Method and device for determining technical limit well spacing of hydrocarbon gas flooding in low permeability reservoir

Abstract

The present application relates to a kind of low permeability reservoir hydrocarbon gas drive technical limit well spacing determination method and device, wherein, method includes the following steps: obtaining the basic parameter of target reservoir;Establish low permeability reservoir hydrocarbon gas drive percolation physical model;On the basis of the basic parameter of target reservoir and physical model, establish low permeability reservoir hydrocarbon gas drive percolation mathematical model;Solve the low permeability reservoir hydrocarbon gas drive percolation mathematical model, obtain the limit well spacing under corresponding condition.The present application can provide technical support for realizing more efficient, economic reservoir development.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, specifically to a method and apparatus for determining the ultimate well spacing in hydrocarbon gas drive technology for low-permeability reservoirs. Background Technology

[0002] Low-permeability reservoirs present numerous challenges to oil and gas development due to their unique geological characteristics, such as low porosity and low permeability. Determining well spacing is a crucial factor in the development of low-permeability reservoirs, directly impacting development efficiency and economic benefits. Traditional reservoir development often relies on empirical formulas and simplified models to determine well spacing, but the applicability of these methods in low-permeability reservoirs is limited, especially in enhanced oil recovery technologies like hydrocarbon flooding, where optimizing well spacing is particularly important.

[0003] Hydrocarbon gas flooding, as an effective method for enhancing oil recovery, improves reservoir flow conditions by injecting hydrocarbon gases, thereby increasing oil recovery. However, due to the often-exertion pressure gradient in low-permeability reservoirs, there is a theoretical maximum value for the injection-production well spacing, known as the limiting well spacing. The main approaches to enhancing oil recovery through hydrocarbon gas flooding include: reducing interfacial tension through miscibility, reducing crude oil viscosity through dissolution, and extracting crude oil with gas. The most important approach is reducing interfacial tension through miscibility.

[0004] Because hydrocarbon-gas flooding in domestic reservoirs generally has a high minimum miscibility pressure, making it difficult to achieve miscibility under reservoir conditions, near-miscible flooding is often used for reservoir development. Although oil-gas interfacial tension exists under near-miscible conditions, it is very low and still has a good effect on improving oil recovery. However, there is currently no clear conclusion on the scope of near-miscible hydrocarbon flooding, and research on the limiting well spacing for near-miscible flooding is relatively lacking. Therefore, exploring a method for calculating the limiting well spacing for hydrocarbon-gas flooding in low-permeability reservoirs under near-miscible conditions is of great significance for the efficient development of low-permeability reservoirs.

[0005] Currently, the methods for calculating the ultimate well spacing for hydrocarbon-gas drive in low-permeability reservoirs can be broadly classified into two categories: determining the ultimate well spacing by calculating the inter-well pressure distribution using reservoir engineering methods; and determining the ultimate well spacing by calculating the inter-well pressure distribution using numerical simulation methods. The former requires fewer parameters and is relatively simple to calculate, but due to the use of numerous assumptions, the results are not very accurate; the latter requires more parameters and has a more complex solution process, but the results are more accurate.

[0006] To fully utilize the crude oil in the formation, the well spacing needs to be reduced, but an overly dense well network increases development costs. To address this contradiction, the limit well spacing must be calculated before drilling injection and production wells in the oilfield to provide a reference for pre-drilling well spacing design. Otherwise, it may affect the future development effect of the oilfield. Therefore, it is urgent to establish a calculation method for the limit well spacing of low-permeability reservoirs. Summary of the Invention

[0007] To address the aforementioned problems, the purpose of this invention is to provide a method and apparatus for determining the limiting well spacing in hydrocarbon gas drive technology for low-permeability reservoirs, which can provide technical support for achieving more efficient and economical reservoir development.

[0008] To achieve the above objectives, the present invention adopts the following technical solution:

[0009] The method for determining the limiting well spacing in low-permeability reservoir hydrocarbon gas drive technology according to the present invention includes the following steps:

[0010] Obtain the basic parameters of the target reservoir;

[0011] Establish a physical model for hydrocarbon gas drive seepage in low-permeability oil reservoirs;

[0012] Based on the basic parameters and physical model of the target reservoir, a mathematical model of hydrocarbon gas drive seepage in low-permeability oil reservoirs is established.

[0013] Solve the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir to obtain the limiting well spacing under the corresponding conditions.

[0014] The determination method, preferably, includes the following basic parameters of the target reservoir:

[0015] Crude oil viscosity μ o Viscosity of water (μ) w Reservoir permeability k, reservoir porosity φ, bound water saturation S wc , seepage cross-sectional area A, injection rate q, production time T, original reservoir pressure P i Injection well pressure P in Production well pressure P out The original pressure P of the reservoir r Oil-water and oil-gas phase permeation curves of the reservoir.

[0016] The determination method, preferably, includes establishing a physical model for hydrocarbon gas drive seepage in low-permeability reservoirs, which includes:

[0017] For a single injection and extraction process in an infinitely large formation, the entire seepage zone is divided into four parts based on the changes in fluid properties during the hydrocarbon displacement process: pure gas seepage zone, oil-gas miscible zone, oil-gas near-miscible zone, and pure oil seepage zone. The seepage zone is divided according to the pressure distribution and hydrocarbon concentration changes during the hydrocarbon displacement process.

[0018] The determination method, preferably, involves the formation process of the four parts as follows: as gas injection proceeds, the pressure near the injection well increases, and the hydrocarbon displacement front undergoes dissolution and extraction with the crude oil, resulting in dynamic miscibility; as the distance increases, the pressure in the area away from the injection well decreases, and when the pressure drops to about 0.8 times the minimum miscibility pressure, a near-miscible zone is formed; as time progresses, the length of the miscible zone or near-miscible zone gradually increases, and its position also moves forward at a certain speed, forming a pure gas seepage zone behind it and a pure oil seepage zone in front of it.

[0019] The determination method, preferably, includes establishing a mathematical model for hydrocarbon gas drive seepage in low-permeability reservoirs, which includes:

[0020] Assuming the reservoir is a low-permeability heterogeneous oil reservoir, the seepage conforms to the two-phase isothermal non-Darcy flow of oil and gas, the seepage model is a one-dimensional radial flow model, the formation pressure is higher than the bubble point pressure but lower than the minimum miscibility pressure, the viscosity reduction effect of hydrocarbon gas on crude oil is considered, the change of the oil phase initiation pressure gradient is considered, and the dissolution, ion mass transfer and adsorption of gas and oil layer are considered during the hydrocarbon gas displacement process to establish a one-dimensional convection-diffusion equation.

[0021] Assuming the injected gas composition is constant and is pure CH4; the oil phase start-up pressure gradient G is regressed using experimental data from the start-up pressure gradient of the mine core. o The viscosity of the oil-gas mixture within the miscible swept zone was determined to be μ. mix Based on core displacement experimental data from the mine, the front discrimination conditions for different facies zones were determined, and the starting pressure gradient of the oil-gas mixture in the miscible zone was corrected to G. mix ;

[0022] The pure gas seepage zone, the oil-gas mixed zone, and the pure oil seepage zone belong to the single-phase seepage stage, where the fluid viscosity and starting pressure gradient change. The single-phase seepage equation is used to describe the seepage process in this stage.

[0023] In the near-miscible region of oil and gas, since crude oil and injected gas are no longer miscible during the near-miscible seepage process, the calculation method of two-phase seepage of oil and gas is used to calculate the seepage resistance.

[0024] Under the assumed conditions, the one-dimensional convection-diffusion equation is:

[0025]

[0026] The boundary conditions are:

[0027] C(x,0)=0,0≤x<∞ (2)

[0028] C(0,t)=C0, C(∞,)=0,0<t<∞ (3)

[0029] Using the Laplace transform, the analytical solution to the one-dimensional convection-diffusion equation can be obtained as follows:

[0030]

[0031] in:

[0032]

[0033] Once the CH4 concentration distribution is known, the density of the oil-gas mixture can be calculated using the following empirical formula, and the corresponding starting pressure gradient can be corrected accordingly:

[0034]

[0035]

[0036] In the above formula, μ mix Viscosity of the oil-gas mixture; μ o and μ g denoted as oil phase viscosity and gas phase viscosity, respectively; C is methane concentration; G is the starting pressure gradient; a and n are undetermined constants; and k is reservoir permeability.

[0037] The determination method, preferably, includes solving the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir, comprising:

[0038] Calculate the pressure difference loss and length change within the pure gas seepage zone:

[0039] The length of the pure gas permeation zone is:

[0040]

[0041] In the formula, r1 is the distance between the boundary of the pure gas seepage zone and the injection well, r0 is the wellhead radius, Q is the gas injection rate, h is the reservoir thickness, and t is the time. Porosity;

[0042] The pressure distribution within the pure gas seepage zone is as follows:

[0043]

[0044] Pressure difference ΔP consumed g for:

[0045]

[0046] In the formula, Q is the gas injection rate; μ is the gas viscosity; r is the distance from the injection well; k is the reservoir permeability; and h is the reservoir thickness.

[0047] Calculate the CH4 concentration distribution, pressure drop, and length variation within the miscible region:

[0048] The CH4 concentration in the miscible region decreases continuously, while the viscosity of the oil-gas mixture and the oil phase initiation pressure gradient increase continuously. The miscible region is divided into n grids. Considering that the fluid properties in each grid are consistent, the CH4 concentration, crude oil viscosity, and oil phase initiation pressure gradient in each grid are calculated using equations (4), (6), and (7), respectively.

[0049] Assuming a time step of Δt and a distance step of Δx, the distance step is increased cyclically until the reservoir pressure drops to the minimum miscibility pressure or the grid CH4 concentration drops to the frontal concentration C. f The calculation stops; the total grid length at which the calculation stops is the length of the mixed region at different times (r2-r1)=ΣΔx, and the migration time T=ΣΔt; where r2=ΣΔx+r1;

[0050] The pressure gradient is:

[0051]

[0052] Pressure difference ΔP consumed mix for:

[0053]

[0054] In the formula, ΔP mix The pressure difference consumed in the miscible region; G mix To initiate the pressure gradient in the corrected miscible region;

[0055] Calculate the CH4 concentration distribution, pressure drop, and length variation within the near-miscible region:

[0056] The CH4 concentration distribution characteristics and calculation methods in the near-miscible region are exactly the same as those in the miscible region, but the methods for determining the pressure drop loss and interval length are different; assuming the time step is Δt and the distance step is Δx, the distance step is cyclically increased until the reservoir pressure drops to 0.8 times the minimum miscibility pressure or the grid CH4 concentration drops to the frontal concentration C. f The near-mixed region length (r3-r2) = ΣΔx and the transport time T = ΣΔt were calculated at different times; where r3 = ΣΔx + r2.

[0057] The pressure difference loss in the near-miscible zone is calculated using the non-piston displacement two-phase flow resistance calculation method; given the relative permeability data of the reservoir, and ignoring the effects of gravity and capillary force, the coefficients a and b in the formula are calculated graphically.

[0058]

[0059] The above equation can also be expressed by the polynomial μ. r ω o =A+Bz+Cz 2 An approximate expression is used to calculate the pressure difference consumed by the two-phase flow in the near-miscible section;

[0060] Pressure difference ΔP consumed in the near-miscible region mixo for:

[0061]

[0062] In the formula, A, B, and C are all constants, derived from the polynomial μ. r ω o =A+Bz+Cz 2 Fitting μ r ω o The relationship curve between z and z is obtained; z f =1-S w -S or S w Water saturation; S or Residual oil saturation; μ r The oil-water viscosity ratio, μ o Crude oil viscosity; μ w ω is the viscosity of water; o For intermediate parameters, k rw k ro These are the relative permeability under bound water conditions and the relative permeability under residual oil conditions, respectively.

[0063] Calculate the pressure difference loss and length change within the pure oil seepage zone:

[0064] The pressure distribution in the pure oil zone is as follows:

[0065]

[0066] Pressure difference ΔP o for:

[0067]

[0068] The length r4 of the pure oil zone, which is also the oil drainage radius of the pure oil zone, is:

[0069]

[0070] In the formula P is the mean formation pressure. wf For the bottom-hole flowing pressure of the production well; μ o Where is the oil phase viscosity; k is the reservoir permeability;

[0071] q represents the injection speed.

[0072] Preferably, the limiting well spacing is determined in the following manner:

[0073] Let r1 be the location of the pure gas seepage zone front, r2 be the location of the miscible zone front, r3 be the location of the near-miscible zone front, and r4 be the location of the pure oil zone front. Let L be the actual well spacing. When L = r1 + r2 + r3 + r4, the pressure at the point where the miscible front and the pure oil zone meet exactly reaches the formation mean pressure P. ε When the pressure fronts of the two meet, L is the limit well spacing under the set production rate, and the boundary between the two seepage zones is the hydrocarbon drive wave front.

[0074] The device for determining the ultimate well spacing in low-permeability reservoir hydrocarbon gas drive technology according to the present invention includes:

[0075] The first processing unit is used to obtain the basic parameters of the target reservoir;

[0076] The second processing unit is used to establish a physical model of hydrocarbon gas drive seepage in low-permeability reservoirs.

[0077] The third processing unit is used to establish a mathematical model of hydrocarbon gas drive seepage in low-permeability reservoirs based on the basic parameters and physical model of the target reservoir.

[0078] The fourth processing unit is used to solve the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir and obtain the limiting well spacing under the corresponding conditions.

[0079] The present invention also provides a computer storage medium storing a computer program thereon, wherein the computer program, when executed by a processor, implements the steps of the method for determining the ultimate well spacing of the hydrocarbon gas drive technology in low-permeability reservoirs.

[0080] The present invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the method steps for determining the limit well spacing of the hydrocarbon gas drive technology in low-permeability reservoirs.

[0081] The present invention has the following advantages due to the adoption of the above technical solutions:

[0082] This invention comprehensively considers the special geological characteristics of low-permeability reservoirs, as well as the flow characteristics and distribution patterns of hydrocarbons and gases in the reservoirs. It also takes into account the characteristics of hydrocarbon gas drive implementation in the field. By accurately solving the change in methane concentration through the mass transfer-adsorption equation and correcting the crude oil viscosity and start-up pressure gradient, and by describing the displacement characteristics of different phase segments in segments, a rapid and accurate method for calculating the limit well spacing of hydrocarbon gas miscible / near-miscible drive technology in low-permeability reservoirs is obtained. Attached Figure Description

[0083] Various other advantages and benefits will become apparent to those skilled in the art upon reading the following detailed description of preferred embodiments. The accompanying drawings are for illustrative purposes only and are not intended to limit the invention. Throughout the drawings, the same reference numerals denote the same parts. In the drawings:

[0084] Figure 1 This is a flowchart of the extreme well spacing calculation method in this invention;

[0085] Figure 2 This is a schematic diagram of the physical model of the ultimate well spacing in this invention;

[0086] Figure 3 This is a dimensionless mass concentration distribution diagram of methane in the miscible and near-miscible regions in an embodiment of the present invention;

[0087] Figure 4 f is an embodiment of the present invention o -z relationship curve;

[0088] Figure 5 This is a diagram showing the limiting well spacing under different initial crude oil viscosities in an embodiment of the present invention;

[0089] Figure 6 This is a diagram showing the limiting well spacing under different gas injection rates in an embodiment of the present invention;

[0090] Figure 7 This is a diagram showing the limiting well spacing under different reservoir permeability in the embodiments of the present invention;

[0091] Figure 8 This is a diagram showing the limiting well spacing under different production pressure differentials in an embodiment of the present invention; Detailed Implementation

[0092] Exemplary embodiments of the invention will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the invention are shown in the drawings, it should be understood that the invention can be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided to enable a more thorough understanding of the invention and to fully convey the scope of the invention to those skilled in the art.

[0093] This invention provides a method for determining the limiting well spacing in hydrocarbon gas drive technology for low-permeability reservoirs. Addressing the need to comprehensively consider the unique geological characteristics of low-permeability reservoirs, as well as the flow characteristics and distribution patterns of hydrocarbons within the reservoir, this method uses the mass transfer-adsorption-diffusion equation to accurately solve for changes in hydrocarbon concentration and corrects for crude oil viscosity and starting pressure gradient. This results in a rapid and accurate method for calculating the limiting well spacing in hydrocarbon gas drive technology for low-permeability reservoirs, providing technical support for more efficient and economical reservoir development.

[0094] like Figure 1 As shown, the method for determining the limiting well spacing in low-permeability reservoir hydrocarbon gas drive technology provided by the present invention includes the following steps:

[0095] (1) Obtain the basic parameters of the target reservoir;

[0096] (2) Establish a physical model of hydrocarbon gas drive seepage in low-permeability reservoirs;

[0097] (3) Based on the basic parameters and physical model of the target reservoir, establish a mathematical model of hydrocarbon gas drive seepage in low-permeability reservoirs;

[0098] (4) Solve the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir to obtain the limit well spacing under the corresponding conditions.

[0099] In the above embodiments, preferably, the basic parameters of the target reservoir include: crude oil viscosity μ. o Viscosity of water (μ) w Reservoir permeability k, reservoir porosity φ, bound water saturation S wc , seepage cross-sectional area A, injection rate q, production time T, original reservoir pressure P i Injection well pressure P in Production well pressure P out The original pressure P of the reservoir r Oil-water and oil-gas phase permeation curves of the reservoir.

[0100] In the above embodiments, preferably, as follows: Figure 2 As shown, the establishment of the physical model for hydrocarbon gas drive seepage in low-permeability reservoirs includes:

[0101] For a single injection and production process in an infinitely large formation, based on the changes in fluid properties during hydrocarbon displacement, the entire seepage region is divided into four parts: a pure gas seepage region, an oil-gas miscible region, an oil-gas near-miscible region, and a pure oil seepage region. These seepage regions are defined according to the pressure distribution and hydrocarbon concentration changes during the hydrocarbon displacement process.

[0102] In the above embodiments, preferably, the formation process of the four parts is as follows: as gas injection proceeds, the pressure in the near-wellbore zone of the injection well increases, and the hydrocarbon displacement front undergoes dissolution and extraction with the crude oil, resulting in dynamic miscibility; as the distance increases, the pressure in the area away from the injection well decreases, and when the pressure drops to about 0.8 times the minimum miscibility pressure, a near-miscible zone is formed; as time goes by, the length of the miscible zone or near-miscible zone gradually increases, and its position also moves forward at a certain speed, forming a pure gas seepage zone behind it and a pure oil seepage zone in front of it.

[0103] In the above embodiments, preferably, establishing a mathematical model for hydrocarbon gas drive seepage in low-permeability reservoirs includes:

[0104] Assuming the reservoir is a low-permeability heterogeneous oil reservoir, the seepage conforms to the two-phase isothermal non-Darcy flow of oil and gas, the seepage model is a one-dimensional radial flow model, the formation pressure is higher than the bubble point pressure but lower than the minimum miscibility pressure, the viscosity reduction effect of hydrocarbon gas on crude oil is considered, the change of the oil phase initiation pressure gradient is considered, and the dissolution, ion mass transfer and adsorption of gas and oil layer are considered during the hydrocarbon gas displacement process to establish a one-dimensional convection-diffusion equation.

[0105] Assuming the injected gas composition is constant and is pure CH4; the oil phase start-up pressure gradient G is regressed using experimental data from the start-up pressure gradient of the mine core. o The viscosity of the oil-gas mixture within the miscible swept zone was determined to be μ. mix Based on core displacement experimental data from the mine, the front discrimination conditions for different facies zones were determined, and the starting pressure gradient of the oil-gas mixture in the miscible zone was corrected to G. mix ;

[0106] The pure gas seepage zone, the oil-gas mixed zone, and the pure oil seepage zone belong to the single-phase seepage stage, where the fluid viscosity and starting pressure gradient change. The single-phase seepage equation is used to describe the seepage process in this stage.

[0107] In the near-miscible region of oil and gas, since crude oil and injected gas are no longer miscible during the near-miscible seepage process, the calculation method of two-phase seepage of oil and gas is used to calculate the seepage resistance.

[0108] Under the assumed conditions, the one-dimensional convection-diffusion equation is:

[0109]

[0110] The boundary conditions are:

[0111] C(x,0)=0,0≤x<∞ (2)

[0112] C(0,t)=C0,C(∞,)=0,0<t<∞ (3)

[0113] Using the Laplace transform, the analytical solution to the one-dimensional convection-diffusion equation can be obtained as follows:

[0114]

[0115] in:

[0116]

[0117] Once the CH4 concentration distribution is known, the density of the oil-gas mixture can be calculated using the following empirical formula, and the corresponding starting pressure gradient can be corrected accordingly:

[0118]

[0119]

[0120] In the above formula, μ mix Viscosity of the oil-gas mixture; μ o and μ g denoted as oil phase viscosity and gas phase viscosity, respectively; C is methane concentration; G is the starting pressure gradient; a and n are undetermined constants; and k is reservoir permeability.

[0121] In the above embodiments, preferably, solving the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir includes:

[0122] Calculate the pressure difference loss and length change within the pure gas seepage zone:

[0123] The length of the pure gas permeation zone is:

[0124]

[0125] In the formula, r1 is the distance between the boundary of the pure gas seepage zone and the injection well, r0 is the wellhead radius, Q is the gas injection rate, h is the reservoir thickness, and t is the time. Porosity;

[0126] The pressure distribution within the pure gas seepage zone is as follows:

[0127]

[0128] Pressure difference ΔP consumed g for:

[0129]

[0130] In the formula, Q is the gas injection rate; μ is the gas viscosity; r is the distance from the injection well; k is the reservoir permeability; and h is the reservoir thickness.

[0131] Calculate the CH4 concentration distribution, pressure drop, and length variation within the miscible region:

[0132] The CH4 concentration in the miscible region decreases continuously, while the viscosity of the oil-gas mixture and the oil phase initiation pressure gradient increase continuously. The miscible region is divided into n grids. Considering that the fluid properties in each grid are consistent, the CH4 concentration, crude oil viscosity, and oil phase initiation pressure gradient in each grid are calculated using equations (4), (6), and (7), respectively.

[0133] Assuming a time step of Δt and a distance step of Δx, the distance step is increased cyclically until the reservoir pressure drops to the minimum miscibility pressure or the grid CH4 concentration drops to the frontal concentration C. f The calculation stops; the total grid length at which the calculation stops is the length of the mixed region at different times (r2-r1)=ΣΔx, and the migration time T=ΣΔt; where r2=ΣΔx+r1;

[0134] The pressure gradient is:

[0135]

[0136] Pressure difference ΔP consumed mix for:

[0137]

[0138] In the formula, ΔP mix The pressure difference consumed in the miscible region; G mix To initiate the pressure gradient in the corrected miscible region;

[0139] Calculate the CH4 concentration distribution, pressure drop, and length variation within the near-miscible region:

[0140] The CH4 concentration distribution characteristics and calculation methods in the near-miscible region are exactly the same as those in the miscible region, but the methods for determining the pressure drop loss and interval length are different; assuming the time step is Δt and the distance step is Δx, the distance step is cyclically increased until the reservoir pressure drops to 0.8 times the minimum miscibility pressure or the grid CH4 concentration drops to the frontal concentration C. f The near-mixed region length (r3-r2) = ΣΔx and the transport time T = ΣΔt were calculated at different times; where r3 = ΣΔx + r2.

[0141] The pressure difference loss in the near-miscible zone is calculated using the non-piston displacement two-phase flow resistance calculation method; given the relative permeability data of the reservoir, and ignoring the effects of gravity and capillary force, the coefficients a and b in the formula are calculated graphically.

[0142]

[0143] The above equation can also be expressed by the polynomial μ. r ω o =A+Bz+Cz 2 An approximate expression is used to calculate the pressure difference consumed by the two-phase flow in the near-miscible section;

[0144] Pressure difference ΔP consumed in the near-miscible region mixo for:

[0145]

[0146] In the formula, A, B, and C are all constants, derived from the polynomial μ. r ω o =A+Bz+Cz 2 Fitting μ r ω o The relationship curve between z and z is obtained; z f =1-S w -S or S wWater saturation; S or Residual oil saturation; μ r The oil-water viscosity ratio, μ o Crude oil viscosity; μ w ω is the viscosity of water; o For intermediate parameters, k rw k ro These are the relative permeability under bound water conditions and the relative permeability under residual oil conditions, respectively.

[0147] Calculate the pressure difference loss and length change within the pure oil seepage zone:

[0148] The pressure distribution in the pure oil zone is as follows:

[0149]

[0150] Pressure difference ΔP o for:

[0151]

[0152] The length r4 of the pure oil zone, which is also the oil drainage radius of the pure oil zone, is:

[0153]

[0154] In the formula P is the mean formation pressure. wf For the bottom-hole flowing pressure of the production well; μ o ρ is the oil phase viscosity; k is the reservoir permeability; q is the injection rate.

[0155] In the above embodiments, preferably, the limiting well spacing is determined in the following manner:

[0156] Let r1 be the location of the pure gas seepage zone front, r2 be the location of the miscible zone front, r3 be the location of the near-miscible zone front, and r4 be the location of the pure oil zone front. Let L be the actual well spacing. When L = r1 + r2 + r3 + r4, the pressure at the point where the miscible front and the pure oil zone meet exactly reaches the formation mean pressure P. ε When the pressure fronts of the two meet, L is the limit well spacing under the set production rate, and the boundary between the two seepage zones is the hydrocarbon drive wave front.

[0157] Example 1:

[0158] Obtain basic parameters of the target reservoir: crude oil viscosity μ o =1.2 mPa·s, viscosity of water μ w = 1 mPa·s, formation permeability k = 8 × 10 -3 μm 2 Formation porosity φ = 0.144, bound water saturation Swc =0.42, reservoir thickness 80m, seepage cross-sectional area A = 8000m³ 2 Injection velocity q = 100m 3 / d, production time T=90d, injection well pressure P in =40MPa, production well pressure P out =18MPa, reservoir original pressure P r =33.4MPa.

[0159] Under the assumed conditions, the one-dimensional convection-diffusion equation is:

[0160]

[0161] The boundary conditions are:

[0162] C(x,0)=0,0≤x<∞ (2)

[0163] C(0,t)=C0,C(∞,)=0,0<t<∞ (3)

[0164] Using the Laplace transform, the solution to this mathematical model can be obtained as follows:

[0165]

[0166] in

[0167]

[0168] Once the CH4 concentration distribution is known, the density of the oil-gas mixture can be calculated using the following empirical formula, and the starting pressure gradient at the corresponding location can be corrected.

[0169]

[0170]

[0171] In the above formula, μ mix The viscosity of the oil-gas mixture is given in mPa·s; μ o / μ g These represent the oil phase viscosity and gas phase viscosity, respectively, in mPa·s; C is the methane concentration, in kg·m³. -3 The starting pressure gradient is G; a and n are undetermined constants.

[0172] Solving the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir, we obtain the limiting well spacing under the corresponding conditions:

[0173] Calculate the pressure difference loss and length change within the pure gas seepage zone:

[0174] Length of pure gas permeation zone:

[0175]

[0176] In the formula, r1 is the distance between the boundary of the pure gas seepage zone and the injection well, r0 is the wellhead radius, Q is the gas injection rate, and h is the reservoir thickness.

[0177] Pressure distribution within the pure gas permeation zone:

[0178]

[0179] Pressure difference ΔP consumed g for:

[0180]

[0181] Calculate the CH4 concentration distribution, pressure drop, and length variation within the miscible region:

[0182] In the miscible region, the CH4 concentration continuously decreases, while the viscosity of the oil-gas mixture and the oil phase initiation pressure gradient continuously increase. The miscible region is divided into n equal grids. Assuming that the fluid properties are consistent within each grid, equations (4), (6), and (7) are used to calculate the CH4 concentration in each grid, resulting in dimensionless methane mass concentration distribution maps of the miscible and near-miscible regions, as shown below. Figure 3 As shown. Then, the corresponding crude oil viscosity and starting pressure gradient are calculated based on the CH4 concentration within the grid. Assuming a time step of Δt = 1 day and a distance step of Δx = 0.1 m, the distance step is increased cyclically until the reservoir pressure drops to the minimum miscibility pressure or the grid CH4 concentration drops to the leading edge concentration Cf, at which point the calculation stops. The total grid length at the time of calculation stop is the miscible region length (r2-r1) = ΣΔx, and the migration time T = ΣΔt.

[0183] The pressure gradient is:

[0184]

[0185] The pressure difference consumed is:

[0186]

[0187] Calculate the CH4 concentration distribution, pressure drop, and length variation within the near-miscible region:

[0188] The calculation method for CH4 concentration distribution in the near-miscible region is exactly the same as that in the miscible region, but the methods for determining pressure loss and interval length are different. Assuming a time step of Δt = 1 day and a distance step of Δx = 0.1 m, the grid number is cyclically increased until the reservoir pressure drops to 0.8 times the minimum miscibility pressure or the grid CH4 concentration drops to the leading edge concentration C. f The calculation stops. At this point, the total grid length is the near-mixed region length at different times (r3-r2) = ΣΔx, and the transport time is T = ΣΔt.

[0189] The pressure differential loss in the near-miscible zone is calculated using a method for calculating the resistance to two-phase flow without piston displacement. Given the relative permeability data of the reservoir, and neglecting the effects of gravity and capillary forces, the coefficients a and b in the formula can be calculated graphically, such as... Figure 4 As shown.

[0190] The relative permeability data of the target reservoir are shown in Table 1:

[0191] Table 1. Relative gas-liquid permeability data of the target reservoir.

[0192] 0.41 0.49 0 0.45 0.4 0 0.51 0.32 0.02 0.56 0.24 0.05 0.65 0.18 0.1 0.73 0.12 0.18 0.78 0.08 0.28 0.84 0.04 0.41 0.89 0.02 0.58 0.95 0.01 0.77 0.41 0.49 0

[0193]

[0194] In the formula, a = -0.0875 and b = 2.89.

[0195] The above equation can also be expressed by the polynomial μ. r ω o =A+Bz+Cz 2 An approximate expression is used to calculate the pressure difference consumed by the two-phase flow in the near-mixed phase section.

[0196] The pressure differential consumed in the near-miscible region is:

[0197]

[0198] In the formula, A = 0.115, B = 0.104, and C = 0.0044, derived from the polynomial μ r ω o =A+Bz+Cz 2 Fitting μ r ω o The relationship curve between z and z is obtained; z f =1-S w -S or ;

[0199] Calculate the pressure difference loss and length change within the pure oil seepage zone:

[0200] The pressure distribution in the pure oil zone is as follows:

[0201]

[0202] The pressure difference is:

[0203]

[0204] The length r4 of the pure oil zone, which is also the oil drainage radius of the pure oil zone, is:

[0205]

[0206] In the formula P is the mean formation pressure. wf The bottom flow pressure of the production well.

[0207] By calculating the pressure loss and seepage zone length of each region through the above steps, when the pressure at the hydrocarbon drive front equals the average formation pressure, the sum of the lengths of the four regions is 397.3 m, which is the limiting well spacing under the corresponding injection conditions for this reservoir. This calculation result is basically consistent with the actual situation in the oilfield, thus confirming the effectiveness of the present invention.

[0208] Analysis of factors influencing the ultimate well spacing:

[0209] Without changing other parameters, the effects of the above factors on the ultimate well spacing can be analyzed by modifying different gas injection rates, initial crude oil viscosity, permeability, and production pressure differentials.

[0210] Taking the target reservoir conditions as an example, the maximum well spacing with a maximum gas injection time of 200 days is calculated for initial crude oil viscosities of 1, 1.5, 3, 4, 5, 6.5, and 8 mPa·s. Figure 5 As shown, the limiting well spacing for hydrocarbon gas drive in low-permeability reservoirs decreases with increasing initial crude oil viscosity.

[0211] Taking the target reservoir conditions as an example, the maximum well spacing with a maximum gas injection time of 200 days is calculated for gas injection rates of 20, 32, 40, 48, and 60 t / d. Figure 6 As shown, the limiting well spacing for hydrocarbon gas drive in low-permeability reservoirs increases with increasing gas injection rate.

[0212] Taking the target reservoir conditions as an example, the maximum well spacing with a maximum gas injection time of 200 days is calculated for reservoir permeability of 8, 20, 30, 40, 50, 60, 80, and 100 mD. Figure 7 As shown, the limiting well spacing for hydrocarbon gas drive in low-permeability reservoirs increases with increasing reservoir permeability.

[0213] Taking the target reservoir conditions as an example, the maximum well spacing with a maximum gas injection time of 200 days is calculated under the conditions of production pressure differentials of 15, 18, 21, and 24 MPa. Figure 8 As shown, the limiting well spacing for hydrocarbon gas drive in low-permeability reservoirs increases with increasing production pressure differential.

[0214] The ultimate well spacing was calculated by designing a 4-factor, 5-level orthogonal experiment and the results were analyzed by gray-scale correlation analysis, as shown in Table 2. This allows us to determine the magnitude of the influence of each factor on the ultimate well spacing of hydrocarbon drive.

[0215] Table 2. Factors for Orthogonal Experiments

[0216] Level 1 15 8 1 20 Level 2 18 20 1.5 32 Level 3 21 50 3 40 Level 4 24 80 5 48 Level 5 27 100 8 60

[0217] The grey relational analysis results show that permeability has the greatest impact on the ultimate well spacing, followed by production pressure differential and crude oil viscosity, while gas injection rate has the least impact on the ultimate well spacing.

[0218] Example 2:

[0219] This invention also provides a device for determining the limiting well spacing in hydrocarbon gas drive technology for low-permeability reservoirs, comprising:

[0220] The first processing unit is used to obtain the basic parameters of the target reservoir;

[0221] The second processing unit is used to establish a physical model of hydrocarbon gas drive seepage in low-permeability reservoirs.

[0222] The third processing unit is used to establish a mathematical model of hydrocarbon gas drive seepage in low-permeability reservoirs based on the basic parameters and physical model of the target reservoir.

[0223] The fourth processing unit is used to solve the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir and obtain the limiting well spacing under the corresponding conditions.

[0224] Example 3:

[0225] The present invention also provides a computer storage medium storing a computer program thereon, wherein the computer program, when executed by a processor, implements the steps of the method for determining the ultimate well spacing of the hydrocarbon gas drive technology in low-permeability reservoirs.

[0226] Example 4:

[0227] The present invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the method steps for determining the limit well spacing of the hydrocarbon gas drive technology in low-permeability reservoirs.

[0228] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for determining the limiting well spacing in hydrocarbon gas drive technology for low-permeability reservoirs, characterized in that, Includes the following steps: Obtain the basic parameters of the target reservoir; A physical model for hydrocarbon gas drive seepage in low-permeability reservoirs was established, including: for the case of one injection and one production in an infinite formation, the entire seepage area was divided into four parts based on the changes in fluid properties during hydrocarbon gas drive: pure gas seepage area, oil-gas miscible area, oil-gas near-miscible area, and pure oil seepage area. The oil-gas near-miscible area is the area formed when the pressure decreases with increasing distance from the injection well and the pressure drops to about 0.8 times the minimum miscibility pressure. Based on the basic parameters and physical model of the target reservoir, a mathematical model of hydrocarbon gas drive seepage in low-permeability oil reservoirs is established. Solving the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir yields the limiting well spacing under corresponding conditions, including calculations of CH4 concentration distribution, pressure loss, and length variation within the near-miscible zone: The CH4 concentration distribution characteristics and calculation methods in the near-miscible region are exactly the same as those in the miscible region, but the methods for determining the pressure drop loss and interval length are different; assuming the time step is Δt and the distance step is Δx, the distance step is cyclically increased until the reservoir pressure drops to 0.8 times the minimum miscibility pressure or the grid CH4 concentration drops to the frontal concentration C. f The near-mixed region length (r3-r2) was calculated to be ΣΔx at different times, and the transport time was calculated to be ΣΔt. The pressure differential loss in the near-miscible zone is calculated using a non-piston-displacement two-phase flow resistance calculation method. Given the relative permeability data of the reservoir, and neglecting the effects of gravity and capillary forces, the coefficients in the formula are calculated graphically. , ; （13） The above expression can also be expressed by a polynomial. An approximate expression is used to calculate the pressure difference consumed by the two-phase flow in the near-miscible section; Pressure differential consumed in the near-miscible region for: （14） In the formula, A, B, and C are all constants, derived from the polynomial. Fitting The relationship curve with z is obtained; ; , ; These are the relative permeability under bound water conditions and the relative permeability under residual oil conditions, respectively.

2. The determination method according to claim 1, characterized in that, The basic parameters of the target reservoir include: Crude oil viscosity μ o 、 Viscosity of water μ w 、 reservoir permeability k、 reservoir porosity 、 Bound water saturation S wc 、 seepage cross-sectional area A、 Injection speed q、 Production time T、 Original reservoir pressure P i 、 Injection well pressure P in 、 Production well pressure P out 、 Original pressure P of reservoir r Oil-water and oil-gas phase permeation curves of the reservoir.

3. The determination method according to claim 1, characterized in that, The seepage zone is divided based on the pressure distribution and hydrocarbon concentration changes during the hydrocarbon displacement process.

4. The determination method according to claim 3, characterized in that, The formation process of the four parts is as follows: as gas injection proceeds, the pressure in the near-wellbore zone of the injection well increases, and the hydrocarbon displacement front undergoes dissolution and extraction with the crude oil, resulting in dynamic miscibility; as time goes by, the length of the miscible zone or near-miscible zone gradually increases, and its position also moves forward at a certain speed, forming a pure gas seepage zone behind it and a pure oil seepage zone in front of it.

5. The determination method according to claim 3, characterized in that, The establishment of the mathematical model for hydrocarbon gas drive seepage in low-permeability reservoirs includes: Assuming the reservoir is a low-permeability heterogeneous oil reservoir, the seepage conforms to the two-phase isothermal non-Darcy flow of oil and gas, the seepage model is a one-dimensional radial flow model, the formation pressure is higher than the bubble point pressure but lower than the minimum miscibility pressure, the viscosity reduction effect of hydrocarbon gas on crude oil is considered, the change of the oil phase initiation pressure gradient is considered, and the dissolution, ion mass transfer and adsorption of gas and oil layer are considered during the hydrocarbon gas displacement process to establish a one-dimensional convection-diffusion equation. Assuming the injected gas composition is constant and is pure CH4; the oil phase start-up pressure gradient G is regressed using experimental data from the start-up pressure gradient of the mine core. o The viscosity of the oil-gas mixture within the miscible swept zone was determined to be μ. mix Based on core displacement experimental data from the mine, the front discrimination conditions for different facies zones were determined, and the starting pressure gradient of the oil-gas mixture in the miscible zone was corrected to G. mix ; The pure gas seepage zone, the oil-gas mixed zone, and the pure oil seepage zone belong to the single-phase seepage stage, where the fluid viscosity and starting pressure gradient change. The single-phase seepage equation is used to describe the seepage process in this stage. In the near-miscible region of oil and gas, since crude oil and injected gas are no longer miscible during the near-miscible seepage process, the calculation method of two-phase seepage of oil and gas is used to calculate the seepage resistance. Under the assumed conditions, the one-dimensional convection-diffusion equation is: （1） The boundary conditions are: （2） （3） Using the Laplace transform, the analytical solution to the one-dimensional convection-diffusion equation can be obtained as follows: （4） in: （5） Once the CH4 concentration distribution is known, the density of the oil-gas mixture can be calculated using the following empirical formula, and the corresponding starting pressure gradient can be corrected accordingly: （6） （7） In the above formula, The viscosity of the oil-gas mixture; These are the oil phase viscosity and the gas phase viscosity, respectively. This refers to the methane concentration. To initiate the pressure gradient; , These are undetermined constants; k This represents reservoir permeability.

6. The determination method according to claim 5, characterized in that, The process of solving the mathematical model for hydrocarbon gas drive seepage in the low-permeability reservoir to obtain the limiting well spacing under the corresponding conditions also includes: Calculate the pressure difference loss and length change within the pure gas seepage zone: The length of the pure gas permeation zone is: （8） In the formula The distance between the boundary of the pure gas seepage zone and the injection well. The length of the wellhead radius. The gas injection rate, t represents the reservoir thickness; t represents time. ; The pressure distribution within the pure gas seepage zone is as follows: （9） Pressure difference consumed for: （10） In the formula, This refers to the gas injection rate; For gas viscosity; r This is the distance from the gas injection well; k Reservoir permeability; h Reservoir thickness; Calculate the CH4 concentration distribution, pressure drop, and length variation within the miscible region: The CH4 concentration in the miscible region decreases continuously, while the viscosity of the oil-gas mixture and the oil phase initiation pressure gradient increase continuously. The miscible region is divided into n grids. Considering that the fluid properties in each grid are consistent, the CH4 concentration, crude oil viscosity, and oil phase initiation pressure gradient in each grid are calculated using equations (4), (6), and (7), respectively. Assuming a time step of Δt and a distance step of Δx, the distance step is increased cyclically until the reservoir pressure drops to the minimum miscibility pressure or the grid CH4 concentration drops to the frontal concentration C. f The calculation stops; the total grid length at which the calculation stops is the length of the mixed region at different times (r2-r1) = ΣΔx, and the transport time T = ΣΔt; The pressure gradient is: （11） Pressure difference consumed for: （12） In the formula, Calculate the pressure difference loss and length change within the pure oil seepage zone: The pressure distribution in the pure oil zone is as follows: （15） pressure difference for: （16） The length r4 of the pure oil zone, which is also the oil drainage radius of the pure oil zone, is: （17） In the formula To represent the average formation pressure, For the bottom flow pressure of the production well; ; .

7. The determination method according to claim 6, characterized in that, The limiting well spacing is determined in the following way: Let r1 be the location of the pure gas seepage zone front, r2 be the location of the miscible zone front, r3 be the location of the near-miscible zone front, and r4 be the location of the pure oil zone front. Let L be the actual well spacing. When L = r1 + r2 + r3 + r4, the pressure at the point where the miscible front and the pure oil zone meet exactly reaches the formation mean pressure. When the pressure fronts of the two meet, L is the limit well spacing under the set production rate, and the boundary between the two seepage zones is the hydrocarbon drive wave front.

8. A device for determining the limiting well spacing in hydrocarbon gas drive technology for low-permeability oil reservoirs, characterized in that, include: The first processing unit is used to obtain the basic parameters of the target reservoir; The second processing unit is used to establish a physical model of hydrocarbon gas drive seepage in low-permeability oil reservoirs. This includes: for the case of one injection and one production in an infinitely large formation, the entire seepage area is divided into four parts based on the changes in fluid properties during hydrocarbon gas drive: pure gas seepage area, oil-gas miscible area, oil-gas near-miscible area, and pure oil seepage area. The oil-gas near-miscible area is the region where the pressure decreases as the distance increases and the area away from the injection well decreases. The pressure is formed when it drops to about 0.8 times the minimum miscibility pressure. The third processing unit is used to establish a mathematical model of hydrocarbon gas drive seepage in low-permeability reservoirs based on the basic parameters and physical model of the target reservoir. The fourth processing unit is used to solve the mathematical model of hydrocarbon gas drive seepage in the low-permeability reservoir to obtain the limiting well spacing under the corresponding conditions, including the calculation of CH4 concentration distribution, pressure loss, and length variation in the near-miscible zone: The CH4 concentration distribution characteristics and calculation methods in the near-miscible region are exactly the same as those in the miscible region, but the methods for determining the pressure drop loss and interval length are different; assuming the time step is Δt and the distance step is Δx, the distance step is cyclically increased until the reservoir pressure drops to 0.8 times the minimum miscibility pressure or the grid CH4 concentration drops to the frontal concentration C. f The near-mixed region length (r3-r2) was calculated to be ΣΔx at different times, and the transport time was calculated to be ΣΔt. The pressure differential loss in the near-miscible zone is calculated using a non-piston-displacement two-phase flow resistance calculation method. Given the relative permeability data of the reservoir, and neglecting the effects of gravity and capillary forces, the coefficients in the formula are calculated graphically. , ; （13） The above expression can also be expressed by a polynomial. An approximate expression is used to calculate the pressure difference consumed by the two-phase flow in the near-miscible section; Pressure differential consumed in the near-miscible region for: （14） In the formula, A, B, and C are all constants, derived from the polynomial. Fitting The relationship curve with z is obtained; ; , ; These are the relative permeability under bound water conditions and the relative permeability under residual oil conditions, respectively.

9. A computer storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by the processor, it implements the steps of the method for determining the limit well spacing of low-permeability reservoir hydrocarbon gas drive technology as described in any one of claims 1-7.

10. A computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the steps of the method for determining the limit well spacing of hydrocarbon gas drive technology in low-permeability reservoirs as described in any one of claims 1-7.

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