Method for judging water injection effectiveness in injection-production coupling process of low-permeability reservoir

Abstract

The invention discloses a method for judging water injection effectiveness in an injection-production coupling process of a low-permeability reservoir, which comprises the following steps of: collecting parameters such as porosity, permeability, relative permeability curve, oil-water viscosity, density, volume coefficient, compression coefficient and comprehensive moisture content of rocks at oil and water well ends in a block, and respectively calculating fluid pressure transmitting coefficients at the oil and water well ends; obtaining real starting pressure gradient scatter diagrams of the rock core under different fluidity, and obtaining a pressure gradient empirical formula through scatter diagram regression; acquiring flowing bottomhole pressure of oil and water wells; the method comprises the following steps: improving an unstable radial seepage model between oil wells and water wells in a one-source-one-sink infinite stratum, establishing a pressure formula of unstable seepage of immediate vicinity of wellbores of the oil wells and the water wells, and respectively solving stratum pressures of the immediate vicinity of wellbores of the oil wells and the water wells; drawing a pressure profile map in a well water injection process and an oil well oil extraction process; the oil well effectiveness characteristics are divided into non-effectiveness, intermittent effectiveness, continuous effectiveness and instant effectiveness according to the oil and water well pressure profile map form in the injection and production process.

Description

Technical Field

[0001] The invention belongs to the technical field of oil reservoir development, and in particular relates to a method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir. Background Art

[0002] The interwell formation pressure distribution of an oil reservoir is one of the most important development indicators during oilfield development. It is a crucial parameter for dynamic prediction and reserve calculation. However, during oil and gas field development, as injection and production time continues to change and injection and production work systems continue to change, formation pressure changes dynamically, pressure distribution is uneven, and pressure systems vary greatly. This makes formation pressure prediction extremely difficult. There is an urgent need to establish a method for calculating oil and water interwell pressure that takes into account the nonlinear seepage characteristics of low-permeability reservoirs. This method can analyze the transmission of water well pressure to oil wells during water flooding, thereby analyzing the effectiveness of each oil well and guiding the efficient adjustment of oil and water wells.

[0003] Currently, the main methods used to predict reservoir formation pressure distribution in China and abroad are density and acoustic logging data, using the equivalent depth method. However, this accuracy needs to be improved. A secondary approach is to measure pressure buildup curves during shut-in wells, followed by the determination of average formation pressure using the MBH, MDH, Dietz, and extended Muskat methods. These methods require pressure buildup data or are limited to pseudo-steady-state conditions and long production times, inevitably leading to errors. However, during oilfield development, excessively high interwell formation pressures can lead to waterlogging and increase injection pressure, which in turn increases costs. If interwell formation pressures remain too low, sufficient production pressure differentials cannot be generated to drive oil from the reservoir to the bottom of the production wells, and three-phase flow may even occur, impairing the fluidity of the formation crude oil. Therefore, based on seepage mechanics theory, reservoir engineering methods, and physical simulation experiments, studying the pressure distribution patterns of complex interwell pressure systems under injection-production conditions and mapping formation pressure profiles under these conditions are crucial for analyzing well performance, guiding injection-production adjustments, and improving reservoir development outcomes. Summary of the Invention

[0004] The purpose of the present invention is to provide a method for judging the effectiveness of water injection in the injection-production coupling process of low permeability oil reservoirs, aiming to provide a method for intuitively reflecting the pressure distribution between oil and water wells and judging the effectiveness of oil wells during the water injection development of low permeability oil reservoirs, thereby guiding the adjustment of oil reservoir injection and production parameters and improving the development effect of low permeability oil reservoirs.

[0005] In order to achieve the above purpose, the technical solutions adopted are as follows:

[0006] A method for judging the effectiveness of water injection in a low permeability oil reservoir injection-production coupling process comprises the following steps:

[0007] S1, collect the rock porosity, permeability, relative permeability curve, oil-water viscosity, density, volume coefficient, compressibility, and comprehensive water content parameters at the oil and water well ends in the block, and calculate the fluid pressure conductivity coefficient at the oil and water well ends respectively;

[0008] S2, based on the core single-phase flow start-up pressure gradient experiment under different permeabilities and different fluid viscosities, obtain the actual core start-up pressure gradient scatter plot under different fluidities, and obtain the pressure gradient empirical formula through scatter plot regression; the fluidity is the ratio of the permeability to the fluid viscosity;

[0009] S3, using a reservoir engineering method or a pressure gauge monitoring method to obtain the bottom hole flow pressure of the oil and water wells; the bottom hole flow pressure of the water well is the sum of the injection pressure at the wellhead of the water well and the hydrostatic column pressure of the injected water;

[0010] S4, considering the starting pressure gradient of low permeability reservoirs, the micro-compressibility of the formation and fluids, improves the unstable radial seepage model between oil and water wells in an infinite formation with one source and one sink. Based on the seepage model, the pressure formulas for unstable seepage in the areas near the oil and water wells are established. The formation pressures in the areas near the oil and water wells are calculated respectively. If the oil and water wells have been fractured, the formation pressure near the front of the fracture is calculated.

[0011] S5, draw pressure profiles during the water well injection process and the oil well production process, the pressure profiles including a pressure rise curve 1 from the center of the oil well to the oil well wall with the oil well as the center; a pressure rise curve 2 from the oil well wall to the oil and water wells; the distance from the oil well wall to the oil and water wells does not exceed the oil well's maximum oil leakage radius; a pressure drop curve 3 from the center of the water well to the water well wall with the water well as the center; a pressure drop curve 4 from the water well wall to the oil and water wells; the distance from the water well wall to the oil and water wells does not exceed the water well's maximum liquid supply radius;

[0012] S6. Based on the pressure profiles between oil and water wells during the injection and production process, the oil well response characteristics are divided into four categories: no response, intermittent response, continuous response, and instant response. The classification rules are as follows:

[0013] The pressure profile between the water wells includes the water well's limit fluid supply radius relative to the oil well's limit oil drainage radius, and the pressure profile curve at this time indicates that the oil well is intermittently effective;

[0014] The maximum fluid supply radius of the water well is separated from the maximum oil drainage radius of the oil well, and after a round of coupled water injection, the water well pressure wave and front pressure P are less than 0.9 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is ineffective.

[0015] The water well's limit fluid supply radius intersects the oil well's limit oil drainage radius at a short distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are 0.9-1.1 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is intermittently effective.

[0016] The water well's limit fluid supply radius intersects the oil well's limit oil drainage radius over a long distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are 1.1-1.5 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well continues to be effective.

[0017] The maximum fluid supply radius of the water well intersects the maximum oil drainage radius of the oil well over a long distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are greater than 1.5 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is effective instantly.

[0018] According to the above scheme, in step S1, the fluid pressure conductivity coefficient at the oil well end is The water well end fluid pressure conductivity coefficient

[0019] Among them, C t1 =C o +C f ;

[0020] Where η o is the fluid pressure conductivity coefficient at the oil well end; K o is the effective permeability of the oil phase; K w is the effective permeability of the water phase; is the reservoir porosity; μ o is the underground viscosity of the oil phase; C t1 is the comprehensive compression coefficient at the oil well end; η w is the pressure conductivity coefficient of the fluid at the well end; μ w is the underground viscosity of formation water; C t2 is the comprehensive compression coefficient at the well end; C o is the crude oil compressibility coefficient; C f is the rock compression coefficient; S wi S is the bound water saturation; oi is the maximum oil saturation; C w is the formation water compressibility coefficient.

[0021] According to the above scheme, in step S1, the low permeability reservoir has a serious sensitivity effect. During the production and development process, the formation pressure at the oil well end drops. According to the reservoir stress sensitivity experiment, the true permeability K1 at the oil well end and the true permeability K2 at the water well end under the current pressure drop amplitude are calculated. The flow rate curve is calculated based on the collected well area relative permeability curve. The corresponding oil saturation in the relative permeability curve is found according to the comprehensive water content of the well area. The relative permeability K of the oil in the relative permeability curve is determined according to the corresponding water saturation. ro With K rw , the effective permeability of the oil phase is K o =K1·K ro , the effective permeability of water phase is K w =K2·K rw .

[0022] According to the above scheme, the core used to start the pressure gradient experiment in step S2 is a real core that reflects the permeability distribution of the reservoir, the crude oil uses a compound oil whose viscosity reflects the actual underground crude oil viscosity of the block, and the water phase uses the block formation water.

[0023] According to the above scheme, in step S2, the actual starting pressure of the core is the minimum starting pressure recorded by the pressure sensor when the first oil droplet emerges from the core outlet.

[0024] According to the above scheme, in step S3, the bottom hole flowing pressure of the oil well is obtained by using the reservoir engineering method, which includes the following steps:

[0025] (1) Calculate the oil well pump pressure P p =g / [(1 / β-1) / (1-f w )+S];

[0026] Where, P p is the pump port pressure; g is the gas-oil ratio, obtained through the fluid high-pressure physical property test; β is the pump filling coefficient; f w is the water content; S is the natural gas solubility coefficient, which is calculated according to the empirical formula;

[0027] (2) Calculate the density of the wellbore mixed liquid column d according to the empirical formula L =(0.8d o +0.01)×(1-f w )+0.95f w ;

[0028] Where, d L is the density of the mixed liquid column in the cylinder; d o is the underground crude oil density;

[0029] (3) Calculation of oil well bottom hole pressure P wf =(L m -L p ) / 100·d L +P p ;

[0030] Where, P wf is the bottom hole flowing pressure of the oil well; L m is the depth of the middle oil layer; L p Pump hanging depth.

[0031] According to the above scheme, the improved unstable radial seepage model between oil and water wells in an infinite formation with one source and one sink in step S4 has the following characteristics:

[0032] (1) The stratum is an infinite stratum of equal thickness and isotropy, in which only one well is producing and one well is injecting water;

[0033] (2) The fluid is unstable seepage and the seepage process is isothermal;

[0034] (3) The diameter of oil and water wells is very small compared to the entire formation, so they are considered as a point source and a point sink;

[0035] (4) The formation and liquid are slightly compressible, and the compressibility coefficient is constant.

[0036] According to the above solution, in step S4, the pressure formula for unstable seepage in the oil well and its fracture near-wellbore area is:

[0037]

[0038] Where, P e1 is the formation pressure near the oil well; P wf is the bottom hole flowing pressure of the oil well; q o Daily oil production of the oil well; h1 is the effective thickness of the perforated section of the oil well; t is the production time; r o is the radius of the oil well; S1 is the skin coefficient of the oil well; λ0 is the starting pressure gradient under the oil well reservoir conditions;

[0039] The pressure formula for unstable seepage in the well and its fracture near the wellbore area is:

[0040]

[0041] Where, P e2 P is the formation pressure near the wellbore; w is the bottom hole flow pressure of the injection well; q w The daily water injection volume of the well; h2 is the effective thickness of the perforated section of the well; t is the water injection time; r w is the radius of the well; S2 is the skin coefficient of the well; λ w is the starting pressure gradient under reservoir conditions of the water well.

[0042] According to the above solution, in step S5, the pressure rise curve 1 is calculated using the pressure formula of unstable seepage in the near-wellbore area of ​​the oil well;

[0043] The pressure rise curve 2 is based on the influence of the starting pressure during the seepage process of the low permeability reservoir fluid. The pressure loss will occur during pressure transmission. The starting pressure gradient λ1 of the fluid with the same viscosity as the oil phase at the reservoir permeability is used to represent the loss rate of the oil phase pressure drop;

[0044] The limit oil leakage radius

[0045] Where, R1 is the maximum oil drainage radius of the oil well; a1 and b1 are the correlation coefficients in the regression empirical formula of the oil phase starting pressure gradient; P e1 Formation pressure near the oil well; Pe1′ is the formation pressure at the maximum oil drainage radius.

[0046] According to the above scheme, in step S5, the pressure drop curve 3 is calculated by the pressure formula of unstable seepage in the near-well zone of the water well;

[0047] The pressure drop curve 4 is based on the fact that low permeability reservoirs are affected by the starting pressure during water flooding, and pressure loss occurs during pressure transmission. The starting pressure gradient λ2 of a fluid with a viscosity equivalent to that of the water phase at the reservoir permeability is used to represent the loss rate of water phase pressure drop.

[0048] The maximum liquid supply radius of the water well

[0049] Where R2 is the limit of the water supply radius of the well; a2 and b2 are the correlation coefficients in the empirical regression formula of the water phase starting pressure gradient; P e2 Formation pressure near the wellbore; P e2′ is the formation pressure at the maximum fluid supply radius.

[0050] According to the above scheme, in step S5, if the oil and water wells have been fractured, then the pressure rise curve 1 is from the center of the oil well to the front end of the oil well fracture, the pressure rise curve 2 is from the front end of the oil well fracture to the oil and water wells, and the distance between the front end of the oil well fracture and the oil and water wells does not exceed the maximum oil drainage radius of the oil well. The pressure drop curve 3 is from the center of the water well to the front end of the water well pressure fracture, and the pressure drop curve 4 is from the front end of the water well pressure fracture to the oil and water wells, and the distance between the front end of the water well pressure fracture and the oil and water wells does not exceed the maximum liquid supply radius of the water well.

[0051] Compared with the prior art, the present invention has the following beneficial effects:

[0052] This application provides a method for determining the effectiveness of water injection during the coupled injection-production process in low-permeability reservoirs. It measures the changes in formation pressure at any location between oil and water wells during the injection-production process, clarifies the effectiveness of the corresponding oil wells, and provides guidance for the preparation of adjustment plans for low-permeability reservoirs and the optimization of oil and water well spacing. This method can fully utilize the effect of water injection to increase formation pressure, rationally optimize water injection rates, reduce water injection costs, and optimize injection-production parameters and oil and water well spacing based on the effectiveness characteristics of the oil wells, thereby significantly improving block reserve utilization and oilfield development efficiency. BRIEF DESCRIPTION OF THE DRAWINGS

[0053] In order to more clearly illustrate the technical solutions of the implementation methods of the present application, the following is a brief introduction to the drawings required for use in the implementation methods. It should be understood that the following drawings only show certain embodiments of the present application and therefore should not be regarded as limiting the scope. For ordinary technicians in this field, other relevant drawings can be obtained based on these drawings without paying any creative work.

[0054] Figure 1 This is a flow chart for judging the effectiveness of water injection in low permeability reservoirs by improving the unstable seepage model of the present invention.

[0055] Figure 2 Graphs showing the phase permeability curve and fractional flow rate curve used in the examples.

[0056] Figure 3 This is the result of drawing the inter-well pressure profile of the test well group in the work area in the embodiment. DETAILED DESCRIPTION

[0057] To make the objectives, technical solutions, and advantages of the embodiments of the present application more clear, the technical solutions in the embodiments of the present application will be clearly and completely described below in conjunction with the accompanying drawings of the embodiments of the present application. Obviously, the described embodiments are only part of the embodiments of the present application, not all of the embodiments. Generally, the components of the embodiments of the present application described and shown in the drawings herein can be arranged and designed in various different configurations.

[0058] Therefore, the following detailed description of the embodiments of the present application provided in the accompanying drawings is not intended to limit the scope of the present application for protection, but merely represents selected embodiments of the present application. All other embodiments obtained by persons of ordinary skill in the art based on the embodiments in the present application without making any creative efforts shall fall within the scope of protection of the present application.

[0059] It should be noted that similar reference numerals and letters denote similar items in the following drawings, and therefore, once an item is defined in one drawing, it does not need to be further defined or explained in subsequent drawings.

[0060] In the description of this application, it should be noted that the terms "upper" and "lower" etc. indicate orientations or positional relationships based on the orientations or positional relationships shown in the accompanying drawings, or the orientations or positional relationships in which the invented product is usually placed when in use. These are only for the convenience of describing this application and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation. Therefore, they should not be understood as limitations on this application.

[0061] In addition, in this application, unless otherwise expressly specified or limited, the phrase "a first feature is above or below a second feature" may include the first and second features being in direct contact, or may include the first and second features being in contact not directly but through another feature between them. Furthermore, the phrases "above, above, and above the second feature" may include the first feature being directly above and obliquely above the second feature, or simply indicate that the first feature is higher in level than the second feature. The phrases "below, below, and below the second feature" may include the first feature being directly below and obliquely below the second feature, or simply indicate that the first feature is lower in level than the second feature.

[0062] Furthermore, terms such as "horizontal" and "vertical" do not necessarily mean that a component must be absolutely horizontal or overhanging, but rather that it can be slightly tilted. For example, "horizontal" simply means that its direction is more horizontal than "vertical," and does not mean that the structure must be completely horizontal, but rather that it can be slightly tilted.

[0063] It should also be noted that, in the description of this application, unless otherwise expressly specified or limited, the terms "disposed," "connected," and "connected" should be understood in a broad sense. For example, they can refer to fixed connections, detachable connections, or integral connections; mechanical connections or electrical connections; direct connections or indirect connections through an intermediate medium; and internal connections between two components. Those skilled in the art will understand the specific meanings of the above terms in this application based on the specific circumstances.

[0064] The specific embodiment provides a method for judging the effectiveness of water injection in low permeability reservoirs by improving the unstable seepage model. Figure 1 As shown, the specific steps include:

[0065] S1. Collect the rock porosity, permeability, relative permeability curve, oil-water viscosity, density, volume coefficient, compressibility, comprehensive water content and other parameters at the oil and water well ends in the block, and calculate the fluid pressure conductivity coefficient at the oil and water well ends respectively.

[0066] The rock porosity at the oil well end is 6.43%, and the original permeability is 0.8mD. The rock porosity at the water well end is 16.20%, and the original permeability is 20mD. After pressure sensitivity, the permeability at the oil well end is K1, which is 0.46mD. The water well end has no pressure sensitivity, and the permeability at the water well end is K2, which is 20mD. The phase permeability curve is as follows: Figure 2 As shown in curves a and b, the formation oil viscosity is 0.78 mPa·s, the water viscosity is 0.38 mPa·s, and the crude oil density is 0.78 g / cm 3 、The density of crude oil is 1.01g / cm 3 , crude oil volume coefficient is 1.16, water volume coefficient is 1.0, crude oil compressibility coefficient is 20.7×10 -4 MPa -1 , the formation water compressibility coefficient is 4.5×10 -4 MPa -1 According to the empirical formula, the rock compression coefficient is 8.5×10 -4 MPa -1 Parameters, comprehensive water content is 90%, according to the phase permeability curve morphology read bound water saturation is 0.33, the maximum oil saturation is 0.75, according to the collected well area phase permeability curve to calculate the flow curve as follows Figure 2As shown in curve c, the comprehensive water content is 50%. Find the corresponding water saturation of 0.42 in the phase permeability curve, and determine the relative permeability K of oil in phase permeability curves a and b based on the corresponding oil saturation. ro is 0.22, and the water relative permeability K rw is 0.05, and the effective permeability of the oil phase is K o =0.46·0.22=0.1mD, the effective permeability of the water phase is K w =20·0.05=1mD;

[0067] In step S1, the oil well fluid pressure conductivity coefficient The water well end fluid pressure conductivity coefficient

[0068] C t1 =C o +C f ;

[0069] Where η o is the fluid pressure conductivity coefficient at the oil well end; K o is the effective permeability of the oil phase; is the reservoir porosity; μ o is the underground viscosity of the oil phase; C t1 is the comprehensive compression coefficient at the oil well end; η w is the pressure conductivity coefficient of the fluid at the well end; μ w is the underground viscosity of formation water; C t2 is the comprehensive compression coefficient at the well end; C o is the crude oil compressibility coefficient; C f is the rock compression coefficient; S wi S is the bound water saturation; oi is the maximum oil saturation; C w is the formation water compressibility coefficient.

[0070] According to the pressure conductivity formula, the pressure conductivity of the fluid at the oil well end is 34078cm 2 / s, the fluid pressure conductivity coefficient at the well end is 98738cm 2 / s. ;

[0071] S2. Based on the core single-phase flow start-up pressure gradient experiment under different permeabilities and fluid viscosities, the actual core start-up pressure at different mobilities is obtained, and an empirical formula for the start-up pressure gradient at different mobilities is established;

[0072] In step S2, the core used in the startup pressure gradient experiment is a real core that reflects the permeability distribution of the reservoir. The crude oil used is a composite oil whose viscosity reflects the actual underground crude oil viscosity of the block. The water phase uses the block formation water. The real startup pressure of the core is the minimum startup pressure recorded by the pressure sensor when the first oil droplet emerges at the core outlet. The fluidity is the ratio of the core permeability to the viscosity of the fluid used in the experiment. The empirical formula for the startup pressure gradient under different fluidities is obtained by plotting a scatter plot of fluidity and the real startup pressure gradient through the startup pressure gradient experiment results, and the empirical formula for the pressure gradient is obtained through scatter plot regression.

[0073] In step S2, the empirical formula for the start-up pressure gradient regression obtained from the core experiment is: Calculate the starting pressure gradient at the oil well end of the target well area Starting pressure gradient at the well end

[0074] S3. Calculate the bottomhole flowing pressure of oil and water wells using reservoir engineering methods or pressure gauge monitoring methods;

[0075] In step S3, the bottom hole flowing pressure of the oil well is obtained using a reservoir engineering method, which includes the following steps:

[0076] (1) Calculate the oil well pump pressure P p =g / [(1 / β-1) / (1-f w )+S];

[0077] Where, P p is the pump port pressure; g is the gas-oil ratio, obtained through the fluid high-pressure physical property test; β is the pump filling coefficient; f w is the water content; S is the natural gas solubility coefficient, which is calculated according to the empirical formula;

[0078] (2) Calculate the density of the wellbore mixed liquid column d according to the empirical formula L =(0.8d o +0.01)×(1-f w )+0.95f w ;

[0079] Where, d L is the density of the mixed liquid column in the cylinder; d o is the underground crude oil density;

[0080] (3) Calculation of oil well bottom hole pressure P wf =(L m -L p ) / 100·d L +P p ;

[0081] Where, P wf is the bottom hole flowing pressure of the oil well; Lm is the depth of the middle oil layer; L p Pump hanging depth.

[0082] In step S3, the reservoir engineering method of this embodiment calculates the bottom hole flowing pressure of oil and water wells; the natural gas solubility coefficient S is 0.09m 3 / (m 3 MPa), oil well production before water injection q o 2.5m 3 / d, perforation thickness 1.5m, water well perforation thickness 4.5m, medium-depth L m The pump hanging depth is 3360m. p The pump filling coefficient β is only 0.2, and the oil well water content f w The skin coefficient of oil and water wells is -1, r0=r w The outer diameter is 139mm, according to P p =g / [(1 / β-1) / (1-f w )+S] to calculate the oil well pump pressure is 5.5MPa, according to d L =(0.8d o +0.01)×(1-f w )+0.95f w The density of the wellbore mixed liquid column was 0.77 g / cm 3 , according to P wf =(L m -L p ) / 100·d L +P p The calculated bottomhole pressure of the oil well is 9.8 MPa. After water injection, the dynamic liquid level reaches the wellhead, and the calculated bottomhole pressure is 25.6 MPa.

[0083] In step S3, the current injection pressure of the water injection well is 69 MPa, and the hydrostatic pressure is converted to 30.6 MPa according to the reservoir depth. The current bottom hole pressure of the water well is calculated to be 99.6 MPa.

[0084] S4. Considering the starting pressure gradient of low-permeability reservoirs and the micro-compressibility of the formation and fluids, an improved model of unstable radial flow between oil and water wells in an infinite formation with one source and one sink is developed. Based on the flow model, pressure formulas for unstable flow in the vicinity of the oil and water wells are established. The formation pressures in the vicinity of the oil and water wells are calculated. If the oil and water wells have been fractured, the calculated formation pressures in the vicinity of the oil and water wells and their fractures are used as the formation pressures.

[0085] The improved unstable radial seepage model between oil and water wells in an infinite formation with one source and one sink in step S4 has the following characteristics:

[0086] 1. The stratum is an infinite stratum of equal thickness and isotropy, in which only one well is producing and one well is injecting water;

[0087] 2. The fluid is unstable seepage and the seepage process is isothermal;

[0088] 3. The diameter of oil and water wells is very small compared to the entire formation, so they can be considered as a point source and a point sink;

[0089] 4. The formation and liquid are slightly compressible, and the compression coefficient is constant.

[0090] According to the above solution, in step S4, the pressure formula for unstable seepage in the oil well and its fracture near-wellbore area is:

[0091]

[0092] Where, P e1 is the formation pressure near the oil well; P wf is the bottom hole flowing pressure of the oil well; q o Daily oil production of the oil well; h1 is the effective thickness of the perforated section of the oil well; t is the production time; r o is the radius of the oil well; S1 is the skin coefficient of the oil well; λ0 is the starting pressure gradient under the oil well reservoir conditions;

[0093] The pressure formula for unstable seepage in the well and its fracture near the wellbore area is:

[0094]

[0095] Where, P e2 P is the formation pressure near the wellbore; w is the bottom hole flow pressure of the injection well; q w The daily water injection volume of the well; h2 is the effective thickness of the perforated section of the well; t is the water injection time; r w is the radius of the well; S2 is the skin coefficient of the well; λ w is the starting pressure gradient under reservoir conditions of the water well.

[0096] The values ​​of the parameters involved in the formula have been provided in the previous article. The difference between the formation pressure in the near-well area of ​​the oil well and the bottom hole pressure before water injection is calculated as P e1 -P wf is 2.1 MPa. According to the oil well bottom hole pressure P calculated above, wf is 9.8 MPa, and the calculated formation pressure P in the near-wellbore area of ​​the oil well is e1 The oil well production after water injection is 2.8m 3 / d, production pressure difference P e1 -P wfis 3.6 MPa, and the calculated formation pressure P in the near-wellbore area of ​​the oil well is e1 The daily water injection rate of the well is 600m 3 / d, calculate the difference between the formation pressure near the wellbore and the bottom hole pressure P w -P e2 =-8.6MPa, the formation pressure near the wellbore is calculated to be P e2 It is 91MPa.

[0097] S5, draw the pressure profile during the water well injection process and the oil well production process. The pressure profile includes the pressure rise curve 1 from the oil well center to the oil well wall; the pressure rise curve 2 from the oil well wall to the oil and water wells; the distance from the oil well wall to the oil and water wells does not exceed the oil well limit oil leakage radius; the pressure drop curve 3 from the water well center to the water well wall; the pressure drop curve 4 from the water well wall to the oil and water wells; the distance from the water well wall to the oil and water wells does not exceed the water well limit liquid supply radius; the water well bottom hole flow pressure P w The formation pressure near the wellbore wall is the formation pressure P in the area near the wellbore. e2 After a round of coupled water injection, the water well pressure wave reaches the front edge P, and the formation pressure near the oil well wall is the formation pressure in the oil well near the wellbore area P e1 , oil well bottom hole flowing pressure P wf .

[0098] According to the above scheme, in step S5, the formation pressure rise curve 1 within the range from the oil production well to the wellbore of the oil production well is calculated using the pressure formula of unstable seepage in the near-wellbore area of ​​the oil well;

[0099] The pressure rise curve 2 between the wellbore wall and the oil and water wells is based on the influence of the starting pressure during the seepage process of the low permeability reservoir fluid. The pressure loss will occur during pressure transmission. The starting pressure gradient λ1 of the fluid with the same viscosity as the oil phase at the reservoir permeability is used to represent the loss rate of the oil phase pressure drop;

[0100] The limit oil leakage radius

[0101] Where, R1 is the maximum oil drainage radius of the oil well; a1 and b1 are the correlation coefficients in the regression empirical formula of the oil phase starting pressure gradient; P e1 Formation pressure near the oil well; P e1′ is the formation pressure at the maximum oil drainage radius.

[0102] According to the above scheme, in step S5, the formation pressure drop curve 3 within the range from the injection well to the injection well wall is calculated using the pressure formula of unstable seepage in the vicinity of the well;

[0103] The pressure drop curve 4 between the injection well wall and the oil and water wells is based on the fact that low permeability oil reservoirs are affected by the starting pressure during water flooding, and pressure loss occurs during pressure transmission. The starting pressure gradient λ2 of a fluid with a viscosity equivalent to that of the water phase at the reservoir permeability is used to represent the loss rate of water phase pressure drop;

[0104] The maximum liquid supply radius of the water well

[0105] Where R2 is the limit of the water supply radius of the well; a2 and b2 are the correlation coefficients in the empirical regression formula of the water phase starting pressure gradient; P e2 Formation pressure near the wellbore; P e2′ is the formation pressure at the maximum fluid supply radius.

[0106] According to the start-up pressure gradient experiment, the water phase pressure drop loss rate is 0.19MPa / m, the distance between the oil and water wells is 340m, and the pressure loss during water injection is calculated to be 64.6MPa, and the formation pressure transmitted to the oil well wall is about 30.6MPa. According to the formula for the oil well's maximum oil drainage radius, the distance from the oil well wall to the oil and water wells is calculated to be 14m. The pressure profile between the oil and water wells is shown in the figure below. Figure 3 shown.

[0107] S6. Based on the pressure profiles between oil and water wells during the injection and production process, the oil well response characteristics are divided into four categories: no response, intermittent response, continuous response, and instant response. The classification rules are as follows:

[0108] The pressure profile between the water wells includes the water well's limit fluid supply radius relative to the oil well's limit oil drainage radius, and the pressure profile curve at this time indicates that the oil well is intermittently effective;

[0109] The maximum fluid supply radius of the water well is separated from the maximum oil drainage radius of the oil well, and after a round of coupled water injection, the water well pressure wave and front pressure P are less than 0.9 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is ineffective.

[0110] The water well's limit fluid supply radius intersects the oil well's limit oil drainage radius at a short distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are 0.9-1.1 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is intermittently effective.

[0111] The water well's limit fluid supply radius intersects the oil well's limit oil drainage radius over a long distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are 1.1-1.5 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well continues to be effective.

[0112] The water well's limit fluid supply radius intersects the oil well's limit oil drainage radius over a long distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are greater than 1.5 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is instantly effective.

[0113] In step S6, based on the drawn pressure profile between the oil and water wells, it is found that the water well pressure transmission radius intersects the oil well's maximum oil drainage radius at a short distance, and the water well pressure wave and front pressure P after one round of coupled water injection is 1.01 times the original formation pressure. The oil well's effectiveness is intermittent. According to the actual production situation of the oil well, the oil well's production before coupled water injection is 2.4m 3 / d, the oil well production after water injection is 2.8m 3 / d, the oil production increase is small, and the oil well effect is intermittent, which shows that this method has strong reliability.

[0114] In summary, this application provides a method for determining the effectiveness of water injection during the coupled injection-production process in low-permeability reservoirs. It identifies changes in formation pressure at any location between oil and water wells during the injection-production process, clarifies the effectiveness of corresponding oil wells, and provides guidance for the preparation of adjustment plans for low-permeability reservoirs and the optimization of oil and water well spacing. This method can fully utilize the effect of water injection to increase formation pressure, rationally optimize water injection volumes, reduce water injection costs, and optimize injection-production parameters and oil and water well spacing based on the effectiveness characteristics of oil wells, thereby significantly improving block reserve utilization and oilfield development efficiency.

[0115] The above description is merely a preferred embodiment of the present application and is not intended to limit the present application. Those skilled in the art will readily appreciate that various modifications and variations are possible. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present application shall be included within the scope of protection of the present application.

Claims

1. A method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir, characterized in that The following steps are involved: S1, collect the rock porosity, permeability, relative permeability curve, oil-water viscosity, density, volume coefficient, compressibility, and comprehensive water content parameters at the oil and water well ends in the block, and calculate the fluid pressure conductivity coefficient at the oil and water well ends respectively; S2, based on the core single-phase flow start-up pressure gradient experiment under different permeabilities and different fluid viscosities, obtain the actual core start-up pressure gradient scatter plot under different fluidities, and obtain the pressure gradient empirical formula through scatter plot regression; the fluidity is the ratio of the permeability to the fluid viscosity; S3, using a reservoir engineering method or a pressure gauge monitoring method to obtain the bottom hole flow pressure of the oil and water wells; the bottom hole flow pressure of the water well is the sum of the injection pressure at the wellhead of the water well and the hydrostatic column pressure of the injected water; S4, considering the starting pressure gradient of low permeability reservoirs, the micro-compressibility of the formation and fluid, improves the unstable radial seepage model between oil and water wells in an infinite formation with one source and one sink. Based on the seepage model, the pressure formulas for unstable seepage in the areas near the oil and water wells are established, and the formation pressures in the areas near the oil and water wells are calculated respectively; S5, draw pressure profiles during the water well injection process and the oil well production process, the pressure profiles including a pressure rise curve 1 from the center of the oil well to the oil well wall with the oil well as the center; a pressure rise curve 2 from the oil well wall to the oil and water wells; the distance from the oil well wall to the oil and water wells does not exceed the oil well's maximum oil leakage radius; a pressure drop curve 3 from the center of the water well to the water well wall with the water well as the center; a pressure drop curve 4 from the water well wall to the oil and water wells; the distance from the water well wall to the oil and water wells does not exceed the water well's maximum liquid supply radius; S6. Based on the pressure profiles between oil and water wells during the injection and production process, the oil well response characteristics are divided into four categories: no response, intermittent response, continuous response, and instant response. The classification rules are as follows: The pressure profile between the water wells includes the water well's limit fluid supply radius relative to the oil well's limit oil drainage radius, and the pressure profile curve at this time indicates that the oil well is intermittently effective; The water well's limit fluid supply radius is separated from the oil well's limit oil drainage radius, and after a round of coupled water injection, the water well pressure wave and front pressure P are less than 0.9 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is ineffective. The water well's limit fluid supply radius intersects the oil well's limit oil drainage radius at a short distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are 0.9-1.1 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is intermittently effective. The water well's limit fluid supply radius intersects the oil well's limit oil drainage radius over a long distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are 1.1-1.5 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well continues to be effective. The maximum fluid supply radius of the water well intersects the maximum oil drainage radius of the oil well over a long distance, and after a round of coupled water injection, the water well pressure wave and front pressure P are greater than 1.5 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is effective instantly.

2. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that In step S1, the oil well end fluid pressure conductivity coefficient The water well end fluid pressure conductivity coefficient Among them, C t1 =C o +C f ; Where η o is the fluid pressure conductivity coefficient at the oil well end; K o is the effective permeability of the oil phase; K w is the effective permeability of the water phase; is the reservoir porosity; μ o is the underground viscosity of the oil phase; C t1 is the comprehensive compression coefficient at the oil well end; η w is the pressure conductivity coefficient of the fluid at the well end; μ w is the underground viscosity of formation water; C t2 is the comprehensive compression coefficient at the well end; C o is the crude oil compressibility coefficient; C f is the rock compression coefficient; S wi S is the bound water saturation; oi is the maximum oil saturation; C w is the formation water compressibility coefficient.

3. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that In step S1, according to the reservoir stress sensitivity experiment, the true permeability K1 of the oil well end and the true permeability K2 of the water well end under the current pressure drop amplitude are obtained. The flow rate curve is calculated based on the collected well area relative permeability curve. The corresponding water saturation in the relative permeability curve is found according to the comprehensive water content of the well area. The relative permeability K of the oil in the relative permeability curve is determined according to the corresponding water saturation. ro With K rw , the effective permeability of the oil phase is K o =K1·K ro , the effective permeability of water phase is K w =K2·K rw .

4. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that The core used to start the pressure gradient experiment in step S2 is a real core that reflects the permeability distribution of the reservoir. The crude oil uses compound oil, whose viscosity reflects the actual underground crude oil viscosity of the block, and the water phase uses formation water in the block.

5. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that The actual starting pressure of the core in step S2 is the minimum starting pressure recorded by the pressure sensor when the first oil droplet emerges from the core outlet.

6. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that In step S3, the bottom hole flowing pressure of the oil well is obtained by using a reservoir engineering method, which includes the following steps: (1) Calculate the oil well pump pressure P p =g / [(1 / β-1) / (1-f w )+S]; Where, P p is the pump port pressure; g is the gas-oil ratio, obtained through the fluid high-pressure physical property test; β is the pump filling coefficient; f w is the water content; S is the natural gas solubility coefficient, which is calculated according to the empirical formula; (2) Calculate the density of the wellbore mixed liquid column d according to the empirical formula L =(0.8d o +0.01)×(1-f w )+0.95f w ; Where, d L is the density of the mixed liquid column in the cylinder; d o is the underground crude oil density; (3) Calculation of oil well bottom hole pressure P wf =(L m -L p ) / 100·d L +P p ; Where, P wf is the bottom hole flowing pressure of the oil well; L m is the depth of the middle oil layer; L p Pump hanging depth.

7. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that The improved unstable radial seepage model between oil and water wells in an infinite formation with one source and one sink in step S4 has the following characteristics: (1) The stratum is an infinite stratum of equal thickness and isotropy, in which only one well is producing and one well is injecting water; (2) The fluid is unstable seepage and the seepage process is isothermal; (3) The diameter of oil and water wells is very small compared to the entire formation and should be considered as a point source and a point sink; (4) The formation and liquid are slightly compressible, and the compressibility coefficient is constant.

8. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that In step S4, the pressure formula for unstable seepage in the oil well and its fracture near-wellbore area is: Where, P e1 is the formation pressure near the oil well; P wf is the bottom hole flowing pressure of the oil well; q o Daily oil production of the oil well; h1 is the effective thickness of the perforated section of the oil well; t is the production time; r o is the radius of the oil well; S1 is the skin coefficient of the oil well; λ0 is the starting pressure gradient under the oil well reservoir conditions; The pressure formula for unstable seepage in the well and its fracture near the wellbore area is: Where, P e2 P is the formation pressure near the wellbore; w is the bottom hole flow pressure of the injection well; q w The daily water injection volume of the well; h2 is the effective thickness of the perforated section of the well; t is the water injection time; r w is the radius of the well; S2 is the skin coefficient of the well; λ w is the starting pressure gradient under reservoir conditions of the water well.

9. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that In step S5, the pressure rise curve 1 is calculated using the pressure formula of unstable seepage in the near-wellbore area of ​​the oil well; The pressure rise curve 2 is based on the influence of the starting pressure during the seepage process of the low permeability reservoir fluid. The pressure loss will occur during pressure transmission. The starting pressure gradient λ1 of the fluid with the same viscosity as the oil phase at the reservoir permeability is used to represent the loss rate of the oil phase pressure drop; The limit oil leakage radius Where, R1 is the maximum oil drainage radius of the oil well; a1 and b1 are the correlation coefficients in the regression empirical formula of the oil phase starting pressure gradient; P e1 Formation pressure near the oil well; P e1′ is the formation pressure at the maximum oil drainage radius; If the oil and water wells have been fractured, the pressure rise curve 1 is from the center of the oil well to the front end of the oil well fracture, and the pressure rise curve 2 is from the front end of the oil well fracture to the oil and water wells. The distance from the front end of the oil well fracture to the oil and water wells does not exceed the maximum oil leakage radius of the oil well.

10. The method for judging the effectiveness of water injection in the injection-production coupling process of a low permeability oil reservoir according to claim 1, characterized in that In step S5, the pressure drop curve 3 is calculated using the pressure formula of unstable seepage in the near-well zone of the water well; The pressure drop curve 4 is based on the fact that low permeability reservoirs are affected by the starting pressure during water flooding, and pressure loss occurs during pressure transmission. The starting pressure gradient λ2 of a fluid with a viscosity equivalent to that of the water phase at the reservoir permeability is used to represent the loss rate of water phase pressure drop. The maximum liquid supply radius of the water well Where R2 is the limit of the water supply radius of the well; a2 and b2 are the correlation coefficients in the empirical regression formula of the water phase starting pressure gradient; P e2 Formation pressure near the wellbore; P e2′ is the formation pressure at the limit fluid supply radius; If the oil and water wells have been fractured, the pressure drop curve 3 is from the center of the water well to the front end of the water well pressure fracture, and the pressure drop curve 4 is from the front end of the water well pressure fracture to the oil and water wells. The distance from the front end of the water well pressure fracture to the oil and water wells does not exceed the maximum fluid supply radius of the water well.

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