CN109505590B - Shale gas reservoir pressure determination method and computer readable storage medium - Google Patents
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- 238000003860 storage Methods 0.000 title claims abstract description 11
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- 238000005056 compaction Methods 0.000 claims abstract description 42
- 230000008859 change Effects 0.000 claims abstract description 14
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- 229930195733 hydrocarbon Natural products 0.000 claims description 38
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- 238000006243 chemical reaction Methods 0.000 claims description 21
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- 239000012530 fluid Substances 0.000 claims description 7
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- 238000007906 compression Methods 0.000 claims description 6
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 claims description 5
- 238000009933 burial Methods 0.000 claims description 5
- 239000001257 hydrogen Substances 0.000 claims description 5
- 229910052739 hydrogen Inorganic materials 0.000 claims description 5
- 238000001179 sorption measurement Methods 0.000 claims description 5
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- 238000011156 evaluation Methods 0.000 abstract description 23
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- 229910052900 illite Inorganic materials 0.000 description 2
- VGIBGUSAECPPNB-UHFFFAOYSA-L nonaaluminum;magnesium;tripotassium;1,3-dioxido-2,4,5-trioxa-1,3-disilabicyclo[1.1.1]pentane;iron(2+);oxygen(2-);fluoride;hydroxide Chemical compound [OH-].[O-2].[O-2].[O-2].[O-2].[O-2].[F-].[Mg+2].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[K+].[K+].[K+].[Fe+2].O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2 VGIBGUSAECPPNB-UHFFFAOYSA-L 0.000 description 2
- 239000000047 product Substances 0.000 description 2
- 238000000197 pyrolysis Methods 0.000 description 2
- 238000012937 correction Methods 0.000 description 1
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- SWQJXJOGLNCZEY-UHFFFAOYSA-N helium atom Chemical compound [He] SWQJXJOGLNCZEY-UHFFFAOYSA-N 0.000 description 1
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- 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
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- E—FIXED CONSTRUCTIONS
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- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
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Abstract
The invention discloses a method for determining shale gas reservoir pressure and a computer readable storage medium, comprising the following steps: obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg(ii) a Determining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining the reservoir background pressure P formed by compactionp‑inorg(ii) a Based on organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp‑org(ii) a Reservoir background pressure P formed by superposition of compactionp‑inorgAdditional pore pressure P generated by pressurization with kerogenp‑orgDetermining shale gas reservoir pressure Pp. The invention has the advantages that: the key parameters in the invention can be obtained through logging information, so that the method has strong operability and reliability, effectively improves the shale reservoir pressure logging evaluation precision, and has great practical value in shale gas exploration.
Description
Technical Field
The invention relates to the field of unconventional oil and gas exploration and development, in particular to a shale gas reservoir pressure determination method and a computer readable storage medium.
Background
The abnormal pressure of the oil and gas reservoir is closely related to the generation, storage and exploitation of oil and gas, and the cause mechanism of the abnormal pressure of the oil and gas reservoir comprises the following components: under-compaction, fluid volume increase (hydrothermal expansion, mineral conversion, hydrocarbon production), fluid motion and buoyancy, pressure transfer, formation effects, etc., abnormal pressure formation is often a multifactorial mixing cause. Nowadays, accurate evaluation of abnormal pressure becomes a key and difficult problem in shale gas reservoir exploration and development, and needs to be solved urgently. The shale gas reservoir usually needs to undergo the actions of deep burying, diagenesis, hydrocarbon generation, hydrocarbon discharge, reservoir formation, structure lifting and the like, so that an abnormally high pressure reservoir with higher gas saturation can be formed, and the additional hydrocarbon generation pressurization is a main cause mechanism of abnormal high pressure of the shale gas reservoir under the background of under-compaction/structure lifting. The Filipetone method (Filipetone W R. timing of formation parameters and The prediction of compression from semiconductor data [ J ]. The SEG Symposium on geomessure students, 1982(10):17-21), eaton formula (Eaton B. graphical methods predictions World wide [ J ]. World Oil,1976:183(1):51-56) and improved methods of the two methods (Liu Sha, Zhang Wan Xuanfu, etc.. third series abnormal formation pressure analysis [ J ]. Petroleum institute under northern hollow of Liaoxi, 1993, 14 (1): 14-24), Yunmei thick method (Yunmei thick. earthquake formation pressure prediction [ J ]. Oil geophysical exploration, 1996, 31 (4): 575 586) and the like) mainly based on the relation between longitudinal wave time difference (reciprocal of longitudinal wave velocity) and abnormal pressure, solve the pressure evaluation problem, and can provide more accurate evaluation results for the abnormal pressure evaluation problem of compaction causes. But for the abnormal pressure reservoir mixed with other causes, the method has lower evaluation result precision. The method comprises the steps of predicting abnormal formation pressure [ C ] by utilizing a geophysical technology, establishing a new pressure calculation formula by constructing a method for a rock-apparent pressure and a pressure correction coefficient through an oil-gas reservoir formation theory and exploration and development technology in 2014 and 7 so as to solve the problem that when formation pressure evaluation is directly carried out by simply utilizing wave impedance (the difference between rock volume density and sound wave time), the deviation between a calculation result and actual formation pressure is large, but the method has high difficulty in determining key parameters during actual application and is difficult to popularize and apply across regions. The method for predicting the formation pressure by combining the longitudinal and transverse wave velocities and the application [ J ] natural gas geoscience 2015, 26 (2): 367 and 370) is used for establishing an elastic parameter combination method, and a shale gas reservoir pressure prediction model is deduced by using the relation between the longitudinal and transverse wave velocities and the effective stress, but the method is based on an elementary elastic theory and an ideal fluctuation equation, the assumed condition is large in difference with the actual geological characteristics, and the prediction result is not high. The fundamental reason why the evaluation result of the shale gas reservoir is poor or the application difficulty is high is that the abnormal pressure evaluation problem cannot be solved from the analysis of the shale gas reservoir pressure cause mechanism.
Therefore, it is necessary to develop a pore pressure determination method that uses the shale gas reservoir pressure cause and pore preservation relationship as breakthrough and reflects the comprehensive impact of the compaction effect and the hydrocarbon generation effect, so as to improve the shale gas reservoir pressure evaluation accuracy.
The information disclosed in this background section is only for enhancement of understanding of the general background of the invention and should not be taken as an acknowledgement or any form of suggestion that this information forms the prior art already known to a person skilled in the art.
Disclosure of Invention
The invention provides a shale gas reservoir pressure determination method and a computer readable storage medium, which are based on analysis of shale pore components and pressure cause relationship, establish the shale gas reservoir pressure determination method and improve the evaluation precision of the shale gas reservoir pressure.
According to an aspect of the present invention, a method for determining a shale gas reservoir pressure is provided, including:
obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg；
Determining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining the reservoir background pressure P formed by compactionp-inorg；
Based on the organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-org；
A background pressure P of the reservoir formed by superposing the compactionp-inorgAdditional pore pressure P generated by pressurization with said kerogenp-orgDetermining shale gas reservoir pressure Pp。
Preferably, the shale reservoir is a type I kerogen reservoir.
Further, by utilizing the normal compaction trend section of the inorganic pores in the whole well section, the compaction coefficient C and the surface inorganic porosity are determined by the formula (1)
Wherein C is a compaction coefficient and is dimensionless;
h is the reservoir burial depth in m.
Further, the compaction creates a reservoir background pressure Pp-inorgComprises the following steps:
where ρ isWIn terms of pore fluid density, in kg/m3；
ρbDensity of overburden, unit kg/m3；
g is gravity acceleration in m/s2。
Preferably, based on the organic porosity ΦorgDetermining an additional pore pressure P resulting from said kerogen-generating hydrocarbon pressurizationp-orgComprises the following steps:
determination of the kerogen conversion and the organic porosity PhiorgThe relationship of (1);
based on kerogen conversion and organic porosity phiorgDetermining the additional pore pressure P resulting from the pressurization of said kerogenp-org。
Further, the kerogen conversion and the organic porosity Φ were determined using the following formula (3)orgThe relationship of (1):
wherein, Δ F ═ F2-F1The amount of change in the conversion rate of kerogen before and after hydrocarbon generation;
Φorgis organic porosity in v/v units;
Pp-orgadditional pore pressure in Mpa;
CTOCis the kerogen compression coefficient in Mpa-1；
HI is the hydrogen index of kerogen in g/g.
Further wherein said formula (3) is determined by the steps of:
the volume of kerogen consumed and the volume of remaining kerogen are respectively set as VTOCA，VTOCB：
VTOCA＝VTOC·HI·ΔF (4)
VTOCB＝VTOC·(1-HI·ΔF) (5)
In the formula, VTOCIs the original organic matter volume in m3；
The remaining kerogen is compressed under high pressure and reduced in volume by Δ VTOCBUnit m of3：
ΔVTOCB＝VTOCB·CTOC.Pp-org＝VTOC·(1-HI·ΔF)·CTOC.Pp-org (6)
The organic porosity phiorgExpressed as:
the above formula (7) is collated to obtain the relation (3) of the kerogen conversion rate and the organic porosity.
Further, the additional pore pressure P formed by pressurization of the kerogenp-orgComprises the following steps:
in the formula (I), the compound is shown in the specification,
wherein epsilon is the natural gas loss rate and is dimensionless;
ρTOCdensity of kerogen before hydrocarbon generation in kg/m3；
The mass ratio of free state and adsorption state of the natural gas after alpha is hydrocarbon, unit w/w;
ρfreis the density of free gas in kg/m3；
ρadsIn kg/m as density of adsorbed gas3。
Further wherein said formula (8) is determined by the steps of:
the total mass M of the natural gas generated by the kerogen hydrocarbon generationgComprises the following steps:
Mg＝VTOCA·ρTOC·(1-ε) (9)
sum of product V of free gas and adsorbed gas in organic poresgComprises the following steps:
the organic porosity phiorgExpressed as:
substituting equation (3) into this equation, there are:
the additional pore pressure P resulting from the hydrocarbon generation can be determined by working up the above formula (12)p-orgRelation (8).
Preferably, the shale gas reservoir pressure PpComprises the following steps:
Pp＝Pp-inorg+Pp-org (13)。
according to another aspect of the invention, a computer-readable storage medium is proposed, on which a computer program is stored, wherein the program realizes the following steps when executed by a processor:
obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg；
Determining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining the reservoir background pressure P formed by compactionp-inorg；
Based on the organic porosity ΦorgDetermination of kerogen increaseAdditional pore pressure P of the pressp-org；
A background pressure P of the reservoir formed by superposing the compactionp-inorgAdditional pore pressure P generated by pressurization with said kerogenp-orgDetermining shale gas reservoir pressure Pp。
According to the shale gas reservoir pressure determining method and the computer readable storage medium, the advantages are that: the key parameters in the invention can be obtained through logging information, so that the method has strong operability and reliability, effectively improves the shale reservoir pressure logging evaluation precision, and has great practical value in shale gas exploration.
The method of the present invention has 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.
Drawings
The above and other objects, features and advantages of the present invention will become more apparent by describing in more detail exemplary embodiments thereof with reference to the attached drawings, in which like reference numerals generally represent like parts.
Fig. 1 shows a flow chart of the steps of a shale gas reservoir pressure determination method according to the present invention.
Figure 2 shows a schematic view of the kerogen hydrocarbon pressurization principle according to the invention.
Fig. 3 shows an effect graph of a shale gas reservoir pressure logging evaluation method according to an exemplary embodiment of the present 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.
The invention is mainly suitable for shale gas reservoirs, which mainly use I-type kerogen, and the final product of kerogen pyrolysis/pyrolysis is dry gas.
As shown in fig. 1, a method for determining a shale gas reservoir pressure according to the present invention includes:
obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg；
Determining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining the reservoir background pressure P formed by compactionp-inorg；
Based on organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-org；
Reservoir background pressure P formed by superposition of compactionp-inorgAdditional pore pressure P generated by pressurization with kerogenp-orgDetermining shale gas reservoir pressure Pp。
As a preferred scheme, the change rule of inorganic pores along with the burial depth is analyzed, the normal compaction trend section of the inorganic pores in the whole well section is utilized, and the compaction coefficient C and the surface inorganic porosity are determined according to the formula (1)
Wherein H is the reservoir burial depth and the unit is m.
According to the determined compaction coefficient C (dimensionless) and the surface inorganic porosity
Further determining the background pressure P of the reservoir formed by compactionp-inorgIn Mpa.
Wherein the compaction is carried outBackground pressure P of reservoir formed by actionp-inorgComprises the following steps:
in the formula, ρWIn terms of pore fluid density, in kg/m3；
ρbDensity of overburden, unit kg/m3；
g is the acceleration of gravity in m/s2；
H is the reservoir burial depth and is expressed in m.
Preferably, based on the organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-orgIs an important feature of the solution of the invention. Additional pore pressure P due to the solution of kerogen-derived hydrocarbon pressurizationp-orgThe method firstly determines the relationship between the kerogen conversion rate and the organic pore development degree and further can obtain the kerogen conversion rate according to the organic porosity phiorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-org。
The conversion rate of kerogen and the degree of organic pore development phi were determined using the following formulaorgThe relationship is as follows:
wherein, Δ F ═ F2-F1The amount of change in the conversion rate of kerogen before and after hydrocarbon generation; phiorgIs organic porosity in v/v units; pp-orgAdditional pore pressure in Mpa; cTOCIs the kerogen compression coefficient in Mpa-1HI is the hydrogen index of kerogen in g/g.
Figure 2 shows a schematic view of the kerogen hydrocarbon pressurization principle according to the invention. As shown in FIG. 2, TOCAKerogen, TOC, indicative of Hydrocarbon consumptionBIndicating the residueThe rest of the kerogen. GlostRepresenting the portion of gas lost by the expulsion of hydrocarbons after the formation of hydrocarbons, the remaining hydrocarbons being in the free state (G)fre) Or in an adsorbed state (G)ads) The kerogen is added into the shale gas reservoir, so that the pressure in the shale gas reservoir is increased, and the residual kerogen is compressed by abnormal high pressure, so that the volume of the kerogen is reduced after hydrocarbon generation.
According to the type I kerogen hydrocarbon generation pressurization principle shown in figure 2, the hydrocarbon generation consumption and the residual kerogen volume are respectively VTOCA，VTOCB：
VTOCA＝VTOC·HI·ΔF (4)
VTOCB＝VTOC·(1-HI·ΔF) (5)
In the formula, VTOCIs the original organic matter volume in m3HI is kerogen hydrogen index,. DELTA.F ═ F2-F1The amount of change in the conversion rate of kerogen before and after hydrocarbon generation.
The residual kerogen is compressed under abnormally high pressure and reduced in volume by Δ VTOCB：
ΔVTOCB＝VTOCB·CTOC.Pp-org＝VTOC·(1-HI·ΔF)·CTOC.Pp-org (6)
In the formula Pp-orgAdditional pore pressure, Mpa; cTOCIs the kerogen compression factor, Mpa-1。
Organic porosity phiorgCan be expressed as:
the conversion rate of kerogen and the organic porosity phi can be determined by finishing the above formula (7)orgThe degree of development is given in relation (3).
Next, based on the relationship between the conversion of kerogen and the organic porosity, the organic porosity can be used to determine an additional pore pressure P resulting from the pressurization of the kerogen with the hydrocarbonp-org：
In the formula (I), the compound is shown in the specification,
the above-described relationship determination method is as follows:
total mass M of natural gas from kerogen formation type I in FIG. 2gComprises the following steps:
Mg＝VTOCA·ρTOC·(1-ε) (9)
in the formula, epsilon is the natural gas loss rate and is dimensionless; rhoTOCDensity of kerogen before hydrocarbon generation, kg/m3. The natural gas respectively exists in two states of free gas and adsorption gas after hydrocarbon generation, the mass ratio of the natural gas to the adsorption gas is alpha, and the sum V of the products of the free gas and the adsorption gas in the organic pores isgComprises the following steps:
ρfreand rhoadsThe density of free gas and the density of adsorbed gas are kg/m3；
The organic porosity phiorgAnd can be represented as:
substituting equation (3) into this equation, there are:
the additional pore pressure P resulting from the hydrocarbon generation can be determined by working up the above formula (12)p-orgRelation (8).
Preferably, the first and second electrodes are formed of a metal,determining shale gas reservoir pressure P using the equationp：
Pp＝Pp-inorg+Pp-org (13)。
The key data in the steps can be directly obtained through logging data, so that the method has high operability and reliability, and can effectively improve the shale reservoir pressure evaluation precision.
A computer-readable storage medium according to the invention, on which a computer program is stored, wherein the program realizes the following steps when executed by a processor:
obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg；
Determining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining the reservoir background pressure P formed by compactionp-inorg；
Based on organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-org；
Reservoir background pressure P formed by superposition of compactionp-inorgAdditional pore pressure P generated by pressurization with kerogenp-orgDetermining shale gas reservoir pressure Pp。
Examples
Fig. 1 shows a flow chart of the steps of a shale gas reservoir pressure determination method according to the present invention.
The invention discloses a method for determining shale gas reservoir pressure, which comprises the following steps:
obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg；
Determining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining the reservoir background pressure P formed by compactionp-inorg；
Based on organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-org；
Reservoir background pressure P formed by superposition of compactionp-inorgAdditional pore pressure P generated by pressurization with kerogenp-orgDetermining shale gas reservoir pressure Pp。
The method is applied to carry out reservoir pressure logging evaluation on the shale gas well to be tested in a certain area.
Fig. 3 shows an effect graph of a shale gas reservoir pressure logging evaluation method according to an exemplary embodiment of the present invention.
According to the logging information, the organic porosity and the inorganic porosity (shown in the 4 th path of the figure 3) of the shale gas well to be tested in the local area can be determined, the organic porosity and the inorganic porosity can be tested by using the core helium total porosity testing information (shown in the 5 th path of the figure 3), and further, the shale gas reservoir pressure is determined by using the pressure evaluation model and method established by the invention.
Firstly, evaluating the background pressure of a reservoir formed by compaction by utilizing the evaluation result of inorganic porosity and the formula (2) (as shown in a 6 th path of a figure 3); secondly, the organic porosity evaluation result and the formula (4) are used to evaluate the hydrocarbon generation pressure formed by pressurization of the kerogen with the respective dissipation rates of 63%, 65% and 67% in 3 groups (as shown in the 7 th path in FIG. 3); finally, evaluation is carried out by using the formula (5) to obtain 3 groups of shale gas reservoir pressures (as shown in fig. 3, lane 8 and curve) under the conditions that the loss rates are 63%, 65% and 67%, respectively. And comparing the measured pressure with the measured pressure at the 2410 position of the shale gas well to be measured in the area (as shown in the 8 th path in fig. 3, a round dot), wherein the evaluation result of the reservoir pressure is consistent with the measured pressure under the condition that the loss rate is 65%, so that the evaluation result of the reservoir pressure of the shale gas well to be measured in the area can be determined under the condition that the reservoir pressure is 65% of the loss rate (as shown in the 8 th path in fig. 3, a black solid line).
Because the relative content of illite and the total hydrocarbon content of reservoir drilling have a good indication effect on the reservoir pressure distribution, the reservoir pressure evaluation result can be verified by using the data.
The comparison result shows that the relative content of the X-diffraction illite of the shale gas well core to be detected in the area has good consistency with the reservoir pressure prediction result (as shown in the 9 th path of the figure 3); the drilling total hydrocarbon content except 2342.5m is influenced by interference factors such as drilling fluid return delay and the like, and the reservoir fluid pressure cannot be accurately reflected, and besides, the 2342.5m is matched with the reservoir pressure curve variation trend evaluated by the research by the variation trend of the deep well section total hydrocarbon content (as shown in a 10 th track in figure 3).
Having described embodiments of the present invention, the foregoing description is intended to be exemplary, not exhaustive, and not limited to the disclosed embodiments. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the illustrated 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 (8)
1. A method of determining shale gas reservoir pressure, comprising:
obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg；
According to the inorganic porosity phiinorgDetermining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining reservoir background pressure P formed by compactionp-inorg；
Based on the organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-org；
A background pressure P of the reservoir formed by superposing the compactionp-inorgAdditional pore pressure P generated by pressurization with said kerogenp-orgDetermining shale gas reservoir pressure Pp；
Wherein based on the organic porosity ΦorgDetermining an additional pore pressure P resulting from said kerogen-generating hydrocarbon pressurizationp-orgComprises the following steps:
determination of the kerogen conversion and the organic porosity PhiorgThe relationship of (1);
based on the kerogen conversionAnd organic porosity phiorgDetermining the additional pore pressure P resulting from the pressurization of said kerogenp-org；
Wherein the kerogen conversion and organic porosity Φ are determined using the following formula (3)orgThe relationship of (1):
wherein, Δ F ═ F2-F1The amount of change in the conversion rate of kerogen before and after hydrocarbon generation;
Φorgis organic porosity in v/v units;
Pp-orgadditional pore pressure in Mpa;
CTOCis the kerogen compression coefficient in Mpa-1；
HI is the hydrogen index of kerogen in g/g.
2. The shale gas reservoir pressure determination method of claim 1, wherein the compaction coefficient C and the surface inorganic porosity are determined by equation (1) using the inorganic pore normal compaction trend section in the whole wellbore section
Wherein C is a compaction coefficient and is dimensionless;
h is the reservoir burial depth in m.
3. The shale gas storage of claim 2Method for determining formation pressure, wherein the compaction forms a reservoir background pressure Pp-inorgComprises the following steps:
where ρ isWIn terms of pore fluid density, in kg/m3；
ρbDensity of overburden, unit kg/m3；
g is gravity acceleration in m/s2。
4. The shale gas reservoir pressure determination method of claim 1, wherein said equation (3) is determined by:
the volume of kerogen consumed and the volume of remaining kerogen are respectively set as VTOCA，VTOCB：
VTOCA＝VTOC·HI·ΔF (4)
VTOCB＝VTOC·(1-HI·ΔF) (5)
In the formula, VTOCIs the original organic matter volume in m3；
The remaining kerogen is compressed under high pressure and reduced in volume by Δ VTOCBUnit m of3：
ΔVTOCB＝VTOCB·CTOC.Pp-org＝VTOC·(1-HI·ΔF)·CTOC.Pp-org (6)
The organic porosity phiorgExpressed as:
the kerogen conversion and the organic porosity phi obtained by the above formula (7) are arrangedorgThe relational expression (3).
5. The method of claim 1The shale gas reservoir pressure of (1), wherein the additional pore pressure P formed by pressurization of the kerogen isp-orgComprises the following steps:
in the formula (I), the compound is shown in the specification,
wherein epsilon is the natural gas loss rate and is dimensionless;
ρTOCdensity of kerogen before hydrocarbon generation in kg/m3；
The mass ratio of free state and adsorption state of the natural gas after alpha is hydrocarbon, unit w/w;
ρfreis the density of free gas in kg/m3；
ρadsIn kg/m as density of adsorbed gas3。
6. The shale gas reservoir pressure determination method of claim 5, wherein said formula (8) is determined by:
the total mass M of the natural gas generated by the kerogen hydrocarbon generationgComprises the following steps:
Mg＝VTOCA·ρTOC·(1-ε) (9)
sum of product V of free gas and adsorbed gas in organic poresgComprises the following steps:
the organic porosity phiorgExpressed as:
substituting equation (3) into this equation, there are:
the additional pore pressure P resulting from the hydrocarbon generation can be determined by working up the above formula (12)p-orgRelation (8).
7. The shale gas reservoir pressure determination method of claim 1, wherein said shale gas reservoir pressure PpComprises the following steps:
Pp＝Pp-inorg+Pp-org (13)。
8. a computer-readable storage medium, on which a computer program is stored, wherein the program, when executed by a processor, performs the steps of:
obtaining shale gas reservoir inorganic porosity phi according to logging data informationinorgAnd organic porosity Φorg；
According to the inorganic porosity phiinorgDetermining normal compaction trend by using the change rule of stratum inorganic pores along with the buried depth, and then determining reservoir background pressure P formed by compactionp-inorg；
Based on the organic porosity ΦorgDetermination of additional pore pressure P resulting from pressurization of kerogenp-org；
A background pressure P of the reservoir formed by superposing the compactionp-inorgAdditional pore pressure P generated by pressurization with said kerogenp-orgDetermining shale gas reservoir pressure Pp；
Wherein based on the organic porosity ΦorgDetermining an additional pore pressure P resulting from said kerogen-generating hydrocarbon pressurizationp-orgStep bagComprises the following steps:
determination of the kerogen conversion and the organic porosity PhiorgThe relationship of (1);
based on the kerogen conversion and organic porosity ΦorgDetermining the additional pore pressure P resulting from the pressurization of said kerogenp-org；
Wherein the kerogen conversion and organic porosity Φ are determined using the following formula (3)orgThe relationship of (1):
wherein, Δ F ═ F2-F1The amount of change in the conversion rate of kerogen before and after hydrocarbon generation;
Φorgis organic porosity in v/v units;
Pp-orgadditional pore pressure in Mpa;
CTOCis the kerogen compression coefficient in Mpa-1；
HI is the hydrogen index of kerogen in g/g.
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