A chemical profile control parameter design method and device based on a four-dimensional well testing model

Abstract

The present application belongs to the field of chemical profile control and flooding reservoir well test interpretation, and relates to a chemical profile control and flooding parameter design method and device based on a four-dimensional well test model. The chemical profile control and flooding parameter design method based on the four-dimensional well test model comprises the following steps: calculating a polymer flooding well test data after polymer profile control and flooding, and calculating a polymer mobility distribution field around a well and a circular distribution field of polymer viscosity around the well; combining a shape factor and using an equal-area conversion principle to draw an actual distribution field of polymer viscosity around the well; using a Petrophysical module in Petrel software to draw polymer viscosity actual distribution contour lines in different well groups together to generate a polymer viscosity distribution field map of the entire block; and determining a total polymer injection amount, a profile control slug amount and a channeling sealing slug amount of a single well group according to an area coefficient and a direction coefficient. The present application solves the problem that it is difficult to determine a polymer profile control and flooding reservoir plugging position, a profile control slug amount and a channeling sealing slug amount, and provides a scientific and reasonable theoretical basis for formulating a next profile control and flooding scheme.

Description

TECHNICAL FIELD

[0001] The present application belongs to the field of chemical profile control and reservoir well test interpretation, and particularly relates to a chemical profile control parameter design method and device based on a four-dimensional well test model. BACKGROUND

[0002] Most of the oilfields in Bohai area are continental sandstone oilfields, which are mostly fluvial facies or delta facies deposits, resulting in serious heterogeneity in the horizontal and vertical directions of the reservoirs. In the later development stage, the injected water is washed in the reservoir, preferentially seeping along the high-permeability channels, to a certain extent, damaging the rock structure of the high-permeability layers and reducing the seepage resistance therein, thus aggravating the heterogeneity of the reservoir. In order to prevent the injected water from rushing along such high-permeability channels and forming the invalid circulation of the injected water, one of the most commonly used techniques by petroleum engineers is polymer profile control. The polymer profile control technique is to use polymer solution to preferentially seep along the high-permeability channels and stay therein, so as to reduce the seepage capacity of the injected water in the high-permeability channels, and then increase the water injection amount in the low-permeability channels, so as to ultimately achieve the purpose of increasing the swept range of the injected water and improving the recovery rate.

[0003] However, in the actual oilfield construction process, since the polymer, oil and water are all located in the underground rock, the swept range and plugging position of the injected polymer are difficult to monitor, and the means for engineers to determine the polymer profile control effect are limited to the monitoring of the flow rate of the wellhead crude oil and water. However, the wellhead flow rate monitoring still cannot infer the swept range and plugging position of the polymer, which leads to the difficulty in formulating the next construction scheme. Therefore, the development of a polymer profile control effect monitoring method is crucial for the formulation of the oil reservoir enhanced recovery scheme.

[0004] The predecessors have carried out research on the monitoring of the profile control effect of offshore reservoirs based on well test interpretation methods, and established a double-zone composite well test model to interpret the polymer distribution after profile control. In the physical hypothesis of the model, the physical properties of the inner zone and the outer zone are different, so as to distinguish the fluid mobility mutation area in the high-permeability layer, and determine it as the plugging position of the polymer profile control. However, since the rock and fluid properties are the same in the inner zone or the outer zone, the method is no longer applicable to the polymer profile control reservoirs with strong heterogeneity.

[0005] In addition, the conventional well test interpretation technique is established on the basis of a one-dimensional well test model with radial homogeneity, and the interpretation results obtained can only be an average value within the pressure swept range of a single well point, which cannot meet the requirement of the evaluation of the effect of the chemical flooding reservoir measures. The planar distribution change law of the formation parameters such as the reservoir properties and fluids in the chemical flooding reservoir is affected by the injected chemical agents, and the change of the physical properties and the interpretation of the fluid parameters between multiple well points require the reservoir interpretation technique to change from "one-dimensional well test" to "four-dimensional well test". SUMMARY

[0006] In order to solve the above technical problems, the application provides a chemical profile control parameter design method and device based on a four-dimensional well testing model, which couples the fluid mobility and other parameters of the fluid distributed along the radial direction to the seepage mathematical model according to the fluid seepage characteristics in the non-uniform porous medium.

[0007] Specifically, the chemical profile control parameter design method based on the four-dimensional well testing model comprises the following steps.

[0008] According to the single well real well testing data after the polymer profile control, the polymer mobility distribution field around the well and the circular distribution field of the polymer viscosity around the well are calculated.

[0009] The actual distribution field of the polymer viscosity around the well is drawn by combining the shape factor and the equal-area conversion principle.

[0010] The actual distribution contour of the polymer viscosity in different well groups is drawn together by using the Petrophysical module in the Petrel software to generate the polymer viscosity distribution field map of the whole block.

[0011] According to the area coefficient and the direction coefficient, the total polymer injection amount, the profile control slug amount and the channeling sealing slug amount of a single well group are determined.

[0012] The chemical profile control parameter design method based on the four-dimensional well testing model, and the polymer mobility distribution field around the well is obtained by the following method.

[0013] The instantaneous mobility is determined according to the natural gas production, the natural gas formation volume factor, the reservoir thickness and the pressure reciprocal.

[0014] The dimensionless pseudo-time is determined according to the instantaneous mobility, the time, the porosity, the comprehensive compressibility coefficient and the wellbore radius.

[0015] The detection radius is determined according to the instantaneous mobility, the detection time, the porosity and the comprehensive compressibility coefficient.

[0016] The mobility corresponding to the detection radius at the detection time is obtained by the following formula.

[0017]

[0018] Wherein, M n is the fluid velocity, mD / (mPa·s); is the instantaneous mobility, mD / (mPa·s); M i represents the mobility corresponding to the detection radius r i at the time t i , mD / (mPa·s); is the instantaneous dimensionless Boltzmann variable; W 1 / 2,1 / 2 is the Whittaker function.

[0019] The above-mentioned chemical profile control parameter design method based on the four-dimensional well testing model, the circular distribution field of the polymer viscosity around the well is obtained by combining the polymer mobility distribution field around the well with the relationship between the polymer mobility and the polymer viscosity in the reservoir after polymer flooding.

[0020] The above-mentioned chemical profile control parameter design method based on the four-dimensional well testing model, the shape factor is the actual distribution shape of the polymer viscosity in the reservoir near each well group.

[0021] The above-mentioned chemical profile control parameter design method based on the four-dimensional well testing model, the actual distribution field of the polymer viscosity around the well comprises the following steps:

[0022] (1) The area of the circular viscosity field contour with a radius of r1 is πr1 2 .

[0023] (2) According to the equal-area conversion principle, the actual viscosity contour area corresponding to the circular viscosity field contour with a radius of r1 determined according to the tracer breakthrough vector is also πr1 2 .

[0024] (3) Assuming that the shape factor is a closed polygon composed of n points, the coordinates of the points are A1(x1, y1), A2(x2, y2), …, An(xn, yn) respectively, then the area of the shape factor is: n n n

[0025]

[0026] Since the shape factor is a closed polygon composed of n points, the first point in the coordinates of the shape factor is the (n+1)th point, that is, x n+1 =x1, y n+1 =y1; the circular viscosity contour field in a well group is converted into an actual viscosity contour field by the equal-area conversion principle, and the expression is as follows:

[0027]

[0028] In the formula, S is the area of the shape factor, m 2 ; x is the horizontal coordinate of the point on the shape factor; y is the vertical coordinate of the point on the shape factor.

[0029] The above-mentioned chemical profile control parameter design method based on the four-dimensional well testing model, the area coefficient is determined according to the polymer profile control inner radius, the polymer profile control outer radius and the polymer profile control radius of the actual distribution field of the polymer viscosity around the well.

[0030] ​​​The direction coefficient is determined according to polymer channeling area and polymer swept area of the actual distribution field of polymer viscosity around the well.

[0031] The total polymer injection amount is determined according to polymer profile control outer radius, polymer profile control inner radius, polymer profile control layer thickness, formation porosity, polymer injection area coefficient and injection pore volume multiple.

[0032] The channeling plug amount is determined according to the total polymer injection amount, the proportion of high-permeability layer thickness to water injection formation thickness and the direction coefficient of polymer injection.

[0033] The profile control plug amount is determined according to the total polymer injection amount and the channeling plug amount.

[0034] In another aspect, the present application further provides a chemical profile control and flooding parameter design device based on a four-dimensional well testing model, comprising:

[0035] A well polymer mobility and viscosity distribution field determination module is configured to calculate a well polymer mobility distribution field and a well polymer viscosity circular distribution field according to single-well real testing data after polymer profile control and flooding.

[0036] A well polymer viscosity actual distribution field determination module is configured to draw a well polymer viscosity actual distribution field by area conversion principle in combination with a shape factor.

[0037] A whole block polymer viscosity distribution field determination module is configured to draw polymer viscosity actual distribution contour lines in different well groups together to generate a whole block polymer viscosity distribution field map by using a Petrophysical module in Petrel software.

[0038] A single well group polymer profile control and channeling amount determination module is configured to determine total polymer injection amount, profile control plug amount and channeling plug amount of a single well group according to area coefficient and direction coefficient.

[0039] In still another aspect, the present application further provides an electronic device, comprising a processor, a memory, a communication interface and a communication bus, the processor, the memory and the communication interface complete communication with each other through the communication bus; the memory is used to store at least one executable instruction, and the executable instruction makes the processor execute corresponding operations of the chemical profile control and flooding parameter design method based on a four-dimensional well testing model.

[0040] In still another aspect, the present application provides a computer storage medium, wherein at least one executable instruction is stored in the computer storage medium, and the executable instruction causes a processor to perform operations corresponding to the chemical profile control parameter design method based on a four-dimensional well testing model.

[0041] The technical solution of the present application has the following beneficial effects:

[0042] (1) The chemical profile control parameter design method based on a four-dimensional well testing model solves the problem of determining the plugging position, profile control slug and channeling blocking slug of a polymer profile control reservoir, and can provide a scientific and reasonable theoretical basis for subsequent profile control scheme formulation.

[0043] (2) The chemical profile control parameter design method based on a four-dimensional well testing model breaks through the limitation of a conventional one-dimensional well testing model, comprehensively considers the variation law of chemical flooding reservoir information in time and space, and can effectively solve the problems of plugging position and plugging effect after injection of different types of chemical agents (biological nano, weak gel, nano microsphere, etc.) into a reservoir.

[0044] (3) The chemical profile control parameter design method based on a four-dimensional well testing model can directly use production data of an oilfield injection-production well, is simple to apply, and can avoid the production capacity loss caused by shut-in of a conventional well testing.

[0045] (4) The chemical profile control parameter design method based on a four-dimensional well testing model provides an effective quantitative interpretation means for multi-cycle chemical flooding scheme optimization design, and fills the technical gap of planar quantitative interpretation of a chemical flooding fluid. BRIEF DESCRIPTION OF DRAWINGS

[0046] Various other advantages and benefits will become apparent to those of ordinary skill in the art upon reading the following detailed description of the preferred embodiments with reference made to the accompanying drawings. The drawings are for purposes of illustration only and are not considered a limitation of the present application.

[0047] Figure 1 is a flow chart of the chemical profile control parameter design method based on a four-dimensional well testing model of the present application;

[0048] Figure 2 is a schematic diagram of a pressure and pressure derivative double logarithmic curve plotted based on pressure buildup well testing data;

[0049] Figure 3 is a schematic diagram of a four-dimensional well testing interpreted fluid viscosity distribution with radius;

[0050] Figure 4 (a) is a schematic diagram of a tracer breakthrough vector;

[0051] Figure 4(b) is a schematic diagram of polymer distribution shape in the reservoir near the well group after polymer profile control;

[0052] Figure 4 (c) is a schematic diagram of polymer viscosity contour without breakthrough;

[0053] Figure 4 (d) is a schematic diagram of polymer viscosity contour considering breakthrough vector;

[0054] Figure 5 is a comparison diagram of polymer viscosity distribution shape after polymer profile control of different well groups;

[0055] Figure 6 is a diagram of polymer viscosity distribution in the reservoir after polymer profile control;

[0056] Figure 7 is a schematic diagram of the chemical profile control parameter design device structure based on the four-dimensional well testing model of the present application;

[0057] Figure 8 is a schematic diagram of the structure of the electronic device of the present application. DETAILED DESCRIPTION

[0058] In order to fully understand the purpose, features and effects of the present application, the present application will be described in detail through the following specific embodiments. The process method of the present application adopts conventional methods or devices in the art except for the following content. Unless otherwise specified, the following terms have the meanings commonly understood by those skilled in the art.

[0059] At present, various profile control and polymer flooding technologies in offshore chemical flooding reservoirs cause large changes in reservoir fluid and physical property parameters, and lack of quantitative characterization means for distribution regularity, which affects the reliability and authenticity of chemical flooding measure effect evaluation and enhanced oil recovery technology process scheme design. The existing conventional well testing technology solves the effect evaluation problem of homogeneous reservoirs through single well point pressure drop / pressure recovery well testing method, and the application scene is mainly water flooding reservoirs, which cannot explain the crosslinking, migration and plugging effect of chemicals in chemical flooding reservoirs.

[0060] The chemical profile control parameter design method based on the four-dimensional well testing model disclosed by the present application is a wellbore reservoir parameter field inversion method based on percolation theory combined with ISA (inverse solution algorithm) algorithm. The method uses reservoir percolation theory to establish a radial heterogeneous percolation mathematical model, solves the radial heterogeneous percolation diffusion equation set combining the perturbation theory and Laplace theory, and establishes an inversion algorithm (ISA algorithm) of the reservoir parameter field.

[0061] Specifically, as shown in Figure 1 The chemical profile control parameter design method based on the four-dimensional well testing model of the present application comprises:

[0062] S110 calculating the polymer mobility distribution field and the circular distribution field of polymer viscosity around the well according to the single-well real test well data after polymer profile control;

[0063] S120 drawing the actual distribution field of polymer viscosity around the well by the equal-area conversion principle combined with the shape factor;

[0064] S130 using the Petrophysical module in Petrel software to draw the actual distribution isopleths of polymer viscosity in different well groups together to generate the polymer viscosity distribution field map of the entire block;

[0065] S140 determining the total polymer injection amount, the profile control slug amount and the channeling sealing slug amount of a single well group according to the area coefficient and the direction coefficient.

[0066] In a preferred embodiment, the four-dimensional well test model-based chemical profile control parameter design method provided by the present application comprises the following steps:

[0067] Step one, hypothetical conditions: (1) the reservoir type is an infinite heterogeneous reservoir; (2) the well is produced at a constant rate; (3) the effects of gravity and capillary force are ignored; (4) the reservoir fluid is incompressible. Then the dimensionless seepage equation of the production well of the infinite radial heterogeneous reservoir is established as follows:

[0068]

[0069] In the formula, r D is the dimensionless radial distance; k D (r D ) is the dimensionless formation permeability, which is a function of the dimensionless radial distance; p D is the dimensionless formation pressure; t D is the dimensionless time.

[0070] The dimensionless definitions in formula (1) are as follows:

[0071] Dimensionless time:

[0072]

[0073] Dimensionless radius:

[0074]

[0075] Dimensionless radial mobility:

[0076]

[0077] wherein,

[0078]

[0079]

[0080] Dimensionless pressure and dimensionless pressure derivative:

[0081]

[0082] where k is the reference permeability, mD; t is time, d; φ is porosity, fraction; C t is the compressibility, fraction; μ is the gas viscosity, mPa·s; r w is the wellbore radius, m; r is the radial distance, m; h is the reservoir thickness, m; p i is the initial formation pressure, MPa; p(r, t) is the formation pressure, a function of radial distance and time, MPa; q is the gas production rate, m 3 / d; B is the gas formation volume factor, fraction; p wD is the dimensionless bottomhole flowing pressure; p w is the bottomhole flowing pressure, MPa; p' wD is the dimensionless bottomhole flowing pressure derivative; M D (r D ) is the dimensionless mobility, a function of dimensionless radial distance; M(r) is the mobility, a function of radial distance, mD / (mPa·s); k(r) is the formation permeability, a function of radial distance, mD; is the reference mobility, mD / (mPa·s).

[0083] Step 2, solve the mathematical model of seepage equation (1), and get the analytical solution of pressure and pressure derivative as

[0084]

[0085] In equation (7), W 1 / 21 / 2 is the Whittaker function.

[0086]

[0087] Where:

[0088]

[0089] Step 3, establish the inversion algorithm of fluid mobility and other parameter fields before and after chemical profile control, first define M(r) as the harmonic mean of M(r, θ) at position r:

[0090]

[0091] Combining equation (6) and equation (8), we can get

[0092]

[0093] For equation (11), redefined the mobility, denoted as

[0094]

[0095] Since The derivative of pressure at a certain time represents the instantaneous mobility.

[0096] From equation (5), equation (11) and equation (12), we can derive:

[0097]

[0098] From equation (2), equation (4) and the definition of instantaneous mobility, redefine the dimensionless pseudo-time:

[0099]

[0100] Based on the definition of equation (14), equation (8) becomes:

[0101]

[0102] Assume M(r) can be represented as a discrete piecewise function, that is, when r i-1 <r≤r i (i = 1, 2, …, n), M(r) = M i . In this way, the essence of this inversion algorithm is to solve M n corresponding to the detection radius r n at time t n . The detection radius r n is defined as:

[0103]

[0104] Definition:

[0105]

[0106]

[0107] At time t = t n , equations (17) and (18) are combined, and equation (13) is transformed into:

[0108]

[0109] From equation (17), equation (18), we can get:

[0110]

[0111] Combining equation (17), equation (20), equation (19) can be rewritten as:

[0112]

[0113] From equation (17), we can get:

[0114]

[0115] Substitute equation (22) into equation (21), we get:

[0116]

[0117] Combining equation (9), equation (14), the integral in equation (23) can be expressed as:

[0118]

[0119] According to the definition of dimensionless Boltzmann variable, the corresponding instantaneous dimensionless Boltzmann variable is defined as:

[0120]

[0121] From equation (25), we get:

[0122]

[0123] Substitute equation (26) into equation (24), we get:

[0124]

[0125] Combining equation (27), equation (23) can be further expressed as:

[0126]

[0127] Where, M n is the fluid velocity, mD / (mPa·s); is the instantaneous mobility, mD / (mPa·s); M i represents the mobility corresponding to the detection radius r i at t i time, mD / (mPa·s); is the instantaneous dimensionless Boltzmann variable; W 1 / 2,1 / 2 is the Whittaker function.

[0128] Step four, using the single well real test well data after polymer profile control, calculate the instantaneous mobility from equation (12)

[0129] Step five, calculate the dimensionless pseudo-time from equation (14)

[0130] Step six, calculate the detection radius r from formula (16) n .

[0131] Step seven, calculate the mobility M from formula (28) n , we can get the detection radius r n at time t n , and the corresponding mobility M n , and we get the polymer mobility distribution field around the well.

[0132] Step eight, determine the polymer viscosity distribution and plugging position. According to the relationship between polymer mobility and polymer viscosity in the reservoir after polymer flooding (μ = M n / k), combined with the polymer mobility distribution obtained in step seven, we can obtain the polymer viscosity distribution in the reservoir, and further determine the area with the maximum polymer viscosity, i.e. the polymer plugging position.

[0133] Step nine, based on the method of interpreting polymer viscosity distribution in step eight based on single well test data, we can interpret the polymer viscosity distribution in the reservoir near different wells in different well groups.

[0134] Step ten, determine the shape factor. The actual distribution shape of polymer viscosity near each well group in the reservoir is shown in Figure 4 (b), we newly define Figure 4 (b) as the shape factor. In order to accurately characterize the shape factor using tracer data, we newly define the polymer breakthrough vector Figure 4 (a)), which is directed from the injection well to the polymer response well, and its size is the polymer breakthrough velocity. We determine the specific shape of the shape factor Figure 4 (b) based on this.

[0135] Step eleven, draw the actual viscosity field contour map. Combine the actual distribution shape of polymer in the reservoir determined in step ten, and convert the circular viscosity field with radius r into the actual distribution contour map of polymer viscosity near the reservoir in different well groups based on the principle of equal area. The main purpose of this step is to convert the annular viscosity field into the actual viscosity field according to the shape factor using mathematical algorithm, and the algorithm is as follows:

[0136] (1) The area of the circular viscosity field with radius r1 is πr1 2 ;

[0137] (2) According to the principle of equal area, it can be determined that the actual viscosity contour area corresponding to the circular viscosity field with radius r1 determined according to the tracer breakthrough vector is also πr1 2 .

[0138] (3) Assume the shape factor is a closed polygon composed of n points, where the coordinates of each point are A1(x1,y1), A2(x2,y2), ..., A n (x n ,y n If the shape factor is such that the area can be expressed as:

[0139]

[0140] Since the shape factor is a closed polygon composed of n points, the first point in the coordinate system of the shape factor is the (n+1)th point, i.e., x. n+1 =x1,y n+1 =y1. Equation (30) can be obtained by applying the principle of equal area transformation. Figure 4 (a) The geodetic coordinates of the injection well point are (x inj ,y inj After connecting this point to each point in the shape factor, the lengths of the line segments can be calculated as l1, l2, l3, ..., l based on the coordinates of the two points. n Therefore, by scaling the lengths of each line segment proportionally, the coordinates of the isolines of different viscosity fields can be obtained. According to equation (30), the circular viscosity isoline field in a well group can be converted into the actual viscosity isoline field, as shown in the following expression:

[0141]

[0142] In the formula: S is the area of ​​the shape factor, m 2 x is the x-coordinate of the point on the shape factor; y is the y-coordinate of the point on the shape factor.

[0143] Step 12: Draw the polymer viscosity distribution map of the block. Using the actual polymer viscosity distribution contour lines in the reservoirs near different well groups from Step 11 as constraints, use the Petrophysical module in Petrel software to draw the actual polymer viscosity distribution contour lines in different well groups together to generate a polymer viscosity distribution field map for the entire block.

[0144] Step Thirteen: Determine the polymer flow control and sealing / channeling dosage for a single well group. Using the actual viscosity field contour map obtained in Step Twelve, the area coefficient γ and direction coefficient α can be determined. The proportion κ of the high-permeability layer thickness to the injected reservoir thickness can be determined using well logging interpretation data. The area coefficient γ and direction coefficient α characterize planar heterogeneity, while the proportion κ of the high-permeability layer characterizes vertical heterogeneity. The total polymer injection volume V1 can be calculated using the polymer injection pore volume multiple, and then the polymer sealing / channeling dosage V2 can be calculated. The total polymer injection volume V1 minus the sealing / channeling dosage V2 equals the flow control dosage V3. The specific calculation formula is as follows:

[0145] V1=π(Re 2 -R w 2 )hφγη (31)

[0146] V2 = V1κα (32)

[0147] V3 = V1-V2 (33)

[0148]

[0149]

[0150] S 封窜 = S 波及 -S 调驱 (36)

[0151] S 波及 = π(R t 2 -R w 2 ) (37)

[0152] S 调驱 = π(R min 2 -R w 2 ) (38)

[0153] wherein: V1 is the total amount of polymer injected, m 3 ; V2 is the amount of polymer used for channeling plugging, m 3 ; V3 is the amount of polymer used for profile control, m 3 ; h is the thickness of the polymer profile control layer, m; φ is the formation porosity; γ is the area coefficient of polymer injection; α is the direction coefficient of polymer injection; κ is the proportion of high permeability layer thickness to the thickness of water injection formation; η is the injection pore volume multiple; S 封窜 is the area of polymer channeling plugging part, m 3 ; S 波及 is the total area of polymer sweep, m 3 ; S 调驱 is the area of polymer profile control part, m 3 ; R w is the inner radius of polymer profile control, m; R e is the outer radius of polymer profile control, which is the average oil-water well spacing of profile control well group, m; R t is the polymer profile control radius, m; R min is the minimum sweep distance of polymer injected so far, m.

[0154] The following describes the four-dimensional well testing model-based chemical profile control parameter design method of the present application with a specific example:

[0155] Step 1, draw a pressure and pressure derivative double logarithmic curve schematic diagram based on pressure buildup well testing data (see Figure 2 ), combine Figure 2 the single well pressure derivative curve, and calculate the instantaneous mobility according to formula (12)

[0156] Step 2, combine the abscissa time t corresponding to the single well pressure derivative curve in Figure 2 , and calculate the dimensionless pseudo-time according to formula (14)

[0157] Step 3, calculate the detection radius r corresponding to the instantaneous mobility according to formula (16) n .

[0158] Step 4, combine the instantaneous mobility , calculate the mobility M according to formula (28) n , and the detection radius r n at time t n corresponding to the mobility M n .

[0159] Step 5, according to the relationship between the polymer mobility and the polymer viscosity in the reservoir after polymer flooding (μ=M n / k), and combining the polymer mobility distribution, the polymer viscosity distribution with the radial distance in the reservoir can be obtained (see Figure 3 ), and the area with the maximum polymer viscosity, i.e., the polymer plugging position (r=16m) around one of the polymer injection wells, is determined.

[0160] Step 6, according to the tracer data of multiple wells in a well group, the chemical agent breakthrough vector is calculated using the tracer breakthrough velocity (see Figure 4 (a)), and the actual distribution shape of the polymer viscosity in the reservoir near different well groups is determined (see Figure 4 (b)). Since Figure 2 is the polymer viscosity distribution with the radial distance, we can draw it as a ring-shaped contour (see Figure 4 (c)). Figure 4 The different radius rings in Figure 4 (c) represent the polymer viscosities corresponding to different radii in Figure 4 (b). Therefore, we obtain the contour map of the ring-shaped distribution of the polymer viscosity. Then we convert the rings in Figure 4 (c) into the actual distribution of the polymer viscosity contour in an equal-area manner according to the actual shape of the polymer in Figure 4 (b)Figure 4 (d)).

[0161] Step 7: The polymer distribution pattern in different well groups can be obtained through step 6 (see...). Figure 5 Following the method in step 6, the actual distribution of polymer viscosity contour lines in different well groups can be obtained. Using these contour lines as constraints, the Petrophysical module in Petrel software is used to plot the actual polymer viscosity distribution contour lines in different well groups together, generating a polymer viscosity distribution field map for the entire block (see...). Figure 6 ).

[0162] Step 8: Based on the calculation formulas for polymer modulating and sealing / channeling dosages (Equations 31-38), calculate the total polymer injection volume, sealing / channeling slug dosage, and modulating / channeling slug dosage, respectively. The calculation results are shown in Table 1. The total polymer injection volume V1 is 10126 m³. 3 The amount of polymer-sealed plug V2 is 3524m. 3 The polymer-modified drive plug dosage V3 is 6602m. 3 .

[0163] Table 1. Design of polymer flooding system dosage for injection well W1 in well group 1 of XS10-1 oilfield.

[0164]

[0165] On the other hand, such as Figure 7 As shown, this invention provides a chemical flow control parameter design device based on a four-dimensional well test model, including: a module for determining the polymer mobility and viscosity distribution field around the well, a module for determining the actual distribution field of polymer viscosity around the well, a module for determining the polymer viscosity distribution field of the entire block, and a module for determining the polymer flow control and sealing dosage for a single well group.

[0166] The module for determining the polymer mobility and viscosity distribution field around the well is used to calculate the circular distribution field of polymer mobility and polymer viscosity around the well based on the experimental well data of a single well after polymer-driven regulation.

[0167] The module for determining the actual distribution field of polymer viscosity around the well is used to plot the actual distribution field of polymer viscosity around the well by combining the shape factor and the principle of equal area transformation.

[0168] The module for determining the polymer viscosity distribution field of the entire block is used to draw the contour lines of the actual polymer viscosity distribution in different well groups together using the Petrophysical module in Petrel software, and generate a polymer viscosity distribution field map of the entire block.

[0169] The module for determining the amount of polymer injection, slugs used for slug control, and slug control for a single well group is used to determine the total amount of polymer injection, slug control, and slug control for a single well group based on the area factor and direction factor.

[0170] On the other hand, such as Figure 8 As shown, this invention provides a structural schematic diagram of an electronic device. This embodiment does not limit the specific implementation of the electronic device. Figure 8 As shown, the electronic device may include: a processor 202, a communications interface 204, a memory 206, and a communications bus 208.

[0171] The processor 202, communication interface 204, and memory 206 communicate with each other via communication bus 208. Communication interface 204 is used to communicate with other network elements such as clients or other servers. The processor 202 executes program 210, specifically performing the relevant steps in the above method embodiments.

[0172] Specifically, program 210 may include program code that includes computer operation instructions.

[0173] Processor 202 may be a central processing unit (CPU), an application-specific integrated circuit (ASIC), or one or more integrated circuits configured to implement embodiments of the present invention. The electronic device may include one or more processors of the same type, such as one or more CPUs; or it may include processors of different types, such as one or more CPUs and one or more ASICs.

[0174] Memory 206 is used to store program 210. Memory 206 may include high-speed RAM memory, and may also include non-volatile memory, such as at least one disk storage device.

[0175] Specifically, program 210 can be used to cause processor 202 to execute the chemical drive parameter design method based on a four-dimensional well test model in any of the above method embodiments.

[0176] The algorithms and displays presented herein are not inherently related to any particular computer, virtual system, or other apparatus. Various general purpose systems can be used with programs in accordance with the teachings herein, or it can prove convenient to construct more specialized apparatus to perform the required method steps. The required structure for a variety of these systems will be apparent from the description above. In addition, the present embodiments are not described with reference to any particular programming language. It will be appreciated that a variety of programming languages can be used to implement the teachings of the present disclosure as described herein, and any oblique descriptions of language are for illustrative purposes only and expressly not intended to limit the scope or appurtenance of the present disclosure.

[0177] In the description provided herein, numerous specific details are set forth. However, it is understood that embodiments of the application can be practiced without these specific details. In some instances, well-known methods, structures and techniques have not been described in detail in order to not obscure the understanding of this description. Also, the description occasionally refers to example embodiments of the application. This, however, does not mean that each and every implementation of the application requires each of the features that are described for an example implementation. Therefore, the description is not to be interpreted as a limitation on the scope of the application as claimed.

[0178] Those skilled in the art will appreciate that the modules in the apparatuses in the embodiments can be adapted and placed in one or more apparatuses other than the embodiments. The modules or units or components in the embodiments can be combined into one module or unit or component, and further can be divided into more sub-modules or sub-units or sub-components. Any combination of all the features disclosed in the specification (including the accompanying claims, abstract and drawings), and any method or apparatus so disclosed, can be used in any combination, except that at least some of such features and / or processes or units are mutually exclusive, unless explicitly stated otherwise. Each feature disclosed in the description (including the accompanying claims, abstract and drawings) can be replaced by alternative features serving the same, equivalent or similar purpose, unless explicitly stated otherwise.

[0179] Furthermore, those skilled in the art will appreciate that the features of the different embodiments can be combined in any combination with one another, as the scope of the present application is not limited by the features of any particular embodiment. For example, in the claims, any of the claimed embodiments can be used in any combination.

[0180] Various component embodiments of the present application can be implemented in hardware, or as software modules running in one or more processors, or in combinations thereof. As will be appreciated by those skilled in the art, a microprocessor or digital signal processor (DSP) can be used in practice to implement some or all of the functionality of some or all of the components according to embodiments of the present application. The present application can also be implemented as a program of instructions for performing part or all of the methods described herein, e.g., a computer program and a computer program product. Such program of the present application can be stored on a computer readable medium, or can be in the form of one or more signals. Such signals can be downloaded from an Internet website, or provided on a carrier signal, or in any other form.

[0181] It should be noted that the above-mentioned embodiments illustrate rather than limit the application, and that one skilled in the art will be able to design many alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. The word 'comprising' does not exclude the presence of elements or steps other than those listed in a claim. The word 'a' or 'an' preceding an element does not exclude the presence of a plurality of such elements. The application can be implemented by means of both hardware and software, and any combination thereof. In a unit claim, several devices can be listed with a conjunction like 'and'. None of these devices is a prerequisite for the others. The usage of the words 'first','second', and 'third', etc. do not limit the number of these devices. These designations can be interpreted as names. The steps of any method claims herein do not have to be performed in order. Unless otherwise defined, all terms are to be given their broadest interpretation.

Claims

1. A chemical profile control parameter design method based on a four-dimensional well test model, characterized in that, The method comprises the following steps: According to the single well real test well data after polymer profile control, the polymer mobility distribution field and the circular distribution field of polymer viscosity around the well are calculated; The actual distribution field of polymer viscosity around the well is drawn by combining the shape factor and the equal-area conversion principle; The actual distribution contour of polymer viscosity in different well groups is drawn together by using the Petrophysical module in Petrel software to generate the polymer viscosity distribution field map of the whole block; According to the area coefficient and the direction coefficient, the total polymer injection amount, the profile control slug amount and the channeling blocking slug amount of a single well group are determined; The circular distribution field of polymer viscosity around the well is obtained by combining the relationship between polymer mobility and polymer viscosity in the reservoir after polymer displacement and the polymer mobility distribution field around the well; the shape factor is the actual distribution shape of polymer viscosity in the reservoir near each well group; the area coefficient is determined according to the actual distribution field of polymer viscosity around the well, the inner radius of polymer profile control, the outer radius of polymer profile control and the polymer profile control radius; The actual distribution field of polymer viscosity around the well comprises the following steps: (1) the circular viscosity field contour area of radius r 1 of the circle is π r 1 2 ; (2) By applying the principle of equal area conversion, the radius determined based on the tracer's surge vector can be clearly defined as follows: r The area of ​​the actual viscosity contour lines corresponding to the circular viscosity field contour lines of 1 is also π. r 1 2 ; (3) Assume that the shape factor is a closed polygon composed of n points, where the coordinates of each point are A 1( x 1, y 1), A 2( x 2, y 2),…, A n ( x n , y n ), then the area of the shape factor is represented as: Since the shape factor is a closed polygon composed of n points, the first point in the coordinates of the shape factor is the first n +1 point, that is, x n+1 = x 1, y n+1 = y 1; the circular viscosity contour field in a well group is converted into the actual viscosity contour field by the equal-area conversion principle, and the expression is as follows: wherein: S is the area of the form factor, m 2 ; x is the abscissa of the point on the form factor; y is the ordinate of the point on the form factor.

2. The method according to claim 1, wherein, The polymer mobility distribution field around the well is obtained by the following method: The instantaneous mobility is determined according to the natural gas production, the natural gas formation volume factor, the reservoir thickness and the pressure derivative; The dimensionless pseudo-time is determined according to the instantaneous mobility, the time, the porosity, the comprehensive compressibility and the wellbore radius; The detection radius is determined according to the instantaneous mobility, the detection time, the porosity and the comprehensive compressibility; The mobility corresponding to the detection radius at the detection time is obtained by the following formula: where, M n is the fluid velocity, mD / (mPa s); is the instantaneous mobility, mD / (mPa s); M i represents the time at which the t i radius is probed at time r i corresponding mobility, mD / (mPa s); is the instantaneous dimensionless Boltzmann variable; W 1 / 2,1 / 2 is the Whittaker function.

3. The method according to claim 1, wherein, The total polymer injection amount is determined according to the outer radius of polymer profile control, the inner radius of polymer profile control, the thickness of polymer profile control layer, the formation porosity, the area coefficient of polymer injection and the injection pore volume multiple.

4. The method according to claim 1, wherein, The channeling blocking slug amount is determined according to the total polymer injection amount, the ratio of the thickness of high permeability layer to the thickness of water injection formation and the direction coefficient of polymer injection.

5. The method according to claim 1, wherein, The profile control slug amount is determined according to the total polymer injection amount and the channeling blocking slug amount.

6. A device for designing chemical profile control parameters based on a four-dimensional well test model, characterized in that, The method comprises the following steps: The well polymer mobility and viscosity distribution field determination module is used to calculate the polymer mobility distribution field and the circular distribution field of polymer viscosity around the well according to the single well real test well data after polymer profile control; The actual distribution field of polymer viscosity around the well is determined by combining the shape factor and the equal-area conversion principle; The whole block polymer viscosity distribution field determination module is used to draw the actual distribution contour of polymer viscosity in different well groups together by using the Petrophysical module in Petrel software to generate the polymer viscosity distribution field map of the whole block; The polymer profile control and channeling blocking amount determination module of a single well group is used to determine the total polymer injection amount, the profile control slug amount and the channeling blocking slug amount of a single well group according to the area coefficient and the direction coefficient; The circular distribution field of the polymer viscosity around the well is obtained by combining the polymer mobility distribution field around the well with the relationship between the polymer mobility and the polymer viscosity in the reservoir after polymer flooding; the shape factor is the actual distribution shape of the polymer viscosity in the reservoir near each well group; and the area coefficient is determined according to the polymer flooding inner radius, the polymer flooding outer radius and the polymer profile control radius in the actual distribution field of the polymer viscosity around the well. The method for drawing the actual distribution field of the polymer viscosity around the well comprises the following steps: (1) the circular viscosity field contour area of radius r 1 is π r 1 2 ; (2) Through the equal area conversion principle, it can be clear that the actual viscosity contour area corresponding to the circular viscosity field contour with a radius of r 1 determined by the tracer breakthrough vector is also π r 1 2 ; (3) Assume that the shape factor is a closed polygon consisting of n points, where the coordinates of each point are A 1( x 1, y 1), A 2( x 2, y 2),…, A n ( x n , y n ), then the area of the shape factor is represented as: Since the shape factor is a closed polygon composed of n points, the first point in the coordinates of the shape factor is the n +1th point, that is, x n+1 = x 1, y n+1 = y 1; the circular viscosity contour field in a well group is converted into the actual viscosity contour field by the equal-area conversion principle, and the expression is as follows: wherein: S is the area of the form factor, m 2 ; x is the abscissa of the point on the form factor; y is the ordinate of the point on the form factor.

7. An electronic device, comprising: The processor, the memory, the communication interface and the communication bus complete communication with each other through the communication bus; The memory is used for storing at least one executable instruction, and the executable instruction makes the processor execute the operation corresponding to the chemical profile control and flooding parameter design method based on the four-dimensional well testing model. 8.A computer storage medium, wherein at least one executable instruction is stored in the storage medium, and the executable instruction makes a processor execute the operation corresponding to the chemical profile control and flooding parameter design method based on the four-dimensional well testing model.

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