CN109143373B - Shale gas reservoir stratum pressure calculation method and computer readable storage medium - Google Patents

Shale gas reservoir stratum pressure calculation method and computer readable storage medium Download PDF

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CN109143373B
CN109143373B CN201710512097.8A CN201710512097A CN109143373B CN 109143373 B CN109143373 B CN 109143373B CN 201710512097 A CN201710512097 A CN 201710512097A CN 109143373 B CN109143373 B CN 109143373B
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elasticity tensor
sandy
mixture
elasticity
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胡起
胡华锋
朱童
曹辉兰
许凯
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China Petroleum and Chemical Corp
Sinopec Geophysical Research Institute
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Sinopec Geophysical Research Institute
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Abstract

The shale gas reservoir stratum pressure calculation method comprises the following steps: acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information; acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture; acquiring acoustic wave time difference based on the elasticity tensor of the equivalent shale; and acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference. The shale gas reservoir stratum pressure calculation method can reduce uncertainty of establishment of a trend line when actually measured pressure data is insufficient, effectively considers the influence of lithology on the trend line, and finally improves the accuracy of pressure prediction.

Description

Shale gas reservoir stratum pressure calculation method and computer readable storage medium
Technical Field
The invention relates to the field of oil and gas geophysical, in particular to a shale gas reservoir stratum pressure calculation method and a computer readable storage medium.
Background
Unconventional oil and gas resources represented by shale gas become hot spots for the research of the energy field in China. The actual drilling data of the Sichuan basin show that the daily gas yield of the shale gas has positive correlation with the formation pressure coefficient, and high pressure or ultrahigh pressure usually corresponds to good storage conditions and enough formation energy, thereby being beneficial to high and stable yield of the shale gas. In the drilling stage, the formation pressure is indispensable key data of the drilling fluid and the structural design of the well body, and accurate pressure prediction is helpful for safe and economical drilling. Therefore, in the shale gas exploration and development process, the pressure research of the oil-gas reservoir has very important significance.
The logging information has the advantages of good longitudinal continuity, high resolution and high data reliability, can accurately acquire the longitudinal distribution rule of the formation pressure, has smaller influence of factors such as well bores, formation conditions and the like on the relative density logging, resistivity logging and the like of the acoustic time difference logging, and is often used for calculating the formation pressure. The main methods for calculating the formation pressure by using the acoustic wave data include an equivalent depth method, an Eaton equation method and the like, the use of the methods is based on the fact that a normal compaction trend line (NCT) is known, namely the change rule of acoustic wave time difference along with the buried depth under the normal pressure condition, and then the magnitude of abnormal pressure is estimated according to the deviation degree of the actually measured acoustic wave time difference and the NCT.
The conventional method for constructing the NCT is as follows: and selecting sound wave time difference data of the pure mud rock stratum of the normal compaction section according to the actually measured pressure information, removing abnormal points, and fitting a relational expression of the abnormal points and the depth to obtain a normal compaction trend line of the whole well section. However, there are two disadvantages to this approach. Firstly, when actual measurement pressure information of a research area is limited, particularly for a new exploration area with a small number of wells, strong subjectivity and randomness exist in the establishment of NCT based on data fitting, accurate calculation is difficult, large pressure prediction errors are easily brought, and the applicability of a compaction trend line construction method based on data fitting in formation pressure prediction is limited to a certain extent; secondly, the stratum is often the sand shale interbed (including shale gas reservoir), the sensitivity degree of different rock frameworks to pressure changes is different, sandstone and mudstone correspond to different acoustic time differences and change rules thereof, and it is not reasonable to predict the stratum pressure of the sandstone section by using the normal acoustic time difference constructed by the mudstone section data.
Pervukhina and Han et al have recently proposed a shale rock physics model named CPS (clay plus silt), and proved by practical application that the model can be used for solving the acoustic wave time difference under the normal compaction condition, and has higher pressure prediction precision relative to a regional compaction trend line obtained based on data fitting. However, the above model is established for general shale, and the influence of hydrocarbon-producing substances (organic substances) is not considered in the model. The existence of organic matters not only greatly reduces the hardness of the rock, but also the anisotropy of the rock is further enhanced by the directional arrangement of the spatial distribution form of the organic matters. In order to apply the idea of constructing the compaction trend line by using the rock physical model to the shale gas reservoir rich in organic matters, the model needs to be improved, so that the method is suitable for the pressure prediction problem of the actual work area in China.
Therefore, there is a need to develop a shale gas reservoir formation pressure calculation method and a computer readable storage medium capable of directly calculating the shale gas reservoir formation pressure based on a petrophysical model.
Disclosure of Invention
The invention provides a shale gas reservoir stratum pressure calculation method and a computer readable storage medium.
According to one aspect of the invention, a shale gas reservoir formation pressure calculation method is provided. The method may include:
acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information;
acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture;
acquiring acoustic wave time difference based on the elasticity tensor of the equivalent shale;
and acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference.
Preferably, the acquiring the wet clay elasticity tensor based on the well log data comprises: based on logging information, acquiring total rock porosity and clay volume content, and acquiring the wet clay elasticity tensor based on the total rock porosity and the clay volume content, wherein the concrete formula is as follows:
Figure BDA0001334890490000031
Figure BDA0001334890490000032
wherein phi and fcRespectively representing the total porosity of the rock and the volume content of the clay, and kappa is the porosity of the wet clay, namely the volume fraction of pore fluid in the wet clay;
Figure BDA0001334890490000033
is the elasticity tensor of pure clay; cijFor the elasticity tensor of wet clay, the model assumes that the clay has a transversely isotropic symmetry, whose elasticity tensor can be characterized by five independent parameters:
Figure BDA0001334890490000034
Figure BDA0001334890490000035
the values of the independent parameters are as follows:
Figure BDA0001334890490000036
Figure BDA0001334890490000037
preferably, the obtaining the elasticity tensor of the sandy mixture based on the logging information comprises: the method comprises the steps of obtaining a sand mixture component, a sand mixed component volume content and a sand mixed component elastic modulus based on logging data, obtaining the sand mixture elastic tension through the calculation of a Voight-reus-Hill model based on the sand mixture component, the sand mixed component volume content and the sand mixed component elastic modulus, and obtaining the sand mixture elastic tension through the specific formula:
Figure BDA0001334890490000038
Figure BDA0001334890490000039
Figure BDA0001334890490000041
wherein i is the ith sandy mineral, N is the number of types of the sandy minerals, and fiIs the volume content, M, of the i-th sandy mix componentiIs the modulus of elasticity of the ith gritty mix component; the Voigt and reus models provide the upper limit M of the equivalent rock modulus, respectivelyVAnd a lower limit MRThe upper and lower limits are arithmetically averaged to obtain MHThe elastic modulus of the sandy mixture is obtained, and the elasticity tensor of the sandy mixture can be expressed as follows:
Figure BDA0001334890490000042
wherein: cxyK and μ represent the volume modulus and shear modulus of the sandy mix, respectively, as the elasticity tensor of the sandy mix.
Preferably, the obtaining the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture comprises: obtaining the elasticity tensor of the equivalent shale formed by the wet clay-sandy mixture-organic matter through the Backus average formula calculation based on the elasticity tensor of the wet clay, the elasticity tensor of the sandy mixture and the elasticity tensor of the organic matter,
Figure BDA0001334890490000043
wherein, CeffIs the elastic tensor of the equivalent shale, Cij' are the components of this tensor, which can be found from the elastic components of the wet clay elasticity tensor, the sandy mixture elasticity tensor, and the organic matter elasticity tensor:
Figure BDA0001334890490000051
Figure BDA0001334890490000052
C12'＝C11-<c11>+<c12>，
Figure BDA0001334890490000053
Figure BDA0001334890490000054
C66'＝<c66>
wherein, cijElastic stiffness components representing the elastic tensor of wet clay, the elastic tensor of sandy mixture and the elastic tensor of organic matter< >Indicating a weighted average of its internal properties by volume ratio.
Preferably, the acoustic time difference is obtained based on the elasticity tensor of the equivalent shale, and the specific formula is
Figure BDA0001334890490000055
DT＝1/Vp (7)
Where ρ represents the rock density, C33' is the stiffness component of the elastic tensor of the equivalent shale, and DT denotes the acoustic moveout.
Preferably, the acquiring the formation pressure of the shale gas reservoir based on the acoustic moveout comprises: the formation pressure of the shale gas reservoir is obtained through calculation of an Eaton equation through the overburden formation pressure, the hydrostatic pressure, the acoustic time difference and the actually measured acoustic wave difference of the formation, and the concrete formula is as follows:
Pp＝Pov-(Pov-Ph)(DT/Δt)c (8)
wherein, PpIs shale gas reservoir formation pressure, PovIs overburden pressure, PhThe hydrostatic pressure is adopted, delta t is the actually measured acoustic time difference of the stratum, and c is an Eaton constant;
wherein the overburden pressure PovAnd the hydrostatic pressure PhAll can be solved by density integration, and the calculation formula is as follows:
Figure BDA0001334890490000056
wherein g is the gravity acceleration, h is the burial depth, and rho (z) is the formation water density at the depth z;
Figure BDA0001334890490000061
where g is the gravitational acceleration, h is the burial depth, and ρ (z) is the formation rock density at depth z.
According to another aspect of the present invention, a computer-readable storage medium having a computer program stored thereon is presented, the computer-readable storage medium comprising:
acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information;
acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture;
acquiring acoustic wave time difference based on the elasticity tensor of the equivalent shale;
and acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference.
Preferably, the acquiring the wet clay elasticity tensor based on the well log data comprises: based on logging information, acquiring total rock porosity and clay volume content, and acquiring the wet clay elasticity tensor based on the total rock porosity and the clay volume content, wherein the concrete formula is as follows:
Figure BDA0001334890490000062
Figure BDA0001334890490000063
wherein phi and fcRespectively representing the total porosity of the rock and the volume content of the clay, and kappa is the porosity of the wet clay, namely the volume fraction of pore fluid in the wet clay;
Figure BDA0001334890490000064
is the elasticity tensor of pure clay; cijFor the elasticity tensor of wet clay, the model assumes that the clay has a transversely isotropic symmetry, whose elasticity tensor can be characterized by five independent parameters:
Figure BDA0001334890490000065
Figure BDA0001334890490000071
the values of the independent parameters are as follows:
Figure BDA0001334890490000072
Figure BDA0001334890490000073
preferably, the obtaining the elasticity tensor of the sandy mixture based on the logging information comprises: the method comprises the steps of obtaining a sand mixture component, a sand mixed component volume content and a sand mixed component elastic modulus based on logging data, obtaining the sand mixture elastic tension through the calculation of a Voight-reus-Hill model based on the sand mixture component, the sand mixed component volume content and the sand mixed component elastic modulus, and obtaining the sand mixture elastic tension through the specific formula:
Figure BDA0001334890490000074
Figure BDA0001334890490000075
Figure BDA0001334890490000076
wherein i is the ith sandy mineral, N is the number of types of the sandy minerals, and fiIs the volume content, M, of the i-th sandy mix componentiIs the modulus of elasticity of the ith gritty mix component; the Voigt and reus models provide the upper limit M of the equivalent rock modulus, respectivelyVAnd a lower limit MRThe upper and lower limits are arithmetically averaged to obtain MHThe elastic modulus of the sandy mixture is obtained, and the elasticity tensor of the sandy mixture can be expressed as follows:
Figure BDA0001334890490000077
wherein: cxyK and μ represent the volume modulus and shear modulus of the sandy mix, respectively, as the elasticity tensor of the sandy mix.
Preferably, the obtaining the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture comprises: obtaining the elasticity tensor of the equivalent shale formed by the wet clay-sandy mixture-organic matter through the Backus average formula calculation based on the elasticity tensor of the wet clay, the elasticity tensor of the sandy mixture and the elasticity tensor of the organic matter,
Figure BDA0001334890490000081
wherein, CeffIs the elastic tensor of the equivalent shale, Cij' are the components of this tensor, which can be found from the elastic components of the wet clay elasticity tensor, the sandy mixture elasticity tensor, and the organic matter elasticity tensor:
Figure BDA0001334890490000082
Figure BDA0001334890490000083
C12'＝C11-<c11>+<c12>，
Figure BDA0001334890490000084
Figure BDA0001334890490000085
C66'＝<c66>
wherein, cijElastic stiffness components representing the elastic tensor of wet clay, the elastic tensor of sandy mixture and the elastic tensor of organic matter< >Indicating a weighted average of its internal properties by volume ratio.
The invention has the beneficial effects that: the normal compaction trend line is constructed through the method, the shale gas reservoir stratum pressure is calculated, the uncertainty of the establishment of the trend line when the actually measured pressure data is insufficient can be reduced, the influence of lithology on the trend line can be effectively considered, the irrationality of the compaction trend line of the common mudstone section when the sand-mudstone mutual layer is formed in the traditional method is solved, and the accuracy of pressure prediction can be finally improved.
The method and apparatus of the present invention have other features and advantages which will be apparent from or are set forth in detail in the accompanying drawings and the following detailed description, which are incorporated herein, and which together serve to explain certain principles of the invention.
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The foregoing and other objects, features and advantages of the invention will be apparent from the following more particular descriptions of exemplary embodiments of the invention as illustrated in the accompanying drawings wherein like reference numbers generally represent like parts throughout the exemplary embodiments of the invention.
Fig. 1 shows a flow chart of a shale gas reservoir formation pressure calculation method according to the present invention.
Figures 2a-2c show a schematic representation of the calculated lamination coefficient for a J1 well in a work area, according to one embodiment of the present invention.
Fig. 3a-3d show schematic diagrams of the calculation of the prediction of the lamination coefficient of four adjacent wells of a J1 well, respectively, according to one embodiment of the invention.
Detailed Description
The invention will be described in more detail below with reference to the accompanying drawings. While the preferred embodiments of the present invention are shown in the drawings, it should be understood that the present invention may be embodied in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art.
Embodiment mode 1
In this embodiment, the shale gas reservoir formation pressure calculation method according to the present invention includes:
acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information;
acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture;
acquiring acoustic wave time difference based on the elasticity tensor of the equivalent shale;
and acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference.
Specifically, the normal compaction trend line is constructed through the method, the uncertainty of the establishment of the trend line when the actually measured pressure data is insufficient can be reduced, the influence of lithology on the trend line can be effectively considered, the irrationality of the compaction trend line of the common mudstone section in the sand-mudstone interbed in the traditional method is solved, and the accuracy of pressure prediction can be finally improved.
Specifically, the elasticity tensor of the wet clay mixture is linearly inversely related to the wet clay porosity (volume content of fluid in the wet clay), and not to the mineral component of the clay. Thus, the wet clay elasticity tensor can be determined solely by the wet clay porosity, and the elasticity tensor of the entire shale can be determined jointly by the wet clay porosity and the volume content of the sandy mixture (other mineral components than clay). Meanwhile, the change of the formation pressure only influences the opening and closing of soft pores in the rock, the influence of the soft pores on the total porosity is negligible, so that two factors influencing the elasticity tensor of the shale are not influenced by abnormal pressure, and the speed or time difference of the rock under the normal compaction condition can be calculated by the model.
In particular, the present invention assumes that clay and pore fluid constitute a wet clay mixture, while hard minerals such as quartz, feldspar, calcite, pyrite, etc. constitute a sandy mixture. The components of the model are changed from the original two phases of wet clay-sandy mixture into three phases of wet clay-sandy mixture-organic matter. Compared with the traditional model in which a differential equivalent medium theory (DEM model) is adopted to obtain the equivalent elasticity tensor of the two-phase mixture, the model of the invention selects a Backus average formula to obtain the elasticity tensor of the equivalent shale formed by the wet clay-sandy mixture-organic matter three phases.
The concrete steps of the shale gas reservoir formation pressure calculation method according to the invention are explained in detail below.
And acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information.
In one example, the obtaining the wet clay elasticity tensor based on the well log data comprises: based on logging information, acquiring total rock porosity and clay volume content, and acquiring the wet clay elasticity tensor based on the total rock porosity and the clay volume content, wherein the concrete formula is as follows:
Figure BDA0001334890490000101
Figure BDA0001334890490000102
wherein phi and fcRespectively representing the total porosity of the rock and the volume content of the clay, and kappa is the wet clay pore spaceDegree, i.e., the volume fraction of pore fluid in the wet clay;
Figure BDA0001334890490000111
is the elasticity tensor of pure clay; cijFor the elasticity tensor of wet clay, the model assumes that the clay has a transversely isotropic symmetry, whose elasticity tensor can be characterized by five independent parameters:
Figure BDA0001334890490000112
Figure BDA0001334890490000113
the values of the independent parameters are as follows:
Figure BDA0001334890490000114
Figure BDA0001334890490000115
in one example, the obtaining the elasticity tensor of the sandy mixture based on the log data comprises: based on logging information, acquiring sand mixture components, sand mixed component volume content and sand mixed component elastic modulus, and based on the sand mixture components, the sand mixed component volume content and the sand mixed component elastic modulus, calculating through a Voight-reus-Hill model to acquire a sand mixture elasticity tensor, wherein the concrete formula is as follows:
Figure BDA0001334890490000116
Figure BDA0001334890490000117
Figure BDA0001334890490000118
wherein i is the ith sandy mineral, N is the number of types of the sandy minerals, and fiIs the volume content, M, of the i-th sandy mix componentiIs the modulus of elasticity of the ith gritty mix component; the Voigt and reus models provide the upper limit M of the equivalent rock modulus, respectivelyVAnd a lower limit MRThe upper and lower limits are arithmetically averaged to obtain MHThe elastic modulus of the sandy mixture is obtained, and the elasticity tensor of the sandy mixture can be expressed as follows:
Figure BDA0001334890490000121
wherein: cxyK and μ represent the volume modulus and shear modulus of the sandy mix, respectively, as the elasticity tensor of the sandy mix.
And acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture.
In one example, the obtaining the elasticity tensor of the equivalent shale based on the wet clay elasticity tensor and the sandy mixture elasticity tensor comprises: obtaining the elasticity tensor of the equivalent shale formed by the wet clay-sandy mixture-organic matter through Backus average formula calculation based on the elasticity tensor of the wet clay, the elasticity tensor of the sandy mixture and the elasticity tensor of the organic matter,
Figure BDA0001334890490000122
wherein, CeffIs the elastic tensor of the equivalent shale, Cij' are the components of this tensor, which can be found from the elastic components of the wet clay elasticity tensor, the sandy mixture elasticity tensor, and the organic matter elasticity tensor:
Figure BDA0001334890490000123
Figure BDA0001334890490000124
C12'＝C11-<c11>+<c12>，
Figure BDA0001334890490000131
Figure BDA0001334890490000132
C66'＝<c66>
wherein, cijElastic stiffness components representing the elastic tensor of wet clay, the elastic tensor of sandy mixture and the elastic tensor of organic matter< >Indicating a weighted average of its internal properties by volume ratio.
In particular, the bulk modulus K according to the organic mattero＝2.9GPaAnd shear modulus muoThe elasticity tensor matrix for organic matter can be calculated as 2.7 GPa:
Figure BDA0001334890490000133
wherein: coIs the elastic tensor of organic matter, KoAnd muoThe bulk modulus and the shear modulus of organic matter are respectively expressed.
And acquiring the acoustic wave time difference based on the elasticity tensor of the equivalent shale.
In an example, the acoustic wave time difference is obtained based on the elasticity tensor of the equivalent shale, and the specific formula is as follows:
Figure BDA0001334890490000134
DT＝1/Vp (7)
where ρ represents the rock density, C33Of' equivalent shalesThe stiffness component of the elastic tensor, DT, represents the acoustic moveout.
And acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference.
In one example, the obtaining shale gas reservoir formation pressure based on acoustic moveout comprises: the shale gas reservoir stratum pressure is obtained through calculation of Eaton equation through overburden pressure, hydrostatic pressure, acoustic time difference and stratum actual measurement acoustic difference, and the concrete formula is as follows:
Pp＝Pov-(Pov-Ph)(DT/Δt)c (8)
wherein, PpIs shale gas reservoir formation pressure, PovIs overburden pressure, PhThe hydrostatic pressure is adopted, delta t is the actually measured acoustic time difference of the stratum, and c is an Eaton constant;
wherein the overburden pressure PovAnd the hydrostatic pressure PhAll can be solved by density integration, and the calculation formula is as follows:
Figure BDA0001334890490000141
wherein g is the gravity acceleration, h is the burial depth, and rho (z) is the formation water density at the depth z;
Figure BDA0001334890490000142
where g is the gravitational acceleration, h is the burial depth, and ρ (z) is the formation rock density at depth z.
Specifically, the invention provides a method for directly calculating a normal compaction trend line of a shale gas reservoir based on a petrophysical model on the basis of improving a CPS (cyber physical system) model aiming at the limitation of a conventional compaction trend line construction method in pressure prediction of a new exploration area and a non-mudstone section, and further solving a formation pressure through an Eaton equation. Compared with a fitting method based on data driving, the method has the advantages that the dependence on actually measured pressure data can be reduced by introducing the rock physical relationship and calculating the compaction trend line based on model driving, the uncertainty of building the compaction trend line is reduced, the influence of lithology is automatically considered, and finally the accuracy of pressure prediction is improved.
Specifically, the shale gas reservoir stratum pressure calculation method can reduce uncertainty of establishment of a trend line when actually measured pressure data is insufficient, effectively considers the influence of lithology on the trend line, and finally improves the accuracy of pressure prediction.
Example 1
The implementation process of the method is explained by actual logging information of a certain work area and compared with the pressure prediction effect of the traditional method.
Fig. 1 shows a flow chart of a shale gas reservoir formation pressure calculation method according to the present invention. Figures 2a-2c show a schematic representation of the results of a laminate stress factor calculation for a J1 well within a work area, according to one embodiment of the present invention. Fig. 3a-3d show schematic diagrams of the calculation of the prediction of the lamination coefficient of four adjacent wells of a J1 well, respectively, according to one embodiment of the invention.
As shown in fig. 1, 2a, 2b, 2c, 3a, 3b, 3c and 3d, the target zone of the research area is a shale gas reservoir, the obtained pressure information is limited, and only the variation range of the pressure coefficient is known to be [1.2,1.55], and there is a significant abnormal high pressure. In order to construct the NCT based on data fitting, a J1 well drilling a target layer is selected as a correction well, the pressure coefficient of the target layer of the well is assumed to be just 1.2-1.55, the coefficient of the NCT expression is continuously adjusted to enable the error between the predicted formation pressure and the actual measurement data to be minimum at two extreme points of 1.2 and 1.55, and a regression coefficient is obtained. The constructed compaction trend line is indicated by "NCT-fit" (solid gray line in FIG. 2 a). In addition, on the basis of obtaining the mineral composition and physical property parameters of the target layer through well logging interpretation, a compaction trend line is calculated by using the modeling flow shown in FIG. 1 and is represented by 'NCT-model' (a black solid line in FIG. 2 a). Due to the fact that the target layer has abnormal high pressure on the whole, the logging acoustic time difference (a dotted line in figure 2 a) is larger than the normal time difference at the same depth, and therefore the two constructed NCTs are located on the left side of the logging acoustic time difference. The NCT-model can take into account changes in lithology, reflecting more detail than the approximate expression used by the NCT-fit. The solid black and solid grey lines in fig. 2b represent the formation pressure, as constrained by the overburden pressure (dashed line) and hydrostatic pressure (dotted line), based on the NCT-model and NCT-fit calculations, respectively. The solid black and solid gray lines in fig. 2c represent the pressure coefficients, respectively, derived based on the two NCTs described above, converted from the formation pressures in fig. 2 b. It can be seen that part of the pressure data points calculated by the NCT-fit deviate significantly from the measured pressure coefficient interval [1.2,1.55], and the prediction error at the deviation may be caused by the increase of the non-mud mineral content with reference to the mineral component information. And the pressure coefficient prediction result corresponding to the NCT-model is matched with the actually measured pressure region, so that higher prediction accuracy is embodied.
Generally speaking, wells in the same working area and the same pressure system have the same normal acoustic time difference change law, and the same compaction trend line can be used. To verify the stability of the patented method, we used the established NCT-model and NCT-fit directly in the four neighbors of the J1 well for pressure prediction and compared their predicted effects, as shown in FIGS. 3a-3 d. And similarly, the pressure coefficients calculated based on the NCT-model can be matched with the measured pressure interval, and the effect is superior to that of the NCT-fit.
Embodiment mode 2
In this embodiment, there is provided a computer-readable storage medium having a computer program stored thereon according to another aspect of the present invention, the computer-readable storage medium including:
acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information;
acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture;
acquiring acoustic wave time difference based on the elasticity tensor of the equivalent shale;
and acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference.
In one example, the obtaining the wet clay elasticity tensor based on the well log data comprises: based on logging information, acquiring total rock porosity and clay volume content, and acquiring the wet clay elasticity tensor based on the total rock porosity and the clay volume content, wherein the concrete formula is as follows:
Figure BDA0001334890490000161
Figure BDA0001334890490000162
wherein phi and fcRespectively representing the total porosity of the rock and the volume content of the clay, and kappa is the porosity of the wet clay, namely the volume fraction of pore fluid in the wet clay;
Figure BDA0001334890490000163
is the elasticity tensor of pure clay; cijFor the elasticity tensor of wet clay, the model assumes that the clay has a transversely isotropic symmetry, whose elasticity tensor can be characterized by five independent parameters:
Figure BDA0001334890490000171
Figure BDA0001334890490000172
the values of the independent parameters are as follows:
Figure BDA0001334890490000173
Figure BDA0001334890490000174
in one example, the obtaining the elasticity tensor of the sandy mixture based on the log data comprises: based on logging information, acquiring sand mixture components, sand mixed component volume content and sand mixed component elastic modulus, and based on the sand mixture components, the sand mixed component volume content and the sand mixed component elastic modulus, calculating through a Voight-reus-Hill model to acquire a sand mixture elasticity tensor, wherein the concrete formula is as follows:
Figure BDA0001334890490000175
Figure BDA0001334890490000176
Figure BDA0001334890490000177
wherein i is the ith sandy mineral, N is the number of types of the sandy minerals, and fiIs the volume content, M, of the i-th sandy mix componentiIs the modulus of elasticity of the ith gritty mix component; the Voigt and reus models provide the upper limit M of the equivalent rock modulus, respectivelyVAnd a lower limit MRThe upper and lower limits are arithmetically averaged to obtain MHThe elastic modulus of the sandy mixture is obtained, and the elasticity tensor of the sandy mixture can be expressed as follows:
Figure BDA0001334890490000181
wherein: cxyK and μ represent the volume modulus and shear modulus of the sandy mix, respectively, as the elasticity tensor of the sandy mix.
In one example, the obtaining the elasticity tensor of the equivalent shale based on the wet clay elasticity tensor and the sandy mixture elasticity tensor comprises: obtaining the elasticity tensor of the equivalent shale formed by the wet clay-sandy mixture-organic matter through Backus average formula calculation based on the elasticity tensor of the wet clay, the elasticity tensor of the sandy mixture and the elasticity tensor of the organic matter,
Figure BDA0001334890490000182
wherein, CeffIs the elastic tensor of the equivalent shale, Cij' are the components of this tensor, which can be found from the elastic components of the wet clay elasticity tensor, the sandy mixture elasticity tensor, and the organic matter elasticity tensor:
Figure BDA0001334890490000183
Figure BDA0001334890490000184
C12'＝C11-<c11>+<c12>，
Figure BDA0001334890490000185
Figure BDA0001334890490000186
C66'＝<c66>
wherein, cijElastic stiffness components representing the elastic tensor of wet clay, the elastic tensor of sandy mixture and the elastic tensor of organic matter< >Indicating a weighted average of its internal properties by volume ratio.
It will be appreciated by persons skilled in the art that the above description of embodiments of the invention is intended only to illustrate the benefits of embodiments of the invention and is not intended to limit embodiments of the invention to any examples given.
Having described embodiments of the present invention, the foregoing description is intended to be exemplary, not exhaustive, and not limited to the embodiments disclosed. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the described embodiments. The terminology used herein is chosen in order to best explain the principles of the embodiments, the practical application, or improvements made to the technology in the marketplace, or to enable others of ordinary skill in the art to understand the embodiments disclosed herein.

Claims (9)

1. A shale gas reservoir formation pressure calculation method comprises the following steps:
acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information;
acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture;
acquiring acoustic wave time difference based on the elasticity tensor of the equivalent shale;
acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference;
wherein, based on the elasticity tensor of the equivalent shale, the acoustic wave time difference is obtained, and the concrete formula is as follows:
Figure FDA0003001591010000011
DT＝1/Vp (7)
where ρ represents the rock density, C33' is the stiffness component of the elastic tensor of the equivalent shale, DT represents the acoustic moveout;
the elasticity tensor of the wet clay mixture is in a linear negative correlation with the porosity of the wet clay and is not related to the mineral components of the clay, so that the elasticity tensor of the wet clay is determined by the single porosity of the wet clay, the elasticity tensor of the whole shale is determined by the porosity of the wet clay and the volume content of the sand mixture, meanwhile, the change of the formation pressure only influences the opening and closing of soft pores in the rock, the influence of the soft pores on the total porosity is ignored, so that the two factors influencing the elasticity tensor of the shale are not influenced by abnormal pressure, and the speed or the time difference of the rock under the normal compaction condition is calculated by a model;
the clay and pore fluid form a wet clay mixture, quartz, feldspar, calcite and pyrite hard minerals form a sandy mixture, the model comprises the components of a wet clay-sandy mixture-organic matter three phase, and the elasticity tensor of equivalent shale formed by the wet clay-sandy mixture-organic matter three phase is obtained by selecting a Backus average formula.
2. The shale gas reservoir formation pressure calculation method of claim 1, wherein said obtaining a wet clay elasticity tensor based on well log data comprises: based on logging information, acquiring total rock porosity and clay volume content, and acquiring the wet clay elasticity tensor based on the total rock porosity and the clay volume content, wherein the concrete formula is as follows:
Figure FDA0003001591010000021
Figure FDA0003001591010000022
wherein phi and fcRespectively representing the total porosity of the rock and the volume content of the clay, and kappa is the porosity of the wet clay, namely the volume fraction of pore fluid in the wet clay;
Figure FDA0003001591010000023
is the elasticity tensor of pure clay; cijFor the elasticity tensor of wet clay, the model assumes that the clay has a transversely isotropic symmetry, whose elasticity tensor can be characterized by five independent parameters:
Figure FDA0003001591010000024
Figure FDA0003001591010000025
the values of the independent parameters are as follows:
Figure FDA0003001591010000026
Figure FDA0003001591010000027
3. the shale gas reservoir formation pressure calculation method of claim 1, wherein said obtaining a sand mixture elasticity tensor based on well log data comprises: based on logging information, acquiring components of a sandy mixture, volume contents of the components of the sandy mixture and elastic moduli of the components of the sandy mixture, and calculating through a Voight-Reuss-Hill model to acquire an elasticity tensor of the sandy mixture according to the components of the sandy mixture, the volume contents of the components of the sandy mixture and the elastic moduli of the components of the sandy mixture, wherein the specific formula is as follows:
Figure FDA0003001591010000028
Figure FDA0003001591010000031
Figure FDA0003001591010000032
wherein q is the q-th sandy mineral, N is the number of kinds of sandy minerals, fqIs the volume content of the q-th sandy mixture component, MqIs the modulus of elasticity of the qth sandy mix component; the Voigt and reus models provide the upper limit M of the equivalent rock modulus, respectivelyVAnd a lower limit MRThe upper and lower limits are arithmetically averaged to obtain MHThe elastic modulus of the sandy mixture is obtained, and the elasticity tensor of the sandy mixture can be expressed as follows:
Figure FDA0003001591010000033
wherein: cxyK and μ represent the bulk modulus and shear modulus of the sandy blend, respectively, as the elasticity tensor of the sandy blend.
4. The shale gas reservoir formation pressure calculation method of claim 3, wherein said obtaining an elasticity tensor of an equivalent shale based on said wet clay elasticity tensor and said sandy mixture elasticity tensor comprises: obtaining the elasticity tensor of the equivalent shale formed by the wet clay-sandy mixture-organic matter through the Backus average formula calculation based on the elasticity tensor of the wet clay, the elasticity tensor of the sandy mixture and the elasticity tensor of the organic matter,
Figure FDA0003001591010000041
wherein, CeffIs the elastic tensor of the equivalent shale, Cij' are the components of this tensor, which can be found from the elastic stiffness components of the wet clay elasticity tensor, sand mixture elasticity tensor, organic matter elasticity tensor:
Figure FDA0003001591010000042
Figure FDA0003001591010000043
C12'＝C11-<c11>+<c12>，
Figure FDA0003001591010000044
Figure FDA0003001591010000045
C66'＝<c66>
wherein, cijElastic stiffness components representing the elastic tensor of wet clay, the elastic tensor of sandy mixture and the elastic tensor of organic matter<>Indicating a weighted average of its internal properties by volume ratio.
5. The shale gas reservoir formation pressure calculation method of claim 1, wherein said obtaining shale gas reservoir formation pressure based on acoustic moveout comprises: the shale gas reservoir stratum pressure is obtained by computing according to Eaton equation through overburden pressure, hydrostatic pressure, acoustic time difference and stratum actual measurement acoustic time difference, and the concrete formula is as follows:
Pp＝Pov-(Pov-Ph)(DT/Δt)c (8)
wherein, PpIs shale gas reservoir formation pressure, PovIs overburden pressure, PhThe hydrostatic pressure is adopted, delta t is the actually measured acoustic time difference of the stratum, and c is an Eaton constant;
wherein the overburden pressure PovAnd the hydrostatic pressure PhAll can be solved by density integration, and the calculation formula is as follows:
Figure FDA0003001591010000051
wherein g is the gravity acceleration, h is the burial depth, and rho (z) is the formation water density at the depth z;
Figure FDA0003001591010000052
where g is the gravitational acceleration, h is the burial depth, and ρ (z)' is the formation rock density at depth z.
6. A computer-readable storage medium having a computer program stored thereon, wherein the computer-readable storage medium comprises:
acquiring the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture based on the logging information;
acquiring the elasticity tensor of the equivalent shale based on the elasticity tensor of the wet clay and the elasticity tensor of the sandy mixture;
acquiring acoustic wave time difference based on the elasticity tensor of the equivalent shale;
acquiring the formation pressure of the shale gas reservoir based on the acoustic wave time difference;
wherein, based on the elasticity tensor of the equivalent shale, the acoustic wave time difference is obtained, and the concrete formula is as follows:
Figure FDA0003001591010000053
DT＝1/Vp (7)
where ρ represents the rock density, C33' is the stiffness component of the elastic tensor of the equivalent shale, DT represents the acoustic moveout;
the elasticity tensor of the wet clay mixture is in a linear negative correlation with the porosity of the wet clay and is not related to the mineral components of the clay, so that the elasticity tensor of the wet clay is determined by the single porosity of the wet clay, the elasticity tensor of the whole shale is determined by the porosity of the wet clay and the volume content of the sand mixture, meanwhile, the change of the formation pressure only influences the opening and closing of soft pores in the rock, the influence of the soft pores on the total porosity is ignored, so that the two factors influencing the elasticity tensor of the shale are not influenced by abnormal pressure, and the speed or the time difference of the rock under the normal compaction condition is calculated by a model;
the clay and pore fluid form a wet clay mixture, quartz, feldspar, calcite and pyrite hard minerals form a sandy mixture, the model comprises the components of a wet clay-sandy mixture-organic matter three phase, and the elasticity tensor of equivalent shale formed by the wet clay-sandy mixture-organic matter three phase is obtained by selecting a Backus average formula.
7. The computer-readable storage medium of claim 6, wherein the obtaining the wet clay elasticity tensor based on the well log data comprises: based on logging information, acquiring total rock porosity and clay volume content, and acquiring the wet clay elasticity tensor based on the total rock porosity and the clay volume content, wherein the concrete formula is as follows:
Figure FDA0003001591010000061
Figure FDA0003001591010000062
wherein phi and fcRespectively representing the total porosity of the rock and the volume content of the clay, and kappa is the porosity of the wet clay, namely the volume fraction of pore fluid in the wet clay;
Figure FDA0003001591010000063
is the elasticity tensor of pure clay; cijFor the elasticity tensor of wet clay, the model assumes that the clay has a transversely isotropic symmetry, whose elasticity tensor can be characterized by five independent parameters:
Figure FDA0003001591010000064
Figure FDA0003001591010000065
the values of the independent parameters are as follows:
Figure FDA0003001591010000066
Figure FDA0003001591010000071
8. the computer-readable storage medium of claim 6, wherein the obtaining the sand mixture elasticity tensor based on the well log data comprises: based on logging information, acquiring components of a sandy mixture, volume contents of the components of the sandy mixture and elastic moduli of the components of the sandy mixture, and calculating through a Voight-Reuss-Hill model to acquire an elasticity tensor of the sandy mixture according to the components of the sandy mixture, the volume contents of the components of the sandy mixture and the elastic moduli of the components of the sandy mixture, wherein the specific formula is as follows:
Figure FDA0003001591010000072
Figure FDA0003001591010000073
Figure FDA0003001591010000074
wherein q is the q-th sandy mineral, N is the number of kinds of sandy minerals, fqIs the volume content of the q-th sandy mixture component, MqIs the modulus of elasticity of the qth sandy mix component; the Voigt and reus models provide the upper limit M of the equivalent rock modulus, respectivelyVAnd a lower limit MRThe upper and lower limits are arithmetically averaged to obtain MHThe elastic modulus of the sandy mixture is obtained, and the elasticity tensor of the sandy mixture can be expressed as follows:
Figure FDA0003001591010000075
wherein: cxyK and μ represent the bulk modulus and shear modulus of the sandy blend, respectively, as the elasticity tensor of the sandy blend.
9. The computer-readable storage medium of claim 6, wherein the deriving an elasticity tensor for an equivalent shale based on the wet clay elasticity tensor and the sandy-mixture elasticity tensor comprises: obtaining the elasticity tensor of the equivalent shale formed by the wet clay-sandy mixture-organic matter through the Backus average formula calculation based on the elasticity tensor of the wet clay, the elasticity tensor of the sandy mixture and the elasticity tensor of the organic matter,
Figure FDA0003001591010000081
wherein, CeffIs the elastic tensor of the equivalent shale, Cij' are the components of this tensor, which can be found from the elastic stiffness components of the wet clay elasticity tensor, sand mixture elasticity tensor, organic matter elasticity tensor:
Figure FDA0003001591010000082
Figure FDA0003001591010000083
C12'＝C11-<c11>+<c12>，
Figure FDA0003001591010000084
Figure FDA0003001591010000085
C66'＝<c66>
wherein, cijIndicating wet clay bombElastic stiffness component of tensor, elastic tensor of sandy mixture and elastic tensor of organic matter<>Indicating a weighted average of its internal properties by volume ratio.
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