Oil well reverse displacement synergistic transformation injection parameter and crack parameter optimization method

Abstract

The invention provides an oil well reverse displacement synergistic transformation injection parameter and fracture parameter optimization method, and belongs to the technical field of oil reservoir yield increase, and the method comprises the following steps: 1, selecting a low-yield and low-efficiency oil well in an oil reservoir target area; 2, determining a reasonable formation pressure maintaining level in combination with formation conditions; step 3, determining the injection amount of the synergistic flooding oil by applying the result of the step 2; step 4, optimizing the concentration of a surfactant in the synergistic oil displacement liquid; 5, determining the soaking time of the oil well; and 6, determining crack parameters of the low-viscosity synergistic oil displacement transformation stage and the guanidine gum sand-carrying fracturing transformation stage, wherein the crack parameters comprise the crack supporting height, the crack half length and the crack flow conductivity. The method can be widely applied to oil well reverse displacement synergistic transformation process design, and by means of design optimization of synergistic displacement oil injection parameters and fracture parameters, the formation pressure can be effectively increased, the reservoir seepage condition can be improved, the oil displacement efficiency can be improved, and the single well yield and recovery efficiency after transformation can be improved.

Description

Technical Field

[0001] The invention relates to the technical field of oil reservoir production enhancement, and in particular to a method for optimizing injection parameters and fracture parameters of an oil well reverse displacement efficiency enhancement transformation. Background Art

[0002] Generally, fracturing is used to increase initial production, but the production increase effect after fracturing of low-formation energy wells cannot be guaranteed. If there is no water injection well to supplement energy after oil well fracturing or the water injection is ineffective, the production will decrease rapidly and the recovery rate will be low. Although an effective displacement relationship can be established between injection and production wells by increasing water injection wells and shortening the injection-production well spacing, it is difficult to establish a reasonable injection-production well network or the cost of establishing it is too high due to limitations such as formation conditions, reserve scale, well network mode, and special offshore operating conditions, resulting in poor economic efficiency.

[0003] A reverse displacement efficiency-enhancing transformation process has been developed for low-yield and low-efficiency oil wells that have no injection-production relationship or poor injection-production efficiency, have a large decline in liquid production, and are in urgent need of energy replenishment. Before the sand fracturing construction, a large amount of efficiency-enhancing oil-displacing fluid is injected in a short period of time at a large displacement and super-fracture pressure, and the well is kept awake for a period of time. By replenishing formation energy, forming a micro-crack network, imbibing and replacing residual oil in micropores, and improving the displacement efficiency of residual oil, the effect of sand fracturing is enhanced, which greatly increases the initial production of the oil well, reduces the decline rate, and effectively improves the recovery rate. At present, the production-enhancing transformation of offshore reservoirs is easy to promote on a large scale.

[0004] According to the principle of reverse displacement efficiency enhancement, the injection volume of the efficiency enhancement oil displacement fluid, the concentration of the surfactant, the time of the well shut-in, and the design optimization of the optimal fracture parameters in the oil displacement fluid stage and the sand-carrying fluid stage are extremely critical. The reverse displacement efficiency enhancement technology for offshore oil wells is still in the experimental and initial stages. The design and optimization process of various parameters is not systematic. It often adopts the method of analogy with onshore oil field design parameters or determines parameters according to on-site construction capabilities. It cannot provide a scientific design basis and a systematic parameter quantification process, which affects the rationality of the design and also increases the difficulty of implementation effect and parameter evaluation. To this end, a method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells was invented. Summary of the invention

[0005] In view of this, the present invention aims to propose a method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells, which can solve the problems of unclear methods, unsystematic optimization process and arbitrary parameter values ​​in the process of injection parameter and fracture parameter design optimization, and provide new methods and ideas for parameter design optimization.

[0006] To achieve the above object, the technical solution of the present invention is implemented as follows: a method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells, comprising the following steps:

[0007] Step 1, selecting low-yield and low-efficiency oil wells in the target area of ​​the reservoir;

[0008] Step 2, determining a reasonable formation pressure maintenance level based on formation conditions;

[0009] Step 3, applying the result of step 2 to determine the injection amount of the enhanced oil displacement fluid;

[0010] Step 4, optimizing the concentration of surfactant in the synergistic oil displacement fluid;

[0011] Step 5, determining the well shut-in time of the oil well;

[0012] Step 6, determine the fracture parameters in the low-viscosity enhanced oil displacement fluid reconstruction stage and the guar gum sand fracturing reconstruction stage, including fracture support height, fracture half-length, and fracture conductivity.

[0013] Furthermore, step 1 includes, based on the structural characteristics of the reservoir, reservoir physical properties, driving type, reservoir pressure level, remaining reserve basis, and current well network conditions, selecting low-yield and low-efficiency oil wells with no injection-production relationship or poor injection-production efficiency, large liquid production decline, well conditions that meet the conditions for reverse displacement efficiency improvement, and urgent need for energy replenishment in closed and semi-closed reservoirs with fault blocks or lithological boundaries, poor reservoir physical properties, and undeveloped edge and bottom water.

[0014] Furthermore, in step 2, the following formula is used to calculate the reasonable formation pressure maintenance level:

[0015] ηs=130.4·K0-0.1258

[0016] Among them, η s To maintain a reasonable formation pressure level, %, K0 is the formation permeability, mD.

[0017] Furthermore, in step 3, the current formation pressure is obtained, and the difference in formation pressure change required to reach the reasonable formation pressure maintenance level calculated in step 2 is determined, and the required injection amount of the enhanced oil displacement fluid is calculated using numerical simulation methods and reservoir engineering methods;

[0018] The required difference in formation pressure change is calculated using the following formula:

[0019] ΔP=η s ·P i -P p

[0020] Where ΔP is the formation pressure change difference, MPa, η s To maintain a reasonable formation pressure level, %, P i is the original formation pressure, MPa, P p is the current formation pressure, MPa.

[0021] Furthermore, the numerical simulation method for determining the injection amount of the enhanced oil displacement fluid includes the following steps:

[0022] Step 31, establishing a numerical model of the target area reservoir and completing history matching;

[0023] Step 32, simulating the formation pressure at the end of injection under different injection volume conditions;

[0024] Step 33, simulating the oil production under different injection rates when the well is opened after being shut in for 10 days and under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0025] Furthermore, the reservoir engineering method uses the material balance formula to calculate the injection amount of the enhanced oil displacement fluid;

[0026] The formula for determining the well control limit radius is as follows:

[0027]

[0028] Among them, R e is the well control limit radius, m, P e is the formation supply boundary pressure, MPa, P wf is the bottom hole flowing pressure of the oil well, MPa, μ is the underground viscosity of the fluid, mPa·s, K is the formation permeability, mD;

[0029] The formula for determining the injection amount of the enhanced oil displacement fluid is as follows:

[0030]

[0031] Where V is the injection volume of the enhanced oil displacement fluid, m 3 , C o is the crude oil compressibility coefficient, MPa -1 , C w is the formation water compressibility coefficient, MPa -1 , C f is the rock compression coefficient, MPa -1 , S wi is the bound water saturation, a decimal, R e is the well control limit radius, m, H is the oil layer thickness, m, Φ is the formation porosity, a decimal, and ΔP is the formation pressure change difference, MPa.

[0032] Further, in step 4, the surfactant in the synergistic oil displacement fluid can reduce the oil / water interfacial tension and the water contact angle on the rock surface. The numerical simulation method is used to optimize the concentration of the surfactant in the synergistic oil displacement fluid by taking the cumulative oil enhancement effect as the evaluation index. Step 4 includes the following steps:

[0033] Step 41, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid as the initial injection condition;

[0034] Step 42, the effect of surfactant concentration on oil displacement efficiency is approximately treated as a change in the oil-water relative permeability curve, and relative permeability curves under different surfactant concentration distributions are interpolated and imported into the numerical model;

[0035] Step 43, simulating the same injection volume of oil displacement fluid, opening the well after shutting down for 10 days, and the oil production under different surfactant concentration conditions under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0036] Furthermore, in step 5, the well shut-in after transformation can not only promote the balanced improvement of formation energy in the well-controlled area, but also improve the sweep range and imbibition replacement effect of the enhanced oil displacement fluid in the well-controlled area. The empirical analogy method and numerical simulation method are used to determine the well shut-in time.

[0037] Furthermore, the empirical analogy method is to determine that the shut-in time for a reservoir with a permeability of 10mD-30mD is 6d-10d by analogy with the reservoir geological conditions and construction examples of the reverse displacement efficiency enhancement process implemented offshore. During the on-site shut-in process, the wellhead pressure is monitored and the shut-in is terminated when the shut-in pressure drop is less than 0.5MPa / day.

[0038] The numerical simulation method for determining the shut-in time includes the following steps:

[0039] Step 51, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid and the surfactant concentration as initial injection conditions;

[0040] Step 52, simulating the oil production under different shut-in times when the same oil displacement fluid injection volume, surfactant concentration, and well shut-in conditions are used, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0041] Furthermore, in step 6, a numerical simulation method is used to design and optimize fracture parameters with cumulative oil enhancement effect as an evaluation index. Step 6 includes the following steps:

[0042] Step 61, based on the reservoir numerical model established in step 3, setting the same oil displacement fluid injection volume, surfactant concentration, well shut-in condition, and well shut-in time as simulation conditions;

[0043] Step 62, determining the crack height according to the reconstruction requirements and the layer and section selection results;

[0044] Step 63, when simulating the same fracture height and conductivity, determine the cumulative oil increase effect under different fracture half-length conditions in the low-viscosity enhanced oil displacement fluid transformation stage and the guar gum sand fracturing transformation stage, and compare and optimize the parameters in combination with the distance from the fault in the fracture direction and the sand body scale;

[0045] Step 64, simulating the same fracture height and fracture half length, determining the cumulative oil increase effect under different fracture conductivity conditions in the guar gum sand fracturing stage, and performing parameter comparison and optimization;

[0046] Among them, in step 63, the setting of the half-length of the fracture in the fracture extension direction needs to be smaller than the distance between the oil well and the fault. When there is a water injection well in the same layer in the fracture extension direction, the setting of the half-length of the fracture needs to be smaller than half of the distance between the oil and water wells.

[0047] Compared with the prior art, the method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells described in the present invention has the following advantages:

[0048] (1) The method of designing the injection amount of the enhanced oil displacement fluid by using the reservoir engineering method in the method of the present invention has good operability, and the various reservoir parameters used in the design process are easy to obtain. The accuracy is further improved by combining the numerical simulation method. It has been applied in the design of the reverse displacement efficiency enhancement process of offshore oil wells, is easy to promote, and solves the problems of strong arbitrariness in the selection of design parameters and long optimization cycle;

[0049] (2) The method of the present invention is aimed at low-yield and low-efficiency oil wells with no injection-production relationship or poor injection-production efficiency, large decrease in liquid production, and urgent need for energy supplementation. The method adopts reservoir engineering methods, numerical simulation methods, and empirical analogy methods to determine the design and optimization method of the combination of the injection amount of the efficiency-enhancing oil displacement fluid, the concentration of the surfactant, the well shut-in time, and the artificial fracture parameters, thereby improving the systematic and scientific nature of the design and providing a new method and idea for the promotion and application of reverse displacement efficiency enhancement in oil wells;

[0050] (3) The method described in the present invention can be widely used in the design of oil well reverse displacement efficiency enhancement process. Through the design and optimization of the injection parameters of the efficiency-enhancing oil displacement fluid and the fracture parameters, the formation pressure can be effectively increased, the reservoir seepage conditions can be improved, the oil displacement efficiency can be improved, and the single well production and recovery rate after the transformation can be increased. BRIEF DESCRIPTION OF THE DRAWINGS

[0051] The accompanying drawings constituting a part of the present invention are used to provide a further understanding of the present invention. The exemplary embodiments of the present invention and their descriptions are used to explain the present invention and do not constitute an improper limitation of the present invention. In the accompanying drawings:

[0052] Figure 1 This is a flow chart of the injection parameter and fracture parameter optimization method for reverse displacement efficiency enhancement of oil wells. DETAILED DESCRIPTION

[0053] It should be noted that, in the absence of conflict, the embodiments of the present invention and the features in the embodiments may be combined with each other.

[0054] The present invention will be described in detail below with reference to the accompanying drawings and in conjunction with embodiments.

[0055] like Figure 1 As shown, the present invention is a method for optimizing injection parameters and fracture parameters of oil well reverse displacement efficiency enhancement transformation, comprising the following steps:

[0056] Step 1, select low-yield and low-efficiency oil wells in the target area of ​​the reservoir; specifically, based on the structural characteristics of the reservoir, reservoir physical properties, driving type, reservoir pressure level, remaining reserve basis, and current well network conditions, select low-yield and low-efficiency oil wells with no injection-production relationship or poor injection-production efficiency, large liquid production decline, well conditions that meet the conditions for reverse displacement efficiency improvement, and urgent need for energy replenishment in the remaining oil enrichment target area of ​​fault blocks or closed and semi-closed reservoirs with lithological boundaries, poor reservoir physical properties, and undeveloped edge and bottom water.

[0057] Step 2: Determine the reasonable formation pressure maintenance level based on the formation conditions; use the following formula to calculate the reasonable formation pressure maintenance level:

[0058] ηs=130.4·K0-0.1258

[0059] Among them, η s To maintain a reasonable formation pressure level, %, K0 is the formation permeability, mD.

[0060] Step 3, applying the result of step 2 to determine the injection amount of the enhanced oil displacement fluid;

[0061] Obtain the current formation pressure, determine the difference in formation pressure change required to achieve the reasonable formation pressure maintenance level calculated in step 2, and use numerical simulation methods and reservoir engineering methods to calculate the required injection volume of the enhanced oil recovery fluid. The method of using reservoir engineering methods to design the injection volume of the enhanced oil recovery fluid has good operability, and the various reservoir parameters used in the design process are easy to obtain. Combined with numerical simulation methods, the accuracy is further improved.

[0062] The required difference in formation pressure change is calculated using the following formula:

[0063] ΔP=η s ·P i -P p

[0064] Where ΔP is the formation pressure change difference, MPa, η s To maintain a reasonable formation pressure level, %, P i is the original formation pressure, MPa, Pp is the current formation pressure, MPa.

[0065] The numerical simulation method for determining the injection amount of the enhanced oil displacement fluid includes the following steps:

[0066] Step 31, establishing a numerical model of the target area reservoir and completing history matching;

[0067] Step 32, simulating the formation pressure at the end of injection under different injection volume conditions;

[0068] Step 33, simulating the oil production under different injection rates when the well is opened after being shut in for 10 days and under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0069] The reservoir engineering method uses the material balance formula to calculate the injection volume of the enhanced oil displacement fluid;

[0070] The formula for determining the well control limit radius is as follows:

[0071]

[0072] Among them, R e is the well control limit radius, m, P e is the formation supply boundary pressure, MPa, P wf is the bottom hole flowing pressure of the oil well, MPa, μ is the underground viscosity of the fluid, mPa·s, K is the formation permeability, mD;

[0073] The formula for determining the injection amount of the enhanced oil displacement fluid is as follows:

[0074]

[0075] Where V is the injection volume of the enhanced oil displacement fluid, m 3 , C o is the crude oil compressibility coefficient, MPa -1 , C w is the formation water compressibility coefficient, MPa -1 , C f is the rock compression coefficient, MPa -1 , S wi is the bound water saturation, a decimal, R e is the well control limit radius, m, H is the oil layer thickness, m, Φ is the formation porosity, a decimal, and ΔP is the formation pressure change difference, MPa.

[0076] Step 4, optimizing the concentration of surfactant in the synergistic oil displacement fluid;

[0077] The surfactant in the enhanced oil displacement fluid can reduce the oil / water interfacial tension and the water contact angle on the rock surface. The main evaluation index is the improvement of oil displacement efficiency. The numerical simulation method is used to optimize the surfactant concentration in the enhanced oil displacement fluid with the cumulative oil enhancement effect as the evaluation index, including the following steps:

[0078] Step 41, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid as the initial injection condition;

[0079] Step 42, the effect of surfactant concentration on oil displacement efficiency is approximately treated as a change in the oil-water relative permeability curve, and relative permeability curves under different surfactant concentration distributions are interpolated and imported into the numerical model;

[0080] Step 43, simulating the same injection volume of oil displacement fluid, opening the well after shutting down for 10 days, and the oil production under different surfactant concentration conditions under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0081] Step 5, determine the shut-in time of the oil well; after the transformation, shut-in can not only promote the balanced improvement of the formation energy in the well-controlled area, but also improve the sweep range and imbibition replacement effect of the efficiency-enhancing oil displacement fluid in the well-controlled area. The well shut-in time is determined by using empirical analogy method and numerical simulation method.

[0082] The empirical analogy method is to determine that the shut-in time for reservoirs with a permeability of 10mD-30mD is 6d-10d by analogy with the reservoir geological conditions and construction examples of the reverse displacement efficiency enhancement process implemented offshore. The wellhead pressure is monitored during the on-site shut-in process, and the shut-in is terminated when the drop in shut-in pressure is less than 0.5MPa / day.

[0083] The numerical simulation method for determining the shut-in time includes the following steps:

[0084] Step 51, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid and the surfactant concentration as initial injection conditions;

[0085] Step 52, simulating the oil production under different shut-in times when the same oil displacement fluid injection volume, surfactant concentration, and well shut-in conditions are used, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0086] Step 6, determine the fracture parameters in the low-viscosity enhanced oil displacement fluid reconstruction stage and the guar gum sand fracturing reconstruction stage, including fracture support height, fracture half-length, and fracture conductivity.

[0087] The numerical simulation method is used to take the cumulative oil increase effect as the evaluation index to design and optimize the fracture parameters, including the following steps:

[0088] Step 61, based on the reservoir numerical model established in step 3, setting the same oil displacement fluid injection volume, surfactant concentration, well shut-in condition, and well shut-in time as simulation conditions;

[0089] Step 62, determining the crack height according to the reconstruction requirements and the layer and section selection results;

[0090] Step 63, when simulating the same fracture height and conductivity, determine the cumulative oil increase effect under different fracture half-length conditions in the low-viscosity enhanced oil displacement fluid transformation stage and the guar gum sand fracturing transformation stage, and compare and optimize the parameters in combination with the distance from the fault in the fracture direction and the sand body scale;

[0091] Step 64, simulating the same fracture height and fracture half length, determining the cumulative oil increase effect under different fracture conductivity conditions in the guar gum sand fracturing stage, and performing parameter comparison and optimization;

[0092] Among them, in step 63, the setting of the half-length of the fracture in the fracture extension direction needs to be smaller than the distance between the oil well and the fault. When there is a water injection well in the same layer in the fracture extension direction, the setting of the half-length of the fracture needs to be smaller than half of the distance between the oil and water wells.

[0093] In order to enable those skilled in the art to more clearly understand the technical solution of the present invention, the technical solution of the present invention will be described in detail below in conjunction with specific embodiments, but it is worth noting that the present invention is not limited to these embodiments. In the following detailed description of the present invention, some specific details are described in detail. However, for the part that is not described in detail, those skilled in the art can also fully understand the present invention.

[0094] It should be noted that the following detailed descriptions are exemplary and are intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meanings as those commonly understood by those skilled in the art to which the present invention belongs.

[0095] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, it indicates the presence of features, steps, operations and / or combinations thereof.

[0096] like Figure 1 As shown, it is a flow chart of the method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement transformation of oil wells according to the present invention.

[0097] Step 1: Select low-yield and low-efficiency oil wells in the target area of ​​the reservoir.

[0098] The W1 block is an offshore complex fault block reservoir with a burial depth of 2900m, an average oil layer thickness of 25m, an average permeability of 16mD, medium-low porosity, low permeability reservoir, and strong plane heterogeneity; closed elastic drive, original formation pressure of 31.2MPa, and no edge and bottom water development; 2 injections and 4 productions in the block, with poor injection and production effects, among which the A1 well produced 60m3 of oil in the initial production period. 3 / d, no water, the liquid volume continued to decline after production, no water injection effect, the well was shut down in 2022 due to low production and low efficiency, and the oil production before shutting down was 15m 3 / d, water content 10%, cumulative oil production 1.4×10 4 m 3 , the recovery rate is 11%, the current formation pressure is 22.2MPa, and the converted formation pressure coefficient is 0.78. The recovery rate of Well A1 is not high, the injection-production efficiency is poor, and the formation pressure coefficient is low. It is in urgent need of energy supplementation and productivity improvement, which meets the well selection criteria.

[0099] Step 2: Determine the reasonable formation pressure maintenance level based on the formation conditions.

[0100] The following formula is used to calculate the reasonable formation pressure maintenance level:

[0101] ηs=130.4·K0-0.1258

[0102] Among them, η s To maintain a reasonable formation pressure level, %, K0 is the formation permeability, mD.

[0103] The average permeability of the oil layer in Well A1 is 12mD, and the calculated reasonable formation pressure maintenance level is 95.4%.

[0104] Step 3, applying the result of step 2, determine the injection amount of the enhanced oil displacement fluid.

[0105] Obtain the current formation pressure, determine the difference in formation pressure change required to reach the reasonable formation pressure maintenance level calculated in step 2, and use numerical simulation methods and reservoir engineering methods to calculate the required injection volume of the enhanced oil displacement fluid; the difference in formation pressure change required is calculated using the following formula:

[0106] ΔP=η s ·P i -P p

[0107] Where ΔP is the formation pressure change difference, MPa, η s To maintain a reasonable formation pressure level, %, P i is the original formation pressure, MPa, P p is the current formation pressure, MPa.

[0108] The original formation pressure of Well A1 is 31.2MPa, and the current formation pressure is 22.2MPa. The reasonable formation pressure maintenance level calculated in step 2 is 95.4%, that is, the formation pressure is maintained at 31.2×95.4%=29.8MPa. It is necessary to increase the formation pressure in the well control area by injecting enhanced oil displacement fluid, and the increase value is 29.8-22.2=7.6Mpa.

[0109] The numerical simulation method for determining the injection amount of the enhanced oil displacement fluid includes the following steps:

[0110] Step 31, establishing a numerical model of the target area reservoir and completing history matching;

[0111] Step 32, simulating the formation pressure at the end of injection under different injection volume conditions;

[0112] Step 33, simulating the oil production under different injection rates when the well is opened after being shut in for 10 days and under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0113] The injection volume of the enhanced oil displacement fluid is set to 4000m 3 、6000m 3 , 8000m 3 , 10000m 3 、12000m 3 The numerical simulation of the reservoir was carried out, and the results showed that the cumulative oil volume increased with the increase of injection volume. When the injection volume was greater than 8000m 3 , the oil-increasing effect slowed down, and the corresponding formation pressure coefficient recovered to 29.3MPa.

[0114] The reservoir engineering method uses the material balance formula to calculate the injection volume of the enhanced oil displacement fluid;

[0115] The formula for determining the well control limit radius is as follows:

[0116]

[0117] Among them, R e is the well control limit radius, m, P e is the formation supply boundary pressure, MPa, P wf is the bottom hole flowing pressure of the oil well, MPa, μ is the underground viscosity of the fluid, mPa·s, K is the formation permeability, mD; the specific values ​​of each parameter are shown in Table 1 below.

[0118] Table 1 Parameters for calculating well control limit radius

[0119]

[0120]

[0121] The calculated well control limit radius of Well A1 is 161m.

[0122] The formula for determining the injection amount of the enhanced oil displacement fluid is as follows:

[0123]

[0124] Where V is the injection volume of the enhanced oil displacement fluid, m 3 , C o is the crude oil compressibility coefficient, MPa -1 , C w is the formation water compressibility coefficient, MPa -1 , C f is the rock compression coefficient, MPa -1 , S wi is the bound water saturation, a decimal, R e is the well control limit radius, m, H is the oil layer thickness, m, Φ is the formation porosity, decimal, ΔP is the formation pressure change difference, MPa. The specific values ​​of each parameter are shown in Table 2 below.

[0125] Table 2 Parameters for calculating the injection volume of the enhanced oil displacement fluid

[0126]

[0127] The calculated injection volume of the enhanced oil displacement fluid in Well A1 is 8818m 3 .

[0128] Based on the results of numerical simulation and reservoir engineering methods, and taking into account spillover, diffusion and loss, the injection volume of the enhanced oil displacement fluid for Well A1 was determined to be 9000m 3 .

[0129] Step 4, optimizing the concentration of surfactant in the enhanced oil displacement fluid.

[0130] The surfactant in the enhanced oil displacement fluid can reduce the oil / water interfacial tension and the water contact angle on the rock surface. The main evaluation index is the improvement of oil displacement efficiency. The numerical simulation method is used to optimize the surfactant concentration in the enhanced oil displacement fluid with the cumulative oil enhancement effect as the evaluation index, including the following steps:

[0131] Step 41, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid as the initial injection condition;

[0132] Step 42, the effect of surfactant concentration on oil displacement efficiency is approximately treated as a change in the oil-water relative permeability curve, and relative permeability curves under different surfactant concentration distributions are interpolated and imported into the numerical model;

[0133] Step 43, simulating the same injection volume of oil displacement fluid, opening the well after shutting down for 10 days, and the oil production under different surfactant concentration conditions under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0134] The oil-water relative permeability curves corresponding to surfactant concentrations of 0%, 0.15%, 0.35%, and 0.55% were interpolated and imported into the numerical model in step 3, and the injection volume of the enhanced oil displacement fluid was set to 9000m 3 The simulation results show that as the surfactant concentration increases, the cumulative oil production increases accordingly. When the concentration is greater than 0.35%, the oil increase effect slows down. Referring to the implementation of similar oil fields, combined with the on-site construction capacity and benefit evaluation, the surfactant concentration injected into Well A1 is determined to be 0.35%.

[0135] Step 5, determine the well shut-down time.

[0136] After the transformation, the well shut-in can improve the formation energy balance in the well-controlled area on the one hand, and improve the sweep range and imbibition replacement effect of the efficiency-enhancing oil displacement fluid in the well-controlled area on the other hand. The empirical analogy method and numerical simulation method are used to determine the well shut-in time.

[0137] Analogous to the reverse displacement efficiency enhancement process example of offshore low-permeability oil wells, the shut-in time for oil reservoirs with a permeability of 10mD-30mD is 6d-10d. The wellhead pressure is monitored during the on-site shut-in process, and the shut-in can be terminated when the drop in shut-in pressure is less than 0.5MPa / day.

[0138] In step 5, the numerical simulation method for determining the shut-in time includes:

[0139] Step 51, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid and the surfactant concentration as initial injection conditions;

[0140] Step 52, simulating the oil production under different shut-in times when the same oil displacement fluid injection volume, surfactant concentration, and well shut-in conditions are used, and performing parameter comparison and optimization according to the cumulative oil production effect.

[0141] In the reservoir numerical model, the injection volume of the enhanced oil displacement fluid is set to 9000m 3 , the surfactant concentration was 0.35%, and the shut-in time was designed to be 4 days, 6 days, 8 days, 10 days, and 12 days for simulation. The results showed that when the shut-in time was greater than 8 days, the oil increase effect slowed down and the oil increase tended to be stable. The optimal shut-in time for Well A1 was determined to be 8 days.

[0142] Step 6: Determine the fracture parameters, including fracture support height, fracture half-length, and fracture conductivity.

[0143] The numerical simulation method is used to take the cumulative oil increase effect as the evaluation index to design and optimize the fracture parameters, including the following steps:

[0144] Step 61, based on the reservoir numerical model established in step 3, setting the same oil displacement fluid injection volume, surfactant concentration, well shut-in condition, and well shut-in time as simulation conditions;

[0145] Step 62, determining the crack height according to the reconstruction requirements and the layer and section selection results;

[0146] Step 63, simulating the cumulative oil increase effect under different fracture half-length conditions when the fracture height and conductivity are the same, and performing parameter comparison and optimization in combination with the distance from the fault in the fracture direction and the scale of the sand body;

[0147] Step 64, simulating the cumulative oil increase effect under different fracture conductivity conditions with the same fracture height and fracture half length, and performing parameter comparison and optimization.

[0148] The oil layer thickness of Well A1 is 25m, the vertical span of the oil layer is 41m, and the fracture height is determined to be 40m.

[0149] In the reservoir numerical model, the injection volume of the enhanced oil displacement fluid is set to 9000m 3 , surfactant concentration is 0.35%, fracture conductivity is set to 25D·cm, fracture half-lengths are designed to be 80m, 100m, 120m, 140m, and 160m respectively, and the soaking time is set to 8 days for reservoir numerical simulation. The results show that the fracture half-length is positively correlated with the oil-increasing effect. When the fracture half-length is greater than 120m, the oil-increasing effect slows down. The distance between Well A1 and the adjacent water injection well is 390m, and the distance to the adjacent fault in the direction of the maximum principal stress is 150m. Taking the above conditions into consideration, the fracture half-length is preferably determined to be 130m.

[0150] In the reservoir numerical model, the injection volume of the enhanced oil displacement fluid is set to 9000m 3 , surfactant concentration was 0.35%, fracture half-length was set to 130 mm, fracture conductivity was designed to be 10 D·cm, 15 D·cm, 20 D·cm, 25 D·cm, 30 D·cm respectively, and well soaking time was set to 8 days for reservoir numerical simulation. The results showed that the fracture conductivity was positively correlated with the oil increase effect. When the conductivity was greater than 20 D·cm, the oil increase effect slowed down. Combined with the construction capacity and process countermeasures, the fracture conductivity was preferably determined to be 20 D·cm.

[0151] The parts not described in detail in this embodiment are well-known common means in the industry and are not described here one by one. The above embodiments are preferred embodiments of the present invention, but the embodiments of the present invention are not limited to the above embodiments. Any other changes, modifications, substitutions, combinations, and simplifications made without departing from the spirit and principle of the present invention shall be equivalent replacement methods and are included in the protection scope of the present invention.

Claims

1. A method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells, characterized in that: The following steps are involved: Step 1, selecting low-yield and low-efficiency oil wells in the target area of ​​the reservoir; Step 2, determining a reasonable formation pressure maintenance level based on formation conditions; Step 3, applying the result of step 2 to determine the injection amount of the enhanced oil displacement fluid; Step 4, optimizing the concentration of surfactant in the synergistic oil displacement fluid; Step 5, determining the well shut-in time of the oil well; Step 6, determine the fracture parameters in the low-viscosity enhanced oil displacement fluid reconstruction stage and the guar gum sand fracturing reconstruction stage, including fracture support height, fracture half-length, and fracture conductivity.

2. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 1, characterized in that: Step 1 includes selecting low-yield and low-efficiency oil wells with no injection-production relationship or poor injection-production efficiency, large liquid production decline, well conditions that meet the conditions for reverse displacement efficiency improvement, and urgent need for energy supplementation in closed and semi-closed oil reservoirs with fault blocks or lithological boundaries, poor reservoir properties, and undeveloped edge and bottom water in the target area of ​​residual oil enrichment based on the structural characteristics of the reservoir, reservoir physical properties, driving type, reservoir pressure level, remaining reserves basis, and current well network conditions.

3. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 1, characterized in that: In step 2, the reasonable formation pressure maintenance level is calculated using the following formula: ηs=130.4·K0-0.1258 Among them, η s To maintain a reasonable formation pressure level, %, K0 is the formation permeability, mD.

4. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 3, characterized in that: In step 3, the current formation pressure is obtained, and the difference in formation pressure change required to reach the reasonable formation pressure maintenance level calculated in step 2 is determined. The required injection amount of the enhanced oil displacement fluid is calculated using numerical simulation methods and reservoir engineering methods; The required difference in formation pressure change is calculated using the following formula: ΔP=η s ·P i -P p Where ΔP is the formation pressure change difference, MPa, η s To maintain a reasonable formation pressure level, %, P i is the original formation pressure, MPa, P p is the current formation pressure, MPa.

5. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 4, characterized in that: The numerical simulation method for determining the injection amount of the enhanced oil displacement fluid includes the following steps: Step 31, establishing a numerical model of the target area reservoir and completing history matching; Step 32, simulating the formation pressure at the end of injection under different injection volume conditions; Step 33, simulating the oil production under different injection rates when the well is opened after being shut in for 10 days and under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

6. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 4, characterized in that: The reservoir engineering method uses the material balance formula to calculate the injection volume of the enhanced oil displacement fluid; The formula for determining the well control limit radius is as follows: Among them, R e is the well control limit radius, m, P e is the formation supply boundary pressure, MPa, P wf is the bottom hole flowing pressure of the oil well, MPa, μ is the underground viscosity of the fluid, mPa·s, K is the formation permeability, mD; The formula for determining the injection amount of the enhanced oil displacement fluid is as follows: Where V is the injection volume of the enhanced oil displacement fluid, m 3 , C o is the crude oil compressibility coefficient, MPa -1 , C w is the formation water compressibility coefficient, MPa -1 , C f is the rock compression coefficient, MPa -1 , S wi is the bound water saturation, a decimal, R e is the well control limit radius, m, H is the oil layer thickness, m, Φ is the formation porosity, a decimal, and ΔP is the formation pressure change difference, MPa.

7. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 5, characterized in that: In step 4, the surfactant in the synergistic oil displacement fluid can reduce the oil / water interfacial tension and the water contact angle on the rock surface. The concentration of the surfactant in the synergistic oil displacement fluid is optimized by using a numerical simulation method and taking the cumulative oil enhancement effect as an evaluation index. Step 4 includes the following steps: Step 41, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid as the initial injection condition; Step 42, the effect of surfactant concentration on oil displacement efficiency is approximately treated as a change in the oil-water relative permeability curve, and relative permeability curves under different surfactant concentration distributions are interpolated and imported into the numerical model; Step 43, simulating the same injection volume of oil displacement fluid, opening the well after shutting down for 10 days, and the oil production under different surfactant concentration conditions under the same shut-in conditions, and performing parameter comparison and optimization according to the cumulative oil production effect.

8. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 5, characterized in that: In step 5, the well shut-in after transformation can not only promote the balanced improvement of formation energy in the well-controlled area, but also improve the sweep range and imbibition replacement effect of the enhanced oil displacement fluid in the well-controlled area. The empirical analogy method and numerical simulation method are used to determine the well shut-in time.

9. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 8, characterized in that: The empirical analogy method is to compare the geological conditions and construction examples of the target reservoirs that implement the reverse displacement efficiency enhancement process at sea, and determine that the shut-in time for reservoirs with a permeability of 10mD-30mD is 6d-10d. During the on-site shut-in process, the wellhead pressure is monitored and the shut-in is terminated when the shut-in pressure drop is less than 0.5MPa / day. The numerical simulation method for determining the shut-in time includes the following steps: Step 51, based on the reservoir numerical model established in step 3, setting the optimized injection amount of the enhanced oil displacement fluid and the surfactant concentration as initial injection conditions; Step 52, simulating the oil production under different shut-in times when the same oil displacement fluid injection volume, surfactant concentration, and well shut-in conditions are used, and performing parameter comparison and optimization according to the cumulative oil production effect.

10. The method for optimizing injection parameters and fracture parameters for reverse displacement efficiency enhancement of oil wells according to claim 5, characterized in that: In step 6, a numerical simulation method is used to design and optimize fracture parameters with cumulative oil enhancement effect as the evaluation index. Step 6 includes the following steps: Step 61, based on the reservoir numerical model established in step 3, setting the same oil displacement fluid injection volume, surfactant concentration, well shut-in condition, and well shut-in time as simulation conditions; Step 62, determining the crack height according to the reconstruction requirements and the layer and section selection results; Step 63, when simulating the same fracture height and conductivity, determine the cumulative oil increase effect under different fracture half-length conditions in the low-viscosity enhanced oil displacement fluid transformation stage and the guar gum sand fracturing transformation stage, and compare and optimize the parameters in combination with the distance from the fault in the fracture direction and the sand body scale; Step 64, simulating the same fracture height and fracture half length, determining the cumulative oil increase effect under different fracture conductivity conditions in the guar gum sand fracturing stage, and performing parameter comparison and optimization; Among them, in step 63, the setting of the half-length of the fracture in the fracture extension direction needs to be smaller than the distance between the oil well and the fault. When there is a water injection well in the same layer in the fracture extension direction, the setting of the half-length of the fracture needs to be smaller than half of the distance between the oil and water wells.

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