Simulation method and system for stimulation of natural gas hydrate reservoir throat reaming working fluid

Abstract

The application discloses a kind of natural gas hydrate reservoir throat reaming working fluid stimulation simulation methods, comprising: obtaining the basic parameters of natural gas hydrate reservoir, test production data and drilling and completion parameters;According to basic parameters, test production data and drilling and completion parameters, calculate natural gas hydrate reservoir damage, wherein, using damage coefficient and blockage ratio to represent damage size;According to damage coefficient and and blockage ratio representation, the damage degree of natural gas hydrate reservoir is classified, to determine whether it needs to carry out stimulation treatment;When needing to carry out stimulation treatment, the damage distribution of natural gas hydrate reservoir is represented using basic parameters, test production data and drilling and completion parameters;Establish the simulation prediction model of natural gas hydrate reservoir throat reaming working fluid stimulation value;Based on natural gas hydrate reservoir throat reaming working fluid stimulation target requirement, in combination with the damage distribution of natural gas hydrate reservoir, the construction parameters of natural gas hydrate reservoir are optimized according to simulation prediction model.

Description

Technical Field

[0001] This invention relates to the field of natural gas hydrate reservoir production enhancement technology, and in particular to a method and system for simulating production enhancement using a working fluid for throat clearing and pore enlargement in natural gas hydrate reservoirs. Background Technology

[0002] Natural gas hydrate is a crystalline substance formed under high pressure and low temperature conditions, consisting of the combination of natural gas and water molecules. It possesses enormous reserve potential and is considered an important resource for the future energy sector. However, the development and utilization of natural gas hydrate faces several challenges. Because the crystalline material of natural gas hydrate exists within the reservoir, when contaminants clog the gas flow channels in the reservoir pores and throats, gas flow decreases, thus affecting the extraction efficiency of natural gas hydrate. Throat-clearing and pore-enlarging working fluids are typically highly permeable liquids that can dissolve or disrupt hydrate crystals and reservoir blockages, restoring unobstructed gas flow channels and thereby increasing production.

[0003] Therefore, a production enhancement simulation method is needed before use to optimize the composition and dosage of the working fluid and construction conditions. Summary of the Invention

[0004] The main objective of this invention is to provide a method and system for simulating production enhancement using a throat-clearing and pore-expanding working fluid in natural gas hydrate reservoirs. Before using the throat-clearing and pore-expanding working fluid, a production enhancement simulation experiment is conducted to improve the accuracy and reliability of the simulation prediction and achieve a more effective production enhancement effect.

[0005] To achieve the above objectives, the present invention provides a method for simulating production enhancement using a working fluid for throat clearing and pore enlargement in natural gas hydrate reservoirs, comprising the following steps:

[0006] Step S1: Obtain basic parameters, test production data, and drilling and completion parameters of the natural gas hydrate reservoir;

[0007] Step S2: Calculate the damage to the natural gas hydrate reservoir based on the basic parameters, the test production data, and the drilling and completion parameters, wherein the damage coefficient and the plugging ratio are used to characterize the magnitude of the damage;

[0008] Step S3: Based on the damage coefficient and the blockage ratio, classify the degree of damage to the natural gas hydrate reservoir and determine whether production enhancement is necessary.

[0009] Step S4: When production enhancement is required, the damage distribution of the natural gas hydrate reservoir is characterized using the basic parameters, the test production data, and the drilling and completion parameters.

[0010] Step S5: Establish a simulation and prediction model for the production enhancement value of the working fluid used for throat opening and pore enlargement in the natural gas hydrate reservoir; and

[0011] Step S6: Based on the production target requirements of the working fluid for throat opening and pore enlargement in the natural gas hydrate reservoir, and combined with the damage distribution of the natural gas hydrate reservoir, optimize the construction parameters of the natural gas hydrate reservoir according to the simulation prediction model.

[0012] The present invention also provides a simulation system for increasing the production of a natural gas hydrate reservoir through a throat-clearing and pore-expanding working fluid, comprising a processor and a memory, wherein the memory stores a computer program, and when the computer program is executed by the processor, it implements the steps of the simulation method for increasing the production of a natural gas hydrate reservoir through a throat-clearing and pore-expanding working fluid as described above.

[0013] The present invention also provides a storage medium storing one or more programs, which can be executed by one or more processors to implement the steps of the simulation method for increasing production of natural gas hydrate reservoir throat opening and pore enlargement working fluid as described above.

[0014] The simulation system and method for enhancing production using throat clearing and reaming working fluid in natural gas hydrate reservoirs provided by this invention have the following beneficial effects: This invention obtains basic parameters, trial production data, and drilling and completion parameters of the natural gas hydrate reservoir, and comprehensively analyzes multiple key factors to gain a more comprehensive understanding of the reservoir's characteristics and condition; it uses damage coefficients and blockage ratios to characterize the extent of damage to the natural gas hydrate reservoir and classifies the degree of damage to help determine whether production enhancement measures are needed; when production enhancement is required, a numerical simulation prediction model for enhancing production using throat clearing and reaming working fluid in natural gas hydrate reservoirs is established; subsequently, based on the target requirements for enhancing production using throat clearing and reaming working fluid in natural gas hydrate reservoirs, combined with damage distribution and the simulation prediction model, the reservoir's construction parameters are optimized; this method helps improve construction efficiency and production enhancement effects, maximizes reservoir potential, and thus provides scientific decision-making basis and technical guidance, thereby improving the development efficiency and production enhancement effects of natural gas hydrate reservoirs. Attached Figure Description

[0015] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on the provided drawings without creative effort:

[0016] Figure 1 The diagram shows a flowchart of a method for simulating the production enhancement of a natural gas hydrate reservoir by using a throat-clearing and pore-enlarging working fluid, according to an embodiment of the present invention.

[0017] Figure 2 The image shows a physical model of the wellbore and formation.

[0018] Figure 3 The figure shows the physical model of the heat balance equation within the fluid injection unit inside the tubing.

[0019] Figure 4 The figure shows the physical model of the heat balance equation within the i-th unit.

[0020] Figure 5 The figure shows the three-dimensional distribution of wellbore temperature at different times;

[0021] Figure 6 The figure shows the physical model of formation temperature. Detailed Implementation

[0022] To facilitate understanding of the present invention, a more complete description will be given below with reference to the accompanying drawings. Typical embodiments of the invention are shown in the drawings. However, the invention can be implemented in many different forms and is not limited to the embodiments described herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete.

[0023] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains. The terminology used herein in the description of the invention is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention.

[0024] Figure 1 The diagram shows a flowchart of a method for simulating the production enhancement of a natural gas hydrate reservoir using a throat-clearing and pore-enlarging working fluid, according to an embodiment of the present invention. Figure 1 As shown, the simulation method for enhancing production using the working fluid for throat opening and perforation enlargement in natural gas hydrate reservoirs includes the following steps:

[0025] Step S1: Obtain basic parameters, test production data, and drilling and completion parameters of the natural gas hydrate reservoir;

[0026] Specifically, in one embodiment of the present invention, for the natural gas hydrate reservoir to be simulated, the basic parameters of the natural gas hydrate reservoir are first collected, such as reservoir location, thickness and depth; reservoir lithology and physical properties, such as porosity, permeability, compressibility coefficient, etc.; distribution, content and saturation of natural gas hydrates, etc. Then, a test production operation is carried out to collect test production data and drilling and completion parameters.

[0027] Step S2: Calculate the damage to the natural gas hydrate reservoir based on the basic parameters, the test production data, and the drilling and completion parameters, wherein the damage coefficient and the plugging ratio are used to characterize the magnitude of the damage;

[0028] Specifically, in one embodiment of the present invention, two commonly used parameters for evaluating the degree of reservoir damage are the skin coefficient S and the plugging ratio DR. The damage coefficient S and the plugging ratio DR... dThe calculation formula is as follows:

[0029]

[0030]

[0031] Where, k o r represents the original permeability of the reservoir. w k is the radius of the wellbore; d For damage penetration rate; r d h is the radius of the damage zone; h is the reservoir thickness; p For the perforation thickness; k H k represents the horizontal permeability of the reservoir. v The vertical permeability of the reservoir; l p D represents the penetration depth of the perforation; a and b are coefficients determined by the perforation phase angle; en For the hole is dense; r p S is the radius of the aperture; c Compaction damage coefficient; Q o Q represents the theoretical yield; d This represents the actual output.

[0032] In this embodiment, the skin coefficient S and the plugging ratio DR are used to characterize the degree of damage to natural gas hydrate reservoirs. These two parameters directly reflect the extent of damage to natural gas hydrate reservoirs, making it easier to understand changes in reservoir properties and production capacity decline. By comparing and analyzing the skin coefficient S and plugging ratio DR of different reservoirs or different extraction schemes, it is possible to quickly identify which reservoirs have suffered more severe damage, thus providing a basis for optimizing extraction schemes.

[0033] Step S3: Based on the damage coefficient and the blockage ratio, classify the degree of damage to the natural gas hydrate reservoir and determine whether production enhancement is necessary.

[0034] Specifically, in one embodiment of the present invention, the skin coefficient indicates that reservoir damage is related not only to a decrease in reservoir permeability but also to the depth of invasion. Therefore, the standard for evaluating the degree of reservoir damage is:

[0035] For porous reservoirs: if S>0 and D d If S = 0 and D > 1, then there is damage, and it is necessary to unblock the blockage and increase production; d =1, then there is no harm, and no need to unblock and increase production; if S<0 and D d If the value is less than 1, the reservoir will experience increased production.

[0036] For fractured reservoirs: if S>-3 and D d If S = -3 and D > 1, then there is damage, and it is necessary to unblock and increase production;d =1, then there is no harm, and no need to unblock and increase production; if S<-3 and D d If the value is less than 1, the reservoir will experience increased production.

[0037] Furthermore, if S is >0 to <2, it is considered minor injury; if S is 2 to <10, it is considered relatively serious injury; if S is ≥10, it is considered serious injury.

[0038] Step S4: When production enhancement is required, the damage distribution of the natural gas hydrate reservoir is characterized using the basic parameters, the test production data, and the drilling and completion parameters.

[0039] Specifically, in one embodiment of the present invention, when a suspended particle stream invades a porous medium, the suspended particles exhibit physical processes of being captured, released, retained, and transported by the pores under various forces. Simultaneously, the invading fluid displaces the formation fluid under the influence of movement and diffusion, forming localized blockages and thus reducing the matrix permeability of the invading area. Therefore, in step S4, reservoir permeability is used to characterize the damage distribution. The relationship between reservoir permeability k and the amount of particles captured σ brought or generated by the external fluid is:

[0040]

[0041] Where, k o (x,y,z,t) represents the reservoir permeability at point (x,y,z) at time t; k o (x,y,z) represents the original permeability of the reservoir at point (x,y,z); σ(x,y,z,t) represents the amount of particles captured at point (x,y,z) at time t; α represents the damage intensity coefficient; and x,y,z represents the three-dimensional spatial position in the Cartesian coordinate system centered on the wellbore.

[0042] Furthermore, the particle capture amount σ at any point and time near the well can be expressed as:

[0043]

[0044] Among them, V pw m is the volume concentration of the external fluid. 3 / s; A is the cross-sectional area of ​​the flow path, m² 2 ; Let c be the average flow velocity at point (x,y,z) at time t, in m / s; pw Let be the particle concentration in the external fluid at point (x,y,z) at time t, which is dimensionless.

[0045] Average flow rate It can be obtained from the following formula:

[0046]

[0047] The particle concentration distribution in an external fluid at any point and at any time can be expressed as:

[0048]

[0049] In the formula: φ is the reservoir porosity, dimensionless; U is the flow velocity vector, m / s; D L denoted as the diffusion coefficient of the external fluid, in m / s.

[0050] The damage distribution of the reservoir can be obtained using the above formulas (3) to (6).

[0051] Step S5: Establish a simulation and prediction model for the production increase value of the working fluid for throat opening and pore enlargement in the natural gas hydrate reservoir;

[0052] Specifically, in one embodiment of the present invention, during acidizing operations, reservoir temperature has a significant impact on the performance of the acid main agent and additives, as well as the acid-rock reaction rate. The simulation calculation of reservoir temperature requires wellbore temperature as an internal boundary condition for solution. Therefore, simulating wellbore temperature is crucial. Thus, in step S5, the simulation prediction model includes a wellbore temperature model. During acid injection, due to thermal differences between the injection fluid, casing, cement sheath, and formation, unstable heat transfer occurs between different materials during acid flow.

[0053] Injecting at a temperature of T on the ground inj Under certain conditions, fluid is pumped into the wellbore at a constant displacement Q. As the fluid flows through the tubing, convective heat transfer occurs radially between points in the formation, satisfying the heat balance equation: Heat flowing into the unit cell / unit time - Heat flowing out of the unit cell / unit time = Heat change within the unit cell / unit time. (See below) Figure 2 As shown, in the Z1 layer, in each unit cell radially upwards... Convection heat transfer occurs between them.

[0054] Figure 3 The figure shows the time at t n+1 The physical model of the heat balance equation within the unit body of the injected fluid in the tubing at any given time, and the heat flowing into the unit body from the side:

[0055]

[0056] Heat flowing into the unit from the top:

[0057] Heat flowing out of the bottom of the unit:

[0058] Heat change of the tubing unit per unit time:

[0059] According to the principle of heat balance equation: Heat flowing into the unit / unit time - Heat flowing out of the unit / unit time = Heat change within the unit / unit time. Therefore, the final heat balance equation for the injected fluid unit in the tubing can be written as:

[0060]

[0061] Where r0 is the inner radius of the tubing; ΔH j The height of the unit cell; λ1 represents the temperature at unit (1, j) and (0, j-1 / 2) at time n+1; C0 represents the specific heat of the acid solution; ρ0 represents the density of the acid solution; and Q represents the constant pumping rate of the liquid into the wellbore.

[0062] The i-th unit cell in segment j is as follows Figure 4 As shown. Heat flowing into the unit on the right:

[0063]

[0064] In the formula:

[0065]

[0066] Heat flowing out of the unit on the left:

[0067]

[0068] Change in heat within the i-th unit per unit time:

[0069]

[0070] According to the heat balance equation:

[0071]

[0072] When i = N-1, the above formula can be written as:

[0073]

[0074] In the formula: r i —Radial distance along the center of the oil pipe, in meters;

[0075] ΔH j —Unit height, m;

[0076] —Temperature at unit cell (i, j) at time n+1, in °C;

[0077] λ i — Thermal conductivity of the medium in the i-th unit cell, (kcal / (kg·℃));

[0078] C i —Specific heat of the medium liquid in the i-th unit, (kcal / (m·min·℃)).

[0079] The transient temperature distribution of the wellbore can be solved using equations (8), (13), and (14).

[0080] Furthermore, a central difference method is used spatially, and a forward difference method is used temporally. The transient distribution of wellbore temperature over time in a vertical well is simulated under a surface injection temperature of Tinj = 18℃, as well as the wellbore temperature distribution at the same time under different injection rates. For example... Figure 5 As shown, the initial wellbore temperature is positively correlated with the well depth; the greater the vertical depth, the higher the temperature. With a fixed injection rate, the wellbore temperature gradually decreases over time *a*, and this decreasing trend diminishes over longer periods. When injection is complete, the bottom hole temperature gradually approaches the surface injection temperature. Figure 5 As shown, injection rate is also one of the dominant factors in reducing wellbore temperature; the temperature decreases faster with increasing injection rate. Furthermore, at the same wellbore depth, a larger injection rate often leads to faster wellbore cooling. This is because a larger injection rate results in stronger convective heat transfer, leading to more rapid cooling of the wellbore.

[0081] Specifically, in one embodiment of the present invention, the rheological properties of the treatment fluid, the acid-rock reaction rate, and the performance of acid additives will all change due to the influence of formation temperature, thereby directly affecting the acidizing effect. Therefore, in order to improve the reliability and guidance of the acidizing design and make it more in line with actual production, the influence of formation temperature distribution must be considered. Therefore, in step S5, the simulation prediction model includes a formation temperature distribution model and a reservoir temperature model.

[0082] In this embodiment, the j-th vertically oriented stratum is taken as the target layer and used to calculate the transient distribution of reservoir temperature. The j-th stratum is divided into N segments radially upwards, and the i-th segment is taken as the research object. A numerical model of reservoir temperature is established, such as... Figure 6 As shown.

[0083] If the reservoir temperature change caused by the exothermic reaction of acid and rock is ignored, the heat exchange process of unit i is divided into two parts: one part is the heat exchange process between fluid and rock, and the other part is the heat exchange process within the unit.

[0084] (1) Heat exchange within the unit

[0085] The heat transferred to the unit on the left is:

[0086]

[0087] The heat transferred from the right-side unit is:

[0088]

[0089] (2) Heat exchange between fluid and rock

[0090] The heat flowing into the unit from the left side is:

[0091] ρ L v r rθHC L T (17)

[0092] The heat flowing out of the unit on the right is:

[0093]

[0094] (3) Heat change per unit time of unit cell

[0095]

[0096] From the heat balance equation, we get:

[0097]

[0098] In the formula: v w — Apparent flow velocity of the liquid at the well wall, m / min;

[0099] v r —Liquid inflow radial velocity, m / min;

[0100] T—Reservoir radial temperature, °C;

[0101] λ L — Thermal conductivity of the injected fluid, kcal / (m·min·℃);

[0102] C L —Specific heat of the injected liquid, kcal / (kg·℃);

[0103] λ r — Thermal conductivity of the strata rocks, kcal / (m·min·℃);

[0104] ρ r —Density of strata rocks, kg / m³ 3 ;

[0105] C r —Specific heat of strata rocks, kcal / (kg·℃);

[0106] H – Thickness of the acidified layer, in meters (m).

[0107] Equation (20) is the reservoir temperature field heat balance equation when the exothermic reaction of acid and rock is ignored. Equation (20) can be simplified to the following form:

[0108]

[0109] in:

[0110]

[0111] Considering the acid concentration distribution and the exothermic process of the acid-rock reaction, the increase in reservoir temperature caused by the exothermic reaction is as follows:

[0112]

[0113] The reservoir temperature can then be characterized as:

[0114]

[0115] In the formula: T j —The formation temperature during the exothermic acid-rock reaction is not considered, in °C.

[0116] Furthermore, during the acid injection process, the reaction between the acid and the rock minerals causes a change in porosity, i.e. It is a function of time and location. In equation (21), the coefficients A1 and B1 change linearly with porosity. Therefore, when solving the transient distribution of the formation temperature field, it is necessary to couple the acid concentration distribution model to obtain the correct result.

[0117] make:

[0118]

[0119] After dimensionless transformation of equation (21) and substitution of equation (24) into equation (21), the numerical calculation model of the dimensionless partial differential equation is as follows:

[0120]

[0121]

[0122] After performing central difference on equation (25), a numerical model is constructed:

[0123]

[0124] The numerical model is obtained through further simplification:

[0125]

[0126] In the formula:

[0127]

[0128]

[0129]

[0130]

[0131] Using the formation temperature gradient as the external boundary condition and the fluid temperature inside the tubing at different times as the internal boundary condition, the reservoir temperature model can be written in the form A·X=B through difference, transforming the equation into a problem of solving a tridiagonal system of equations. The matrix form of equation (28) is:

[0132]

[0133] The system of equations (28) constitutes a strictly diagonally dominant tridiagonal system of equations with a coefficient matrix, combined with Figure 6 The given physical model considers the temperature of the injected fluid in the tubing. As the internal boundary condition of the formation temperature field, formation temperature As its outer boundary condition.

[0134] At the input end, when i = 1, for equation (29):

[0135]

[0136] At the export end, when i = N, for equation (29):

[0137]

[0138] Specifically, in one embodiment of the present invention, acidification of hydrate reservoirs is a complex reaction process. Due to differences in reaction rates and specific surface areas, the PERM-A acid reaction rate is closely related to the rock and mineral type and physical properties. Assuming that mass transfer is much faster than acid flow (due to a larger Damkhler coefficient), the reaction process is closely related to temperature changes because temperature significantly affects the acid-rock reaction kinetic parameters. Furthermore, the acid-rock reaction is accompanied by the formation of new precipitates. These precipitates include Si(OH)4 and other types of precipitates, collectively referred to as silica gel precipitates.

[0139] In this embodiment, based on the molar concentration equilibrium principle of acid-rock reaction, the molar concentration equilibrium equations for PERM-A acid concentration, H2SiF6 acid concentration, fast-reaction mineral concentration, slow-reaction mineral concentration, and silica gel precipitate concentration can be derived respectively. The acid concentration model is characterized by the following formula:

[0140]

[0141]

[0142]

[0143]

[0144]

[0145] Among them, C A1 PERM-A acidity; C A2 The acidity of H2SiF6; C m1 For fast-reacting minerals; C m2 Slow-reacting minerality; C m3 t is the concentration of Si(OH)4; t is the injection time; r is the radial distance of the formation; V is the apparent velocity at r; T is the temperature field distribution of the acidized section at different times; R is the gas constant; R i E is the reaction rate constant. ai Activation energy; v i For solubility, i = 1, PERM-A acid with fast-reacting minerals; i = 2, PERM-A acid with slow-reacting minerals; i = 3, PERM-A acid with Si(OH)4; i = 4, H2SiF6 acid with fast-reacting minerals; σ ip The mass of H2SiF6 generated per unit mass of PERM-A acid consumed; The value represents the formation porosity. Furthermore, the implicit difference method is used to solve the equations, which exhibits unconditional convergence. Therefore, implicit forward differencing is used for the time grid, and implicit backward differencing is used for the spatial grid.

[0146] Specifically, in one embodiment of the present invention, during the acid-rock reaction process of acidification, the formation porosity changes as the formation rocks and minerals are continuously dissolved by the acid. Therefore, in step S5, the simulation prediction model includes a porosity and permeability model, wherein the formulas for calculating the porosity and permeability at unit i in the k-th segment at any time are as follows:

[0147]

[0148]

[0149] In the formula: k 0,k φ 0,k The initial permeability and porosity of the formation; The values ​​represent the permeability and porosity of the i-th unit cell in the k-th segment at time n+1 during acidification; L is an empirical index. Let be the concentration of mineral j in the i-th unit cell of the k-th segment at time n; Let be the concentration of mineral j in the i-th unit cell of the k-th segment at time n+1; Let be the concentration of silica gel mineral in the i-th unit cell of the k-th segment at time n; W represents the concentration of silica mineral in the i-th unit cell of the k-th segment at time n+1. j ρ is the average molar molecular weight of mineral j;j Let be the density of mineral j.

[0150] In this embodiment, damage calculations are performed on a single well using data obtained from well testing and logging. The calculation results are then extrapolated to the target acidizing zone and acidizing simulation is conducted. This allows for a more reasonable description of the radial distribution of porosity and permeability in the damaged formation. During the dynamic simulation of the acid-rock reaction, the transient distribution of porosity and permeability under these assumptions is closer to the actual situation, providing a more reasonable description of the dynamic reaction process and formation property changes during acidizing. The improved porosity and permeability index distribution provides a more accurate and reasonable description of the damaged zone. Furthermore, the simulation calculations are based on the influence of formation temperature changes (affected by both convective heat transfer during acid injection and exothermic reactions in the acid-rock reaction) on the acid-rock reaction rate, and the reduction in porosity caused by secondary precipitation during the acid-rock reaction. This results in more accurate calculations of the permeability enhancement factor and skin factor.

[0151] Step S6: Based on the production target requirements of the working fluid for throat opening and pore enlargement in the natural gas hydrate reservoir, and combined with the damage distribution of the natural gas hydrate reservoir, optimize the construction parameters of the natural gas hydrate reservoir according to the simulation prediction model.

[0152] Specifically, in one embodiment of the present invention, based on the production target requirements of the working fluid for venting and expanding the pores in the natural gas hydrate reservoir, and combined with the reservoir damage distribution, step S5 is used to simulate and optimize the design of the discharge rate and acid injection intensity.

[0153] This invention also provides a simulation system for enhancing the production of natural gas hydrate reservoirs using a throat-clearing and pore-enlarging working fluid, which may include:

[0154] Memory, used to store computer programs;

[0155] When a processor executes a computer program stored in the aforementioned memory, it can perform the following steps:

[0156] Acquire basic parameters, test production data, and drilling and completion parameters of the natural gas hydrate reservoir; calculate the damage to the natural gas hydrate reservoir based on the basic parameters, test production data, and drilling and completion parameters, wherein the damage magnitude is characterized by a damage coefficient and a blockage ratio; classify the degree of damage to the natural gas hydrate reservoir based on the damage coefficient and the blockage ratio to determine whether production enhancement is necessary; when production enhancement is necessary, characterize the damage distribution of the natural gas hydrate reservoir using the basic parameters, test production data, and drilling and completion parameters; establish a simulation prediction model for the production enhancement value of the throat clearing and reaming working fluid for the natural gas hydrate reservoir; based on the production enhancement target requirements of the throat clearing and reaming working fluid for the natural gas hydrate reservoir, and combined with the damage distribution of the natural gas hydrate reservoir, optimize the construction parameters of the natural gas hydrate reservoir according to the simulation prediction model.

[0157] This invention also provides a computer-readable storage medium storing a computer program, which, when executed by a processor, can perform the following steps;

[0158] Acquire basic parameters, test production data, and drilling and completion parameters of the natural gas hydrate reservoir; calculate the damage to the natural gas hydrate reservoir based on the basic parameters, test production data, and drilling and completion parameters, wherein the damage magnitude is characterized by a damage coefficient and a blockage ratio; classify the degree of damage to the natural gas hydrate reservoir based on the damage coefficient and the blockage ratio to determine whether production enhancement is necessary; when production enhancement is necessary, characterize the damage distribution of the natural gas hydrate reservoir using the basic parameters, test production data, and drilling and completion parameters; establish a simulation prediction model for the production enhancement value of the throat clearing and reaming working fluid for the natural gas hydrate reservoir; based on the production enhancement target requirements of the throat clearing and reaming working fluid for the natural gas hydrate reservoir, and combined with the damage distribution of the natural gas hydrate reservoir, optimize the construction parameters of the natural gas hydrate reservoir according to the simulation prediction model.

[0159] The computer-readable storage medium may include various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM) > random access memory (RAM), magnetic disks, or optical disks.

[0160] Numerous specific details are set forth in the specification provided herein. However, it will be understood that embodiments of the invention may be practiced without these specific details. In some instances, well-known methods, structures, and techniques have not been shown in detail so as not to obscure the understanding of this specification.

[0161] Similarly, it should be understood that, in order to simplify this disclosure and aid in understanding one or more of the various aspects of the invention, in the above description of exemplary embodiments of the invention, various features of the invention are sometimes grouped together in a single embodiment, figure, or description thereof. However, this method of disclosure should not be construed as reflecting an intention that the claimed invention requires more features than are expressly recited in each claim. Rather, as reflected in the following claims, inventive aspects lie in fewer than all features of a single foregoing disclosed embodiment. Therefore, the claims following the detailed description are hereby expressly incorporated into this detailed description, wherein each claim itself is a separate embodiment of the invention.

[0162] Those skilled in the art will understand that modules in the device of the embodiments can be adaptively changed and placed in one or more devices different from that embodiment. Modules, units, or components in the embodiments can be combined into a single module, unit, or component, and further, they can be divided into multiple sub-modules, sub-units, or sub-components. Except where at least some of such features and / or processes or units are mutually exclusive, any combination can be used to combine all features disclosed in this specification (including the accompanying claims, abstract, and drawings) and all processes or units of any method or device so disclosed. Unless expressly stated otherwise, each feature disclosed in this specification (including the accompanying claims, abstract, and drawings) may be replaced by an alternative feature that serves the same, equivalent, or similar purpose.

[0163] Furthermore, those skilled in the art will understand that although some embodiments herein include certain features included in other embodiments but not others, combinations of features from different embodiments are intended to be within the scope of the invention and form different embodiments. For example, in the following claims, any of the claimed embodiments can be used in any combination.

[0164] The various component embodiments of the present invention can be implemented in hardware, or as software modules running on one or more processors, or a combination thereof. Those skilled in the art will understand that microprocessors or digital signal processors (DSPs) can be used in practice to implement some or all of the functions of some or all of the components according to the embodiments of the present invention. The present invention can also be implemented as a device or apparatus program (e.g., a computer program and computer program product) for performing part or all of the methods described herein. Such programs implementing the present invention can be stored on a computer-readable medium, or can be in the form of one or more signals. Such signals can be downloaded from an Internet website, provided on a carrier signal, or provided in any other form.

[0165] It should be noted that the above embodiments are illustrative of the invention and not restrictive, and that those skilled in the art can devise alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses should not be construed as limiting the claims. The word "comprising" does not exclude the presence of elements or steps not listed in the claims. The word "a" or "an" preceding an element does not exclude the presence of a plurality of such elements. The invention can be implemented by means of hardware comprising several different elements and by means of a suitably programmed computer. In the unit claims enumerating several means, several of these means may be embodied by the same item of hardware. The use of the words first, second, and third, etc., does not indicate any order. These words can be interpreted as names.

Claims

1. A method for simulating production enhancement using a working fluid for throat opening and pore enlargement in natural gas hydrate reservoirs, characterized in that, Includes the following steps: Step S1: Obtain basic parameters, test production data, and drilling and completion parameters of the natural gas hydrate reservoir; Step S2: Calculate the damage to the natural gas hydrate reservoir based on the basic parameters, the test production data, and the drilling and completion parameters, wherein the damage coefficient and the plugging ratio are used to characterize the magnitude of the damage; Step S3: Based on the damage coefficient and the blockage ratio, classify the degree of damage to the natural gas hydrate reservoir and determine whether production enhancement is necessary. Step S4: When production enhancement is required, the damage distribution of the natural gas hydrate reservoir is characterized using the basic parameters, the test production data, and the drilling and completion parameters. Step S5: Establish a simulation and prediction model for the production enhancement value of the working fluid used for throat opening and pore enlargement in the natural gas hydrate reservoir; and Step S6: Based on the production target requirements of the working fluid for throat opening and pore enlargement in the natural gas hydrate reservoir, and combined with the damage distribution of the natural gas hydrate reservoir, optimize the construction parameters of the natural gas hydrate reservoir according to the simulation prediction model; In step S2, the formulas for calculating the damage coefficient S and the blockage ratio Dd are as follows: (1) (2) Wherein, ko is the original reservoir permeability; rw is the wellbore radius; kd is the permeability of the damaged zone; rd is the radius of the damaged zone; h is the reservoir thickness; hp is the perforation thickness; kH is the horizontal permeability of the reservoir; kv is the vertical permeability of the reservoir; lp is the perforation penetration depth; a and b are coefficients determined by the perforation phase angle; Den is the porosity; rp is the perforation radius; Sc is the compaction damage coefficient; Qo is the theoretical production rate; and Qd is the actual production rate. In step S3, For porous reservoirs: if S>0 and Dd>1, there is damage and unblocking is required to increase production; if S = 0 and Dd = 1, there is no damage and no unblocking is required to increase production; if S<0 and Dd<1, the reservoir will increase production. For fractured reservoirs: if S > -3 and Dd > 1, there is damage and it is necessary to unplug and increase production; if S = -3 and Dd = 1, there is no damage and it is not necessary to unplug and increase production; if S < -3 and Dd < 1, the reservoir will increase production.

2. The method for simulating increased production of natural gas hydrate reservoirs using a throat-clearing and pore-enlarging working fluid as described in claim 1, characterized in that, In step S4, reservoir permeability is used to characterize the damage distribution. The relationship between reservoir permeability k and the amount of particulates captured by the external fluid, σ, is as follows: (3) Where ko(x, y, z, t) is the reservoir permeability at point (x, y, z) at time t; ko(x, y, z) is the original reservoir permeability at point (x, y, z); σ(x, y, z, t) is the particle capture amount at point (x, y, z) at time t; α is the damage intensity coefficient; and x, y, z are the three-dimensional spatial positions in the Cartesian coordinate system centered on the wellbore.

3. The method for simulating increased production of natural gas hydrate reservoirs using a throat-clearing and pore-enlarging working fluid as described in claim 2, characterized in that... In step S5, the simulation prediction model includes a wellbore temperature model, which is represented by the thermal balance equation of the injected fluid unit in the wellbore tubing.

4. The method for simulating increased production of natural gas hydrate reservoirs using a throat-clearing and pore-enlarging working fluid as described in claim 3, characterized in that, In step S5, the simulation prediction model includes a formation temperature distribution model, which is expressed by the formation temperature field heat balance equation.

5. The method for simulating increased production of natural gas hydrate reservoirs using a throat-clearing and pore-enlarging working fluid as described in claim 4, characterized in that... In step S5, the simulation prediction model includes a reservoir temperature model.

6. The method for simulating increased production of natural gas hydrate reservoirs using a throat-clearing and pore-enlarging working fluid as described in claim 5, characterized in that... In step S5, the simulation prediction model includes an acid concentration model.

7. The method for simulating increased production of natural gas hydrate reservoirs using a throat-clearing and pore-enlarging working fluid as described in claim 6, characterized in that... In step S5, the simulation prediction model includes porosity and permeability models.

8. A simulation system for increasing production of natural gas hydrate reservoirs using a working fluid for throat clearing and pore enlargement, characterized in that, It includes a processor and a memory, the memory storing a computer program that, when executed by the processor, implements the steps of the simulation method for increasing production of a natural gas hydrate reservoir through a throat-clearing and pore-expanding working fluid as described in any one of claims 1 to 7.

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