A method for predicting sand production risk in a natural gas hydrate reservoir

Abstract

This patent discloses a method for predicting sand production risk in natural gas hydrate reservoir development, belonging to the field of marine oil and gas engineering technology. It can be used for predicting sand production risk in hydrate reservoirs, contributing to effective sand control and increased production capacity. Considering the changes in saturation and permeability caused by hydrate phase transitions, a mechanical model for predicting sand production risk is established based on the effective stress distribution around the well, shear, and failure criteria. The model considers the influence of different rock states, critical bottom hole pressure differential, saturation, permeability, and key mechanical parameters (cohesion and internal friction angle) on the sand production risk (F coefficient) of hydrate reservoir development. Based on the pore pressure change model, permeability change model, and critical bottom hole pressure differential model for hydrate reservoir development, a mechanical model for predicting sand production risk in hydrate reservoirs is finally established, achieving effective prediction of sand production risk in hydrate reservoir development.

Description

Technical Field

[0001] This invention belongs to the field of marine oil and gas engineering technology, specifically relating to a method for predicting sand production risk in natural gas hydrate reservoir development. Background Technology

[0002] Natural gas hydrate (NGH) is an ice-like, cage-like crystalline compound formed by the interaction of light gas and water under certain high pressure and low temperature conditions. It is characterized by its wide distribution, huge reserves, high energy density, and lack of pollution. However, sand production from hydrate reservoirs is a significant challenge when using depressurization, thermal injection, and chemical injection methods for hydrate extraction. Currently, hydrate production trials in projects worldwide, such as the Messiyakha gas field and the Ignik Sikumi, have almost all encountered sand production problems to varying degrees. Inducing hydrate decomposition through physicochemical methods is currently the most effective approach for hydrate extraction. While sand production is a necessary step in hydrate extraction, natural gas hydrates are typically not solidified into rocks and have a high content of fine silt. Furthermore, decomposition is accompanied by phase changes, which can easily lead to a decrease in the physical and mechanical properties of hydrate reservoirs. Therefore, sand production is unavoidable in hydrate development. When using depressurization extraction and other methods, the large production pressure differential further exacerbates the severity of sand production in hydrate reservoirs. Sand production not only causes a decrease in production and damage to downhole equipment and pipelines, but can even lead to the abandonment of production wells, severely restricting the development and utilization of hydrate resources. Therefore, it is essential to predict the risk of sand production in natural gas hydrate reservoirs, which is also a major challenge in the current development of offshore oil and gas resources.

[0003] Formation sand production is a complex phenomenon encompassing fluid flow, rock deformation, and failure. Its main mechanisms include tensile failure, shear failure, and particle transport. This process can be roughly divided into three key stages: First, the rock failure stage, where sand grains in the formation transform from skeletal sand to loose sand due to the destruction of the rock structure—a prerequisite for sand production; second, the migration stage of the loose sand; and finally, the expansion stage of the damaged area after sand production. Only when the formation undergoes these three stages will large-scale sand production occur. Therefore, a mechanical model for sand production in hydrate reservoirs is established, and sand production risk prediction is conducted. The key to this study is to first clarify the distribution of the stress field around the hydrate extraction well, while also considering the coupling relationship between hydrate phase changes and pore pressure field, permeability field, and formation strength characteristics. Based on this, sand production risk prediction can be carried out. To this end, a calculation model for the stress field around the well and the critical bottom hole pressure difference in natural gas hydrate depressurization extraction is established to predict sand production risk. This model is then applied to a hydrate reservoir in the Sea of ​​Japan to conduct a case study analysis of sand production during depressurization extraction of hydrates. The study analyzes the variation law of the critical bottom hole pressure difference, the influence of different saturation and permeability, and mechanical parameters on sand production risk, aiming to provide important theoretical support for sand production risk analysis of hydrate reservoirs.

[0004] This patent proposes a method for predicting sand production risk in natural gas hydrate reservoir development. It considers changes in relative permeability and saturation during hydrate development, and establishes a mechanical model for predicting sand production risk in natural gas hydrate reservoir development based on the effective stress distribution around the well, the Mogi-Coulomb failure criterion considering intermediate principal stress, and changes in liquid bridging force and drag force. The model is used to analyze sand production in hydrate reservoir development and calculate... The distribution of risk coefficients yields the radius of the critical sand-producing region, enabling accurate prediction of sand-producing risk in hydrate reservoirs. Summary of the Invention

[0005] To address the aforementioned shortcomings in existing technologies, this invention provides a method for predicting sand production risk in natural gas hydrate reservoirs. This method comprehensively considers the response characteristics of permeability, saturation, and formation pressure caused by phase changes after hydrate reservoir decomposition, overcoming the challenge that traditional hydrate sand production models cannot accurately predict the degree, distribution range, and key factors affecting sand production. Secondly, it enables rapid analysis of sand production through numerical simulation, while avoiding the high data interactivity and grid coordination requirements faced by commonly used thermodynamic and geotechnical mechanics software in numerical analysis. Furthermore, this sand production prediction mechanical model has high computational efficiency and good convergence, making it a good theoretical analysis tool for predicting sand production risk.

[0006] To achieve the above-mentioned objectives, the present invention adopts the following technical solution:

[0007] A method for predicting sand production risk in natural gas hydrate reservoir development is provided, which specifically includes the following steps: S1. Based on the reservoir characteristics, collect key sand production analysis data from the field and calculate the initial pore pressure and effective stress of the natural gas hydrate formation; S2. Relative permeability and saturation were obtained from the multiphase flow model of hydrate formations. The relationship between them exists; S3. Establish a well perimeter stress calculation model for natural gas hydrate reservoirs; S4. A critical bottom hole pressure differential model for hydrate reservoir development was established based on the sand production shear failure of natural gas hydrate reservoirs. S5. Calculate the tensile failure mechanical criteria for sand production in natural gas hydrate reservoirs caused by changes in liquid bridge force and drag force. S6. Iterate and solve the above model to obtain the sand production risk (F coefficient) of hydrate reservoir development, and then make a judgment on the sand production risk of hydrate reservoir.

[0008] Furthermore, in step S1, the model assumes steady flow within the finite-sized reservoir, with gas flow being linear unidirectional steady seepage, and uses the formation mean pressure. The formulas for calculating gas pressure and water pressure in the pores are as follows: (15) (16)

[0009] in, Indicates distance from well axis Gas pressure in the pores at a certain location, MPa; indicates the distance from the well axis. Water pressure in the pores at the location, MPa; Let be the distance from the boundary of a finite large reservoir to the well axis, in meters (m). The boundary distance representing a finite large reservoir is Fluid pressure at the location, MPa; Let be the reservoir thickness, in meters (m). The distance from the well axis is in meters (m). and Here are the flow rates of gas and water, respectively, in m³ / s; and Here, represents the viscosity of gas and water, respectively, in Pa·s; The absolute permeability is expressed in m². and ρa and ρb are the relative permeabilities of gas and water, respectively, and are dimensionless.

[0010] Furthermore, in step S1, considering the gas and water produced after the hydrate decomposition, the pore pressure is affected by both gas pressure and pore pressure, resulting in the following formula: (17)

[0011] Furthermore, step S2 uses the Brooks and Corey multiphase flow model for hydrate formations, assuming that the gas and liquid phases are immiscible and the porous medium is homogeneous and isotropic, to determine the relative permeability and saturation. The following relationship exists between them: (18) (19)

[0012] in, Expressed as residual gas saturation, % Expressed as residual water saturation, % The fitting coefficients are dimensionless.

[0013] Furthermore, step S3 considers the plastic deformation characteristics of hydrate sediments and selects the Mogi-Coulomb failure criterion for hydrate sand production prediction; this criterion is simplified to a coefficient... To represent the shear failure state, its expression is: (20)

[0014] Furthermore, among them, Cohesion, MPa; The internal friction angle is °; The stress is octahedral normal, MPa; For octahedral shear stress, MPa.

[0015] This coefficient The physical meaning is clear: This indicates that the rock micro-elements are intact and in a safe state, and the strata will not produce sand. This indicates that the rock has been sheared and broken, resulting in sand production in the strata. Larger is safer, and vice versa. The smaller the value, the more severe the shearing damage to the formation.

[0016] Furthermore, in step S3, after the hydrate reservoir is drilled through, the original formation stress equilibrium condition is broken, and the stress around the wellbore is redistributed. The stress is superimposed in the horizontal and vertical directions using elastic solutions to obtain the distance from the wellbore under the combined action of bottomhole pressure and in-situ stress. The stress distribution at the point is as follows: (twenty one) (twenty two) (twenty three) (twenty four) (25) (26)

[0017] in, Expressed as radial stress components around the well, in MPa; Expressed as the circumferential stress component around the well, in MPa; Expressed as the axial stress component around the well, in MPa; , , These are the wellbore shear stresses, in MPa; Expressed as the distance from the wellbore axis, in meters (m). Expressed as wellbore radius, in meters; Represented as the perimeter angle, in degrees; Expressed as Poisson's ratio, as a decimal; The bottom hole pressure is in MPa.

[0018] Furthermore, in step S3, considering the shear and tensile failure mechanics criteria for sand production in hydrate reservoirs, a sand production risk coefficient for natural gas hydrate reservoirs is established. Its expression is: (27)

[0019] This coefficient The physical meaning is: when At that time, the strata were stable and there was no risk of sand production; when This indicates that the rock has been damaged and there is a risk of sand production in the strata. The smaller the size, the higher the risk of sand production.

[0020] Furthermore, in step S4, the initial pore pressure and effective stress of the formation are first calculated, taking into account the changes in phase, physical properties and mechanical characteristics after hydrate decomposition, and the critical bottom hole pressure differential (CDP) and sand production risk coefficient of the hydrate reservoir are solved iteratively. and sand output radius To assess the risk of sand production. Attached Figure Description

[0021] Figure 1 This is a flowchart of the method.

[0022] Figure 2 Flowchart for the calculation of mechanical model for predicting sand production risk in hydrate reservoirs

[0023] Figure 3 Schematic diagram of sand production radius in hydrate reservoir

[0024] Figure 4 The relative permeability evolution curve during hydrate extraction

[0025] Figure 5 The variation of risk coefficient F with water saturation and permeability

[0026] Figure 6 The critical bottom hole pressure varies with cohesion.

[0027] Figure 7 The critical bottom hole pressure varies with the internal friction angle.

[0028] Figure 8 The variation of sand production radius with cohesion under different bottom hole pressures

[0029] Figure 9 The variation of sand production radius with internal friction angle under different bottom hole pressure differentials Specific implementation steps

[0030] Furthermore, the present invention provides an exemplary description of the technical solution through the following specific embodiments, which is intended to facilitate understanding and implementation of the present invention by those skilled in the art. It should be understood that the scope of protection of the present invention is not limited to the specific embodiments described, but is based on the technical solution defined in the claims. For those skilled in the art, any equivalent substitution, improvement or modification based on the technical solution of the present invention, as long as it does not depart from the inventive concept and scope of protection defined in the claims, shall fall within the scope of protection of the present invention.

[0031] As shown in the figure, a method for predicting sand production risk in natural gas hydrate reservoir development includes the following steps: S1. Calculate the initial pore pressure and effective stress of the formation using Bishop's effective stress theory; S2. Relative permeability and saturation were obtained from the Brooks and Corey multiphase flow model of hydrate formations. The relationship between them exists; S3. Establish a wellbore stress calculation model, and establish a critical bottom hole pressure differential model for hydrate reservoir exploitation based on the mechanical criteria of sand production shear failure and tensile failure in hydrate reservoirs. S4. Iterate and solve the above model to determine the risk of sand production in hydrate reservoirs;

[0032] The method for constructing a mechanical model for predicting sand production risk in natural gas hydrate reservoirs based on Bishop effective stress is as follows:

[0033] Step S1 assumes steady flow within the finite-sized reservoir during model establishment, with gas flow being linear unidirectional steady seepage. The formation mean pressure is used. The formulas for calculating gas and water pressure in the pores are as follows: (28) (29)

[0034] in, Indicates distance from well axis Gas pressure in the pores at a certain location, MPa; indicates the distance from the well axis. Water pressure in the pores at the location, MPa; Let be the distance from the boundary of a finite large reservoir to the well axis, in meters (m). The boundary distance representing a finite large reservoir is Fluid pressure at the location, MPa; Let be the reservoir thickness, in meters (m). The distance from the well axis is in meters (m). and Here are the flow rates of gas and water, respectively, in m³ / s; and Here, represents the viscosity of gas and water, respectively, in Pa·s; The absolute permeability is expressed in m². and ρa and ρb are the relative permeabilities of gas and water, respectively, and are dimensionless.

[0035] In step S1, considering the gas and water produced after the hydrate decomposition, the pore pressure is affected by both gas pressure and pore pressure, resulting in the following formula: (30)

[0036] Step S2 uses the Brooks and Corey multiphase flow model for hydrate formations, assuming that the gas and liquid phases are immiscible and the porous medium is homogeneous and isotropic, to determine the relative permeability and saturation. The following relationship exists between them: (31) (32)

[0037] in, Expressed as residual gas saturation, % Expressed as residual water saturation, % The fitting coefficients are dimensionless.

[0038] Step S3 considers the plastic deformation characteristics of hydrate sediments and selects the Mogi-Coulomb failure criterion, which considers the intermediate principal stress, to predict hydrate sand production; this criterion is then simplified using coefficients. To represent the shear failure state, its expression is: (33)

[0039] in, Cohesion, MPa; The internal friction angle is °; The stress is octahedral normal, MPa; For octahedral shear stress, MPa.

[0040] This coefficient The physical meaning is clear: This indicates that the rock micro-elements are intact and in a safe state, and the strata will not produce sand. This indicates that the rock has been sheared and broken, resulting in sand production in the strata. Larger is safer, and vice versa. The smaller the value, the more severe the shearing damage to the formation. [0041 In step S3, after the hydrate reservoir is drilled out, the original formation stress equilibrium condition is broken, and the stress around the wellbore is redistributed. The stress is superimposed in the horizontal and vertical directions using elastic solutions to obtain the distance from the wellbore under the combined action of bottom hole pressure and ground stress.] The stress distribution at the point is as follows: (34) (35) (36) (37) (38) (39)

[0041] in, Expressed as radial stress components around the well, in MPa; Expressed as the circumferential stress component around the well, in MPa; Expressed as the axial stress component around the well, in MPa; , , These are the wellbore shear stresses, in MPa; Expressed as the distance from the wellbore axis, in meters (m). Expressed as wellbore radius, in meters; Represented as the perimeter angle, in degrees; Expressed as Poisson's ratio, as a decimal; The bottom hole pressure is in MPa.

[0042] In step S4, considering the plastic deformation characteristics of hydrate sediments, the Mogi-Coulomb failure criterion based on intermediate principal stress is preferred for predicting hydrate sand production; this criterion is simplified to use a coefficient To represent the shear failure state, its expression is: (40)

[0043] in, Cohesion, MPa; The internal friction angle is °; The stress is octahedral normal, MPa; For octahedral shear stress, MPa.

[0044] This coefficient The physical meaning is clear: This indicates that the rock micro-elements are intact and in a safe state, and the strata will not produce sand. This indicates that the rock has been sheared and broken, resulting in sand production in the strata. Larger is safer, and vice versa. The smaller the value, the more severe the shearing damage to the formation.

[0045] In step S5, considering the shear and tensile failure mechanics criteria for sand production in hydrate reservoirs, a sand production risk coefficient for natural gas hydrate reservoirs is established. Its expression is: (41)

[0046] This coefficient The physical meaning is: when At that time, the strata were stable and there was no risk of sand production; when This indicates that the rock has been damaged and there is a risk of sand production in the strata. The smaller the size, the higher the risk of sand production.

[0047] In step S6, the initial pore pressure and effective stress of the formation are first calculated. Considering the changes in phase, physical properties and mechanical characteristics after hydrate decomposition, the critical bottom hole pressure differential (CDP) and the sand production risk coefficient of the hydrate reservoir are solved iteratively. and sand output radius To assess the risk of sand production.

[0048] In summary, this study constructs a mechanical model for predicting sand production risk in natural gas hydrate reservoirs based on Bishop effective stress, addressing the phase transition during hydrate extraction. It is necessary to consider the coupling relationship between hydrate phase changes and pore pressure field, permeability field, and formation strength characteristics. Firstly, a calculation model for the peri-well stress field and critical bottomhole pressure difference in depressurized natural gas hydrate extraction is established to predict sand production risk. This model is then applied to a hydrate reservoir in the Sea of ​​Japan for a case study analysis of sand production during depressurized hydrate extraction, analyzing the variation law of critical bottomhole pressure difference and the influence of different saturations, permeabilities, and mechanical parameters on sand production risk.

[0049] The mechanical model verification shows that the gas flow activity in the reservoir is greater than that of water. During the two-phase flow, the gas flow is dominant, but is affected by water. In the prediction and analysis of sand production risk in hydrate reservoirs, the changes in permeability and saturation need to be considered. The formation pressure first decreases and then increases with the increase of water saturation, while the F value first increases and then decreases. Both the formation pressure and the F value decrease with the increase of permeability.

[0050] As cohesion decreases, the cementation strength between sediment particles weakens, and the sand-producing radius increases. The smaller the cohesion, the greater the rate of increase in the sand-producing radius of the hydrate reservoir. As the internal friction angle decreases, the rock's ultimate storage energy increases, the sand-producing radius increases, and the rate of increase also increases. When the angle is less than 25°, there is a phenomenon of rapid expansion of the sand-producing range.

[0051] Analysis of actual cases revealed that the rock mechanical characteristics differ under different conditions (dry sandstone, pre-hydrate formation, hydrate-bearing, and post-hydrate decomposition), resulting in variations in the extent and degree of sand production from hydrate sediments. Therefore, adopting graded and classified sand control schemes for hydrate reservoirs is of great significance for the safe and efficient development of hydrates.

Claims

1. A method for predicting sand production risk in natural gas hydrate reservoir development, characterized in that, Includes the following steps: S1. Based on the reservoir characteristics, collect key sand production analysis data from the field and calculate the initial pore pressure and effective stress of the natural gas hydrate formation; S2. Relative permeability and saturation were obtained from the multiphase flow model of hydrate formations. The relationship between them exists; S3. Establish a well perimeter stress calculation model for natural gas hydrate reservoirs; S4. A critical bottom hole pressure differential model for hydrate reservoir development was established based on the sand production shear failure of natural gas hydrate reservoirs. S5. Calculate the tensile failure mechanical criteria of sand production in natural gas hydrate reservoirs caused by changes in liquid bridge force and drag force. S6. Iterate through the above model to obtain the sand production risk (F coefficient) of the hydrate reservoir, and then make a judgment on the sand production risk of the hydrate reservoir.

2. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 1 requires clarifying the stress field distribution around the hydrate production well, and simultaneously considering the coupling relationship between hydrate phase changes and pore pressure field, permeability field, and formation strength characteristics, characterized in that... Step S1 assumes steady flow within a finite reservoir during model establishment, with gas flow being linear unidirectional steady-state seepage. The formation mean pressure is used. The formulas for calculating gas and water pressure in the pores are as follows: （1） （2） in, Indicates distance from well axis Gas pressure in the pores at a certain location, MPa; indicates the distance from the well axis. Water pressure in the pores at the location, MPa; Let be the distance from the boundary of a finite large reservoir to the well axis, in meters (m). The boundary distance representing a finite large reservoir is Fluid pressure at the location, MPa; Let be the reservoir thickness, in meters (m). The distance from the well axis is in meters (m). and The flow rates of gas and water are respectively, in meters. 3 / s; and Here, represents the viscosity of gas and water, respectively, in Pa·s; m represents absolute penetration rate. 2 ; and ρa and ρb are the relative permeabilities of gas and water, respectively, and are dimensionless.

3. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 2, characterized in that, In step S1, considering the gas and water produced after the hydrate decomposition, the pore pressure is affected by both gas pressure and pore pressure, resulting in the following formula: （3）。 4. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 3, characterized in that, Step S2 uses the Brooks and Corey multiphase flow model for natural gas hydrate formations, assuming that the gas and liquid phases are immiscible and the porous medium is homogeneous and isotropic, to determine the relative permeability and saturation. The following relationship exists between them: （4） （5） in, Expressed as residual gas saturation, % Expressed as residual water saturation, % The fitting coefficients are dimensionless.

5. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 3, characterized in that, Step S3 considers the plastic deformation characteristics of hydrate sediments and preferably uses the Mogi-Coulomb failure criterion, which takes into account the intermediate principal stress, to predict hydrate sand production. This criterion is then simplified using coefficients. To represent the shear failure state, its expression is: （6） in, Cohesion, MPa; The internal friction angle is °; The stress is octahedral normal, MPa; For octahedral shear stress, MPa.

6. This coefficient The physical meaning is clear: This indicates that the rock micro-elements are intact and in a safe state, and the strata will not produce sand. This indicates that the rock has been sheared and damaged, resulting in sand production in the strata. Larger is safer, and vice versa. The smaller the value, the more severe the shearing damage to the formation.

7. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 5, characterized in that, In step S3, after the hydrate reservoir is drilled through, the original formation stress equilibrium condition is broken, and the stress around the wellbore is redistributed. Using elastic solutions, the stresses in the horizontal and vertical directions are superimposed to obtain the distance from the wellbore under the combined action of bottomhole pressure and in-situ stress. The stress distribution at the point is as follows: （8） （9） （10） （11） （11） （12） in, Expressed as radial stress components around the well, in MPa; Expressed as the circumferential stress component around the well, in MPa; Expressed as the axial stress component around the well, in MPa; , , These are the wellbore shear stresses, in MPa; Expressed as the distance from the wellbore axis, in meters (m). Expressed as wellbore radius, in meters; Represented as the perimeter angle, in degrees; It is expressed as Poisson's ratio, a decimal. The bottom hole pressure is in MPa.

8. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 6, characterized in that, In step S4, considering the plastic deformation characteristics of hydrate sediments, the Mogi-Coulomb failure criterion based on intermediate principal stress is preferred for predicting hydrate sand production. This criterion is simplified using coefficients. To represent the shear failure state, its expression is: （13） in, Cohesion, MPa; The internal friction angle is °; The stress is octahedral normal, MPa; For octahedral shear stress, MPa.

9. This coefficient The physical meaning is clear: This indicates that the rock micro-elements are intact and in a safe state, and the strata will not produce sand. This indicates that the rock has been sheared and damaged, resulting in sand production in the strata. Larger is safer, and vice versa. The smaller the value, the more severe the shearing damage to the formation.

10. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 7, characterized in that, In step S5, considering the shear and tensile failure mechanics criteria for sand production in hydrate reservoirs, a sand production risk coefficient for natural gas hydrate reservoirs is established. Its expression is: （14） This coefficient The physical meaning is: when At that time, the strata were stable and there was no risk of sand production; when This indicates that the rock has been damaged and there is a risk of sand production in the strata. The smaller the size, the higher the risk of sand production.

11. The method for predicting sand production risk in natural gas hydrate reservoir development according to claim 7, characterized in that, In step S6, the initial pore pressure and effective stress of the formation are first calculated. Considering the changes in phase, physical properties and mechanical characteristics after hydrate decomposition, the critical bottom hole pressure differential (CDP) and the sand production risk coefficient of the hydrate reservoir are solved iteratively. and sand output radius To assess the risk of sand production.

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