CN108254289B

CN108254289B - Method and device for determining gas content of shale

Info

Publication number: CN108254289B
Application number: CN201711365218.7A
Authority: CN
Inventors: 侯连华; 罗霞; 林森虎; 王京红; 韩文学
Original assignee: Petrochina Co Ltd
Current assignee: Petrochina Co Ltd
Priority date: 2017-12-18
Filing date: 2017-12-18
Publication date: 2020-07-10
Anticipated expiration: 2037-12-18
Also published as: CN108254289A

Abstract

The embodiment of the application discloses a method and a device for determining gas content of shale; the method comprises the following steps: putting the first shale core sample into a first closed desorber filled with drilling fluid, and simulating a natural gas desorption process of the second shale core sample when the second shale core sample is lifted so as to establish a correlation model of natural gas desorption rate and pressure difference; when the pressure in the first closed desorber is reduced to a preset ground pressure, the pressure and the temperature in the first closed desorber are respectively kept at the preset ground pressure and the formation temperature, and the natural gas desorption process of the second shale core sample after being lifted to a wellhead is simulated to establish a correlation model of the natural gas desorption rate and the desorption time; determining the free gas amount of the second shale core sample based on a correlation model of the natural gas desorption rate and the pressure difference and a correlation model of the natural gas desorption rate and the desorption time; and determining the shale gas content of the interval of interest in which the second shale core sample is positioned. The accuracy of the determined shale gas content may be improved.

Description

Method and device for determining gas content of shale

Technical Field

The application relates to the technical field of petroleum and natural gas exploration and development, in particular to a method and a device for determining gas content of shale.

Background

Shale oil and gas has become an important field of oil and gas exploration and development, the storage yield is rapidly increased, and about 40 percent (%) of well yield and Estimated Ultimate Recovery (EUR) cannot meet the commercial development standard from the current shale oil and gas exploration and development condition. The method has the advantages that the factors influencing whether the shale oil and gas can be commercially developed are more, wherein the shale gas content is one of important factors for determining whether the shale oil and gas has the commercial development value, and the correct evaluation of the shale gas content is the key for evaluating and predicting the 'sweet spot' of the shale oil and gas commercial development.

The main process of the conventional method for measuring the gas content of shale at present is to put a collected shale core into a desorber to obtain the desorbed gas content in the shale core, crush the shale core after desorption to obtain the residual gas content, and calculate the lost gas content of the shale core before putting into the desorber by methods such as the united states federal mineral agency direct method (USBM direct method), the improved direct method, the smith-williams method, the curve fitting method and the like according to the relationship between the desorbed gas content of the shale core in the desorber and the desorption time, but the lost gas content of the shale core obtained by using the methods is insufficient in accuracy, so that the obtained gas content of the shale is low in accuracy and is generally only equal to the lower limit of the actual gas content of the shale.

In view of the above problems, no effective solution has been proposed.

Disclosure of Invention

The embodiment of the application aims to provide a method and a device for determining the gas content of shale so as to improve the accuracy of the determined gas content of the shale.

In order to solve the above technical problem, an embodiment of the present application provides a method and an apparatus for determining a gas content of shale, which are implemented as follows:

a method for determining shale gas content is provided with a first shale core sample, a second shale core sample, and formation temperature and formation pressure at the depth of a layer where the first shale core sample is located when the first shale core sample is drilled; the first shale core sample is collected by a pressure-maintaining coring method, and the second shale core sample is collected by a conventional coring method; the method comprises the following steps:

putting the first shale core sample into a first closed desorber filled with drilling fluid, and simulating a natural gas desorption process of the second shale core sample when the second shale core sample is lifted so as to establish a correlation model of a natural gas desorption rate and a pressure difference; wherein the pressure differential is determined from the formation pressure minus the pressure within the first confined desorber;

when the pressure in the first closed desorber is reduced to a preset ground pressure, the pressure and the temperature in the first closed desorber are respectively kept at the preset ground pressure and the formation temperature, and a natural gas desorption process of the second shale core sample after being lifted to a wellhead is simulated to establish a correlation model of natural gas desorption rate and desorption time;

determining the free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time;

and determining the shale gas content of the target interval in which the second shale core sample is positioned based on the free gas content of the second shale core sample.

In a preferred embodiment, the step of putting the first shale core sample into a first closed desorber filled with a drilling fluid, and simulating a natural gas desorption process of the second shale core sample when the second shale core sample is lifted up to establish a correlation model of a natural gas desorption rate and a pressure difference includes:

after the first-page rock core sample is lifted to a wellhead, taking the first-page rock core sample out of the coring barrel, and putting the first-page rock core sample into a first closed desorber filled with drilling fluid; wherein the temperature and pressure within the first closed desorber are the formation temperature and the formation pressure, respectively;

maintaining the first closed desorber in a constant temperature state with the temperature being the formation temperature, reducing the pressure in the first closed desorber from the formation pressure to a preset ground pressure according to a specified pressure reduction rate, and acquiring first natural gas desorption rate data corresponding to the first page rock core sample in the pressure reduction process in the first closed desorber; wherein the first natural gas desorption rate data comprises a plurality of first data points comprising: a pressure differential and a first natural gas desorption rate; the pressure difference corresponds to the first natural gas desorption rate one by one; the specified pressure reduction rate represents a drilling fluid column pressure reduction rate at the depth of layer where the core barrel is located during the core lifting process;

establishing a correlation model of the natural gas desorption rate and the pressure difference based on the first natural gas desorption rate data; wherein the correlation model of the natural gas desorption rate and the pressure difference comprises a first correlation coefficient.

In a preferred scheme, the correlation model of the natural gas desorption rate and the pressure difference is established by adopting the following formula:

Q₁＝a₁₁ΔP²

wherein Q is₁Represents the first natural gas desorption rate, Δ P represents the pressure difference, a₁₁Representing the first correlation coefficient; wherein, when Δ P is less than or equal to 0, Q₁The value of (d) is 0.

In a preferred embodiment, the simulating a natural gas desorption process of the second shale core sample after being lifted to a wellhead to establish a correlation model of a natural gas desorption rate and desorption time includes:

acquiring second natural gas desorption rate data corresponding to the first page rock core sample in a specified process; wherein the specified process represents a process in which a natural gas desorption rate of the first shale core sample increases with increasing desorption time; the second natural gas desorption rate data comprises a plurality of second data points comprising: a desorption time and a second natural gas desorption rate; the desorption time corresponds to the desorption rate of the second natural gas one by one;

establishing a correlation model of the natural gas desorption rate and the desorption time based on the second natural gas desorption rate data; wherein the correlation model of the natural gas desorption rate and the desorption time comprises a second correlation coefficient and a third correlation coefficient.

In a preferred scheme, the correlation model of the natural gas desorption rate and the desorption time is established by adopting the following formula:

wherein Q is₂Represents the second natural gas desorption rate, t₂Represents the desorption time, a₂₁And a₂₂Respectively represent the secondTwo correlation coefficients and the third correlation coefficient.

In a preferred embodiment, the determining the free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time includes:

after the second shale core sample is lifted to a wellhead, taking the second shale core sample out of the coring barrel, and putting the second shale core sample into a second closed desorber filled with drilling fluid; wherein the temperature and pressure in the second confined desorber are the formation temperature and the preset formation pressure, respectively; acquiring natural gas desorption rates corresponding to two specified desorption times respectively, and the natural gas desorption amount of the second shale core sample in the desorption process in the second closed desorber;

determining the natural gas loss amount of the second shale core sample from the wellhead to the process of putting the second shale core sample into a second airtight desorber according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model of the natural gas desorption rate and the desorption time;

determining the natural gas loss amount of the second shale core sample in the process from drilling to lifting and the natural gas loss amount of the second shale core sample in the lifting process based on the correlation model of the natural gas desorption rate and the pressure difference;

and determining the free gas amount of the second shale core sample based on the natural gas loss amount of the second shale core sample in the process from drilling to lifting, the natural gas loss amount of the second shale core sample in the lifting process, the natural gas loss amount of the second shale core sample in the process from the wellhead to the second airtight desorber, and the natural gas desorption amount of the second shale core sample in the desorption process in the second airtight desorber.

In a preferred embodiment, the determining, according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model between the natural gas desorption rate and the desorption time, a natural gas loss amount of the second shale core sample from a wellhead to a second airtight desorber includes:

determining a second correlation coefficient and a third correlation coefficient corresponding to the second shale core sample according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model of the natural gas desorption rate and the desorption time;

establishing a correlation relation between the natural gas desorption rate and the desorption time corresponding to the second shale core sample according to a second correlation coefficient and a third correlation coefficient corresponding to the second shale core sample and a correlation model between the natural gas desorption rate and the desorption time;

and determining the natural gas loss amount of the second shale core sample from the wellhead to the process of putting the second shale core sample into a second airtight desorber based on the correlation between the natural gas desorption rate corresponding to the second shale core sample and the desorption time.

In a preferred embodiment, the determining the natural gas loss amount of the second shale core sample in the process from after drilling to before lifting and the natural gas loss amount of the second shale core sample in the lifting process based on the correlation model between the natural gas desorption rate and the pressure difference includes:

determining the natural gas desorption rate when the second shale core sample is lifted to the wellhead according to the correlation between the natural gas desorption rate corresponding to the second shale core sample and the desorption time;

determining a first correlation coefficient corresponding to the second shale core sample according to the natural gas desorption rate when the second shale core sample is lifted to a wellhead, the formation pressure at the depth of the layer where the second shale core sample is located when the second shale core sample is drilled, and the preset ground pressure;

establishing a correlation relation between the natural gas desorption rate and the pressure difference corresponding to the second shale core sample according to the first correlation coefficient corresponding to the second shale core sample and the correlation model between the natural gas desorption rate and the pressure difference;

and determining the natural gas loss amount of the second shale core sample in the process from drilling to lifting and the natural gas loss amount of the second shale core sample in the lifting process based on the correlation between the natural gas desorption rate corresponding to the second shale core sample and the pressure difference.

In a preferred embodiment, the method further provides a mass of the second shale core sample; the mass of the second shale core sample represents the mass of the drilling fluid and water on the surface of the second shale core sample after desorption is completed; determining the shale gas content of the target interval where the second shale core sample is located based on the free gas content of the second shale core sample, wherein the determining comprises the following steps:

putting the desorbed second shale core sample into a closed pulverizer filled with water, and pulverizing the desorbed second shale core sample to obtain the residual gas amount of the second shale core sample;

and determining the shale gas content of the target interval where the second shale core sample is located based on the free gas content and residual gas content of the second shale core sample and the mass of the second shale core sample.

A device for determining shale gas content provides a first shale core sample, a second shale core sample, and formation temperature and formation pressure at a depth of layer where the first shale core sample is located when the first shale core sample is drilled; the first shale core sample is collected by a pressure-maintaining coring method, and the second shale core sample is collected by a conventional coring method; the device comprises: the device comprises a first correlation model determining module, a second correlation model determining module, a free gas amount determining module and a shale gas content determining module; wherein the content of the first and second substances,

the first correlation model determining module is used for putting the first shale core sample into a first closed desorber filled with drilling fluid and simulating a natural gas desorption process of the second shale core sample when the second shale core sample is lifted so as to establish a correlation model of a natural gas desorption rate and a pressure difference; wherein the pressure differential is determined from the formation pressure minus the pressure within the first confined desorber;

the second correlation model determining module is used for respectively keeping the pressure and the temperature in the first closed desorber at the preset ground pressure and the formation temperature when the pressure in the first closed desorber is reduced to the preset ground pressure, and simulating a natural gas desorption process of the second shale core sample after being lifted to a wellhead so as to establish a correlation model of natural gas desorption rate and desorption time;

the free gas amount determining module is used for determining the free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time;

and the shale gas content determining module is used for determining the shale gas content of the target interval where the second shale core sample is based on the free gas content of the second shale core sample.

In a preferred embodiment, the first association model determining module includes: the device comprises a first desorption rate data acquisition module and a first model establishing module; wherein the content of the first and second substances,

the first desorption rate data acquisition module is used for taking out the first rock core sample from the core taking barrel after the first rock core sample is lifted to a wellhead and putting the first rock core sample into a first closed desorber filled with drilling fluid; wherein the temperature and pressure within the first closed desorber are the formation temperature and the formation pressure, respectively; maintaining the first closed desorber in a constant temperature state with the temperature being the formation temperature, reducing the pressure in the first closed desorber from the formation pressure to a preset ground pressure according to a specified pressure reduction rate, and acquiring first natural gas desorption rate data corresponding to the first page rock core sample in the pressure reduction process in the first closed desorber; wherein the first natural gas desorption rate data comprises a plurality of first data points comprising: a pressure differential and a first natural gas desorption rate; the pressure difference corresponds to the first natural gas desorption rate one by one; the specified pressure reduction rate represents a drilling fluid column pressure reduction rate at the depth of layer where the core barrel is located during the core lifting process;

the first model establishing module is used for establishing a correlation model of the natural gas desorption rate and the pressure difference based on the first natural gas desorption rate data; wherein the correlation model of the natural gas desorption rate and the pressure difference comprises a first correlation coefficient; specifically, the first model determination module is used for establishing the correlation model of the natural gas desorption rate and the pressure difference by adopting the following formula:

Q₁＝a₁₁ΔP²

In a preferred embodiment, the second association model determining module includes: a second desorption rate data acquisition module and a second model establishing module; wherein the content of the first and second substances,

the second desorption rate data acquisition module is used for acquiring second natural gas desorption rate data corresponding to the first shale core sample in the appointed process; wherein the specified process represents a process in which a natural gas desorption rate of the first shale core sample increases with increasing desorption time; the second natural gas desorption rate data comprises a plurality of second data points comprising: a desorption time and a second natural gas desorption rate; the desorption time corresponds to the desorption rate of the second natural gas one by one;

the second model establishing module is used for establishing a correlation model of the natural gas desorption rate and the desorption time based on the second natural gas desorption rate data; wherein the correlation model of the natural gas desorption rate and the desorption time comprises a second correlation coefficient and a third correlation coefficient; specifically, the second model establishing module is used for establishing the correlation model of the natural gas desorption rate and the desorption time by adopting the following formula:

wherein Q is₂Represents the second natural gas desorption rate, t₂Represents the desorption time, a₂₁And a₂₂Respectively representing the second correlation coefficient and the third correlation coefficient.

In a preferred embodiment, the free gas amount determining module includes: a desorption amount determining submodule, a first loss amount determining submodule, a second loss amount determining submodule and a free gas amount determining submodule; wherein the content of the first and second substances,

the desorption amount determining submodule is used for taking the second shale core sample out of the coring barrel after the second shale core sample is lifted to a wellhead and putting the second shale core sample into a second airtight desorber filled with drilling fluid; wherein the temperature and pressure in the second confined desorber are the formation temperature and the preset formation pressure, respectively; acquiring natural gas desorption rates corresponding to two specified desorption times respectively, and the natural gas desorption amount of the second shale core sample in the desorption process in the second closed desorber;

the first loss amount determining submodule is used for determining the natural gas loss amount of the second shale core sample from the wellhead to the process of being placed into a second airtight desorber according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model of the natural gas desorption rate and the desorption time;

the second loss amount determining submodule is used for determining the natural gas loss amount of the second shale core sample in the process from drilling to lifting and the natural gas loss amount of the second shale core sample in the lifting process based on the correlation model of the natural gas desorption rate and the pressure difference;

the free gas amount determining submodule is used for determining the free gas amount of the second shale core sample based on the natural gas loss amount of the second shale core sample in the process from drilling to lifting, the natural gas loss amount of the second shale core sample in the lifting process, the natural gas loss amount of the second shale core sample in the process from a wellhead to putting into a second airtight desorber, and the natural gas desorption amount of the second shale core sample in the desorption process in the second airtight desorber.

A method for determining shale gas content is provided with a shale core sample in a target interval, the mass of the shale core sample and the formation temperature at the depth of layer where the shale core sample is located when the shale core sample is drilled; wherein the shale core sample is collected by a pressure-maintaining coring method; the method comprises the following steps:

after the shale core sample is lifted to a wellhead, taking the shale core sample out of a coring barrel, and putting the shale core sample into a closed desorber filled with drilling fluid; wherein the temperature and pressure in the closed desorber are respectively a preset ground temperature and the formation pressure;

acquiring natural gas desorption rate data corresponding to the shale core sample in a specified process, and acquiring natural gas desorption amount of the shale core sample in a desorption process in the closed desorber; wherein the specified process represents a process in which a natural gas desorption rate of the shale core sample increases with increasing desorption time; the natural gas desorption rate data comprises a plurality of data points comprising: desorption time and rate of natural gas desorption; the desorption time corresponds to the natural gas desorption rate one by one;

establishing an incidence relation between the natural gas desorption rate and the desorption time based on the natural gas desorption rate data;

determining the loss amount of natural gas from the wellhead to the process of putting the shale core sample into the closed desorber based on the correlation; determining the residual gas volume of the shale core sample;

and determining the shale gas content of the target interval based on the natural gas desorption amount of the shale core sample in the desorption process in the closed desorber, the natural gas loss amount of the shale core sample from the well mouth to the closed desorber, and the residual gas amount and the mass of the shale core sample.

The embodiment of the application provides a method and a device for determining gas content of shale, wherein a first shale core sample can be placed into a first closed desorber filled with drilling fluid, and a natural gas desorption process of a second shale core sample during lifting is simulated to establish a correlation model of natural gas desorption rate and pressure difference; wherein the pressure differential is determined from the formation pressure minus the pressure within the first confined desorber; when the pressure in the first closed desorber is reduced to a preset ground pressure, the pressure and the temperature in the first closed desorber can be respectively kept at the preset ground pressure and the formation temperature, and the natural gas desorption process of the second shale core sample after being lifted to a wellhead is simulated to establish a correlation model of the natural gas desorption rate and the desorption time; determining a free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time; the shale gas content of the interval of interest in which the second shale core sample is located may be determined based on the free gas content of the second shale core sample. In this manner, the accuracy of the determined shale gas content may be improved.

Drawings

In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the drawings needed to be used in the description of the embodiments or the prior art will be briefly introduced below, it is obvious that the drawings in the following description are only some embodiments described in the present application, and for those skilled in the art, other drawings can be obtained according to the drawings without any creative effort.

FIG. 1 is a flow chart of an embodiment of a method of determining gas content of shale according to the present application;

FIG. 2 is a block diagram illustrating the composition of an embodiment of the apparatus for determining gas content in shale;

FIG. 3 is a block diagram illustrating a first correlation model determining module according to an embodiment of the apparatus for determining gas content in shale;

FIG. 4 is a block diagram illustrating a second correlation model determining module according to an embodiment of the apparatus for determining gas content in shale;

fig. 5 is a block diagram of a free gas amount determination module in an embodiment of the device for determining gas content of shale.

Detailed Description

The embodiment of the application provides a method and a device for determining gas content of shale.

In order to make those skilled in the art better understand the technical solutions in the present application, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application, and it is obvious that the described embodiments are only a part of the embodiments of the present application, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present application.

The embodiment of the application provides a method for determining gas content of shale. And determining the gas content of the shale, providing a first shale core sample and a second shale core sample, and providing the formation temperature and the formation pressure at the depth of layer where the first shale core sample is located when the first shale core sample is drilled.

In this embodiment, the first page core sample is collected by dwell coring. The second shale core sample is collected by conventional coring methods. The natural gas in the second shale core sample is desorbed and dissipated gradually along with the gradual reduction of the pressure of the drilling fluid column in the core barrel on the second shale core sample in the conventional coring process, and the natural gas in the second shale core sample is desorbed and dissipated continuously but cannot be collected in the process that the second shale core sample is lifted to the desorber from the wellhead, so that the loss of the natural gas amount exists. And the collection mode of pressurize coring can guarantee that the natural gas in the first page rock core sample can not lose after the rock core is lifted to the well head and before being taken out from the coring barrel. Therefore, the decompression speed and the required time of the second shale core sample in the lifting process can be simulated by the first shale core sample subjected to pressure-maintaining coring in the subsequent process, and the natural gas loss amount in the conventional coring and core lifting process can be completely reproduced.

In this embodiment, the first shale core sample and the second shale core sample may be collected from shale intervals of different research work areas, or may be collected from shale intervals of the same research work area.

In this embodiment, the formation temperature and the formation pressure at the depth of the first rock core sample may be obtained by drilling the first rock core sample.

Fig. 1 is a flow chart of an embodiment of a method for determining gas content of shale according to the present application. As shown in fig. 1, the method for determining the gas content of shale includes the following steps.

Step S101: putting the first shale core sample into a first closed desorber filled with drilling fluid, and simulating a natural gas desorption process of the second shale core sample when the second shale core sample is lifted so as to establish a correlation model of a natural gas desorption rate and a pressure difference; wherein the pressure differential is determined from the formation pressure minus the pressure within the first confined desorber.

In this embodiment, the step of placing the first shale core sample into a first closed desorber filled with a drilling fluid, and simulating a natural gas desorption process of the second shale core sample when the second shale core sample is lifted up to establish a correlation model between a natural gas desorption rate and a pressure difference may specifically include the following steps:

(1) after the first-page rock core sample is lifted to a wellhead, the first-page rock core sample can be taken out of the coring barrel and placed into a first closed desorber filled with drilling fluid. Wherein the temperature and pressure within the first closed desorber are the formation temperature and the formation pressure, respectively.

(2) The first closed desorber may be maintained at a constant temperature with the temperature of the formation, the pressure in the first closed desorber may be reduced from the formation pressure to a preset surface pressure at a specified pressure reduction rate, and first natural gas desorption rate data corresponding to the first shale core sample during the pressure reduction in the first closed desorber may be obtained. Wherein the first natural gas desorption rate data may include a plurality of first data points, which may include: pressure differential and first natural gas desorption rate. The pressure difference corresponds to the first natural gas desorption rate one by one. The specified rate of pressure reduction may represent a rate of drilling fluid column pressure reduction at a depth of layer at the location of the core barrel during core lifting. For example, the core pull rate in the well is 10 meters per minute (m/min), simulating a drilling fluid column pressure reduction rate of 0.115MPa/min at the depth of layer at the location of the core barrel during core pull.

(3) Based on the first natural gas desorption rate data, a correlation model of the natural gas desorption rate and the pressure difference may be established. Wherein the correlation model of the natural gas desorption rate and the pressure difference can comprise a first correlation coefficient. Specifically, a polynomial fitting method can be adopted to establish the correlation model of the natural gas desorption rate and the pressure difference.

In this embodiment, the correlation model of the natural gas desorption rate and the pressure difference can be established by using the following formula:

Q₁＝a₁₁ΔP²

wherein Q is₁Represents the first natural gas desorption rate in cubic centimeters per minute (cm)³/min), Δ P represents said pressure difference in megapascals (MPa), a₁₁Representing the first correlation coefficient; wherein, when Δ P is less than or equal to 0, Q₁The value of (d) is 0.

In the present embodiment, the preset ground pressure may be 0.101325 megapascals (MPa).

In this embodiment, the pressure differential may be determined from the formation pressure minus the pressure within the first closed containment desorber. Since the specified rate of pressure decrease may represent a rate of drilling fluid column pressure decrease at the depth of layer at the location of the core barrel during core lifting, the pressure in the first desorber is reduced from the formation pressure to a preset surface pressure at the specified rate of pressure decrease, the pressure in the first desorber being equivalent to the drilling fluid column pressure at the depth of layer at the location of the core barrel during core lifting plus the preset surface pressure. As such, the pressure differential may represent the pressure differential resulting from subtracting the drilling fluid column pressure and the predetermined surface pressure from the formation pressure.

Step S102: when the pressure in the first closed desorber is reduced to a preset ground pressure, the pressure and the temperature in the first closed desorber are respectively kept at the preset ground pressure and the formation temperature, and the natural gas desorption process of the second shale core sample after being lifted to a wellhead is simulated, so that a correlation model of the natural gas desorption rate and the desorption time is established.

In this embodiment, specifically, when the pressure in the first closed desorber is reduced to a preset ground pressure, the pressure and the temperature in the first closed desorber may be maintained at the preset ground pressure and the formation temperature, respectively, and second natural gas desorption rate data corresponding to the first rock core sample in a specified process may be obtained. Wherein the specified process represents a process in which a natural gas desorption rate of the first shale core sample increases with increasing desorption time. The second natural gas desorption rate data may include a plurality of second data points, which may include: desorption time and second natural gas desorption rate. The desorption time corresponds to the second natural gas desorption rate one by one. For example, the time taken for the first shale core sample to be taken out of the coring barrel and placed into the closed desorber is 4 minutes, and the maximum desorption time of the first shale core sample, in which the desorption rate of natural gas increases with the increase of the desorption time, is 51 minutes, i.e., the time of the specified process is 51 minutes. A correlation model of the natural gas desorption rate to desorption time may be established based on the second natural gas desorption rate data. Wherein the correlation model of the natural gas desorption rate and the desorption time can comprise a second correlation coefficient and a third correlation coefficient. Specifically, a polynomial fitting method can be adopted to establish a correlation model of the natural gas desorption rate and the desorption time.

In this embodiment, the correlation model of the desorption rate and desorption time of natural gas can be established by using the following formula:

wherein Q is₂Represents the desorption rate of the second natural gas in cm³/min，t₂Represents the desorption time in minutes, a₂₁And a₂₂Respectively representing the second correlation coefficient and the third correlation coefficient.

Step S103: and determining the free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time.

In this embodiment, the determining the free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time may specifically include the following steps:

(1) after the second shale core sample is lifted to the wellhead, the second shale core sample may be taken out of the coring barrel and placed into a second closed desorber containing drilling fluid. Wherein the temperature and pressure within the second confined desorber are the formation temperature and the predetermined formation pressure, respectively. And the natural gas desorption rate corresponding to two appointed desorption times and the natural gas desorption amount of the second shale core sample in the desorption process in the second closed desorber can be obtained. The two appointed desorption times can be any two desorption times from 1 minute to 5 minutes after the second shale core sample is placed into the second closed desorber. For example, the two specified desorption times may be the 1 st and 2 nd minutes, respectively, after the second shale core sample is placed into the second closed desorber.

(2) And determining the natural gas loss amount of the second shale core sample from the wellhead to the second airtight desorber according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model of the natural gas desorption rate and the desorption time.

(3) Based on the correlation model of the natural gas desorption rate and the pressure difference, the natural gas loss amount of the second shale core sample in the process from drilling to lifting and the natural gas loss amount of the second shale core sample in the lifting process can be determined.

(4) And determining the free gas amount of the second shale core sample based on the natural gas loss amount of the second shale core sample in the process from drilling to lifting, the natural gas loss amount of the second shale core sample in the lifting process, the natural gas loss amount of the second shale core sample in the process from the wellhead to the second airtight desorber, and the natural gas desorption amount of the second shale core sample in the desorption process in the second airtight desorber. Specifically, the sum of the natural gas loss amount of the second shale core sample in the process from drilling to lifting, the natural gas loss amount of the second shale core sample in the lifting process, the natural gas loss amount of the second shale core sample in the process from the wellhead to putting into a second closed desorber, and the natural gas desorption amount of the second shale core sample in the desorption process in the second closed desorber can be used as the free gas amount of the second shale core sample.

In this embodiment, the time from the withdrawal of the second shale core sample from the coring barrel to the introduction into the second closed desorber is less than or equal to 30 minutes.

In this embodiment, the desorption amount of the natural gas of the second shale core sample during the desorption process in the second closed desorber, that is, the total desorption amount of the natural gas of the second shale core sample after the desorption in the second closed desorber is completed, may be obtained. Wherein the desorption amount of natural gas in one day is less than 1cm³When it is time, it indicates that desorption is complete.

In this embodiment, determining the natural gas loss amount of the second shale core sample from the wellhead to the second airtight desorber according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model between the natural gas desorption rate and the desorption time may specifically include the following steps:

(1) and determining a second correlation coefficient and a third correlation coefficient corresponding to the second shale core sample according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model of the natural gas desorption rate and the desorption time. Specifically, the two specified desorption times and the natural gas desorption rates respectively corresponding to the specified desorption times may be substituted into the correlation model of the natural gas desorption rate and the desorption time, so as to obtain a second correlation coefficient and a third correlation coefficient corresponding to the second shale core sample. For example, the time t from the taking of the second shale core sample from the coring barrel to the putting in of the second closed desorber is 15 minutes, and the two specified desorption times may be the tth time after the second shale core sample is taken from the coring barrel₃(t +1) min and t₄(t +2) minutes, and the natural gas desorption rates corresponding to the two specified desorption times are respectively Q₃And Q₄And Q is represented by the following formula₃And Q₄Conversion to the corresponding values at ground standard atmospheric pressure and 25 degrees celsius (° c):

wherein Q' represents the conversion of Q into a corresponding value at a standard atmospheric pressure on the ground and at 25 degrees Celsius (. degree. C.) when the pressure and temperature are P and T, respectively; q represents the natural gas desorption rate at a pressure and temperature of P and T, respectively, P representing the pressure for Q and T representing the temperature for Q. The corresponding value Q can be obtained₃'and Q'₄Are respectively 40.4404cm³Min and 40.8216cm³And/min. Will specify the desorption time t₃(t₃16) min and t₄(t₄17) minutes, and the corresponding value Q₃'and Q'₄Substituting the natural gas desorption rate and the desorption time into the correlation model of the natural gas desorption rate and the desorption time to obtain the natural gas desorption rate and the desorption timeThe second and third correlation coefficients for the second shale core sample are 25.914 and 0.1595, respectively.

(2) And establishing the correlation between the natural gas desorption rate and the desorption time corresponding to the second shale core sample according to the second correlation coefficient and the third correlation coefficient corresponding to the second shale core sample and the correlation model of the natural gas desorption rate and the desorption time. For example, the correlation between the desorption rate and the desorption time of the natural gas corresponding to the second shale core sample may be established by using the following formula:

Q'₂＝25.914(t'₂)^0.1595

wherein, Q'₂Representing a natural gas desorption rate, t 'of the second shale core sample from wellhead to placement in a second closed desorber or during the designation'₂Representing a desorption time of the second shale core sample from the wellhead until being placed in a second closed desorber or during the designated process.

(3) And determining the natural gas loss amount of the second shale core sample from the wellhead to the process of putting the second shale core sample into a second airtight desorber based on the correlation between the natural gas desorption rate corresponding to the second shale core sample and the desorption time. Specifically, based on the correlation between the natural gas desorption rate corresponding to the second shale core sample and the desorption time, the natural gas desorption rate of the second shale core sample from the wellhead to the second airtight desorber can be determined. And determining the natural gas loss amount of the second shale core sample from the wellhead to the second airtight desorber according to the natural gas desorption rate of the second shale core sample from the wellhead to the second airtight desorber.

In this embodiment, determining the natural gas loss amount of the second shale core sample in the process from after drilling to before lifting and the natural gas loss amount of the second shale core sample in the lifting process based on the correlation model between the natural gas desorption rate and the pressure difference may specifically include the following steps:

(1) according to the second shale coreAnd determining the natural gas desorption rate when the second shale core sample is lifted to the wellhead according to the correlation between the natural gas desorption rate corresponding to the sample and the desorption time. For example, t 'may be'₂Substituting the value of 1 into the correlation between the natural gas desorption rate and the desorption time corresponding to the second shale core sample, and calculating to obtain the value of the natural gas desorption rate when the second shale core sample is lifted to the wellhead, which is 25.914cm³/min。

(2) And determining a first correlation coefficient corresponding to the second shale core sample according to the natural gas desorption rate when the second shale core sample is lifted to a wellhead, the formation pressure at the depth of layer where the second shale core sample is located when the second shale core sample is drilled, and the preset ground pressure. Specifically, for example, when the second shale core sample is drilled, the formation pressure at the depth of layer where the second shale core sample is located is 19.665MPa, the depth of layer where the second shale core sample is located is 1710m, the preset ground pressure is 0.101325MPa, and the natural gas desorption rate value when the second shale core sample is lifted up to the wellhead (25.914 cm)³Min), and substituting the difference value between the formation pressure (19.665MPa) at the depth of layer where the second shale core sample is located and the preset ground pressure (0.101325MPa) when the first shale core sample is drilled into the correlation model of the natural gas desorption rate and the pressure difference, so that the value of the first correlation coefficient corresponding to the second shale core sample is calculated to be 0.0678.

(3) And according to the first correlation coefficient corresponding to the second shale core sample and the correlation model of the natural gas desorption rate and the pressure difference, establishing a correlation relationship between the natural gas desorption rate and the pressure difference corresponding to the second shale core sample. For example, the correlation between the natural gas desorption rate and the pressure difference corresponding to the second shale core sample may be established by using the following formula:

Q′₁＝0.0678(ΔP′₁)²

wherein, Q'₁Representing the second shale core sample from after drilling to during lifting or during liftingRate of desorption of Natural gas, Δ P'₁And the pressure difference represents the formation pressure at the depth of layer where the second shale core sample is located when the second shale core sample is drilled, and the drilling fluid column pressure at the depth of layer where the core barrel is located in the process from drilling to lifting of the second shale core sample or in the lifting process. When delta P'₁Less than 0, Q'₁Is 0.

(4) Based on the correlation between the natural gas desorption rate and the pressure difference corresponding to the second shale core sample, the natural gas loss amount of the second shale core sample in the process from drilling to lifting and the natural gas loss amount of the second shale core sample in the lifting process can be determined. Specifically, for example, when the second shale core sample is drilled, the depth H of a stratum where the second shale core sample is located is 1710m, and the density rho of the drilling fluid_mudIs 1.2g/cm³The pressure of the drilling fluid column at the depth of the stratum of the location is rho_mudH/100 and formation pressure 19.665MPa, i.e.. DELTA.P₁＝19.665-ρ_mudH/100, delta P 'of the second shale core sample from after drilling to before lifting'₁Is-0.855 MPa, less than 0. As such, the second shale core sample has a natural gas loss of 0 during the time from drill-in to drill-up. Meanwhile, the natural gas desorption rate of the second shale core sample in the uplifting process can be determined based on the correlation between the natural gas desorption rate corresponding to the second shale core sample and the pressure difference. And calculating the natural gas loss amount of the second shale core sample in the lifting process according to the natural gas desorption rate of the second shale core sample in the lifting process.

Step S104: and determining the shale gas content of the target interval in which the second shale core sample is positioned based on the free gas content of the second shale core sample.

In this embodiment, the mass of the second shale core sample may be obtained; and the mass of the second shale core sample represents the mass of the drilling fluid and water on the surface of the second shale core sample after desorption is completed. For example, the mass of the second shale core sample may be weighed using a ten-thousandth electronic balance to yield a mass of 1200.0001 grams (g) for the second shale core sample.

In this embodiment, determining the shale gas content of the target interval where the second shale core sample is located based on the free gas content of the second shale core sample may specifically include placing the desorbed second shale core sample into a closed pulverizer filled with water, and performing pulverization treatment on the desorbed second shale core sample to obtain the residual gas content of the second shale core sample. And determining the shale gas content of the target interval in which the second shale core sample is positioned based on the free gas content and residual gas content of the second shale core sample and the quality of the second shale core sample. Specifically, the shale gas content of the interval of interest where the second shale core sample is located may be obtained by dividing the sum of the free gas amount and the residual gas amount of the second shale core sample by the mass of the second shale core sample.

For example, the interval of interest in the research area is marine sedimentary, the distance between the pressure-holding coring well and the conventional coring well is 100 meters, the shale distribution in the research area is stable, and the properties are basically consistent, and the first shale core sample and the second shale core sample are in the same interval of interest in the same research area and are corresponding layers, so that the shale gas contents of the two wells should be the same. When the first shale core sample is drilled, the depth H of the layer where the first shale core sample is located is 1700m, the corresponding formation pressure is 19.55MPa, when the second shale core sample is drilled, the depth H of the layer where the second shale core sample is located is 1710m, the corresponding formation pressure is 19.665MPa, and the density rho of the drilling fluid is 19.665MPa_mudIs 1.2g/cm³The time from taking the first shale core sample out of the coring barrel to putting the first shale core sample into the closed desorber is 4 minutes, the time from taking the second shale core sample out of the coring barrel to putting the second shale core sample into the closed desorber is 15 minutes, the mass of the first shale core sample is 1050.0325 grams, and the mass of the second shale core sample is 1200.0001 grams. Can respectively obtain by the methodThe shale gas contents respectively corresponding to the first shale core sample and the second shale core sample are 5.8964 cubic meters per ton and 5.8439 cubic meters per ton, and the relative error between the two is 0.898%. The gas content of the shale obtained by pressure-maintaining coring reflects the real gas content of the shale stratum, so that the gas content of the conventional coring well shale core obtained by the method is more accurate.

The embodiment of the application also provides a method for determining the gas content of the shale. The method for determining the gas content of the shale can be provided with a shale core sample in a target interval, the mass of the shale core sample and the formation temperature at the depth of a layer where the shale core sample is located when the shale core sample is drilled; wherein the shale core sample is collected by a pressure-holding coring method. The method for determining the gas content of the shale comprises the following steps.

Step S201: after the shale core sample is lifted to a wellhead, the shale core sample can be taken out of the coring barrel and put into a closed desorber filled with drilling fluid; wherein the temperature and pressure within the confined desorber are a preset surface temperature and the formation pressure, respectively.

Step S202: the natural gas desorption rate data corresponding to the shale core sample in the appointed process can be obtained, and the natural gas desorption amount of the shale core sample in the desorption process in the closed desorber can be obtained; wherein the specified process represents a process in which a natural gas desorption rate of the shale core sample increases with increasing desorption time; the natural gas desorption rate data comprises a plurality of data points comprising: desorption time and rate of natural gas desorption; the desorption time corresponds to the natural gas desorption rate one by one.

Step S203: based on the natural gas desorption rate data, a correlation of the natural gas desorption rate with desorption time may be established.

In this embodiment, based on the data of the desorption rate of the natural gas, a polynomial fitting method can be used to establish the correlation between the desorption rate of the natural gas and the desorption time. Specifically, for example, the correlation of the natural gas desorption rate with desorption time may be established using the following equation:

Q″₂＝19.88(t″₂)^0.1377

wherein, Q ″)₂Represents the natural gas desorption rate, t' of the shale core sample from the wellhead to the airtight desorber or in the specified process₂Representing a desorption time of the shale core sample from a wellhead until being placed in a confined desorber or during the specified process.

Step S204: based on the correlation, an amount of natural gas lost from a wellhead to the process of tripping the shale core sample into the confined desorber may be determined. Specifically, based on the correlation, the natural gas desorption rate of the shale core sample from the wellhead to the process of being placed in the confined desorber can be determined. And determining the natural gas loss amount of the shale core sample from the wellhead to the airtight desorber according to the natural gas desorption rate of the shale core sample from the wellhead to the airtight desorber.

A residual gas volume of the shale core sample may be determined. Specifically, the shale core sample after desorption may be placed in a closed pulverizer filled with water, and the shale core sample after desorption may be pulverized to obtain the residual gas amount of the shale core sample.

Step S205: and determining the shale gas content of the target interval based on the natural gas desorption amount of the shale core sample in the desorption process in the closed desorber, the natural gas loss amount of the shale core sample from the well mouth to the closed desorber, and the residual gas amount and the mass of the shale core sample.

In this embodiment, the mass of the shale core sample may be obtained; and the mass of the shale core sample represents the mass of the shale core sample after the drilling fluid and water on the surface of the shale core sample after desorption is removed. For example, the mass of the shale core sample may be weighed using a ten-thousandth electronic balance to obtain 1050.0325 grams of the mass of the shale core sample.

In this embodiment, the shale gas content of the target interval is determined based on the natural gas desorption amount of the shale core sample during desorption in the closed desorber, the natural gas loss amount of the shale core sample from the wellhead to the closed desorber, and the residual gas amount and the mass of the shale core sample, and specifically may include dividing the sum of the natural gas desorption amount of the shale core sample during desorption in the closed desorber, the natural gas loss amount of the shale core sample from the wellhead to the closed desorber, and the residual gas amount of the shale core sample by the mass of the shale core sample to obtain the shale gas content of the target interval in which the shale core sample is located. Therefore, the shale gas content can be determined by the method provided by the embodiment of the application aiming at a research work area with pressure-maintaining coring.

According to the embodiment of the method for determining the gas content of the shale, the first shale core sample can be placed into a first closed desorber filled with drilling fluid, and a natural gas desorption process of the second shale core sample during lifting is simulated, so that a correlation model of a natural gas desorption rate and a pressure difference is established; wherein the pressure differential is determined from the formation pressure minus the pressure within the first confined desorber; when the pressure in the first closed desorber is reduced to a preset ground pressure, the pressure and the temperature in the first closed desorber can be respectively kept at the preset ground pressure and the formation temperature, and the natural gas desorption process of the second shale core sample after being lifted to a wellhead is simulated to establish a correlation model of the natural gas desorption rate and the desorption time; determining a free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time; the shale gas content of the interval of interest in which the second shale core sample is located may be determined based on the free gas content of the second shale core sample. Therefore, the natural gas loss amount of the shale core sample in the process from drilling to lifting, the natural gas loss amount of the shale core sample in the lifting process and the natural gas loss amount of the shale core sample in the process from a wellhead to the second airtight desorber can be accurately obtained, and the accuracy of the determined shale gas content can be improved.

Fig. 2 is a composition structure diagram of an embodiment of the device for determining gas content of shale. The device for determining the gas content of the shale provides a first shale core sample, a second shale core sample, and the formation temperature and the formation pressure at the depth of a layer where the first shale core sample is located when the first shale core sample is drilled; wherein the first shale core sample is collected by a pressure-holding coring method, and the second shale core sample is collected by a conventional coring method. As shown in fig. 2, the apparatus for determining gas content of shale may include: the method comprises a first correlation model determining module 100, a second correlation model determining module 200, a free gas amount determining module 300 and a shale gas content determining module 400.

The first correlation model determining module 100 may be configured to place the first shale core sample in a first closed desorber filled with a drilling fluid, and simulate a natural gas desorption process of the second shale core sample when the second shale core sample is lifted up, so as to establish a correlation model between a natural gas desorption rate and a pressure difference; wherein the pressure differential is determined from the formation pressure minus the pressure within the first confined desorber.

The second correlation model determining module 200 may be configured to, when the pressure in the first closed desorber is reduced to a preset ground pressure, maintain the pressure and the temperature in the first closed desorber at the preset ground pressure and the formation temperature, respectively, and simulate a natural gas desorption process of the second shale core sample after being lifted up to a wellhead, so as to establish a correlation model between a natural gas desorption rate and a desorption time.

The free gas amount determination module 300 may be configured to determine the free gas amount of the second shale core sample based on the correlation model of the natural gas desorption rate and the pressure difference and the correlation model of the natural gas desorption rate and the desorption time.

The shale gas content determining module 400 may be configured to determine the shale gas content of the interval of interest where the second shale core sample is located based on the free gas content of the second shale core sample.

Fig. 3 is a structural diagram of a first correlation model determining module in an embodiment of the apparatus for determining gas content in shale according to the present application. As shown in fig. 3, the first association model determining module 100 in fig. 2 may include: a first desorption rate data acquisition module 110 and a first model building module 120.

The first desorption rate data acquisition module 110 may be configured to take out the first page rock core sample from the coring barrel after the first page rock core sample is lifted to a wellhead, and place the first page rock core sample into a first airtight desorber filled with a drilling fluid; wherein the temperature and pressure within the first closed desorber are the formation temperature and the formation pressure, respectively; maintaining the first closed desorber in a constant temperature state with the temperature being the formation temperature, reducing the pressure in the first closed desorber from the formation pressure to a preset ground pressure according to a specified pressure reduction rate, and acquiring first natural gas desorption rate data corresponding to the first page rock core sample in the pressure reduction process in the first closed desorber; wherein the first natural gas desorption rate data comprises a plurality of first data points comprising: a pressure differential and a first natural gas desorption rate; the pressure difference corresponds to the first natural gas desorption rate one by one; the specified rate of pressure reduction represents the rate of pressure reduction of the drilling fluid column at the depth of layer at the location of the core barrel during core lifting.

The first model building module 120 may be configured to build a correlation model of the natural gas desorption rate and the pressure difference based on the first natural gas desorption rate data; wherein the correlation model of the natural gas desorption rate and the pressure difference comprises a first correlation coefficient; in particular, the first model determination module may be configured to model the natural gas desorption rate versus pressure differential using the following equation:

Q₁＝a₁₁ΔP²

Fig. 4 is a structural diagram of a second correlation model determining module in an embodiment of the apparatus for determining gas content in shale according to the present application. As shown in fig. 4, the second association model determining module 200 in fig. 2 may include: a second desorption rate data acquisition module 210 and a second model building module 220.

The second desorption rate data acquisition module 210 may be configured to acquire second natural gas desorption rate data corresponding to the first rock core sample in a specified process; wherein the specified process represents a process in which a natural gas desorption rate of the first shale core sample increases with increasing desorption time; the second natural gas desorption rate data comprises a plurality of second data points comprising: a desorption time and a second natural gas desorption rate; the desorption time corresponds to the second natural gas desorption rate one by one.

The second model establishing module 220 may be configured to establish a correlation model of the natural gas desorption rate and the desorption time based on the second natural gas desorption rate data; wherein the correlation model of the natural gas desorption rate and the desorption time comprises a second correlation coefficient and a third correlation coefficient; specifically, the second model establishing module may be configured to establish the correlation model of the desorption rate and the desorption time of the natural gas by using the following formula:

Fig. 5 is a block diagram of a free gas amount determination module in an embodiment of the device for determining gas content of shale. As shown in fig. 5, the free gas amount determination module 300 in fig. 2 may include: a desorption amount determination submodule 310, a first loss amount determination submodule 320, a second loss amount determination submodule 330 and a free gas amount determination submodule 340.

The desorption amount determining submodule 310 may be configured to, after the second shale core sample is lifted to the wellhead, take the second shale core sample out of the coring barrel, and place the second shale core sample into a second airtight desorber filled with a drilling fluid; wherein the temperature and pressure in the second confined desorber are the formation temperature and the preset formation pressure, respectively; and acquiring natural gas desorption rates corresponding to the two appointed desorption times respectively, and the natural gas desorption amount of the second shale core sample in the desorption process in the second closed desorber.

The first loss amount determining submodule 320 may be configured to determine, according to the natural gas desorption rate corresponding to the specified desorption time and the correlation model between the natural gas desorption rate and the desorption time, a natural gas loss amount of the second shale core sample from the wellhead to the second airtight desorber.

The second loss amount determination submodule 330 may be configured to determine, based on the correlation model between the natural gas desorption rate and the pressure difference, a natural gas loss amount of the second shale core sample during the process from drilling to lifting and a natural gas loss amount of the second shale core sample during the lifting.

The free gas amount determining submodule 340 may be configured to determine the free gas amount of the second shale core sample based on a natural gas loss amount of the second shale core sample in a process from drilling to lifting, a natural gas loss amount of the second shale core sample in a lifting process, a natural gas loss amount of the second shale core sample in a process from a wellhead to being placed into a second airtight desorber, and a natural gas desorption amount of the second shale core sample in a desorption process in the second airtight desorber.

The embodiment of the device for determining the gas content of the shale corresponds to the embodiment of the method for determining the gas content of the shale, so that the technical scheme of the embodiment of the method for determining the gas content of the shale can be realized, and the technical effect of the embodiment of the method can be obtained.

In the 90 th generation of 20 th century, it is obvious that improvements in Hardware (for example, improvements in Circuit structures such as diodes, transistors and switches) or software (for improvement in method flow) can be distinguished for a technical improvement, however, as technology develops, many of the improvements in method flow today can be regarded as direct improvements in Hardware Circuit structures, designers almost all obtain corresponding Hardware Circuit structures by Programming the improved method flow into Hardware circuits, and therefore, it cannot be said that an improvement in method flow cannot be realized by Hardware entity modules, for example, Programmable logic devices (Programmable logic devices L organic devices, P L D) (for example, Field Programmable Gate Arrays (FPGAs) are integrated circuits whose logic functions are determined by user Programming of devices), and a digital system is "integrated" on a P L D "by self Programming of designers without requiring many kinds of integrated circuits manufactured and manufactured by special chip manufacturers to design and manufacture, and only a Hardware program is written by Hardware logic editor (software) such as Hardware editor software, software editor, software, Hardware editor, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software, Hardware, software.

Those skilled in the art will also appreciate that, in addition to implementing the controller as pure computer readable program code, the same functionality can be implemented by logically programming method steps such that the controller is in the form of logic gates, switches, application specific integrated circuits, programmable logic controllers, embedded microcontrollers and the like. Such a controller may thus be considered a hardware component, and the means included therein for performing the various functions may also be considered as a structure within the hardware component. Or even means for performing the functions may be regarded as being both a software module for performing the method and a structure within a hardware component.

The apparatuses and modules illustrated in the above embodiments may be implemented by a computer chip or an entity, or by a product with certain functions.

For convenience of description, the above devices are described as being divided into various modules by functions, and are described separately. Of course, the functionality of the various modules may be implemented in the same one or more software and/or hardware implementations as the present application.

From the above description of the embodiments, it is clear to those skilled in the art that the present application can be implemented by software plus necessary general hardware platform. With this understanding in mind, the present solution, or portions thereof that contribute to the prior art, may be embodied in the form of a software product, which in a typical configuration includes one or more processors (CPUs), input/output interfaces, network interfaces, and memory. The computer software product may include instructions for causing a computing device (which may be a personal computer, a server, or a network device, etc.) to perform the methods described in the various embodiments or portions of embodiments of the present application. The computer software product may be stored in a memory, which may include forms of volatile memory in a computer readable medium, Random Access Memory (RAM) and/or non-volatile memory, such as Read Only Memory (ROM) or flash memory (flash RAM). Memory is an example of a computer-readable medium. Computer-readable media, including both non-transitory and non-transitory, removable and non-removable media, may implement information storage by any method or technology. The information may be computer readable instructions, data structures, modules of a program, or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), Static Random Access Memory (SRAM), Dynamic Random Access Memory (DRAM), other types of Random Access Memory (RAM), Read Only Memory (ROM), Electrically Erasable Programmable Read Only Memory (EEPROM), flash memory or other memory technology, compact disc read only memory (CD-ROM), Digital Versatile Discs (DVD) or other optical storage, magnetic cassettes, magnetic tape magnetic disk storage or other magnetic storage devices, or any other non-transmission medium that can be used to store information that can be accessed by a computing device. As defined herein, computer readable media does not include transitory computer readable media (transient media), such as modulated data signals and carrier waves.

The embodiments in the present specification are described in a progressive manner, and the same and similar parts among the embodiments are referred to each other, and each embodiment focuses on the differences from the other embodiments. In particular, as for the apparatus embodiment, since it is substantially similar to the method embodiment, the description is relatively simple, and for the relevant points, reference may be made to the partial description of the method embodiment.

The application is operational with numerous general purpose or special purpose computing system environments or configurations. For example: personal computers, server computers, hand-held or portable devices, tablet-type devices, multiprocessor systems, microprocessor-based systems, set top boxes, programmable consumer electronics, network PCs, minicomputers, mainframe computers, distributed computing environments that include any of the above systems or devices, and the like.

The application may be described in the general context of computer-executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc. that perform particular tasks or implement particular abstract data types. The application may also be practiced in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network. In a distributed computing environment, program modules may be located in both local and remote computer storage media including memory storage devices.

While the present application has been described with examples, those of ordinary skill in the art will appreciate that there are numerous variations and permutations of the present application without departing from the spirit of the application, and it is intended that the appended claims encompass such variations and permutations without departing from the spirit of the application.

Claims

1. A method for determining gas content of shale is characterized in that a first shale core sample and a second shale core sample are provided, and formation temperature and formation pressure at the depth of a layer where the first shale core sample is located when the first shale core sample is drilled are provided; the first shale core sample is collected by a pressure-maintaining coring method, and the second shale core sample is collected by a conventional coring method; the method comprises the following steps:

2. The method for determining the gas content of shale according to claim 1, wherein the step of putting the first shale core sample into a first closed desorber filled with drilling fluid and simulating the natural gas desorption process of the second shale core sample when being lifted up to establish a correlation model of the natural gas desorption rate and the pressure difference comprises the following steps:

3. The method for determining the gas content of shale according to claim 2, wherein the correlation model of the natural gas desorption rate and the pressure difference is established by adopting the following formula:

Q₁＝a₁₁ΔP²

4. The method for determining the gas content in the shale as claimed in claim 1, wherein the simulating the natural gas desorption process of the second shale core sample after being lifted to the wellhead to establish a correlation model of the natural gas desorption rate and the desorption time comprises:

5. The method for determining the gas content in the shale according to claim 4, wherein the correlation model of the natural gas desorption rate and the desorption time is established by adopting the following formula:

6. The method for determining the gas content of shale as claimed in claim 1, wherein the determining the free gas content of the second shale core sample based on the model relating natural gas desorption rate to pressure difference and the model relating natural gas desorption rate to desorption time comprises:

after the second shale core sample is lifted to a wellhead, taking the second shale core sample out of the coring barrel, and putting the second shale core sample into a second closed desorber filled with drilling fluid; wherein the temperature and pressure in the second closed desorber are the formation temperature and the preset surface pressure, respectively; acquiring natural gas desorption rates corresponding to two specified desorption times respectively, and the natural gas desorption amount of the second shale core sample in the desorption process in the second closed desorber;

7. The method for determining the gas content in the shale according to claim 6, wherein the determining the loss amount of the natural gas of the second shale core sample from the wellhead to the second airtight desorber according to the desorption rate of the natural gas corresponding to the specified desorption time and the correlation model of the desorption rate of the natural gas and the desorption time comprises:

8. The method for determining the gas content of the shale as claimed in claim 7, wherein the determining the natural gas loss amount of the second shale core sample from the process of drilling to the process of lifting and the natural gas loss amount of the second shale core sample during the process of lifting based on the correlation model of the natural gas desorption rate and the pressure difference comprises:

9. The method for determining gas content of shale as claimed in claim 1, wherein the method further provides a mass of the second shale core sample; the mass of the second shale core sample represents the mass of the drilling fluid and water on the surface of the second shale core sample after desorption is completed; determining the shale gas content of the target interval where the second shale core sample is located based on the free gas content of the second shale core sample, wherein the determining comprises the following steps:

10. A device for determining gas content of shale is characterized in that the device provides a first shale core sample, a second shale core sample, and formation temperature and formation pressure at the depth of a layer where the first shale core sample is located when the first shale core sample is drilled; the first shale core sample is collected by a pressure-maintaining coring method, and the second shale core sample is collected by a conventional coring method; the device comprises: the device comprises a first correlation model determining module, a second correlation model determining module, a free gas amount determining module and a shale gas content determining module; wherein the content of the first and second substances,

11. The apparatus for determining gas content in shale according to claim 10, wherein the first correlation model determining module comprises: the device comprises a first desorption rate data acquisition module and a first model establishing module; wherein the content of the first and second substances,

Q₁＝a₁₁ΔP²

12. The apparatus for determining gas content in shale according to claim 10, wherein the second correlation model determining module comprises: a second desorption rate data acquisition module and a second model establishing module; wherein the content of the first and second substances,

13. The apparatus for determining gas content in shale according to claim 10, wherein said free gas content determining module comprises: a desorption amount determining submodule, a first loss amount determining submodule, a second loss amount determining submodule and a free gas amount determining submodule; wherein the content of the first and second substances,

the desorption amount determining submodule is used for taking the second shale core sample out of the coring barrel after the second shale core sample is lifted to a wellhead and putting the second shale core sample into a second airtight desorber filled with drilling fluid; wherein the temperature and pressure in the second closed desorber are the formation temperature and the preset surface pressure, respectively; acquiring natural gas desorption rates corresponding to two specified desorption times respectively, and the natural gas desorption amount of the second shale core sample in the desorption process in the second closed desorber;