CN111472782A - Optimization method for shale reservoir exploitation - Google Patents

Optimization method for shale reservoir exploitation Download PDF

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CN111472782A
CN111472782A CN202010271156.9A CN202010271156A CN111472782A CN 111472782 A CN111472782 A CN 111472782A CN 202010271156 A CN202010271156 A CN 202010271156A CN 111472782 A CN111472782 A CN 111472782A
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gas
injection
water
phase
permeability
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夏阳
韦世明
金衍
林伯韬
向建华
魏林胜
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China University of Petroleum Beijing
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21C—MINING OR QUARRYING
    • E21C41/00—Methods of underground or surface mining; Layouts therefor
    • E21C41/16—Methods of underground mining; Layouts therefor
    • E21C41/24—Methods of underground mining; Layouts therefor for oil-bearing deposits
    • 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
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • 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
    • 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
    • E21B47/06—Measuring temperature or pressure
    • G—PHYSICS
    • G06—COMPUTING; CALCULATING OR COUNTING
    • G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
    • G06Q50/00—Systems or methods specially adapted for specific business sectors, e.g. utilities or tourism
    • G06Q50/02—Agriculture; Fishing; Mining

Abstract

The invention provides an optimization method for shale reservoir exploitation, and belongs to the technical field of oil and gas exploitation. The optimization method for shale reservoir exploitation comprises the following steps: setting at least two groups of injection and production parameters, wherein the injection and production parameters comprise injection time, injection amount and well closing time; determining the predicted yield corresponding to each group of injection-production parameters according to a pre-established flow model; and selecting injection-production parameters for production according to the comparison result of the predicted yield. Through the scheme provided by the invention, reasonable mining data guidance can be provided for actual mining of the shale reservoir.

Description

Optimization method for shale reservoir exploitation
Technical Field
The invention relates to the technical field of oil and gas exploitation, in particular to an optimization method for shale reservoir exploitation.
Background
Shale oil and gas become main exploration and customs objects in the present stage and a future period of time of the country, but due to the ultralow porosity and the ultralow permeability of a shale stratum, the flow resistance of the oil and gas is very large, and a conventional horizontal well cannot obtain industrial airflow, so that the yield increase is carried out by multistage hydraulic fracturing. A large amount of fracturing fluid is injected into a stratum in the hydraulic fracturing process, but the amount of water discharged in flowback after the fracturing is usually not more than 20% of the injection amount, and a phase permeation test shows that the saturation of the bound water of the shale is greater than the initial water saturation, so that a large part of the injected fracturing fluid becomes the bound water of the shale and cannot be discharged, and the undischarged water occupies a gas outflow channel, so that the phase permeation rate of oil gas is reduced, and the effect of the hydraulic fracturing is influenced.
At present, a lot of documents report that a shale matrix permeates and absorbs part of water to generate new microcracks inside the shale matrix, so that the absolute permeability of the matrix is improved, and the permeability can be improved to a certain extent.
The fracture initiation is a relatively rapid process, a large amount of fracturing fluid still needs to be pumped into the stratum after the hydraulic fracture is formed to keep the conductivity of the hydraulic fracture, the well is often closed for several days in order to enable the shale matrix to be subjected to imbibition to form micro-fractures, and in the process of pumping the fracturing fluid and closing the well, the discharge amount of the fracturing fluid and the well closing time are the most important factors for determining the yield after the hydraulic fracture is performed
The existing method can be used for hydraulic fracturing injection simulation of the shale reservoir and capacity prediction, but none of the methods can be used for hydraulic fracturing injection simulation optimization with the aim of maximizing production. The existing fracturing fluid injection simulation method has the following defects: the imbibition of the fracturing fluid after entering the formation cannot be quantitatively measured, and the simulation area size is influenced by human factors. The existing capacity prediction method has the defects that: only a single flow regime of the full simulation area can be considered, i.e. the simulation area is a two-phase flow or a single-phase flow, and because the irreducible water saturation of the shale is higher than the initial water saturation, the single-phase flow and the multi-phase flow exist in the stratum simultaneously in both the injection process and the production process.
Disclosure of Invention
It is an object of embodiments of the present invention to provide an optimization method for shale reservoir production that addresses one or more of the above technical problems.
In order to achieve the above object, an embodiment of the present invention provides an optimization method for shale reservoir exploitation, including: setting at least two groups of injection and production parameters, wherein the injection and production parameters comprise injection time, injection amount and well closing time; determining the predicted yield corresponding to each group of injection-production parameters according to a pre-established flow model; and selecting injection-production parameters for production according to the comparison result of the predicted yield.
Optionally, the pre-calculated yield corresponding to each group of injection-production parameters is determined according to a pre-established flow model: determining boundary conditions according to the development stage and the injection-production parameters; and determining the predicted yield corresponding to the injection-production parameters according to the boundary conditions and the flow model, wherein the development phase comprises a liquid injection phase, a well closing phase and a production phase.
Optionally, the determining the boundary condition according to the development stage and the injection-production parameter includes: when in the liquid injection stage, the boundary conditions are as follows: q. q.sw＝Qw(ii) a When in the well-closing stage, the boundary conditions are as follows: q. q.sw0; and when in the production phase, the boundary conditions are: p is a radical ofwBHP where q iswIs the amount of water injected per unit volume of rock, QwFor injection of fracturing fluids, pwBHP is the water phase pressure and BHP is the bottom hole pressure.
Optionally, the flow model is predicted by the following formula when exploiting shale gasFirstly, establishing:
Figure BDA0002443202220000021
Figure BDA0002443202220000031
where φ is the formation porosity, SwWater saturation), M is the gas molar mass, z is the gas deviation factor, R is the gas constant, T is the formation temperature, ρgaIs the gas density, p, under standard conditionssIs shale density, VLIs L angmuir volume constant, pLL angmuir pressure, pgIs the gas pressure, pwAs fracturing fluid density, pwPressure of the aqueous phase, KmAs the permeability of the matrix, ctwIs the total compression factor of water, rhogIs the gas density, qwIs the amount of water injected per unit volume of rock, KfIn order to determine the permeability of the crack,
Figure BDA0002443202220000032
is a gas phase conductance factor, λwIs the water phase flow conductivity coefficient,
Figure BDA0002443202220000033
optionally, when exploiting the shale oil deposit, the flow model is pre-established by the following formula:
Figure BDA0002443202220000034
Figure BDA0002443202220000035
where ρ isoIs the oil density, ctoIs the total compression factor of the oil, SwIs the water saturation, phi is the formation porosity, rhowAs fracturing fluid density, ctwIs the total compression factor of water, pwPressure of the aqueous phase, KmAs the permeability of the matrix, lambdaoIs the oil phase conductivity coefficient, rhogIs the gas density, pcIs the capillary force of oil and water phases, lambdawIs the water phase conductivity coefficient, qwIs a unit volumeAmount of water injected into the rock, KfIn order to determine the permeability of the crack,
Figure BDA0002443202220000036
optionally, the aqueous phase conductivity is determined by the following formula: lambda [ alpha ]w＝krw/μwWherein λ iswIs the water phase conductivity coefficient, muwViscosity of fracturing fluid, krwRelative water permeability.
Optionally, the water relative permeability is determined by the following formula:
Figure BDA0002443202220000037
wherein k isrwIs the relative permeability of water, SwIs the water saturation, SwcTo irreducible water saturation.
Optionally, the gas phase conductivity is determined by the following formula:
Figure BDA0002443202220000041
wherein the content of the first and second substances,
Figure BDA0002443202220000042
is the gas-phase conductivity coefficient,
Figure BDA0002443202220000043
is the apparent relative permeability of the gas, mugIs the gas viscosity.
Optionally, the gas apparent relative permeability is determined by the following equation:
Figure BDA0002443202220000044
wherein the content of the first and second substances,
Figure BDA0002443202220000045
as apparent relative permeability of gas, krgPhi is the relative gas permeability, phi is the formation porosity, mugIs gas viscosity, DkIs Knudsen diffusion coefficient, KmAs the permeability of the matrix, pgIs the gas pressure.
OptionallyThe gas relative permeability is determined by the following formula:
Figure BDA0002443202220000046
wherein k isrgIs the relative permeability of gas, SwIs the water saturation, SwcTo irreducible water saturation.
By the technical scheme, the optimization method for shale reservoir exploitation is provided, and reasonable exploitation data guidance can be provided for actual exploitation of the shale reservoir.
The technical scheme provided by the invention can also solve the following difficulties in the injection and productivity prediction of the shale oil-gas multistage horizontal fracturing well:
single-phase flow and multi-phase flow occur in the stratum due to the unique phase permeability property of the shale, and the existing model cannot completely describe the fluid flow in the injection and production processes, so that the injection optimization aiming at maximizing the productivity cannot be realized;
in the existing scheme, the influence of imbibition cannot be considered in numerical simulation, and the imbibition process is accompanied with the hydration of clay minerals, so that the influence of the two is difficult to specifically characterize;
the fractured shale stratum forms multi-scale discrete hydraulic fractures, and the existing scheme cannot solve the flow problem of two-phase fluid in a discrete fracture network.
Additional features and advantages of embodiments of the present invention will be described in detail in the detailed description which follows.
Drawings
The accompanying drawings, which are included to provide a further understanding of the embodiments of the invention and are incorporated in and constitute a part of this specification, illustrate embodiments of the invention and together with the description serve to explain the embodiments of the invention without limiting the embodiments of the invention. In the drawings:
FIG. 1 is a schematic flow chart diagram of an optimization method for shale reservoir production provided by an embodiment of the invention;
FIG. 2 is a bottom hole flow pressure profile for a well;
FIG. 3 is a plot of gas production fit versus prediction for a wellbore interval;
FIG. 4 is a predicted gas production curve for a shale reservoir.
Detailed Description
The following detailed description of embodiments of the invention refers to the accompanying drawings. It should be understood that the detailed description and specific examples, while indicating embodiments of the invention, are given by way of illustration and explanation only, not limitation.
Fig. 1 is a schematic flow chart of an optimization method for shale reservoir production according to an embodiment of the present invention. As shown in fig. 1, the optimization method for shale reservoir production includes steps S120 to S160.
In step S120, at least two sets of injection-production parameters are set.
For shale reservoir exploitation, the exploitation mode is limited, and the injection time, the injection amount and the well closing time in the injection and exploitation parameters are the factors which have the greatest influence on the yield after hydraulic fracturing, so that efficient exploitation of the shale reservoir can be realized only by selecting proper injection and exploitation parameters. On the basis, at least two groups of injection and production parameters can be preset so as to be convenient for optimizing shale reservoir exploitation subsequently.
Optionally, under the condition that related shale reservoir exploitation experience exists, the related injection-production parameters can be adjusted according to the related injection-production parameters, so that the optimal injection-production parameters can be selected more quickly.
Or the selection of the injection-production parameters can be optimized by the following method: under the condition that the injection-production parameters are selected and the predicted yield corresponding to the group of injection-production parameters is determined through the scheme provided by the invention, the group of injection-production parameters can be adjusted in a targeted manner. For example, a set of injection-production parameters of big data and a set of injection-production parameters of small data may be preset, and injection-production parameters may be adjusted by bisection to obtain a new set of injection-production parameters, and the like.
In step S140, the predicted production rate corresponding to each set of injection-production parameters is determined according to the pre-established flow model.
For the shale reservoir, the stored energy sources comprise shale gas and shale oil reservoirs, and the geological environments of the shale gas and the shale oil reservoirs are different, so that flow models can be respectively established for the shale gas and the shale oil reservoirs to improve the reliability of the optimization result.
In the process of determining the predicted yield corresponding to the injection-production parameters by using the flow model, boundary conditions need to be determined according to the development stage and the injection-production parameters, and then the predicted yield corresponding to the injection-production parameters is determined according to the set boundary conditions and the flow model.
The boundary conditions need to be set for the three processes of the injection phase, the well-closing phase and the production phase respectively, the boundary conditions are set at the bottom of the well, and the boundary conditions are set to be different types along with the time (for example, a flow boundary, namely a pressure gradient boundary, is given for the injection phase and the well-closing phase, and a pressure boundary condition is given for the production process).
Optionally, the boundary condition may be specifically as follows:
when in the liquid injection stage, the boundary conditions are as follows: q. q.sw＝Qw；
When in the well-closing stage, the boundary conditions are as follows: q. q.sw0; and
when in the production phase, the boundary conditions are as follows: p is a radical ofw＝BHP，
Wherein q iswIs the amount of water injected per unit volume of rock, QwFor injection of fracturing fluids, pwBHP is the bottom hole pressure.
For bottom hole pressure, it can be set to a constant or it can be time-varying data obtained from production tests, e.g. at t>tclose+tinjectionWhen is, pwBHP, where tcloseTime of closing the well, tinjectionThe injection time is shown.
In the subsequent optimization process, the gas production rate for the same long time can be calculated under the same BHP, and the optimal injection parameters are selected according to the maximum gas production rate.
In step S160, based on the comparison of the predicted production volumes, the production-injection parameters for production are selected.
And under the condition that the conditions allow, determining the optimal injection-production parameters according to the comparison result between the predicted yields corresponding to the injection-production parameter groups as many as possible.
The technical scheme provided by the embodiment of the invention provides an optimization method for shale reservoir exploitation, and can provide reasonable exploitation data guidance for actual exploitation of shale reservoirs.
For exploiting shale gas in shale reservoirs, a flow model may be pre-established by the following two formulas provided by embodiments of the present invention.
(1) For shale gas reservoirs, the multiphase flow in the formation is gas-water two-phase flow, so the adaptive flow control equation in the pores of the shale matrix is as follows:
Figure BDA0002443202220000071
(2) since the width of a fracture in a shale reservoir is much smaller than its length, the flow velocity at the fracture cross section is considered equal everywhere, so the flow control equation within a discrete fracture is:
Figure BDA0002443202220000072
where φ is the formation porosity, SwWater saturation), M is the gas molar mass, z is the gas deviation factor, R is the gas constant, T is the formation temperature, ρgaIs the gas density, p, under standard conditionssIs shale density, VLIs L angmuir volume constant, pLL angmuir pressure, pgIs gas pressure, pwAs fracturing fluid density, pwPressure of the aqueous phase, KmAs the permeability of the matrix, ctwIs the total compression factor of water, rhogIs the gas density, qwIs the amount of water injected per unit volume of rock, KfIn order to determine the permeability of the crack,
Figure BDA0002443202220000081
is a gas phase flow guide systemNumber, lambdawIs the water phase flow conductivity coefficient,
Figure BDA0002443202220000082
Figure BDA0002443202220000083
and
Figure BDA0002443202220000084
respectively, first derivative with respect to time.
For exploiting a shale oil reservoir in a shale reservoir, a flow model can be established in advance through the following two formulas provided by the embodiment of the invention.
(3) For shale oil deposit, the multiphase flow in the stratum is oil-water two-phase flow, and the self-adaptive flow control equation in the shale matrix gap is as follows:
Figure BDA0002443202220000085
(4) the flow control equation within a discrete fracture is:
Figure BDA0002443202220000086
where ρ isoIs the oil density, ctoIs the total compression factor of the oil, SwIs the water saturation, phi is the formation porosity, rhowAs fracturing fluid density, ctwIs the total compression factor of water, pwPressure of the aqueous phase, KmAs the permeability of the matrix, λoIs the oil phase conductivity coefficient, rhogIs the gas density, pcIs the capillary force of oil and water phases, lambdawIs the water phase conductivity coefficient, qwIs the amount of water injected per unit volume of rock, KfIn order to determine the permeability of the crack,
Figure BDA0002443202220000087
the fracturing progression of the shale oil-gas multi-stage fracturing horizontal well at present can often reach more than 20 grades, single-stage or several-stage simultaneous fracturing is often performed in the fracturing process, the fractured section is plugged after fracturing is completed, and then fracturing of the non-fractured section is performed, so the injection scheme and the sealing time of each section are often different, the construction effect can be seen only after the fracturing of the whole well is completed in actual construction, and the relation between injection and capacity of each section cannot be accurately analyzed.
For the above formula provided by the present invention, the parameters involved in the formula can be determined by experiment, can be obtained from field data, and can also be obtained by the existing calculation method. For example, porosity, a phase permeability function measured by a phase permeability test, a capillary force function measured by a mercury flooding test, a relation between a permeability of a matrix and water saturation measured by a imbibition test, and initial formation pressure and water saturation can be obtained from oilfield field data.
Optionally, the conductivity factor lambda for the aqueous phasewIn other words, it can be determined by the following formula: lambda [ alpha ]w＝krw/μw，μwViscosity of fracturing fluid, krwRelative water permeability.
Optionally, for gas phase conductivity
Figure BDA0002443202220000091
In other words, it can be determined by the following formula:
Figure BDA0002443202220000092
Figure BDA0002443202220000093
is the apparent relative permeability of the gas, mugIs the gas viscosity.
Wherein the gas apparent relative permeability
Figure BDA0002443202220000094
Can also be used for treatingIs determined by the following equation:
Figure BDA0002443202220000095
krgphi is the relative gas permeability, phi is the formation porosity, mugIs gas viscosity, DkIs Knudsen diffusion coefficient, KmAs the permeability of the matrix, pgIs the gas pressure.
Some of the parameters related to the above formula may be measured through experiments, and another part may be obtained through calculation, and the method for obtaining the parameters related to the above formula may be any existing method.
It is contemplated that a two-phase flow zone may be formed near the well and a single-phase oil or gas flow may be formed away from the well due to the invasion of the fracturing fluid. During production, the pressure of the single-phase flow area is higher than that of the two-phase flow area, and the single-phase flow area does not contain water (only oil or gas), so that water cannot flow from the single-phase flow area to the two-phase flow area, and therefore the flow direction must be considered when solving the formula in the flow model.
On this basis, in order to solve the above technical problem and enable the pre-established flow model to automatically adapt to two-phase flow and single-phase flow in the simulation process, the embodiment of the present invention provides a scheme for describing a phase-permeation curve by using a piecewise function, which can realize the adaptability of the flow model to different flow states in principle.
Relative permeability to water krwIn a word:
Figure BDA0002443202220000101
Swis the water saturation, SwcIrreducible water saturation, i.e., inability to flow when the water saturation is less than the irreducible water saturation;
relative permeability to gas krgIn a word:
Figure BDA0002443202220000102
Swis the water saturation, SwcTo irreducible water saturation.
The technical scheme provided by the embodiment of the invention can establish the self-adaptive flow model in the shale fracturing and production processes, solves the mathematical characterization that multi-phase flow and single-phase flow exist simultaneously in the injection and production processes, can effectively solve the problem of water flow direction, and realizes the solution of the self-adaptive flow model.
Wherein, under the condition that the water saturation is greater than the irreducible water saturation, the relation between the water saturation and the water relative permeability or the gas relative permeability in the formula can be directly determined by the existing calculation method, and can also be directly obtained by fitting after the phase permeability test.
Optionally, the embodiment of the present invention further provides a method for determining the water phase permeability and the gas phase permeability obtained by fitting the phase permeation experimental data, which is respectively as follows:
Figure BDA0002443202220000103
considering that many experiments are carried out for the imbibition research of fracturing fluid at present, but quantitative characterization is not carried out in numerical simulation, the embodiment of the invention also provides a method for processing the imbibition experimental data of the shale rock core to obtain an experimental relation curve of rock core water saturation and permeability, and then fitting to obtain the relation between the rock core absolute permeability and sweat saturation, so that the quantitative characterization of imbibition can be realized, and the expression can be Km＝Km(Sw) Wherein, K ismAs the permeability of the matrix, SwThe water saturation.
Optionally, the embodiment of the present invention further provides a relation between the permeability of the core matrix and the change of the water saturation, which is obtained by fitting the imbibition experimental data:
Figure BDA0002443202220000104
Kdrypermeability of the dry core.
For shale reservoirs, shale stratum has high shale content, matrix hydration can occur to cause matrix permeability reduction if the permeability is weak and micro cracks do not occur, the core matrix permeability reaction obtained by the permeability experimental data is the comprehensive influence of the permeability and the hydration, and the well closing time optimization in the liquid injection process can be realized based on the comprehensive influence.
The technical solution provided by the embodiment of the present invention will be explained in detail by using a specific embodiment. In this embodiment, the optimization of shale reservoir production may be achieved by:
(1) obtaining the porosity and permeability of the research area through a pore permeation experiment;
(2) obtaining a phase permeation curve of a research area through a phase permeation experiment;
(3) obtaining a capillary force curve of a research area through a mercury injection experiment;
(4) obtaining the relation between the absolute permeability and the water saturation of the shale matrix through a imbibition experiment;
(5) obtaining a hydraulic fracture network through a site fracturing construction report;
(6) carrying out multi-group injection-production numerical simulation by using the calculation program in the invention to obtain corresponding productivity;
(7) and obtaining the optimal liquid injection measures (liquid injection displacement, liquid injection time and well closing time) according to the maximum productivity.
According to the technical scheme provided by the embodiment of the invention, the field production data is sorted, the well bottom pressure is given, the fitting of the production data can be realized, and then the production prediction can be carried out. For example, as shown in fig. 2 and 3, fig. 2 is a bottom hole flow pressure variation curve of a well, and fig. 3 is a gas production rate fitting and prediction curve of a well section. Based on fig. 3, it can be determined that the flow model provided by the embodiment of the invention can be well applied to shale reservoirs, and the predicted gas production is basically consistent with the actual on-site gas production.
In the embodiment, three groups of injection-production parameters are set, namely 1) injecting liquid at 7L/min for 60min and then closing the well for 1 day, 2) injecting liquid at 6L/min for 70min and then closing the well for 18h, and 3) injecting liquid at 5L/min for 84min and then closing the well for 15 h.
After the flow model provided by the embodiment of the invention is adopted to calculate the predicted yield, the yield change curve shown in figure 4 can be obtained. As can be seen from fig. 4, after one hundred days of estimated production, the gas production rates of case 2 and case 3 are close, while the gas production rate of case 1 is greater than those of case 2 and case 3, and thus it can be determined that case 1 is more preferable.
It should also be noted that the terms "comprises," "comprising," or any other variation thereof, are intended to cover a non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements but may include other elements not expressly listed or inherent to such process, method, article, or apparatus. Without further limitation, an element defined by the phrase "comprising an … …" does not exclude the presence of other identical elements in the process, method, article, or apparatus that comprises the element.
The above are merely examples of the present application and are not intended to limit the present application. Various modifications and changes may occur to those skilled in the art. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application should be included in the scope of the claims of the present application.

Claims (10)

1. An optimization method for shale reservoir production, the method comprising:
setting at least two groups of injection and production parameters, wherein the injection and production parameters comprise injection time, injection amount and well closing time;
determining the predicted yield corresponding to each group of injection-production parameters according to a pre-established flow model; and
and selecting injection-production parameters for production according to the comparison result of the predicted yield.
2. The method of claim 1, wherein determining the projected production for each set of the voidage replacement parameters based on a pre-established flow model comprises:
determining boundary conditions according to the development stage and the injection-production parameters; and
determining the predicted yield corresponding to the injection-production parameters according to the boundary conditions and the flow model,
wherein the development phase comprises a liquid injection phase, a well closing phase and a production phase.
3. The method of claim 2, wherein determining boundary conditions based on the development phase and the voidage replacement parameters comprises:
when in the liquid injection stage, the boundary conditions are as follows: q. q.sw＝Qw；
When in the well-closing stage, the boundary conditions are as follows: q. q.sw0; and
when in the production phase, the boundary conditions are as follows: p is a radical ofw＝BHP，
Wherein q iswIs the amount of water injected per unit volume of rock, QwFor injection of fracturing fluids, pwBHP is the water phase pressure and BHP is the bottom hole pressure.
4. The method of claim 1, wherein the flow model is pre-established by the following equation when exploiting shale gas:
Figure FDA0002443202210000021
Figure FDA0002443202210000022
where φ is the formation porosity, SwWater saturation), M is the gas molar mass, z is the gas deviation factor, R is the gas constant, T is the formation temperature, ρgaIs the gas density, p, under standard conditionssIs shale density, VLIs L angmuir volume constant, pLL angmuir pressure, pgIs the gas pressure, pwDensity of fracturing fluid，pwPressure of the aqueous phase, KmAs the permeability of the matrix, ctwIs the total compression factor of water, rhogIs the gas density, qwIs the amount of water injected per unit volume of rock, KfIn order to determine the permeability of the crack,
Figure FDA0002443202210000023
is the gas phase conductivity, lambdawIs the water phase flow conductivity coefficient,
Figure FDA0002443202210000024
5. the method of claim 1, wherein the flow model is pre-established when exploiting a shale reservoir by the following equation:
Figure FDA0002443202210000025
Figure FDA0002443202210000026
where ρ isoIs the oil density, ctoIs the total compression factor of the oil, SwIs the water saturation, phi is the formation porosity, rhowAs fracturing fluid density, ctwIs the total compression factor of water, pwPressure of the aqueous phase, KmIs the permeability of the matrix, lambdaoIs the oil phase conductivity coefficient, rhogIs the gas density, pcIs the capillary force of oil and water phases, lambdawIs the water phase conductivity coefficient, qwIs the amount of water injected per unit volume of rock, KfIn order to determine the permeability of the crack,
Figure FDA0002443202210000031
6. the method according to claim 4 or 5, wherein the water phase conductivity is determined by the following formula:
λw＝krw/μw，
wherein λ iswIs the water phase conductivity coefficient, muwViscosity of fracturing fluid, krwRelative water permeability.
7. The method of claim 6, wherein the water relative permeability is determined by the formula:
Figure FDA0002443202210000032
wherein k isrwIs the relative permeability of water, SwIs the water saturation, SwcTo irreducible water saturation.
8. The method of claim 4, wherein the gas phase conductivity is determined by the formula:
Figure FDA0002443202210000033
wherein the content of the first and second substances,
Figure FDA0002443202210000034
is the gas-phase conductivity coefficient,
Figure FDA0002443202210000035
is the apparent relative permeability of the gas, mugIs the gas viscosity.
9. The method of claim 8, wherein the apparent relative permeability of the gas is determined by the formula:
Figure FDA0002443202210000036
wherein the content of the first and second substances,
Figure FDA0002443202210000037
as apparent relative permeability of gas, krgPhi is the relative gas permeability, phi is the formation porosity, mugIs gas viscosity, DkIs Knudsen diffusion coefficient, KmAs the permeability of the matrix, pgIs the gas pressure.
10. The method of claim 9, wherein the gas relative permeability is determined by the formula:
Figure FDA0002443202210000041
wherein k isrgIs the relative permeability of gas, SwIs the water saturation, SwcTo irreducible water saturation.
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