CN116067821A - Shale gas content measuring method, device, equipment and medium - Google Patents
Shale gas content measuring method, device, equipment and medium Download PDFInfo
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Abstract
The embodiment of the application discloses a method, a device, equipment and a medium for measuring the gas content of shale gas. Wherein the method comprises the following steps: obtaining the free gas content of a target well bore; acquiring the gas content and desorption time of the adsorbed gas of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample; determining the residual quantity according to the shale gas output model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content; and determining the shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity. According to the technical scheme, under the condition of no geological coring, the shale gas content of the target well bore is measured, so that the cost and time for drilling and coring are saved, the cost is reduced, and the engineering time is shortened.
Description
Technical Field
The invention relates to the technical field of oil and gas exploration, in particular to a method, a device, equipment and a medium for measuring the gas content of shale gas.
Background
The formation and enrichment of shale gas have the unique characteristics of the shale gas, and compared with the conventional natural gas, the shale gas development has the advantages of long exploitation life and long production period, and how to determine the gas content of the shale gas is a problem for long-term exploration in the industry.
The main scheme at present is that a geological coring mode is adopted, and shale gas content is tested on a coring sample. However, geological coring of a wellbore presents the problem of greater cost and longer engineering time.
Disclosure of Invention
The invention provides a method, a device, equipment and a medium for measuring the gas content of shale gas, which can measure the gas content of shale gas under the condition of no geological coring. According to an aspect of the present invention, there is provided a method for measuring the gas content of shale gas, the method comprising:
obtaining the free gas content of a target well bore;
acquiring the gas content and desorption time of the adsorbed gas of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample;
determining the residual quantity according to the shale gas output model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content;
and determining the shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity.
According to another aspect of the present invention, there is provided a shale gas content measuring apparatus, comprising:
the free gas content acquisition module is used for acquiring the free gas content of the target well bore;
the adsorption gas content acquisition module is used for acquiring the adsorption gas content and desorption time of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample;
the residual quantity determining module is used for determining residual quantity according to the shale gas output model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content;
the shale gas content determining module is used for determining the shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity.
According to another aspect of the present invention, there is provided an electronic apparatus including:
at least one processor; and
a memory communicatively coupled to the at least one processor; wherein,,
the memory stores a computer program executable by the at least one processor to enable the at least one processor to perform the method for measuring shale gas content according to any embodiment of the invention.
According to another aspect of the present invention, there is provided a computer readable storage medium storing computer instructions for causing a processor to implement the method for measuring shale gas content according to any embodiment of the present invention when executed.
The technical scheme of the embodiment of the application comprises the following steps: obtaining the free gas content of a target well bore; acquiring the gas content and desorption time of the adsorbed gas of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample; determining the residual quantity according to the shale gas output model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content; and determining the shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity. According to the technical scheme, under the geological coring-free condition, the shale gas content of the target well bore is measured by respectively determining the free gas content, the adsorbed gas content and the residual quantity, so that the cost and time for drilling and coring are saved, the cost is reduced, and the engineering time is shortened.
It should be understood that the description in this section is not intended to identify key or critical features of the embodiments of the invention or to delineate the scope of the invention. Other features of the present invention will become apparent from the description that follows.
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In order to more clearly illustrate the technical solutions of the embodiments of the present application, the drawings that are needed in the description of the embodiments will be briefly described below, it being obvious that the drawings in the following description are only some embodiments of the present invention, and that other drawings may be obtained according to these drawings without inventive effort for a person skilled in the art.
FIG. 1 is a flow chart of a method for measuring shale gas content according to an embodiment of the present application;
FIG. 2 is a schematic diagram of cumulative produced gas content of a method for measuring shale gas content according to an embodiment of the present application;
FIG. 3 is a schematic diagram of a ratio of free gas to adsorbed gas to total gas output in a method for measuring shale gas content according to an embodiment of the present application;
fig. 4 is a schematic diagram of a shale gas production model of a shale gas content measuring method according to an embodiment of the present application;
fig. 5 is a flowchart of a method for measuring shale gas content according to a second embodiment of the present application;
fig. 6 is a schematic structural diagram of a shale gas content measuring device according to a third embodiment of the present application;
fig. 7 is a schematic structural diagram of an electronic device for implementing a method for measuring the gas content of shale gas according to an embodiment of the application.
Detailed Description
In order to make the present invention better understood by those skilled in the art, the following description will be made in detail, with reference to the accompanying drawings, in which embodiments of the present invention are shown, and it is apparent that the described embodiments are only some, but not all, embodiments of the present invention. All other embodiments, which can be made by those skilled in the art based on the embodiments of the present invention without making any inventive effort, shall fall within the scope of the present invention.
It should be noted that the terms "first," "second," "target," and the like in the description and claims of the present invention and in the above figures are used for distinguishing between similar objects and not necessarily for describing a particular sequential or chronological order. It is to be understood that the data so used may be interchanged where appropriate such that the embodiments of the invention described herein may be implemented in sequences other than those illustrated or otherwise described herein. Furthermore, the terms "comprises," "comprising," and "having," and any variations thereof, are intended to cover a non-exclusive inclusion, such that a process, method, system, article, or apparatus that comprises a list of steps or elements is not necessarily limited to those steps or elements expressly listed but may include other steps or elements not expressly listed or inherent to such process, method, article, or apparatus.
Example 1
Fig. 1 is a flowchart of a method for measuring the gas content of shale gas according to an embodiment of the present application, where the method may be performed by a device for measuring the gas content of shale gas, where the device for measuring the gas content of shale gas may be implemented in hardware and/or software, and where the device for measuring the gas content of shale gas may be configured in an electronic device with data processing capability. As shown in fig. 1, the method includes:
s110, obtaining the free gas content of the target well bore.
According to the technical scheme, the shale gas content can be measured under the geological coring condition, so that the cost and time for drilling and coring are saved, the cost is reduced, and the engineering time is shortened.
In the embodiment of the application, the unit of the free gas content can be m 3 T, i.e. cubic meters per ton. During drilling, the free gas in the slurry returned from the target well bore can be removed by the deaerator, and the free gas content can be obtained.
In this embodiment, optionally, obtaining the free gas content of the target wellbore includes: and determining the free gas content of the target well bore according to the diameter of the drill bit, the full hydrocarbon value measured by the real-time isotope, the drilling time, the slurry pump displacement, the degasser efficiency and the rock density.
The drill bit diameter may be the diameter of the drill bit used for drilling during the drilling process, and the unit may be m. The real-time isotope measured total hydrocarbon value may be expressed in percent and may be the mud out gas measurement minus the mud in gas measurement. The drilling time can be 1 meter of time for the drill bit to drillThe units are min/m. The unit of the mud pump displacement can be m 3 And/min. Deaerator efficiency may also be referred to as deaeration efficiency. The rock density may be the rock density of the target wellbore.
In an embodiment of the present application, further, determining the free gas content of the target wellbore according to the drill bit diameter, the real-time isotope measurement total hydrocarbon value, the drilling time, the mud pump displacement, the deaerator efficiency, and the rock density, includes: the free gas content is determined by the following formula:
CIGC＝K1×t×Q×TG×ρ/(k2×D)；
wherein CIGC is free gas content, K1 is a constant, the value of K1 can be 0.012732, t is drilling time, Q is slurry pump displacement, TG is a real-time isotope measurement full hydrocarbon value, ρ is rock density, K2 is deaerator efficiency, and D is drill bit diameter.
CIGC is the measured isotopic gas content of the slurry gas in m 3 and/T, which is equal to the free gas content.
By adopting the scheme, the embodiment of the application accurately determines the free gas content of the target well bore.
S120, acquiring the gas content and desorption time of the adsorbed gas of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample.
The cuttings sample may be cuttings generated during a logging process.
In this embodiment, the time of the abscissa in fig. 2 may be the delay time of the shale gas logging, the total output may be the sum of the output amounts of the free gas and the adsorption gas, the curve of the total output may be the change condition of the produced shale gas growing along with time, and the curve of the produced free gas and the curve of the produced adsorption gas are the same. As shown in FIG. 2, taking the adsorbed gas as an example, as the delay time increases, the adsorbed gas produced by the cuttings sample of the target wellbore increases, and the cumulative amount of produced gas (unit m 3 T) gradually approaches the theoretical adsorbed gas content, thus, embodiments of the present application may determine the adsorbed gas content of the cuttings sample of the target wellbore at the desorption time, i.e., at the time of desorptionIn between, the amount of the accumulated produced adsorption gas (unit m 3 T) is the adsorbed gas content of the cuttings sample of the target wellbore, it is obvious that there may be a remaining portion of the cuttings sample that may be processed in a subsequent step.
It should be noted that, the specific desorption time is not limited in the embodiment of the present application. FIG. 3 is a schematic diagram showing the ratio of the total gas output of the free gas and the adsorbed gas.
S130, determining the residual quantity according to the shale gas production model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the remaining amount refers to the amount of shale gas content of the target wellbore other than the free gas content and the adsorbed gas content.
The shale gas output model can be determined according to practical conditions, and the embodiment of the application is not limited to the determination. In one possible embodiment, the time-varying conditions of the adsorbed gas, the free gas, and the total produced gas may be determined based on historical data of the well bore being surveyed, and a shale gas production model may be determined and applied to the target well bore.
As shown in fig. 4, the time 0 may be the time when the drill bit drills the rock in the drilling process, and the shale gas yield model is divided into 3 parts according to the embodiment of the application, wherein the first part is 0 to 6.5 hours, the second part is 6.5 to 12 hours, and the third part is more than 12 hours due to the large difference of the yield gas amounts at different times. According to the scheme, the shale gas output model is divided into 3 parts, so that the curve expression of each part is determined more accurately, and the residual quantity is determined conveniently later.
Specifically, according to the shale gas output model, the total output gas amount when the time is long enough (for example, one month) can be determined, and the total output gas amount corresponding to the desorption time is subtracted from the total output gas amount when the time is long enough, so that the residual amount can be obtained.
For example, if the desorption time is 168 hours, the adsorbed gas content obtained in S120 is the gas content desorbed after 168 hours, in which case, there may be a residual amount in the cuttings sample, and the total output gas content for a sufficiently long time may be subtracted from the total output gas content corresponding to 168 hours to obtain the residual amount.
And S140, determining shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity.
Wherein the shale gas content can be expressed in units of (unit m 3 /T)。
In this embodiment, optionally, determining the shale gas content of the target wellbore according to the free gas content, the adsorbed gas content and the residual amount includes: and determining the sum of the free gas content, the adsorbed gas content and the residual quantity as the shale gas content of the target well bore.
Since the free gas content, the adsorbed gas content and the residual amount of the target well bore are respectively determined, the shale gas content of the target well bore is equal to the sum of the free gas content, the adsorbed gas content and the residual amount.
The technical scheme of the embodiment of the application comprises the following steps: obtaining the free gas content of a target well bore; acquiring the gas content and desorption time of the adsorbed gas of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample; determining the residual quantity according to the shale gas output model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content; and determining the shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity. According to the technical scheme, under the geological coring-free condition, the shale gas content of the target well bore is measured by respectively determining the free gas content, the adsorbed gas content and the residual quantity, so that the cost and time for drilling and coring are saved, the cost is reduced, and the engineering time is shortened.
Example two
Fig. 5 is a flowchart of a method for measuring the gas content of shale gas according to a second embodiment of the present application, where the embodiment of the present application is optimized based on the foregoing embodiment.
As shown in fig. 5, the method in the embodiment of the application specifically includes the following steps:
s210, obtaining the free gas content of the target well bore.
S220, acquiring the gas content and desorption time of the adsorbed gas of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample.
In this embodiment, optionally, the gas content of the adsorbed gas of the cuttings sample of the target wellbore is the gas content of the tank top gas after desorption of the cuttings sample of the target wellbore divided by the mass of the cuttings sample.
It is obvious that since the unit of the adsorption gas content is m 3 If the mass of the rock debris sample is not 1 ton, the adaptive unit conversion can be performed.
In this embodiment, optionally, the adsorbed gas content of the cuttings sample of the target wellbore is determined by the following formula:
PIGC＝TG′×VJ×K3；
where PIGC is the adsorbed gas content of the cuttings sample of the target wellbore, TG' is the total hydrocarbon value corresponding to the real-time isotope measurement of the desorption process, VJ is the headspace volume, k3=1/cuttings sample mass.
In the scheme, the gas content of the adsorption gas of each ton of rock can be converted through proper amplification or reduction according to the mass of the rock debris sample. Illustratively, if the cuttings sample is 0.01T, k3=100, the unit of K3 is 1/T.
S230, determining the residual quantity according to the shale gas production model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the remaining amount refers to the amount of shale gas content of the target wellbore other than the free gas content and the adsorbed gas content.
In this embodiment, optionally, determining the remaining amount according to the shale gas output model and the desorption time includes steps A1-A3:
and A1, determining the total output corresponding to the desorption time according to a shale gas output model.
And step A2, determining the total output corresponding to the preset time according to the shale gas output model.
And step A3, determining the residual quantity according to the total output quantity corresponding to the preset time and the total output quantity corresponding to the desorption time.
The preset time may be determined according to an actual situation, which is not limited in the embodiment of the present application. The total produced gas output may be the sum of the produced gas outputs of the free gas and the adsorbed gas.
For example, the desorption time may be 168 hours, the preset time may be 720 hours, the value of the total gas output of 720 hours and the value of the total gas output of 168 hours are determined according to the shale gas output model, and the remaining amount is determined according to the total gas output of 720 and the total gas output of 168 hours.
In this embodiment, optionally, determining the remaining amount according to the total output amount corresponding to the preset time and the total output amount corresponding to the desorption time includes: and subtracting the total output corresponding to the desorption time from the total output corresponding to the preset time to obtain the residual quantity.
In this embodiment, as illustrated in fig. 4, the shale gas production model is divided into 3 parts, where the first part is 0 to 6.5 hours, and the total production amount y1 may be expressed as:
y1＝0.0504×x 2 +0.3739×x-0.0105；
the amount of free gas m1 produced can be expressed as:
m1＝0.0274×x 2 +0.425×x-0.0359；
the amount of produced adsorption gas n1 can be expressed as:
n1＝0.0229×x 2 0.0511 x+0.0254; where x is time.
The second fraction is 6.5 to 12 hours, in which the total yield y2 can be expressed as:
y2＝-0.0231×x 2 +0.5841×x+1.6696；
the amount of free gas m2 produced can be expressed as:
m2＝-0.0129×x 2 +0.2951×x+2.3214；
the amount of produced adsorption gas n2 can be expressed as:
n2＝-0.0113×x 2 +0.3094 ×x-0.7425; where x is time.
The third fraction is greater than 12 hours, where the total yield y3 can be expressed as:
y3＝3×E -07 ×x 3 -0.0001×x 2 +0.0156×x+5.3367；
the amount of free gas m3 produced can be expressed as:
m3＝1×E -08 ×x 3 -5×E -06 ×x 2 +0.0007×x+4.013；
the amount of produced adsorption gas n3 can be expressed as:
n3＝3×E -07 ×x 3 -0.0001×x 2 +0.0149×x+1.3235; where x is time.
And S240, determining the sum of the free gas content, the adsorbed gas content and the residual quantity as the shale gas content of a target well bore.
According to the technical scheme, according to the shale gas output model, the total output gas quantity in the preset time is determined, and after the total output gas quantity in the desorption time is subtracted from the total output gas quantity in the preset time, the residual quantity is obtained, so that the shale gas content is determined. According to the technical scheme, under the geological coring-free condition, the shale gas content of the target well bore is measured by respectively determining the free gas content, the adsorbed gas content and the residual quantity, so that the cost and time for drilling and coring are saved, the cost is reduced, and the engineering time is shortened.
Example III
Fig. 6 is a schematic structural diagram of a device for measuring the gas content of shale gas according to the third embodiment of the present application, where the device may execute the method for measuring the gas content of shale gas according to any embodiment of the present invention, and has functional modules and beneficial effects corresponding to the execution method. As shown in fig. 6, the apparatus includes:
a free gas content acquisition module 310 for acquiring the free gas content of the target wellbore;
an adsorption gas content acquisition module 320, configured to acquire an adsorption gas content and a desorption time of a cuttings sample of the target wellbore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample;
a remaining amount determining module 330, configured to determine a remaining amount according to the shale gas production model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content;
the shale gas content determining module 340 is configured to determine the shale gas content of the target wellbore according to the free gas content, the adsorbed gas content and the residual amount.
Optionally, the free gas content obtaining module 310 includes:
and the free gas content acquisition unit is used for determining the free gas content of the target well hole according to the diameter of the drill bit, the full hydrocarbon value measured by the real-time isotopes, the drilling time, the slurry pump displacement, the deaerator efficiency and the rock density.
Optionally, the free gas content obtaining unit includes:
the free gas content is determined by the following formula:
CIGC＝K1×t×Q×TG×ρ/(k2×D)；
wherein CIGC is free gas content, K1 is constant 0.012732, t is drilling time, Q is slurry pump displacement, TG is a real-time isotope measurement full hydrocarbon value, ρ is rock density, K2 is deaerator efficiency, and D is drill bit diameter.
Optionally, the gas content of the adsorbed gas of the cuttings sample of the target well bore is the gas content of the tank top gas after desorption of the cuttings sample of the target well bore divided by the mass of the cuttings sample;
the adsorbed gas content of the cuttings sample of the target wellbore is determined using the following formula:
PIGC＝TG′×VJ×K3；
where PIGC is the adsorbed gas content of the cuttings sample of the target wellbore, TG' is the total hydrocarbon value corresponding to the real-time isotope measurement of the desorption process, VJ is the headspace volume, k3=1/cuttings sample mass.
Optionally, the remaining amount determining module 330 includes:
the first total output gas amount determining unit is used for determining the total output gas amount corresponding to the desorption time according to the shale gas output model;
the second total output gas outlet determining unit is used for determining total output gas quantity corresponding to preset time according to the shale gas output model;
and the residual quantity determining unit is used for determining the residual quantity according to the total output quantity corresponding to the preset time and the total output quantity corresponding to the desorption time.
Optionally, the remaining amount determining unit includes:
and the residual quantity determination subunit is used for subtracting the total output quantity corresponding to the desorption time from the total output quantity corresponding to the preset time to obtain the residual quantity.
Optionally, the shale gas content determination module 340 is specifically configured to:
and determining the sum of the free gas content, the adsorbed gas content and the residual quantity as the shale gas content of the target well bore.
The shale gas content measuring device provided by the embodiment of the application can execute the shale gas content measuring method provided by any embodiment of the invention, and has the corresponding functional modules and beneficial effects of the executing method.
Example IV
Fig. 7 shows a schematic diagram of the structure of an electronic device 10 that may be used to implement an embodiment of the invention. Electronic devices are intended to represent various forms of digital computers, such as laptops, desktops, workstations, personal digital assistants, servers, blade servers, mainframes, and other appropriate computers. Electronic equipment may also represent various forms of mobile devices, such as personal digital processing, cellular telephones, smartphones, wearable devices (e.g., helmets, glasses, watches, etc.), and other similar computing devices. The components shown herein, their connections and relationships, and their functions, are meant to be exemplary only, and are not meant to limit implementations of the inventions described and/or claimed herein.
As shown in fig. 7, the electronic device 10 includes at least one processor 11, and a memory, such as a Read Only Memory (ROM) 12, a Random Access Memory (RAM) 13, etc., communicatively connected to the at least one processor 11, in which the memory stores a computer program executable by the at least one processor, and the processor 11 may perform various appropriate actions and processes according to the computer program stored in the Read Only Memory (ROM) 12 or the computer program loaded from the storage unit 18 into the Random Access Memory (RAM) 13. In the RAM 13, various programs and data required for the operation of the electronic device 10 may also be stored. The processor 11, the ROM 12 and the RAM 13 are connected to each other via a bus 14. An input/output (I/O) interface 15 is also connected to bus 14.
Various components in the electronic device 10 are connected to the I/O interface 15, including: an input unit 16 such as a keyboard, a mouse, etc.; an output unit 17 such as various types of displays, speakers, and the like; a storage unit 18 such as a magnetic disk, an optical disk, or the like; and a communication unit 19 such as a network card, modem, wireless communication transceiver, etc. The communication unit 19 allows the electronic device 10 to exchange information/data with other devices via a computer network, such as the internet, and/or various telecommunication networks.
The processor 11 may be a variety of general and/or special purpose processing components having processing and computing capabilities. Some examples of processor 11 include, but are not limited to, a Central Processing Unit (CPU), a Graphics Processing Unit (GPU), various specialized Artificial Intelligence (AI) computing chips, various processors running machine learning model algorithms, digital Signal Processors (DSPs), and any suitable processor, controller, microcontroller, etc. The processor 11 performs the various methods and processes described above, such as the measurement of shale gas content.
In some embodiments, the method of measuring shale gas content may be implemented as a computer program tangibly embodied on a computer-readable storage medium, such as storage unit 18. In some embodiments, part or all of the computer program may be loaded and/or installed onto the electronic device 10 via the ROM 12 and/or the communication unit 19. When the computer program is loaded into RAM 13 and executed by processor 11, one or more steps of the shale gas content measurement method described above may be performed. Alternatively, in other embodiments, the processor 11 may be configured to perform the shale gas content measurement method in any other suitable manner (e.g., by means of firmware).
Various implementations of the systems and techniques described here above may be implemented in digital electronic circuitry, integrated circuit systems, field Programmable Gate Arrays (FPGAs), application Specific Integrated Circuits (ASICs), application Specific Standard Products (ASSPs), systems On Chip (SOCs), load programmable logic devices (CPLDs), computer hardware, firmware, software, and/or combinations thereof. These various embodiments may include: implemented in one or more computer programs, the one or more computer programs may be executed and/or interpreted on a programmable system including at least one programmable processor, which may be a special purpose or general-purpose programmable processor, that may receive data and instructions from, and transmit data and instructions to, a storage system, at least one input device, and at least one output device.
A computer program for carrying out methods of the present invention may be written in any combination of one or more programming languages. These computer programs may be provided to a processor of a general purpose computer, special purpose computer, or other programmable data processing apparatus, such that the computer programs, when executed by the processor, cause the functions/acts specified in the flowchart and/or block diagram block or blocks to be implemented. The computer program may execute entirely on the machine, partly on the machine, as a stand-alone software package, partly on the machine and partly on a remote machine or entirely on the remote machine or server.
In the context of the present invention, a computer-readable storage medium may be a tangible medium that can contain, or store a computer program for use by or in connection with an instruction execution system, apparatus, or device. The computer readable storage medium may include, but is not limited to, an electronic, magnetic, optical, electromagnetic, infrared, or semiconductor system, apparatus, or device, or any suitable combination of the foregoing. Alternatively, the computer readable storage medium may be a machine readable signal medium. More specific examples of a machine-readable storage medium would include an electrical connection based on one or more wires, a portable computer diskette, a hard disk, a Random Access Memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or flash memory), an optical fiber, a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing.
To provide for interaction with a user, the systems and techniques described here can be implemented on an electronic device having: a display device (e.g., a CRT (cathode ray tube) or LCD (liquid crystal display) monitor) for displaying information to a user; and a keyboard and a pointing device (e.g., a mouse or a trackball) through which a user can provide input to the electronic device. Other kinds of devices may also be used to provide for interaction with a user; for example, feedback provided to the user may be any form of sensory feedback (e.g., visual feedback, auditory feedback, or tactile feedback); and input from the user may be received in any form, including acoustic input, speech input, or tactile input.
The systems and techniques described here can be implemented in a computing system that includes a background component (e.g., as a data server), or that includes a middleware component (e.g., an application server), or that includes a front-end component (e.g., a user computer having a graphical user interface or a web browser through which a user can interact with an implementation of the systems and techniques described here), or any combination of such background, middleware, or front-end components. The components of the system can be interconnected by any form or medium of digital data communication (e.g., a communication network). Examples of communication networks include: local Area Networks (LANs), wide Area Networks (WANs), blockchain networks, and the internet.
The computing system may include clients and servers. The client and server are typically remote from each other and typically interact through a communication network. The relationship of client and server arises by virtue of computer programs running on the respective computers and having a client-server relationship to each other. The server can be a cloud server, also called a cloud computing server or a cloud host, and is a host product in a cloud computing service system, so that the defects of high management difficulty and weak service expansibility in the traditional physical hosts and VPS service are overcome.
It should be appreciated that various forms of the flows shown above may be used to reorder, add, or delete steps. For example, the steps described in the present invention may be performed in parallel, sequentially, or in a different order, so long as the desired results of the technical solution of the present invention are achieved, and the present invention is not limited herein.
The above embodiments do not limit the scope of the present invention. It will be apparent to those skilled in the art that various modifications, combinations, sub-combinations and alternatives are possible, depending on design requirements and other factors. Any modifications, equivalent substitutions and improvements made within the spirit and principles of the present invention should be included in the scope of the present invention.
Claims (10)
1. The method for measuring the gas content of the shale gas is characterized by comprising the following steps of:
obtaining the free gas content of a target well bore;
acquiring the gas content and desorption time of the adsorbed gas of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample;
determining the residual quantity according to the shale gas output model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content;
and determining the shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity.
2. The method of claim 1, wherein obtaining the free gas content of the target wellbore comprises:
and determining the free gas content of the target well bore according to the diameter of the drill bit, the full hydrocarbon value measured by the real-time isotope, the drilling time, the slurry pump displacement, the degasser efficiency and the rock density.
3. The method of claim 2, wherein determining the free gas content of the target wellbore based on the bit diameter, the real-time isotope measured total hydrocarbon value, the drilling time, the mud pump displacement, the degasser efficiency, the rock density, comprises:
the free gas content is determined by the following formula:
CIGC＝K1×t×Q×TG×ρ/(k2×D)；
wherein CIGC is free gas content, K1 is constant 0.012732, t is drilling time, Q is slurry pump displacement, TG is a real-time isotope measurement full hydrocarbon value, ρ is rock density, K2 is deaerator efficiency, and D is drill bit diameter.
4. The method of claim 1, wherein the adsorbed gas content of the cuttings sample of the target wellbore is the gas content of the canister top gas after desorption of the cuttings sample of the target wellbore divided by the mass of the cuttings sample;
the adsorbed gas content of the cuttings sample of the target wellbore is determined using the following formula:
PIGC＝TG′×VJ×K3；
where PIGC is the adsorbed gas content of the cuttings sample of the target wellbore, TG' is the total hydrocarbon value corresponding to the real-time isotope measurement of the desorption process, VJ is the headspace volume, k3=1/cuttings sample mass.
5. The method of claim 1, wherein determining the remaining amount based on the shale gas production model and the desorption time comprises:
determining the total output corresponding to the desorption time according to a shale gas output model;
determining the total output corresponding to the preset time according to the shale gas output model;
and determining the residual quantity according to the total output corresponding to the preset time and the total output corresponding to the desorption time.
6. The method of claim 5, wherein determining the remaining amount based on the total produced amount corresponding to the preset time and the total produced amount corresponding to the desorption time comprises:
and subtracting the total output corresponding to the desorption time from the total output corresponding to the preset time to obtain the residual quantity.
7. The method of claim 1, wherein determining a shale gas content of a target wellbore from the free gas content, the adsorbed gas content, and the residual amount comprises:
and determining the sum of the free gas content, the adsorbed gas content and the residual quantity as the shale gas content of the target well bore.
8. The utility model provides a measuring device of shale gas content which characterized in that includes:
the free gas content acquisition module is used for acquiring the free gas content of the target well bore;
the adsorption gas content acquisition module is used for acquiring the adsorption gas content and desorption time of the rock debris sample of the target well bore; the desorption time refers to the time for desorbing the adsorption gas of the rock debris sample;
the residual quantity determining module is used for determining residual quantity according to the shale gas output model and the desorption time; the shale gas output model reflects the output of shale gas of a target well hole at each time; the residual amount refers to the amount of shale gas content of the target wellbore except the free gas content and the adsorbed gas content;
the shale gas content determining module is used for determining the shale gas content of the target well hole according to the free gas content, the adsorbed gas content and the residual quantity.
9. An electronic device, the electronic device comprising:
at least one processor; and
a memory communicatively coupled to the at least one processor; wherein,,
the memory stores a computer program executable by the at least one processor to enable the at least one processor to perform the method of measuring shale gas content of any of claims 1-7.
10. A computer readable storage medium, characterized in that the computer readable storage medium stores computer instructions for causing a processor to implement the method of measuring shale gas content of any of claims 1-7 when executed.
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