CN108798654B - Method and device for determining corresponding relation between bottom hole pressure and time of shale gas well - Google Patents

Method and device for determining corresponding relation between bottom hole pressure and time of shale gas well Download PDF

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CN108798654B
CN108798654B CN201810389715.9A CN201810389715A CN108798654B CN 108798654 B CN108798654 B CN 108798654B CN 201810389715 A CN201810389715 A CN 201810389715A CN 108798654 B CN108798654 B CN 108798654B
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pressure
bottom hole
fracture
formation
permeability
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CN108798654A (en
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贾爱林
王军磊
位云生
齐亚东
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Petrochina Co Ltd
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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
    • E21B47/00—Survey of boreholes or wells

Abstract

The embodiment of the application discloses a method and a device for determining the corresponding relation between the bottom hole pressure and the time of a shale gas well. The method comprises the following steps: determining a first incidence relation between a second fracture permeability and bottom hole pressure corresponding to the target gas well based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure; determining a second incidence relation between the yield of the target gas well and the bottom hole pressure, the first fracture permeability and the production time of the target gas well based on the formation permeability, the formation porosity, the formation thickness and the fracture attribute data; and determining the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time according to the first correlation and the second correlation. According to the technical scheme provided by the embodiment of the application, the final recoverable reserves of the shale gas well can be improved.

Description

Method and device for determining corresponding relation between bottom hole pressure and time of shale gas well
Technical Field
The application relates to the technical field of natural gas development, in particular to a method and a device for determining a corresponding relation between bottom hole pressure and time of a shale gas well.
Background
With the continuous development of shale gas, how to efficiently manage gas wells to obtain higher development benefits under the condition that drilling and fracturing technologies are gradually mature becomes one of the core problems concerned by various large oil and gas companies. The corresponding relation between the bottom hole pressure of the gas well and the time is generally called a gas well production system and is also called a working system, the corresponding relation is an important means in daily production management of the gas well, a reasonable production system can not only ensure that higher gas well productivity is maintained, but also obtain higher long-term income, and a simulation result shows that the internal income rate can be increased by 4% when the final accumulated yield of the gas well is increased by 20%.
Horizontal well drilling and volume fracturing are the main technical means for shale gas development. The pressed shale reservoir forms complex fracture networks which obtain higher conductivity by pumping a large amount of propping agents and form an artificial gas reservoir with a multi-scale seepage space together with the lamellar shale reservoir. In the production process of a gas well, the effective stress is gradually increased due to stratum pressure failure caused by continuous gas production, and the propping agents in the seepage space are extruded to generate embedding, crushing, dissolving and other phenomena in different degrees. Meanwhile, the special layered reservoir structure of the shale also enables the flow channel to be easy to deform, so that the permeability of the flow channel is obviously reduced. Therefore, how to alleviate the reduction of the seepage capability of the artificial gas reservoir becomes a prominent problem in shale gas well development management work.
The optimal production allocation scheme of the shale gas well at present lacks scientific and reasonable technical support for a long time, only a semi-empirical pressure control scheme that the production allocation with a few parts of flow without resistance is adopted at the initial stage and the annual reduction rate is controlled to be 40-50% after the shale gas well is put into operation for 1-1.5 years can be used, the scheme needs enough production dynamic data support and complicated summary analysis, lacks development theoretical support, is only suitable for blocks with similar geological engineering backgrounds, and does not have popularization and application values. Efficient development of shale gas urgently requires a scientific and reasonable optimization method of a gas well production system to improve the final recoverable reserves of shale gas wells.
Disclosure of Invention
The embodiment of the application aims to provide a method and a device for determining the corresponding relation between the bottom hole pressure of a shale gas well and time, so as to improve the final recoverable reserve of the shale gas well.
In order to solve the technical problem, the method and the device for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time provided by the embodiment of the application are realized as follows:
the method for determining the corresponding relation between the bottom hole pressure of the shale gas well and time provides stratum attribute data, fracture attribute data and rock mechanics data of a target reservoir in a target work area; wherein the target work area comprises a target gas well which is drilled in the target reservoir; the fracture attribute data is used for characterizing physical properties of the fracture; the formation attribute data comprises first fracture permeability, formation porosity, formation thickness and original formation pressure; the first fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the virgin formation pressure; the method comprises the following steps:
determining a first incidence relation between a second fracture permeability corresponding to the target gas well and bottom hole pressure based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure;
determining a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, the production time of the target gas well based on the formation permeability, the formation porosity, and the formation thickness, and the fracture property data;
and determining the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time according to the first and second incidence relations.
In a preferred scheme, the method is also provided with the common coefficient of rocks in the target reservoir; wherein the ordinary coefficient is used for representing the hardness of the rock; determining a first correlation between a second fracture permeability corresponding to the target gas well and a bottom hole pressure, comprising:
determining an incidence relation between a second fracture permeability and a permeability stress-sensitive parameter corresponding to the target gas well based on a pyworth coefficient and a poisson ratio in the rock mechanics data and the first fracture permeability;
determining a correlation between the permeability stress-sensitive parameter and the bottom hole pressure based on a generalized coefficient of the rock;
and determining the first incidence relation according to the incidence relation between the second fracture permeability and the permeability stress sensitive parameter and the incidence relation between the permeability stress sensitive parameter and the bottom hole pressure.
In a preferred scheme, the incidence relation between the second fracture permeability and the permeability stress sensitivity parameter corresponding to the target gas well is determined by adopting the following formula:
Figure BDA0001643123730000021
Δp＝pi-pw
wherein, Kf(pw) And Kf(pi) Representing the second fracture permeability and the first fracture permeability, respectively; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; α and υ represent the pyworth coefficient and the poisson ratio, respectively; η (Δ p) represents the permeability stress sensitivity parameter; Δ p represents the pressure differential resulting from subtracting the bottom hole pressure from the virgin formation pressure; wherein the permeability stress sensitive parameter is associated with the pressure difference.
In a preferred embodiment, when the ordinary coefficient of the rock is greater than or equal to a specified ordinary coefficient threshold, the correlation between the permeability stress-sensitive parameter and the bottom hole pressure is determined by using the following formula:
η(Δp)＝AΔp+B
Δp＝pi-pw
wherein η (Δ ρ) represents the permeability stress sensitivity parameter; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; Δ p represents the pressure differential resulting from subtracting the bottom hole pressure from the virgin formation pressure; a and B are constants;
when the normal coefficient of the rock is less than the specified normal coefficient threshold, determining the correlation between the permeability stress-sensitive parameter and the bottom hole pressure using the following formula:
η(Δp)＝C
wherein C is a constant.
In a preferred embodiment, the method further provides gas property data of the reservoir of interest at the virgin formation pressure; wherein the gas property data is used to characterize physical characteristics of the gas in the reservoir of interest; determining a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, the production time of the target gas well, comprising:
determining a correlation between the production of the target gas well and a pseudo-pressure differential, a pseudo-time, the first fracture permeability based on the formation permeability, the formation porosity, the formation thickness, a fracture width and a fracture half-length in the fracture property data, and the gas property data; wherein the pseudo-pressure difference represents a difference between a pseudo-pressure corresponding to the virgin formation pressure and a pseudo-pressure corresponding to the bottom hole pressure;
determining an association between the pseudo-time and the production time based on the gas property data, the original formation pressure and an average formation pressure corresponding to the target gas well;
respectively determining the correlation between the pseudo pressure corresponding to the original formation pressure and the correlation between the pseudo pressure corresponding to the bottom hole pressure and the bottom hole pressure based on the gas attribute data and the original formation pressure;
and determining the second association relationship according to the association relationship between the yield of the target gas well and the pseudo-pressure difference, the pseudo-time, the first fracture permeability, the association relationship between the pseudo-time and the production time, the association relationship between the pseudo-pressure corresponding to the original formation pressure and the association relationship between the pseudo-pressure corresponding to the bottom hole pressure and the bottom hole pressure.
Preferably, the correlation between the yield of the target gas well and the pseudo pressure difference, the pseudo time and the first fracture permeability is determined by the following formula:
Figure BDA0001643123730000041
Figure BDA0001643123730000042
wherein q represents the yield of the target gas well; m (p)i)-m(pw) Representing said pseudo-pressure difference, m (p)i) And m (p)w) Respectively representing a pseudo pressure corresponding to the original formation pressure and a pseudo pressure corresponding to the bottom hole pressure; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; n issRepresenting the number of fracture sections after the staged fracturing treatment of the target gas well, nfRepresenting the number of fractures, w, within one of said fracture zonesfAnd xfRespectively representing the fracture width and the fracture half-length in the fracture attribute data; kf(pi) Representing the first fracture permeability; kmRepresents the formation permeability, h represents the formation thickness, phimRepresenting the formation porosity, ηmiRepresenting a formation diffusion coefficient of the reservoir of interest at the virgin formation pressure; b isgi、μgiAnd cgiRespectively representing a gas volume coefficient, a gas viscosity and a gas compression coefficient in the gas attribute data; t is taRepresenting the pseudo-time.
Preferably, the correlation between the pseudo-time and the production time is determined by the following formula:
Figure BDA0001643123730000043
wherein, taRepresenting the pseudo-time; mu.sgiRepresenting the viscosity of the gas in said gas property data,
Figure BDA0001643123730000044
represents the corrected gas compressibility, p, at the virgin formation pressureiTo representThe virgin formation pressure, μg[pavg(τ)]Representing the gas viscosity at the average formation pressure corresponding to the target gas well,
Figure BDA0001643123730000045
represents a corrected gas compressibility, p, at a corresponding average formation pressure for the target gas wellavg(τ) represents an average formation pressure corresponding to the target gas well, the average formation pressure being associated with the production time; τ denotes the time variable to be integrated and t denotes the production time.
In a preferred embodiment, the bottom hole pressure is related to a pseudo pressure corresponding to the bottom hole pressure by the following formula:
Figure BDA0001643123730000051
wherein, m (p)w) Respectively representing the pseudo pressure corresponding to the bottom hole pressure; mu.sgiRepresenting the viscosity of the gas in said gas property data,
Figure BDA0001643123730000052
represents the corrected gas deviation coefficient, p, at the virgin formation pressureiRepresenting the original formation pressure, ξ representing the pressure variable to be integrated, μg(xi) represents the corrected gas viscosity at a bottom hole pressure of pressure value xi,
Figure BDA0001643123730000053
indicating the corrected gas deviation coefficient, p, at a bottom hole pressure of value xiscDenotes the standard atmospheric pressure, pwRepresenting the bottom hole pressure.
In a preferred embodiment, determining the corresponding relationship between the bottom hole pressure and the production time corresponding to the target gas well includes:
determining an incidence relation between the yield of the target gas well, the bottom hole pressure and the production time according to the first incidence relation and the second incidence relation;
respectively determining a plurality of relation curves of the specified production time corresponding to the yield and the bottom hole pressure of the plurality of target gas wells according to the incidence relation among the yield of the target gas well, the bottom hole pressure and the production time, and determining the target bottom hole pressure corresponding to the maximum value point in each relation curve; wherein the specified production time corresponds to the relationship curve one to one;
and fitting the specified production time and the target bottom hole pressure to obtain the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time.
The device comprises a device for determining the corresponding relation between the bottom hole pressure of the shale gas well and time, wherein the device provides stratum attribute data, fracture attribute data and rock mechanics data of a target reservoir in a target work area; wherein the target work area comprises a target gas well which is drilled in the target reservoir; the fracture attribute data is used for characterizing physical properties of the fracture; the formation attribute data comprises first fracture permeability, formation porosity, formation thickness and original formation pressure; the first fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the virgin formation pressure; the device comprises: the system comprises a first incidence relation determining module, a second incidence relation determining module and a target corresponding relation determining module; wherein the content of the first and second substances,
the first incidence relation determining module is used for determining a first incidence relation between second fracture permeability and bottom hole pressure corresponding to the target gas well based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure;
the second incidence relation determination module is used for determining a second incidence relation between the yield of the target gas well and the bottom hole pressure, the first fracture permeability and the production time of the target gas well based on the formation permeability, the formation porosity and the formation thickness and the fracture attribute data;
and the target corresponding relation determining module is used for determining the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time according to the first associated relation and the second associated relation.
As can be seen from the above technical solutions provided by the embodiments of the present application, the method and the apparatus for determining the correspondence between the bottom-hole pressure and the time of a shale gas well provided by the embodiments of the present application may determine, based on the rock mechanics data and the first fracture permeability, a first correlation between a second fracture permeability and the bottom-hole pressure corresponding to the target gas well, and may also determine, based on the formation permeability, the formation porosity, the formation thickness, and the fracture property data, a second correlation between the production of the target gas well and the bottom-hole pressure, the first fracture permeability, and the production time of the target gas well; finally, the corresponding relation between the bottom hole pressure and the production time corresponding to the target gas well can be determined according to the first correlation and the second correlation. Therefore, according to the method, various stratum attribute data, rock mechanics data and fracture attribute data of the shale gas reservoir can be combined, a set of scientific and reasonable gas well production system optimization scheme is established, the optimal corresponding relation between the bottom hole pressure and the production time is obtained, and the final recoverable reserve of the shale gas well can be improved.
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In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the drawings needed to be used in the description of the embodiments or the prior art will be briefly introduced below, it is obvious that the drawings in the following description are only some embodiments described in the present application, and for those skilled in the art, other drawings can be obtained according to the drawings without any creative effort.
FIG. 1 is a flow chart of an embodiment of a method of determining a bottom hole pressure versus time relationship for a shale gas well according to the present application;
FIG. 2 is a schematic diagram of a physical model of a multi-stage volumetric fractured horizontal well in an embodiment of the present application;
FIG. 3 is a schematic illustration of a gas flow model in a single fracture in an embodiment of the present application;
FIG. 4 is a graphical representation of a relationship between production and bottom hole pressure for the target gas well for different production times in an embodiment of the present application;
FIG. 5 is a schematic illustration of three production regimes selected in a graphical representation of the relationship between production and bottom hole pressure for the target gas well at different production times of FIG. 4, in an embodiment of the present application;
FIG. 6 is a schematic of the cumulative production from a single well for three production regimes, respectively, in an example of the present application;
FIG. 7 is a schematic representation of the variation of the bottom hole pressure, formation pore pressure, total in situ stress, and effective stress of a gas well under two production regimes in an embodiment of the present application;
FIG. 8 is a block diagram illustrating the components of one embodiment of the present apparatus for determining bottom hole pressure versus time for a shale gas well;
FIG. 9 is a block diagram illustrating the composition of another embodiment of the apparatus for determining bottom hole pressure versus time for a shale gas well.
Detailed Description
The embodiment of the application provides a method and a device for determining the corresponding relation between the bottom hole pressure of a shale gas well and time.
In order to make those skilled in the art better understand the technical solutions in the present application, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application, and it is obvious that the described embodiments are only a part of the embodiments of the present application, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present application.
The embodiment of the application provides a method for determining the corresponding relation between the bottom hole pressure of a shale gas well and time. The method for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time can provide stratum attribute data, fracture attribute data and rock mechanics data of a target reservoir in a target work area; wherein the target work area comprises a target gas well which is drilled in the target reservoir; the fracture attribute data is used for characterizing physical properties of the fracture; the formation attribute data comprises first fracture permeability, formation porosity, formation thickness and original formation pressure; the first fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the virgin formation pressure. Moreover, the method for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time can also be provided with gas property data under the original formation pressure; wherein the gas property data is used to characterize physical properties of the gas in the reservoir of interest.
In this embodiment, the target work area may be a work area yet to be developed or being developed. For example, the Sichuan basin shale gas production zone. The work area comprises a shale gas reservoir, namely the target reservoir. The work area also includes a target gas well that encounters the reservoir of interest. The target gas well may refer to a well that has been drilled in the reservoir of interest.
In this embodiment, the formation property data, the fracture property data, the rock mechanics data, and the gas property data at the original formation pressure of the target reservoir may be obtained by a method of a mine field test and a test. The data have certain influence on optimizing the corresponding relation between the bottom hole pressure of the shale gas well and the time. The corresponding relationship between the bottom hole pressure of the shale gas well and the time can be generally called as the production system of the shale gas well.
In this embodiment, the formation permeability and the first fracture permeability in the formation property data, and the fracture width and the fracture half-length in the fracture property data may be obtained by a well testing and productivity testing method. The stratum permeability mainly refers to the effective permeability of the stratum in an effective influence area of volume modification after staged fracturing treatment is carried out on the horizontal well. The permeability in this region can be effectively improved so that an effective flow of gas can take place. The fractures mainly refer to artificial fractures with certain width and length formed through propping of propping agents when staged fracturing treatment is carried out on the horizontal well.
In this embodiment, the original formation pressure and the formation porosity in the formation property data, and the length and the well spacing of the horizontal well section in the target gas well may be calculated by using an empirical formula through a logging test, a static pressure test, and the like. And the rock mechanical data can be obtained by a rock core triaxial stress test method. The rock mechanics data can comprise a pythow (Biot) coefficient, a Poisson ratio, a Young modulus and the like, and the data can be used as influencing factors of permeability stress sensitive parameters. And obtaining a permeability stress sensitivity curve, namely a relation curve of a fracture permeability ratio and effective stress, by using a core stress sensitivity experiment method, so as to provide a data basis for subsequently determining the incidence relation between the second fracture permeability corresponding to the target gas well and the bottom hole pressure. Wherein the fracture permeability ratio value may refer to a ratio of the second fracture permeability to the first fracture permeability, the second fracture permeability being used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure.
In the present embodiment, the gas volume coefficient, the gas viscosity, the gas compressibility, and the langmuir isothermal adsorption curve in the gas property data can be obtained by the high-pressure physical properties and the isothermal adsorption experimental method.
For example, for a certain developed gas well X1 in a shale gas production area of the Sichuan basin, formation attribute data, rock mechanics data, gas attribute data and the like corresponding to the X1 well can be acquired. Table 1 is a basic parameter data table corresponding to the X1 well.
TABLE 1 basic parameter data sheet corresponding to X1 well
Figure BDA0001643123730000081
FIG. 1 is a flow chart of an embodiment of a method of determining a bottom hole pressure versus time relationship for a shale gas well according to the present application. As shown in FIG. 1, the method for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time comprises the following steps.
Step S101: determining a first incidence relation between a second fracture permeability corresponding to the target gas well and bottom hole pressure based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure.
In this embodiment, the method for determining the bottom hole pressure of the shale gas well corresponding to the time can also be provided with a generalized coefficient of rocks in the reservoir of interest. Wherein the common coefficient is used for characterizing the rock hardness. Correspondingly, determining a first correlation between a second fracture permeability and a bottom hole pressure corresponding to the target gas well based on the rock mechanics data and the first fracture permeability may specifically include determining a correlation between a second fracture permeability and a permeability stress-sensitive parameter corresponding to the target gas well based on a pyworthiness coefficient and a poisson ratio in the rock mechanics data and the first fracture permeability. Determining a correlation between the permeability stress-sensitive parameter and the bottom hole pressure based on a generalized coefficient of the rock. The first correlation may be determined based on a correlation between the second fracture permeability and the permeability stress-sensitive parameter, and a correlation between the permeability stress-sensitive parameter and the bottom hole pressure. Wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure.
In this embodiment, the following formula may be adopted to determine the correlation between the permeability of the second fracture corresponding to the target gas well and the permeability stress-sensitive parameter:
Figure BDA0001643123730000091
Δp＝pi-pw
wherein, Kf(pw) And Kf(pi) Respectively representing the second fracture permeability and the first fractureSeam permeability; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; α and υ represent the pyworth coefficient and the poisson ratio, respectively; η (Δ p) represents the permeability stress sensitivity parameter; Δ p represents the pressure differential resulting from subtracting the bottom hole pressure from the virgin formation pressure; wherein the permeability stress sensitive parameter is associated with the pressure difference.
In this embodiment, when the ordinary coefficient of the rock is greater than or equal to a specified ordinary coefficient threshold, the correlation between the permeability stress-sensitive parameter and the bottom hole pressure may be determined using the following formula:
η(Δp)＝AΔp+B
Δp＝pi-pw
wherein η (Δ ρ) represents the permeability stress sensitivity parameter; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; Δ p represents the pressure differential resulting from subtracting the bottom hole pressure from the virgin formation pressure; a and B are constants.
When the generalized coefficient of the rock is less than the specified generalized coefficient threshold value, the correlation between the permeability stress-sensitive parameter and the bottom hole pressure may be determined using the following equation:
η(Δp)＝C
wherein C is a constant. Constants A, B and C may be determined based on the fracture permeability ratio versus effective stress curves for core samples of different hardnesses.
In this embodiment, the value range of the specified normal coefficient threshold may be 2 to 3.
Step S102: determining a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, the production time of the target gas well based on the formation permeability, the formation porosity, and the formation thickness, and the fracture property data.
In this embodiment, fig. 2 is a schematic diagram of a physical model of a multi-stage volumetric fractured horizontal well in the example of the present application. FIG. 3 shows an embodiment of the present inventionSchematic representation of the gas flow pattern in a single fracture in an example. A second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, and the production time of the target gas well may be determined based on the formation permeability, the formation porosity, and the formation thickness, and the fracture property data, based on a physical model of a multi-stage volumetric fractured horizontal well and a gas flow model in a single fracture as shown in fig. 2 and 3. Wherein the physical model of the multi-stage volumetric fractured horizontal well has the following definitions: (1) the stratum is uniform and equal in thickness, and a main gas flowing area exists between the artificial fractures; (2) extremely low stratum permeability and no influence of fracture interference in seepage process (3) horizontal well fracturing nfSegments, each segment forming nsThe strip cracks and the artificial cracks are uniformly distributed and have the same attribute; (4) the artificial fracture completely penetrates the stratum from top to bottom, and has flow guiding capacity. As shown in fig. 2 and 3, the fracture is perpendicular to the horizontal wellbore, and gas flows from the formation into the fracture by desorption, elastic compression, etc., flows into the fracture, flows along the fracture into the wellbore, and is finally produced. In FIGS. 2 and 3, the half-length of the crack is xfThe crack spacing is xsCrack length of 2 ×)fThe formation thickness is h. The SRV width in FIG. 2 represents the width of the effective area of influence of the volume modification, a single level of length LsFor the length of each fracturing zone, i.e. horizontal wellbore length LwDivided by the number n of horizontal well fracturing sectionsfValue of (1), crack spacing xsIs of a single stage length LsDivided by the number of fractures n in each fracture sectionsThe value of (c). The gray cubes in fig. 3 represent fractures and the gray cylinders represent horizontal wellbores.
In this embodiment, based on the physical model, a bilinear flow mathematical model of gas flowing from the formation into the fracture and gas flowing from the fracture into the wellbore may be established according to the seepage rule of gas in the formation and the seepage rule of gas in the fracture, that is, a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability and the production time of the target gas well may be determined based on the formation permeability, the formation porosity and the formation thickness, and the fracture property data, and may be specifically determined according to the following steps:
(1) determining a correlation between the production of the target gas well and a pseudo-pressure differential, a pseudo-time, the first fracture permeability based on the formation permeability, the formation porosity, the formation thickness, a fracture width and a fracture half-length in the fracture property data, and the gas property data; wherein the pseudo-pressure difference represents a difference between a pseudo-pressure corresponding to the virgin formation pressure and a pseudo-pressure corresponding to the bottom hole pressure;
(2) determining an incidence relation between the pseudo-time and the production time based on the gas attribute data, the original formation pressure and the average formation pressure corresponding to the target gas well;
(3) respectively determining the correlation between the pseudo pressure corresponding to the original formation pressure and the correlation between the pseudo pressure corresponding to the bottom hole pressure and the bottom hole pressure based on the gas attribute data and the original formation pressure;
(4) and determining the second association relationship according to the association relationship between the yield of the target gas well and the pseudo-pressure difference, the pseudo-time, the first fracture permeability, the association relationship between the pseudo-time and the production time, the association relationship between the pseudo-pressure corresponding to the original formation pressure and the association relationship between the pseudo-pressure corresponding to the bottom hole pressure and the bottom hole pressure.
In the embodiment, the correlation between the yield of the target gas well and the pseudo-pressure difference, the pseudo-time and the first fracture permeability is determined by the following formulas:
Figure BDA0001643123730000111
Figure BDA0001643123730000112
wherein q represents the yield of the target gas well; m (p)i)-m(pw) Representing said pseudo-pressure difference, m (p)i) And m (p)w) Respectively representing a pseudo pressure corresponding to the original formation pressure and a pseudo pressure corresponding to the bottom hole pressure; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; n issRepresenting the number of fracture sections after the staged fracturing treatment of the target gas well, nfRepresenting the number of fractures, w, within one of said fracture zonesfAnd xfRespectively representing the fracture width and the fracture half-length in the fracture attribute data; kf(pi) Representing the first fracture permeability; kmRepresents the formation permeability, h represents the formation thickness, phimRepresenting the formation porosity, ηmiRepresenting a formation diffusion coefficient of the reservoir of interest at the virgin formation pressure; b isgi、μgiAnd cgiRespectively representing a gas volume coefficient, a gas viscosity and a gas compression coefficient in the gas attribute data; t is taRepresenting the pseudo-time.
In the present embodiment, the correlation between the pseudo-time and the production time may be determined using the following formula:
Figure BDA0001643123730000113
wherein, taRepresenting the pseudo-time; mu.sgiRepresenting the viscosity of the gas in said gas property data,
Figure BDA0001643123730000114
represents the corrected gas compressibility, p, at the virgin formation pressureiRepresenting the original formation pressure, μg[pavg(τ)]Representing the gas viscosity at the average formation pressure corresponding to the target gas well,
Figure BDA0001643123730000115
represented in the target gas well pairCorrected gas compressibility at the desired mean formation pressure, pavg(τ) represents an average formation pressure corresponding to the target gas well, the average formation pressure being associated with the production time; τ denotes the time variable to be integrated and t denotes the production time.
In this embodiment, the bottom hole pressure may be related to a pseudo pressure corresponding to the bottom hole pressure by the following formula:
Figure BDA0001643123730000121
wherein, m (p)w) Respectively representing the pseudo pressure corresponding to the bottom hole pressure; mu.sgiRepresenting the viscosity of the gas in said gas property data,
Figure BDA0001643123730000122
represents the corrected gas deviation coefficient, p, at the virgin formation pressureiRepresenting the original formation pressure, ξ representing the pressure variable to be integrated, μg(xi) represents the corrected gas viscosity at a bottom hole pressure of pressure value xi,
Figure BDA0001643123730000123
indicating the corrected gas deviation coefficient, p, at a bottom hole pressure of value xiscDenotes the standard atmospheric pressure, pwRepresenting the bottom hole pressure.
Similarly, the correlation of pseudo pressure corresponding to the virgin formation pressure may be used with the following formula:
Figure BDA0001643123730000124
wherein, m (p)i) Respectively representing the pseudo pressure corresponding to the bottom hole pressure; mu.sgiRepresenting the viscosity of the gas in said gas property data,
Figure BDA0001643123730000125
represents the corrected gas deviation coefficient, p, at the virgin formation pressureiRepresenting the original formation pressure, pscRepresenting standard atmospheric pressure, [ xi ] representing the pressure variable to be integrated, [ mu ]g(xi) represents the corrected gas viscosity at the original formation pressure at a pressure value xi,
Figure BDA0001643123730000126
representing the corrected gas deviation factor at the original formation pressure of pressure value ξ.
In this embodiment, the average formation pressure may be determined using the following equation:
Figure BDA0001643123730000127
wherein p isavgRepresents the average formation pressure corresponding to the target gas well,
Figure BDA0001643123730000131
representing a corrected gas bias coefficient at the average formation pressure,
Figure BDA0001643123730000132
represents the corrected gas deviation coefficient, p, at the virgin formation pressureiRepresenting said original formation pressure, KmRepresents the formation permeability, h represents the formation thickness, phimRepresenting the formation porosity, Bgi、μgiAnd cgiRespectively representing a gas volume coefficient, a gas viscosity and a gas compression coefficient in the gas attribute data; x is the number offRepresenting a fracture half-length in the fracture attribute data; m represents the slope of the fitted line between the yield corrected pseudo pressure difference and the production time under root. The yield-corrected pseudo pressure difference may be employed
Figure BDA0001643123730000133
To indicate that the production time under the root number can be adopted
Figure BDA0001643123730000134
Wherein t represents the production time.
In the present embodiment, the corrected gas deviation coefficient and the corrected gas compression coefficient at a given pressure may be determined using the following formulas, respectively:
Figure BDA0001643123730000135
Figure BDA0001643123730000136
where p represents the specified pressure, which may be the mean formation pressure pavgThe virgin formation pressure piOr the bottom hole pressure pw；
Figure BDA0001643123730000137
And
Figure BDA0001643123730000138
respectively representing a corrected gas deviation coefficient and a corrected gas compression coefficient at the specified pressure, Zg(p) and cg(p) represents a gas deviation factor and a gas compression factor at the specified pressure; b isg(p) represents the gas volume coefficient at said given pressure, VLAnd pLRespectively representing a blue pressure and a blue volume, phimRepresenting the formation porosity.
Step S103: and determining the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time according to the first and second incidence relations.
In this embodiment, determining the corresponding relationship between the bottom hole pressure and the production time corresponding to the target gas well according to the first and second association relationships may specifically include determining the association relationship between the yield of the target gas well and the bottom hole pressure and the production time according to the first and second association relationships. According to the incidence relation among the yield of the target gas well, the bottom hole pressure and the production time, relation curves of the yield of the target gas wells and the bottom hole pressure corresponding to the specified production time are respectively determined, and the target bottom hole pressure corresponding to the maximum value point in each relation curve is determined. And the specified production time corresponds to the relation curve one by one. Fitting the specified production time and the target bottom hole pressure to obtain a corresponding relation between the bottom hole pressure and the production time corresponding to the target gas well.
In this embodiment, the correlation between the production of the target gas well and the bottom hole pressure and the production time may be determined by the following formula:
Figure BDA0001643123730000141
Figure BDA0001643123730000142
wherein q represents the yield of the target gas well; m (p)i)-m(pw) Representing said pseudo-pressure difference, m (p)i) And m (p)w) Respectively representing a pseudo pressure corresponding to the original formation pressure and a pseudo pressure corresponding to the bottom hole pressure; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; α and υ represent the pyworth coefficient and the poisson ratio, respectively; η (Δ p) represents the permeability stress sensitivity parameter; Δ p represents the pressure differential resulting from subtracting the bottom hole pressure from the virgin formation pressure; n issRepresenting the number of fracture sections after the staged fracturing treatment of the target gas well, nfRepresenting the number of fractures, w, within one of said fracture zonesfAnd xfRespectively representing the fracture width and the fracture half-length in the fracture attribute data; kf(pw) Representing the second fracture permeability; kmRepresenting the formation permeability, h representing the formation thickness，φmRepresenting the formation porosity, ηmiRepresenting a formation diffusion coefficient of the reservoir of interest at the virgin formation pressure; b isgi、μgiAnd cgiRespectively representing a gas volume coefficient, a gas viscosity and a gas compression coefficient in the gas attribute data; t is taRepresenting the pseudo-time.
In this embodiment, according to the correlation between the yield of the target gas well and the bottom hole pressure and the production time, determining a relationship curve between a plurality of specified production times and the yields and the bottom hole pressures of the plurality of target gas wells, which may specifically include obtaining a set of production data from the production dynamic data of the target gas well. Wherein the set of production data includes data of the pseudo-pressure difference and the corresponding production time. Then, a yield corrected pseudo pressure difference and a production time under root are determined, respectively, based on the pseudo pressure difference and the corresponding production time in the set of production data. In this way, a set of data comprising a yield corrected pseudo pressure difference and a production time under root can be obtained, wherein the yield corrected pseudo pressure difference and the production time under root correspond one to one. Next, a plurality of data points of the yield-corrected pseudo pressure difference and the production time under the root may be plotted in a rectangular coordinate system, and the slope M of a fitted straight line between the yield-corrected pseudo pressure difference and the production time under the root may be determined using a linear regression analysis method. Substituting the slope M into the formula corresponding to the determined average formation pressure to obtain average formation pressures p corresponding to different specified production times tavgFurther obtain the simulated time t corresponding to different specified production time ta. Finally, the simulation time t corresponding to the different appointed production time t is respectivelyaSubstituting the formula corresponding to the incidence relation between the yield of the target gas well, the bottom hole pressure and the production time to obtain a relation curve of the yield of the target gas wells and the bottom hole pressure corresponding to the specified production time.
For example, fig. 4 is a schematic diagram of a relationship curve of the production and the bottom hole pressure of the target gas well corresponding to different production times in the embodiment of the application. The abscissa and ordinate in fig. 4 are bottom hole pressure and daily production per well, in megapascals (MPa) and ten thousand squares/day, respectively. As shown in fig. 4, the target bottom hole pressure corresponding to the maximum point in each relationship curve may be determined according to the relationship curves of the yield and the bottom hole pressure of the target gas well respectively corresponding to 6 different production times. And then fitting the multiple production times and the multiple target bottom hole pressures to obtain the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time, namely the optimal production system of the target gas well.
In one embodiment of the present application, the method for determining the bottom-hole pressure of the shale gas well corresponding to the time may further include: and establishing a whole-process production dynamic model of the target gas well under the optimal production regime according to the corresponding relation between the bottom hole pressure and the production time corresponding to the target gas well and the first incidence relation. Specifically, a formula for the corresponding relationship between the bottom hole pressure and the production time corresponding to the target gas well may be substituted into the formula for representing the first correlation, and in consideration of the inhomogeneous effect on gas well production after the production system is changed, a full-process production dynamic model of the target gas well under the optimal production system is established by using a Duhamel (Duhamel) convolution method.
In this embodiment, the entire gas well production cycle may be divided into n production time segments. The overall process production dynamic model of the target gas well under the optimal production regime can be established by adopting the following formula:
Figure BDA0001643123730000161
Δpj＝pw,j-1-pw,j
wherein q represents the yield of the target gas well; m (p)w,j) Representing a pressure value of pw,jA pseudo pressure corresponding to the bottom hole pressure of (a); p is a radical ofw,jRepresents a target bottom hole pressure corresponding to the jth production time, wherein p is the target bottom hole pressure when j is 1w,j-1Is the originalFormation pressure pi(ii) a α and υ represent the pyworth coefficient and the poisson ratio, respectively; η (Δ p) represents the permeability stress sensitivity parameter; Δ p represents the pressure differential resulting from subtracting the bottom hole pressure from the virgin formation pressure; n issRepresenting the number of fracture sections after the staged fracturing treatment of the target gas well, nfRepresenting the number of fractures, w, within one of said fracture zonesfAnd xfRespectively representing the fracture width and the fracture half-length in the fracture attribute data; kf(pw,j-1) Expressed at a pressure value of pw,jWherein K is K when j is 1f(pw,j-1) Is the first fracture permeability; kmRepresents the formation permeability, h represents the formation thickness, phimRepresenting the formation porosity, ηmiRepresenting a formation diffusion coefficient of the reservoir of interest at the virgin formation pressure; b isgi、μgiAnd cgiRespectively representing a gas volume coefficient, a gas viscosity and a gas compression coefficient in the gas attribute data; t is ta,jThe pseudo-time corresponding to the jth production time is shown.
In this embodiment, when determining the average formation pressure for each production period, the fitting pressure difference of the production correction in the production period and the production time under the root may be fitted to obtain the slope M of the corresponding fitting straight line, and then the corresponding average formation pressure may be determined. In this way, the slope M can be updated in real time according to the production time period.
For example, fig. 5 is a schematic diagram of three production regimes selected in the example of the present application in a graphical plot of production versus bottom hole pressure for the target gas well corresponding to the different production times of fig. 4, respectively. FIG. 6 is a schematic of the cumulative production from a single well for each of the three production regimes of the present example. The abscissa and ordinate in fig. 5 are bottom hole pressure and daily production per well, in megapascals (MPa) and ten thousand squares/day, respectively. The abscissa and ordinate in fig. 6 are production time and cumulative production per well in units of years and billions, respectively. In fig. 5 and 6, an optimized path 1 is a production system of a pressure relief production mode, an optimized path 2 is an optimal production system determined by the method of the application, and an optimized path 3 is a production system of an unreasonable pressure control production mode. As shown in fig. 6, in the early stage of production, that is, in the production time period before the gray dashed line in fig. 6, the production system of the pressure relief production mode can obtain a higher cumulative yield, and after the production enters the middle and later stages of production, that is, in the production time period after the gray dashed line in fig. 6, by using the optimal production system determined by the method of the present application, the gas well can obtain a higher cumulative yield, and as the production time increases, the effect of the optimal production system on the increase of the cumulative yield of the gas well becomes more and more significant. By contrast, the accumulated yield of the gas well under the production system of the unreasonable pressure control production mode is lower than that of the pressure relief production mode and the optimal production system determined by the method, which indicates that the production effect of the gas well is lower than that of the pressure relief production scheme possibly due to the adoption of the improper pressure control production scheme.
FIG. 7 is a graphical representation of the variation in bottom hole pressure, formation pore pressure, total in situ stress, and effective stress for a gas well under two production regimes in an example of the present application. Fig. 7 (a) and (b) are schematic diagrams of changes in bottom hole pressure, formation pore pressure, total in-situ stress, and effective stress of the gas well under the production regime corresponding to the optimized path 1 and the production regime corresponding to the optimized path 2 in fig. 5, respectively. The abscissa and ordinate in (a) and (b) in fig. 7 are the production time and pressure, respectively, in days and megapascals (MPa), respectively. As shown in fig. 7, the change form of the effective stress in the formation or the fracture can be effectively influenced by the control of the production system, and particularly, the increase amplitude of the effective stress can be effectively inhibited by adopting the production system corresponding to the optimized path 2, so that the seepage passage is kept open for a long time, and the productivity of the gas well can be ensured.
Table 2 is the final recoverable reserves (EUR) for three gas wells with similar geological engineering backgrounds. Wherein, the three gas wells are shale wells X1, X2 and X3 respectively. The three gas wells respectively adopt a production system of a pressure relief production mode corresponding to the optimized path 1 and an optimal production system corresponding to the optimized path 2 in the figure 5 to control production. The normalized EUR in table 2 represents the ratio of EUR to the effective use reserve, and the EUR increase ratio is the difference between EURs corresponding to the optimum production system and the pressure release production system, respectively, and the ratio of EUR corresponding to the pressure release production system.
TABLE 2 Final recoverable reserves for three gas wells of similar geological engineering background
Figure BDA0001643123730000171
As can be seen from Table 2, the optimal production regime determined by the method of the present application can effectively improve the EUR of a single well, and the purpose of improving the development effect of the single well is achieved.
According to the embodiment of the method for determining the corresponding relation between the bottom hole pressure and the time of the shale gas well, a first related relation between a second fracture permeability and the bottom hole pressure corresponding to the target gas well can be determined based on the rock mechanics data and the first fracture permeability, and a second related relation between the yield of the target gas well and the bottom hole pressure, the first fracture permeability and the production time of the target gas well can be determined based on the formation permeability, the formation porosity and the formation thickness and the fracture property data; finally, the corresponding relation between the bottom hole pressure and the production time corresponding to the target gas well can be determined according to the first correlation and the second correlation. Therefore, according to the method, various stratum attribute data, rock mechanics data and fracture attribute data of the shale gas reservoir can be combined, a set of scientific and reasonable gas well production system optimization scheme is established, the optimal corresponding relation between the bottom hole pressure and the production time is obtained, and the final recoverable reserve of the shale gas well can be improved.
FIG. 8 is a block diagram illustrating the components of one embodiment of the present apparatus for determining the bottom hole pressure versus time relationship for a shale gas well. The device for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time provides stratum attribute data, fracture attribute data and rock mechanics data of a target reservoir in a target work area; wherein the target work area comprises a target gas well which is drilled in the target reservoir; the fracture attribute data is used for characterizing physical properties of the fracture; the formation attribute data comprises first fracture permeability, formation porosity, formation thickness and original formation pressure; the first fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the virgin formation pressure. As shown in fig. 8, the apparatus for determining the bottom hole pressure of the shale gas well corresponding to the time may include: a first incidence relation determining module 100, a second incidence relation determining module 200 and a target correspondence relation determining module 300.
The first correlation determination module 100 may be configured to determine a first correlation between a second fracture permeability and a bottom hole pressure corresponding to the target gas well based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure.
The second correlation determination module 200 may be configured to determine a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, and the production time of the target gas well based on the formation permeability, the formation porosity, and the formation thickness, and the fracture property data.
The target corresponding relation determining module 300 may be configured to determine a corresponding relation between bottom hole pressure and production time corresponding to the target gas well according to the first associated relation and the second associated relation.
FIG. 9 is a block diagram illustrating the composition of another embodiment of the apparatus for determining bottom hole pressure versus time for a shale gas well. As shown in fig. 9, the apparatus for determining a bottom-hole pressure versus time relationship for a shale gas well may include a memory, a processor, and a computer program stored on the memory, the memory having stored therein formation property data, fracture property data, and rock mechanics data for a reservoir of interest in a region of interest; wherein the target work area comprises a target gas well which is drilled in the target reservoir; the fracture attribute data is used for characterizing physical properties of the fracture; the formation attribute data comprises first fracture permeability, formation porosity, formation thickness and original formation pressure; the first fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the virgin formation pressure, the computer program when executed by the processor performs the steps of:
step S101: determining a first incidence relation between a second fracture permeability corresponding to the target gas well and bottom hole pressure based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure;
step S102: determining a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, the production time of the target gas well based on the formation permeability, the formation porosity, and the formation thickness, and the fracture property data;
step S103: and determining the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time according to the first and second incidence relations.
The device embodiment for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time corresponds to the method embodiment for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time, the technical scheme of the method embodiment for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time can be achieved, and the technical effects of the method embodiment are achieved.
In the 90 s of the 20 th century, improvements in a technology could clearly distinguish between improvements in hardware (e.g., improvements in circuit structures such as diodes, transistors, switches, etc.) and improvements in software (improvements in process flow). However, as technology advances, many of today's process flow improvements have been seen as direct improvements in hardware circuit architecture. Designers almost always obtain the corresponding hardware circuit structure by programming an improved method flow into the hardware circuit. Thus, it cannot be said that an improvement in the process flow cannot be realized by hardware physical modules. For example, a Programmable Logic Device (PLD), such as a Field Programmable Gate Array (FPGA), is an integrated circuit whose Logic functions are determined by programming the Device by a user. A digital system is "integrated" on a PLD by the designer's own programming without requiring the chip manufacturer to design and fabricate application-specific integrated circuit chips. Furthermore, nowadays, instead of manually making an Integrated Circuit chip, such Programming is often implemented by "logic compiler" software, which is similar to a software compiler used in program development and writing, but the original code before compiling is also written by a specific Programming Language, which is called Hardware Description Language (HDL), and HDL is not only one but many, such as abel (advanced Boolean Expression Language), ahdl (alternate Language Description Language), traffic, pl (core unified Programming Language), HDCal, JHDL (Java Hardware Description Language), langue, Lola, HDL, laspam, hardbyscript Description Language (vhr Description Language), and the like, which are currently used by Hardware compiler-software (Hardware Description Language-software). It will also be apparent to those skilled in the art that hardware circuitry that implements the logical method flows can be readily obtained by merely slightly programming the method flows into an integrated circuit using the hardware description languages described above.
Those skilled in the art will also appreciate that, in addition to implementing the controller as pure computer readable program code, the same functionality can be implemented by logically programming method steps such that the controller is in the form of logic gates, switches, application specific integrated circuits, programmable logic controllers, embedded microcontrollers and the like. Such a controller may thus be considered a hardware component, and the means included therein for performing the various functions may also be considered as a structure within the hardware component. Or even means for performing the functions may be regarded as being both a software module for performing the method and a structure within a hardware component.
The apparatuses and modules illustrated in the above embodiments may be implemented by a computer chip or an entity, or by a product with certain functions.
For convenience of description, the above devices are described as being divided into various modules by functions, and are described separately. Of course, the functionality of the various modules may be implemented in the same one or more software and/or hardware implementations as the present application.
From the above description of the embodiments, it is clear to those skilled in the art that the present application can be implemented by software plus necessary general hardware platform. With this understanding in mind, the present solution, or portions thereof that contribute to the prior art, may be embodied in the form of a software product, which in a typical configuration includes one or more processors (CPUs), input/output interfaces, network interfaces, and memory. The computer software product may include instructions for causing a computing device (which may be a personal computer, a server, or a network device, etc.) to perform the methods described in the various embodiments or portions of embodiments of the present application. The computer software product may be stored in a memory, which may include forms of volatile memory in a computer readable medium, Random Access Memory (RAM) and/or non-volatile memory, such as Read Only Memory (ROM) or flash memory (flash RAM). Memory is an example of a computer-readable medium. Computer-readable media, including both non-transitory and non-transitory, removable and non-removable media, may implement information storage by any method or technology. The information may be computer readable instructions, data structures, modules of a program, or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), Static Random Access Memory (SRAM), Dynamic Random Access Memory (DRAM), other types of Random Access Memory (RAM), Read Only Memory (ROM), Electrically Erasable Programmable Read Only Memory (EEPROM), flash memory or other memory technology, compact disc read only memory (CD-ROM), Digital Versatile Discs (DVD) or other optical storage, magnetic cassettes, magnetic tape magnetic disk storage or other magnetic storage devices, or any other non-transmission medium that can be used to store information that can be accessed by a computing device. As defined herein, computer readable media does not include transitory computer readable media (transient media), such as modulated data signals and carrier waves.
The embodiments in the present specification are described in a progressive manner, and the same and similar parts among the embodiments are referred to each other, and each embodiment focuses on the differences from the other embodiments. In particular, as for the apparatus embodiment, since it is substantially similar to the method embodiment, the description is relatively simple, and for the relevant points, reference may be made to the partial description of the method embodiment.
The application is operational with numerous general purpose or special purpose computing system environments or configurations. For example: personal computers, server computers, hand-held or portable devices, tablet-type devices, multiprocessor systems, microprocessor-based systems, set top boxes, programmable consumer electronics, network PCs, minicomputers, mainframe computers, distributed computing environments that include any of the above systems or devices, and the like.
The application may be described in the general context of computer-executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc. that perform particular tasks or implement particular abstract data types. The application may also be practiced in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network. In a distributed computing environment, program modules may be located in both local and remote computer storage media including memory storage devices.
While the present application has been described with examples, those of ordinary skill in the art will appreciate that there are numerous variations and permutations of the present application without departing from the spirit of the application, and it is intended that the appended claims encompass such variations and permutations without departing from the spirit of the application.

Claims (10)

1. The method for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time is characterized by providing stratum attribute data, fracture attribute data and rock mechanics data of a target reservoir in a target work area; wherein the target work area comprises a target gas well which is drilled in the target reservoir; the fracture attribute data is used for characterizing physical properties of the fracture; the formation attribute data comprises first fracture permeability, formation porosity, formation thickness and original formation pressure; the first fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the virgin formation pressure; the method comprises the following steps:
determining a first incidence relation between a second fracture permeability corresponding to the target gas well and bottom hole pressure based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure;
determining a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, the production time of the target gas well based on the formation permeability, the formation porosity, and the formation thickness, and the fracture property data;
and determining the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time according to the first and second incidence relations.
2. The method of claim 1, wherein the method is further provided with a prevalence coefficient for rock in the reservoir of interest; wherein the ordinary coefficient is used for representing the hardness of the rock; determining a first correlation between a second fracture permeability corresponding to the target gas well and a bottom hole pressure, comprising:
determining an incidence relation between a second fracture permeability and a permeability stress-sensitive parameter corresponding to the target gas well based on a pyworth coefficient and a poisson ratio in the rock mechanics data and the first fracture permeability;
determining a correlation between the permeability stress-sensitive parameter and the bottom hole pressure based on a generalized coefficient of the rock;
and determining the first incidence relation according to the incidence relation between the second fracture permeability and the permeability stress sensitive parameter and the incidence relation between the permeability stress sensitive parameter and the bottom hole pressure.
3. The method of claim 2, wherein the correlation between the second fracture permeability and the permeability stress-sensitive parameter for the target gas well is determined using the following equation:
Figure FDA0001643123720000011
Δp＝pi-pw
wherein, Kf(pw) And Kf(pi) Representing the second fracture permeability and the first fracture permeability, respectively; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; α and υ represent the pyworth coefficient and the poisson ratio, respectively; η (Δ p) represents the permeability stress sensitivity parameter; Δ p represents the pressure differential resulting from subtracting the bottom hole pressure from the virgin formation pressure; wherein the permeability stress sensitive parameter is associated with the pressure difference.
4. The method of claim 2,
determining a correlation between the permeability stress-sensitive parameter and the bottom hole pressure using the following formula when the generalized coefficient of the rock is greater than or equal to a specified generalized coefficient threshold value:
η(Δp)＝AΔp+B
Δp＝pi-pw
wherein η (Δ ρ) represents the permeability stress sensitivity parameter; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; Δ p represents the pressure of the original formation minus the bottom hole pressureA difference; a and B are constants;
when the normal coefficient of the rock is less than the specified normal coefficient threshold, determining the correlation between the permeability stress-sensitive parameter and the bottom hole pressure using the following formula:
η(Δp)＝C
wherein C is a constant.
5. The method of claim 1, further providing gas property data of the reservoir of interest at the virgin formation pressure; wherein the gas property data is used to characterize physical characteristics of the gas in the reservoir of interest; determining a second correlation between the production of the target gas well and the bottom hole pressure, the first fracture permeability, the production time of the target gas well, comprising:
determining a correlation between the production of the target gas well and a pseudo-pressure differential, a pseudo-time, the first fracture permeability based on the formation permeability, the formation porosity, the formation thickness, a fracture width and a fracture half-length in the fracture property data, and the gas property data; wherein the pseudo-pressure difference represents a difference between a pseudo-pressure corresponding to the virgin formation pressure and a pseudo-pressure corresponding to the bottom hole pressure;
determining an association between the pseudo-time and the production time based on the gas property data, the original formation pressure and an average formation pressure corresponding to the target gas well;
respectively determining the correlation between the pseudo pressure corresponding to the original formation pressure and the correlation between the pseudo pressure corresponding to the bottom hole pressure and the bottom hole pressure based on the gas attribute data and the original formation pressure;
and determining the second association relationship according to the association relationship between the yield of the target gas well and the pseudo-pressure difference, the pseudo-time, the first fracture permeability, the association relationship between the pseudo-time and the production time, the association relationship between the pseudo-pressure corresponding to the original formation pressure and the association relationship between the pseudo-pressure corresponding to the bottom hole pressure and the bottom hole pressure.
6. The method of claim 5 wherein the correlation between the yield of the target gas well and the pseudo-pressure differential, pseudo-time, first fracture permeability is determined using the following equations:
Figure FDA0001643123720000031
Figure FDA0001643123720000032
wherein q represents the yield of the target gas well; m (p)i)-m(pw) Representing said pseudo-pressure difference, m (p)i) And m (p)w) Respectively representing a pseudo pressure corresponding to the original formation pressure and a pseudo pressure corresponding to the bottom hole pressure; p is a radical ofwAnd piRepresenting the bottom hole pressure and the virgin formation pressure, respectively; n issRepresenting the number of fracture sections after the staged fracturing treatment of the target gas well, nfRepresenting the number of fractures, w, within one of said fracture zonesfAnd xfRespectively representing the fracture width and the fracture half-length in the fracture attribute data; kf(pi) Representing the first fracture permeability; kmRepresents the formation permeability, h represents the formation thickness, phimRepresenting the formation porosity, ηmiRepresenting a formation diffusion coefficient of the reservoir of interest at the virgin formation pressure; b isgi、μgiAnd cgiRespectively representing a gas volume coefficient, a gas viscosity and a gas compression coefficient in the gas attribute data; t is taRepresenting the pseudo-time.
7. The method of claim 5, wherein the correlation between the pseudo-time and the production time is determined using the following equation:
Figure FDA0001643123720000041
wherein, taRepresenting the pseudo-time; mu.sgiRepresenting the viscosity of the gas in said gas property data,
Figure FDA0001643123720000042
represents the corrected gas compressibility, p, at the virgin formation pressureiRepresenting the original formation pressure, μg[pavg(τ)]Representing the gas viscosity at the average formation pressure corresponding to the target gas well,
Figure FDA0001643123720000043
represents a corrected gas compressibility, p, at a corresponding average formation pressure for the target gas wellavg(τ) represents an average formation pressure corresponding to the target gas well, the average formation pressure being associated with the production time; τ denotes the time variable to be integrated and t denotes the production time.
8. The method of claim 5, wherein the bottom hole pressure is correlated to a pseudo pressure corresponding to the bottom hole pressure using the following equation:
Figure FDA0001643123720000044
wherein, m (p)w) Respectively representing the pseudo pressure corresponding to the bottom hole pressure; mu.sgiRepresenting the viscosity of the gas in said gas property data,
Figure FDA0001643123720000045
represents the corrected gas deviation coefficient, p, at the virgin formation pressureiTo representThe original formation pressure, ξ, represents the pressure variable, μ, to be integratedg(xi) represents the corrected gas viscosity at a bottom hole pressure of pressure value xi,
Figure FDA0001643123720000046
indicating the corrected gas deviation coefficient, p, at a bottom hole pressure of value xiscDenotes the standard atmospheric pressure, pwRepresenting the bottom hole pressure.
9. The method of claim 1, wherein determining a bottom hole pressure versus production time correspondence for the target gas well comprises:
determining an incidence relation between the yield of the target gas well, the bottom hole pressure and the production time according to the first incidence relation and the second incidence relation;
respectively determining a plurality of relation curves of the specified production time corresponding to the yield and the bottom hole pressure of the plurality of target gas wells according to the incidence relation among the yield of the target gas well, the bottom hole pressure and the production time, and determining the target bottom hole pressure corresponding to the maximum value point in each relation curve; wherein the specified production time corresponds to the relationship curve one to one;
and fitting the specified production time and the target bottom hole pressure to obtain the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time.
10. The device for determining the corresponding relation between the bottom hole pressure of the shale gas well and the time is characterized in that the device provides stratum attribute data, fracture attribute data and rock mechanics data of a target reservoir in a target work area; wherein the target work area comprises a target gas well which is drilled in the target reservoir; the fracture attribute data is used for characterizing physical properties of the fracture; the formation attribute data comprises first fracture permeability, formation porosity, formation thickness and original formation pressure; the first fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the virgin formation pressure; the device comprises: the system comprises a first incidence relation determining module, a second incidence relation determining module and a target corresponding relation determining module; wherein the content of the first and second substances,
the first incidence relation determining module is used for determining a first incidence relation between second fracture permeability and bottom hole pressure corresponding to the target gas well based on the rock mechanics data and the first fracture permeability; wherein the second fracture permeability is used to characterize the fracture permeability of the reservoir of interest at the bottom hole pressure;
the second incidence relation determination module is used for determining a second incidence relation between the yield of the target gas well and the bottom hole pressure, the first fracture permeability and the production time of the target gas well based on the formation permeability, the formation porosity and the formation thickness and the fracture attribute data;
and the target corresponding relation determining module is used for determining the corresponding relation between the bottom hole pressure corresponding to the target gas well and the production time according to the first associated relation and the second associated relation.
CN201810389715.9A 2018-04-27 2018-04-27 Method and device for determining corresponding relation between bottom hole pressure and time of shale gas well Active CN108798654B (en)

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