Quantitative evaluation method for influence of formation water in shale reservoir on methane adsorption amount

Abstract

The invention discloses a quantitative evaluation method for the influence of formation water in a shale reservoir on the methane adsorption amount. The quantitative evaluation method comprises the following steps: constructing a kerogen model of a target area; adding water molecules into the kerogen model to obtain a steady-state matrix model with a water molecule distribution conformation; inserting methane molecules into the steady-state matrix model to obtain the number of the inserted methane molecules at different temperatures and pressures; and determining a quantitative relationship between the methane gas suction amount and the underground fugacity and the moisture content by combining the number of the methane molecules, and completing quantitative evaluation of the influence of the formation water in the shale reservoir on the methane gas adsorption amount according to the quantitative relationship. The method disclosed by the invention reveals the occurrence state and aggregation characteristics of the methane gas in the water-containing shale reservoir, and has important guiding significance for further understanding the enrichment mechanism of the shale gas.

Description

Technical Field

[0001] The present disclosure relates to the field related to shale gas resource volume and reserve evaluation, and particularly relates to a quantitative evaluation method for estimating methane adsorption capacity, accumulation scale and quantity under the conditions of different contents of original formation water. Background Art

[0002] The statements in this section only provide background information related to the present disclosure and do not constitute prior art.

[0003] Compared with conventional oil and gas, shale gas has the characteristics of being self-generated, self-stored, self-sealed, large-area continuous hydrocarbon accumulation, no obvious oil-water interface and trap range, poor reservoir physical properties, low pore connectivity, and the need for hydraulic fracturing to form economic productivity. Although it exists in the reservoir in various forms including free state, adsorbed state and a small amount of dissolved state, it is not difficult to see from the actual production data of shale gas fields such as Antrim, Ohio, New Albany, Barnett and Lewis that the contribution of adsorbed gas in the estimation of in-situ resource volume and production is relatively prominent (generally accounting for 20 - 85%).

[0004] Previous researchers have carried out a lot of work on adsorbed gas in shale reservoirs. The research content mainly focuses on analyzing the influence of external factors such as different rock and mineral components, organic matter type and abundance, thermal evolution maturity, reservoir pore and fracture structure characteristics, temperature and pressure on gas adsorption capacity through isothermal adsorption experiments; and calculating the maximum methane adsorption volume in different types of pores through empirical formulas based on monolayer and multilayer adsorption theories.

[0005] In fact, shale reservoir fluids, especially formation water, have a strong control over the accumulation capacity of methane gas in nano-scale pores, and at the same time, they will also cause a significant decrease in the adsorption capacity of organic matter for methane gas, thus affecting the accuracy of the estimation results of the ultimate in-situ resource volume and geological reserves. However, the previous experimental testing methods and theoretical empirical formulas rarely involve the evaluation of the destructive effect of formation water on gas adsorption capacity; moreover, the existing molecular dynamics methods usually have a short simulation time, and in this case, it is difficult to accurately describe the invasion volume and specific distribution position of formation water in the shale formation series, resulting in a large difference between the simulation results and the actual underground situation in the calculation results. In addition, there are many reports on the adsorption behavior of water molecules and the occurrence positions of water molecules in shale (or coal rock) at present, but there are few published results on shale wettability, the formation conditions of stable water films, and their effects on shale oil and gas accumulation and destruction; there are even blank areas in the combination of formation water content and the change of reservoir physical property characteristics and further affecting the methane adsorption gas volume. Moreover, the existing experiments and simulations usually do not consider the aggregation mechanism of methane in nano-scale pores under different water content conditions at the micro scale, nor do they have a quantitative evaluation of its influence on the final adsorbed gas volume.

[0006] Although the influence of formation water on methane gas adsorption is an important evaluation content for judging the underground gas occurrence state and estimating resource potential. However, based on the current research status, and due to the strong heterogeneity and anisotropy of shale, the tight reservoir, the large span and uneven distribution of formation water content, how to comprehensively and scientifically understand the aggregation mechanism of methane gas under different water content conditions, and transform it into a quantitative evaluation of the influence on the final adsorbed gas volume, and finally obtain an accurate and reasonable resource volume estimation value is the current urgent research focus and hot spot.

[0007] Generally speaking, the main reasons why the influence of formation water on methane adsorption gas volume has not been considered in the existing experiments and studies on shale reservoir adsorption gas volume are as follows: In terms of the basic model, there are significant differences in the characteristics of shale reservoir in different blocks, formations, and even different positions in the same block or formation. The gas aggregation mechanism and accumulation mode are also different. If starting from conventional macroscopic geological evaluation parameters or using the same set of empirical models alone, there will be problems of poor adaptability and weak relevance between the target and the means.

[0008] In terms of test analysis, it is often difficult to simultaneously meet or reach the true temperature and pressure of the target shale formation under laboratory conditions; at the same time, it is difficult to obtain samples, with high costs and limited experimental data volume, resulting in certain spatial limitations of the experimental results, thus indirectly reducing their universality, guiding significance, and popularization.

[0009] In terms of theoretical calculation, the existing empirical formulas are mostly based on the methane adsorption capacity of pores or fractures under ideal conditions. However, it is not difficult to find from the parameters in the formula that the applicability and accuracy of the model are mostly controlled by the organic matter abundance, type, thermal evolution maturity, mineral composition of the shale, and the actual adsorption state of methane (monolayer, bilayer or multilayer); and some of these indicators cannot be quantified or are not involved in direct calculation, which will ultimately lead to a certain degree of deviation in the calculation results of the adsorbed gas volume.

[0010] It should be noted that the information disclosed in the above background art section is only used to enhance the understanding of the background of the present disclosure, and therefore may include information that does not constitute the prior art. Summary of the Invention

[0011] In view of this, the present disclosure provides a quantitative evaluation of the influence of formation water on the adsorbed gas volume of methane in shale reservoirs. Specifically, by means of macroscopic parameters such as the formation water content, temperature and pressure of the target shale formation, the aggregation mechanism of methane gas in shale reservoirs is studied, so as to obtain a quantitative calculation formula for the adsorbed gas volume of methane under the given values of the above indicators.

[0012] The quantitative evaluation method for the influence of formation water on the adsorbed gas volume of methane in the shale reservoir described above includes: Obtain the geochemical information of the target area, build the topological structure of kerogen molecules, and construct the kerogen model of the target area; Add water molecules to the kerogen model to obtain a steady-state matrix model with the conformational distribution of water molecules; Insert methane molecules into the steady-state matrix model and stop when the energy fluctuation range reaches the set value to obtain the number of methane molecules inserted at different temperatures and pressures; Combine the number of methane molecules to determine the quantitative relationship between the methane uptake and the underground fugacity and water content, and complete the quantitative evaluation of the influence of formation water on the adsorbed gas volume of methane in the shale reservoir according to the quantitative relationship.

[0013] In the present disclosure and possible embodiments, the method for building the topological structure of kerogen molecules includes: Based on the geochemical information, use nuclear magnetic resonance spectroscopy, infrared spectroscopy and mass spectrometry to obtain the ratios of carbon, hydrogen, oxygen, nitrogen and sulfur in the organic matter content of the target area and the ratios of different functional groups in the organic matter; Obtain the organic matter chemical formula through the ratios of carbon, hydrogen, oxygen, nitrogen and sulfur and the ratios of the functional groups; Refer to the organic matter chemical formula and use molecular dynamics to build the topological structure of kerogen molecules.

[0014] In the present disclosure and possible embodiments, the method for constructing the kerogen model of the target area includes: Regarding the topological structure of the kerogen molecule as a kerogen unit, placing the kerogen unit into the reservoir space of shale where both micro-nano micropores and narrow fractures exist to obtain a primary kerogen model of the target area; Using the grand canonical ensemble Monte Carlo method to simulate and process the primary kerogen model, enabling the recombination of the kerogen units to form the kerogen model of the target area.

[0015] In the present disclosure and possible embodiments, the method for adding water molecules to the kerogen model includes: Determining the number of water molecules to be added to the kerogen model; Adding the water molecules in batches. After each addition of the water molecules, using the grand canonical ensemble Monte Carlo method to simulate and process the system and reaching the thermal equilibrium state, then adding the next batch of the water molecules in the same mode until all the water molecules are added and the final thermal equilibrium state is reached, obtaining a steady-state matrix model with the water molecule distribution conformation.

[0016] In the present disclosure and possible embodiments, the method for determining the number of water molecules to be added to the kerogen model includes: The product of the number of kerogen units in the kerogen model and the molar mass of the kerogen, divided by the molar mass of water and then multiplied by 0.01, is equal to the number of water molecules corresponding to 1% of the mass of the kerogen model; Calculating the total number of water molecules to be added according to 5% of the mass of the kerogen model.

[0017] In the present disclosure and possible embodiments, the method for determining the thermal equilibrium state includes: Based on Newton's second law, using the Verlet algorithm to track the movement displacement and velocity of each atom at each time step, and calculating the energy difference generated between the current time step and the previous time step due to the atomic movement by calculating the energy iteration. The time step corresponding to when the energy difference is not higher than 2% is determined as the start of the thermal equilibrium state.

[0018] In the present disclosure and possible embodiments, inserting the methane molecules into the steady-state matrix model according to the grand canonical ensemble Monte Carlo method and the molecular dynamics theory.

[0019] In the present disclosure and possible embodiments, the method for inserting the methane molecules includes: Obtaining the chemical potential energy of the reference methane gas at different temperatures and pressures; During the process of inserting the methane molecules, judging the chemical potential energy of the system until the energy fluctuation range does not exceed 2%, obtaining the number of methane molecules inserted at the corresponding temperature and pressure.

[0020] The present disclosure has the following beneficial effects: In the evaluation method of the present invention, during the process of establishing the reservoir model, the atomic structure of kerogen is described in detail, and the influence and control of the proportion of different polar functional groups on the water molecule distribution are considered. Before the quantitative calculation, the rationality of the framework within the scope of geological understanding is ensured; based on the physical criteria of the method and the shale gas accumulation mechanism, starting from the molecular motion law and the internal correlation of variables, data processing, insertion, training and other work are carried out through programs, reducing human intervention, so that while improving the richness of data, the objectivity of the entire simulation process is also promoted; the general formula of the fitting relationship between the methane adsorption gas volume and the underground fugacity and water content is proposed, quantifying the influence of the formation water content on the underground methane gas adsorption capacity, achieving the purpose of connecting the microscopic mechanism to the macroscopic evaluation and transforming the qualitative analysis into quantitative calculation, greatly improving the accuracy, authenticity and reliability of the shale adsorption gas volume calculation result, weakening the difficulty of the evaluation work caused by the heterogeneity of the shale reservoir, and having strong popularization; through the research and description of the methane molecular motion law under different water content conditions, the occurrence state and aggregation characteristics of methane gas in the water-bearing shale reservoir are revealed, which has important guiding significance for further understanding the shale gas enrichment mechanism. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Through the description of the embodiments of the present disclosure with reference to the following drawings, the above and other objects, features and advantages of the present disclosure will become clearer. In the drawings: Figure 1 is the formation model of the embodiment of the present disclosure (dark gray represents porosity); Figures 2-1 to 2-5 is the formation water-bearing model constructed according to different water contents in the embodiment of the present disclosure; Figure 2-6 is Figure 2-3 the enlarged diagram of the occurrence state of molecular water in Figure 3 is the schematic diagram of the adsorption of methane molecules under the influence of formation water in the embodiment of the present disclosure; Figure 4 is the schematic diagram of the change of methane molecular adsorption energy in the embodiment of the present disclosure. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0022] The following describes the present disclosure based on embodiments. However, it should be noted that the present disclosure is not limited to these embodiments. In the following detailed description of the present disclosure, some specific details are described in detail. However, for the parts not described in detail, those skilled in the art can also fully understand the present disclosure.

[0023] In addition, those of ordinary skill in the art should understand that the provided drawings are only for illustrating the purposes, features, and advantages of the present disclosure, and the drawings are not actually drawn to scale. At the same time, unless the context clearly requires otherwise, words such as "including" and "comprising" in the entire specification and claims should be interpreted in an inclusive sense rather than an exclusive or exhaustive sense; that is, it means "including but not limited to".

[0024] To make the objectives, technical solutions, and advantages of the present invention clearer and more understandable, the following further describes the present invention in detail with reference to the drawings and by way of examples. Embodiment

[0025] Numerous domestic and foreign examples show that the formation water content is closely related to the oil and gas production, and it has an obvious obstructive effect on the methane gas accumulation. Due to the better affinity and stronger interaction between formation water and the shale surface, water molecules will occupy more adsorption sites and form a water lock effect in the nano-pores, blocking the pore-throat paths during the gas diffusion process, and ultimately resulting in a decrease in the methane adsorption capacity and rate.

[0026] Accordingly, in the embodiments of the present invention, based on numerical simulation, by using technical means such as open-source software (Large-scale Atomic / Molecular Massively Parallel Simulator), the dynamic change process of the methane adsorption gas volume with different water contents, temperatures, and pressures is analyzed. During this process, by improving the traditional simulation force field, the topological structure of each component participating in the simulation process is described in detail, especially the conformation of organic matter (disassembled to the atomic level). Without sacrificing the intermolecular and intramolecular interaction forces, sufficient data training workload is ensured. Then, according to the corresponding statistical method, a quantitative relationship general formula between the obtained independent variables (water content, temperature, pressure) and the dependent variable (methane adsorption gas volume) is established, so as to achieve the purpose of determining the methane adsorption gas volume in the shale reservoir based on formation water.

[0027] The specific solution adopted in this embodiment is as follows: 1. Construct a model framework for evaluating the influence of water content on the methane adsorption gas volume; the specific construction process is as follows: 1. Through the geochemical information of the target area, depict the topological structure of kerogen molecules and construct a kerogen model for the target area; the specific method is as follows: (1) Collect basic data such as the kerogen type (including carbon / oxygen ratio, carbon / hydrogen ratio), thermal evolution maturity, density, porosity, and formation water content of the target shale formation in the target area as geochemical information.

[0028] (2) Obtain the ratios of carbon, hydrogen, oxygen, nitrogen, and sulfur in the organic matter content and the ratios of different functional groups in the organic matter through three experimental methods: nuclear magnetic resonance spectroscopy (NMR), infrared spectroscopy, and mass spectrometry.

[0029] Based on the ratios of carbon, hydrogen, oxygen, nitrogen, and sulfur in the organic matter content and the ratios of different functional groups obtained by the above experimental means, use the molecular dynamics method to build a molecular topology structure. This molecular topology structure is specific to each atom, and each molecular topology structure corresponds to a kerogen unit. A total of 20 kerogen units are built in the embodiments of the present disclosure. Of course, the number of the built kerogen units can be more or less, and the method of the present disclosure does not limit this.

[0030] (3) Use the open-source software LAMMPS (Large-scale Atomic / Molecular Massively Parallel Simulator) to place 20 kerogen units into a simulation box, with 10 in the upper part and 10 in the lower part, and leave a fixed narrow crack with a space of 2 nanometers in the middle to retain an important part of the physical properties of shale, that is, the storage space characteristics of shale with the coexistence of micro-nano micropores and narrow cracks, to obtain a primary kerogen model of the target area.

[0031] The matrix thickness determined in the model of the present invention is much larger than the thickness of the narrow crack, aiming to prominently display the narrow crack. Because if the matrix thickness is close to the width of the narrow crack, the physical characteristics of the narrow crack in shale cannot be highlighted; and the distribution of methane gas and the difference in adsorption between the narrow crack and the micro-nano pores can be compared. Further, the gas adsorption aggregation characteristics depending on the narrow crack and the micro-nano pores and the methane gas adsorption amount can be obtained through simulation calculations.

[0032] (4) Reconstruct the primary kerogen model to obtain a stable kerogen model of the target area: Use the grand canonical ensemble Monte Carlo method to simulate and process the primary kerogen model. Specifically, by means of heating, pressurizing, then constant-temperature depressurizing, and constant-pressure cooling, the 20 kerogen units are recombined to achieve collapse and reconstruction, and finally a stable kerogen model of the target area is formed, as specifically shown in Figure 1 Obviously, the kerogen model obtained through the above process fits the morphology of the shale reservoir and is completely different from the single molecular structure generated in step (1).

[0033] 2. Add water molecules to the kerogen model. During the addition process, determine the equilibrium state through iterative calculation to obtain a steady-state matrix model with the water molecule distribution conformation. The specific process is as follows: (1) Calculate the number of water molecules added to the kerogen model. The specific calculation method is as follows: The molar mass of kerogen is 2484 g / mol, and the molar mass of water is 18 g / mol. Each kerogen model consists of 20 kerogen units, and one kerogen unit is one kerogen molecule. Then the formula for calculating the number of water molecules corresponding to 1% of the mass of the kerogen model is: 2484 * 20 / (18 * 100), and the calculation result is approximately 50 water molecules.

[0034] Similarly, calculate the number of water molecules corresponding to adding 2%, 3%, 4%, and 5% of the mass of the kerogen model.

[0035] (2) After placing approximately 50 water molecules corresponding to 1 wt% of the mass of the kerogen model at any position in the simulation box, use the grand canonical ensemble Monte Carlo method for simulation until reaching the thermal equilibrium state. Since the simulation system is a closed system, energy exchange occurs during the simulation to achieve thermal equilibrium. At this time, the model energy is minimized and the structure is most stable. Continue in the same pattern, that is, after adding 50 water molecules each time (equivalent to 1 wt% of the mass of the kerogen model), use the grand canonical ensemble Monte Carlo method for simulation and wait until the thermal equilibrium state is reached before adding the next batch of water molecules, until the addition of water molecules equivalent to 5 wt% of the mass of the kerogen model is completed and the final thermal equilibrium state is reached.

[0036] Although the water molecules are placed at any position in the simulation box, the molecules will achieve the final distribution in terms of geometric structure according to the principles of classical molecular dynamics. Therefore, after the final thermal equilibrium state is determined, the conformation of the re-distribution of water molecules can be obtained, that is, the water molecules move according to their own physical properties and adsorb at the reasonable adsorption sites of the organic matter model. Calculate and retain 20000000 steps starting from the thermal equilibrium state as the steady-state structure, and retain the model generated in the last step as the steady-state matrix model for subsequent calculation of the influence of water content on methane adsorption capacity.

[0037] (3) For the above method of determining the thermal equilibrium state, based on Newton's second law, the Verlet algorithm is used to track the movement displacement and velocity of each atom at each time step. By calculating the energy generated by the atomic movement to iterate the energy difference between this time step and the previous time step. At the beginning of the energy minimization process, the energy difference changes significantly in each step. So, keep performing iterative calculations until the energy difference is stable and does not show a difference higher than 2%. Then stop the iterative calculation and determine this time step as the start of the equilibrium state.

[0038] Figures 2-1 to 2-5The shown formation water content model is constructed based on a water content of 1 wt% - 5 wt%. During the simulation process, it can be seen that a - b shows the distribution state when the water molecule content is 1 - 2 wt%. In this distribution state, water molecules first selectively adsorb in micro - and nano - pores. This is because at this time, the number of water molecules is relatively small, and the adhesion force between water molecules is relatively small. They will first choose the vicinity of hydrophilic functional groups in micro - and nano - pores. Since the amount of water molecules is small, they do not aggregate together, and most of them appear in a dispersed form without forming an aggregated amount. When the water molecule content is 3 wt% and above, since the number of water molecules gradually increases, the adhesion force between water molecules becomes relatively strong, becoming the dominant force in the intermolecular interaction of water molecules, causing water molecules to form water bridges and aggregate together, as specifically shown in the distribution state of c - d. What e shows is the distribution state when the water molecule content is 5 wt%. At this time, as the water molecule content increases, the situation and phenomenon of water molecule aggregation will occur, and it will mainly concentrate and aggregate in the narrow cracks of the shale matrix.

[0039] As Figure 2-6 shown, when the content of water molecules is relatively low (< 3 wt% of the matrix mass), they tend to be distributed dispersedly near - COOH and C = O functional groups, preferably in organic matter micro - and nano - pores and on the surface of narrow cracks; when the content of water molecules is relatively high (> 3 wt% of the matrix mass), they tend to aggregate into small water droplets or form water bridges in narrow cracks.

[0040] The steady - state matrix model constructed by the above steps in the embodiments of the present disclosure has the following advantages: ① The construction of the traditional organic matter kerogen model is based on the commercial software Materials Studio. However, this software has some limitations in model construction. For example, it can only calculate the number of atoms within 100,000. But the open - source software LAMMPS used in the present invention can perform super - large - scale simulations, and can accurately simulate the number of atoms exceeding 100,000. ② During the use of the open - source software in this embodiment, some specified calculation methods and calculation parameters of intermolecular forces based on different force fields can be added. For example, the force field parameters of the commercial software Materials Studio only have some specified force field information. However, the open - source software LAMMPS used in the present invention can expand other force field types and can adjust the parameters according to the needs during the simulation process. ③In this simulation process, a heating and cooling annealing process is added, and a simulation process of increasing and then decreasing pressure is also added to simulate the essential temperature and pressure changes during hydrocarbon generation. This makes the entire simulation process closer to the temperature and pressure conditions changes caused by burial depth, uplift, hydrocarbon generation, and migration during the real formation hydrocarbon generation process, as well as the evolution of functional groups due to temperature and pressure changes. During the modeling process, the shale model undergoes the above temperature and pressure changes to reproduce the hydrocarbon generation process, making the constructed shale model closer to the real formation, with a similarity greater than 90% to the underground porosity, carbon / oxygen ratio, and carbon / hydrogen ratio.

[0041] II. Using the steady-state matrix model, insert methane molecules according to the grand canonical ensemble Monte Carlo method and classical molecular dynamics theory, stop when the energy reaches the set convergence state, collect the number of methane molecules at this time, and extract the average value of the number of methane molecules based on the data after energy convergence. The specific process is as follows: At the given temperature of the target shale formation series, convert the pressure value into underground fugacity. Insert methane molecules into the steady-state matrix model. As Figure 3 shown, there are methane gas molecules in the micro-nano pores of the shale matrix, indicating that the micro-nano pores are also the locations where methane gas is stored. Since the process of inserting methane molecules is directly related to temperature and pressure, different temperatures and pressures are related to chemical potential, and chemical potential energy greatly affects the aggregation degree of methane gas. At different temperatures and pressures, a fixed chemical potential energy of methane gas is targeted.

[0042] Since the process of inserting methane molecules is directly related to temperature and pressure, and different temperatures and pressures are related to chemical potential, chemical potential energy greatly affects the aggregation degree of methane gas. At different temperatures and pressures, a fixed chemical potential energy of methane gas is targeted. By calculating the chemical potential energy of methane gas corresponding to different temperatures and pressures, put these chemical potential energies of methane gas into the command line of the open-source software LAMMPS program script, and use the grand canonical ensemble Monte Carlo method and classical molecular dynamics theory to continuously insert, delete, and rotate and add 10000000 steps of methane molecules to continuously approach this chemical potential energy until the energy converges without excessive fluctuations, indicating that this simulation process is close to the equilibrium state, the energy is relatively stable, and the fluctuation range does not exceed 2%. At this time, it can be stated that the number and movement of methane molecules in the reservoir are basically in equilibrium, and record the average value of the number of methane molecules after the curve converges.

[0043] The results are as Figure 4 shown. Figure 4The latter part is the manifestation that its energy convergence will not have excessive fluctuations, indicating that this simulation process is close to the equilibrium state and the simulation reaches a stable state. The first 2 million steps are the process with obvious energy fluctuations, and the fluctuations are not obvious in the subsequent 8 million steps. Then, the number of methane molecules obtained in each of these 8 million steps is averaged to obtain an average value, which is the number of inserted methane molecules at this temperature and pressure. Preferably, the process of inserting methane molecules should be carried out 5 times, and the average value of these 5 times is used as the final measurement result of the number of methane molecules; the number of methane molecules obtained in this step is used as the counting result for the establishment of the following formula.

[0044] III. Using the extracted number of methane molecules, determine the quantitative relationship between methane gas uptake and underground fugacity and water content, and complete the quantitative evaluation of the influence of formation water on methane adsorption gas volume in shale reservoirs according to the quantitative relationship; the specific process is as follows: Using the data at different positions obtained from the above simulation, with the converted underground fugacity (formation true pressure value) as x, setting the formation water content as y, and the average value of the number of methane molecules after the energy and momentum curves converge as z, a three-dimensional data coordinate system is established.

[0045] Changing the parameter values such as temperature, pressure, and water content, repeating the above numerical simulation work, a large number of data points with three-dimensional information of underground fugacity, water content, and the number of methane molecules can be obtained; using MATLAB software to conduct a correlation analysis on the obtained data, finally obtaining the general formula of the quantitative fitting relationship between methane gas uptake and underground fugacity and water content under given geological conditions, fitting it into an isothermal adsorption curve, obtaining a modified Langmuir curve, and completing the quantitative evaluation of the influence of formation water on methane adsorption gas volume in shale reservoirs according to the curve.

[0046] Application Example Taking a shale model with a relatively high carbon content constructed by all carbon atoms as an example, calculate the methane gas aggregation situation and the methane gas adsorption volume in shale under given temperature, different pressures, and different formation water contents.

[0047] Using the method of the present invention, comprehensively calculate the adsorption situation of methane gas reservoirs in shale matrix using two parameters of pressure value and water content. Input the available formation pressure information in the research area into the X-axis and the formation water content information into the Z-axis, and obtain the general formula of the methane gas aggregation volume on the Y-axis y = f(x,z) = 4.402 + 1.18*x - 0.33*z - 0.4391*x^2 - 0.09764*x*z.

[0048] Using 0-20 MPa pressure as x-axis information and formation water as another parameter, the accumulation of methane gas in the affected shale layer is comprehensively calculated. The data points in the study area are put into the three-axis coordinate diagram of X-pressure / Z-formation water content, and different colors are used to represent the distribution relationship between formation water and methane gas. By fitting the curve, the accumulation equation of methane gas under the influence of formation water at different pressures is y=f(x,z) = 4.402 + 1.18*x - 0.33*z - 0.4391*x^2 -0.09764*x*z (where x is the formation pressure value and z is the formation water content), which can be used to calculate the theoretical value of methane gas that can be sealed under different formation water content conditions.

[0049] The above-described embodiments are only embodiments of the present disclosure, and the descriptions thereof are relatively specific and detailed, but they cannot be construed as limiting the scope of the present disclosure. It should be noted that, for a person of ordinary skill in the art, without departing from the concept of the present disclosure, several variations, equivalent substitutions, improvements, etc. may be made, all of which fall within the scope of protection of the present disclosure. Therefore, the scope of protection of the present disclosure shall be subject to the attached claims.

Claims

1. A quantitative evaluation method for the influence of formation water on the methane adsorption gas volume in shale reservoirs, characterized in that, Including: Obtain the geochemical information of the target area, build the topological structure of kerogen molecules, and construct a kerogen model for the target area; Add water molecules to the kerogen model to obtain a steady-state matrix model with a water molecule distribution conformation; Insert methane molecules into the steady-state matrix model and stop when the energy fluctuation range reaches a set value to obtain the number of methane molecules inserted at different temperatures and pressures; Combine the number of methane molecules to determine the quantitative relationship between methane gas absorption and underground fugacity and water content, and complete the quantitative evaluation of the influence of formation water on methane adsorption gas volume in shale reservoirs based on the quantitative relationship.

2. The quantitative evaluation method for the influence of formation water on the methane adsorption gas volume in shale reservoirs according to claim 1, wherein The method for building the topological structure of kerogen molecules includes: Based on the geochemical information, use nuclear magnetic resonance spectroscopy, infrared spectroscopy, and mass spectrometry to obtain the proportions of carbon, hydrogen, oxygen, nitrogen, and sulfur in the organic matter content of the target area and the ratio of different functional groups in the organic matter; Obtain the organic matter chemical formula through the proportions of carbon, hydrogen, oxygen, nitrogen, and sulfur and the ratio of the functional groups; Refer to the organic matter chemical formula and use molecular dynamics to build the topological structure of kerogen molecules.

3. The quantitative evaluation method for the influence of formation water on the methane adsorption gas volume in shale reservoirs according to claim 2, wherein The method for constructing a kerogen model for the target area includes: Regard the topological structure of kerogen molecules as kerogen units, and place the kerogen units in the reservoir space of shale with both micro-nano micropores and narrow fractures to obtain a primary kerogen model for the target area; Use the grand canonical ensemble Monte Carlo method to simulate and process the primary kerogen model to recombine the kerogen units to form the kerogen model for the target area.

4. The quantitative evaluation method for the influence of formation water on the methane adsorption gas volume in shale reservoirs according to claim 3, wherein, The method for adding water molecules to the kerogen model includes: Determine the number of water molecules to be added to the kerogen model; Add the water molecules in batches. After each addition of the water molecules, use the grand canonical ensemble Monte Carlo method to simulate and process the system and reach the thermal equilibrium state, and then add the next batch of water molecules in the same mode until all the water molecules are added and the final thermal equilibrium state is reached to obtain a steady-state matrix model with a water molecule distribution conformation.

5. The quantitative evaluation method for the influence of formation water on the methane adsorption gas volume in shale reservoirs according to claim 4, characterized in that The method for determining the number of water molecules to be added to the kerogen model includes: The product of the number of kerogen units in the kerogen model and the molar mass of kerogen, divided by the molar mass of water and then multiplied by 0.01, is equal to the number of water molecules corresponding to 1% of the mass of the kerogen model; Calculate the total number of water molecules to be added according to 5% of the mass of the kerogen model.

6. The quantitative evaluation method for the influence of formation water on the methane adsorption gas volume in shale reservoirs according to claim 5, characterized in that The method for determining the thermal equilibrium state includes: Based on Newton's second law, use the Verlet algorithm to track the movement displacement and velocity of each atom at each time step, and calculate the energy difference generated between the current time step and the previous time step due to the movement of the atoms. The time step corresponding to when the energy difference is not higher than 2% is determined as the start of the thermal equilibrium state.

7. The quantitative evaluation method for the influence of formation water on methane adsorption gas volume in a shale reservoir according to claim 6, characterized in that: According to the grand canonical ensemble Monte Carlo method and molecular dynamics theory, insert the methane molecules into the steady-state matrix model.

8. The quantitative evaluation method for the influence of formation water on the methane adsorption gas volume in shale reservoirs according to claim 7, characterized in that, The method for inserting the methane molecules includes: Obtain the chemical potential energy of the target methane gas at different temperatures and pressures; During the process of inserting the methane molecules, judge the chemical potential energy of the system until the energy fluctuation range does not exceed 2%, and obtain the number of methane molecules inserted at the corresponding temperature and pressure.

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