CN106894814B - Rapid identification method for secondary enrichment of residual oil in high-water-content later period of complex fault block oil reservoir - Google Patents

Abstract

The invention provides a rapid identification method for the secondary enrichment of residual oil in the later stage of high water cut in complex fault block oil reservoirs. It includes: measuring the target oil reservoir to obtain the geological parameters and well pattern parameters of the target oil reservoir; establishing a preliminary physical model of the target oil reservoir according to the geological parameters and well pattern parameters of the target oil reservoir; The physical model is fitted and calculated according to the streamline flow pipe method to obtain the dynamic fitting characteristics of the production well and the saturation field before the secondary enrichment of the remaining oil, and the preliminary physical model of the target oil reservoir is corrected to obtain The revised physical model; based on the revised physical model, the calculation of vertical enrichment and horizontal enrichment is carried out for each node in the process of remaining oil enrichment, so as to obtain the reservoir saturation and water content of each node, and achieve the goal Identification of secondary enrichment of remaining oil in late stage of high water-cut reservoir. This method can accurately predict the changes of the dynamic parameters of the displacement front.

Description

Rapid identification method for secondary enrichment of remaining oil in complex fault-block reservoirs with high water cut in late stage

technical field

The invention relates to a rapid identification method for the secondary enrichment of residual oil in the later stage of high water cut in a complex fault-block oil reservoir, and belongs to the field of complex fault-block oilfield development.

Background technique

Complex fault block reservoirs have the geological characteristics of "small, scattered, lean and fragmented". The development well pattern and the degree of reserve control are greatly affected by the plane distribution shape of the reservoir. Most fault blocks cannot form a perfect injection-production well pattern. . As a result, the complex fault block reservoirs generally have the problems of rapid water cut rise and low recovery degree. How to effectively improve the secondary enrichment and recovery degree of the remaining oil after water flooding development is to improve the water flooding development of complex fault block oilfields. effect and the key to enhanced ultimate oil recovery.

Most of the studies on the enrichment of remaining oil in the later stage of high water cut in conventional oil reservoirs do not consider the influence of imperfect injection-production well pattern, and the enrichment laws and calculation methods are relatively simple. However, in actual situations, both the geological characteristics of the reservoir and the imperfection of the injection-production well pattern will have an impact on complex fault-block reservoirs, so that there will still be a large amount of remaining oil in the later high water-cut reservoirs, mainly distributed in Intervals with strong heterogeneity and areas beyond the control of the well pattern. Therefore, the research on the enrichment of remaining oil in the later stage of high water cut in conventional oil reservoirs cannot meet the needs of the actual development of complex fault-block reservoirs. In the actual application process, it cannot effectively calculate the secondary enrichment of remaining oil, and cannot accurately predict A series of problems such as the change of the dynamic parameters of the displacement front.

To sum up, it is an urgent technical problem to be solved in this field to provide a new calculation method for the secondary enrichment of residual oil in the later stage of high water cut in complex fault-block reservoirs.

SUMMARY OF THE INVENTION

In order to solve the above technical problems, the present invention provides a rapid identification method for the secondary enrichment of residual oil in the later stage of high water cut in complex fault-block oil reservoirs, which can accurately predict the changes of displacement front parameters, so that complex fault-block oil reservoirs can be accurately identified. The rapid calculation of the secondary enrichment of the remaining oil in the later stage of high water cut is realized.

In order to achieve the above purpose, the present invention provides a rapid identification method for the secondary enrichment of residual oil in the later stage of high water cut in complex fault-block oil reservoirs. The method includes the following steps:

Step S10, measuring the target oil reservoir to obtain geological parameters and well pattern parameters of the target oil reservoir;

Step S11, establishing a preliminary physical model of the target oil reservoir according to the geological parameters and well pattern parameters of the target oil reservoir;

Step S12, based on the preliminary physical model of the target oil reservoir, perform fitting and calculation according to the streamline flow pipe method to obtain the dynamic fitting characteristics of the production well and the saturation field before the secondary enrichment of the remaining oil, and analyze the target oil reservoir. The preliminary physical model is corrected to obtain the corrected physical model; wherein, the dynamic fitting feature of the oil production well can represent the actual production performance of the oil production well;

Step S13, based on the revised physical model, perform vertical enrichment and horizontal enrichment calculations for each node in the process of remaining oil enrichment, so as to obtain the reservoir saturation and water cut of each node; Identification of secondary enrichment of residual oil in late water-bearing stage.

Compared with the prior art, the technical solution provided by the present invention simultaneously studies the geological characteristics of complex fault-block oil reservoirs and the characteristics of injection-production well pattern, and on this basis, establishes a target oil reservoir by establishing a target oil reservoir. The physical model (the physical model has the typical geological characteristics of the target oil reservoir), combined with the streamline flow pipe method theory and formula in the field, the final calculation method can be effectively applied to complex fault block reservoirs to achieve residual oil Fast calculation of secondary enrichment and accurate prediction of changes in dynamic parameters of the leading edge of the trunk.

In the technical solution provided by the present invention, the streamline flow pipe method refers to the streamline method and the flow pipe method, wherein the streamline method is a mathematical representation method for mathematically describing the plane migration law of underground fluids; The pipe method is a physical model building method to mathematically describe the spatial structure of the underground fluid and the migration relationship of each node in the space; these two methods are both calculation methods known in the art and professional terms in the art .

In the above calculation method, preferably, in step S12, the dynamic fitting characteristics of the oil production well include the following parameters: oil production, water production and water cut.

In the above calculation method, preferably, in step S11, according to the geological parameters and well pattern parameters of the target oil reservoir, establishing the physical model of the target oil reservoir includes the following steps:

According to the obtained well pattern parameters, set the bottom surface type of the preliminary physical model;

According to the obtained geological parameters, the geological parameters of the preliminary physical model are set.

In the above calculation method, preferably, according to the obtained well pattern parameters, setting the bottom surface type of the preliminary physical model includes the following steps:

According to the obtained well pattern parameters, determine the well pattern type, oil-water well ratio, well spacing and row spacing of the target reservoir;

According to the well pattern type and the ratio of oil-water wells, set the bottom surface type of the preliminary physical model (the setting process is shown in Figure 2):

When the well pattern type is staggered, the bottom surface type of the preliminary physical model is set to be an equilateral triangle;

When the well pattern type is facing, and the ratio of the number of oil-water wells = 1, the bottom surface type of the preliminary physical model is set to be rectangular;

When the well pattern type is facing, and the oil-water well ratio is ≠ 1, the bottom surface type of the preliminary physical model is set to be an equilateral triangle;

When the bottom surface type of the preliminary physical model is rectangle, set the length of the rectangle to be equal to the well spacing, and the width of the rectangle to be equal to the row spacing; when the bottom surface type of the preliminary physical model is equilateral triangle, set the side length of the regular triangle to be equal to the well spacing, and the length of the regular triangle to be equal to the well spacing. Height equals row spacing.

In the technical solution provided by the present invention, the preliminary physical model is a model with a three-dimensional spatial structure, and the three-dimensional spatial structure includes a horizontal X direction, a horizontal Y direction and a vertical Z direction (the horizontal X direction and the horizontal Y direction are perpendicular to each other, and the vertical Z direction is perpendicular to each other. The directions are perpendicular to the X direction and the Y direction respectively), and the bottom surface of the preliminary physical model is on the horizontal plane formed by the horizontal X direction and the horizontal Y direction. After the bottom surface type is determined according to the above method, the bottom surface is translated along the vertical Z direction for a section. The three-dimensional spatial structure obtained after the distance (this distance is the thickness of the preliminary physical model, which is equal to the thickness of the actual reservoir) is the spatial structure of the preliminary physical model. After a certain distance in the vertical direction, a cubic structure is obtained, and the cubic structure is the spatial structure of the preliminary physical model.

In this spatial structure, each single oil layer is divided into three directions according to horizontal X, horizontal Y, and vertical Z. On the horizontal plane, the plane is divided into multiple flow pipes according to the direction of the main flow of the fluid in the underground seepage (as shown in the figure). 8); the length of each flow tube varies according to the shape of the reservoir, and is numerically equal to the length of the reservoir at the corresponding position on the plane where a single flow tube is located. For regular rectangular reservoirs, each flow tube on the same plane has the same length; for triangular reservoirs, each flow tube on the same plane has a different length. The width of each flow tube (the width is the diameter of the flow tube) and the length (the length is the length of the flow tube in the direction of the main flow line) are numerically the same, and the division scale is flexibly determined according to the size of the reservoir, and the value range is 1 -20m.

After the plane flow pipe is divided, in the direction perpendicular to the main flow line, continue to divide according to the width and length of the flow pipe with the same plane setting. The flow pipes in the three directions will intersect in space to form a grid, and the intersection point is the calculation Nodes (as shown in Figure 9, the dots in the figure represent nodes, and the circular tubes represent flow tubes); each flow tube in the direction of the main flow line corresponds to an output end.

Because the stratum is heterogeneous, the fluid usually has anisotropy in the underground seepage process, that is, the flow direction is not single, and there may be flow in all directions, but there must be a main flow direction, which is related to mining. Because whether it is an oil production well or a water injection well, the formation pressure will change near the well point (the formation pressure near the oil production well point will decrease, and the formation pressure near the water injection well point will increase), thus forming a pressure in the production area. The pressure difference is the main power source for driving the underground fluid flow, and this direction is the direction of the main flow line described in the present invention.

In the above calculation method, preferably, the step S12 includes the following steps:

Step S121, preset reservoir characteristic parameters of the preliminary physical model to obtain preset reservoir characteristics;

Use the actual dynamic history characteristics of the oil production well to fit the preset reservoir characteristic parameters to determine the final dynamic fitting characteristics of the oil production well and the reservoir characteristics of the preliminary physical model; wherein, the actual dynamic history of the oil production well Features include parameters such as oil production, water production and water cut;

Step S122, according to the streamline flow pipe method, the oil saturation field before the secondary enrichment of the remaining oil is obtained by preliminary fitting;

The oil saturation field before the secondary enrichment of the remaining oil obtained by preliminary fitting is fitted and corrected by using the saturation correction relationship to determine the final oil saturation field before the secondary enrichment of the remaining oil;

Step S123, correcting the preliminary physical model of the target oil reservoir to obtain a corrected physical model.

In the above calculation method, preferably, in step S121, the characteristic parameters of the reservoir include initial oil saturation, reservoir thickness, reservoir dip, injection-production rate and average permeability.

In the above calculation method, preferably, in step S121, the preset reservoir characteristic parameters are fitted by using the actual dynamic historical characteristics of the oil production well, so as to determine the dynamic fitting characteristics of the final oil production well and the correlation of the preliminary physical model. Reservoir characterization, including the following steps:

Based on the preliminary physical model of the target oil reservoir, the fitting calculation is carried out according to the streamline flow pipe method, and the dynamic fitting characteristics of the oil production well obtained by preliminary fitting are obtained;

When the dynamic fitting characteristics of the production wells obtained by the preliminary fitting are consistent with the actual dynamic historical characteristics of the oil producing wells in the target reservoir, it is judged that the dynamic fitting characteristics of the oil production wells obtained by the preliminary fitting meet the requirements;

When the dynamic fitting characteristics of the production wells obtained by the preliminary fitting do not match the actual dynamic historical characteristics of the oil producing wells in the target reservoir, it is judged that the dynamic fitting characteristics of the production wells obtained by the preliminary fitting do not meet the requirements; When it is necessary to modify the reservoir characteristic parameters of the preliminary physical model, and re-fit the dynamic fitting characteristics of the production wells according to the streamline flow pipe method, until the dynamic fitting characteristics of the oil production wells are consistent with the production wells in the target reservoir is consistent with the actual dynamic historical characteristics;

When the dynamic fitting characteristics of the production wells obtained by preliminary fitting are consistent with the actual dynamic historical characteristics of the oil production wells in the target oil reservoir, the corresponding reservoir characteristics are determined to be the reservoir characteristics of the preliminary physical model.

In the above calculation method, preferably, in step S122, according to the streamline flow pipe method, the preliminary fitting to obtain the oil saturation field before the secondary enrichment of the remaining oil includes the following steps:

Calculate the water content and water rise rate of each node in the direction of the main flow line;

Calculate the saturation of the water-bearing front and the position of the water-bearing front in the direction of the main flow line;

Calculate the total moisture content at the output end in the direction of the main flow line.

In the above calculation method, preferably, in step S122, the oil saturation field before the secondary enrichment of the remaining oil obtained by preliminary fitting is fitted and corrected by using the saturation correction relationship, including the following steps:

Set the saturation correction relationship, correct the oil saturation field obtained by preliminary fitting before the secondary enrichment of the remaining oil, and obtain the corrected oil saturation field;

When the corrected oil saturation field is consistent with the actual oil saturation field of the target oil reservoir, it is judged that the corrected oil saturation field meets the requirements;

When the corrected oil saturation field does not match the actual saturation field of the target reservoir, it is judged that the corrected oil saturation field does not meet the requirements; The oil saturation field before the secondary enrichment of the remaining oil is re-corrected until the corrected oil saturation field is consistent with the actual oil saturation field of the target reservoir; the corrected oil saturation field is consistent with the actual oil saturation field of the target reservoir. When the oil saturation field is consistent, it is determined as the final oil saturation field before the secondary enrichment of the remaining oil.

In the technical solution provided by the present invention, the actual underground saturation field is unknown, and the information obtained through the single well test can only represent one underground point, that is, the current saturation level at the location of the well. For the overall reservoir, the saturation data obtained through several well points is still very limited for the entire reservoir, so it is necessary to use these known data to predict the saturation of other locations in the reservoir. The data is usually based on the data of adjacent known points, and the unknown data between two adjacent points is obtained by interpolation method, but the prediction result obtained by such interpolation cannot represent the real reservoir saturation, so it needs to be checked and corrected. The test method is to fit the performance of a single well (including oil production, water production, and water cut) by constantly correcting the saturation predicted by the interpolation method, because the performance of a single well is the data that can actually be measured. If the single-well fitting result is consistent with the actual single-well performance, it means that the predicted saturation or the corrected saturation is consistent with the actual saturation field; otherwise, the correction needs to be continued.

In the above calculation method, preferably, in step S11, the calculation method further includes setting the sedimentary rhythm, geological dip and permeability anisotropy of the preliminary physical model according to the actual geological structure characteristics of the target oil reservoir; wherein:

Sedimentary rhythm refers to the diagenetic law of layered deposition in the order of particle size and specific gravity, and is divided into three types: homogeneous rhythm, positive rhythm, and inverse rhythm; homogeneous in physical properties; positive rhythm sand layer: coarse grain size in the lower part, fine grain size in the upper part, reflecting the weakening of the hydrodynamic conditions of the sedimentary environment from bottom to top; anti-rhythm sand layer: fine grain size in the lower part, coarse grain size in the upper part, and hydrodynamic conditions of the sedimentary environment Conditions become stronger from bottom to top;

Formation dip refers to the angle between the oil layer strike and the horizontal plane between oil and water wells;

Permeability anisotropy means that there are differences in permeability changes in different directions of the oil layer.

In the above calculation method, preferably, the geological parameters of the preliminary physical model are set according to the obtained geological parameters, which mainly means that the average permeability and the initial oil saturation of the preliminary physical model are set according to the obtained actual geological parameters of the target oil reservoir. , porosity, irreducible water saturation, residual oil saturation, permeability gradient, underground crude oil viscosity, reservoir thickness, number of reservoir layers, injection-production rate and other conventional parameters that need to be acquired in reservoir measurement; among them:

Average permeability refers to the ability of rock to allow fluid to pass under a certain pressure difference;

The initial oil saturation is the ratio of the oil-bearing volume in the effective pores of the oil layer to the effective pore volume of the rock, expressed as a percentage;

Porosity refers to the ratio of the sum of the volume of all pore spaces in a rock sample to the volume of the rock sample;

The irreducible water saturation refers to the percentage of the minimum water body remaining in the rock pores in the pore volume of the reservoir due to the wettability of the rock surface;

Residual oil saturation refers to the percentage of the volume of residual oil in rock pores;

The permeability gradient refers to the ratio of the maximum permeability to the minimum permeability;

Subterranean crude oil viscosity is a measure of the frictional resistance of one part of the crude oil to flow relative to another part under formation conditions.

In the above calculation method, preferably, after the end of step S11 and before the start of step S12, the calculation method includes, based on the preliminary physical model of the target oil reservoir, pre-determining the number of vertical division layers and the vertical heterogeneity of the preliminary physical model. The steps of setting include the following processes:

The thickness of a single layer of the preliminary physical model = the total thickness of the preliminary physical model/the preset number of longitudinally divided layers;

Initial heterogeneity of the preliminary physical model = preset longitudinal heterogeneity.

In the above calculation method, preferably, in step S122, based on the preliminary physical model of the target oil reservoir, according to the streamline flow pipe method, the preliminary fitting to obtain the saturation field before the secondary enrichment of the remaining oil includes the following steps:

①Calculate the water content and water rise rate of each node in the direction of the main flow line; the water content here refers to the water content calculated by the Berkeley-Lewirt formula (B-L formula for short) in the direction of the main flow line. In the physical model Each node on the main line can obtain a corresponding data after calculation by this formula, so a series of data points are obtained;

② Calculate the water-bearing front saturation and the water-bearing front position in the direction of the main flow line;

③ Calculate the total water content of the output end in the direction of the main flow line;

(4) Judging the total water content of the production end in the direction of the main flow line, and correcting the reservoir characteristic parameters according to the actual water content of the oil production well, so that the fitted water content of the oil production well is consistent with the actual water content;

⑤ Based on the calculation method from step ① to step ④, obtain the oil saturation field corresponding to the fitting water cut of the production well when it meets the requirement of secondary enrichment of remaining oil, and the oil saturation field is the predicted value;

⑥ Interpolate the oil saturation from the boundary to the main flow line to correct the oil saturation field obtained in step ⑤, so as to obtain the saturation field before the secondary enrichment of the remaining oil.

In the above calculation method, preferably, in step ①:

The formula for calculating the moisture content of each node in the direction of the main flow line is shown in Equation 1, which can be used to calculate the moisture content corresponding to any point in the physical model

In formula 1, f _w is the water content, a decimal; k _rw , k _ro are the relative permeability of water phase and oil phase, dimensionless; μ _w , μ _o are the viscosity of water phase and oil phase, mPa·s ;

More preferably, the calculation formula of the water rise rate is as shown in formula 2

In Equation 2, _f'w is the water rise rate (the reciprocal of the water content), a decimal; _Sw is the water saturation, a decimal; i is the i-th node position, and i-1 is the previous node position of the i-node place.

In the above calculation method, preferably, in step ②, calculating the saturation of the water-bearing front and the position of the water-bearing front include:

According to the _Sw - _fw relationship curve, connect each _Sw - _fw relationship curve node to form a line through the _Swi point, find the derivative of the line, and the node with the largest derivative value is the front water saturation _Swf ; Then, according to the relationship of S _w - f' _w , the value of f' _w (S _wf ) is obtained; finally, the position x _f of the water-bearing front is obtained.

In the above calculation method, preferably, in step ②, the calculation formula of the position of the water-bearing front on the main flow line is as shown in Equation 3

in,

In Equation 3, x _f is the position of the water-bearing front, m; x ₀ is the initial position of water-bearing, m; f' _w (S _wf ) is the water-cut rise rate corresponding to the saturation of the water-bearing front, a decimal; Φ is the porosity, decimal; A is the cross-sectional area, m ² ; Q is the flow rate, m ³ ; t is the displacement time, days; f _w ( _{Swf ) is the water content corresponding to the saturation of the water-bearing front, a decimal; S wf is} the water-bearing front Saturation, decimal; S _wc is the irreducible water saturation, decimal.

In the above calculation method, preferably, in step 3, calculating the total water content of the output end in the direction of the main flow line includes:

According to the ratio of the water injection volume of each layer and the permeability of each flow pipe, the flow rate of each flow pipe is split, and the water breakthrough time of each layer and the water content of each layer at the output end are calculated;

According to the flow rate of each flow pipe, the water content at the output end of each layer is weighted and averaged to obtain the total water content at the output end on the main flow line.

In the above calculation method, preferably, in step ③, preferably, the calculation formula of the water breakthrough time of each layer is shown in formula 4

In Equation 4, x _f is the position of the water-bearing front, m; x ₀ is the initial position of water-bearing, m; _f'w (S _wf ) is the water-cut rise rate corresponding to the saturation of the water-bearing front, a decimal; A is the cross-sectional area, m ² ; Q is the flow rate, m ³ .

In the above calculation method, preferably, in step 3, the calculation of the moisture content at the output end of each layer includes:

When calculating, first determine the water penetration time of each flow pipe, and then use the flow splitting method to calculate the water rise rate corresponding to the water saturation at the output end of each layer according to the formula shown in Equation 5, and then according to the formula shown in Equation 2 formula, calculate the moisture content f _w at the output end of each layer;

In Equation 5, _t is the production time, days; _T is the water breakthrough time, days; L is the oil-water well spacing, m; decimal.

In the above method, preferably, in step (4), judging the total water content of the output end in the direction of the main flow line includes the following steps: starting from the initial time, comparing the calculated total water content of the output end in the direction of the main flow line with the The actual water cut of the oil production well is numerically compared; when the two values do not match, the reservoir characteristic parameters should be corrected. If the calculated water content obtained by the revised model is consistent with or has a small difference between the actual water content, the fitting process of the water content corresponding to this time point is completed, and the judgment of the water content corresponding to the next time point begins. ; Until the termination time of the actual water content measurement, the judgment process ends and the water content fitting is completed. Among them, for thin oil reservoirs, when the numerical difference is within -5%-5%, the difference is considered small, otherwise, the difference is considered large; for heavy oil reservoirs, the numerical difference is -15%-15% When the difference is within the range, the difference is considered to be small, otherwise the difference is considered to be large.

In the above calculation method, preferably, in step S13, the calculation process of the vertical enrichment includes:

① Calculate the vertical height difference of each node of each flow pipe, and then accumulate and sum the vertical height difference of each node of each flow pipe according to the top-to-bottom method and the bottom-to-top method to obtain the vertical height difference. The total vertical height difference of each node of each flow pipe upward (the total vertical height difference includes the total vertical height difference of each node of each flow pipe vertically from top to bottom, and the vertical height difference of each flow pipe from bottom to top vertically The total vertical height difference of the pipe feeding stage);

② Calculate the average water saturation when each node of each flow pipe in the vertical direction is completely balanced; wherein, the complete equilibrium refers to the state in which the remaining oil cannot be enriched after being enriched. At this time, the oil content in the vertical and horizontal directions is Saturation no longer changes;

Compare the thickness of each flow tube with the total vertical height difference of each node of each flow tube in the vertical direction obtained in step ①, so as to obtain the saturation profile when each node of each flow tube in the vertical direction is completely balanced. The maximum saturation average value and the minimum saturation average value of each node above;

③Compare the average water saturation when each node of each flow tube is completely balanced with the average maximum water saturation and the average minimum water saturation of each node on the saturation profile to obtain the profile equilibrium type A, profile Equilibrium sub-type B, the inter-node scale coefficient a of the profile equilibrium type, the inter-node scale coefficient b of the profile equilibrium sub-type, the equilibrium position of the profile equilibrium type A and the equilibrium position of the profile equilibrium sub-type B ;

④ Calculate the water saturation of the secondary oil-water interface and the equivalent capillary force at the equilibrium state of the profile;

⑤ Calculate the water saturation and relative permeability of oil and water at each node of each flow pipe in the vertical direction.

大于最大含水饱和度的平均值

的节点个数；所述剖面平衡态次级类型B是指垂向上每条流管各节点完全平衡时，各节点的平均含水饱和度

小于最小含水饱的平均值

的节点个数；所述节点间比例系数包含剖面平衡态类型节点间比例系数a和剖面平衡态次级类型节点间比例系数b；其中，剖面平衡态类型节点间比例系数a是指垂向上每条流管各节点完全平衡时，各节点的平均含水饱和度

小于最大含水饱和度的平均值

的节点个数占该条流管节点总数的比值；剖面平衡态次级类型节点间比例系数b是指垂向上每条流管各节点完全平衡时，各节点的平均含水饱和度

大于最大含水饱和度的平均值

的节点个数占该条流管节点总数的比值；所述平衡位置是指在完全平衡条件下平均含水饱和度值所处的油层剖面的位置，其包括剖面平衡态类型A的平衡位置和剖面平衡态次级类型B的平衡位置；所述次生油水界面的剖面含水饱和度是指由于重力影响下产生次生油水界面下计算出剖面各节点的含水饱和度值；所述剖面平衡态等效毛管力是指根据次生油水界面的剖面含水饱和度计算出考虑重力影响的剖面各节点处的毛管力值。In the above calculation method, the profile equilibrium state type A refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced.

greater than the average value of maximum water saturation

The number of nodes in the equilibrium state of the profile B refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced.

less than the mean value of minimum water saturation

The number of nodes in When each node of the strip tube is completely balanced, the average water saturation of each node

less than the mean value of maximum water saturation

The ratio of the number of nodes to the total number of nodes in the flow pipe; the proportionality coefficient b between the nodes of the secondary type in the equilibrium state of the profile refers to the average water saturation of each node when the nodes of each flow pipe in the vertical direction are completely balanced.

greater than the average value of maximum water saturation

The ratio of the number of nodes to the total number of nodes in the flow pipe; the equilibrium position refers to the position of the oil layer profile where the average water saturation value is located under the condition of complete equilibrium, which includes the equilibrium position and profile of the profile equilibrium type A The equilibrium position of the secondary type B in the equilibrium state; the profile water saturation of the secondary oil-water interface refers to the water saturation value of each node of the profile calculated under the secondary oil-water interface generated under the influence of gravity; the profile equilibrium state, etc. Effective capillary force refers to the calculation of the capillary force value at each node of the profile considering the influence of gravity according to the profile water saturation of the secondary oil-water interface.

In the above calculation method, preferably, in step ①, the calculation formula of the vertical height difference of each node of each flow pipe is as shown in Equation 6

In Equation 6, Δh is the height difference caused by the capillary force, m; P _c is the capillary force at each node, atm; γ _w is the weight of water, ×10 ⁴ N/m ³ ; γ _o is the oil's Severity, ×10 ⁴ N/m ³ ; i is the subscript representing the i-th node position, i+1 represents the next node position of the i-node, for example, P _c(i) represents the capillary at the i-th node position force, P _c(i+1) represents the capillary force at the i+1th node position.

Preferably, in step ①, the vertical height difference of each node of each flow pipe is accumulated and summed in a top-to-bottom manner, and when the total vertical height difference of each node in the vertical direction is obtained, the calculation formula is as shown in Equation 7 shown

In Equation 7, h _ud(i) is the total vertical height difference of each node of each flow pipe from top to bottom in the vertical direction; i is the position of the ith node; j is the position of the jth node;

Preferably, in step ①, the vertical height difference of each node of each flow pipe is accumulated and summed in a downward-to-up manner, and when the total vertical height difference of each node in the vertical direction is obtained, the calculation formula is as shown in Equation 8 shown

In Equation 8, h _du(i) is the total vertical height difference of each node of each flow pipe from bottom to top; i is the position of the i-th node; j is the position of the j-th node; n is the The total number of nodes in each flow pipe vertically.

In the above calculation method, preferably, in step ②, the calculation formula of the average water saturation when each node of each flow pipe in the vertical direction is completely balanced is shown in 9

为垂向上每条流管各节点完全平衡时的平均含水饱和度；S_wz为垂向上每条流管完全平衡时各节点的含水饱和度；i为第i个节点位置处；n为垂向上每条流管节点总数；In Equation 9,

is the average water saturation of each node of each flow tube in the vertical direction when it is completely balanced; S _wz is the water saturation of each node when each flow tube is completely balanced in the vertical direction; i is the position of the i-th node; n is the vertical direction The total number of nodes in each flow pipe;

Preferably, in step ②, when each node of each flow pipe in the vertical direction is completely balanced, the calculation formula of the average value of the maximum water saturation of each node on the saturation profile is as shown in Equation 10

为垂向上每条流管各节点完全平衡时，饱和度剖面上各节点的最大含水饱和度的平均值；S_w为各节点含水饱和度；h_ud为垂向上从上往下每条流管各节点的总垂向高度差；h为小层厚度；Δh为垂向上每条流管各节点的垂向高度差；i为第i个节点位置处；j为第j个节点位置处；n为垂向上每条流管节点总数；In Equation 10,

is the average value of the maximum water saturation of each node on the saturation profile when the nodes of each flow tube are completely balanced in the vertical direction; S _w is the water saturation of each node; h _ud is the vertical direction of each flow tube from top to bottom The total vertical height difference of each node; h is the thickness of the small layer; Δh is the vertical height difference of each node of each flow pipe in the vertical direction; i is the position of the ith node; j is the position of the jth node; n is the total number of nodes of each flow pipe in the vertical direction;

Preferably, in step ②, when each node of each flow tube in the vertical direction is completely balanced, the calculation formula of the average value of the minimum water saturation of each node on the saturation profile is as shown in Equation 11

为垂向上每条流管各节点完全平衡时，饱和度剖面上各节点的最小含水饱和度的平均值；S_w为各节点含水饱和度；h_du为垂向上从下往上每条流管各节点的总垂向高度差；h为小层厚度；Δh为垂向上每条流管各节点的垂向高度差；i为第i个节点位置处；j为第j个节点位置处；n为垂向上每条流管节点总数。In Equation 11,

is the average value of the minimum water saturation of each node on the saturation profile when each node of each flow pipe is completely balanced in the vertical direction; S _w is the water saturation of each node; h _du is the vertical direction from bottom to top of each flow pipe The total vertical height difference of each node; h is the thickness of the small layer; Δh is the vertical height difference of each node of each flow pipe in the vertical direction; i is the position of the ith node; j is the position of the jth node; n is the total number of nodes of each flow pipe in the vertical direction.

In the above calculation method, preferably, in step ③, the calculation formula of the proportional coefficient between nodes of the profile equilibrium type is as shown in Equation 12

为垂向上每条流管各节点完全平衡时，饱和度剖面上各节点的最大含水饱和度的平均值；

为垂向上每条流管各节点的平均含水饱和度；A为剖面平衡态类型；i为第i个节点位置处；n为垂向上每条流管节点总数。In Equation 12, a is the proportionality coefficient between nodes of the section equilibrium state type;

is the average value of the maximum water saturation of each node on the saturation profile when each node of each flow pipe in the vertical direction is completely balanced;

is the average water saturation of each node of each flow tube in the vertical direction; A is the type of section equilibrium state; i is the position of the ith node; n is the total number of nodes of each flow tube in the vertical direction.

In the above calculation method, preferably, in step ③, the calculation formula of the inter-node proportional coefficient of the secondary type of the profile equilibrium state is as shown in Equation 13

为垂向上每条流管各节点完全平衡时，饱和度剖面上各节点的最小含水饱和度的平均值；

为垂向上每条流管各节点的平均含水饱和度；B为剖面平衡态次级类型；i为第i个节点位置处；n为垂向上每条流管节点总数。In Equation 13, b is the proportionality coefficient between secondary type nodes in the section equilibrium state;

is the average value of the minimum water saturation of each node on the saturation profile when each node of each flow pipe in the vertical direction is completely balanced;

is the average water saturation of each node of each flow tube in the vertical direction; B is the secondary type of the profile equilibrium state; i is the position of the ith node; n is the total number of nodes of each flow tube in the vertical direction.

In the above calculation method, preferably, in step ③, the calculation formula of the equilibrium position of the profile equilibrium type is as shown in Equation 14

In Equation 14, x _a is the equilibrium position of the profile equilibrium type; h is the thickness of the small layer, m; h _ud is the total vertical height difference of each node of each flow pipe from top to bottom in the vertical direction, m; a is the profile The proportional coefficient between the nodes of the equilibrium type; i is the position of the i-th node; A is the equilibrium type of the section.

In the above calculation method, preferably, in step ③, the calculation formula of the equilibrium position of the secondary type of the profile equilibrium state is as shown in Equation 15

In Equation 15, x _b is the equilibrium position of the secondary type in the profile equilibrium state; h is the thickness of the small layer, m; h _du is the total vertical height difference of each node of each flow pipe vertically from bottom to top, m; b is the proportional coefficient between the nodes of the secondary type of the profile equilibrium state; i is the position of the i-th node; B is the secondary type of the profile equilibrium state.

In the above calculation method, preferably, in step ④, the calculation formula of the cross-sectional water saturation of the secondary oil-water interface is as shown in Equation 16

In Equation 16, S _wpm is the profile water saturation of each node at the secondary WOC interface position, a decimal; S _w is the water saturation corresponding to each node in the phase permeability, a decimal; Δh is the oil-water height caused by capillary force difference, m; H _pm is the section height of each node at the position of the secondary WOC interface, m; i is the position of the ith node.

In the above calculation method, preferably, in step ④, the calculation formula of the equivalent capillary force in the section equilibrium state of the secondary oil-water interface is as shown in Equation 17

In Equation 17, S _wpm is the profile water saturation of each node at the secondary WOC interface position, a decimal; S _w is the water saturation corresponding to each node in the phase permeability, a decimal; P _cpm is the secondary WOC interface position every Section capillary force of each node, atm; P _c is the capillary force corresponding to each node in the capillary pressure curve, atm; i is the subscript indicating the position of the i-th node, i-1 indicates the position of the previous node of the i node .

In the above calculation method, preferably, in step ⑤, the calculation process of the water saturation of each node of each flow pipe in the vertical direction and the relative permeability of oil and water phases includes:

Step 1: Calculate the relative permeability of oil phase and water phase corresponding to each node of each flow tube in the vertical direction at the initial time of enrichment. The calculation formula is shown in Equation 18.

In Equation 18, K _r(t0) is the relative permeability of each node of oil and water at the initial time of enrichment, dimensionless; K _r is the relative permeability of each node in the oil-water phase permeability, dimensionless; _Sw is Water saturation corresponding to each node in the oil-water phase infiltration, decimal; S _w(t0) is the water saturation of each node at the initial time of enrichment, decimal; i is the subscript indicating the position of the ith node, i-1 Represents the position of the previous node of the i node;

Step 2: Calculate the oil saturation corresponding to each node of each flow tube in the vertical direction during the enrichment process. The calculation formula is shown in Equation 19.

In Equation 19, S _o is the oil saturation corresponding to each node, decimal; K _Z is the permeability corresponding to each node in the Z direction, mD; K _ro is the relative oil permeability of each node, dimensionless ; K _rw is the relative permeability of water at each node, dimensionless; μ _w is the viscosity of water, mPa s; μ _o is the viscosity of oil, mPa s; P _c is the capillary force of each node, atm ; P _c∞ is the profile capillary force of each node at the secondary WOC interface position, atm; φ is the porosity, decimal; t is the enrichment time, days; n is the number of time periods divided; i is the position of the ith node place;

Step 3: Calculate the relative permeability of the oil phase and the water phase corresponding to each node of each flow tube in the vertical direction at the time of completion of enrichment. The calculation formula is shown in Equation 20.

In Equation 20, K _r(tj) is the relative permeability of each node at the time of calculation of enrichment, dimensionless; K _r is the relative permeability of each node in the oil-water phase permeability, dimensionless; S _w is the water saturation corresponding to each node in the oil-water phase infiltration, decimal; S _w(tj) is the water saturation of each node at the time of completion of the calculation of enrichment, a decimal; i is the subscript indicating the position of the i-th node, i -1 means at the previous node position of the i-node.

In the above calculation method, preferably, in step S13, the calculation process of the horizontal enrichment includes:

Step 1: Calculate the capillary force corresponding to each node of each flow tube on the plane at the initial moment of enrichment. The calculation formula is shown in Equation 21

In Equation 21, P _c(t0) is the capillary force of each node at the initial time of enrichment, atm; P _c is the capillary force corresponding to each node in the capillary pressure curve, atm; S _w is each of the oil-water permeability Water saturation corresponding to the node, decimal; S _w(t0) is the water saturation of each node at the initial time of enrichment, decimal; i is the subscript indicating the position of the i-th node, i-1 indicates the previous node of the i node node location;

Step 2: Calculate the oil saturation corresponding to each node of each flow tube on the plane during the enrichment process. The calculation formula is shown in Equation 22.

In Equation 22, S _o is the oil saturation corresponding to each node, decimal; K _Z is the permeability corresponding to each node in the X direction, mD; K _ro is the relative oil permeability of each node, dimensionless ; K _rw is the relative permeability of water at each node, dimensionless; μ _w is the viscosity of water, mPa s; μ _o is the viscosity of oil, mPa s; P _c is the capillary force of each node, atm ; φ is porosity, decimal; t is time, days; n is the number of time periods divided; i is the subscript to indicate the position of the i-th node, i+1 indicates the position of the next node of the i-node, i-1 Represents the position of the previous node of the i node;

Step 3: Calculate the capillary force corresponding to each node of each flow tube on the plane at the time of completion of enrichment. The calculation formula is shown in Equation 23

In Equation 23, P _c(tj) is the capillary force of each node at the time of enrichment completion, atm; P _c is the capillary force corresponding to each node in the capillary pressure curve, atm; S _w is each node in the oil-water permeability Corresponding water saturation, decimal; S _w(tj) is the water saturation of each node at the time of enrichment completion, decimal; i is the subscript indicating the position of the i-th node, and i-1 indicates the previous node of the i node location;

Step 4, according to the oil saturation corresponding to each node of each flow tube on the plane during the enrichment process, and formula 20, obtain the relative permeability of oil phase and water phase of each node of each flow tube on the plane.

In a specific embodiment, step S12 includes the following processes (as shown in Figures 3 and 4):

(1) Presetting the characteristic parameters of the preliminary physical model to obtain a preset preliminary physical model; wherein,

Set the thickness of a single layer of the preliminary physical model = the total thickness of the preliminary physical model / the preset number of longitudinal division layers;

Set Initial Heterogeneity of Preliminary Physical Model = Preset Longitudinal Heterogeneity;

(2) Based on the preset preliminary physical model, the fitted water cut of the oil production well is calculated according to the streamline flow pipe method;

(3) Judging the fitted water cut of the calculated oil production well:

The fitted water cut is consistent with the actual water cut of the oil production well in the target oil reservoir, and it is judged that the fitted water cut meets the requirements;

The fitted water cut does not match the actual water cut of the production wells in the target oil reservoir, and it is judged that the fitted water cut does not meet the requirements; at this time, it is necessary to divide the number of vertical layers and the vertical non-conformity of the preliminary physical model. The homogeneity is modified, and the operation process of steps (2)-(3) is repeated until the fitted water cut is consistent with the actual water cut of the oil production well on the target reservoir;

(4) Based on the preset preliminary physical model, set the target water cut, and calculate the oil saturation field when the water cut of the oil production well reaches the target water cut according to the streamline flow pipe method; wherein, the target water cut is the production The water content of the oil well reaches the water content corresponding to the time of shut-in enrichment;

(5) setting the saturation correction relationship, and using it to correct the oil saturation field calculated in step (4) to obtain the corrected oil saturation field;

(6) Judge the corrected oil saturation field:

The corrected oil saturation field is consistent with the actual saturation field of the target oil reservoir, and it is judged that the corrected oil saturation field meets the requirements;

The corrected oil saturation field is inconsistent with the actual saturation field of the target oil reservoir, and it is judged that the corrected oil saturation field does not meet the requirements; at this time, reset the saturation correction relationship, and repeat steps ( 5) to the operation process of step (6), until the corrected oil saturation field is consistent with the actual saturation field of the target oil reservoir;

(7) Correcting the preliminary physical model of the target oil reservoir to obtain the corrected physical model.

In a specific embodiment, step S13 includes the following processes:

(1) Calculate the vertical height difference of each node of each flow pipe, and carry out the cumulative summation according to the top-to-bottom method and the bottom-to-top method respectively to obtain the total vertical height difference corresponding to each vertical node position;

(2) Calculate the average water saturation when each node of each flow pipe in the vertical direction is completely balanced, and compare the thickness of the layer where each flow pipe is located and the total vertical height difference corresponding to the position of each node in the vertical direction. Obtain the maximum water saturation average value and the minimum water saturation average value of each node on the saturation profile;

(3) Compare the average water saturation in the vertical direction with the average value of the maximum water saturation and the average value of the minimum water saturation at each node on the saturation profile to obtain the profile equilibrium type, profile equilibrium secondary type, The inter-node scale factor of the profile equilibrium type, the inter-node scale factor of the profile equilibrium sub-type, the equilibrium position of the profile equilibrium type and the equilibrium position of the profile equilibrium sub-type;

(4) Calculate the profile water saturation of the secondary oil-water interface and the equivalent capillary force in the profile equilibrium state;

(5) Preset enrichment time and enrichment times. In each cycle calculation, perform vertical and horizontal enrichment calculations respectively, and calculate the water saturation at each node of each flow tube and the relative relationship between oil and water phases. Permeability (as shown in Figure 5);

(6) After completing one vertical and horizontal enrichment calculation in each cycle, judge whether the preset enrichment times are reached. If not, perform step (5) calculation again. If the enrichment times are reached, the output is saved for the last time. Accumulate the calculated water saturation and relative permeability data of oil and water at each node of each flow pipe;

(7) According to the data obtained in step (6), calculate the water cut at the end of the production well, that is, the water cut at the opening of the production well, and output the water cut at the opening of the production well, and the calculation is over.

Beneficial effects of the present invention:

The existing method is not suitable for the geological and well pattern characteristics of complex fault-block oil reservoirs, and cannot effectively perform rapid calculation of the secondary enrichment of remaining oil. The technical solution provided by the present invention effectively solves this drawback of the existing method, It can accurately predict the changes of displacement front parameters, which enables the rapid calculation of the secondary enrichment of remaining oil in the later stage of high water cut in complex fault-block reservoirs.

Description of drawings

Fig. 1 is a schematic flowchart of the method for rapid identification of secondary enrichment of remaining oil in the later stage of high water cut in complex fault-block reservoirs;

Fig. 2 is the schematic flow chart of the establishment of the preliminary physical model of the complex fault block oil reservoir in Example 1;

3 is a schematic flowchart of a method for fitting the dynamic historical characteristics of oil production wells in Example 1;

Fig. 4 is the calculation flow schematic diagram of the saturation field before the remaining oil secondary enrichment in Example 1;

5 is a schematic diagram of the calculation flow of each node parameter in the secondary enrichment process of remaining oil in Example 1;

6 is a schematic diagram of the spatial structure of a physical model of a complex fault-block oil reservoir in Example 1;

Figure 7 is a comparison diagram of the plane oil saturation field before and after the enrichment of the remaining oil in Example 1 and the vertical oil saturation field. In the figure, A is the oil saturation field in the horizontal direction before enrichment, and C is the vertical oil saturation field before enrichment. oil saturation field in the horizontal direction after enrichment, B is the oil saturation field in the horizontal direction after enrichment, D is the oil saturation field in the vertical direction after enrichment;

Fig. 8 is the schematic diagram of the flow pipe of the horizontal plane along the direction of the main flow line;

FIG. 9 is a schematic diagram of the spatial structure of the flow tube.

Detailed ways

In order to have a clearer understanding of the technical features, purposes and beneficial effects of the present invention, the technical solutions of the present invention are now described in detail below, but should not be construed as limiting the scope of implementation of the present invention.

Example

This embodiment takes a complex fault-block oil reservoir in China as the research object, and provides a rapid identification method for the secondary enrichment of residual oil in the later stage of high water cut in a complex fault-block oil reservoir. As shown in Figure 1, the method includes:

In step S10, the target oil reservoir is measured to obtain the geological parameters and well pattern parameters of the target oil reservoir (as shown in Table 1).

Step S11, establishing a preliminary physical model of the target oil reservoir according to the geological parameters and well pattern parameters of the target oil reservoir, which specifically includes the following steps:

①According to the obtained well pattern parameters, set the bottom surface type of the preliminary physical model, which includes the following processes:

a. According to the obtained well pattern parameters, determine the well pattern type, oil-water well number ratio, well spacing and row spacing of the target reservoir;

b. According to the well pattern type and the ratio of the number of oil-water wells, set the bottom surface type of the preliminary physical model (the setting process is shown in Figure 2): when the well pattern type of the target reservoir is staggered, set the bottom surface type of the preliminary physical model Set as equilateral triangle; when the well pattern type of the target reservoir is facing, and the ratio of oil-water wells = 1, set the bottom surface type of the preliminary physical model to rectangle; when the well pattern type of the target reservoir is facing, and When the number of oil and water wells is ≠ 1, the bottom surface type of the preliminary physical model is set to be a regular triangle; in this embodiment, the bottom surface type of the preliminary physical model is a regular triangle;

c. According to the well spacing and row spacing determined above, set the side length of the equilateral triangle to be equal to the well spacing, and the height of the equilateral triangle to be equal to the row spacing;

d. After the bottom surface type is determined as an equilateral triangle, move the bottom surface along the vertical direction for a distance, the distance is the thickness of the actual reservoir, and the obtained three-dimensional spatial structure is the spatial structure of the preliminary physical model.

②According to the actual geological structure characteristics of the target oil reservoir, set the sedimentary rhythm, geological dip angle and permeability anisotropy of the preliminary physical model; among them,

Sedimentary rhythm refers to the diagenetic law of layered deposition in the order of particle size and specific gravity, and is divided into three types: homogeneous rhythm, positive rhythm, and inverse rhythm; homogeneous in physical properties; positive rhythm sand layer: coarse grain size in the lower part, fine grain size in the upper part, reflecting the weakening of the hydrodynamic conditions of the sedimentary environment from bottom to top; anti-rhythm sand layer: fine grain size in the lower part, coarse grain size in the upper part, and hydrodynamic conditions of the sedimentary environment Conditions become stronger from bottom to top;

Formation dip refers to the angle between the oil layer strike and the horizontal plane between oil and water wells;

Permeability anisotropy means that there are differences in permeability changes in different directions of the oil layer.

③According to the obtained actual geological parameters of the target reservoir, set the average permeability, initial oil saturation, porosity, irreducible water saturation, residual oil saturation, permeability gradient, underground crude oil viscosity, reservoir thickness of the preliminary physical model , conventional parameters that need to be obtained in reservoir measurement, such as the number of reservoir layers, injection-production rate, etc.; among them,

Average permeability refers to the ability of rock to allow fluid to pass under a certain pressure difference;

The initial oil saturation is the ratio of the oil-bearing volume in the effective pores of the oil layer to the effective pore volume of the rock, expressed as a percentage;

Porosity refers to the ratio of the sum of the volume of all pore spaces in a rock sample to the volume of the rock sample;

The irreducible water saturation refers to the percentage of the minimum water body remaining in the rock pores in the pore volume of the reservoir due to the wettability of the rock surface;

Residual oil saturation refers to the percentage of the volume of residual oil in rock pores;

The permeability gradient refers to the ratio of the maximum permeability to the minimum permeability;

Subterranean crude oil viscosity is a measure of the frictional resistance of one part of the crude oil to flow relative to another part under formation conditions.

The preliminary physical model of the target oil reservoir in this embodiment is shown in Fig. 6. The bottom of the model is an equilateral triangle. The size of each grid in the X, Y, and Z directions of the model is 10m, 10m, and 2m, respectively. The total is 35×30×25=26250, and there is edge water in the lower part of the reservoir. The production well (PRO) is located in the high part of the reservoir, the injection well (INC) is located in the low part of the reservoir, and the oil and water wells are arranged in the opposite direction. The specific parameters are shown in Table 1

Table 1 Corresponding parameters of the preliminary physical model of the target reservoir

parameter name parameter value parameter name parameter value Well pattern type equilateral triangle Porosity/% 0.28 Well spacing/m 300 Groundwater viscosity/mPa.s 0.6 Row spacing/m 300 Underground Crude Oil Viscosity/mPa.s 7 Formation dip/° 10 Gravity of groundwater 0.96 Reservoir Rhythm positive rhythm Specific gravity of underground oil 0.78 Reservoir thickness/m 50 Initial oil saturation/% 0.55 Maximum oil and water capillary force/bar 0.5 Bound water saturation/% 0.25 Average permeability/10^-3μm² 300 Residual oil saturation/% 0.20 Vertical Plane Permeability Ratio 0.3 Water cut before shut-in/% 92 Penetration level difference 5 Single layer water injection/m³ 500

Step S12, based on the preliminary physical model of the target oil reservoir, perform fitting and calculation according to the streamline flow pipe method to obtain the dynamic fitting characteristics of the production well and the saturation field before the secondary enrichment of the remaining oil, and analyze the target oil reservoir. The preliminary physical model is corrected to obtain the corrected physical model, which specifically includes the following steps:

① Preset the reservoir parameter characteristics of the preliminary physical model (as shown in Figure 3), and obtain the preset preliminary physical model: the thickness of a single layer of the model = the total thickness of the model/the number of longitudinally divided layers, the initial non-layer thickness of the model Homogeneity = longitudinal heterogeneity;

②Using Equation 1 and Equation 2 to calculate the water content and the water rise rate of each node in the direction of the main flow line, respectively.

③ Calculate the saturation of the water-bearing front and the position of the water-bearing front in the direction of the main flow line. The specific process includes:

According to formula 1 and formula 2, the relationship curve between water saturation ( _Sw ) and water content (f _w ) can be established (referred to as the S _w — f _w relationship curve), and the S _{w (i)} point and each S _w — The nodes of the _fw relationship curve are connected into a line, and the derivative of the line is obtained, and the node corresponding to the largest derivative value is the water saturation of the front edge (S _wf );

According to Equation 1 and Equation 2, the relationship between water saturation ( _Sw ) and water rise rate (f' _w ) can be established (denoted as S _w - f' _w ), and the value of f' _w (S _wf ) can be obtained from this relationship , and further calculate the water-containing front position (x _f ) according to Equation 3.

④Calculate the total water content of the output end in the direction of the main flow line. The specific process includes:

a. According to the ratio of the water injection amount of each layer and the permeability of each flow pipe (the water injection amount of each layer and the permeability data of each flow pipe can be directly measured and obtained), split the flow rate of each flow pipe , to calculate the water breakthrough time of each layer (the calculation formula is shown in Equation 4) and the water content of the output end of each layer (the calculation formula is shown in Equation 5 and Equation 2);

b. According to the flow rate of each flow pipe, the water content at the output end of each layer is weighted and averaged to obtain the total water content at the output end in the direction of the main flow line.

⑤ Judge and correct the total water content at the output end in the direction of the above main flow line until the total water content at the output end is consistent with the actual water content (at this time, the corresponding longitudinal division layers and longitudinal heterogeneity data meet the requirements, is the final acceptance value), so as to obtain the fitted water cut of the production well.

Among them, the correction process includes modifying the vertical division layers and vertical heterogeneity of the preliminary physical model, and fitting the reservoir heterogeneity (as shown in Figure 3).

⑥ Set the target water cut (the target water cut refers to the water cut corresponding to the time of shut-in enrichment), and according to the calculation methods from the above steps ② to ⑤, the water cut of the oil production well is obtained to achieve the secondary enrichment of the remaining oil. When required, the corresponding oil saturation field is the predicted value.

⑦ Interpolate the oil saturation from the boundary to the main flow line (that is, establish a saturation correction relationship) to correct the oil saturation field obtained in the above step (6), so as to obtain the saturation field before the secondary enrichment of the remaining oil; The calculation flow of steps ①-⑤ is shown in Figure 3, and the calculation flow of steps ⑥-⑦ is shown in Figure 4.

⑧ According to the number of vertical division layers and the final acceptance value of vertical heterogeneity determined in step ⑤, the preliminary physical model of the target oil reservoir is corrected to obtain the corrected physical model (as shown in Fig. 3).

Step 13: Based on the revised physical model, perform vertical enrichment and horizontal enrichment calculations for each node in the remaining oil enrichment process to obtain the reservoir saturation and water cut of each node to complete the target oil reservoir with high water cut. The identification of the secondary enrichment of the remaining oil in the later stage (as shown in Figure 5) specifically includes the following steps:

1) The calculation flow of the vertical enrichment process is as follows:

①According to Equation 6, calculate the vertical height difference of each node of each flow pipe, and then follow the method from top to bottom (the calculation formula is shown in Equation 7) and from bottom to top (the calculation formula is shown in Equation 8). ), the vertical height difference of each node of each flow pipe is accumulated and summed, and the total vertical height difference corresponding to the position of each vertical node is obtained.

② Calculate the average water saturation when each node of each flow tube in the vertical direction is completely balanced (the calculation formula is shown in Equation 9), and compare the thickness of the layer where each flow tube is located with the The total vertical height difference of the nodes is compared, and the average maximum water saturation (calculation formula is shown in Equation 10) and minimum water saturation average (calculation formula is shown in Equation 11) of each node on the saturation profile is obtained. shown).

③ Compare the average water saturation of each node of each flow tube when it is completely balanced with the average maximum saturation and the average minimum saturation of each node on the obtained saturation profile, and obtain the profile equilibrium type A, profile Equilibrium sub-type B, the inter-node scale coefficient a of the profile equilibrium type, the inter-node scale coefficient b of the profile equilibrium sub-type, the equilibrium position of the profile equilibrium type A and the equilibrium position of the profile equilibrium sub-type B ;in,

大于最大含水饱和度的平均值

的节点个数；所述剖面平衡态次级类型B是指垂向上每条流管各节点完全平衡时，各节点的平均含水饱和度

小于最小含水饱的平均值

的节点个数；The profile equilibrium state type A refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced.

greater than the mean value of maximum water saturation

The number of nodes in the equilibrium state of the profile B refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced.

less than the mean value of minimum water saturation

the number of nodes;

小于最大含水饱和度的平均值

的节点个数占该条流管节点总数的比值(计算公式如式12所示)；剖面平衡态次级类型节点间比例系数b是指垂向上每条流管各节点完全平衡时，各节点的平均含水饱和度

大于最大含水饱和度的平均值

的节点个数占该条流管节点总数的比值(计算公式如式13所示)；The proportionality coefficient a between the nodes of the profile equilibrium type refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced.

less than the mean value of maximum water saturation

The ratio of the number of nodes to the total number of nodes in the flow tube (the calculation formula is shown in Equation 12); the proportionality coefficient b between the nodes of the secondary type in the section equilibrium state refers to the vertical balance of the nodes of each flow tube when the nodes are completely balanced. The average water saturation of

greater than the mean value of maximum water saturation

The ratio of the number of nodes to the total number of nodes in the flow pipe (the calculation formula is shown in Equation 13);

The equilibrium position of the profile equilibrium state type A (the calculation formula is shown in Equation 14) and the equilibrium position of the profile equilibrium state of the secondary type B (the calculation formula is shown in the formula 15);

④ Calculate the profile water saturation of the secondary oil-water interface (the calculation formula is shown in Equation 16) and the equivalent capillary force at the profile equilibrium state (the calculation formula is shown in Equation 17).

⑤Calculate the water saturation and relative permeability of oil and water at each node of each flow pipe in the vertical direction; the specific process includes the following:

a. According to formula 18, calculate the relative permeability of oil phase and water phase corresponding to each node of each flow pipe in the vertical direction at the initial time of enrichment;

b. According to formula 19, calculate the oil saturation corresponding to each node of each flow pipe in the vertical direction during the enrichment process;

c. According to formula 20, calculate the relative permeability of oil phase and water phase corresponding to each node of each flow pipe in the vertical direction at the time of enrichment completion.

2) The calculation flow of the horizontal enrichment process is as follows

① Calculate the capillary force corresponding to each node of each flow tube on the plane at the initial moment of enrichment (the calculation formula is shown in Equation 21);

② Calculate the oil saturation corresponding to each node of each flow tube on the plane during the enrichment process (the calculation formula is shown in Equation 22);

③ Calculate the capillary force corresponding to each node of each flow tube on the plane at the time of enrichment completion (the calculation formula is shown in Equation 23).

3) Follow the process shown in Figure 5:

a. Preset enrichment time and enrichment times. In each cycle calculation, carry out vertical and horizontal enrichment calculations respectively, and calculate the water saturation at each node of each flow pipe and the relative permeability of oil and water phases Rate;

b. After each cycle of vertical and horizontal enrichment calculations, determine whether the preset enrichment times are reached. If not, then perform the calculation of step a. If the enrichment times are reached, output and save the last enrichment. Calculated data of water saturation and relative permeability of oil and water at each node of each flow pipe;

c. According to the data obtained in step b, calculate the water cut at the end of the production well (the calculation formula is shown in Equation 1), that is, the water cut at the opening of the production well, output the water cut at the opening of the production well, and the calculation is over.

In this example, according to the above-mentioned rapid identification method for the secondary enrichment of remaining oil in the later stage of high water cut in complex fault-block reservoirs, the comparison map of the plane oil saturation field and the vertical oil saturation field before and after the remaining oil enrichment was obtained (Fig. 7). As shown in Fig. 7, A is the oil saturation field in the horizontal direction before enrichment, C is the oil saturation field in the vertical direction before enrichment, B is the oil saturation field in the horizontal direction after enrichment, and D is the oil saturation field in the enrichment direction. oil saturation field in the vertical direction).

Claims (25)

1. A quick identification method for secondary enrichment of residual oil in a high-water-cut later period of a complex fault block oil reservoir comprises the following steps:

step S10, measuring the target oil deposit to obtain the geological parameters and well pattern parameters of the target oil deposit;

step S11, establishing a primary physical model of the target oil reservoir according to the geological parameters and the well pattern parameters of the target oil reservoir;

step S12, based on the preliminary physical model of the target oil reservoir, performing fitting calculation according to a streamline flow pipe method to obtain dynamic fitting characteristics of the oil production well and a saturation field before secondary enrichment of residual oil, and correcting the preliminary physical model of the target oil reservoir to obtain a corrected physical model;

step S13, based on the corrected physical model, calculating the vertical enrichment and the horizontal enrichment of each node in the residual oil enrichment process respectively to obtain the reservoir saturation and the water content of each node; and finishing the identification of the secondary enrichment of the residual oil in the later period of high water content of the target oil reservoir.

2. The method of claim 1, wherein in step S11, building a physical model of the target reservoir based on the geological parameters and well pattern parameters of the target reservoir comprises the steps of:

setting the bottom surface type of the preliminary physical model according to the obtained well pattern parameters;

and setting the geological parameters of the preliminary physical model according to the obtained geological parameters.

3. The method of claim 1 or 2, wherein setting a floor type of the preliminary physical model based on the obtained well pattern parameters comprises the steps of:

determining the well pattern type, the oil-water well ratio, the well spacing and the row spacing of the target oil reservoir according to the obtained well pattern parameters;

setting the bottom surface type of a preliminary physical model according to the well pattern type and the oil-water well ratio: when the well pattern type is staggered, setting the bottom surface type of the preliminary physical model as a regular triangle; when the well pattern type is right, and the oil-water well ratio is 1, the bottom surface type of the primary physical model is set to be rectangular; when the well pattern type is right, and the oil-water well ratio is not equal to 1, setting the bottom surface type of the preliminary physical model as a regular triangle;

when the bottom surface type of the preliminary physical model is rectangular, setting the length of the rectangle to be equal to the well spacing, and setting the width of the rectangle to be equal to the row spacing; and when the bottom surface type of the primary physical model is a regular triangle, setting the side length of the regular triangle to be equal to the well spacing, and setting the height of the regular triangle to be equal to the row spacing.

4. The method of claim 1, wherein step S12 includes the steps of:

step S121, presetting reservoir characteristic parameters of the preliminary physical model to obtain preset reservoir characteristics;

fitting preset reservoir characteristic parameters by using actual dynamic historical characteristics of the oil production well to determine final dynamic fitting characteristics of the oil production well and reservoir characteristics of the primary physical model;

step S122, according to a streamline and flow pipe method, preliminarily fitting to obtain an oil saturation field before secondary enrichment of residual oil;

fitting and correcting the oil-containing saturation field before secondary enrichment of the residual oil obtained by primary fitting by using a saturation correction relational expression to determine the final oil-containing saturation field before secondary enrichment of the residual oil;

and S123, correcting the primary physical model of the target oil reservoir to obtain a corrected physical model.

5. The method of claim 4, wherein in step S121, fitting preset reservoir characteristic parameters with actual dynamic historical characteristics of the production wells to determine final dynamically fitted characteristics of the production wells and reservoir characteristics of the preliminary physical model comprises the steps of:

performing fitting calculation according to a streamline flow pipe method based on a preliminary physical model of the target oil reservoir to obtain dynamic fitting characteristics of the oil production well obtained through preliminary fitting;

when the dynamic fitting characteristics of the oil production well obtained by the preliminary fitting are in accordance with the actual dynamic history characteristics of the oil production well of the target oil reservoir, judging that the dynamic fitting characteristics of the oil production well obtained by the preliminary fitting are in accordance with the requirements;

when the dynamic fitting characteristics of the oil production well obtained by the preliminary fitting do not accord with the actual dynamic history characteristics of the oil production well of the target oil reservoir, judging that the dynamic fitting characteristics of the oil production well obtained by the preliminary fitting do not accord with the requirements; at the moment, reservoir characteristic parameters of the primary physical model need to be modified, and dynamic fitting characteristics of the oil production well are re-fitted according to a streamline flow pipe method until the dynamic fitting characteristics of the oil production well accord with actual dynamic historical characteristics of the oil production well on the target oil reservoir;

and when the dynamic fitting characteristics of the oil production well obtained by the preliminary fitting are consistent with the actual dynamic historical characteristics of the oil production well of the target oil reservoir, determining the corresponding reservoir characteristics as the reservoir characteristics of the preliminary physical model.

6. The method of claim 4, wherein the preliminary fitting to obtain the oil saturation field before secondary enrichment of the remaining oil according to a streamlined flow tube method in step S122 comprises the steps of:

calculating the water content and the water content increase rate of each node in the main flow line direction;

calculating the saturation degree of the water-containing front edge and the position of the water-containing front edge in the main flow line direction;

and calculating the total water content of the output end in the main flow line direction.

7. The method of claim 4, wherein in step S122, the preliminary fitting oil saturation field before secondary enrichment of the residual oil is subjected to fitting correction by using a saturation correction relation, and the method comprises the following steps:

setting a saturation correction relational expression, and correcting the oil-containing saturation field obtained by primary fitting before secondary enrichment of the residual oil to obtain a corrected oil-containing saturation field;

when the corrected oil saturation field conforms to the actual oil saturation field of the target oil reservoir, judging that the corrected oil saturation field conforms to the requirements;

when the corrected oil saturation field does not accord with the actual saturation field of the target oil reservoir, judging that the corrected oil saturation field does not accord with the requirement; at the moment, resetting the saturation correction relational expression, and correcting the oil-containing saturation field before secondary enrichment of the residual oil until the corrected oil-containing saturation field is consistent with the actual oil-containing saturation field of the target oil reservoir;

and when the corrected oil saturation field is consistent with the actual oil saturation field of the target oil reservoir, determining the corrected oil saturation field as the final oil saturation field before secondary enrichment of the residual oil.

8. The method according to claim 6, wherein the calculation formula of the water content of each node in the main streamline direction is shown as formula 1

In formula 1, f_wThe water content is obtained; k is a radical of_rw、k_roRelative permeability of water phase and oil phase respectively; mu.s_w、μ_oThe viscosity of the water phase and the oil phase respectively.

9. The method according to claim 6, wherein the water cut increase rate is calculated according to the formula 2

In formula 2, f'_wIs the water cut rate of rise; s_wThe water saturation; i is the ith node position and i-1 is the node position immediately preceding the inode.

10. The method according to claim 6, wherein the calculation formula of the position of the water-containing front edge in the main flow line direction is as shown in formula 3

Wherein,

in formula 3, x_fIs the hydrous leading edge position; x is the number of₀Is a water-containing initial position;f'_w(S_wf) The water cut rising rate corresponding to the saturation of the water cut front; phi is porosity; a is the sectional area; q is the flow; t is t_pAs displacement time; f. of_w(S_wf) The water content is corresponding to the saturation of the water-containing front edge; s_wfIs the water cut front saturation; s_wcTo irreducible water saturation.

11. The method of claim 6, wherein the calculation of the total moisture content of the production end in the direction of the main flow line comprises:

splitting the flow of each flow pipe according to the ratio of the water injection amount of each layer to the permeability of each flow pipe, and calculating the water breakthrough time of each layer and the water content of the output end of each layer;

and carrying out weighted average on the water content of each layer of output end according to the flow of each flow pipe so as to obtain the total water content of the output end in the main flow line direction.

12. The method according to claim 11, wherein the formula for calculating the water breakthrough time of each layer is shown in formula 4

In formula 4, x_fIs the hydrous leading edge position; x is the number of₀Is a water-containing initial position; f'_w(S_wf) The water cut rising rate corresponding to the saturation of the water cut front; a is the sectional area; q is the flow; phi is the porosity.

13. The method of claim 11, wherein the calculating of the moisture content of the production end of each layer comprises:

calculating the water cut rising rate corresponding to the water saturation of each layer of the output end according to a formula shown in a formula 5;

then, according to a formula shown in a formula 2, calculating the water content of the output end of each layer;

in formula 5, t_pAs displacement time; t is water breakthrough time; l is the oil-water well spacing; f'_w(S_wL) The water cut rising rate corresponding to the water cut saturation of each layer of the produced end; phi is the porosity.

14. The method of claim 1, wherein in step S13, the calculation process of the vertical enrichment comprises:

calculating the vertical height difference of each node of each flow pipe, and then performing cumulative summation respectively in a top-down mode and a bottom-up mode to obtain the total vertical height difference of each node of each flow pipe in the vertical direction;

calculating the average water saturation when each node of each flow pipe in the vertical direction is completely balanced, and then obtaining the maximum water saturation average value and the minimum water saturation average value of each node on the saturation profile according to the thickness of the layer where each flow pipe is located and the total vertical height difference of each node of each flow pipe in the vertical direction;

obtaining a section balanced state type, a section balanced state secondary type, an inter-node proportion coefficient and a balanced position according to the average water saturation when each node of each flow pipe is completely balanced in the vertical direction, and the maximum water saturation average value and the minimum water saturation average value of each node on a saturation section;

calculating the section water saturation and section equilibrium state equivalent capillary force of a secondary oil-water interface;

and calculating the water saturation and the relative permeability of the oil phase and the water phase of each node of each flow pipe in the vertical direction.

15. The method of claim 14, wherein the vertical height difference of each node of each flow tube is calculated as shown in equation 6

In equation 6,. DELTA.h is the height difference caused by capillary force；P_cThe capillary force at each node of each flow pipe in the vertical direction; gamma ray_wIs the severity of the water; gamma ray_oIs the severity of the oil; i is the ith node position; i +1 is the next node position of inode.

16. The method of claim 14, wherein the total vertical height difference of the nodes of each flow tube in the vertical direction is calculated as shown in equation 7 from top to bottom

In formula 7, h_ud(i)The total vertical height difference of each node of each flow pipe from top to bottom in the vertical direction; i is the ith node position; j is the jth node location.

17. The method of claim 14, wherein the total vertical height difference of the nodes of each flow tube in the vertical direction is calculated according to the formula 8 from bottom to top

In formula 8, h_du(i)The total vertical height difference of each node of each flow pipe from bottom to top in the vertical direction; i is the ith node position; j is the jth node position; n is the total number of nodes of each flow pipe in the vertical direction.

18. The method of claim 14 wherein the average water saturation at full equilibrium at each node of each vertical flow line is calculated as shown in 9

In the formula 9, the first and second groups,

the average water saturation when each node of each flow pipe in the vertical direction is completely balanced; s_wzThe water saturation of each node when each flow pipe in the vertical direction is completely balanced; i is the ith node position; n is the total number of nodes of each flow pipe in the vertical direction.

19. The method of claim 14, wherein the calculation formula of the average value of the maximum water saturation of each node on the saturation profile is shown in formula 10

In the formula 10, the first and second groups,

the average value of the maximum water saturation of each node on the saturation profile when each node of each flow pipe in the vertical direction is completely balanced; s_wWater saturation of each node; h is_udThe total vertical height difference of each node of each flow pipe from top to bottom in the vertical direction; h is the thickness of the small layer; delta h is the vertical height difference of each node of each flow pipe in the vertical direction; i is the ith node position; j is the jth node position; n is the total number of nodes of each flow pipe in the vertical direction.

20. The method of claim 14, wherein the minimum water saturation average value of each node on the saturation profile is calculated according to equation 11

In the formula (11), the first and second groups,

the average value of the minimum water saturation of each node on the saturation profile when each node of each flow pipe in the vertical direction is completely balanced; s_wWater saturation of each node; h is_duThe total vertical height difference of each node of each flow pipe from bottom to top in the vertical direction; h is the thickness of the small layer; delta h is the vertical height difference of each node of each flow pipe in the vertical direction; i is the ith node position; j is the jth node position; n is the total number of nodes of each flow pipe in the vertical direction.

21. The method of claim 14, wherein the inter-node scaling factors include an inter-node scaling factor of a profile balanced state type and an inter-node scaling factor of a profile balanced state sub-type; the equilibrium positions comprise an equilibrium position of a profile equilibrium state type and an equilibrium position of a profile equilibrium state secondary type;

the formula for calculating the proportionality coefficient between the nodes of the profile equilibrium state type is shown in formula 12

In formula 12, a is a cross-sectional equilibrium type inter-node scaling factor;

the average value of the maximum water saturation of each node on the saturation profile when each node of each flow pipe in the vertical direction is completely balanced;

the average water saturation of each node of each flow pipe in the vertical direction; a is a profile equilibrium state type; i is the ith node position; n is the total number of nodes of each flow tube in the vertical direction;

the formula for calculating the proportional coefficient between the nodes of the profile balance state secondary type is shown in formula 13

In formula 13, b is a cross-sectional equilibrium secondary-type inter-node scaling factor;

the average value of the minimum water saturation of each node on the saturation profile when each node of each flow pipe in the vertical direction is completely balanced;

the average water saturation of each node of each flow pipe in the vertical direction; b is a profile equilibrium secondary type; i is the ith node position; n is the total number of nodes of each flow tube in the vertical direction;

the formula for calculating the equilibrium position of the profile equilibrium state type is shown in formula 14

In formula 14, x_aIs a section equilibrium state type equilibrium position; h is the thickness of the small layer; h is_udThe total vertical height difference of each node of each flow pipe from top to bottom in the vertical direction; a is a proportional coefficient between profile equilibrium type nodes; i is the ith node position; a is a profile equilibrium state type;

the formula for calculating the equilibrium position of the secondary type of the profile equilibrium state is shown in formula 15

In formula 15, x_bIs a profile balance state secondary type balance position; h is the thickness of the small layer; h is_duThe total vertical height difference of each node of each flow pipe from bottom to top in the vertical direction; b is a proportional coefficient between secondary type nodes in a section balance state; i is the ith node position; b is a profile equilibrium secondary type.

22. The method of claim 14, wherein the formula for calculating the profile water saturation of the secondary oil water interface is shown in equation 16

In formula 16, S_wpmThe section water saturation of each node at the position of the secondary oil-water interface; s_wThe water saturation corresponding to each node in the phase permeation; delta h is the oil-water height difference caused by capillary force; h_pmThe section height of each node at the position of a secondary oil-water interface is taken as the height of the section of each node; i is at the ith node position.

23. The method of claim 14, wherein the equation for calculating the profile equilibrium equivalent capillary force at the secondary oil water interface is given by equation 17

In formula 17, S_wpmThe section water saturation of each node at the position of the secondary oil-water interface; s_wThe water saturation corresponding to each node in the phase permeation; p_cpmThe section capillary force of each node at the position of a secondary oil-water interface is obtained; p_cThe capillary force corresponding to each node in the capillary pressure curve; i is at the ith node position.

24. The method of claim 14, wherein the calculating of the water saturation and the relative permeability of the oil and water phases at each node of each flow pipe vertically comprises:

step 1, calculating the relative permeability of the oil phase and the water phase of each node of each flow pipe in the vertical direction at the initial enrichment moment, wherein the calculation formula is shown as a formula 18

In formula 18, K_r(t0)The relative permeability of each node for enriching oil water at the initial moment; k_r(i)Relative permeability corresponding to each node in oil-water phase seepage; s_w(i)The water saturation corresponding to each node in the oil-water phase seepage; s_w(t0)Is rich inCollecting the water saturation of each node at the initial moment; i is the ith node position;

step 2, calculating the oil saturation of each node of each flow pipe in the vertical direction in the enrichment process, wherein the calculation formula is shown as formula 19

In formula 19, S_oOil saturation corresponding to each node; k_ZThe permeability corresponding to each node in the Z direction, wherein the Z direction is the direction vertical to the horizontal plane; k_roThe oil relative permeability for each node; k_rwRelative permeability of water for each node; mu.s_wIs the viscosity of water; mu.s_oIs the viscosity of the oil; p_cCapillary force for each node; p_c∞The section capillary force of each node at the position of a secondary oil-water interface is obtained; phi is porosity; t is enrichment time; n is the number of divided time periods; i is the ith node position; (i +1/2) is the position intermediate the i, i +1 th node; (i-1/2) is the position intermediate the i-1 st, i-th node;

step 3, calculating the relative permeability of the oil phase and the water phase of each node of each flow pipe in the vertical direction at the completion moment of enrichment, wherein the calculation formula is shown as a formula 20

In formula 20, K_r(tj)Relative permeability of each node at the completion of enrichment; k_r(i)Relative permeability corresponding to each node in oil-water phase seepage; s_w(i)The water saturation corresponding to each node in the oil-water phase seepage; s_w(tj)The water saturation of each node at the completion of the enrichment; i is at the ith node position.

25. The method of claim 1, wherein in step S13, the calculation of the level enrichment comprises:

step 1, calculating capillary force of each node of each flow tube on a plane at the initial enrichment moment, wherein a calculation formula is shown as a formula 21

In formula 21, P_c(t0)Enriching capillary force of each node at initial time; p_c(i)The capillary force corresponding to each node in the capillary pressure curve; s_w(i)The water saturation corresponding to each node in the oil-water phase seepage; s_w(t0)Enriching the water saturation of each node at the initial moment; i is the ith node position;

step 2, calculating the oil saturation of each node of each flow pipe on the plane in the enrichment process, wherein the calculation formula is shown as a formula 22

In formula 22, S_oOil saturation corresponding to each node; k_xThe permeability corresponding to each node in the X direction, which is the horizontal direction; k_roThe oil relative permeability for each node; k_rwRelative permeability of water for each node; mu.s_wIs the viscosity of water; mu.s_oIs the viscosity of the oil; p_cCapillary force for each node; phi is the porosity; t is enrichment time; n is the number of divided time periods; i is the ith node position;

step 3, calculating capillary force of each node of each flow tube on the plane at the completion moment of enrichment, wherein a calculation formula is shown as a formula 23

In formula 23, P_c(tj)Calculating capillary force of each node at the completion moment of enrichment; p_c(i)The capillary force corresponding to each node in the capillary pressure curve; s_w(i)The water saturation corresponding to each node in the oil-water phase seepage; s_w(tj)Calculating the water saturation of each node at the completion moment of enrichment; i is at the ith node position.

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