Method and device for determining formation pressure coefficient after shale gas well fracturing

Abstract

The invention provides a method and device for determining a formation pressure coefficient after shale gas well fracturing, a computer readable storage medium and electronic equipment. The method comprises the steps of calculating well bottom fracture pressure values of all sections of a horizontal well according to pressure response values after a bridge plug ball is pumped into a well, then calculating a minimum horizontal principal stress value according to pressure drop, well opening pressure and well closing pressure after fracturing pump stopping for a certain time, and correcting a maximum horizontal principal stress value according to an indoor test and well logging method to obtain a well bottom fracture pressure value. And finally, reversely deducing a formation pressure value according to a fracture pressure calculation formula based on the well bottom fracture pressure value, the minimum horizontal principal stress value and the maximum horizontal principal stress value.

Description

Technical Field

[0001] The present invention relates to the technical field of shale gas reservoir exploration and development, and particularly relates to a method, a device, a computer-readable storage medium and an electronic device for determining the formation pressure coefficient after fracturing of a shale gas well. Background Technique

[0002] The technology of shale gas reservoir exploration and development is an important direction for the current and future development in the field of oil exploration. Among them, when exploring shale gas reservoirs, there are many methods for predicting and calculating the formation pressure of shale gas reservoirs. For example:

[0003] Patent ZL201610384295.6 mainly uses seismic means to predict formation pressure. The main method is as follows: perform wavefield separation on the VSP seismic record to obtain the upgoing wave seismic record and the downgoing wave seismic record. Perform deconvolution processing on the downgoing wave seismic record to extract the optimal deconvolution operator. Apply the optimal deconvolution operator to the upgoing wave seismic record and obtain the corridor stack seismic record after processing. Establish an inversion initial velocity model for each layer section through comprehensive analysis and processing of VSP velocity, well logging acoustic velocity, and surface seismic velocity. According to the established inversion initial velocity model, perform inversion calculation on the corridor stack seismic record to obtain the VSP seismic wave impedance. Calculate the longitudinal wave velocity of the rock based on the obtained VSP seismic wave impedance. Calculate the formation pressure value according to the calculated longitudinal wave velocity of the rock.

[0004] Patent ZL201611255977.3 mainly uses well logging methods to calculate formation pressure. The main method is as follows: obtain the well logging data of the target work area, and determine the lithological composition of the drilling well and the percentage content data of the lithological composition, porosity, and pore fluid composition according to the well logging data; obtain the modulus constants of each lithological composition; calculate the bulk modulus of the drilling well after material mixing and the upper and lower limits of the shear modulus of the drilling well after material mixing; calculate the mineral skeleton velocity of the drilling well and the critical pore velocity of the drilling well respectively according to the density, upper and lower limits of the bulk modulus of the drilling well after mixing, and upper and lower limits of the shear modulus of the drilling well after mixing in the well logging data, and determine the mineral skeleton velocity and the critical pore velocity of the target work area. Determine the formation pressure of the target work area according to the density, formation velocity, formation density in the well logging data, and the mineral skeleton velocity and the critical pore velocity of the target work area.

[0005] Patent ZL201710512097.8 discloses a method for calculating formation pressure of shale gas reservoir and a computer-readable storage medium. The method for calculating formation pressure of shale gas reservoir includes: obtaining the elastic tensor of wet clay and the elastic tensor of sandy mixture based on logging data; obtaining the elastic tensor of equivalent shale based on the elastic tensor of wet clay and the elastic tensor of sandy mixture; obtaining the acoustic travel time based on the elastic tensor of equivalent shale; and obtaining the formation pressure of shale gas reservoir based on the acoustic travel time.

[0006] Patent ZL201910652304.9, a method for calculating formation pressure based on short-term production data. By mainly selecting the formation pressure and cumulative gas production of any two production points with the production time interval in the pseudo-steady state stage less than 1 month, and combining the original formation pressure, deviation coefficient under original conditions, and the relationship formula between deviation coefficient and pressure under the condition of pressure ≥ 13 MPa, a method for calculating formation pressure of any production point is established. Substituting the cumulative gas production of any production point, the corresponding formation pressure can be calculated.

[0007] Patent ZL202110763391.2 relates to a method, device, medium and equipment for predicting and analyzing formation pressure, including the following steps: a Measuring the formation pore pressure equivalent density, overburden pressure equivalent density, formation water density, measured acoustic travel time value and measured formation pressure data point Ep at the formation well depth H; b Substituting the formation pore pressure equivalent density, overburden pressure equivalent density, formation water density and measured acoustic travel time value at the well depth H into the Eaton method formation pore pressure calculation model formula; c Obtaining the normal pressure trend line. When abnormal pressure increase occurs in the formation, using the feedforward neural network model in deep learning to correct the Eaton method formation pore pressure calculation model formula, so as to determine the optimal solution of the acoustic travel time trend line of a single well; d Based on the formation pore pressure equivalent density and measured formation pressure data point Ep, calculating the deviation and variance, and using the feedforward neural network model in deep learning to predict the regional Eaton index n.

[0008] The patent 202010228391.8 under application provides a method for calculating formation pressure for shale gas wells. By using the element logging data widely used in shale gas wells and selecting the elements that are jointly sensitive to the rock pore volume parameter and the rock pore fluid volume parameter, a relationship model with the formation pressure is established, achieving the purpose of calculating the formation pressure of shale gas in real time, continuously and accurately through element logging data.

[0009] Patent ZL202110887725.7 provides a method and device for calculating the average formation pressure of a coalbed methane reservoir. By counting the basic parameters of the coal seam and the cumulative water production and gas production of the coalbed methane wells, the basic parameters, cumulative water production and cumulative gas production are used to calculate the average formation pressure of the coalbed methane reservoir. The parameters used in this method are easy to obtain, thereby reducing the difficulty and cost of calculating the average formation pressure. In addition, the formation pressure and critical desorption pressure are obtained, and by judging whether the formation pressure is greater than the critical desorption pressure, it is determined that the coalbed methane reservoir is in the early drainage stage or the gas desorption stage. Different calculation methods are used to calculate the average formation pressure of the coalbed methane reservoir according to different stages. In the process of coalbed methane development, the effects of dissolved gas, stress sensitivity and matrix shrinkage are taken into account, and the average formation pressure of the coalbed methane reservoir can be calculated more accurately.

[0010] Patent 202211622189.9, which is being applied for, is a method for calculating the formation pressure of a gas well based on reservoir stress sensitivity. It uses the test data before the gas well is put into production, the production capacity test data, and the bottom hole pressure and production data at any time. It can quickly calculate the formation pressure at that moment without shutting down the well, evaluate the gas well production capacity, and is of great significance to the dynamic analysis of gas well production.

[0011] Patent 202111556248.2, which is being applied for, is a method, device and equipment for calculating the combined P-wave and S-wave formation pressure, which belongs to the field of geophysical exploration. It includes the following steps: obtaining borehole seismic data of P-wave and S-wave, and preprocessing the borehole seismic data of P-wave and S-wave; based on the preprocessed borehole seismic data, stratifying the measured formation, and calculating the P-wave layer velocity and S-wave layer velocity of each measured formation; obtaining well logging density data, processing the well logging density data, and obtaining the density data of each measured formation; based on the P-wave layer velocity, S-wave layer velocity and density data of each measured formation, determining the ground stress of the formation to be measured in each measured formation; based on the average density of the overlying formation of the measured formation, determining the overlying formation pressure at the formation to be measured; based on the overlying formation pressure and ground stress at the formation to be measured, determining the formation pressure of the formation to be measured.

[0012] Among the above methods for calculating formation pressure, geophysics, logging interpretation and production test are the most common. Before fracturing shale oil and gas wells, the formation pressure is generally estimated by seismic prediction and drilling fluid density. A small number of wells also use micro-injection fracturing to obtain formation pressure, but the test time is generally longer and the test is mainly based on the formation pressure before fracturing. Summary of the invention

[0013] In view of the above problems, embodiments of the present invention provide a method, an apparatus, a computer-readable storage medium and an electronic device for determining a formation pressure coefficient after fracturing a shale gas well.

[0014] In a first aspect, an embodiment of the present invention provides a method for determining the formation pressure coefficient after fracturing of a shale gas well, including the following steps:

[0015] S100. Determine the bottom-hole fracture pressure value of each section of the horizontal well according to the pressure response after pumping the bridge plug ball into the wellbore;

[0016] S200. Determine the minimum horizontal principal stress value of each section of the horizontal well according to the shut-in pressure curve after the fracturing pump is stopped;

[0017] S300. Determine the corresponding maximum horizontal principal stress value according to the minimum horizontal principal stress value of each section of the horizontal well;

[0018] S400. Determine the formation pressure value according to the bottom-hole fracture pressure value, the minimum horizontal principal stress value, the maximum horizontal principal stress value of each section of the horizontal well, and the core tensile strength;

[0019] S500. Determine the formation pressure coefficient according to the ratio of the formation pressure value to the formation depth.

[0020] According to the embodiment of the present invention, step S100 mainly includes:

[0021] According to the pressure response after pumping the bridge plug ball into the wellbore, determine the ground pressure peak value, the liquid column pressure, and the wellbore friction; determine the bottom-hole fracture pressure value of each section of the horizontal well according to the bottom-hole fracture pressure calculation formula:

[0022] Pf = Pmax + Pl - P

[0023] In the formula, Pf is the bottom-hole fracture pressure, Pmax is the ground pressure peak value, Pl is the liquid column pressure, and P is the wellbore friction.

[0024] According to the embodiment of the present invention, the above wellbore friction is equivalent to the clear water friction.

[0025] According to the embodiment of the present invention, step S200 mainly includes:

[0026] According to the shut-in pressure curve after the last stage of fracturing pump is stopped, determine the pressure drop, the open-hole pressure, and the shut-in pressure after a specified shut-in time of the fracturing pump;

[0027] Calculate the minimum horizontal principal stress value according to the pressure drop, the open-hole pressure, and the shut-in pressure after the specified shut-in time of the fracturing pump.

[0028] According to the embodiment of the present invention, calculating the minimum horizontal principal stress value according to the pressure drop, the open-hole pressure, and the shut-in pressure after the specified shut-in time of the fracturing pump includes:

[0029] According to the pressure drop, the open-hole pressure, and the shut-in pressure after the specified shut-in time of the fracturing pump, determine the closure pressure value by using the G-function analysis method of fracturing;

[0030] Equivalent the closed pressure value to the minimum horizontal principal stress value.

[0031] According to an embodiment of the present invention, in step S400, the core tensile strength is determined by the Brazilian splitting method.

[0032] According to an embodiment of the present invention, the formation pressure value is inversely calculated according to the following fracture pressure calculation formula:

[0033] Pf = 3σh - σH - Ph + T0

[0034] In the formula, Pf is the bottom-hole fracture pressure, σh is the minimum horizontal principal stress value, σH is the maximum horizontal principal stress value, and T0 is the core tensile strength.

[0035] In a second aspect, the present invention further provides a device for determining the formation pressure coefficient after fracturing of a shale gas well, which is characterized by including:

[0036] A bottom-hole fracture pressure analysis module, configured to determine the bottom-hole fracture pressure value of each section of the horizontal well according to the pressure response after pumping the bridge plug ball into the wellbore;

[0037] A minimum principal stress value analysis module, configured to determine the minimum horizontal principal stress value of each section of the horizontal well according to the shut-in pressure curve after the fracturing pump stops;

[0038] A maximum principal stress value analysis module, configured to determine the corresponding maximum horizontal principal stress value according to the minimum horizontal principal stress value of each section of the horizontal well;

[0039] A formation pressure value calculation module, configured to determine the formation pressure value according to the bottom-hole fracture pressure value, the minimum horizontal principal stress value, the maximum horizontal principal stress value, and the core tensile strength of each section of the horizontal well;

[0040] A formation pressure coefficient determination module, configured to determine the formation pressure coefficient according to the ratio of the formation pressure value to the formation depth.

[0041] In a third aspect, an embodiment of the present invention provides a computer-readable storage medium, on which a computer program is stored, and when the program is executed by a processor, it implements a method for determining the formation pressure coefficient after fracturing of a shale gas well as described in the first aspect above.

[0042] In a fourth aspect, an embodiment of the present invention provides an electronic device, which includes:

[0043] A processor;

[0044] A memory for storing executable instructions of the processor;

[0045] Wherein, the processor is configured to execute the instructions to implement a method for determining the formation pressure coefficient after fracturing of a shale gas well as described in the first aspect above.

[0046] Compared with the prior art, the above technical solution of the present invention has the following beneficial effects:

[0047] The present invention provides a method for determining the formation pressure coefficient after fracturing of a shale gas well. This method uses the main fracturing construction curves of each section of the horizontal well of shale gas to determine the fracture pressure, the minimum principal stress value, and the maximum principal stress value, calculates the formation pressure value based on the fracture pressure, the minimum principal stress value, and the maximum principal stress value, and further determines the formation pressure coefficient. This method is simple and easy to implement. Through this method, the pressure coefficient of the reservoir can be judged, and then for shales with different pressure coefficients, different fracturing modes can be adopted to adjust the on-site fracturing construction parameters. BRIEF DESCRIPTION OF THE DRAWINGS

[0048] In order to more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the following will briefly introduce the drawings required for the description of the embodiments or the prior art. Obviously, the following drawings are only some embodiments of the present invention. For those of ordinary skill in the art, other drawings can be obtained based on these drawings without creative efforts.

[0049] Figure 1 is a flowchart of the steps of the method for determining the formation pressure coefficient after fracturing of a shale gas well provided by an embodiment of the present invention;

[0050] Figure 2 is an actual construction curve diagram when the pressure rises to the peak Pmax after the bridge plug ball is set in the first case of the embodiment of the present invention;

[0051] Figure 3 is the fracture pressure value of each section calculated in the first case of the embodiment of the present invention (where the inversion algorithm of the present invention is used for the first section);

[0052] Figure 4 is the formation pressure value obtained in the first case of the embodiment of the present invention;

[0053] Figure 5 is the fracture pressure value of each section calculated in the second case of the embodiment of the present invention (where the inversion algorithm of the present invention is used for the first section);

[0054] Figure 6 is a schematic diagram of the composition of an electronic device provided by an embodiment of the present invention. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0055] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are some, but not all, of the embodiments of the present invention. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts shall fall within the scope of protection of the present invention.

[0056] Embodiment 1

[0057] For most of the main body of hydraulic fracturing of shale gas horizontal wells, an open-hole liner (two sizes of φ139.7mm or φ114.3mm) + pumped bridge plug and perforation joint operation process technology is adopted, with a domestic share of over 95%. The main steps of this set of process technology are as follows: (1) For the first stage, continuous oil perforation or opening the toe-end sliding sleeve is adopted; (2) Fracture the first stage; (3) Use cable to pump a hollow soluble or drillable bridge plug to the designated position for setting, then lift the perforating gun to perform perforation for each cluster in the second stage. After the perforation is completed, lift it out of the wellhead; (4) After pumping the bridge plug ball into the wellbore, seal the first stage; (5) Fracture the second stage; (6) Subsequently, fracture to the last stage according to steps (3), (4), and (5).

[0058] In the first step, calculate the bottom-hole fracture pressure of each stage according to the pressure response after pumping the bridge plug ball into the wellbore. The specific method is to pump the bridge plug ball into the bottom hole at a displacement of 2m 3 / min. At the moment when the bridge plug ball is set on the bridge plug, it will burst open the perforation cluster, and the wellhead pressure will have a large increase. After the pressure rises to the peak value Pmax, it will drop, indicating that the formation is fractured. The bottom-hole fracture pressure calculation formula is:

[0059] Pf = Pmax + Pl - P

[0060] In the formula, Pf is the bottom-hole fracture pressure, Pmax is the ground pressure peak value, Pl is the liquid column pressure, and P is the wellbore friction.

[0061] During the stage of setting the bridge plug ball, the inside of the φ139.7mm or φ114.3mm casing is mainly a mixture of pre-treatment acid, clear water, and part of the slickwater. Since the displacement is small at this time (2m 3 / min), compared with clear water, the friction value of the slickwater is equivalent. At this time, the liquid in the wellbore can be equivalently regarded as clear water. According to the friction formula of clear water, it is calculated based on the entire casing length from the perforation section to the wellhead, and then substituted into the bottom-hole fracture pressure calculation formula, and the fracture pressure value Pf of each stage can be obtained more simply.

[0062] Step 2: Calculate the minimum horizontal principal stress value based on the pressure drop after pump shutdown for 30 minutes after fracturing and the well-opening pressure. Specifically, use the shut-in pressure curve after the last-stage fracturing pump shutdown, and analyze and obtain the closure pressure value through the G-function analysis method of fracturing, which is equivalent to the minimum principal stress value. For normal-pressure shale, the minimum principal stress values of each section of a single well can also be calculated from the pressure curves of each section after pump shutdown and shut-in.

[0063] Step 3: Compare the minimum principal stress value obtained by on-site inversion with the value calculated by in-situ stress testing or logging methods before fracturing design. If they are relatively close, the maximum horizontal principal stress value is given by the in-situ stress testing or logging calculation method. If they are inconsistent, correct the stress profile according to the logging method and the inverted minimum principal stress, and give the maximum horizontal principal stress σH.

[0064] Step 4: Before fracturing design, obtain the tensile strength T0 of the shale core of the target layer of this well by the Brazilian splitting method.

[0065] Step 5: According to the formula Pf = 3σh - σH - Ph + T0, calculate the formation pressure value Ph in reverse. From the ratio of the formation pressure to the depth, the formation pressure coefficient can be determined.

[0066] Through Figure 1 the method shown above, the formation pressure coefficient values of each section or a single well can be obtained relatively simply. If they are consistent with the pre-fracturing understanding, the original fracturing design idea and plan can be used for fracturing construction. If they are inconsistent with the pre-fracturing understanding, the fracturing design and plan need to be corrected. This method helps to guide on-site fracturing construction.

[0067] The following combines the on-site specific implementation process and results to illustrate the technical effects of the method for determining the formation pressure coefficient after fracturing of shale gas wells.

[0068] Case 1: A shale gas well in the southeastern Sichuan region, with a vertical depth of 4242.00 - 4364.53 m, passing through the second, third, and fourth sub-layers, and there are small faults around. This well was fractured in 25 sections, and the Pmax pressure values after the plugs and balls of each section were seated were recorded as Figure 2 shown, and the bottom-hole fracture pressure Pf of each section was obtained through the calculation formula, as Figure 3 shown.

[0069] This well is an overpressure reservoir. The pressure drop after 30 minutes of pump shutdown for each section is small. The minimum principal stress calculated by the shut-in pressure is 98 MPa, which is consistent with the in-situ stress test before fracturing design. Then the maximum horizontal principal stress value is 108 MPa.

[0070] The tensile strength of this well is 12 MPa.

[0071] Using the formula in Step 5, the formation pressure value can be calculated as Figure 4As shown, the average formation pressure of each section is 76.7 Mpa, and the calculated formation pressure coefficient is 1.78, which is equivalent to the pressure coefficient obtained from the pressure build-up test. Based on the formation pressure value obtained according to the present invention, the dynamic adjustment of the fracturing construction parameters for each section is further improved. The construction success rate after fracturing of this well is relatively high, and the test production of this well is also relatively high, reaching 42.66×104 m3 / d, achieving good application results.

[0072] Case 2: A deep shale gas well in southeastern Sichuan. The vertical depth of Target A is 4242.17 m, and the vertical depth of Target B is 4343.80 m. This well was fractured in 30 sections, and the Pmax pressure values after the bridge plugs and balls were seated in each section were recorded. Through the calculation formula, the bottom-hole fracture pressure of each section was obtained, as Figure 5 shown.

[0073] This well is an overpressure reservoir. The pressure drop within 30 minutes after the pump was stopped in each section was small. After shut-in, the minimum principal stress was calculated to be 98 MPa using the pressure, and the maximum horizontal principal stress value was 113 MPa.

[0074] The tensile strength of this well is 14 MPa.

[0075] Finally, the average formation pressure of each section was calculated to be 63.2 MPa, and then the formation pressure coefficient was calculated to be 1.47, which is equivalent to the pressure coefficient obtained from the pressure build-up test.

[0076] Based on the formation pressure value obtained according to the present invention, the dynamic adjustment of the fracturing construction parameters for each section is further improved. The construction success rate after fracturing of this well is relatively high, and the test production of this well is also relatively high, reaching 41.2×104 m3 / d, achieving good application results.

[0077] Case 3: A well in southeastern Sichuan. The total measured depth after drilling is 4482.5 m, and the vertical depth is 3526.87 m. The formation after drilling is the Longmaxi Formation. The measured depth of Target A is 3575.00 m, and the vertical depth is 3250.67 m. The measured depth of Target B is 4482.5 m, and the vertical depth is 3526.87 m. Before fracturing, the geological design of this well considered it to be an overpressure reservoir, and the pressure coefficient was 1.35 - 1.45.

[0078] Before fracturing this well, there were 9 sections. The formation opening pressure was relatively low, about 11 - 24 MPa. According to experience, it was speculated to be an atmospheric pressure reservoir. However, since the formation pressure value could not be calculated by other methods and the persuasion was not strong, on-site, the fracturing design plan was still carried out according to the overpressure shale gas fracturing mode. Through the method of the present invention, the fracture pressure values, minimum principal stress values, and maximum principal stresses of each section were calculated by on-site technicians. Finally, the average pressure coefficient of the first 9 sections was calculated, and this value was 0.9, determining it to be an atmospheric pressure reservoir. The subsequent fracturing sections were adjusted accordingly according to the atmospheric pressure shale gas fracturing mode.

[0079] The present invention has been applied in various shale gas blocks in northeastern and southeastern Sichuan. It can calculate the formation pressure more accurately, which is a new and important evaluation method for post-fracture analysis and can effectively guide the adjustment of fracturing construction parameters for each well.

[0080] Embodiment 2

[0081] In addition, the present invention also provides a device for determining the formation pressure coefficient after fracturing of a shale gas well, which mainly includes:

[0082] A bottom-hole fracture pressure analysis module, which is used to determine the bottom-hole fracture pressure value of each section of the horizontal well according to the pressure response after pumping the bridge plug ball into the wellbore;

[0083] A minimum principal stress value analysis module, which is used to determine the minimum horizontal principal stress value of each section of the horizontal well according to the shut-in pressure curve after fracturing pump shutdown;

[0084] A maximum principal stress value analysis module, which is used to determine the corresponding maximum horizontal principal stress value according to the minimum horizontal principal stress value of each section of the horizontal well;

[0085] A formation pressure value calculation module, which is used to determine the formation pressure value according to the bottom-hole fracture pressure value, the minimum horizontal principal stress value, the maximum horizontal principal stress value of each section of the horizontal well and the core tensile strength;

[0086] A formation pressure coefficient determination module, which is used to determine the formation pressure coefficient according to the ratio of the formation pressure value to the formation depth.

[0087] Embodiment 3

[0088] This embodiment provides a computer-readable medium, on which a computer program is stored. When the program is executed by a processor, it realizes each step of a method for determining the formation pressure coefficient after fracturing of a shale gas well as described in the above embodiment.

[0089] It should be noted that all or part of the processes in the methods of the above embodiments of the present invention can be completed by instructing relevant hardware through a computer program. The computer program can be stored in a computer-readable storage medium. When the computer program is executed by a processor, the steps of the above method embodiments can be implemented. Among them, the computer program includes computer program code, and the computer program code can be in the form of source code, object code, executable file or some intermediate form, etc. The computer-readable medium can include: any entity or device capable of carrying the computer program code, recording medium, USB flash drive, mobile hard disk, magnetic disk, optical disc, computer memory, read-only memory (ROM, Read-Only Memory), random access memory (RAM, Random Access Memory), electrical carrier signal, telecommunication signal, and software distribution medium, etc. Of course, there are other ways of readable storage media, such as quantum memory, graphene memory, and so on. It should be noted that the content included in the computer-readable medium can be appropriately increased or decreased according to the requirements of legislation and patent practice within the jurisdiction. For example, in some jurisdictions, according to legislation and patent practice, the computer-readable medium does not include electrical carrier signals and telecommunication signals.

[0090] Embodiment 4

[0091] Figure 6 is a schematic structural diagram of an electronic device according to an embodiment of the present invention. As Figure 6 shown, at the hardware level, the electronic device includes a processor, and optionally also includes an internal bus, a network interface, and a memory. Among them, the memory may include a memory, such as a high-speed random access memory (Random-Access Memory, RAM), and may also include a non-volatile memory, such as at least one disk memory, etc. Of course, the electronic device may also include other hardware required for other services.

[0092] The processor, network interface, and memory can be interconnected through an internal bus. The internal bus can be an ISA (Industry Standard Architecture) bus, a PCI (Peripheral Component Interconnect) bus, or an EISA (Extended Industry Standard Architecture) bus, etc. The bus can be divided into an address bus, a data bus, a control bus, etc. For the sake of convenience of representation, only line segments are used in the figure, but it does not mean that there is only one bus or one type of bus.

[0093] A memory for storing programs. Specifically, the program may include program codes, and the program codes include computer operation instructions. The memory may include a memory and a non-volatile memory, and provide instructions and data to the processor. The processor reads the corresponding computer program from the non-volatile memory into the memory and then runs it. The processor executes the program stored in the memory to perform all the steps in the foregoing method for determining the formation pressure coefficient after fracturing a shale gas well.

[0094] The communication bus mentioned in the above device may be a Peripheral Component Interconnect (PCI) bus or an Extended Industry Standard Architecture (EISA) bus, etc. This communication bus can be divided into an address bus, a data bus, a control bus, etc. For the sake of easy representation, only a thick line is shown in the figure, but it does not mean that there is only one bus or one type of bus. The communication interface is used for communication between the above electronic device and other devices.

[0095] The bus includes hardware, software, or both, for coupling the above components to each other. For example, the bus may include an Accelerated Graphics Port (AGP) or other graphics bus, an Enhanced Industry Standard Architecture (EISA) bus, a Front Side Bus (FSB), a HyperTransport (HT) interconnect, an Industry Standard Architecture (ISA) bus, an InfiniBand interconnect, a Low Pin Count (LPC) bus, a memory bus, a MicroChannel Architecture (MCA) bus, a Peripheral Component Interconnect (PCI) bus, a PCI-Express (PCI-X) bus, a Serial Advanced Technology Attachment (SATA) bus, a Video Electronics Standards Association Local (VLB) bus, or other suitable buses, or a combination of two or more of these. In a suitable case, the bus may include one or more buses. Although the embodiments of the present invention describe and illustrate specific buses, the present invention contemplates any suitable bus or interconnect.

[0096] The memory may include a Random Access Memory (RAM), and may also include a Non-Volatile Memory (NVM), such as at least one disk memory. Optionally, the memory may also be at least one storage device located far from the foregoing processor.

[0097] The memory may include a mass memory for data or instructions. By way of example and not limitation, the memory may include a hard disk drive (HDD), a floppy disk drive, flash memory, an optical disk, a magneto-optical disk, a magnetic tape, or a universal serial bus (USB) drive, or a combination of two or more of these. Where appropriate, the memory may include removable or non-removable (or fixed) media. In a particular embodiment, the memory is a non-volatile solid-state memory. In a particular embodiment, the memory includes a read-only memory (ROM). Where appropriate, the ROM may be a mask-programmed ROM, a programmable ROM (PROM), an erasable PROM (EPROM), an electrically erasable PROM (EEPROM), an electrically rewritable ROM (EAROM), or flash memory, or a combination of two or more of these.

[0098] The above-mentioned processor may be a general-purpose processor, including a central processing unit (CPU), a network processor (NP), etc.; it may also be a digital signal processor (DSP), an application specific integrated circuit (ASIC), a field-programmable gate array (FPGA), or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components.

[0099] It should be noted that those skilled in the art can clearly understand that, for the convenience and brevity of description, only the above-mentioned division of each functional unit and module is used as an example. In actual applications, the above functions can be allocated to different functional units and modules as needed, that is, the internal structure of the device is divided into different functional units or modules to complete all or part of the functions described above. Each functional unit and module in the embodiments can be integrated in a processing unit, or each unit can exist physically alone, or two or more units can be integrated in one unit. The above integrated unit can be implemented in the form of hardware or in the form of a software functional unit. In addition, the specific names of each functional unit and module are only for the convenience of distinguishing from each other and do not limit the protection scope of the present invention. The specific working processes of the units and modules in the above system can refer to the corresponding processes in the foregoing method embodiments and will not be repeated here.

[0100] The devices, equipment, systems, modules or units illustrated in the above embodiments can be specifically implemented by computer chips or entities, or by products with certain functions. A typical implementation device is a computer. Specifically, the computer can be, for example, a personal computer, a laptop computer, an in-vehicle human-machine interaction device, a cellular phone, a camera phone, a smart phone, a personal digital assistant, a media player, a navigation device, an email device, a game console, a tablet computer, a wearable device, or any combination of these devices.

[0101] Although the present invention provides method operation steps as described in the embodiments or flowcharts, more or fewer operation steps may be included based on conventional or non-creative means. The order of steps listed in the embodiments is only one way among many execution orders of the steps and does not represent the only execution order. When the actual device or terminal product is executed, it can be executed in the order of the method shown in the embodiments or the drawings, or executed in parallel (for example, in a parallel processor or multi-threaded processing environment, or even in a distributed data processing environment).

[0102] The present invention is described with reference to the flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to the embodiments of the present invention. It should be understood that each flow and / or block in the flowchart and / or block diagram, and the combination of flows and / or blocks in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to the processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing devices to generate a machine, such that the instructions executed by the processor of the computer or other programmable data processing devices generate a device for implementing the functions specified in Figure 1 one flow or multiple flows and / or blocks Figure 1 one block or multiple blocks.

[0103] These computer program instructions can also be stored in a computer-readable memory that can direct a computer or other programmable data processing devices to work in a specific manner, such that the instructions stored in the computer-readable memory generate a manufactured product including an instruction device, and the instruction device implements the functions specified in Figure 1 one flow or multiple flows and / or blocks Figure 1 one block or multiple blocks.

[0104] These computer program instructions can also be loaded onto a computer or other programmable data processing devices, such that a series of operation steps are executed on the computer or other programmable devices to generate a computer-implemented process, and thus the instructions executed on the computer or other programmable devices provide for implementing the functions in Figure 1 one flow or multiple flows and / or blocks Figure 1Steps of the functions specified in one or more boxes.

[0105] It should be noted that in this text, relational terms such as first and second are only used to distinguish one entity or operation from another entity or operation, and do not necessarily require or imply any actual relationship or order between these entities or operations. Moreover, the term "comprising", "including" or any other variant thereof is intended to cover non-exclusive inclusion, so that a process, method, article or device comprising a series of elements not only includes those elements, but also includes other elements not expressly listed, or also includes elements inherent to such process, method, article or device. Without further limitation, an element defined by the statement "comprising one..." does not exclude the presence of additional identical elements in the process, method, article or device comprising the said element.

[0106] Each embodiment in this specification is described in a related manner. The same or similar parts between the embodiments can be referred to each other, and the differences between each embodiment and other embodiments are emphasized. In particular, for the embodiments of the device, electronic device and readable storage medium, since they are basically similar to the method embodiments, the description is relatively simple, and the relevant parts can be referred to the description of the method embodiments.

[0107] The above is only a preferred embodiment of the present invention and is not intended to limit the protection scope of the present invention. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention are included in the protection scope of the present invention.

Claims

1. A method for determining the formation pressure coefficient after fracturing of a shale gas well, characterized in that, It includes the following steps: S100. Determine the bottom-hole fracture pressure value of each section of the horizontal well according to the pressure response after pumping the bridge plug ball into the wellbore; S200. Determine the minimum horizontal principal stress value of each section of the horizontal well according to the shut-in pressure curve after the fracturing pump is stopped; S300. Determine the corresponding maximum horizontal principal stress value according to the minimum horizontal principal stress value of each section of the horizontal well; S400. Determine the formation pressure value according to the bottom-hole fracture pressure value, minimum horizontal principal stress value, maximum horizontal principal stress value of each section of the horizontal well and the core tensile strength; S500. Determine the formation pressure coefficient according to the ratio of the formation pressure value to the formation depth.

2. The method for determining the formation pressure coefficient after fracturing of a shale gas well according to claim 1, characterized in that, Step S100 includes: According to the pressure response after pumping the bridge plug ball into the wellbore, determine the surface pressure peak value, liquid column pressure and wellbore friction; Determine the bottom-hole fracture pressure value of each section of the horizontal well according to the bottom-hole fracture pressure calculation formula: Pf = Pmax + Pl - P In the formula, Pf is the bottom-hole fracture pressure, Pmax is the surface pressure peak value, Pl is the liquid column pressure, and P is the wellbore friction.

3. The method for determining the formation pressure coefficient after fracturing of a shale gas well according to claim 2, characterized in that, The wellbore friction is equivalent to the clear water friction.

4. The method for determining the formation pressure coefficient after fracturing of a shale gas well according to claim 1, characterized in that, Step S200 includes: According to the shut-in pressure curve after the last section of fracturing pump is stopped, determine the pressure drop, open-hole pressure and shut-in pressure after a specified shut-in time of the fracturing pump; Calculate the minimum horizontal principal stress value according to the pressure drop, open-hole pressure and shut-in pressure after the specified shut-in time of the fracturing pump.

5. The method for determining the formation pressure coefficient after fracturing of a shale gas well according to claim 4, wherein The calculating the minimum horizontal principal stress value according to the pressure drop, open-hole pressure and shut-in pressure after the specified shut-in time of the fracturing pump includes: According to the pressure drop, open-hole pressure and shut-in pressure after the specified shut-in time of the fracturing pump, determine the closure pressure value by using the G-function analysis method of fracturing; Equivalent the closure pressure value to the minimum horizontal principal stress value.

6. The method for determining the formation pressure coefficient after fracturing of a shale gas well according to claim 5, characterized in that, In step S400, the core tensile strength is determined by the Brazilian splitting method.

7. The method for determining the formation pressure coefficient after fracturing of a shale gas well according to claim 6, characterized in that Reverse calculate the formation pressure value according to the fracture pressure calculation formula: Pf = 3σh - σH - Ph + T0 In the formula, Pf is the bottom-hole fracture pressure, σh is the minimum horizontal principal stress value, σH is the maximum horizontal principal stress value, and T0 is the core tensile strength.

8. A device for determining the formation pressure coefficient after fracturing of a shale gas well, characterized in that, It includes: A bottom-hole fracture pressure analysis module, which is used to determine the bottom-hole fracture pressure value of each section of the horizontal well according to the pressure response after pumping the bridge plug ball into the wellbore; A minimum principal stress value analysis module, which is used to determine the minimum horizontal principal stress value of each section of the horizontal well according to the shut-in pressure curve after the fracturing pump is stopped; A maximum principal stress value analysis module, which is used to determine the corresponding maximum horizontal principal stress value according to the minimum horizontal principal stress value of each section of the horizontal well; A formation pressure value calculation module, which is used to determine the formation pressure value according to the bottom-hole fracture pressure value, minimum horizontal principal stress value, maximum horizontal principal stress value of each section of the horizontal well and the core tensile strength; A formation pressure coefficient determination module, which is used to determine the formation pressure coefficient according to the ratio of the formation pressure value to the formation depth.

9. A computer-readable storage medium, characterized in that, It stores a computer program, and when the program is executed by a processor, it implements a method for determining the formation pressure coefficient after fracturing of a shale gas well as described in any one of claims 1 to 7.

10. An electronic device, which includes: A processor; A memory for storing instructions executable by the processor; Wherein, the processor is configured to execute the instructions to implement a method for determining the formation pressure coefficient after fracturing of a shale gas well as described in any one of claims 1 to 7.

Images