A method for judging water injection effectiveness in injection-production coupling process of low-permeability oil reservoir

Abstract

The application discloses a method for judging water injection effectiveness in injection-production coupling process of low-permeability oil reservoirs, collects rock porosity, permeability, relative permeability curve, oil-water viscosity, density, volume coefficient, compression coefficient and comprehensive water cut parameters of oil and water well ends in a block, respectively calculates fluid pressure conductivity coefficients of the oil and water well ends, obtains core real starting pressure gradient scatter diagrams under different fluidity, obtains pressure gradient empirical formula through scatter diagram regression, obtains bottom hole flowing pressures of the oil and water wells, improves an unstable radial seepage model between the oil and water wells in an infinite formation with one source and one sink, establishes a pressure formula of unstable seepage in the near-wellbore zones of the oil and water wells, respectively calculates formation pressures in the near-wellbore zones of the oil and water wells, draws pressure profile diagrams in water injection processes of the water wells and oil production processes of the oil wells, and divides oil well response characteristics into four categories, i.e., no response, intermittent response, continuous response and instantaneous response, according to pressure profile diagram forms between the oil and water wells in the injection-production process.

Description

Technical Field

[0001] This invention belongs to the field of reservoir development technology, specifically relating to a method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs. Background Technology

[0002] Inter-well formation pressure distribution is one of the important development indicators in oilfield development. It is a crucial parameter for dynamic prediction and reserve calculation. However, during oil and gas field development, with the continuous progress of injection and production time and the constant changes in injection and production operating systems, formation pressure exhibits dynamic changes, uneven pressure distribution, and significant differences in pressure systems, making formation pressure prediction extremely difficult. There is an urgent need to establish an inter-well pressure calculation method suitable for considering the nonlinear seepage characteristics of low-permeability reservoirs, to analyze the pressure transmission from water wells to oil wells during water drive, and thus analyze the effectiveness of each corresponding oil well, thereby guiding the efficient adjustment of oil and water wells.

[0003] Currently, both domestically and internationally, density and sonic logging data are mainly used to predict reservoir formation pressure distribution using the equivalent depth method, but the accuracy needs improvement. Secondly, the main approach is to use shut-in well logging to measure pressure recovery curves, and then determine the average formation pressure using the MBH method, MDH method, Dietz method, and extended Muskat method. These methods require relevant pressure recovery data or are limited to quasi-steady-state conditions and long production times, inevitably introducing some errors. However, during oilfield development, excessively high inter-well formation pressure can lead to water flooding and increase injection pressure, thus increasing costs. Conversely, excessively low inter-well formation pressure cannot create a sufficient production pressure differential to drive oil flow from the reservoir to the bottom of the production well, and may even lead to three-phase flow, reducing the fluidity of the formation crude oil. Therefore, based on seepage mechanics theory, reservoir engineering methods, and physical simulation experiments, studying the pressure distribution law of complex inter-well pressure systems under injection-production conditions and mapping formation pressure profiles under these conditions is of great significance for analyzing well performance, guiding injection-production adjustments, and improving reservoir development effectiveness. Summary of the Invention

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

[0005] To achieve the above objectives, the following technical solution is adopted:

[0006] A method for determining the effectiveness of water injection during injection-production coupling in low-permeability reservoirs includes the following steps:

[0007] S1, collect parameters such as rock porosity, permeability, relative permeability curve, oil-water viscosity, density, volume index, compressibility index, and comprehensive water cut at the oil and water well ends within the block, and calculate the fluid pressure conductivity coefficients at the oil and water well ends respectively;

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

[0009] S3, the bottom-hole flowing pressure of oil and water wells is obtained using reservoir engineering methods or pressure gauge monitoring methods; the bottom-hole flowing pressure of the water well is the sum of the injection pressure at the wellhead and the static pressure of the injected water column;

[0010] S4. Considering the starting pressure gradient of low-permeability reservoirs, the microcompressibility of formation and fluid, improve 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, establish the pressure formula for unstable seepage in the near-wellbore zone of oil and water wells, and calculate the formation pressure in the near-wellbore zone of oil and water wells respectively. If the oil and water wells have been fractured, calculate the formation pressure near the fracture front.

[0011] S5. Draw pressure profile diagrams during the water injection process and oil production process of the oil well. The pressure profile includes the pressure rise curve 1 from the center of the oil well to the well wall; the pressure rise curve 2 from the well wall to the oil and water wells; the distance from the well wall to the oil and water wells does not exceed the oil well's limit drainage radius; the pressure drop curve 3 from the center of the water well to the well wall; the pressure drop curve 4 from the well wall to the oil and water wells; the distance from the well wall to the oil and water wells does not exceed the water well's limit fluid supply radius.

[0012] S6, based on the pressure profile of oil and water wells during the injection and production process, the effectiveness characteristics of oil wells are divided into four categories: ineffective, intermittently effective, continuously effective, and instantaneously effective; the classification rules are as follows:

[0013] The pressure profile shape between water wells includes the relative extreme fluid supply radius of the water well and the extreme oil discharge radius of the oil well. At this time, the pressure profile curve represents the intermittent effectiveness of the oil well.

[0014] When the water well's limit supply radius is different from the oil well's limit drainage radius, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P which is less than 0.9 times the original formation pressure, the pressure profile curve indicates that the oil well is ineffective.

[0015] The water well's limit supply radius and the oil well's limit drainage radius intersect at a short distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 supply radius and the oil well's limit drainage radius intersect at a considerable distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 water well's limit supply radius and the oil well's limit discharge radius intersect at a long distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 conductivity coefficient at the wellhead is... The fluid conductivity at the wellhead

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

[0020] In the formula, η o K is the fluid conductivity coefficient at the wellhead; o K represents the effective permeability of the oil phase. w The effective permeability of the aqueous phase; Reservoir porosity; μ o C represents the viscosity of the oil phase underground. t1 η is the comprehensive compressibility coefficient at the wellhead. w μ is the fluid conductivity coefficient at the wellhead. w C represents the viscosity of groundwater in the formation. t2 C is the comprehensive compressibility coefficient at the wellhead. o C is the crude oil compressibility coefficient. f S is the rock compressibility coefficient; wi The water saturation of the book is bound by water; S oi C represents the maximum oil saturation. w is the formation water compressibility coefficient.

[0021] According to the above scheme, in step S1, the low-permeability reservoir sensitivity effect is severe. During production and development, the formation pressure at the oil well tip decreases. Based on the reservoir stress sensitivity experiment, the true permeability K1 at the oil well tip and the true permeability K2 at the water well tip under the current pressure drop are determined. The flow rate curve is calculated based on the collected relative permeability curves of the well area. The corresponding oil saturation in the relative permeability curve is found based on the comprehensive water cut of the well area. The relative permeability K of oil in the relative permeability curve is determined based on 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 the aqueous phase is K. w =K2·K rw .

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

[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, the bottom hole flowing pressure of the oil well is obtained in step S3 using reservoir engineering methods, including the following steps:

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

[0026] In the formula, P p ρ is the pump inlet pressure; g is the gas-oil ratio, obtained through high-pressure fluid property testing; β is the pump filling coefficient; f w is the water content; S is the natural gas solubility coefficient, calculated using an empirical formula.

[0027] (2) Calculate the density d of the wellbore mixture column using empirical formulas. L =(0.8d o +0.01)×(1-f w )+0.95f w ;

[0028] In the formula, d L d is the density of the cylindrical mixture column; o Density of underground crude oil;

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

[0030] In the formula, P wf The bottom-hole flowing pressure of the oil well; L m L represents the middle depth of the oil layer. p Pump mounting depth.

[0031] According to the above scheme, the improved unsteady radial flow 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 infinitely large isotropic stratum of equal thickness, in which only one well is producing water and one well is injecting water.

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

[0034] (3) The diameter of oil and water wells is very small compared to the entire formation, and they should be treated as a source and a sink.

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

[0036] According to the above scheme, in step S4, the pressure formula for unsteady seepage in the oil well and its fracture near-wellbore zone is as follows:

[0037]

[0038] In the formula, P e1 P represents the formation pressure in the near-wellbore zone of the oil well. wf 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 Where S1 is the oil well radius; S1 is the oil well skin coefficient; λ0 is the starting pressure gradient under reservoir conditions.

[0039] The pressure formula for unstable seepage in the near-wellbore zone of the well and its fractures is as follows:

[0040]

[0041] In the formula, P e2 P represents the formation pressure near the wellbore. w The bottom flow pressure of the injection well; q w Daily water injection rate of the well; h2 is the effective thickness of the perforated section of the well; t is the water injection time; r w S2 is the radius of the well; S2 is the skin coefficient of the well; λ w To initiate a pressure gradient under water well reservoir conditions.

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

[0043] The pressure rise curve 2 is based on the influence of the starting pressure during the fluid seepage process in low-permeability reservoirs. Pressure loss will occur during pressure transmission. The starting pressure gradient λ1 of the fluid with similar viscosity to the oil phase under the reservoir permeability is used to represent the rate of pressure loss in the oil phase.

[0044] The limiting oil drain radius

[0045] In the formula, R1 is the ultimate drainage radius of the oil well; a1 and b1 are the correlation coefficients in the empirical formula for the regression of the oil phase initiation pressure gradient; P e1 Near-wellbore formation pressure; Pe1′ This represents the formation pressure at the ultimate oil drain radius.

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

[0047] The pressure drop curve 4 is based on the influence of the starting pressure on low-permeability reservoirs during water drive. Pressure loss will occur during pressure transmission. The starting pressure gradient λ2 of the fluid with viscosity comparable to that of water at reservoir permeability is used to represent the rate of pressure loss in the water phase.

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

[0049] In the formula, R2 is the ultimate fluid supply radius of the water well; a2 and b2 are the correlation coefficients in the empirical formula for the regression of the water phase start-up pressure gradient; P e2 Formation pressure near the wellbore; P e2′ This represents the formation pressure at the limit of the fluid supply radius.

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

[0051] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0052] This application provides a method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs. It tracks formation pressure changes at any location between oil and water wells during the injection-production process, clarifies the effectiveness of corresponding oil wells, and guides the development of adjustment plans and optimization of oil and water well spacing in low-permeability reservoirs. This method can fully utilize water injection to increase formation pressure, rationally optimize water injection volume, reduce water injection costs, and optimize injection-production parameters and oil-water well spacing based on oil well effectiveness characteristics, thereby significantly improving the utilization of reserves and the efficiency of oilfield development. Attached Figure Description

[0053] To more clearly illustrate the technical solutions of the embodiments of this application, the drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of this application and should not be regarded as a limitation of the scope. For those skilled in the art, other related drawings can be obtained from these drawings without creative effort.

[0054] Figure 1 This invention provides a flowchart for determining the effectiveness of water injection in low-permeability reservoirs using an improved unsteady flow model.

[0055] Figure 2 The diagram shows the relative permeability curve and the flow rate curve used in the embodiments.

[0056] Figure 3 The result of drawing the inter-well pressure profile of the test well group in the work area in the example. Detailed Implementation

[0057] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments. The components of the embodiments of this application described and shown in the accompanying drawings can typically be arranged and designed in various different configurations.

[0058] Therefore, the following detailed description of the embodiments of this application provided in the accompanying drawings is not intended to limit the scope of the claimed application, but merely to illustrate selected embodiments of the application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without inventive effort are within the scope of protection of this application.

[0059] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0060] In the description of this application, it should be noted that the terms "upper" and "lower" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, or the orientation or positional relationship in which the product of the invention is usually placed when in use. They are only used to facilitate the description of this application and to simplify the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this application.

[0061] Furthermore, in this application, unless otherwise expressly specified and limited, "above or below" the first feature may include direct contact between the first and second features, or contact between the first and second features through another feature between them. Moreover, "above," "over," and "on" the first feature includes the first feature directly above or diagonally above the second feature, or simply indicates that the first feature is at a higher horizontal level than the second feature. "Below," "below," and "under" the first feature includes the first feature directly below or diagonally below the second feature, or simply indicates that the first feature is at a lower horizontal level than the second feature.

[0062] Furthermore, terms such as "horizontal" and "vertical" do not imply that components must be absolutely horizontal or suspended, but rather that they 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 can be slightly tilted.

[0063] In the description of this application, it should also be noted that, unless otherwise expressly specified and limited, the terms "set up," "connected," and "linked" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this application based on the specific circumstances.

[0064] A specific implementation method provides an improved method for determining the effectiveness of water injection in low-permeability reservoirs using an unsteady flow model. The process is described in the appendix. Figure 1 As shown, the specific steps include:

[0065] S1. Collect parameters such as rock porosity, permeability, relative permeability curve, oil-water viscosity, density, volume coefficient, compressibility coefficient, and overall water cut of the oil and water wellheads in the collection block, and calculate the fluid conductivity coefficients at the oil and water wellheads respectively.

[0066] The rock porosity at the oil well tip is 6.43% and the original permeability is 0.8 mD, while the rock porosity at the water well tip is 16.20% and the original permeability is 20 mD. After pressure-sensitive treatment, the permeability at the oil well tip (K1) is 0.46 mD, while the permeability at the water well tip (K2) is 20 mD without pressure sensitivity. The relative permeability curves are shown below. Figure 2 Curves a and b show the formation oil viscosity as 0.78 mPa·s, water viscosity as 0.38 mPa·s, and crude oil density as 0.78 g / cm³. 3 The density of crude oil is 1.01 g / cm³. 3 The crude oil volume factor is 1.16, the water volume factor is 1.0, and the crude oil compressibility factor is 20.7 × 10⁻⁶. -4 MPa -1 The formation water compressibility coefficient is 4.5 × 10⁻⁶. -4 MPa -1 The rock compressibility coefficient was calculated to be 8.5 × 10⁻⁶ based on empirical formulas. -4 MPa -1 Parameters: Overall water cut 90%; based on the relative permeability curve morphology, bound water saturation is read as 0.33, maximum oil saturation as 0.75; based on the collected relative permeability curves of the well area, the flow distribution curve is calculated as follows. Figure 2As shown in curve c, the overall water content is 50%. Locate the corresponding water saturation of 0.42 in the relative permeability curves. Based on the corresponding oil saturation, determine the relative permeability K of oil in relative permeability curves a and b. ro The relative permeability of water, K, is 0.22. rw The effective permeability of the oil phase 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 aqueous phase is K w =20·0.05=1mD;

[0067] In step S1, the fluid conductivity coefficient at the wellhead The fluid conductivity at the wellhead

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

[0069] In the formula, η o K is the fluid conductivity coefficient at the wellhead; o The effective permeability of the oil phase; Reservoir porosity; μ o C represents the viscosity of the oil phase underground. t1 η is the comprehensive compressibility coefficient at the wellhead. w μ is the fluid conductivity coefficient at the wellhead. w C represents the viscosity of groundwater in the formation. t2 C is the comprehensive compressibility coefficient at the wellhead. o C is the crude oil compressibility coefficient. f S is the rock compressibility coefficient; wi The water saturation of the book is bound by water; S oi C represents the maximum oil saturation. w is the formation water compressibility coefficient.

[0070] The pressure conductivity coefficient of the fluid at the wellhead was calculated to be 34078 cm⁻¹ based on the pressure conductivity formula. 2 / s, the fluid conductivity at the wellhead is 98738cm. 2 / s. ;

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

[0072] In step S2, the core used for the starting pressure gradient experiment is a real core reflecting the permeability distribution of the reservoir. The crude oil used is a blended oil, whose viscosity reflects the actual underground crude oil viscosity of the block. The aqueous phase is the formation water of the block. The real starting pressure of the core is the minimum starting pressure recorded by the pressure sensor when the first oil droplet emerges at the core outlet. The mobility is the ratio of the core permeability to the viscosity of the fluid used in the experiment. The empirical formula for the starting pressure gradient under different mobility is obtained by plotting a scatter plot of mobility and real starting pressure gradient based on the starting pressure gradient experiment results, and by regression analysis of the scatter plot.

[0073] In step S2, the core experiment yielded the empirical formula for the regression of the initiation pressure gradient as follows: The starting pressure gradient at the wellhead of the target well area was calculated. Starting pressure gradient at the wellhead

[0074] S3. Calculate the bottom-hole 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 reservoir engineering methods, including the following steps:

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

[0077] In the formula, P p ρ is the pump inlet pressure; g is the gas-oil ratio, obtained through high-pressure fluid property testing; β is the pump filling coefficient; f w is the water content; S is the natural gas solubility coefficient, calculated using an empirical formula.

[0078] (2) Calculate the density d of the wellbore mixture column using empirical formulas. L =(0.8d o +0.01)×(1-f w )+0.95f w ;

[0079] In the formula, d L d is the density of the cylindrical mixture column; o Density of underground crude oil;

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

[0081] In the formula, P wf The bottom-hole flowing pressure of the oil well; Lm L represents the middle depth of the oil layer. p Pump mounting depth.

[0082] In step S3, the reservoir engineering method of this embodiment calculates the bottom hole flowing pressure of oil and water wells; the solubility coefficient S of natural gas is 0.09m. 3 / (m 3 • MPa), oil well production q before water injection o 2.5m 3 / d, perforation thickness 1.5m, water well perforation thickness 4.5m, oil reservoir medium-deep L m The depth of the pump is 3360m, and the pump mounting depth is L. p The well depth is 2790m, the pump fill factor β is only 0.2, and the water cut f in the well is... w The skin factor was 42% for both oil and water wells that were fracturing and put into production, with a skin factor of -1 for both. r0 = r w The outer diameter is 139mm, according to P p =g / [(1 / β-1) / (1-f w The calculated pressure at the oil well pump inlet is 5.5 MPa, based on d. L =(0.8d o +0.01)×(1-f w )+0.95f w The density of the wellbore mixed fluid column was 0.77 g / cm³. 3 According to P wf =(L m -L p ) / 100·d L +P p The calculated bottomhole flowing pressure of the oil well is 9.8 MPa. After water injection, the dynamic fluid level reaches the wellhead, and the calculated bottomhole flowing pressure is 25.6 MPa.

[0083] In step S3, the current injection pressure of the water injection well is 69 MPa, and the static water column pressure is calculated to be 30.6 MPa based on the reservoir depth. The calculated bottom flow pressure of the water well is 99.6 MPa.

[0084] S4. Considering the starting pressure gradient of low-permeability reservoirs, the microcompressibility of formation and fluids, improve 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, establish the pressure formula for unstable seepage in the near-wellbore zone of oil and water wells, and calculate the formation pressure in the near-wellbore zone of oil and water wells respectively. If the oil and water wells have been fractured, the calculated formation pressure in the near-wellbore zone of oil and water wells is the formation pressure near the oil and water wells and the fractures.

[0085] The improved unsteady radial flow model between oil and water wells in an infinite formation with one source and one sink, as described in step S4, has the following characteristics:

[0086] 1. The stratum is an infinitely large isotropic stratum of uniform thickness, in which only one well is producing water and another well is injecting water;

[0087] 2. The fluid is in an unsteady seepage flow, and the seepage process is isothermal;

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

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

[0090] According to the above scheme, in step S4, the pressure formula for unsteady seepage in the oil well and its fracture near-wellbore zone is as follows:

[0091]

[0092] In the formula, P e1 P represents the formation pressure in the near-wellbore zone of the oil well. wf 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 Where S1 is the oil well radius; S1 is the oil well skin coefficient; λ0 is the starting pressure gradient under reservoir conditions.

[0093] The pressure formula for unstable seepage in the near-wellbore zone of the well and its fractures is as follows:

[0094]

[0095] In the formula, P e2 P represents the formation pressure near the wellbore. w The bottom flow pressure of the injection well; q w Daily water injection rate of the well; h2 is the effective thickness of the perforated section of the well; t is the water injection time; r w S2 is the radius of the well; S2 is the skin coefficient of the well; λ w To initiate a pressure gradient under water well reservoir conditions.

[0096] The values ​​of all parameters involved in the formula have been provided above. The difference P between the formation pressure in the near-wellbore zone and the bottom-hole flowing pressure before water injection is calculated. e1 -P wf The pressure is 2.1 MPa, based on the wellbore bottom pressure P calculated earlier. wf The calculated formation pressure P in the near-wellbore zone is 9.8 MPa. e1 The pressure was 11.9 MPa, close to the 12.3 MPa measured by the well formation pressure monitoring before water injection; the well production after water injection was 2.8 m³ / s. 3 / d, Production pressure difference P e1 -P wfThe calculated formation pressure P in the near-wellbore zone is 3.6 MPa. e1 The pressure is 29.2 MPa. The daily water injection rate of the well is 600 m³. 3 / d, calculate the difference P between the formation pressure near the well and the bottom-hole flowing pressure. w -P e2 The calculated formation pressure near the wellbore is -8.6 MPa. e2 It is 91 MPa.

[0097] S5, Draw pressure profile diagrams during the water injection process and oil production process of the oil well. The pressure profile includes: 1. Pressure rise curve from the center of the oil well to the well wall (centered on the oil well); 2. Pressure rise curve from the well wall to the oil / water wells (the distance between the oil well wall and the oil / water wells does not exceed the oil well's limit drainage radius); 3. Pressure drop curve from the center of the water well to the well wall (centered on the water well); 4. Pressure drop curve from the well wall to the oil / water wells (the distance between the water well wall and the oil / water wells does not exceed the water well's limit fluid supply radius); and the bottom-hole flowing pressure P of the water well. w The formation pressure near the wellbore is the formation pressure P in the near-wellbore zone. e2 After a round of coupled water injection, the water well pressure wave reaches the leading edge P, and the formation pressure near the wellbore is the formation pressure P in the near-wellbore zone. e1 Oil well bottom pressure P wf .

[0098] According to the above scheme, in step S5, the formation pressure rise curve 1 within the range from the oil well to the well wall is calculated by the pressure formula of unstable seepage in the near-wellbore zone of the oil well.

[0099] The pressure rise curve 2 between the well wall of the oil well and the oil and water wells is based on the influence of the starting pressure during the fluid seepage process in low-permeability reservoirs. Pressure loss will occur during pressure transmission. The starting pressure gradient λ1 of the fluid with similar viscosity to the oil phase under the reservoir permeability is used to represent the rate of pressure loss in the oil phase.

[0100] The limiting oil drain radius

[0101] In the formula, R1 is the ultimate drainage radius of the oil well; a1 and b1 are the correlation coefficients in the empirical formula for the regression of the oil phase initiation pressure gradient; P e1 Near-wellbore formation pressure; P e1′ This represents the formation pressure at the ultimate oil drain 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 well wall is calculated using the pressure formula for unstable seepage in the near-well zone of the water well.

[0103] The pressure drop curve 4 between the injection well wall and the oil and water wells is based on the fact that the low-permeability reservoir is affected by the starting pressure during the water drive process, and pressure loss will occur during pressure transmission. The starting pressure gradient λ2 of the fluid with a viscosity comparable to that of water at the reservoir permeability is used to represent the rate of pressure loss in the water phase.

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

[0105] In the formula, R2 is the ultimate fluid supply radius of the water well; a2 and b2 are the correlation coefficients in the empirical formula for the regression of the water phase start-up pressure gradient; P e2 Formation pressure near the wellbore; P e2′ This represents the formation pressure at the limit of the fluid supply radius.

[0106] Based on the pressure gradient test, the pressure loss rate of the water phase is 0.19 MPa / m. With a well-to-water distance of 340 m, the calculated pressure loss during water injection is 64.6 MPa, and the formation pressure transmitted to the wellbore is approximately 30.6 MPa. Using the formula for the ultimate drainage radius of an oil well, the distance from the wellbore wall to the oil / water well is calculated to be 14 m. The resulting pressure profile between the oil and water wells is shown below. Figure 3 As shown.

[0107] S6, based on the pressure profile of oil and water wells during the injection and production process, the effectiveness characteristics of oil wells are divided into four categories: ineffective, intermittently effective, continuously effective, and instantaneously effective; the classification rules are as follows:

[0108] The pressure profile shape between water wells includes the relative extreme fluid supply radius of the water well and the extreme oil discharge radius of the oil well. At this time, the pressure profile curve represents the intermittent effectiveness of the oil well.

[0109] When the water well's limit supply radius is different from the oil well's limit drainage radius, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P which is less than 0.9 times the original formation pressure, the pressure profile curve indicates that the oil well is ineffective.

[0110] The water well's limit supply radius and the oil well's limit drainage radius intersect at a short distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 supply radius and the oil well's limit drainage radius intersect at a considerable distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 supply radius and the oil well's limit drainage radius intersect at a long distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is greater than 1.5 times the original formation pressure. At this time, the pressure profile curve indicates that the oil well is effective instantly.

[0113] In step S6, based on the drawn pressure profile between the oil and water wells, it is found that the pressure transmission radius of the water well intersects the ultimate oil drainage radius of the oil well at a short distance. Furthermore, after one round of coupled water injection, the water well pressure wave reaching the leading edge pressure P is 1.01 times the original formation pressure. The oil well's effectiveness is intermittent. Based on the actual production situation of the oil well, the production rate of the oil well before coupled water injection is 2.4 m³ / s. 3 / d, the oil well production after water injection is 2.8m 3 The oil production increase was small, and the oil wells showed intermittent effectiveness, indicating that this method has strong reliability.

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

[0115] The above description is merely a preferred embodiment of this application and is not intended to limit this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the protection scope of this application.

Claims

1. A method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs, characterized in that... Includes the following steps: S1, collect parameters such as rock porosity, permeability, relative permeability curve, oil-water viscosity, density, volume index, compressibility index, and comprehensive water cut at the oil and water well ends within the block, and calculate the fluid pressure conductivity coefficients at the oil and water well ends respectively; S2, Based on the single-phase flow start-up pressure gradient experiment of core under different permeabilities and fluid viscosities, obtain the scatter plot of the actual start-up pressure gradient of core under different mobility, and obtain the empirical formula of pressure gradient by regression of the scatter plot; the mobility is the ratio of the permeability to the fluid viscosity; S3, the bottom-hole flowing pressure of oil and water wells is obtained using reservoir engineering methods or pressure gauge monitoring methods; the bottom-hole flowing pressure of the water well is the sum of the injection pressure at the wellhead and the static pressure of the injected water column; S4. Considering the starting pressure gradient of low-permeability reservoirs, the microcompressibility of formation and fluid, an improved unstable radial seepage model between oil and water wells in an infinite formation with one source and one sink is established. Based on the seepage model, pressure formulas for unstable seepage in the near-wellbore zone of oil and water wells are established, and formation pressure in the near-wellbore zone of oil and water wells is calculated respectively. S5. Draw pressure profile diagrams during the water injection process and oil production process of the oil well. The pressure profile includes the pressure rise curve 1 from the center of the oil well to the well wall; the pressure rise curve 2 from the well wall to the oil and water wells; the distance from the well wall to the oil and water wells does not exceed the oil well's limit drainage radius; the pressure drop curve 3 from the center of the water well to the well wall; the pressure drop curve 4 from the well wall to the oil and water wells; the distance from the well wall to the oil and water wells does not exceed the water well's limit fluid supply radius. S6, based on the pressure profile of oil and water wells during the injection and production process, the effectiveness characteristics of oil wells are divided into four categories: ineffective, intermittently effective, continuously effective, and instantaneously effective; the classification rules are as follows: The pressure profile shape between water wells includes the relative extreme fluid supply radius of the water well and the extreme oil discharge radius of the oil well. At this time, the pressure profile curve represents the intermittent effectiveness of the oil well. When the water well's limit supply radius is different from the oil well's limit drainage radius, and after one round of coupled water injection, the water well pressure wave front pressure P is less than 0.9 times the original formation pressure, the pressure profile curve indicates that the oil well is ineffective. The water well's limit supply radius and the oil well's limit drainage radius intersect at a short distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 supply radius and the oil well's limit drainage radius intersect at a considerable distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 water well's limit supply radius and the oil well's limit discharge radius intersect at a long distance, and after one round of coupled water injection, the water well pressure wave reaches the leading edge pressure P, which is 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 determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... In step S1, the fluid conductivity coefficient at the wellhead The fluid conductivity at the wellhead Among them, C t1 =C o +C f ; In the formula, η o K is the fluid conductivity coefficient at the wellhead; o K represents the effective permeability of the oil phase. w The effective permeability of the aqueous phase; Reservoir porosity; μ o C represents the viscosity of the oil phase underground. t1 η is the comprehensive compressibility coefficient at the wellhead. w μ is the fluid conductivity coefficient at the wellhead. w C represents the viscosity of groundwater in the formation. t2 C is the comprehensive compressibility coefficient at the wellhead. o C is the crude oil compressibility coefficient. f S is the rock compressibility coefficient; wi The water saturation of the book is bound by water; S oi C represents the maximum oil saturation. w is the formation water compressibility coefficient.

3. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... In step S1, based on reservoir stress sensitivity experiments, the true permeability K1 at the oil well end and the true permeability K2 at the water well end under the current pressure drop are determined. The flow rate curve is calculated based on the collected relative permeability curves of the well area. The corresponding water saturation in the relative permeability curve is found based on the overall water cut of the well area. The relative permeability K of oil in the relative permeability curve is then determined based on 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 the aqueous phase is K. w =K2·K rw .

4. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... In step S2, the core used to initiate the pressure gradient experiment is a real core that reflects the permeability distribution of the reservoir. The crude oil used is a blended oil, whose viscosity reflects the actual underground crude oil viscosity of the block. The water phase is the formation water of the block.

5. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... 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.

6. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... Step S3 involves obtaining the bottom hole flowing pressure of the oil well using reservoir engineering methods, including the following steps: (1) Calculate the oil well pump inlet pressure P p =g / [(1 / β-1) / (1-f w )+S]; In the formula, P p ρ is the pump inlet pressure; g is the gas-oil ratio, obtained through high-pressure fluid property testing; β is the pump filling coefficient; f w is the water content; S is the natural gas solubility coefficient, calculated using an empirical formula. (2) Calculate the density d of the wellbore mixture column using empirical formulas. L =(0.8d o +0.01)×(1-f w )+0.95f w ; In the formula, d L d is the density of the cylindrical mixture column; o Density of underground crude oil; (3) Calculate the bottom flow pressure P of the oil well. wf =(L m -L p ) / 100·d L +P p ; In the formula, P wf The bottom-hole flowing pressure of the oil well; L m L represents the middle depth of the oil layer. p Pump mounting depth.

7. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... The improved unsteady radial flow 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 infinitely large isotropic stratum of equal thickness, in which only one well is producing water and one well is injecting water. (2) The fluid is in an unstable seepage flow, and the seepage process is isothermal; (3) The diameter of oil and water wells is very small compared to the entire formation, and they should be treated as a source and a sink. (4) The formation and the liquid are slightly compressible, and the compressibility coefficient is constant.

8. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... In step S4, the pressure formula for unsteady seepage in the oil well and its fractured near-wellbore zone is as follows: In the formula, P e1 P represents the formation pressure in the near-wellbore zone of the oil well. wf 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 Where S1 is the oil well radius; S1 is the oil well skin coefficient; λ0 is the starting pressure gradient under reservoir conditions. The pressure formula for unstable seepage in the near-wellbore zone of the well and its fractures is as follows: In the formula, P e2 P represents the formation pressure near the wellbore. w The bottom flow pressure of the injection well; q w Daily water injection rate of the well; h2 is the effective thickness of the perforated section of the well; t is the water injection time; r w S2 is the radius of the well; S2 is the skin coefficient of the well; λ w To initiate a pressure gradient under water well reservoir conditions.

9. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... In step S5, the pressure rise curve 1 is calculated using the pressure formula for unstable seepage in the near-wellbore zone of the oil well; The pressure rise curve 2 is based on the influence of the starting pressure during the fluid seepage process in low-permeability reservoirs. Pressure loss will occur during pressure transmission. The starting pressure gradient λ1 of the fluid with similar viscosity to the oil phase under the reservoir permeability is used to represent the rate of pressure loss in the oil phase. The limiting oil drain radius In the formula, R1 is the ultimate drainage radius of the oil well; a1 and b1 are the correlation coefficients in the empirical formula for the regression of the oil phase initiation pressure gradient; P e1 Near-wellbore formation pressure; P e1′ This represents the formation pressure at the ultimate oil drainage radius. If the oil and water wells have been fractured, then pressure rise curve 1 is from the center of the oil well to the front end of the oil well fracture, and 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 oil well's limit drainage radius.

10. The method for determining the effectiveness of water injection during the injection-production coupling process in low-permeability reservoirs as described in claim 1, characterized in that... In step S5, the pressure drop curve 3 is calculated using the pressure formula for unstable seepage in the near-wellbore zone of the water well; The pressure drop curve 4 is based on the influence of the starting pressure on low-permeability reservoirs during water drive. Pressure loss will occur during pressure transmission. The starting pressure gradient λ2 of the fluid with viscosity comparable to that of water at reservoir permeability is used to represent the rate of pressure loss in the water phase. The maximum fluid supply radius of the water well In the formula, R2 is the ultimate fluid supply radius of the water well; a2 and b2 are the correlation coefficients in the empirical formula for the regression of the water phase start-up pressure gradient; P e2 Formation pressure near the wellbore; P e2′ This refers to the formation pressure at the limit of the fluid supply radius; If the oil and water wells have been fracturing, then pressure drop curve 3 is from the center of the water well to the front end of the water well pressure fracture, and 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 water well's limit fluid supply radius.

Images