CN113919247A - Complex fracture network oil reservoir flow simulation method - Google Patents

Complex fracture network oil reservoir flow simulation method Download PDF

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CN113919247A
CN113919247A CN202111147087.1A CN202111147087A CN113919247A CN 113919247 A CN113919247 A CN 113919247A CN 202111147087 A CN202111147087 A CN 202111147087A CN 113919247 A CN113919247 A CN 113919247A
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赵辉
盛广龙
周玉辉
马嘉令
湛文涛
饶翔
胡清雄
程宏杰
王辉
梁成钢
高阳
蒋志斌
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Abstract

The invention discloses a complex fracture network oil reservoir flow simulation method, which comprises the following steps: dispersing an oil reservoir into a series of nodes according to a complex fracture network distribution rule of a control region of the fractured horizontal well, and representing the flow characteristics of fluid in media with different scales by adopting flow paths among the nodes; estimating a pressure Laplace operator by using node physical properties, an influence domain and a weighted least square algorithm, and providing a conductivity calculation method reflecting the seepage capability of a connecting unit and a connected volume calculation method of material-based attribute parameters; and taking the connecting unit as an object, solving and acquiring the flow flux in the unit through a node pressure equation, performing semi-analytic tracking of a saturation equation along the connecting unit to calculate the output dynamics, obtaining the production dynamics of different perforation points, and realizing the simulation of the complex fracture network oil reservoir flow. The method has the advantages that the crack form can be accurately carved in a node form, and the flow simulation of the crack network can be performed rapidly and efficiently.

Description

Complex fracture network oil reservoir flow simulation method
Technical Field
The invention belongs to the field of fractured reservoir flow simulation, and particularly relates to a complex fractured network reservoir flow simulation method.
Background
Almost all oil reservoirs are distributed with cracks, at present, most oil reservoirs are fractured oil reservoirs, fractured oil reservoir flow simulation has a remarkable significance for exploring the fractured oil reservoirs, and at present, fractured oil reservoir simulation has the defects of large calculation amount or low precision.
Disclosure of Invention
The invention provides a complex fracture network oil reservoir flow simulation method with moderate calculation amount and high accuracy for solving the technical problems.
The technical scheme of the invention is as follows: a complex fracture network reservoir flow simulation method comprises the following steps:
step 1: dispersing an oil reservoir into a series of nodes according to a complex fracture network distribution rule of a control region of the fractured horizontal well, and representing the flow characteristics of fluid in media with different scales by adopting flow paths among the nodes;
step 2: estimating a pressure Laplace operator by using node physical properties, an influence domain and a weighted least square algorithm, and providing a conductivity calculation method reflecting the seepage capability of a connecting unit and a connected volume calculation method of material-based attribute parameters;
and step 3: and taking the connecting unit as an object, solving and acquiring the flow flux in the unit through a node pressure equation, performing semi-analytic tracking of a saturation equation along the connecting unit to calculate the output dynamics, obtaining the production dynamics of different perforation points, and realizing the simulation of the complex fracture network oil reservoir flow.
In the step 1, for a fractured horizontal well with complex fracture network distribution characteristics, a node system is adopted to equivalently depict a reservoir oil deposit, then, according to the node distribution condition of the node system, a fluid flow path is represented according to reservoir fluid migration characteristic connection nodes, and based on the node system and the flow path connection principle between nodes, reservoir representation and complex fracture form depiction are carried out on a fractured modified reservoir of the unconventional horizontal well.
The reservoir is divided into three regions, namely a region 1, a region 2 and a region 3 according to fracture distribution characteristics;
the zone 1 is a distribution position of a secondary fracture, third class nodes are respectively arranged at the root, the front end and each inflection point of the secondary fracture, and are sequentially connected according to a fracture expansion rule to accurately depict the fracture form, wherein the physical property parameters of the third class nodes adopt fracture physical property parameters;
the zone 2 is a zone around the secondary fracturing fracture, and class nodes are divided in the zone 2 to accurately describe the complex flowing characteristics of the matrix to the fracture in the zone around the secondary fracturing fracture;
the region 3 is an unmodified region of a reservoir, and a class I node is divided in the region 3 and used for representing fluid from the unmodified region to a modified region;
the distribution density of the third class nodes is greater than that of the first class nodes, and the distribution density of the second class nodes is greater than that of the third class nodes;
the physical property parameters of the first class nodes and the second class nodes adopt matrix physical property parameters, and the matrix physical property parameters can be subjected to heterogeneous assignment according to a fine geological model.
Wherein the flow path between nodes in the step 1 comprises a matrix internal flow path, a matrix-fracturing fracture flow path and a fracturing fracture internal flow path;
the flow path in the matrix is characterized in that the class I nodes are all connected with the class I nodes on the periphery of the class I nodes, and the flow direction of fluid between any two connected class I nodes is bidirectional flow;
the matrix-fracturing fracture flow path is formed by connecting a class II node around the fracturing fracture with a class I node around the fracturing fracture and a class III node nearest to the class II node;
the flow path inside the fractured fracture is that the fluid in the fracture flows to the position of a wellbore along the fracture shape.
Wherein the conductivity T in the step 2ijIs represented by formula (4):
Figure BDA0003285815920000031
wherein, ViIs the control volume of node i in m3；
λijIs the total fluid flow rate in mD (mPa. s)-1，
Wherein the content of the first and second substances,
Figure BDA0003285815920000032
kroand krwRelative permeability of oil phase and water phase, respectively, with unit mD;
μoand muwThe viscosity of the oil phase and the viscosity of the water phase are respectively, and the unit is mPa.s;
Figure BDA0003285815920000033
the coefficient is estimated by Laplace operator generalized finite difference, and the unit is 1;
alpha is a unit conversion coefficient and takes the value of 0.0864;
kijis the average permeability of the connecting element (i.j), in mD, and is taken as the permeability k at the i node of the connecting elementiAnd permeability k at the j nodejThe harmonic mean of (a) is as in formula (5):
Figure BDA0003285815920000034
wherein the communication volume V in the step 2ijIs given by the formula (6):
Figure BDA0003285815920000035
wherein, TijConductivity of the connecting unit in m3/d/MPa；
VRIs the reservoir volume in m3；
LijIs the link unit length in m;
kijis the average permeability of the connecting unit (i.j) in mD;
λijis the total fluid flow rate in mD (mPa. s)-1；
N is the total number of the connection units taking the i node as an end point.
Wherein t time steps in said step 3 connect the upstream fluxes of the units (i.j)
Figure BDA0003285815920000041
Is given by equation (13), where node i is located upstream of node j:
Figure BDA0003285815920000042
wherein the content of the first and second substances,
Figure BDA0003285815920000043
connecting cell conductivity in m for two-phase flow3/d/MPa；
pi t+ΔtIs the pressure at the i node at time t + Δ t, in MPa;
Figure BDA0003285815920000044
is the pressure at the j node at time t + Δ t, in MPa;
after the upstream flux of the connected element has been obtained, it is substituted into the control volume V of the grid i at time tiIn the internal material balance equation (2), the percolation transport equation can be solved to obtain the saturation distribution on the connection unit, wherein formula (2) is as follows:
Figure BDA0003285815920000045
wherein, TijIs the conductivity of two adjacent grids, in mD (mPa. s)-1；
pi,pjThe pressure of the grids i and j is respectively, and the unit is MPa;
Ct,ifor mesh i is the overall compression factor, 1/MPa.
Compared with the prior art, the invention has the beneficial effects that: according to the invention, finite difference is adopted to solve pressure by adopting a connection element seam network flow simulation method, and saturation distribution on a connection path is solved by adopting a semi-analytic method, so that the calculation efficiency is greatly improved on the premise of ensuring the calculation accuracy, and meanwhile, a node form can be adopted to accurately depict the crack form, and seam network flow simulation can be carried out more quickly and efficiently.
Drawings
FIG. 1 is a schematic diagram of an INSIM connectivity model;
FIG. 2 is a schematic diagram of INSIM virtual node encryption;
FIG. 3 is a schematic diagram depicting complex fractures of a fractured horizontal well;
FIG. 4 is a schematic diagram of connection relationships between different types of nodes;
FIG. 5 is a schematic diagram of a fractured horizontal well complex fracture network representing fractured horizontal well complex fracture morphology based on connecting elements;
FIG. 6 is a schematic diagram of node distribution representing complex fracture morphology of a fractured horizontal well based on a connecting element;
FIG. 7 is a schematic diagram of a connection system for fracture horizontal well complex fracture morphology characterization based on a connection element;
FIG. 8 is a schematic diagram of a reservoir property parameter distribution-permeability distribution;
FIG. 9 is a schematic diagram of a reservoir property parameter distribution-porosity distribution;
FIG. 10 is a schematic of reservoir connectivity parameter distribution-conductivity distribution;
FIG. 11 is a schematic of reservoir connected parameter distribution-connected volume distribution;
FIG. 12 is a schematic diagram of inversion of a connected parameter-conductivity distribution based on production data;
FIG. 13 is a schematic diagram of inversion of connected parameter-connected volume distribution based on production data;
FIG. 14 is a schematic comparison of bottom hole flow pressure.
Detailed Description
The present invention is further described in detail below with reference to the attached drawings so that those skilled in the art can implement the invention by referring to the description text.
The connection element method assumes the actual reservoir well points as a series of nodes, and connects the nodes with each other to form a one-dimensional connection path, as shown in fig. 1. For the reservoir with strong heterogeneity, the virtual well point with the injection and production amount of 0 can be added at the corresponding position of the reservoir for fine depiction, as shown in fig. 2. The method greatly improves the calculation efficiency on the premise of ensuring the calculation accuracy, and has obvious advantages.
Aiming at the fractured horizontal well with the complex fracture network distribution characteristics, a node system is adopted to equivalently depict the reservoir, as shown in figure 3. In order to improve the calculation efficiency as much as possible on the premise of ensuring the calculation accuracy, the reservoir is divided into three areas according to the fracture distribution characteristics: the zone 1 is a fracture secondary crack distribution position, nodes are respectively arranged at the root, the front end and each inflection point of a secondary crack, namely third class nodes, the nodes are sequentially connected according to a crack expansion rule, the crack form is accurately depicted, and third class nodes adopt crack physical property parameters such as porosity/permeability and the like; the area 2 is an area around a fracturing secondary fracture, namely a reservoir transformation area, the reservoir in the area has strong heterogeneity and relatively complex fluid seepage due to the influence of the distribution of a fracturing network, and dense nodes, namely class nodes, are divided in the area, so that the complex flowing characteristics of a matrix in the fracturing transformation area to the fracture can be accurately described; the region 3 is an unmodified region of the reservoir, the part of fracture is not affected, the reservoir is homogeneous, the fluid migration rule is simple, and sparse nodes, namely the class nodes, are divided in the region and are used for representing the fluid from the unmodified region to the modified region. The physical parameters of porosity, permeability and the like at the first class node and the second class node adopt matrix physical parameters, and heterogeneous assignment can be performed according to a fine geological model. It should be noted that, under the condition that the model is small or the requirement on the calculation efficiency is not high, the node with the same density may be used to characterize the whole reservoir, and the node distribution may also be characterized by uniform or non-uniform delineation according to the reservoir heterogeneity distribution characteristics.
For the node distribution, the fluid flow path needs to be characterized according to the reservoir fluid migration characteristic connection nodes. There are three flow patterns of fracturing fluid from a modified reservoir, namely, matrix internal flow, matrix-fracture flow, fracture internal flow to the wellbore. (1) Matrix internal flow path: considering the reservoir heterogeneity characteristics, the flowing directions of the fluid at different positions of the local area have uncertainty, so that the nodes of the matrix area are all connected with the adjacent nodes around the nodes, and the fluid flows in two directions to form flowing paths of the fluid between the matrixes, as shown by the (r) type nodes in fig. 4; (2) matrix-fracture flow path: the method comprises the steps that seepage flow with the shortest distance is achieved from fluid in a fracture network to a fracture according to volume fracturing, and the fluid in a matrix around the fracture flows along the path with the smallest distance to the fracture, so that for class II nodes around the fracturing fracture, on one hand, class I nodes around the class II nodes are connected with the class I nodes to form a connecting path, and on the other hand, class III nodes closest to the class I nodes are connected to form a flow path from the matrix to the fracturing fracture, as shown in class II nodes in fig. 4; (3) fracturing fracture internal flow path: the fluid in the fracture generally flows to the wellbore and its flow path is along the fracture formation. Therefore, the type three nodes representing the crack are only connected with the adjacent type three nodes, and a flow path of the fluid inside the crack is formed, as shown by the type three nodes in FIG. 4.
Based on the horizontal well fracturing reformation reservoir node division and the flow path connection principle between the nodes, reservoir characterization and complex fracture morphology depicting can be performed on the unconventional horizontal well fracturing reformation reservoir, as shown in fig. 5-7.
In conventional grid-type numerical simulations, the pressure diffusion equation is considered in its general format as formula (1):
Figure BDA0003285815920000071
wherein k is permeability in mD;
μ is the fluid viscosity in mPa · s;
Figure BDA0003285815920000072
is a Hamiltonian gradient operator;
Ctis the comprehensive compression coefficient, and the unit is 1/MPa;
p is the fluid pressure in MPa;
t is time, d (days);
q is the source-sink term of unit volume in the oil reservoir, 1/d;
alpha is a unit conversion factor and takes the value 0.0864.
At time t, the material balance equation in the control volume Vi of grid i is as follows (2):
Figure BDA0003285815920000073
wherein, TijIs the conductivity of two adjacent grids, in mD (mPa. s)-1；
pi,pjThe pressure of the grids i and j is respectively, and the unit is MPa;
Ct,ifor mesh i is the overall compression factor, 1/MPa.
Then the conductivity between the grids is as follows (3):
Figure BDA0003285815920000074
kijis the average permeability of the grid i, j in mD;
Aijis the common interface area of two adjacent grids i, j, in m2；
LijIs the center-to-center distance between two adjacent grids i, j, and has the unit of m.
In actual reservoir flow simulation, the grid numerical simulation method needs to divide fine grids to obtain a high-precision solution, but the simulation calculation under the fine grids brings huge calculation time consumption. Under the condition of meeting the engineering application precision, in order to reduce the calculation time consumption, a grid coarsening mode is often adopted. Since the connection relationship between grids is limited between adjacent grids, grid coarsening emphasizes the orientation correspondence of the grids. In order to avoid the grid orientation effect, a numerical simulation method based on a connection unit system, namely a connection element method, is provided under a coarsening model to ensure richer connection relations, Zhaohui and the like. In order to calculate the flow equation on the connection unit body, it is necessary to establish the seepage characteristic parameters characterizing the connection unit. Conductivity T in the connection path reflecting the percolation capacity of the connection unitijAs shown in formula (4):
Figure BDA0003285815920000081
wherein, ViIs the control volume of node i in m3；
λijIs the total fluid flow rate in mD (mPa. s)-1，
Wherein the content of the first and second substances,
Figure BDA0003285815920000082
kroand krwRelative permeability of oil phase and water phase, respectively, with unit mD;
μoand muwThe viscosity of the oil phase and the viscosity of the water phase are respectively, and the unit is mPa.s;
Figure BDA0003285815920000083
the coefficient is estimated by Laplace operator generalized finite difference, and the unit is 1;
alpha is a unit conversion coefficient and takes the value of 0.0864;
kijis the average permeability of the connecting element (i.j), in mD, and is taken as the permeability k at the i node of the connecting elementiAnd permeability k at the j nodejThe harmonic mean of (a) is as in formula (5):
Figure BDA0003285815920000091
wherein the communication volume V in the step 2ijIs given by the formula (6):
Figure BDA0003285815920000092
wherein, TijConductivity of the connecting unit in m3/d/MPa；
VRIs the reservoir volume in m3；
LijIs the link unit length in m;
kijis the average permeability of the connecting unit (i.j) in mD;
λijis the total fluid flow rate in mD (mPa. s)-1；
N is the total number of the connection units taking the i node as an end point.
According to the calculation formula of the conductivity and the connection volume, the reservoir physical property parameters are brought in, as shown in fig. 8 and 9, and the conductivity and the connection volume of the reservoir are calculated and obtained as shown in fig. 10 and 11.
Solution of numerical conservation equations
(a) Single phase flow material equation solution
From the equation (2), the control volume V of the node iiThe difference format of the material balance equation in (1) is equation (7):
Figure BDA0003285815920000093
wherein, TijIs the conductivity of the connecting element in m3/d/MPa；
pi t+ΔtIs the pressure at node i at time t + Δ t, in MPa;
Figure BDA0003285815920000094
is the total flow at node i at time t + Δ t in m3/d；
ViIs the control volume of node i in m3；
Ct,iIs the comprehensive compression coefficient with the unit of 1/MPa.
According to equation (7), a linear equation system with respect to pressure is constructed, and the pressure is solved by a numerical simulator.
(b) Two-phase flow material method solution
Neglecting capillary and gravity forces, the two-phase flow pressure diffusion equation is as follows (8):
Figure BDA0003285815920000101
wherein k isro、krwIs relative permeability in mD;
k is permeability in mD;
μ is the fluid viscosity in mPa · s;
Ctis the comprehensive compression coefficient, and the unit is 1/MPa;
p is the fluid pressure in MPa;
t is time in days;
q is the source-sink term per volume in the reservoir, with the unit being 1/day.
Unlike single-phase flow, two-phase flow connection units have a conductivity coefficient which is related to the fluidity and therefore time-dependent (by use of a single phase flow)
Figure BDA0003285815920000102
Expressed), at this time, the two-phase flow pressure equation difference formula is as follows (9):
Figure BDA0003285815920000103
according to the material conservation equation, the calculation format of the pressure dispersion equation can be obtained as shown in the formula (10):
Figure BDA0003285815920000104
wherein, Vp,iIs the controlled pore volume of node i, such that each node controlled pore volume equals the total reservoir pore volume.
As defined herein:
Figure BDA0003285815920000111
wherein
Figure BDA0003285815920000112
And
Figure BDA0003285815920000113
respectively the oil saturation and the water saturation at the node i at the time t;
Co,Cw,Crthe compression coefficients of the oil phase, the water phase and the rock are respectively;
Figure BDA0003285815920000114
one can see the fluidity term in the above equation related to water saturation
Figure BDA0003285815920000115
And Ct,i tAre the result of the t time step taken to linearize the nonlinear pressure equation.
Thus, the nodal control volume mean pressure can be calculated implicitly by solving a system of linear equations in the equation.
Under the conditions of not considering the oil-water weight difference, capillary force, compressibility of oil water and pore media and the like, a pure convection transport equation on the one-dimensional connecting unit under the condition of oil-water two-phase flow can be obtained according to a Buckley-Leverett theory as shown in the formula (12):
Figure BDA0003285815920000116
in the formula, SwIs the water saturation, in units of 1;
qis the total volume of fluid flowing through the seepage section in m3；
Phi is porosity in units of 1;
a is the cross-sectional area of seepage flow, and the unit is m2；
fw(. cndot.) is the water content in units of 1.
Estimating an upstream flux of the connection unit using the node pressure difference and the connection conductivity at the previous time step at the node upstream of the connection unit, assuming that the node i is upstream of the node j, the upstream flux of the connection unit (i, j) at t time step is calculated as equation (13):
Figure BDA0003285815920000117
after the upstream flux of the connection unit is obtained, the transport equation has pure convection characteristics, and the seepage transport equation can be solved according to an upstream weight method and a characteristic line method or a fundamental wave theory of a hyperbolic conservation rate pure convection equation to obtain saturation distribution on the connection unit.
Concept example verification
Based on the shale oil reservoir fracturing horizontal well one-section three-cluster fracture network form and the porosity/permeability distribution characteristics shown in fig. 8 and 9, fracture network flow simulation research is carried out, and basic parameters of the model are shown in table 1.
TABLE 1 model parameters
Figure BDA0003285815920000121
Assuming that the crack length is 0.5m3And simulating the oil production speed of the/d for 1000 days, and calculating the bottom hole flow pressure of the oil production pipe by adopting Eclipse numerical simulation software at a time step every 2 days. The bottom hole flow pressure at the same production rate was then calculated based on the conductivity and connected volume obtained from porosity/permeability (fig. 10 and 11) using the connected element network flow simulation method proposed herein and compared to Eclipse. Meanwhile, the well bottom pressure data of the first 600 days obtained based on Eclipse simulation is used as a real solution, the conductivity and the connected volume (fig. 12 and 13) of the conceptual model are inverted by using an SPSA-based automatic history fitting method, and the well bottom pressure change characteristics of 400 days after the prediction of the conductivity and the connected volume obtained by utilizing inversion fitting are shown in fig. 14.
As can be seen from fig. 14, based on the communication parameters calculated based on the physical property parameters, the bottom hole flowing pressure obtained by simulation is basically consistent with the variation rule of the Eclipse simulation result, but the specific values have certain differences, and the fitting rate is more than 95%. And the prediction result of the connected parameters after fitting is basically the same as the Eclipse simulation result.
Compared with Eclipse and other numerical simulation methods, the connection element slot network flow simulation method adopts finite difference to solve pressure, adopts a semi-analytic method to solve saturation distribution on a connection path, and greatly improves the calculation efficiency on the premise of ensuring the calculation precision. Meanwhile, the crack form can be accurately depicted in a node form, and the flow simulation of the crack network can be performed quickly and efficiently.
While embodiments of the invention have been described above, it is not limited to the applications set forth in the description and the embodiments, which are fully applicable to various fields of endeavor for which the invention may be embodied with additional modifications as would be readily apparent to those skilled in the art, and the invention is therefore not limited to the details given herein and to the embodiments shown and described without departing from the generic concept as defined by the claims and their equivalents.

Claims (7)

1. A complex fracture network reservoir flow simulation method is characterized by comprising the following steps:
step 1: dispersing an oil reservoir into a series of nodes according to a complex fracture network distribution rule of a control region of the fractured horizontal well, and representing the flow characteristics of fluid in media with different scales by adopting flow paths among the nodes;
step 2: estimating a pressure Laplace operator by using node physical properties, an influence domain and a weighted least square algorithm, and providing a conductivity calculation method reflecting the seepage capability of a connecting unit and a connected volume calculation method of material-based attribute parameters;
and step 3: and taking the connecting unit as an object, solving and acquiring the flow flux in the unit through a node pressure equation, performing semi-analytic tracking of a saturation equation along the connecting unit to calculate the output dynamics, obtaining the production dynamics of different perforation points, and realizing the simulation of the complex fracture network oil reservoir flow.
2. The complex fractured network reservoir flow simulation method according to claim 1, wherein in the step 1, for fractured horizontal wells with complex fractured network distribution characteristics, a node system is adopted to equivalently depict the reservoir reservoirs, then, for the node distribution condition of the node system, a node characterization fluid flow path is connected according to reservoir fluid migration characteristics, and based on the node system and the flow path connection principle between nodes, reservoir characterization and complex fractured morphology depicting are carried out on unconventional horizontal well fractured modified reservoirs.
3. The complex fracture network reservoir flow simulation method of claim 2, wherein the reservoir is divided into three regions according to fracture distribution characteristics, namely region 1, region 2 and region 3;
the zone 1 is a distribution position of a secondary fracture, third class nodes are respectively arranged at the root, the front end and each inflection point of the secondary fracture, and are sequentially connected according to a fracture expansion rule to accurately depict the fracture form, wherein the physical property parameters of the third class nodes adopt fracture physical property parameters;
the zone 2 is a zone around the secondary fracturing fracture, and class nodes are divided in the zone 2 to accurately describe the complex flowing characteristics of the matrix to the fracture in the zone around the secondary fracturing fracture;
the region 3 is an unmodified region of a reservoir, and a class I node is divided in the region 3 and used for representing fluid from the unmodified region to a modified region;
the distribution density of the third class nodes is greater than that of the first class nodes, and the distribution density of the second class nodes is greater than that of the third class nodes;
the physical property parameters of the first class nodes and the second class nodes adopt matrix physical property parameters, and the matrix physical property parameters can be subjected to heterogeneous assignment according to a fine geological model.
4. The complex fracture network reservoir flow simulation method of claim 3, wherein the flow paths between nodes in step 1 comprise matrix internal flow paths, matrix-fracture flow paths, fracture internal flow paths;
the flow path in the matrix is characterized in that the class I nodes are all connected with the class I nodes on the periphery of the class I nodes, and the flow direction of fluid between any two connected class I nodes is bidirectional flow;
the matrix-fracturing fracture flow path is formed by connecting a class II node around the fracturing fracture with a class I node around the fracturing fracture and a class III node nearest to the class II node;
the flow path inside the fractured fracture is that the fluid in the fracture flows to the position of a wellbore along the fracture shape.
5. The complex fracture network reservoir flow simulation method of claim 4, wherein the conductivity T in step 2 isijIs represented by formula (4):
Figure FDA0003285815910000021
wherein, ViIs the control volume of node i in m3；
λijIs the total fluid flow rate in mD (mPa. s)-1，
Wherein the content of the first and second substances,
Figure FDA0003285815910000022
kroand krwRelative permeability of oil phase and water phase, respectively, with unit mD;
μoand muwThe viscosity of the oil phase and the viscosity of the water phase are respectively, and the unit is mPa.s;
Figure FDA0003285815910000031
the coefficient is estimated by Laplace operator generalized finite difference, and the unit is 1;
alpha is a unit conversion coefficient and takes the value of 0.0864;
kijis the average permeability of the connecting element (i.j), in mD, and is taken as the permeability k at the i node of the connecting elementiAnd permeability k at the j nodejThe harmonic mean of (a) is as in formula (5):
Figure FDA0003285815910000032
6. the complex fracture network reservoir flow simulation method of claim 5, wherein the connected volume V in step 2ijIs given by the formula (6):
Figure FDA0003285815910000033
wherein, TijConductivity of the connecting unit in m3/d/MPa；
VRIs the reservoir volume in m3；
LijIs the link unit length in m;
kijis the average permeability of the connecting unit (i.j) in mD;
λijis the total fluid flow rate in mD (mPa. s)-1；
N is the total number of the connection units taking the i node as an end point.
7. The complex fracture network reservoir flow simulation method of claim 6,
the t time step in step 3 connects the upstream fluxes of the units (i.j)
Figure FDA0003285815910000034
Is given by equation (13), where node i is located upstream of node j:
Figure FDA0003285815910000035
wherein the content of the first and second substances,
Figure FDA0003285815910000041
connecting cell conductivity in m for two-phase flow3/d/MPa；
pi t+ΔtIs the pressure at the i node at time t + Δ t, in MPa;
Figure FDA0003285815910000042
is the pressure at the j node at time t + Δ t, in MPa;
after the upstream flux of the junction element is obtained, it is substituted into the material balance equation (2) in the control volume Vi of the grid i at time t, and the percolation transport equation can be solved to obtain the saturation distribution over the junction element, where formula (2) is as follows:
Figure FDA0003285815910000043
wherein, TijIs the conductivity of two adjacent grids, in mD (mPa. s)-1；
pi,pjThe pressure of the grids i and j is respectively, and the unit is MPa;
Ct,ifor mesh i is the overall compression factor, 1/MPa.
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CN114970127B (en) * 2022-05-17 2023-06-16 长江大学 Crack network point cloud generation method for numerical simulation of gridless oil reservoir

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