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

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

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CN106894814B
CN106894814B CN201710080315.5A CN201710080315A CN106894814B CN 106894814 B CN106894814 B CN 106894814B CN 201710080315 A CN201710080315 A CN 201710080315A CN 106894814 B CN106894814 B CN 106894814B
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oil
water
saturation
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CN106894814A (en
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杨勇
王建
刘维霞
王瑞
吴义志
宋志超
刘同敬
第五鹏祥
左金
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China University of Petroleum Beijing
Exploration and Development Research Institute of Sinopec Shengli Oilfield Co
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China University of Petroleum Beijing
Exploration and Development Research Institute of Sinopec Shengli Oilfield Co
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20—Displacing by water
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • G—PHYSICS
    • G06—COMPUTING; CALCULATING OR COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F30/00—Computer-aided design [CAD]
    • G06F30/20—Design optimisation, verification or simulation

Abstract

The invention provides a quick identification method for secondary enrichment of residual oil in a high-water-content later period of a complex fault block oil reservoir. It includes: measuring the target oil reservoir to obtain geological parameters and well pattern parameters of the target oil reservoir; 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; 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 an 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; and on the basis of the corrected physical model, calculating vertical enrichment and horizontal enrichment of each node in the residual oil enrichment process respectively to obtain the reservoir saturation and water content of each node, and completing the identification of the secondary enrichment of the residual oil in the later period of high water content of the target oil reservoir. The method can accurately predict the change condition of the dynamic parameters of the displacement front edge.

Description

Rapid identification method for secondary enrichment of residual oil in high-water-content later period of complex fault block oil reservoir
Technical Field
The invention relates to a quick identification method for secondary enrichment of residual oil in a high-water-cut later period of a complex fault block oil reservoir, and belongs to the field of complex fault block oil field development.
Background
The complex fault block oil reservoir has the geological characteristics of small size, scattering, poverty and fragmentation, the development well pattern and the reserve control degree are greatly influenced by the planar distribution shape of the reservoir, and a plurality of fault blocks can not form a perfect injection-production well pattern. Therefore, the problems of rapid water content rise and low extraction degree commonly existing in the complex fault block oil reservoir are caused, and how to effectively improve the secondary enrichment degree and the extraction degree of the residual oil after water drive development is the key for improving the water drive development effect of the complex fault block oil field and improving the final recovery ratio of the oil reservoir.
In the conventional research on the enrichment of residual oil in the later period of high water content of an oil reservoir, the influence caused by the factor of imperfect injection and production well patterns is mostly not considered, and the enrichment rule and the calculation method are relatively simple. However, in practical situations, the geological characteristics of the reservoir and the imperfect injection and production well pattern both affect complex fault block reservoirs, so that a large amount of residual oil still exists in the high-water-content later reservoir and is mainly distributed in intervals with strong heterogeneity and areas with uncontrollable well patterns. Therefore, the research on the enrichment of the residual oil in the later period of high water content of the conventional oil reservoir can not meet the actual development requirement of the complex fault block oil reservoir, and a series of problems that the secondary enrichment of the residual oil can not be effectively and rapidly calculated, the dynamic parameter change of a displacement front edge can not be accurately predicted and the like exist in the actual application process.
In conclusion, the novel calculation method for secondary enrichment of the residual oil in the high-water-cut later period of the complex fault block oil reservoir is an urgent technical problem to be solved in the field.
Disclosure of Invention
In order to solve the technical problems, the invention provides a quick identification method for secondary enrichment of residual oil in the high-water-cut later period of a complex fault block oil reservoir, which can accurately predict the change condition of displacement front parameters and realize quick calculation of secondary enrichment of the residual oil in the high-water-cut later period of the complex fault block oil reservoir.
In order to achieve the aim, the invention provides a quick identification method for secondary enrichment of residual oil in the high water-cut later period of a complex fault block oil reservoir, which 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; wherein the dynamic fitting characteristics of the production well can represent the actual production dynamics of the production well;
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.
Compared with the prior art, the technical scheme provided by the invention simultaneously researches two factors of geological characteristics and injection-production well pattern characteristics of a complex fault block oil reservoir, and on the basis, the finally obtained calculation method can be effectively applied to the complex fault block oil reservoir by establishing a physical model of the target oil reservoir (the physical model has typical geological characteristics of the target oil reservoir) and combining a streamline flow tube method theory and a formula in the field, so that the secondary enrichment of the residual oil is quickly calculated, and the dynamic parameter change of the body displacement front edge is accurately predicted.
In the technical scheme provided by the invention, the streamline and flow pipe method refers to a streamline method and a flow pipe method, wherein the streamline method is a mathematical characterization method for mathematically describing the plane migration rule of the underground fluid; the flow pipe method is a physical model construction method for mathematically describing a space structure where underground fluid is located and the migration relation of each node in the space; both of these methods are computational methods known in the art and are terms of art.
In the above calculation method, preferably, in step S12, the dynamically fitted characteristic of the production well includes the following parameters: oil production, water production and water content.
In the above calculation method, preferably, in step S11, building a physical model of the target reservoir according to the geological parameters and the well pattern parameters of the target reservoir includes the following steps:
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.
In the above calculation method, preferably, the setting of the bottom surface type of the preliminary physical model according to the obtained well pattern parameters includes 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 the preliminary physical model according to the well pattern type and the oil-water well ratio (the setting process is shown in figure 2):
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.
In the technical scheme provided by the invention, the preliminary physical model is a model with a three-dimensional space structure, the three-dimensional space structure comprises a horizontal X direction, a horizontal Y direction and a vertical Z direction (the horizontal X direction is vertical to the horizontal Y direction, the vertical Z direction is respectively vertical to the X direction and the Y direction), the bottom surface of a preliminary physical model is arranged on a horizontal plane formed by the horizontal X direction and the horizontal Y direction together, after the bottom surface type is determined according to the method, the three-dimensional space structure obtained after the bottom surface is translated for a certain distance along the vertical Z direction (the distance is the thickness of the preliminary physical model and is equal to the thickness of the actual reservoir stratum) is the space structure of the preliminary physical model, for example, the bottom surface type is determined to be a rectangle according to the method, and the rectangle is translated for a distance along the vertical direction to obtain a cubic structure, wherein the cubic structure is the spatial structure of the preliminary physical model.
In the space structure, each single oil layer is divided into three directions according to the horizontal X, the horizontal Y and the vertical Z, and a plane is divided into a plurality of flow pipes on the horizontal plane according to the main flow line direction of the fluid during underground seepage (as shown in figure 8); the length of each flow pipe is different according to the shape of the oil deposit, and is equal to the length of the oil deposit at the position corresponding to the plane where the single flow pipe is located in numerical value. For a regular rectangular oil reservoir, the length of each flow tube on the same plane is the same; for a triangular reservoir, the length of each flow tube on the same plane is different. The width (the width is the diameter of the flow pipe) and the length (the length is the length of the flow pipe in the main streamline direction) of each flow pipe are identical in numerical value, the division scale is flexibly determined according to the size of the oil reservoir, and the value range is 1-20 m.
After the planar flow tube is divided, the division is continued according to the width and the length of the flow tube which are the same as those of the planar arrangement in the direction vertical to the main flow line, the flow tubes in the three directions are intersected in the space to form a grid, and the intersection point is a calculation node (as shown in fig. 9, a dot in the graph represents a node, and a round tube represents a flow tube); each flow tube in the direction of the main flow line corresponds to one production end.
Because the formation is heterogeneous, the fluid is generally anisotropic during subsurface seepage, i.e., the direction of flow is not uniform and may flow in all directions, but there must be one major direction of flow, which is related to production. Because the formation pressure changes near the production well (the formation pressure decreases near the production well and increases near the injection well) create a pressure differential in the production zone that is the primary source of power to drive the flow of the subterranean fluid, this direction is the main streamline direction of the present invention.
In the above calculation method, preferably, the 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; the actual dynamic historical characteristics of the oil production well comprise parameters of oil production, water production and water content;
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.
In the above calculation method, preferably, in step S121, the characteristic parameters of the reservoir include initial oil saturation, reservoir thickness, reservoir dip angle, injection and production rate, and average permeability.
In the above calculation method, preferably, in step S121, fitting preset reservoir characteristic parameters by using actual dynamic history characteristics of the production well to determine the final dynamic fitting characteristics of the production well and the reservoir characteristics of the preliminary physical model, includes the following steps:
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.
In the above calculation method, preferably, in step S122, the preliminary fitting to obtain the oil saturation field before the secondary enrichment of the remaining oil according to the streamline flow tube method includes the following steps:
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.
In the above calculation method, preferably, in step S122, the fitting and correcting the oil saturation field before the secondary enrichment of the residual oil obtained by the preliminary fitting by using the saturation correction relation formula includes 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.
In the technical scheme provided by the invention, the actual underground saturation field is unknown, and the information obtained by single well testing can only represent one underground point, namely the current saturation of the position of the well. For an entire oil reservoir, saturation data obtained through a plurality of well points is still very limited for the whole oil reservoir range, so that the saturation of other positions of the oil reservoir needs to be predicted through the known data, the predicted data is usually obtained through interpolation according to the data of adjacent known points, unknown data between the adjacent two points are obtained through the interpolation method, but the prediction result obtained through interpolation cannot represent the true oil reservoir saturation, and therefore the detection and the correction are needed. The inspection method is to fit single well dynamics (including oil production, water production and water content) through saturation predicted by continuously correcting an interpolation method, and the single well dynamics is data which can be actually measured. If the single well fitting result is consistent with the actual single well dynamic, the predicted saturation or the corrected saturation is indicated to be 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 depositional prosody, the geological dip and the permeability anisotropy of the preliminary physical model according to the actual geological structure characteristics of the target reservoir; wherein:
the sedimentary prosody refers to the rule that diagenetic rocks are formed by layered deposition according to the sequence of particle size and specific gravity, and is divided into homogeneous prosody, positive prosody and reverse prosody; homogeneous rhythm sand layer: the hydrodynamic force condition is relatively stable, the lithology in the stratum and the physical property are homogeneous; positive rhythm sand layer: the lower part has coarse granularity, and the upper part has fine granularity, which reflects that the hydrodynamic condition of the deposition environment becomes weaker from bottom to top; a reverse rhythm sand layer: the lower part has fine granularity, the upper part has coarse granularity, and the hydrodynamic condition of the deposition environment is strengthened from bottom to top;
the stratum inclination angle refers to an included angle between the oil layer direction and the horizontal plane between the oil-water wells;
permeability anisotropy refers to the difference in permeability change of the oil layer in different directions.
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 general parameters required to be obtained in oil reservoir measurement, such as average permeability, initial oil saturation, porosity, bound water saturation, residual oil saturation, permeability level difference, underground crude oil viscosity, reservoir thickness, reservoir number of layers, injection and production speed and the like of the preliminary physical model are set according to the obtained actual geological parameters of the target oil reservoir; wherein:
average permeability refers to the amount of capacity of the rock to allow fluid to pass through at a certain pressure differential;
the initial oil saturation is the ratio of the oil volume in the effective pore space of the oil reservoir to the effective pore volume of the rock, expressed as a percentage;
the porosity is the ratio of the sum of all pore space volumes in the rock sample to the volume of the rock sample;
irreducible water saturation refers to the percentage of reservoir pore volume that is occupied by the smallest body of water remaining in the rock pores due to rock surface wettability;
residual oil saturation refers to the percentage of the volume of residual oil in the rock pore space;
the permeability grade difference refers to the ratio of the maximum permeability to the minimum permeability;
the viscosity of a subterranean crude oil refers to a measure of the frictional resistance of the oil as one part flows relative to another part within the crude oil 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 a step of presetting the number of vertical slices and the vertical heterogeneity of the preliminary physical model based on the preliminary physical model of the target reservoir, and the method includes the following steps:
the single-layer thickness of the preliminary physical model is equal to the total thickness/preset longitudinal dividing layer number of the preliminary physical model;
the initial heterogeneity of the preliminary physical model is the preset longitudinal heterogeneity.
In the above calculation method, preferably, in step S122, the preliminary fitting to obtain the saturation field before secondary enrichment of the remaining oil according to a streamline flow pipe method based on the preliminary physical model of the target oil reservoir includes the following steps:
①, calculating the water content and the water content increase rate of each node in the main flow line direction, wherein the water content refers to the water content calculated by a Beckley-Levelet formula (B-L formula for short) in the main flow line direction, and each node on the main flow line in the physical model can obtain corresponding data after being calculated by the formula, so a series of data points are obtained;
② calculating the water-containing front saturation and the water-containing front position in the main flow line direction;
③ calculating the total water content of the output end in the main flow line direction;
④, judging the total water content of the output end in the main flow line direction, and correcting the reservoir characteristic parameters according to the actual water content of the oil production well to make the fitted water content of the oil production well accord with the actual water content;
⑤, obtaining an oil saturation field corresponding to the oil production well when the fitted water content reaches the secondary enrichment requirement of the residual oil based on the calculation method from step ① to step ④, wherein the oil saturation field is a predicted value;
⑥, performing oil saturation interpolation from the boundary to the main flow line to correct the oil saturation field obtained in step ⑤, thereby obtaining the saturation field before secondary enrichment of the residual oil.
In the above calculation method, preferably, in step ①:
the calculation formula of the water content of each node in the main streamline direction is shown as formula 1, and formula 1 can be used for calculating the water content corresponding to any point in the physical model
Figure BDA0001225701000000071
In formula 1, fwWater content, decimal; k is a radical ofrw、kroThe relative permeability of the water phase and the oil phase is zero; mu.sw、μoThe viscosity of the water phase and the oil phase is mPa & s;
more preferably, the calculation formula of the water cut increase rate is shown in formula 2
Figure BDA0001225701000000072
In formula 2, f'wWater content rate of rise (reciprocal of water content), decimal; swWater saturation, decimal; i is the ith node position and i-1 is the node position immediately preceding the inode.
In the above calculation method, preferably, the calculating of the hydration front saturation and the hydration front position in step ② includes:
according to Sw—fwRelation curve, through SwiPoint and each Sw—fwThe nodes of the relation curve are connected into a line, and the derivative of the line is calculatedThe node with the largest derivative value is the leading edge water saturation Swf(ii) a Then according to Sw—f'wTo give f'w(Swf) A value; finally, the water-containing front edge position x is determinedf。
In the above calculation method, preferably, in step ②, the calculation formula of the position of the water-containing front edge on the main flow line is as shown in formula 3
Figure BDA0001225701000000073
Wherein the content of the first and second substances,
Figure BDA0001225701000000081
in formula 3, xfIs the water front position, m; x is the number of0Is the initial position containing water, m; f'w(Swf) Is the water cut rising rate, decimal, corresponding to the water cut front saturation; phi is porosity, decimal; a is the cross-sectional area, m2(ii) a Q is the flow, m3(ii) a t is the displacement time, day; f. ofw(Swf) The water content is the water content corresponding to the saturation of the water-containing front edge, and the decimal number is the water content; swfWater cut front saturation, decimal; swcFractional number to irreducible water saturation.
In the above calculation method, preferably, the calculating of the total water content of the production end in the main flow line direction in step ③ includes:
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 ends on the main flow line.
In the above calculation method, preferably, in step ③, the formula for calculating the water breakthrough time of each layer is as shown in formula 4
Figure BDA0001225701000000082
In formula 4, xfIs the water front position, m; x is the number of0Is the initial position containing water, m; f'w(Swf) Is the water cut rising rate, decimal, corresponding to the water cut front saturation; a is the cross-sectional area, m2(ii) a Q is the flow, m3。
In the above calculation method, preferably, in step ③, the calculating of the moisture content of the produced end of each layer includes:
during calculation, the water breakthrough time of each flow pipe is judged, then the flow splitting method is adopted, the water content increasing rate corresponding to the water saturation of each layer of output end is calculated according to a formula shown in a formula 5, and then the water content f of each layer of output end is calculated according to a formula shown in a formula 2w；
Figure BDA0001225701000000083
In formula 5, t is the production time, day; t is the water breakthrough time, day; l is the oil-water well spacing, m; f'w(SwL) The water cut corresponding to the water saturation at the output end of each layer, fractional number.
In the method, preferably, the step ④ of judging the total water content of the production end in the main flow line direction comprises the steps of comparing the calculated total water content of the production end in the main flow line direction with the actual water content of the oil production well from an initial time, correcting the reservoir characteristic parameters when the two numerical values do not meet each other, continuing to correct the reservoir characteristic parameters if the calculated water content obtained by the corrected model is greatly different from the actual water content, finishing the fitting process of the water content corresponding to the time point if the calculated water content obtained by the corrected model is consistent with or slightly different from the actual water content, starting to judge the water content corresponding to the next time point until the termination time of the actual water content measurement, finishing the judging process, finishing the fitting of the water content, wherein the difference is considered to be small when the numerical difference is within-5% to 5% for a thin oil reservoir, otherwise, and the difference is considered to be large when the numerical difference is within-15% to 15% for a thick oil reservoir, and 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 calculating the vertical height difference of each node of each flow tube, and then performing cumulative summation on the vertical height difference of each node of each flow tube according to the top-down mode and the bottom-up mode respectively to obtain the total vertical height difference of each node of each flow tube in the vertical direction (the total vertical height difference comprises the total vertical height difference of each node of each flow tube from top to bottom in the vertical direction and the total vertical height difference of each flow tube in the given stage from bottom to top in the vertical direction);
②, calculating the average water saturation when each node of each flow pipe in the vertical direction is completely balanced, wherein the complete balance refers to a state that the residual oil can not be enriched after being enriched, and the oil saturation in the vertical direction and the horizontal direction does not change any more;
comparing the thickness of the layer where each flow tube is located with the total vertical height difference of each node of each flow tube in the vertical direction obtained in the step ①, so as to obtain the maximum saturation average value and the minimum saturation average value of each node on the saturation profile when each node of each flow tube in the vertical direction is completely balanced;
③ comparing the average water saturation when each flow tube node is fully balanced with the maximum water saturation average and the minimum water saturation average of each node on the saturation profile to obtain profile balance state type A, profile balance state secondary type B, inter-node proportion coefficient a of the profile balance state type, inter-node proportion coefficient B of the profile balance state secondary type, balance position of the profile balance state type A and balance position of the profile balance state secondary type B;
④ calculating section water saturation and section equilibrium state equivalent capillary force of the secondary oil-water interface;
⑤ calculate the water saturation and the relative permeability of the oil and water phases at each node of each flow tube vertically.
In the above-described calculation method, the calculation is performed,the section balance 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
Figure BDA0001225701000000091
Greater than the average of maximum water saturation
Figure BDA0001225701000000092
The number of nodes; the secondary type B of the profile balance state refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced
Figure BDA0001225701000000101
Less than the average minimum water saturation
Figure BDA0001225701000000102
The number of nodes; the inter-node proportionality coefficients comprise a section balanced state type inter-node proportionality coefficient a and a section balanced state secondary type inter-node proportionality coefficient b; wherein, the proportionality coefficient a between the type nodes of the profile equilibrium state refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced
Figure BDA0001225701000000103
Less than the average of maximum water saturation
Figure BDA0001225701000000104
The number of the nodes accounts for the ratio of the total number of the nodes of the flow pipe; the proportional coefficient b between the secondary type nodes of the profile balance state refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced
Figure BDA0001225701000000105
Greater than the average of maximum water saturation
Figure BDA0001225701000000106
The number of the nodes accounts for the ratio of the total number of the nodes of the flow pipe; the equilibrium position is the average value under the complete equilibrium conditionThe location of the reservoir profile at which the water saturation value is located, including the equilibrium location of profile equilibrium state type A and the equilibrium location of profile equilibrium state sub-type B; the section water saturation of the secondary oil-water interface is the water saturation value of each node of the section calculated under the secondary oil-water interface generated under the influence of gravity; the section equilibrium state equivalent capillary force is a capillary force value at each node of the section considering the influence of gravity, which is calculated according to the section 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 tube is as shown in formula 6
Figure BDA0001225701000000107
In formula 6, Δ h is the height difference caused by capillary force, m; pcCapillary force at each node, atm; gamma raywIs the water gravity,. times.104N/m3；γoOil weight, x 104N/m3(ii) a i being subscript denotes the ith node position, i +1 denotes the next node position of inode, e.g. Pc(i)Represents the capillary force, P, at the ith node positionc(i+1)Representing capillary forces at the i +1 th node position.
Preferably, in step ①, when the vertical height difference of each node of each flow tube is summed up from top to bottom to obtain the total vertical height difference of each node in the vertical direction, the calculation formula is as shown in formula 7
Figure BDA0001225701000000108
In formula 7, hud(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 position;
preferably, in step ①, when the vertical height difference of each node of each flow tube is summed up from bottom to top to obtain the total vertical height difference of each node in the vertical direction, the calculation formula is as shown in formula 8
Figure BDA0001225701000000111
In formula 8, hdu(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.
In the above calculation method, preferably, in step ②, the calculation formula of the average water saturation at the time of complete equilibrium of each flow tube node in the vertical direction is shown in fig. 9
Figure BDA0001225701000000112
In the formula 9, the first and second groups,
Figure BDA0001225701000000113
the average water saturation when each node of each flow pipe in the vertical direction is completely balanced; swzThe 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 tube in the vertical direction;
preferably, in step ②, the calculation formula of the average value of the maximum water saturation of each node on the saturation profile is shown in equation 10 when each node of each flow tube in the vertical direction is fully balanced
Figure BDA0001225701000000114
In the formula 10, the first and second groups,
Figure BDA0001225701000000115
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; swWater saturation of each node; h isudThe 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; Δ h is each flow in the vertical directionVertical height difference of each node of the pipe; i is the ith node position; j is the jth node position; n is the total number of nodes of each flow tube in the vertical direction;
preferably, in step ②, the calculation formula of the average value of the minimum water saturation of each node on the saturation profile is shown in formula 11 when each node of each flow tube in the vertical direction is fully balanced
Figure BDA0001225701000000121
In the formula (11), the first and second groups,
Figure BDA0001225701000000122
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; swWater saturation of each node; h isduThe 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.
In the above calculation method, preferably, in step ③, the calculation formula of the cross-section equilibrium type node-to-node proportionality coefficient is as shown in formula 12
Figure BDA0001225701000000123
In formula 12, a is a cross-sectional equilibrium type inter-node scaling factor;
Figure BDA0001225701000000124
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;
Figure BDA0001225701000000125
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 in the vertical directionThe total number of nodes per flow tube.
In the above calculation method, preferably, in step ③, the calculation formula of the cross-section equilibrium secondary type node-node proportionality coefficient is as shown in formula 13
Figure BDA0001225701000000126
In formula 13, b is a cross-sectional equilibrium secondary-type inter-node scaling factor;
Figure BDA0001225701000000127
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;
Figure BDA0001225701000000128
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 pipe in the vertical direction.
In the above calculation method, preferably, in step ③, the calculation formula of the equilibrium position of the profile equilibrium state type is shown in formula 14
Figure BDA0001225701000000131
In formula 14, xaIs a section equilibrium state type equilibrium position; h is the small layer thickness, m; h isudThe total vertical height difference m 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 type.
In the above calculation method, preferably, in step ③, the calculation formula of the equilibrium position of the profile equilibrium sub-type is shown in formula 15
Figure BDA0001225701000000132
In the formula 15, the first and second groups,xbis a profile balance state secondary type balance position; h is the small layer thickness, m; h isduThe total vertical height difference m 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.
In the above calculation method, preferably, in step ④, the calculation formula of the section water saturation of the secondary oil-water interface is shown in formula 16
Figure BDA0001225701000000133
In formula 16, SwpmThe section water saturation, decimal, of each node of the secondary WOC interface position; swThe water saturation and decimal corresponding to each node in the phase permeation; Δ h is the oil-water height difference, m, caused by capillary force; hpmThe profile height, m, of each node for the secondary WOC interface position; i is at the ith node position.
In the above calculation method, preferably, in step ④, the formula for calculating the section equilibrium state equivalent capillary force of the secondary oil-water interface is shown in formula 17
Figure BDA0001225701000000134
In formula 17, SwpmThe section water saturation, decimal, of each node of the secondary WOC interface position; swThe water saturation and decimal corresponding to each node in the phase permeation; pcpmSection capillary force, atm, of each node at the secondary WOC interface position; pcThe capillary force, atm, corresponding to each node in the capillary pressure curve; i is subscript to indicate the ith node position, and i-1 indicates the position of the node immediately preceding the inode.
In the above calculation method, preferably, in step ⑤, the calculation of the water saturation and the relative permeability of the oil and water phases at each node of each flow tube in the vertical direction includes:
step 1, calculating the relative permeability of the oil phase and the water phase corresponding to each node of each flow pipe in the vertical direction at the initial enrichment moment, wherein the calculation formula is shown as formula 18
Figure BDA0001225701000000141
In formula 18, Kr(t0)The relative permeability of each node of oil and water at the initial enriching moment is dimensionless; krThe relative permeability corresponding to each node in the oil-water phase seepage is zero dimension; swThe water saturation and decimal corresponding to each node in the oil-water phase seepage; sw(t0)Enriching the water saturation and decimal of each node at the initial moment; i is subscript to indicate the position of the ith node, and i-1 indicates the position of the node before the i node;
step 2, calculating the oil saturation corresponding to each node of each flow pipe in the vertical direction in the enrichment process, wherein the calculation formula is shown as formula 19
Figure BDA0001225701000000142
In formula 19, SoThe oil saturation, decimal, corresponding to each node; kZPermeability, mD, corresponding to each node in the Z direction; kroThe oil relative permeability of each node is dimensionless; krwThe relative permeability of water for each node is dimensionless; mu.swViscosity of water, mPa · s; mu.soViscosity of the oil, mPa · s; pcCapillary force, atm, for each node; pc∞Section capillary force, atm, of each node at the secondary WOC interface position; phi is porosity, decimal; t is enrichment time, day; n is the number of divided time periods; i is the ith node position;
step 3, calculating the relative permeability of the oil phase and the water phase corresponding to 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
Figure BDA0001225701000000151
In formula 20, Kr(tj)The relative permeability of each node at the completion moment of enrichment is calculated without dimension; krThe relative permeability corresponding to each node in the oil-water phase seepage is zero dimension; swThe water saturation and decimal corresponding to each node in the oil-water phase seepage; sw(tj)Calculating the water saturation and decimal of each node at the completion moment of enrichment; i is subscript to indicate the ith node position, and i-1 indicates the position of the node immediately preceding the inode.
In the above calculation method, preferably, in step S13, the calculation process of the level enrichment includes:
step 1, calculating capillary force corresponding to each node of each flow tube on a plane at the initial enrichment moment, wherein a calculation formula is shown as a formula 21
Figure BDA0001225701000000152
In formula 21, Pc(t0)To enrich the capillary force, atm, of each node at the initial moment; pcThe capillary force, atm, corresponding to each node in the capillary pressure curve; swThe water saturation and decimal corresponding to each node in the oil-water phase seepage; sw(t0)Enriching the water saturation and decimal of each node at the initial moment; i is subscript to indicate the position of the ith node, and i-1 indicates the position of the node before the i node;
step 2, calculating the oil saturation corresponding to each node of each flow pipe on the plane in the enrichment process, wherein the calculation formula is shown as the formula 22
Figure BDA0001225701000000153
In formula 22, SoThe oil saturation, decimal, corresponding to each node; kZPermeability, mD, corresponding to each node in the X direction; kroThe oil relative permeability of each node is dimensionless; krwThe relative permeability of water for each node is dimensionless; mu.swViscosity of water, mPa · s; mu.soViscosity of the oil, mPa · s; pcCapillary force, atm, for each node; phi is porosity, decimal; t is time, day; n is the number of divided time periods; i is subscript to indicate the position of the ith node, i +1 indicates the position of the node after the i node, and i-1 indicates the position of the node before the i node;
step 3, calculating capillary force corresponding to each node of each flow tube on the plane at the completion moment of enrichment, wherein the calculation formula is shown as formula 23
Figure BDA0001225701000000161
In formula 23, Pc(tj)Capillary force of each node at the completion of enrichment, atm; pcThe capillary force, atm, corresponding to each node in the capillary pressure curve; swThe water saturation and decimal corresponding to each node in the oil-water phase seepage; sw(tj)The water saturation and decimal fraction of each node at the completion moment of enrichment; i is subscript to indicate the position of the ith node, and i-1 indicates the position of the node before the i node;
and 4, obtaining the relative permeability of the oil phase and the water phase of each node of each flow pipe on the plane according to the calculated oil saturation corresponding to each node of each flow pipe on the plane in the enrichment process and a formula 20.
In one embodiment, step S12 includes the following processes (shown in fig. 3 and 4):
(1) presetting the characteristic parameters of the preliminary physical model to obtain a preset preliminary physical model; wherein the content of the first and second substances,
setting the single-layer thickness of the preliminary physical model as the total thickness/preset longitudinal dividing layer number of the preliminary physical model;
setting the initial heterogeneity of the preliminary physical model as a preset longitudinal heterogeneity;
(2) calculating to obtain the fitted water content of the oil production well according to a streamline flow pipe method based on a preset preliminary physical model;
(3) and judging the fitting water content of the oil production well obtained by calculation:
the fitted water content is consistent with the actual water content of an oil production well on the target oil reservoir, and the fitted water content is judged to be in accordance with the requirement;
the fitted water content is not in accordance with the actual water content of the oil production well on the target oil reservoir, and the fitted water content is judged to be not in accordance with the requirement; at the moment, the number of longitudinal division layers and the longitudinal heterogeneity of the primary physical model need to be modified, and the operation processes of the steps (2) to (3) are repeated until the fitted water content is consistent with the actual water content of the oil production well on the target oil reservoir;
(4) setting a target water content based on a preset preliminary physical model, and calculating an oil saturation field when the water content of the oil production well reaches the target water content according to a streamline flow pipe method; wherein the target water content is the corresponding water content when the water content of the oil production well reaches the closing enrichment opportunity;
(5) setting a saturation correction relational expression, and correcting the oil-containing saturation field obtained by calculation in the step (4) by using the saturation correction relational expression to obtain a corrected oil-containing saturation field;
(6) and judging the corrected oil saturation field:
the corrected oil saturation field is in accordance with the actual saturation field of the target oil reservoir, and the corrected oil saturation field is judged to be in accordance with the requirement;
the corrected oil-containing saturation field is not in accordance with the actual saturation field of the target oil reservoir, and the corrected oil-containing saturation field is judged to be not in accordance with the requirements; at the moment, resetting the saturation correction relational expression, and repeating the operation processes from the step (5) to the step (6) until the corrected oil-containing saturation field is consistent with the actual saturation field of the target oil reservoir;
(7) and correcting the primary physical model of the target oil reservoir to obtain a corrected physical model.
In one embodiment, step S13 includes the following process:
(1) calculating the vertical height difference of each node of each flow pipe, and performing cumulative summation respectively in a top-down mode and a bottom-up mode to obtain the total vertical height difference corresponding to each vertical node position;
(2) calculating the average water saturation when each node of each flow pipe in the vertical direction is completely balanced, and comparing the thickness of the layer position of each flow pipe with the total vertical height difference corresponding to each node position in the vertical direction to obtain the maximum water saturation average value and the minimum water saturation average value of each node on the saturation profile;
(3) comparing the average water saturation in the vertical direction with the maximum water saturation average value and the minimum water saturation average value of each node on the saturation profile to obtain a profile balanced state type, a profile balanced state secondary type, an internode proportion coefficient of the profile balanced state secondary type, a balanced position of the profile balanced state type and a balanced position of the profile balanced state secondary type;
(4) calculating the section water saturation and section equilibrium state equivalent capillary force of a secondary oil-water interface;
(5) presetting enrichment time and enrichment times, respectively carrying out vertical and horizontal enrichment calculation in each circulation calculation, and calculating the water saturation and the relative permeability of oil and water phases of each node of each flow pipe (as shown in figure 5);
(6) performing vertical and horizontal enrichment calculation once each cycle, judging whether the preset enrichment times are reached, if not, performing the step (5) for calculation, and if the preset enrichment times are reached, outputting and storing the water saturation and the relative permeability data of the oil phase and the water phase of each node of each flow pipe after the last enrichment calculation;
(7) and (4) calculating the water content of the oil production well end according to the data obtained in the step (6), namely the water content of the oil production well, outputting the water content of the oil production well, and finishing the calculation.
The invention has the beneficial effects that:
the technical scheme provided by the invention effectively overcomes the defect of the existing method, can accurately predict the change condition of the displacement front parameter, and realizes the quick calculation of the secondary enrichment of the residual oil in the later period of high water content of the complex fault block oil reservoir.
Drawings
FIG. 1 is a schematic flow diagram of a secondary enrichment and rapid identification method for residual oil in a high water-cut later stage of a complex fault block oil reservoir;
FIG. 2 is a schematic diagram of a process for establishing a preliminary physical model of a complex fault block reservoir in example 1;
FIG. 3 is a schematic flow chart of a method of fitting the dynamic history characteristics of the production well according to example 1;
FIG. 4 is a schematic flow chart of the calculation of the saturation field before secondary enrichment of the remaining oil in example 1;
FIG. 5 is a schematic view of a calculation flow of parameters of each node in the secondary enrichment process of the residual oil in example 1;
FIG. 6 is a schematic diagram of the spatial configuration of the complex fault block reservoir physical model in example 1;
FIG. 7 is a graph comparing a planar oil saturation field with a vertical oil saturation field before and after enrichment of remaining oil in example 1, wherein A is the horizontal oil saturation field before enrichment, C is the vertical oil saturation field before enrichment, B is the horizontal oil saturation field after enrichment, and D is the vertical oil saturation field after enrichment;
FIG. 8 is a schematic view of a flow tube with a horizontal plane along the main flow line;
fig. 9 is a schematic view of the spatial structure of the flow tube.
Detailed Description
The technical solutions of the present invention will be described in detail below in order to clearly understand the technical features, objects, and advantages of the present invention, but the present invention is not limited to the practical scope of the present invention.
Examples
In this embodiment, a complex fault block oil reservoir in China is used as a research object, and a secondary enrichment fast identification method for residual oil in a high water-cut later stage of the complex fault block oil reservoir is provided, as shown in fig. 1, the method includes:
step S10, the target reservoir is measured to obtain geological parameters and well pattern parameters of the target reservoir (as shown in table 1).
Step S11, establishing a preliminary physical model of the target oil deposit according to the geological parameters and the well pattern parameters of the target oil deposit, which specifically comprises the following steps:
① setting the bottom surface type of the preliminary physical model according to the obtained well pattern parameters, which comprises the following steps:
a. 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;
b. setting the bottom surface type of the preliminary physical model according to the well pattern type and the oil-water well ratio (the setting process is shown in figure 2): when the well pattern type of the target oil reservoir is staggered, setting the bottom surface type of the primary physical model as a regular triangle; when the well pattern type of the target oil reservoir is right and the oil-water well ratio is 1, setting the bottom type of the preliminary physical model as a rectangle; when the well pattern type of the target oil reservoir is right, and the number of oil-water wells is not equal to 1, setting the bottom surface type of the primary physical model as a regular triangle; in this embodiment, the bottom surface type of the preliminary physical model is a regular triangle;
c. 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 according to the determined well spacing and row spacing;
d. after the type of the bottom surface is determined to be a regular triangle, the bottom surface is translated for a certain distance along the vertical direction, the distance is equal to the thickness of the actual reservoir, the obtained three-dimensional space structure is the space structure of the preliminary physical model,
② setting the deposition rhythm, geological inclination and permeability anisotropy of the preliminary physical model according to the actual geological structure characteristics of the target oil reservoir,
the sedimentary prosody refers to the rule that diagenetic rocks are formed by layered deposition according to the sequence of particle size and specific gravity, and is divided into homogeneous prosody, positive prosody and reverse prosody; homogeneous rhythm sand layer: the hydrodynamic force condition is relatively stable, the lithology in the stratum and the physical property are homogeneous; positive rhythm sand layer: the lower part has coarse granularity, and the upper part has fine granularity, which reflects that the hydrodynamic condition of the deposition environment becomes weaker from bottom to top; a reverse rhythm sand layer: the lower part has fine granularity, the upper part has coarse granularity, and the hydrodynamic condition of the deposition environment is strengthened from bottom to top;
the stratum inclination angle refers to an included angle between the oil layer direction and the horizontal plane between the oil-water wells;
permeability anisotropy refers to the difference in permeability change of the oil layer in different directions.
③ setting general parameters required to be obtained in oil reservoir measurement, such as average permeability, initial oil saturation, porosity, irreducible water saturation, residual oil saturation, permeability grade difference, underground crude oil viscosity, reservoir thickness, reservoir dividing layer number, injection-production speed and the like of the primary physical model according to the obtained actual geological parameters of the target oil reservoir,
average permeability refers to the amount of capacity of the rock to allow fluid to pass through at a certain pressure differential;
the initial oil saturation is the ratio of the oil volume in the effective pore space of the oil reservoir to the effective pore volume of the rock, expressed as a percentage;
the porosity is the ratio of the sum of all pore space volumes in the rock sample to the volume of the rock sample;
irreducible water saturation refers to the percentage of reservoir pore volume that is occupied by the smallest body of water remaining in the rock pores due to rock surface wettability;
residual oil saturation refers to the percentage of the volume of residual oil in the rock pore space;
the permeability grade difference refers to the ratio of the maximum permeability to the minimum permeability;
the viscosity of a subterranean crude oil refers to a measure of the frictional resistance of the oil as one part flows relative to another part within the crude oil under formation conditions.
The preliminary physical model of the target reservoir in this embodiment is shown in fig. 6, the bottom surface of the model is a regular triangle, and the size of each mesh in the X, Y, Z direction of the model is: 10m, 10m and 2m, the total number of grids is 35 multiplied by 30 multiplied by 25 which is 26250, and the lower part of the reservoir has edge water. The production wells (PRO) are located at the high part of the reservoir, the injection wells (INC) are located at the low part of the reservoir, and the oil-water wells are arranged opposite to each other. Specific parameters are shown in Table 1
TABLE 1 corresponding parameters of the preliminary physical model of the target reservoir
Parameter name Value of parameter Parameter name Value of parameter
Pattern type Regular triangle Porosity/%) 0.28
Well spacing/m 300 viscosity/mPa.s of groundwater 0.6
Row spacing/m 300 viscosity/mPa.s of underground crude oil 7
Dip/degree of formation 10 Specific gravity of groundwater 0.96
Reservoir rhythm Positive rhythm Underground oil ratioHeavy load 0.78
Reservoir thickness/m 50 Initial oil saturation/%) 0.55
Maximum capillary force/bar of oil and water 0.5 Irreducible water saturation/% 0.25
Average permeability/10-3μm2 300 Residual oil saturation/%) 0.20
Permeability ratio in vertical plane 0.3 Water content before shut-in/%) 92
Difference in permeability grade 5 Water injection quantity per m of single layer3 500
Step S12, based on the preliminary physical model of the target oil deposit, 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 deposit to obtain a corrected physical model, specifically comprising the following steps:
①, presetting reservoir parameter characteristics of the preliminary physical model (as shown in fig. 3) to obtain a preset preliminary physical model, wherein the single-layer thickness of the model is the total thickness/longitudinal dividing layer number of the model, and the initial heterogeneity of the model is the longitudinal heterogeneity;
②, the water content and the water content increase rate of each node in the main flow line direction are calculated by equations 1 and 2, respectively.
③ calculating the water-containing front edge saturation and the water-containing front edge position in the main flow line direction, the specific process comprises:
water saturation (S) can be established according to equations 1 and 2w) With water content (f)w) Is (noted as S)w—fwRelation curve) of Sw(i)Point and each Sw—fwConnecting the nodes of the relation curve to a line, and calculating the derivative of the line, wherein the node corresponding to the maximum derivative value is the water saturation (S) of the leading edgewf)；
Water saturation (S) can be established according to equations 1 and 2w) And water content rate of rise (f'w) (denoted as S)w—f’w) From this relationship, f 'can be obtained'w(Swf) The value, and further calculating according to equation 3 to obtain the water cut front position (x)f)。
④ calculating the total water content of the output end in the main flow line direction, the concrete process comprises:
a. 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 (the water injection amount of each layer and the permeability data of each flow pipe can be directly measured), so as to calculate the water breakthrough time of each layer (the calculation formula is shown as formula 4) and the water content of each layer output end (the calculation formula is shown as formula 5 and formula 2);
b. 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.
⑤, the total water content of the production end in the main flow line direction is judged and corrected until the total water content of the production end is in accordance with the actual water content (at the moment, the corresponding longitudinal division layer number and the longitudinal heterogeneity data are in accordance with the requirements, namely the final acceptance value), and the fitting water content of the oil production well is obtained through fitting.
Wherein, the correction process includes modifying the number of longitudinal partitioned layers and the longitudinal heterogeneity of the preliminary physical model, and fitting the reservoir heterogeneity (as shown in fig. 3).
⑥ setting a target water content (the target water content refers to the corresponding water content when the well closing enrichment opportunity is met), and obtaining an oil saturation field corresponding to the situation that the water content of the oil production well meets the secondary enrichment requirement of the residual oil according to the calculation method from the step ② to the step ⑤, wherein the oil saturation field is a predicted value.
⑦, performing oil saturation interpolation (i.e. establishing a saturation correction relation) on the boundary to the main flow line to correct the oil saturation field obtained in the step ⑥, thereby obtaining a saturation field before secondary enrichment of the remaining oil, wherein the calculation flow of the steps ① - ⑤ is shown in fig. 3, and the calculation flow of the steps ⑥ - ⑦ is shown in fig. 4.
⑧, correcting the preliminary physical model of the target reservoir according to the number of longitudinal division layers and the final acceptance value of the longitudinal heterogeneity determined in step ⑤ to obtain a corrected physical model (as shown in fig. 3).
Step 13, based on the corrected physical model, calculating vertical enrichment and horizontal enrichment of each node in the residual oil enrichment process respectively to obtain reservoir saturation and water content of each node to complete identification of secondary enrichment of residual oil in the high-water-content later stage of the target oil reservoir (as shown in fig. 5), and specifically comprises the following steps:
1) the calculation flow of the vertical enrichment process is as follows:
① according to equation 6, calculating to obtain the vertical height difference of each node of each flow tube, and then respectively performing cumulative summation on the vertical height difference of each node of each flow tube according to the top-down mode (the calculation formula is shown in equation 7) and the bottom-up mode (the calculation formula is shown in equation 8) to obtain the total vertical height difference corresponding to each vertical node position.
② calculating the average water saturation when each node of each flow tube is completely balanced vertically (calculation formula is shown in formula 9), comparing the thickness of the layer of each flow tube with the total vertical height difference of each node of each flow tube vertically obtained in the previous step, and obtaining the maximum water saturation average value (calculation formula is shown in formula 10) and the minimum water saturation average value (calculation formula is shown in formula 11) of each node on the saturation profile.
③ comparing the average water saturation when each flow tube node is completely balanced with the maximum saturation average and the minimum saturation average of each node on the saturation profile to obtain profile balance state type A, profile balance state secondary type B, inter-node proportion coefficient a of the profile balance state type, inter-node proportion coefficient B of the profile balance state secondary type, balance position of the profile balance state type A and balance position of the profile balance state secondary type B, wherein,
the section balance 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
Figure BDA0001225701000000221
Greater than the average of maximum water saturation
Figure BDA0001225701000000222
The number of nodes; the secondary type B of the profile balance state refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced
Figure BDA0001225701000000223
Less than the average minimum water saturation
Figure BDA0001225701000000224
The number of nodes;
the proportion coefficient a between the type nodes of the profile equilibrium state refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced
Figure BDA0001225701000000225
Less than maximum water saturationAverage value of (2)
Figure BDA0001225701000000226
The ratio of the number of the nodes in the flow pipe to the total number of the nodes in the flow pipe (the calculation formula is shown as formula 12); the proportional coefficient b between the secondary type nodes of the profile balance state refers to the average water saturation of each node when each node of each flow pipe in the vertical direction is completely balanced
Figure BDA0001225701000000227
Greater than the average of maximum water saturation
Figure BDA0001225701000000228
The ratio of the number of the nodes in the flow pipe to the total number of the nodes in the flow pipe (the calculation formula is shown in formula 13);
the equilibrium position of the profile equilibrium state type A (the calculation formula is shown in formula 14) and the equilibrium position of the profile equilibrium state secondary type B (the calculation formula is shown in formula 15);
④ calculating the section water saturation (formula shown in formula 16) and section equilibrium state equivalent capillary force (formula shown in formula 17) of the secondary oil-water interface.
⑤, calculating the water saturation and the relative permeability of oil and water phases of each flow pipe node vertically, which comprises the following steps:
a. calculating the relative permeability of the oil phase and the water phase corresponding to each node of each flow pipe in the vertical direction at the initial enrichment moment according to a formula 18;
b. calculating the oil saturation corresponding to each node of each flow pipe in the vertical direction in the enrichment process according to a formula 19;
c. and (4) calculating the relative permeability of the oil phase and the water phase corresponding to each node of each flow pipe in the vertical direction at the completion moment of enrichment according to a formula 20.
2) The calculation procedure of the horizontal enrichment process is as follows
① calculating capillary force corresponding to each flow tube node on the plane at the initial time of enrichment (formula 21);
② calculating the oil saturation corresponding to each node of each flow tube on the plane in the enrichment process (the calculation formula is shown in formula 22);
③ calculating capillary force corresponding to each flow tube node on the plane at the completion time of the enrichment (the calculation formula is shown in formula 23).
3) According to the scheme shown in FIG. 5:
a. presetting enrichment time and enrichment times, respectively carrying out vertical and horizontal enrichment calculation in each circulation calculation, and calculating the water saturation of each node of each flow pipe and the relative permeability of oil and water phases;
b. b, performing vertical and horizontal enrichment calculation once each cycle, judging whether preset enrichment times are reached, if not, performing the calculation of the step a, and if the enrichment times are reached, outputting and storing the water saturation and the relative permeability data of the oil phase and the water phase of each node of each flow pipe after the last enrichment calculation;
c. and c, calculating the water content of the end of the oil production well (the calculation formula is shown as formula 1) according to the data obtained in the step b, namely the water content of the well-opened oil well, outputting the water content of the well-opened oil well, and finishing the calculation.
In this embodiment, a comparison graph between a planar oil-containing saturation field and a vertical oil-containing saturation field before and after enrichment of remaining oil is obtained according to the above-mentioned method for rapidly identifying secondary enrichment of remaining oil in the later period of high water content of a complex fault block oil reservoir (as shown in fig. 7, a in fig. 7 is the oil-containing saturation field in the horizontal direction before enrichment, C is the oil-containing saturation field in the vertical direction before enrichment, B is the oil-containing saturation field in the horizontal direction after enrichment, and D is the oil-containing saturation field in the vertical direction after enrichment).

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
Figure FDA0002364528680000031
In formula 1, fwThe water content is obtained; k is a radical ofrw、kroRelative permeability of water phase and oil phase respectively; mu.sw、μoThe 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
Figure FDA0002364528680000032
In formula 2, f'wIs the water cut rate of rise; swThe 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
Figure FDA0002364528680000033
Wherein the content of the first and second substances,
Figure FDA0002364528680000034
in formula 3, xfIs the hydrous leading edge position; x is the number of0Is a water-containing initial position;f'w(Swf) 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 tpAs displacement time; f. ofw(Swf) The water content is corresponding to the saturation of the water-containing front edge; swfIs the water cut front saturation; swcTo 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
Figure FDA0002364528680000041
In formula 4, xfIs the hydrous leading edge position; x is the number of0Is a water-containing initial position; f'w(Swf) 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;
Figure FDA0002364528680000042
in formula 5, tpAs displacement time; t is water breakthrough time; l is the oil-water well spacing; f'w(SwL) 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
Figure FDA0002364528680000051
In equation 6,. DELTA.h is the height difference caused by capillary force；PcThe capillary force at each node of each flow pipe in the vertical direction; gamma raywIs the severity of the water; gamma rayoIs 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
Figure FDA0002364528680000052
In formula 7, hud(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
Figure FDA0002364528680000053
In formula 8, hdu(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
Figure FDA0002364528680000054
In the formula 9, the first and second groups,
Figure FDA0002364528680000055
the average water saturation when each node of each flow pipe in the vertical direction is completely balanced; swzThe 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
Figure FDA0002364528680000061
In the formula 10, the first and second groups,
Figure FDA0002364528680000062
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; swWater saturation of each node; h isudThe 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
Figure FDA0002364528680000063
In the formula (11), the first and second groups,
Figure FDA0002364528680000064
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; swWater saturation of each node; h isduThe 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
Figure FDA0002364528680000065
In formula 12, a is a cross-sectional equilibrium type inter-node scaling factor;
Figure FDA0002364528680000066
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;
Figure FDA0002364528680000067
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
Figure FDA0002364528680000071
In formula 13, b is a cross-sectional equilibrium secondary-type inter-node scaling factor;
Figure FDA0002364528680000072
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;
Figure FDA0002364528680000073
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
Figure FDA0002364528680000074
In formula 14, xaIs a section equilibrium state type equilibrium position; h is the thickness of the small layer; h isudThe 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
Figure FDA0002364528680000075
In formula 15, xbIs a profile balance state secondary type balance position; h is the thickness of the small layer; h isduThe 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
Figure FDA0002364528680000076
In formula 16, SwpmThe section water saturation of each node at the position of the secondary oil-water interface; swThe water saturation corresponding to each node in the phase permeation; delta h is the oil-water height difference caused by capillary force; hpmThe 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
Figure FDA0002364528680000081
In formula 17, SwpmThe section water saturation of each node at the position of the secondary oil-water interface; swThe water saturation corresponding to each node in the phase permeation; pcpmThe section capillary force of each node at the position of a secondary oil-water interface is obtained; pcThe 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
Figure FDA0002364528680000082
In formula 18, Kr(t0)The relative permeability of each node for enriching oil water at the initial moment; kr(i)Relative permeability corresponding to each node in oil-water phase seepage; sw(i)The water saturation corresponding to each node in the oil-water phase seepage; sw(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
Figure FDA0002364528680000083
In formula 19, SoOil saturation corresponding to each node; kZThe permeability corresponding to each node in the Z direction, wherein the Z direction is the direction vertical to the horizontal plane; kroThe oil relative permeability for each node; krwRelative permeability of water for each node; mu.swIs the viscosity of water; mu.soIs the viscosity of the oil; pcCapillary force for each node; pc∞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
Figure FDA0002364528680000091
In formula 20, Kr(tj)Relative permeability of each node at the completion of enrichment; kr(i)Relative permeability corresponding to each node in oil-water phase seepage; sw(i)The water saturation corresponding to each node in the oil-water phase seepage; sw(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
Figure FDA0002364528680000092
In formula 21, Pc(t0)Enriching capillary force of each node at initial time; pc(i)The capillary force corresponding to each node in the capillary pressure curve; sw(i)The water saturation corresponding to each node in the oil-water phase seepage; sw(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
Figure FDA0002364528680000093
In formula 22, SoOil saturation corresponding to each node; kxThe permeability corresponding to each node in the X direction, which is the horizontal direction; kroThe oil relative permeability for each node; krwRelative permeability of water for each node; mu.swIs the viscosity of water; mu.soIs the viscosity of the oil; pcCapillary 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
Figure FDA0002364528680000101
In formula 23, Pc(tj)Calculating capillary force of each node at the completion moment of enrichment; pc(i)The capillary force corresponding to each node in the capillary pressure curve; sw(i)The water saturation corresponding to each node in the oil-water phase seepage; sw(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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