Liquid injection scale optimization method for reverse pressure driving of offshore low-permeability reservoir

Abstract

The invention provides a liquid injection scale optimization method for reverse pressure driving of an offshore low-permeability reservoir, and belongs to the technical field of oilfield development. Comprising the steps of determining basic parameters according to reservoir geologic features of a target reservoir to be subjected to reverse pressure drive; a finite-discrete element method of a Cohesive unit is adopted to calculate fracture dynamics; the method comprises the following steps of: predicting unit thickness oil increment of different unit thickness liquid injection scales in different soaking times under the conditions of different permeability and formation pressure coefficients before measures on the basis of a mechanism of improving recovery efficiency by equivalent representation of reverse pressure flooding through reservoir numerical simulation; and with the maximum value of the unit thickness oil increasing amount as the target, the optimal liquid injection scale of reverse pressure drive under the conditions of different permeability and formation pressure coefficients before measures is determined. According to the method, the optimal liquid injection scale can be quickly and accurately given according to the basic parameters related to the geological reservoir by determining the basic parameters, calculating the fracture dynamic state, predicting the productivity and establishing the optimization plate, and the calculation precision of reverse pressure drive numerical simulation is improved.

Description

Technical Field

[0001] The invention relates to the technical field of oilfield development, and in particular to a method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs. Background Art

[0002] The fault distribution of offshore low-permeability reservoirs is complex, and it is impossible to establish an effective displacement relationship. Most of the isolated wells are used for exhaustion development, which has a series of development contradictions such as rapid production decline, difficulty in stabilizing production, and low recovery. In order to further improve the recovery rate, it is necessary to cooperate with production-increasing measures. Fracturing is one of the most effective production-increasing measures. Although it can control more geological reserves through cracks, it cannot replenish formation energy. It only uses the geological reserves around the cracks. Although a higher production capacity can be obtained in the early stage after fracturing, it quickly decreases to the economic limit of oil production. There are still development contradictions such as short validity period, rapid production capacity decline, and low recovery. However, reverse pressure drive technology has good adaptability to the above problems.

[0003] There are two main differences between reverse pressure drive and fracturing: (1) In terms of technology: fracturing uses high-viscosity, difficult-to-filter guar gum as the fracturing fluid, which is then returned after fracturing without a well soaking process; while reverse pressure drive uses low-viscosity, easy-to-filter oil displacement agent as the pressure drive fluid, commonly used is surfactant aqueous solution, and the well is fully soaked after fracturing. (2) In terms of mechanism for improving oil recovery: fracturing mainly controls more geological reserves through cracks to improve oil recovery, and during the production process, the reserves are transported to the bottom of the production well through the drainage effect of the cracks, making it easier to produce. Fracturing mainly uses geological reserves around the well point and around the cracks; during the fracturing process, the high-viscosity fracturing fluid only exists inside and around the cracks, and has no function of replenishing formation energy. The main difference between reverse pressure drive and fracturing is that reverse pressure drive not only causes crack expansion, but also causes percolation of the pressure drive fluid. The pressure drive fluid not only exists inside and around the cracks, but also percolates to the deep reservoir in a direction perpendicular to the cracks, replenishing energy in the deep reservoir. In addition, after the reverse pressure drive injection is completed, the well is shut down. On the one hand, it can further enhance the energy enhancement effect after the pressure drive injection, and on the other hand, it can fully replace oil and water under the action of capillary force. Under the combined effect of fractures, percolation energy enhancement and well shut down, compared with fracturing, reverse pressure drive can control more geological reserves and can significantly improve the recovery rate of offshore low-permeability reservoirs.

[0004] The reverse pressure-drive technology has been well applied in the three types of oil layers in Daqing Changyuan, the low-permeability sandstone reservoirs in North China, and the ultra-low permeability tight oil reservoirs in Changqing, but its application in offshore low-permeability reservoirs is in its infancy. Due to the limitations of offshore oilfield construction, the displacement, liquid volume, and pumping procedures are not as flexible as onshore oilfields. It is unclear how the key process parameters of pressure-drive quantitatively affect the pressure-drive effect, and the optimal injection scale of reverse pressure-drive is unknown. Based on this, the present invention establishes a method for optimizing the injection scale of reverse pressure-drive for offshore low-permeability reservoirs, which can determine the optimal injection scale of reverse pressure-drive according to the geological parameters of the reservoir, improve the effect of reverse pressure-drive, and play a guiding role in the development of offshore low-permeability reservoirs. Summary of the invention

[0005] In view of this, the present invention aims to propose a method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs, which simultaneously considers the fracture expansion and pressure drive fluid percolation during the pressure drive injection process, and the pressure diffusion and oil-water displacement during the well soaking process. This method is mainly used to guide the injection scale design of reverse pressure drive for offshore low-permeability reservoirs, provide theoretical guidance for the actual construction process, and improve the development efficiency of offshore low-permeability reservoirs.

[0006] To achieve the above object, the technical solution of the present invention is implemented as follows: a method for optimizing the injection scale of reverse pressure drive in offshore low-permeability reservoirs, comprising the following steps:

[0007] S1. Determine basic parameters according to the reservoir geological characteristics of the target reservoir to be reverse pressure driven;

[0008] S2, calculating fracture dynamics based on the finite-discrete element method of the cohesive unit according to the reservoir geological parameters determined in step S1;

[0009] S3, according to the basic parameters determined in step S1 and the relationship between the fracture half-length and time determined in step S2, based on the equivalent characterization of the reverse pressure drive mechanism for improving oil recovery by reservoir numerical simulation, predict the increase in oil per unit thickness at different soaking times under different permeability and formation pressure coefficient conditions with different unit thickness injection scales;

[0010] S4. Taking the maximum value of the increase in oil per unit thickness as the goal, first design the unit thickness injection scale under different permeabilities and formation pressure coefficients before measures, then calculate the unit thickness increase in oil under reasonable well soaking time, and finally determine the optimal reverse pressure drive injection scale under different permeabilities and formation pressure coefficients before measures based on the unit thickness increase in oil.

[0011] Furthermore, in step S1, the basic parameters include four categories: reservoir geological parameters, rock mechanics parameters, construction injection parameters and oil-water seepage parameters.

[0012] Furthermore, step S2 includes using a finite-discrete element method based on a cohesive unit to simultaneously calculate fracture extension and pressure-driven fluid infiltration, realize fluid-solid coupling, and characterize the fracture extension and pressure-driven fluid infiltration characteristics of the "fracture and seepage" process of reverse pressure-driven injection.

[0013] Furthermore, the finite-discrete element method based on the cohesive unit specifically considers the permeability, the formation pressure coefficient before the measure and the injection scale per unit thickness, clarifies the dynamic change of the fracture half-length with time under the conditions of different permeability and formation pressure coefficient before the measure, that is, the relationship between the fracture half-length and the injection scale per unit thickness, and clarifies the dynamic expansion law of the fracture during the reverse pressure-driven injection process.

[0014] Furthermore, the dynamic expansion law of fractures in the reverse pressure-driven injection process refers to the obtained relationship between the fracture half-length and time, and the segmented characterization of the change of the fracture half-length with time based on the discrete idea, and further considering the reverse pressure-driven production capacity prediction.

[0015] Furthermore, in step S3, the method of numerical simulation of the reservoir is used to equivalently characterize the mechanism of reverse pressure-driven oil recovery, including fracture effect, permeability expansion, pressure-driven agent mechanism of oil recovery and oil-water displacement, and predict the increase in oil per unit thickness at different unit thickness injection scales under different permeabilities and formation pressure coefficients before measures at different well soaking times.

[0016] Furthermore, step S4 is specifically to obtain the relationship between the unit thickness oil increase and the unit thickness injection scale of reverse pressure drive to achieve a reasonable well shut-in time under the conditions of different permeabilities and formation pressure coefficients before measures according to the unit thickness oil increase of different unit thickness injection scales under the conditions of different permeabilities and formation pressure coefficients before measures predicted in step S3, with the maximum value of the unit thickness oil increase as the target, and further obtain the optimal unit thickness injection scale under the conditions of different permeabilities and formation pressure coefficients before measures, that is, the optimal injection scale of reverse pressure drive.

[0017] Compared with the prior art, the method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs described in the present invention has the following advantages:

[0018] (1) The finite-discrete element method of the cohesive unit is used to characterize the fluid-solid coupling process of "fracture and seepage" during the reverse pressure-driven injection process, and the dynamic expansion of fractures and the percolation of the pressure-driven fluid during the reverse pressure-driven injection process are calculated. Compared with the conventional fracturing model, the fine characterization of the fracture expansion during the pressure-driven injection process, the loss of the pressure-driven fluid along the fracture surface, and the seepage of the oil-water two-phase in the matrix can be achieved. The influence of the percolation of the pressure-driven fluid on the fracture expansion during the pressure-driven injection process is considered, and the accuracy of the calculation of the dynamic expansion of fractures is improved;

[0019] (2) Characterize the mechanism of reverse pressure-driven oil recovery based on reservoir numerical simulation and predict production capacity; use the discrete idea to embed the dynamic expansion of fractures calculated by the finite-discrete element method into the reservoir numerical simulation. Compared with conventional production capacity prediction, the influence of pressure distribution and saturation distribution on production capacity during the pressure-driven injection process is considered, and continuous calculation of the entire life cycle of pressure-driven injection is realized, including pressure-driven injection, well shut-in and production stages, which improves the accuracy of reverse pressure-driven production capacity prediction;

[0020] (3) With the goal of maximizing oil production, the optimal injection scale for reverse pressure drive is obtained. Based on the permeability of the well to be driven and the formation pressure coefficient before the measure, the injection scale for reverse pressure drive can be designed quickly and accurately, providing a more accurate reference for the design of reverse pressure drive technology for offshore low-permeability reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] The accompanying drawings constituting a part of the present invention are used to provide a further understanding of the present invention. The exemplary embodiments of the present invention and their descriptions are used to explain the present invention and do not constitute an improper limitation of the present invention. In the accompanying drawings:

[0022] Figure 1 This is a flow chart of a method for optimizing injection scale for reverse pressure drive of offshore low-permeability reservoirs in an embodiment of the present invention;

[0023] Figure 2 A three-dimensional geological model diagram in an embodiment of the present invention;

[0024] Figure 3 It is a top view of the reverse pressure drive with cracking and seepage in an embodiment of the present invention;

[0025] Figure 4 This is a graph showing how the fracture half-length changes with time under different permeabilities and formation pressure coefficients before measures in an embodiment of the present invention;

[0026] Figure 5 A diagram showing the flow of fluid in fractures and matrix in an embodiment of the present invention;

[0027] Figure 6 This is a discrete equivalent characterization diagram of crack extension in an embodiment of the present invention;

[0028] Figure 7 A method for determining a reasonable soaking time under different permeabilities and formation pressure coefficients before measures in an embodiment of the present invention;

[0029] Figure 8 This is a relationship diagram of the reverse pressure drive unit thickness increase in oil production and unit thickness injection scale corresponding to the reasonable well soaking time under different permeabilities and formation pressure coefficients before measures in the embodiment of the present invention;

[0030] Fig. 9This is a diagram of the optimal injection scale per unit thickness in an embodiment of the present invention. DETAILED DESCRIPTION

[0031] It should be noted that, in the absence of conflict, the embodiments of the present invention and the features in the embodiments may be combined with each other.

[0032] The present invention will be described in detail below with reference to the accompanying drawings and in conjunction with embodiments.

[0033] like Figure 1 As shown, the present invention is a method for optimizing the injection scale for reverse pressure drive of offshore low-permeability reservoirs, comprising the following steps:

[0034] S1. Determine basic parameters according to the reservoir geological characteristics of the target reservoir to be reversed pressure-driven, specifically including four categories: reservoir geological parameters, rock mechanical parameters, construction injection parameters and oil-water seepage parameters; preferably, reservoir geological parameters include permeability, porosity and thickness of reservoir and interlayer; rock mechanical parameters include Young's modulus, Poisson's ratio, ground stress, tensile strength, filtration coefficient and pore pressure of reservoir and interlayer; construction injection parameters include displacement, liquid volume and pressure-driven fluid viscosity during pressure-driven process; oil-water seepage parameters include relative permeability curve and capillary force curve before and after pressure-driven, crude oil viscosity-temperature relationship curve, and viscosity-concentration relationship, interfacial tension, adsorption and other related data of pressure-driven agent.

[0035] S2. According to the reservoir geological parameters determined in step S1, the finite-discrete element method based on the cohesive unit is used to calculate the fracture dynamics. Specifically, the finite-discrete element method based on the cohesive unit is used to simultaneously calculate the fracture expansion and the pressure-driven fluid percolation, realize fluid-solid coupling, characterize the fracture expansion and pressure-driven fluid percolation characteristics of the "fracture and seepage" in the reverse pressure-driven injection process, and clarify the dynamic expansion law of the fracture in the reverse pressure-driven injection process. Preferably, the finite-discrete element method based on the cohesive unit specifically considers the permeability, the formation pressure coefficient before the measure, and the injection scale per unit thickness, and clarifies the dynamic change of the fracture half-length over time under different permeability and formation pressure coefficient before the measure, that is, the relationship between the fracture half-length and the injection scale per unit thickness, and clarifies the dynamic expansion law of the fracture in the reverse pressure-driven injection process. Among them, the dynamic expansion law of the fracture in the reverse pressure-driven injection process refers to the obtained relationship between the fracture half-length and time, and the change of the fracture half-length over time is segmented based on the discrete idea, and the reverse pressure-driven production capacity prediction is further considered.

[0036] S3. According to the basic parameters determined in step S1 and the relationship between the fracture half-length and time determined in step S2, the reverse pressure-driven recovery mechanism is equivalently characterized based on reservoir numerical simulation to predict the increase in oil per unit thickness at different soaking times for different injection scales of liquid permeability and formation pressure coefficient before measures. Specifically, according to the reservoir geological parameters, construction injection parameters, oil-water seepage parameters and the relationship between the fracture half-length and time obtained in step S1, the change in the fracture half-length with time is segmentedly characterized based on the discrete idea, and the soaking time is further considered on the basis of step S2. The reverse pressure-driven recovery mechanism is equivalently characterized by the method of reservoir numerical simulation, including fracture action, permeability increase and volume expansion, the recovery mechanism of pressure-driven agents and oil-water replacement, and the increase in oil per unit thickness at different soaking times for different injection scales of liquid permeability and formation pressure coefficient before measures is predicted.

[0037] S4, taking the maximum value of the increase in oil per unit thickness as the target, first design the unit thickness injection scale under different permeabilities and formation pressure coefficients before measures, then calculate the unit thickness increase in oil under reasonable well-keeping time, and finally further determine the optimal injection scale of reverse pressure drive under different permeabilities and formation pressure coefficients before measures according to the unit thickness increase in oil. Specifically, according to the unit thickness increase in oil per unit thickness of the different permeabilities and formation pressure coefficients before measures predicted in step S3, the maximum value of the unit thickness increase in oil is taken as the target, and the relationship between the reverse pressure drive unit thickness increase in oil per unit thickness and the unit thickness injection scale under different permeabilities and formation pressure coefficients before measures is obtained. Still taking the maximum value of the unit thickness increase in oil as the target, the optimal unit thickness injection scale under different permeabilities and formation pressure coefficients before measures, that is, the optimal injection scale of reverse pressure drive, is obtained.

[0038] Preferably, in step S2, in the finite-discrete element method of the cohesive unit, the flow of the fluid in the fracture is manifested as tangential flow and normal flow.

[0039] The tangential flow equation is:

[0040]

[0041] The normal flow equation is:

[0042]

[0043] Where q is the flow rate of the pressure-displacement fluid inside the fracture, m 3 / s; μ is the viscosity of the pressure-displacement fluid, mPa·s; w is the crack width, m; is the pressure gradient, Pa / m; q tis the filtration loss of the pressure-displacement fluid along the left side of the fracture toward the matrix, m 3 / s;q b is the filtration loss of the pressure-displacement fluid along the right side of the fracture toward the matrix, m 3 / s;c t is the filtration coefficient of the pressure-driven fluid along the left side of the fracture, m / (Pa·s); c b is the filtration coefficient of the pressure-displacement fluid along the right side of the fracture, m / (Pa·s); p i is the fluid pressure in the fracture, Pa; p t is the fluid pressure of the matrix on the left side of the fracture, Pa; p b is the fluid pressure in the matrix on the right side of the fracture, Pa.

[0044] Preferably, in step S2, in the finite-discrete element method based on the cohesive unit, the fluid flows in the rock matrix as an oil-water two-phase flow, which can be expressed by Darcy's law as follows:

[0045]

[0046] In the formula, q o is the flow rate of the oil phase, m 3 / s;q w is the flow rate of water phase, m 3 / s; K ro is the relative permeability of the oil phase, dimensionless; K rw is the relative permeability of the water phase, dimensionless; K is the absolute permeability of the rock matrix, m 2 , A is the flow area, m 2 ;Δp o is the pressure difference of the oil phase, Pa; Δp w is the pressure difference of the water phase, Pa; μ o is the viscosity of the oil phase, Pa·s; μ w is the viscosity of the water phase, Pa·s; L is the grid length, m.

[0047] Preferably, in step S3, a linear elastic model is used to characterize the pressure-driven permeability and expansion effect, with porosity as a function of fluid pressure; and a Carmen-Kozeny formula is used to characterize the pressure-driven permeability change, with permeability as a function of pores. During the reverse pressure-driven injection, well shut-in and production life cycle, as long as the fluid pressure changes, the porosity will change accordingly, thereby causing the permeability to change.

[0048] The porosity change is expressed as:

[0049]

[0050] In the formula, is the porosity at the reference pressure, dimensionless; P romaxis the maximum change in porosity, dimensionless; C por is the compression coefficient, MPa -1 ;P rpor is the reference pressure, MPa; P is the formation pressure, MPa.

[0051] The permeability change is expressed as:

[0052]

[0053] Where K0 is the original permeability, mD; is the original porosity, dimensionless; is the changed porosity, dimensionless; C kpower is the coefficient of variation of permeability, dimensionless.

[0054] Preferably, in step S3, the idea of ​​integration is adopted to discretize the dynamic expansion curve of the fracture during the pressure drive injection process into n parts, determine the average fracture half-length of each part, and set the half-length of the fracture in the reservoir value according to the time point, thereby equivalently characterizing the influence of the fracture on the pressure and oil-water distribution pattern during the reverse pressure drive injection process, which is similar to the process of repeated fracturing.

[0055] Preferably, in step S3, the mechanism of improving oil recovery by the pressure-displacing agent mainly considers the effect of the pressure-displacing agent on reducing oil-water interfacial tension, adsorption, diffusion, oil-water phase permeability and capillary force. This is achieved in the reservoir numerical simulation software by setting the oil-water interfacial tension before and after pressure-displacing, the adsorption amount before and after pressure-displacing, the diffusion coefficient before and after pressure-displacing, and using different phase permeability curves and capillary force curves before and after pressure-displacing.

[0056] Preferably, in step S3, the oil-water replacement mainly considers displacement and imbibition, the pore pressure difference controls displacement, the capillary force controls imbibition, the oil-water phase permeability and capillary force changes during the whole life cycle of the pressure drive are considered to clarify the oil-water replacement, and the oil-water displacement process and oil-water imbibition process are simulated by reservoir numerical simulation software.

[0057] Preferably, in step S4, the maximum value of the oil increase per unit thickness is taken as the target, and the relationship between the reverse pressure drive oil increase per unit thickness and the unit thickness injection scale that achieves a reasonable well shut-in time under different permeabilities and formation pressure coefficients before measures is obtained. Specifically, the reverse pressure drive oil increase per unit thickness corresponding to different well shut-in times is compared, and the well shut-in time corresponding to the maximum oil increase is the reasonable well shut-in time. Figure 7 .

[0058] Preferably, in step S4, the optimal injection scale per unit thickness of reverse pressure drive is further obtained, specifically, fixed permeability and formation pressure coefficient before measures are used, and under the condition of reasonable well keeping, the reverse pressure drive unit thickness increase corresponding to different unit thickness injection scales is compared, and the unit thickness injection scale corresponding to the maximum oil increase is the optimal unit thickness injection scale.

[0059] Preferably, in step S4, the optimal injection scale of reverse pressure drive specifically refers to the injection scale per unit thickness corresponding to the maximum oil increase per unit thickness of reverse pressure drive when different permeabilities and formation pressure coefficients before measures reach a reasonable shut-in time, which is the optimal injection scale per unit thickness of reverse pressure drive, and the optimal injection scale per unit thickness of reverse pressure drive is multiplied by the thickness.

[0060] Example 1

[0061] A method for optimizing injection scale for reverse pressure drive in offshore low-permeability reservoirs. Figure 1 , including the following steps:

[0062] S1. Determine the basic parameters according to the reservoir geological characteristics of the target reservoir to be flooded, including reservoir geological parameters (permeability, porosity, thickness, filtration coefficient and pore pressure of reservoir and interlayer), rock mechanical parameters (Young's modulus, Poisson's ratio, ground stress and tensile strength of reservoir and interlayer), construction injection parameters (displacement, liquid volume and flooding fluid viscosity) and oil-water seepage parameters, see Table 1.

[0063] Table 1 Basic parameters

[0064]

[0065] S2. Establish a three-dimensional geological model. Figure 2 , x×y×z is 300m×800m×88m, the x direction is the direction of the minimum horizontal principal stress, the z direction is the direction of the vertical principal stress, the y direction is the direction of the maximum horizontal principal stress, the thickness of the upper and lower interlayers is 30m, the thickness of the middle reservoir is 28m, and (150, 0, 44) on the xz plane is selected as the injection point. Since the expansion plane of the fracture and the vertical principal stress are perpendicular to each other, the Cohesive unit is embedded in the xy plane to simulate the initiation and expansion of the fracture. The model is meshed, and a homogeneous grid is used in the x and z directions, and a transitional grid is used in the z direction. The grid is encrypted toward the middle. The total number of grids in the middle reservoir is 5×133×50=33250, and the upper and lower interlayer grids are non-homogeneous, transitioning from 10m in the middle to 6m, with a grid number of 53200, and a total number of grids in the model is 86450.

[0066] According to the basic parameters determined in step S1, the permeability and the pre-measure formation pressure coefficient are considered. The design scheme is shown in Table 2. The finite-discrete element method based on the cohesive unit is used to simultaneously calculate the fracture extension and the pressure-driven fluid percolation, realize fluid-solid coupling, and characterize the fracture extension of the reverse pressure-driven injection process "fracture and seepage". Figure 3 , clarify the dynamic expansion law of fractures during reverse pressure drive injection, see Figure 4 .

[0067] Table 2 Scheme design table

[0068]

[0069]

[0070] In the finite-discrete element method of cohesive unit, the flow of fluid in the fracture is manifested as tangential flow and normal flow, see Figure 5 .

[0071] The tangential flow equation is:

[0072]

[0073] The normal flow equation is:

[0074]

[0075] Where q is the flow rate of the pressure-displacement fluid inside the fracture, m 3 / s; μ is the viscosity of the pressure-displacement fluid, mPa·s; w is the crack width, m; is the pressure gradient, Pa / m; q t is the filtration loss of the pressure-displacement fluid along the left side of the fracture toward the matrix, m 3 / s;q b is the filtration loss of the pressure-displacement fluid along the right side of the fracture toward the matrix, m 3 / s;c t is the filtration coefficient of the pressure-driven fluid along the left side of the fracture, m / (Pa·s); c b is the filtration coefficient of the pressure-displacement fluid along the right side of the fracture, m / (Pa·s); p i is the fluid pressure in the fracture, Pa; p t is the fluid pressure of the matrix on the left side of the fracture, Pa; p b is the fluid pressure in the matrix on the right side of the fracture, Pa.

[0076] In the finite-discrete element method based on the cohesive unit, the fluid flows in the rock matrix as oil-water two-phase flow, see Figure 5 , which can be expressed by Darcy's law:

[0077]

[0078] In the formula, q o is the flow rate of the oil phase, m 3 / s;q w is the flow rate of water phase, m 3 / s; K ro is the relative permeability of the oil phase, dimensionless; K rw is the relative permeability of the water phase, dimensionless; K is the absolute permeability of the rock matrix, m 2 , A is the flow area, m 2 ;Δp o is the pressure difference of the oil phase, Pa; Δp w is the pressure difference of the water phase, Pa; μ o is the viscosity of the oil phase, Pa·s; μ w is the viscosity of the water phase, Pa·s; L is the grid length, m.

[0079] S3. According to the relationship between the fracture half-length and time obtained in step S2, the change of the fracture half-length with time is characterized in sections based on the discrete idea, and the reverse pressure drive capacity is further predicted. The scheme design is shown in Table 3, where the fracture half-length is calculated based on step S2, and the unit thickness injection scale and time can be converted to each other. The conversion expression is:

[0080]

[0081] Where Q is the injection scale per unit thickness, m 3 / m; t is time, min; h is reservoir thickness, m; v is pressure drive injection displacement, m 3 / min.

[0082] Table 3 Scheme design table

[0083]

[0084]

[0085] The method of reservoir numerical simulation is used to equivalently characterize the mechanism of reverse pressure drive to enhance oil recovery, including fracture effect, permeability expansion, pressure drive agent mechanism to enhance oil recovery and oil-water replacement, and to predict the increase in oil per unit thickness at different soaking times under different permeabilities and formation pressure coefficients before measures with different injection scales per unit thickness.

[0086] The linear elastic model is used to characterize the effect of pressure-driven permeability and expansion, with porosity as a function of fluid pressure; the Carmen-Kozeny formula is used to characterize the change in permeability during pressure-driven injection, with permeability as a function of pores. During the reverse pressure-driven injection, well shut-in and production life cycle, as long as the fluid pressure changes, the porosity will change, which will in turn lead to changes in permeability.

[0087] The porosity change is expressed as:

[0088]

[0089] In the formula, is the porosity at the reference pressure, dimensionless; P romax is the maximum change in porosity, dimensionless; C por is the compression coefficient, MPa -1 ;P rpor is the reference pressure, MPa; P is the formation pressure, MPa.

[0090] The permeability change is expressed as:

[0091]

[0092] Where K0 is the original permeability, mD; is the original porosity, dimensionless; is the changed porosity, dimensionless; C kpower is the coefficient of variation of permeability, dimensionless.

[0093] Using the idea of ​​integration, see Figure 6 The dynamic expansion curve of the fracture during the pressure-driven injection process is discretized into n parts, the average fracture half-length of each part is determined, and the half-length of the fracture is set in segments according to the time points in the reservoir value, thereby equivalently characterizing the influence of the fracture on the pressure and oil-water distribution pattern during the reverse pressure-driven injection process, which is similar to the process of repeated fracturing.

[0094] The mechanism of pressure-displacement agent to improve oil recovery factor takes into account the pressure-displacement agent's effect on reducing oil-water interfacial tension, adsorption, diffusion, oil-water phase permeability and capillary force. This is achieved in the reservoir numerical simulation software by setting the oil-water interfacial tension before and after pressure-displacement, the adsorption amount before and after pressure-displacement, the diffusion coefficient before and after pressure-displacement, and using different phase permeability curves and capillary force curves before and after pressure-displacement.

[0095] Oil-water displacement mainly considers displacement and imbibition. The pore pressure difference controls displacement, and the capillary force controls imbibition. The oil-water phase permeability and capillary force changes during the entire life cycle of the pressure drive are considered to clarify the oil-water displacement process. The oil-water displacement process and oil-water imbibition process are simulated by reservoir numerical simulation software.

[0096] S4. Based on the unit thickness increase in oil production at different permeabilities and formation pressure coefficients before measures predicted in step S3, and taking the maximum value of the unit thickness increase in oil production as the target, the relationship between the unit thickness increase in oil production at different permeabilities and formation pressure coefficients before measures and the unit thickness injection scale is obtained. Figure 7 and Figure 8The maximum value of the oil increase per unit thickness is still taken as the target, that is, when the oil increase per unit thickness and the injection scale per unit thickness curve have an inflection point or a maximum value, the corresponding injection scale per unit thickness is the optimal injection scale per unit thickness, see Fig. 9 , and the product of the reservoir thickness is the optimal injection scale for reverse pressure drive.

[0097] The above embodiments are only used to illustrate the present invention, wherein the various technical features may be combined in any non-contradictory manner. To make the description concise, all possible combinations of the above technical features are not described. The above are only preferred embodiments of the present invention and are not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the protection scope of the present invention.

Claims

1. A method for optimizing the injection scale of reverse pressure drive in offshore low-permeability reservoirs, characterized in that: The following steps are involved: S1. Determine basic parameters according to the reservoir geological characteristics of the target reservoir to be reverse pressure driven; S2, calculating fracture dynamics based on the finite-discrete element method of the cohesive unit according to the reservoir geological parameters determined in step S1; S3, according to the basic parameters determined in step S1 and the relationship between the fracture half-length and time determined in step S2, based on the equivalent characterization of the reverse pressure drive mechanism for improving oil recovery by reservoir numerical simulation, predict the increase in oil per unit thickness at different soaking times under different permeability and formation pressure coefficient conditions with different unit thickness injection scales; S4. Taking the maximum value of the increase in oil per unit thickness as the goal, first design the unit thickness injection scale under different permeabilities and formation pressure coefficients before measures, then calculate the unit thickness increase in oil under reasonable well soaking time, and finally determine the optimal reverse pressure drive injection scale under different permeabilities and formation pressure coefficients before measures based on the unit thickness increase in oil.

2. The method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs according to claim 1, characterized in that: In step S1, the basic parameters include four categories: reservoir geological parameters, rock mechanics parameters, construction injection parameters and oil-water seepage parameters.

3. The method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs according to claim 1, characterized in that: Step S2 includes using a finite-discrete element method based on a cohesive unit to simultaneously calculate fracture extension and pressure-driven fluid infiltration, realize fluid-solid coupling, and characterize the fracture extension and pressure-driven fluid infiltration characteristics of the "fracture and seepage" process of reverse pressure-driven injection.

4. The method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs according to claim 3, characterized in that: The finite-discrete element method based on the cohesive unit specifically considers the permeability, the formation pressure coefficient before the measure and the injection scale per unit thickness, clarifies the dynamic change of the fracture half-length with time under the conditions of different permeability and formation pressure coefficient before the measure, that is, the relationship between the fracture half-length and the injection scale per unit thickness, and clarifies the dynamic expansion law of the fracture during the reverse pressure drive injection process.

5. The method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs according to claim 4, characterized in that: The dynamic expansion law of fractures in the reverse pressure-driven injection process refers to the obtained relationship between the fracture half-length and time. Based on the discrete idea, the change of the fracture half-length with time is segmented and characterized, and the reverse pressure-driven production capacity prediction is further considered.

6. The method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs according to claim 1, characterized in that: The step S3 uses a reservoir numerical simulation method to equivalently characterize the reverse pressure-driven recovery enhancement mechanism, including fracture action, permeability expansion, pressure-driven agent recovery enhancement mechanism, and oil-water replacement, and predicts the unit thickness increase of different unit thickness injection scales under different permeabilities and pre-measure formation pressure coefficients at different well soaking times.

7. The method for optimizing the injection scale of reverse pressure drive for offshore low-permeability reservoirs according to claim 1, characterized in that: Specifically, step S4 comprises obtaining the relationship between the unit thickness increase in oil production and the unit thickness injection scale of reverse pressure drive to achieve a reasonable well shut-in time under conditions of different permeabilities and formation pressure coefficients before measures according to the unit thickness increase in oil production of different unit thickness injection scales under conditions of different permeabilities and formation pressure coefficients before measures predicted in step S3, taking the maximum value of the unit thickness increase in oil production as a target, and further obtaining the optimal unit thickness injection scale under conditions of different permeabilities and formation pressure coefficients before measures, that is, the optimal injection scale of reverse pressure drive.

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