CN110672813B - Shale gas content calculation method - Google Patents
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Abstract
The invention provides a shale gas content calculation method, and belongs to the field of shale exploration and development. The method comprises the steps of firstly collecting experimental data, then inputting the collected experimental data into a shale gas content calculation model to obtain shale gas content under reservoir conditions, or inputting the collected experimental data into the shale gas content calculation model to obtain a curve of pressure and shale gas content, and then obtaining the shale gas content under the reservoir conditions from the curve. The method can quickly obtain the shale gas content, has simple and convenient process, easily obtains the used basic data, can obviously reduce the time and financial cost for obtaining the shale gas content, can improve the calculation precision of the gas content, and has wide application range.
Description
Technical Field
The invention belongs to the field of shale exploration and development, and particularly relates to a shale gas content calculation method.
Background
At present, the gas content of shale is generally obtained by a method of a field pressure-maintaining coring test, the gas content of shale under reservoir conditions needs to be reversely solved by using field desorption data, but part of gas content can be lost before a rock core is put into a desorption device, the size of the lost gas and the loss rule can be influenced by various factors such as a coring mode, a measuring method, an estimating method and the like, and an accurate method is not used for calculating the part of the lost gas; in addition, the time and financial cost of the field test method is high, and the gas content of a large number of rock samples cannot be rapidly obtained. Logging and nuclear magnetic resonance methods usually correct test parameters by using data obtained by a desorption method, so that the logging and nuclear magnetic resonance methods often have fixed errors; other linear regression calculation methods (empirical methods) require a large amount of gas content data and other related data, and have strong experience, good applicability to developed mature blocks and poor applicability to exploration blocks.
The invention with the patent number of 201210592194.X provides a shale gas content measuring method, and the main innovation point is that a sample is placed in a constant-temperature desorption and measurement system to measure desorption amount, so that the problem that gas in a free space changes along with the temperature and pressure conditions of a test environment and influences the measurement of the desorption gas is solved. However, the invention still belongs to the mainstream gas content testing method at present, only small improvement is made, and the problems of accurate calculation of the gas loss, time consumption and financial cost are not solved.
The invention with the patent number of 201310637331.1 establishes a shale gas content testing device and a testing method, and the testing device can seal, crush and degas a whole core or rock sample in an exploration field or a laboratory so as to quickly and accurately obtain the gas content of the sample. The invention reduces the time consumption of gas content test to a certain extent, but does not solve the problem of gas content loss during coring.
The invention with the patent number of 201410249240.5 provides a method for obtaining shale gas content by using a logging curve, relates to the field of exploration geophysics, and particularly relates to a method for calculating the shale gas content by using the logging curve on the basis of a shale hydrocarbon generation dynamics simulation test, a methane isothermal adsorption test and an analysis gas content test. The method takes a thermal simulation result and the like as the basis to obtain the cumulative conversion rate of the shale gas, the gas generation potential and the total amount of the generated hydrocarbon gas; establishing a calculation relation between shale adsorption capacity and TOC and calculating average gas content; acquiring gas content by using field analysis and correcting the average gas content; by linear regression of shale gas content obtained by analytical experiments and shale logging data, a unitary linear regression equation and a binary linear regression equation of the shale gas content and acoustic time difference and resistivity are obtained, the shale gas content is calculated by using a logging curve, and the calculation efficiency and accuracy of the continental facies shale gas content are obviously improved. However, the gas content data acquired by the conventional method is still adopted for correction in the method, which shows that the method still does not solve the problems of gas content loss and inaccurate calculation of the gas content which cannot be avoided by the conventional gas content test to some extent.
The invention with patent number 201410458715.1 provides a shale gas content determination method and a shale gas content determination system, which are mainly characterized in that a computer is used as a processor, under the support of related programs, no pressure resistance exists in the whole determination process, a filtering and drying mechanism is connected with a methane component infrared gas sensor and a carbon dioxide component infrared gas sensor through pipelines, the carbon dioxide component infrared gas sensor outputs to the pipelines of a large-range mass flowmeter and a small-range mass flowmeter and is respectively connected with an electromagnetic valve, the output of the large-range mass flowmeter and the small-range mass flowmeter is connected with an air outlet through a pipeline, the carbon dioxide component infrared gas sensor outputs to the pipeline of the air outlet and is connected with the electromagnetic valve, an acquisition mechanism ADAM4017 receives standard analog signals output by the infrared gas sensors and the mass flowmeter, and a control mechanism ADAM4068 is respectively connected with. The method is characterized in that the content of the desorbed gas, the content of desorbed methane, the accumulated desorbed gas and the like are calculated in real time by using software, but an inaccurate empirical model is still adopted when the gas content is calculated, and the problem of accurate calculation of the gas loss in the coring process is not solved naturally.
The invention with patent number 8,714,004 provides a method for measuring the gas content of an unconventional reservoir, which is to capture the gas carried by rock debris and mud at any time by using a closed desorption system in the drilling process, and further calculate the gas content of the reservoir by using the gas content obtained by the system. The invention needs a plurality of groups of test data to determine the gas content, and the time cost for obtaining the gas content is high; in addition, the degree of pollution of the debris by the mud is larger, and the loss gas quantity is difficult to estimate.
Patent No. 9,405,036 proposes a method for calculating the gas content of a reservoir, which obtains the gas content of the reservoir through nuclear magnetic resonance logging and other logging data. In the same way, the method still adopts the gas content data acquired by the conventional method to correct the test parameters, and still does not solve the problems of gas content loss and inaccurate calculation of the gas content loss, which cannot be avoided by the conventional gas content test.
The invention with the patent number of 9,709,474 provides a device and a test method for automatically measuring the gas content of an unconventional reservoir, and has the innovation points that partial automation is realized, the constant temperature test is realized, and the measurement precision is high. But the essence of the method is still the conventional method for testing the gas content, the time and financial consumption are high, and the problems that the dissipation of the gas content and the gas loss during coring are difficult to calculate accurately and the like cannot be avoided.
The literature, "new shale gas content calculation method" proposes a feasible method for calculating gas content by using absolute adsorption capacity. By assuming the relationship between the volume of an adsorption phase and the specific surface area and the relationship between the minimum value of density distribution in pores and bulk density along with the change of pressure, a new method for calculating the gas content of shale is provided, and the calculation of the gas content of the shale is realized by means of a simplified local density function theory and a shale actual measurement isothermal adsorption curve. The method reduces time consumption and cost for gas content acquisition, but the simplified local density function theory related to the method has defects (shale is a complex mixture) when the shale adsorption characteristics are represented, so that the accuracy of the minimum value of the density distribution calculated by the theory is difficult to determine, and further the accuracy of gas content calculation cannot be ensured.
In the document of 'shale gas content automatic determination technology', because a manual drainage gas recovery method applied to field gas content determination is difficult to meet the requirement of increasing sampling density of a shale reservoir, the article develops the shale gas content automatic determination technology. The technology can effectively reduce the labor intensity of field testing personnel, has higher precision, realizes automatic and accurate evaluation of shale gas content, and still belongs to a conventional testing method.
The document 'a new method for testing the gas content of shale by pre-pressurizing' provides a new method for testing the gas content of shale by pre-pressurizing, so that the calculation of the gas loss can be avoided, and the testing precision is greatly improved. The method comprises the steps of placing a rock core in a high-pressure tank, injecting methane into the rock core by using a booster pump until the pressure reaches a preset pressure, and desorbing and testing the shale gas content after the pressure is stable at the reservoir temperature. The method requires a priori knowledge of reservoir pressure and a long time for pressure recovery.
According to the Fuling area shale gas content calculation model and the application thereof, the Fuling area shale gas content calculation model is developed, main control parameters of free gas content and adsorbed gas content of shale in a research area are screened and analyzed on the basis of a rock core experiment, and calculation models of the free gas content and the adsorbed gas content are respectively established. The model reduces the time and financial consumption of gas content acquisition to a certain extent, but utilizes the data fitting relation between the Langmuir volume and the TOC, Langmuir pressure and temperature, and belongs to an empirical formula generally.
The document 'improvement of shale gas content measurement by desorption method' proposes a method for improving the gas content measurement precision of the conventional desorption method, and the calculation precision is improved by iterative nonlinear regression according to the actually measured desorption data and the change condition of diffusivity along with time.
In the literature, shale gas aggregation conditions and gas content calculation, which takes the Sichuan basin and ancient world around the Sichuan basin as an example, a gas content calculation model considering organic carbon content, total hydrocarbon content, quartz content, clay mineral content, porosity (cracks), density, pyrite content and carbonate content is established by using a multiple linear regression method. The model is convenient and quick to calculate, but basically belongs to a pure experience method.
In summary, the existing method cannot quickly and accurately acquire the gas content of a large number of rock samples, and therefore, a new shale gas content calculation method which is quicker, higher in accuracy and wider in application range needs to be established.
Disclosure of Invention
The invention aims to solve the problems in the prior art, and provides a shale gas content calculation method, which reduces the time and financial cost for obtaining the shale gas content, improves the calculation precision and has a wide application range.
The invention is realized by the following technical scheme:
according to the method, experimental data are collected firstly, then the collected experimental data are input into a shale gas content calculation model to obtain shale gas content under reservoir conditions, or the collected experimental data are input into the shale gas content calculation model to obtain a curve of pressure and shale gas content, and then the shale gas content under reservoir conditions is obtained from the curve.
The experimental data included: saturation degree of shale water and apparent pore volume V of unit mass shalefFree methane phase density ρbulkActually measuring the adsorption n by a volume methodTest；
The reservoir conditions include reservoir temperature and reservoir pressure.
The shale gas content calculation model is as follows:
wherein N is shale gas content and has the unit of m3/t，MmIs the molar mass of methane in g/mol, R is a general gas constant, R is 8.314J/(mol. K), TscIs the temperature in the standard condition in units of K, ZscIs the methane compression factor under standard conditions; p is a radical ofscPressure under standard conditions in Pa;
in the formula (13), the free phase density ρ of methanebulkActually measuring the adsorption n by volume methodTestIs pressure dependent.
One operation of the acquiring experimental data comprises:
directly obtaining the saturation x of the shale water and the apparent pore volume V of the shale in unit mass from the existing datafFree phase density of methane at reservoir conditions ρbulkVolume method actual measurement of adsorption n under reservoir conditionsTest。
The operation of inputting the collected experimental data into the shale gas content calculation model to obtain the shale gas content under the reservoir condition comprises the following steps:
mixing the saturation degree chi of the shale and the apparent pore volume V of the shale per unit massfFree phase density of methane at reservoir conditions ρbulkVolume method actual measurement of adsorption n under reservoir conditionsTestAnd substituting the shale gas content into a shale gas content calculation model, and calculating to obtain the shale gas content under the reservoir condition.
The another operation of collecting experimental data comprises:
s1, drilling a rock core to obtain a rock sample, sealing and packaging the rock sample, and then dividing one rock sample into three parallel small samples in a laboratory, wherein the three parallel small samples are respectively as follows: sample A, sample B and sample C;
s2, testing the water saturation χ of the sample A;
s3, testing the apparent pore volume V of the shale with unit mass of the sample Bf；
S4, obtaining the methane isothermal adsorption curve of the C sample, and obtaining the actually measured adsorption n of the sample under various pressures by the volume method from the curveTest；
S5, obtaining the free phase density rho of methane under each pressure on the isothermal adsorption curve of methanebulk。
Step S4, obtaining a methane isothermal adsorption curve of the sample C by adopting a volume method;
when the methane isothermal adsorption curve of the sample C is obtained by a volume method, the testing temperature is consistent with the reservoir temperature, and the testing pressure starts to rise from 0MPa until the reservoir pressure is reached;
the abscissa of the methane isothermal adsorption curve is pressure, and the ordinate is actually measured adsorption n by a volume methodTest。
The operation of step S5 includes:
calculating the free phase density rho of methane under each pressure according to each pressure in the isothermal adsorption curve of methanebulk。
The operation of inputting the collected experimental data into the shale gas content calculation model to obtain the curve of the pressure and the shale gas content comprises the following steps:
respectively adjusting the water saturation x of the shale obtained in the step S2 and the unit mass obtained in the step S3Apparent pore volume V of shalefAnd step S4, measuring the adsorption n by volume method under each pressureTestAnd the free phase density ρ of methane at each pressure obtained in step S5bulkSubstituting the pressure values into a formula (13) to obtain shale gas content corresponding to each pressure;
and drawing a coordinate graph by taking the pressure as an abscissa and the shale gas content as an ordinate, marking points of the shale gas content corresponding to each pressure in the coordinate graph, and smoothly connecting all the points to form a curve of the pressure and the shale gas content.
The operation of obtaining shale gas content at reservoir conditions from the curve comprises:
and finding a pressure point equal to the reservoir pressure on the abscissa of the curve of the pressure and the shale gas content, making a plumb line through the pressure point, finding an intersection point of the plumb line and the curve, then making a horizontal line through the intersection point, wherein the shale gas content corresponding to the intersection point of the horizontal line and the ordinate is the shale gas content under the reservoir condition.
Compared with the prior art, the invention has the beneficial effects that: the method uses a brand-new absolute adsorption quantity calculation method, and can quickly obtain the shale gas content by combining the actually measured isothermal adsorption data and the porosity data. The method is simple and convenient in process, and used basic data are easy to obtain (the basic data are parameters obtained by other evaluation works), so that the method can obviously reduce the time and financial cost for obtaining the shale gas content, can improve the gas content calculation accuracy, and has a wide application range.
Drawings
FIG. 1 potential energy curve for two methane molecules interaction (Lennard-Jones potential)
FIG. 2VmCalculation model
FIG. 3 is a schematic diagram of the distribution of the free phase and the adsorbed phase in the shale pores.
FIG. 4-1 actual measurement isothermal adsorption curve (pressure coordinate)
FIG. 4-2 actual measurement of isothermal adsorption Curve (Density coordinate)
Fig. 5 gas content curve.
Detailed Description
The invention is described in further detail below with reference to the accompanying drawings:
the invention provides a new method for calculating the gas content of shale. The method is based on the basic relationship between the actually measured adsorption quantity and the absolute adsorption quantity, firstly a new method for calculating the volume of an adsorption phase is established through analysis, then a new method for calculating the absolute adsorption quantity is deduced, then a new model for calculating the gas content is established by utilizing the relationship between the gas content and the absolute adsorption quantity and the actually measured adsorption quantity, and the model can realize the calculation of the gas content by utilizing the data of the shale, such as the actually measured isothermal adsorption data, the porosity and the like. The method can reduce the time and financial cost for obtaining the shale gas content and improve the gas content calculation precision.
The method comprises the following steps:
1) method for calculating absolute adsorption quantity
The methane content in the shale gas is more than 98 percent, so the method replaces the shale gas with methane when selecting the gas parameters.
The key point of the calculation of the absolute adsorption amount is to accurately obtain the volume of the adsorption phase according to the relation (formula (1) -formula (3)) between the absolute adsorption amount, the excess adsorption amount and the adsorption amount actually measured by the volume method.
In the formula: n isabsAbsolute shale adsorption capacity per unit mass, m3/t；nexExcess shale adsorption capacity per unit mass, m3/t；VaVolume of shale adsorption phase per unit mass, m3/t；ρbulkFree methane phase density, kg/m3；Mm-methane molar mass, g/mol; n isTestMeasurement of the amount of adsorption, m, by volume3T; rho (r) -adsorption phase density profile, kg/m3；
Average density of the adsorbed phase, kg/m3。
Taking the volume of the adsorption phase equal to the sum of the volume occupied by each adsorbed molecule:
in the formula: vt-the volume occupied by all adsorbed molecules; n is a radical ofAAvogastron, mol-1；VmAverage volume occupied per adsorbed molecule, m3.
Substituting the formula (4) into the formula (3) to obtain:
Vmcalculated according to a sphere volume calculation formula:
in the formula: r-radius of adsorption molecule.
According to the principle of molecular thermodynamics, when the molecules reach chemical potential equilibrium (i.e. adsorption equilibrium), the relative force between the molecules is 0, and then the distance R between the two molecules can be determined according to the Lennard-Jones potential energy curve0(as shown in FIG. 1), calculated R0Is 0.3737.
Then, according to fig. 2, a calculation expression of R can be obtained:
substituting the expressions (7) and (6) into the expression (5) can obtain:
in the formula: χ is the shale water saturation,%.
According to the formula (8), the corresponding absolute adsorbed gas amount can be calculated by knowing the water saturation and the actually measured adsorbed gas amount.
2) Novel method for calculating gas content
The shale gas content is the total amount of natural gas converted to the natural gas under standard conditions (101.325kPa, 25 ℃) in each ton of shale, and a calculation formula of the shale gas content can be listed according to the figure 3:
wherein: n-shale gas content, m3/t；ρbulkFree methane phase density, kg/m3；VfApparent pore volume per unit mass of shale, m3T; r — universal gas constant, R ═ 8.314J/(mol · K); t isscIs the temperature under standard conditions, K; zscIs the methane compression factor under standard conditions; p is a radical ofscPressure at standard condition, Pa.
Is obtained from the formula (2)
And substituting the formula (9) to obtain:
since the excess adsorption amount is equal to the adsorption amount measured by the volume method, the expression (10) can be changed to:
as shown in formula (11)After the actual measurement of the adsorption capacity of the shale by the volume method is obtained, the true pore volume (V) of the shale is required to be obtained for accurately calculating the gas contenta+Vf) However, there is no experimental method capable of accurately obtaining the true pore volume of the shale so far, and it is difficult to accurately obtain V in each pore of the shale by methods such as high-pressure mercury pressing, constant-speed mercury pressing, nitrogen adsorption, low-temperature carbon dioxide adsorption and the likeaBecause the working fluid molecules in the methods can be adsorbed on the surfaces of the micropores with stronger adsorption potential, the volume of the adsorption phase of the working fluid molecules is different from that of the adsorption phase of the shale gas, and therefore, the formula (11) is used for calculating the gas content of the shale gas.
In order to avoid the error, absolute adsorbed gas content is adopted to calculate gas content, and rho is obtained by the formula (3)bulkVaAnd substituting the formula (11) to obtain:
(12) in the formula VfThe apparent pore volume equivalent to unit mass of shale can be accurately obtained by the current experimental method, the gas content of the shale can be calculated as long as the absolute adsorption capacity of the shale can be obtained, and therefore the formula (8) is substituted into the formula (12) to obtain a new formula for calculating the gas content of the shale:
3) the method for calculating the gas content of the shale by using the new method comprises the following steps:
1, drilling a rock core, sealing and packaging a rock sample, and dividing one rock sample into three small parallel samples in a laboratory;
parallel small samples refer to physical properties with the same or similar characteristics, i.e., one large sample is divided into three small samples: sample A, sample B and sample C; since the following three experiments are all destructive, each test experiment requires a separate sample;
2, testing the water saturation χ of the sample A;
test B sampleApparent pore volume V per unit mass of shalef；
Obtaining a methane isothermal adsorption curve of a C sample by using a volume method, wherein the testing temperature and pressure are required to reach reservoir conditions (the reservoir temperature and pressure are known in advance during early drilling and logging, and the corresponding temperature and pressure are set in an adsorption instrument when the isothermal adsorption curve is obtained); the obtained isothermal adsorption curve of methane is shown in FIG. 4-1, and the abscissa represents pressure and the ordinate represents the measured adsorption n by volume methodTest。
3, acquiring the methane density (namely the methane free phase density rho) corresponding to each pressure on the isothermal adsorption curvebulk): the pressure-adsorption capacity curve (i.e. methane isothermal adsorption curve) is calculated according to the data recorded in the experiment by the volume method theory, and the density-adsorption capacity curve is calculated according to the pressure-adsorption capacity curve.
The reservoir pressure is a pressure, but when the adsorption capacity is obtained by a volume method, an experiment needs to be carried out from 0MPa until the experiment pressure reaches the reservoir pressure so as to correct parameters, so that the experiment adsorption capacity under the reservoir pressure is obtained. In addition, the study on the shale adsorption characteristics requires the adsorption capacity under different pressures, generally, the adsorption capacity of only one pressure point is measured for calculating the gas content, and the study on the shale adsorption characteristics is generally performed before the gas content is calculated, so that the same adsorption experiment is generally performed and the maximum experiment pressure is designed as the reservoir pressure when the shale adsorption characteristics and the gas content are studied.
The corresponding density was calculated directly from the pressure using physicochemical property calculation software. One pressure corresponds to one density at the same temperature, and the two correspond to each other one by one. Fig. 4-2 is equivalent to converting the pressure in fig. 4-1 to a corresponding density.
And 4, substituting the obtained parameters into the formula (13) to calculate the gas content of the rock sample under the reservoir condition: and substituting the methane density and other acquired parameters corresponding to each pressure into a formula (13) to obtain the gas content corresponding to each pressure, smoothly connecting points obtained by calculation according to the formula (13) to form a curve of the pressure and the shale gas content, and reading the gas content of the sample under the reservoir condition from the curve.
If the experimental adsorption n under reservoir conditions is knowntestAnd other related parameters, the gas content under the reservoir condition can be directly calculated by the formula (13), and drawing and reading are not needed. The change trend of the gas content along with the increase of the pressure can be seen from the drawn curve, and the gas content pressure-measuring device is beneficial to researchers to carry out other research works.
If the parameters related to the steps 1-3 are available, the parameters can be directly substituted into the formula (13) to quickly calculate the gas content.
An embodiment of the method of the invention is as follows:
the reservoir pressure of a certain well is 38MPa, and the temperature is 95.6 ℃; after the fresh rock sample was retrieved, the pore volume per unit mass was measured to be 0.0133m3The water saturation is 35 percent, the measured isothermal adsorption curve is shown in figure 4-1 and figure 4-2, the gas content curve is obtained by substituting the data into the formula (13), the gas content of the sample under the reservoir condition is read from the curve to be 4.79m as shown in figure 53/t。
The total gas content consumption time obtained by the method is about 40 hours after the core is taken, and the cost of one test sample is about 3000 yuan; whereas the time spent using the conventional in situ desorption method is about 60 hours, one test sample costs about 5000 yuan. By comparison, the method reduces the cost and improves the efficiency.
The above-described embodiment is only one embodiment of the present invention, and it will be apparent to those skilled in the art that various modifications and variations can be easily made based on the application and principle of the present invention disclosed in the present application, and the present invention is not limited to the method described in the above-described embodiment of the present invention, so that the above-described embodiment is only preferred, and not restrictive.
Claims (9)
1. A shale gas content calculation method is characterized by comprising the following steps: firstly, acquiring experimental data, inputting the acquired experimental data into a shale gas content calculation model to obtain shale gas content under reservoir conditions, or inputting the acquired experimental data into the shale gas content calculation model to obtain a curve of pressure and shale gas content, and then obtaining the shale gas content under the reservoir conditions from the curve;
the shale gas content calculation model is as follows:
wherein N is shale gas content and has the unit of m3/t，MmIs the molar mass of methane in g/mol, R is a general gas constant, R is 8.314J/(mol. K), TscIs the temperature in the standard condition in units of K, ZscIs the methane compression factor under standard conditions; p is a radical ofscPressure under standard conditions in Pa; chi is the water saturation of shale, and the unit is% VfApparent pore volume per unit mass of shale, in m3/t；
In the formula (13), the free phase density ρ of methanebulkActually measuring the adsorption n by volume methodTestIs pressure dependent.
2. The shale gas content calculation method of claim 1, wherein: the experimental data included: saturation degree of shale water and apparent pore volume V of unit mass shalefFree methane phase density ρbulkActually measuring the adsorption n by a volume methodTest；
The reservoir conditions include reservoir temperature and reservoir pressure.
3. The shale gas content calculation method of claim 2, wherein: the operation of collecting experimental data comprises the following steps:
directly obtaining the saturation x of the shale water and the apparent pore volume V of the shale in unit mass from the existing datafFree phase density of methane at reservoir conditions ρbulkVolume method actual measurement of adsorption n under reservoir conditionsTest。
4. The shale gas content calculation method of claim 3, wherein: the operation of inputting the collected experimental data into the shale gas content calculation model to obtain the shale gas content under the reservoir condition comprises the following steps:
mixing the saturation degree chi of the shale and the apparent pore volume V of the shale per unit massfFree phase density of methane at reservoir conditions ρbulkVolume method actual measurement of adsorption n under reservoir conditionsTestAnd substituting the shale gas content into a shale gas content calculation model, and calculating to obtain the shale gas content under the reservoir condition.
5. The shale gas content calculation method of claim 2, wherein: the operation of collecting experimental data comprises the following steps:
s1, drilling a rock core to obtain a rock sample, sealing and packaging the rock sample, and then dividing one rock sample into three parallel small samples in a laboratory, wherein the three parallel small samples are respectively as follows: sample A, sample B and sample C;
s2, testing the water saturation χ of the sample A;
s3, testing the apparent pore volume V of the shale with unit mass of the sample Bf；
S4, obtaining the methane isothermal adsorption curve of the C sample, and obtaining the actually measured adsorption n of the sample under various pressures by the volume method from the curveTest；
S5, obtaining the free phase density rho of methane under each pressure on the isothermal adsorption curve of methanebulk。
6. The shale gas content calculation method of claim 5, wherein: step S4, obtaining a methane isothermal adsorption curve of the sample C by adopting a volume method;
when the methane isothermal adsorption curve of the sample C is obtained by a volume method, the testing temperature is consistent with the reservoir temperature, and the testing pressure starts to rise from 0MPa until the reservoir pressure is reached;
the abscissa of the methane isothermal adsorption curve is pressure, and the ordinate is actually measured adsorption n by a volume methodTest。
7. The shale gas content calculation method of claim 6, wherein: the operation of step S5 includes:
calculating the free phase density rho of methane under each pressure according to each pressure in the isothermal adsorption curve of methanebulk。
8. The shale gas content calculation method of claim 7, wherein: the operation of inputting the collected experimental data into the shale gas content calculation model to obtain the curve of the pressure and the shale gas content comprises the following steps:
respectively adjusting the water saturation χ of the shale obtained in the step S2 and the apparent pore volume V of the shale of unit mass obtained in the step S3fAnd step S4, measuring the adsorption n by volume method under each pressureTestAnd the free phase density ρ of methane at each pressure obtained in step S5bulkSubstituting the pressure values into a formula (13) to obtain shale gas content corresponding to each pressure;
and drawing a coordinate graph by taking the pressure as an abscissa and the shale gas content as an ordinate, marking points of the shale gas content corresponding to each pressure in the coordinate graph, and smoothly connecting all the points to form a curve of the pressure and the shale gas content.
9. The shale gas content calculation method of claim 8, wherein: the operation of obtaining shale gas content at reservoir conditions from the curve comprises:
and finding a pressure point equal to the reservoir pressure on the abscissa of the curve of the pressure and the shale gas content, making a plumb line through the pressure point, finding an intersection point of the plumb line and the curve, then making a horizontal line through the intersection point, wherein the shale gas content corresponding to the intersection point of the horizontal line and the ordinate is the shale gas content under the reservoir condition.
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