at geological time t 3 , the gas reservoir is covered by a cap layer 3 (mudstone), a reservoir layer 2 (sandstone) and a cap layer 2 (mudstone) in sequence; at geological time t 4 , the gas reservoir is covered by a cap layer 3 (mudstone), a reservoir layer 2 (sandstone), a cap layer 2 (mudstone) and a reservoir layer 1 (sandstone) in sequence; at geological time t 1 (i.e., today), the gas reservoir is covered by a cap layer 3 (mudstone), a reservoir layer 2 (sandstone), a cap layer 2 (mudstone), a reservoir layer 1 (sandstone), and a cap layer 1 (mudstone). That is, at different geological moments, the types of lithological strata overlying the gas reservoir are different.

[0091] Step S204: Obtain the gas reservoir and each cap layer and each reservoir layer overlying the gas reservoir at geological time t according to the thermal history and pressure history. i Temperature T ji and pressure P ji (i=1, 2, 3...n).

[0092] Step S205: Calculate the cap layers and reservoir layers overlying the gas reservoir at geological time t iThe effective diffusion coefficient D ji .

[0093] Step S206: Calculate the thickness of the overlying strata at geological time t by using the diffusion coefficients of different lithological strata overlying the gas reservoir and weighted average according to thickness. i The comprehensive diffusion coefficient D ei (i=1, 2, 3,…n).

[0094] Step S207: Calculate geological time t i To geological time t i+1 The diffusion per unit area in this geological time period is q i (i=1, 2, 3,…n).

[0095] Step S208: Calculate geological time t i To geological time t i+1 The amount of natural gas diffusion during this geological period G i .

[0096] Step S209: Add up the natural gas diffusion amount in each geological time period to obtain the cumulative natural gas diffusion amount G of the gas reservoir. c .

[0097] At present, the gas reservoir is covered by three sets of mudstone cap layers with good sealing properties and two sets of sandstone reservoir layers with poor sealing properties. 1 ~t 5 The geological parameters corresponding to the geological moments are shown in Tables 1 to 5, and the final calculated cumulative natural gas diffusion is shown in Table 6.

[0098] According to the calculation results of this embodiment (Table 1 to Table 6), 4.932 billion cubic meters (10 8 m 3 ) natural gas; 6.819 billion cubic meters (10 million cubic meters) were lost in the geological period from 10 million to 15 million years after the formation of the gas reservoir. 8 m 3 ) natural gas; 15.243 billion cubic meters (10 8 m 3 ) natural gas; 24.523 billion cubic meters (10 8 m 3 ) natural gas; the gas reservoir has lost 51.518 billion cubic meters (10 8 m 3) natural gas. The dynamic evolution of the cumulative diffusion of natural gas obtained over geological time can be seen Figure 3 .

[0099] Table 1 Geological time t 1 (Current) Parameter Table

[0100]

[0101] Table 2 Geological time t 2 (5Ma) Parameters

[0102]

[0103] Table 3 Geological time t 3 (15Ma) Parameters

[0104]

[0105] Table 4 Geological time t 4 (20Ma) Parameters

[0106]

[0107] Table 5 Geological time t 5 (30Ma) Parameters

[0108]

[0109] Table 6 Cumulative diffusion results

[0110]

[0111] Embodiment 3

[0112] The third embodiment of the present invention further provides an electronic device, see Figure 4 The electronic device includes a processor 201 and a memory 202, wherein at least one computer program is stored in the memory, and the at least one computer program is loaded and executed by one or more of the above-mentioned processors to enable the processor to implement the method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination as described above.

[0113] Of course, the electronic device may also have components such as a wired or wireless network interface, a keyboard, and an input / output interface for input and output. The electronic device may also include other components for realizing various functions of the device, which will not be described in detail here.

[0114] The third embodiment of the present invention also provides a computer-readable storage medium, in which at least one program code is stored. The program code is loaded and executed by a processor to enable a computer to implement the method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination as described above.

[0115] Optionally, the computer readable storage medium may be a read-only memory (ROM), a random access memory (RAM), a compact disc (CD-ROM), a magnetic tape, a floppy disk, and an optical disc data storage device. Those skilled in the art may understand that all or part of the steps in the above-mentioned embodiment method can be completed by instructing the relevant hardware through a program, and the program is stored in a storage medium, including several instructions to enable a single-chip microcomputer, a chip or a processor to execute all or part of the steps of the method described in each embodiment of the present application. The aforementioned storage medium includes: various media that can store program codes, such as a USB flash drive, a mobile hard disk, a read-only memory (ROM), a random access memory (RAM), a magnetic disk or an optical disc.

[0116] The preferred embodiments of the present invention are described in detail above in conjunction with the accompanying drawings. However, the present invention is not limited to the specific details in the above embodiments. Within the technical concept of the present invention, a variety of simple modifications can be made to the technical solution of the present invention, and these simple modifications all belong to the protection scope of the present invention.

[0117] It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. In order to avoid unnecessary repetition, the present invention will not further describe various possible combinations.

[0118] In addition, various embodiments of the present invention may be arbitrarily combined, and as long as they do not violate the concept of the present invention, they should also be regarded as the contents disclosed by the present invention.

Claims

1. A method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination, characterized in that: The method comprises: Divide the geological evolution time from the formation of gas reservoirs to the present into multiple geological time periods; Determine the diffusion amount of natural gas in each geological time period based on the geological parameters corresponding to the overlying strata of the gas reservoir in each geological time period; The natural gas diffusion in different geological time periods is added together to obtain the cumulative natural gas diffusion in the gas reservoir; Among them, the overlying strata of the gas reservoir are composed of multiple different lithological strata, and the lithological strata contained in the overlying strata of the gas reservoir are different in different geological time periods. The total thickness of the overlying strata of the gas reservoir is determined according to the thickness of the different lithological strata; the geological parameters include the burial depth of the gas reservoir, stratum thickness, temperature, pressure and diffusion coefficient.

2. The method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to claim 1, characterized in that: Determining the amount of natural gas diffusion in each geological time period includes: Determine the diffusion per unit area of ​​the overlying strata of the gas reservoir in each geological time period; Determine the area of ​​gas reservoirs in each geological time period; Based on the diffusion per unit area of ​​the overlying strata of the gas reservoir in each geological time period and the area of ​​the gas reservoir, the diffusion amount of natural gas in each geological time period is determined.

3. The method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to claim 2, characterized in that: Determining the diffusion amount per unit area of ​​the overlying strata of the gas reservoir in each geological time period includes: Determine the comprehensive diffusion coefficient of the overlying strata of the gas reservoir in each geological time period; Based on the comprehensive diffusion coefficient and total thickness of the overlying strata of the gas reservoir in each geological time period, the diffusion amount per unit area of ​​the overlying strata of the gas reservoir in each geological time period is determined.

4. The method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to claim 3, characterized in that: Determining the comprehensive diffusion coefficient of the overlying strata of the gas reservoir in each geological time period includes: Determine the effective diffusion coefficients of different lithological strata contained in the overlying strata of the gas reservoir in each geological time period; The effective diffusion coefficient in each geological time period is weighted averaged according to the thickness of different lithological strata to obtain the comprehensive diffusion coefficient of the overlying strata of the gas reservoir in each geological time period.

5. The method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to claim 4, characterized in that: The calculation formula of the effective diffusion coefficient is: D ji =a×k i / (φ i ×m i ×1 / p i ); Among them, D ji is the jth lithologic stratum overlying the gas reservoir at the i-th geological time t i The effective diffusion coefficient, m 2 / s; a is the correction factor, dimensionless; k i is the i-th geological moment t i Permeability of dry samples, 10 -3 μm 2 ; φ i is the i-th geological moment t i The porosity of the sample, %; μ i is the i-th geological moment t i Natural gas viscosity, Pa.s; p i is the i-th geological moment t i Gas reservoir pressure, MPa; i = 1, 2, 3...n, t1 represents the current time, t n represents the time of gas reservoir formation, t i represents the i-th geological moment.

6. The method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to claim 5, characterized in that: The correction coefficient is determined based on the natural gas diffusion coefficient test data of the actual sample and the natural gas diffusion coefficient test data of the dry sample.

7. The method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to claim 3, characterized in that: The calculation formula of the diffusion per unit area is: c 1i =φ i r wi S gi ; Among them, q i is the time from the i-th geological moment t i To the i+1th geological time t i+1 The diffusion amount per unit area, kg / m 2 ;D ei is the overlying stratum of the gas reservoir at the i-th geological time t i The comprehensive diffusion coefficient, 10 -10 m 2 / s;h ji is the jth lithologic stratum contained in the overlying strata of the gas reservoir at the i-th geological time t i Thickness, m; j = 1, 2, 3, ...; c 1i is the i-th geological moment t i Gas concentration at the interface between the gas and the direct cap layer, kg / m 3 ; φ i is the i-th geological moment t i The porosity of the sample, %; ρ wi is the i-th geological moment t i Density of formation water, kg / m 3 ; S gi is the i-th geological moment t i Solubility of natural gas in formation water under actual temperature and pressure conditions, mol / kg.

8. The method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to claim 4, characterized in that: The method further comprises: The burial history map, thermal history map and pressure history map of the gas reservoir over the geological evolution time are obtained through basin simulation restoration; Determine the burial depth of the overlying strata of the gas reservoir at different geological times and the thickness of different lithological strata contained in the overlying strata of the gas reservoir based on the burial history map; The temperature and pressure of the strata overlying the gas reservoir at different geological moments are determined based on the thermal history diagram and the pressure history diagram.

9. An electronic device, characterized in that: The electronic device includes a processor and a memory, wherein the memory stores at least one computer program, and the at least one computer program is loaded and executed by one or more of the above processors so that the processor executes the method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination as described in any one of claims 1 to 8.

10. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores at least one program code, and the program code is loaded and executed by the processor to enable the computer to execute the method for dynamically determining the diffusion amount of natural gas in a multiple reservoir-cap combination according to any one of claims 1 to 8.

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