A wellbore pressure drop loss calculation method, device, equipment, medium and program

Abstract

The technical scheme of the embodiment of the present application comprises: dividing the strata corresponding to the upper pipe column of the production layer of the production well into n sections from high to low, determining the bottom pressure value of the nth section according to the flow temperature gradient curve, wherein n is a positive integer, the height value of each section is the same preset height value, and the flow temperature gradient curve comprises the bottom temperature value of each section; determining the wellbore pressure drop loss of the upper pipe column according to the bottom pressure value of the nth section; dividing m production sections according to the depth measurement of the production well, calculating the bottom hole pressure value according to the flow temperature gradient curve and the flow value of each production section, and the flow temperature gradient curve comprises the top temperature value of each production section; and determining the wellbore pressure drop loss according to the wellbore pressure drop loss of the upper pipe column and the bottom hole pressure value. The present application finally establishes a large-inclination wellbore pressure drop loss calculation model considering the angle change of the upper pipe column and the production section, the production section wellbore gas distribution and the production section water production distribution, and can accurately calculate the wellbore pressure drop loss of the large-inclination well of the thick-layer strong heterogeneity gas reservoir.

Description

Technical Field

[0001] This invention relates to the field of oil and gas exploration technology, and in particular to a method, apparatus, equipment, medium and program for calculating wellbore pressure drop loss. Background Technology

[0002] For thick, highly heterogeneous gas reservoirs at sea, high-angle wells or horizontal wells are usually used for production. When the well inclination angle of the section entering the producing layer is greater than 60°, the downhole pressure gauge cannot be lowered to the producing layer, and the bottom hole flowing pressure cannot be obtained directly from the measured data. Only relatively complete wellhead oil pressure data are available.

[0003] Conventional wellbore pressure drop calculation methods treat the mass flow rate in the wellbore as a constant value. However, in thick, highly heterogeneous gas reservoirs with large deviated wells, the mass flow rate in the wellbore gradually increases from the bottom to the top of the reservoir. Existing methods for calculating the pressure drop loss of the entire wellbore using variable mass flow are not suitable for calculating the pressure drop loss of thick gas reservoirs with large deviated wells, and they lack verification with measured data.

[0004] Therefore, there is an urgent need to establish a verifiable method for accurately calculating the wellbore pressure drop loss in thick, highly heterogeneous gas reservoirs with large deviated wells. Summary of the Invention

[0005] This invention provides a method, apparatus, equipment, medium, and program for calculating wellbore pressure drop loss, which can accurately calculate the wellbore pressure drop loss of highly deviated wells in thick, highly heterogeneous gas reservoirs.

[0006] According to one aspect of the present invention, a method for calculating wellbore pressure drop loss is provided, comprising:

[0007] The formation corresponding to the upper tubing string of the production well is divided into n segments from high to low. The bottom pressure value of the nth segment is determined according to the flow-temperature gradient curve, where n is a positive integer. The height value of each segment is the same preset height value. The flow-temperature gradient curve includes the bottom temperature value of each segment.

[0008] The pressure drop loss of the upper tubing wellbore is determined based on the bottom pressure value of the nth segment.

[0009] The production well is divided into m production sections based on the well depth. The bottom pressure is calculated based on the flow-temperature gradient curve and the flow rate of each production section. The flow-temperature gradient curve includes the top temperature of each production section.

[0010] The wellbore pressure drop loss is determined based on the pressure drop loss of the upper tubing and the bottom hole pressure value.

[0011] Optionally, the average physical property parameters include: deviation factor, viscosity, friction, and Reynolds number; correspondingly, when the production well has undergone pressure testing and the pressure gauge has been lowered to the upper part of the production formation, determining the bottom pressure of the nth segment based on the flow-temperature gradient curve includes:

[0012] The deviation factor, viscosity, friction and Reynolds number of the first segment are calculated based on the bottom temperature value of the first segment and the pressure value of the upper part of the production layer measured by the pressure gauge.

[0013] The bottom pressure of the first section is determined based on the deviation factor, viscosity, friction, and Reynolds number of the tubing in the first section.

[0014] The bottom pressure of the second segment is calculated based on the bottom pressure of the first segment, the bottom temperature of the second segment, the deviation factor, viscosity, friction, and Reynolds number of the tubing of the second segment, until the bottom pressure of the nth segment is calculated.

[0015] Optionally, the deviation factor, viscosity, friction, and column Reynolds number can be calculated using the following formula:

[0016] ;

[0017] ;

[0018] ;

[0019] ;

[0020] Where D is the inner diameter of the upper tubular column; e is the surface roughness of the upper tubular column. Let be the Reynolds number of the i-th segment of the tubing, which is dimensionless; Let be the friction coefficient of the i-th segment; The wellhead flow rate; This represents the density of the gas at the wellhead. Let be the gas deviation factor for the i-th segment; For the lower pressure corresponding to the i-th segment, when i=1, The pressure value measured by the pressure gauge at the upper part of the production layer; For temperature; The relative density of natural gas; R is the molecular weight of the gas; R is the universal gas constant. The viscosity is [value].

[0021] Optionally, the bottom pressure value can be calculated using the following formula:

[0022] ;

[0023] ;

[0024] in, Let be the bottom pressure value of the i-th segment; Let i be the pressure difference value of the i-th segment. This represents the bottom pressure value of the segment preceding the i-th segment. When i=1, θ is the pressure value measured by the pressure gauge at the upper part of the production layer; θ is the slope angle of the i-th segment; a is the unit conversion coefficient; g is the gravitational acceleration. Let be the friction coefficient of the i-th segment. The wellhead flow rate; Where D is the density of the gas at the wellhead, and D is the inner diameter of the upper tubing string. Let be the gas density of the i-th segment; Let be the height difference between the i-th segment and the producing layer.

[0025] In this embodiment of the invention, the flow rate value of each production section is calculated according to the following formula:

[0026] ;

[0027] in, Let i be the flow rate value of the i-th production segment. The average permeability of each segment. Let the thickness of the i-th production segment be . The wellhead flow rate; H represents the density of the gas at the wellhead; H represents the total thickness of the producing formation. Let be the gas density of the i-th production stage.

[0028] Optionally, the calculation of the bottom hole pressure value based on the flow rate value of each production section includes:

[0029] The top pressure of the first production section is calculated based on the top pressure of the reservoir and the top temperature of the first production section, in descending order of height.

[0030] The top pressure value of the second production section is calculated based on the top pressure value of the first production section and the top temperature value of the second production section, until the top pressure value of the m-th production section is calculated, and the bottom pressure value is obtained.

[0031] The top pressure value is calculated using the following formula:

[0032] ;

[0033] ;

[0034] in, Let be the top pressure value of the i-th production stage. This represents the top pressure value of the production section preceding the i-th production section. When i=1, The set pressure value; denoted as the top pressure difference of the i-th production section; a is the unit conversion coefficient; g is the gravitational acceleration. Let be the gas density of the i-th production stage; θ is the distance difference between the i-th production section and the bottom of the well; θ is the inclination angle of the i-th section; D is the inner diameter of the tubing. Let be the friction coefficient of the i-th segment; Let be the average penetration rate of the i-th production stage.

[0035] Optionally, if the production well has not undergone pressure testing, the flow-temperature gradient curve of other production wells in the gas reservoir where the production well is located can be used as the flow-temperature gradient curve of the production well.

[0036] Optionally, the method further includes:

[0037] The average original formation pressure of the m-th segment of the producing layer is obtained from the static pressure gradient curve of the gas reservoir.

[0038] Based on the top pressure and bottom temperature values ​​of each production section, the average bottom pressure and average temperature of the m-th section are obtained, and the equilibrium viscosity and average deviation factor are obtained based on the average bottom pressure and the average temperature.

[0039] The flow rate value of the m-th segment is calculated based on the average bottom hole pressure, the average temperature, the equilibrium viscosity, and the average deviation factor. The total mass flow rate is obtained by calculating from the m-th segment to the upper section of the wellbore up to the first segment at the top of the producing layer.

[0040] The wellhead flow rate is obtained based on the total mass flow rate, and the flow temperature gradient curve is evaluated based on the comparison between the wellhead flow rate and the measured wellhead flow rate.

[0041] According to another aspect of the present invention, a wellbore pressure drop loss calculation device is provided, comprising:

[0042] The pressure value calculation unit is used to divide the formation corresponding to the upper part of the production well tubing into n segments from high to low, and determine the bottom pressure value of the nth segment according to the flow temperature gradient curve, where n is a positive integer, and the height value of each segment is the same preset height value. The flow temperature gradient curve includes the bottom temperature value of each segment.

[0043] The wellbore pressure drop loss calculation unit is used to determine the wellbore pressure drop loss of the upper tubing string based on the bottom pressure value of the nth segment.

[0044] The bottom hole pressure calculation unit is used to divide the production well into m production sections based on the production well depth, and to calculate the bottom hole pressure value based on the flow-temperature gradient curve and the flow rate value of each production section. The flow-temperature gradient curve includes the top temperature value of each production section.

[0045] The processing unit is used to determine the wellbore pressure drop loss based on the pressure drop loss of the upper tubing string and the bottom hole pressure value.

[0046] According to another aspect of the present invention, an electronic device is provided, the electronic device comprising:

[0047] At least one processor; and a memory communicatively connected to the at least one processor; wherein the memory stores a computer program executable by the at least one processor, the computer program being executed by the at least one processor to enable the at least one processor to perform the wellbore pressure drop loss calculation method according to any embodiment of the present invention.

[0048] According to another aspect of the present invention, a computer-readable storage medium is provided, the computer-readable storage medium storing computer instructions for causing a processor to execute and implement the wellbore pressure drop loss calculation method according to any embodiment of the present invention.

[0049] According to another aspect of the present invention, a computer program product is provided, the computer program product comprising a computer program that, when executed by a processor, implements the wellbore pressure drop loss calculation method according to any embodiment of the present invention.

[0050] The technical solution of this invention involves dividing the formation corresponding to the upper tubing string of a production well into n segments from high to low. The bottom pressure value of the nth segment is determined based on a flow-temperature gradient curve, where n is a positive integer, and each segment has the same preset height. The flow-temperature gradient curve includes the bottom temperature value of each segment. The pressure drop loss of the upper tubing string is determined based on the bottom pressure value of the nth segment. The well is then divided into m production segments based on the well depth sounding. The bottom pressure value is calculated based on the flow-temperature gradient curve and the flow rate value of each production segment. The flow-temperature gradient curve includes the top temperature value of each production segment. The pressure drop loss of the wellbore is determined based on the pressure drop loss of the upper tubing string and the bottom pressure value. This invention divides the reservoir segment into n sub-segments, drawing on research results on variable mass flow in horizontal wells, and considering the additional pressure drop caused by variable mass flow in the open hole segment and the mixed frictional pressure drop at the interface between the open hole and the formation. Finally, a calculation model for the pressure drop loss of a large-angle well was established, taking into account the changes in the angle of the upper tubing and the production section, the gas production distribution in the production section, and the water production distribution in the production section. This model can accurately calculate the pressure drop loss of a large-angle well in a thick, highly heterogeneous gas reservoir.

[0051] It should be understood that the description in this section is not intended to identify key or essential features of the embodiments of the present invention, nor is it intended to limit the scope of the invention. Other features of the invention will become readily apparent from the following description. Attached Figure Description

[0052] To more clearly illustrate the technical solutions in the embodiments of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0053] Figure 1 This is a flowchart of a wellbore pressure drop loss calculation method provided in Embodiment 1 of the present invention;

[0054] Figure 2 This is a schematic diagram of a wellbore pressure drop loss calculation device applicable to Embodiment 2 of the present invention;

[0055] Figure 3 This is a schematic diagram of the structure of an electronic device that implements the wellbore pressure drop loss calculation method of the present invention. Detailed Implementation

[0056] To enable those skilled in the art to better understand the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of the present invention.

[0057] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this invention are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of the invention described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0058] Example 1

[0059] Figure 1This is a flowchart of a wellbore pressure drop loss calculation method provided in Embodiment 1 of the present invention. This embodiment is applicable to calculating the wellbore pressure drop loss of highly deviated wells in thick, highly heterogeneous gas reservoirs. This method can be executed by a wellbore pressure drop loss calculation device, which can be implemented in hardware and / or software and can be configured in an electronic device. Figure 1 As shown, the method includes:

[0060] S110. Divide the formation corresponding to the upper tubing string of the production well into n segments from high to low. Determine the bottom pressure value of the nth segment according to the flow-temperature gradient curve, where n is a positive integer and the height value of each segment is the same preset height value. The flow-temperature gradient curve includes the bottom temperature value of each segment.

[0061] In this embodiment of the invention, the average physical property parameters include: deviation factor, viscosity, frictional resistance, and Reynolds number; correspondingly, when the production well has undergone pressure testing and the pressure gauge has been lowered to the upper part of the production formation, determining the bottom pressure of the nth segment based on the flow-temperature gradient curve includes:

[0062] The deviation factor, viscosity, friction and Reynolds number of the first segment are calculated based on the bottom temperature value of the first segment and the pressure value of the upper part of the production layer measured by the pressure gauge.

[0063] The bottom pressure of the first section is determined based on the deviation factor, viscosity, friction, and Reynolds number of the tubing in the first section.

[0064] The bottom pressure of the second segment is calculated based on the bottom pressure of the first segment, the bottom temperature of the second segment, the deviation factor, viscosity, friction, and Reynolds number of the tubing of the second segment, until the bottom pressure of the nth segment is calculated.

[0065] In this embodiment of the invention, the deviation factor, viscosity, friction, and column Reynolds number are calculated using the following formula:

[0066] ;

[0067] ;

[0068] ;

[0069] ;

[0070] Where D is the inner diameter of the upper tubular column; e is the surface roughness of the upper tubular column. Let be the Reynolds number of the i-th segment of the tubing, which is dimensionless; Let be the friction coefficient of the i-th segment; The wellhead flow rate; This represents the density of the gas at the wellhead. Let be the gas deviation factor for the i-th segment; For the lower pressure corresponding to the i-th segment, when i=1, The pressure value measured by the pressure gauge at the upper part of the production layer; For temperature; The relative density of natural gas; R is the molecular weight of the gas; R is the universal gas constant. The viscosity is [value].

[0071] For production gas wells that undergo pressure testing but have the pressure gauge lowered to the upper part of the production formation, the formation corresponding to the upper tubing string is divided into n equal parts, each with a thickness of h. The bottom temperature of the first section is calculated using the depth h and the measured flow-temperature gradient curve. ,according to , Calculate the average physical property parameters of the first segment using the above formula, and calculate the deviation factor using the DPR method. Using the Lee-Gonzalez semi-empirical viscosity method Calculate friction and Reynolds number The Reynolds number is a dimensionless number used to describe the state of fluid flow. It is defined as the ratio of inertial force to viscous force. When the Reynolds number is small, viscous force dominates, and the fluid flow is laminar; when the Reynolds number is large, inertial force dominates, and the fluid flow is turbulent. A flow-temperature gradient curve is a curve showing how fluid temperature changes with depth or distance. Flow-temperature gradient curves are used in fields such as geology, geothermal engineering, and reservoir engineering. For example, when studying underground thermal conditions, by measuring the fluid temperature at different depths and plotting the flow-temperature gradient curve, we can understand the variation of underground temperature with depth, and thus infer the distribution of underground heat flow, geological structures, etc. In oil reservoirs, the flow-temperature gradient curve helps analyze the temperature distribution of the reservoir, which is of great significance for reservoir development and management.

[0072] S120. Determine the pressure drop loss of the upper tubing wellbore based on the bottom pressure value of the nth segment.

[0073] In this embodiment of the invention, the bottom pressure value is calculated using the following formula:

[0074] ;

[0075] ;

[0076] in, Let be the bottom pressure value of the i-th segment; Let i be the pressure difference value of the i-th segment. θ is the bottom pressure value of the segment above the i-th segment; θ is the oblique angle of the i-th segment; a is the unit conversion coefficient; g is the gravitational acceleration; Let be the friction coefficient of the i-th segment. The wellhead flow rate; Where D is the density of the gas at the wellhead, and D is the inner diameter of the upper tubing string. Let be the gas density of the i-th segment; Let be the height difference between the i-th segment and the producing layer.

[0077] Substituting the above parameters into the above formula, the bottom pressure of the first segment is calculated. ,according to , and the bottom temperature of the second section Calculate the bottom pressure of the second segment. And so on, calculate the bottom pressure of the (i-1)th segment, the ith segment, the (i+1)th segment, and even the nth segment. , calculate Actual measurement with pressure gauge A comparison is performed, where when i=1, The pressure value measured by the pressure gauge at the upper part of the production layer is output. If the error is less than 0.05 MPa, then... The pressure drop loss in the upper tubing of the wellbore is If the error is not less than 0.05 MPa, then modify the h value and recalculate. Continue until the error requirement is met.

[0078] In this embodiment of the invention, the flow rate value of each production section is calculated according to the following formula:

[0079] ;

[0080] in, Let i be the flow rate value of the i-th production segment. The average permeability of each segment. Let the thickness of the i-th production segment be . The wellhead flow rate; H represents the density of the gas at the wellhead; H represents the total thickness of the producing formation. Let be the gas density of the i-th production stage.

[0081] Assuming the inflow rate in each production section varies linearly with the permeability and thickness of that section, the flow rate of each sub-section is calculated. Similar to the previous example, the pressure at the top of the reservoir is defined as... Calculated based on the temperature gradient The pressure at the top of the second section of the producing layer is calculated using the above formula, and so on, until the bottom of the well is calculated to obtain the final bottom-hole pressure.

[0082] S130. Divide the production well into m production sections based on the production well depth, and calculate the bottom hole pressure value based on the flow-temperature gradient curve and the flow rate value of each production section. The flow-temperature gradient curve includes the top temperature value of each production section.

[0083] S140. Divide the production well into m production sections based on the well depth measurement, and calculate the bottom hole pressure value based on the flow-temperature gradient curve and the flow rate value of each production section. The flow-temperature gradient curve includes the top temperature value of each production section.

[0084] In this embodiment of the invention, the calculation of the bottom hole pressure value based on the flow rate value of each production section includes:

[0085] The top pressure of the first production section is calculated based on the top pressure of the reservoir and the top temperature of the first production section, in descending order of height.

[0086] The top pressure value of the second production section is calculated based on the top pressure value of the first production section and the top temperature value of the second production section, until the top pressure value of the m-th production section is calculated, and the bottom pressure value is obtained.

[0087] The top pressure value is calculated using the following formula:

[0088] ;

[0089] ;

[0090] in, Let be the top pressure value of the i-th production stage. This represents the top pressure value of the production section preceding the i-th production section. When i=1, The set pressure value; denoted as the top pressure difference of the i-th production section; a is the unit conversion coefficient; g is the gravitational acceleration. Let be the gas density of the i-th production stage; θ is the distance difference between the i-th production section and the bottom of the well; θ is the inclination angle of the i-th section; D is the inner diameter of the tubing. Let be the friction coefficient of the i-th segment; Let be the average penetration rate of the i-th production stage.

[0091] Based on the well logging, the reservoir is divided into n production segments. Assuming the inflow rate in each segment varies linearly with its permeability and thickness, the flow rate of each segment is calculated. The pressure at the top of the reservoir is defined as... ,according to and the temperature gradient obtained from the flow The pressure at the top of the second section of the producing layer is calculated using the above formula. This process continues until the calculation reaches the bottom of the well, yielding the final bottom-hole pressure. Wellbore pressure drop loss .

[0092] In this embodiment of the invention, when the production well has not undergone pressure testing, the flow-temperature gradient curve of other production wells in the gas reservoir where the production well is located is used as the flow-temperature gradient curve of the production well.

[0093] For a production gas well that has not undergone pressure testing, the formation corresponding to the upper tubing string is divided into n equal parts, each with a thickness of h. Assume a wellhead flow rate... The bottom temperature of the first section was calculated by using depth h and combining the measured flow-temperature gradient curves of other wells in the gas reservoir. ,according to , Using the average physical property parameters of the first paragraph as described above, the deviation factor is calculated using the DPR method, the viscosity is calculated using the Lee-Gonzalez semi-empirical method, and the friction and Reynolds number are calculated.

[0094] Substitute the calculated parameters into the formula to calculate the bottom pressure of the first segment. ,according to , and the bottom temperature of the second section Calculate the bottom pressure of the second segment. And so on, calculate the bottom pressure of the (i-1)th segment, the ith segment, the (i+1)th segment, and even the nth segment. .

[0095] Assuming the inflow rate in each production segment varies linearly with the permeability and thickness of that segment, calculate the flow rate in each sub-segment, where... The average permeability of each segment. Here, H represents the thickness of each segment, and H represents the total thickness of the producing layer. The gas density of this segment is given. The bottom pressure of the nth segment is the same as the top pressure of the producing layer. ,according to , and the calculation of the flow-temperature profile Calculate the top pressure of the second segment of the producing layer. This process continues until the calculation reaches the bottom of the well, yielding the final bottom-hole pressure. .

[0096] In embodiments of the present invention, the method may further include:

[0097] The average original formation pressure of the m-th segment of the producing layer is obtained from the static pressure gradient curve of the gas reservoir.

[0098] Based on the top pressure and bottom temperature values ​​of each production section, the average bottom pressure and average temperature of the m-th section are obtained, and the equilibrium viscosity and average deviation factor are obtained based on the average bottom pressure and the average temperature.

[0099] The flow rate value of the m-th segment is calculated based on the average bottom hole pressure, the average temperature, the equilibrium viscosity, and the average deviation factor. The total mass flow rate is obtained by calculating from the m-th segment to the upper section of the wellbore up to the first segment at the top of the producing layer.

[0100] The wellhead flow rate is obtained based on the total mass flow rate, and the flow temperature gradient curve is evaluated based on the comparison between the wellhead flow rate and the measured wellhead flow rate.

[0101] The average original formation pressure of the lowest segment of the producing layer was obtained from the static pressure gradient curve of the gas reservoir. Using calculation , , and The average bottom hole pressure of this section was obtained. The average temperature of this section Then, the average viscosity of this segment is calculated. Average deviation factor of this segment The flow rate can be calculated using the general form of the binomial formula for capacity. and The total mass flow rate can be obtained by calculating from the lower section of the wellbore to the upper section, up to the top of the producing formation. The calculation formula is as follows:

[0102] ;

[0103] ;

[0104] In the formula: The well control radius; Where is the radius of the wellbore.

[0105] Based on the calculated bottom pressure of the nth segment Bottom pressure of segment n-1 Temperature at the bottom of segment n Temperature at the bottom of segment n-1 The average pressure of the nth segment is calculated as follows: The average temperature of the nth segment is The calculated flow rate of the nth segment is Calculate upwards sequentially to obtain the wellhead flow rate. , with measured wellhead flow If the calculation error is not met, a new flow-temperature gradient curve is given until the calculation result meets the error.

[0106] This invention patent has the following beneficial effects: By considering data such as well depth, wellbore structure, well inclination angle, wellhead pressure, and wellhead flow rate, it addresses the pressure drop differences caused by gas inflow into different sections of thick reservoirs, thus solving the problem of inaccurate wellbore pressure drop loss calculation in highly deviated wells due to the inability of pressure gauges to reach the producing layer. Furthermore, for producing gas wells without downhole pressure gauges, it provides a method for calculating wellbore pressure drop loss using wellhead flow rate correction, offering a new approach to offshore gas well productivity evaluation.

[0107] Example 2

[0108] Figure 2 This is a schematic diagram of a wellbore pressure drop loss calculation device provided in Embodiment 2 of the present invention. Figure 2 As shown, the device includes:

[0109] The pressure value calculation unit 210 is used to divide the formation corresponding to the upper part of the production well tubing into n segments from high to low, and determine the bottom pressure value of the nth segment according to the flow temperature gradient curve, where n is a positive integer, the height value of each segment is the same preset height value, and the flow temperature gradient curve includes the bottom temperature value of each segment.

[0110] Wellbore pressure drop loss calculation unit 220 is used to determine the wellbore pressure drop loss of the upper tubing string based on the bottom pressure value of the nth segment;

[0111] Bottom hole pressure calculation unit 230 is used to divide the production well into m production sections according to the production well depth, and to calculate the bottom hole pressure value according to the flow temperature gradient curve and the flow rate value of each production section. The flow temperature gradient curve includes the top temperature value of each production section.

[0112] Processing unit 230 is used to determine the wellbore pressure drop loss based on the pressure drop loss of the upper tubing string and the bottom hole pressure value.

[0113] The wellbore pressure drop loss calculation device provided in this embodiment of the invention can execute the wellbore pressure drop loss calculation method provided in any embodiment of the invention, and has the corresponding functional modules and beneficial effects of the method.

[0114] Example 3

[0115] Figure 3A schematic diagram of an electronic device 10, which can be used to implement embodiments of the present invention, is shown. The electronic device is intended to represent various forms of digital computers, such as laptop computers, desktop computers, workstations, personal digital assistants, servers, blade servers, mainframe computers, and other suitable computers. The electronic device can also represent various forms of mobile devices, such as personal digital processors, cellular phones, 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 merely illustrative and are not intended to limit the implementation of the invention described and / or claimed herein.

[0116] like Figure 3 As shown, the electronic device 10 includes at least one processor 11 and a memory, such as a read-only memory (ROM) 12 or a random access memory (RAM) 13, communicatively connected to the at least one processor 11. The memory stores computer programs executable by the at least one processor. The processor 11 can perform various appropriate actions and processes based on the computer program stored in the ROM 12 or loaded from storage unit 18 into the RAM 13. The RAM 13 can also store various programs and data required for the operation of the electronic device 10. The processor 11, ROM 12, and RAM 13 are interconnected via a bus 14. An input / output (I / O) interface 15 is also connected to the bus 14.

[0117] Multiple components in electronic device 10 are connected to I / O interface 15, including: input unit 16, such as keyboard, mouse, etc.; output unit 17, such as various types of displays, speakers, etc.; storage unit 18, such as disk, optical disk, etc.; and communication unit 19, such as network card, modem, wireless transceiver, etc. Communication unit 19 allows electronic device 10 to exchange information / data with other devices through computer networks such as the Internet and / or various telecommunications networks.

[0118] Processor 11 can be a variety of general-purpose and / or special-purpose processing components with 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 special-purpose artificial intelligence (AI) computing chips, various processors running machine learning model algorithms, digital signal processors (DSPs), and any suitable processor, controller, microcontroller, etc. Processor 11 performs the various methods and processes described above, such as the wellbore pressure drop loss calculation method.

[0119] In some embodiments, the wellbore pressure drop loss calculation method may be implemented as a computer program tangibly contained in 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 on electronic device 10 via ROM 12 and / or communication unit 19. When the computer program is loaded into RAM 13 and executed by processor 11, one or more steps of the wellbore pressure drop loss calculation method described above may be performed. Alternatively, in other embodiments, processor 11 may be configured to perform the wellbore pressure drop loss calculation method by any other suitable means (e.g., by means of firmware).

[0120] Various embodiments of the systems and techniques described above herein can be implemented in digital electronic circuit systems, integrated circuit systems, field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), application-specific standard products (ASSPs), systems-on-a-chip (SoCs), payload-programmable logic devices (CPLDs), computer hardware, firmware, software, and / or combinations thereof. These various embodiments may include implementations in one or more computer programs that can be executed and / or interpreted on a programmable system including at least one programmable processor, which may be a dedicated or general-purpose programmable processor, capable of receiving data and instructions from a storage system, at least one input device, and at least one output device, and transmitting data and instructions to the storage system, the at least one input device, and the at least one output device.

[0121] Computer programs used to implement the 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, a special-purpose computer, or other programmable data processing device, such that when executed by the processor, the computer programs cause the functions / operations specified in the flowcharts and / or block diagrams to be performed. The computer programs may be executed entirely on a machine, partially on a machine, or as a standalone software package, partially on a machine and partially on a remote machine, or entirely on a remote machine or server.

[0122] In the context of this invention, a computer-readable storage medium can be a tangible medium that may contain or store a computer program for use by or in conjunction with an instruction execution system, apparatus, or device. A computer-readable storage medium may include, but is not limited to, electronic, magnetic, optical, electromagnetic, infrared, or semiconductor systems, apparatus, or devices, or any suitable combination thereof. Alternatively, a computer-readable storage medium may be a machine-readable signal medium. More specific examples of machine-readable storage media include electrical connections based on one or more wires, portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fibers, portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof.

[0123] To provide interaction with a user, the systems and techniques described herein 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 the user; and a keyboard and pointing device (e.g., a mouse or trackball) through which the user provides input to the electronic device. Other types of devices can also be used to provide interaction with the user; for example, feedback provided to the user can be any form of sensory feedback (e.g., visual feedback, auditory feedback, or tactile feedback); and input from the user can be received in any form (including sound input, voice input, or tactile input).

[0124] The systems and technologies described herein can be implemented in computing systems that include backend components (e.g., as data servers), or middleware components (e.g., application servers), or frontend components (e.g., user computers with graphical user interfaces or web browsers through which users can interact with implementations of the systems and technologies described herein), or any combination of such backend, middleware, or frontend components. The components of the system can be interconnected via digital data communication of any form or medium (e.g., communication networks). Examples of communication networks include local area networks (LANs), wide area networks (WANs), blockchain networks, and the Internet.

[0125] A computing system can include clients and servers. Clients and servers are generally located far apart and typically interact through communication networks. The client-server relationship is created by computer programs running on the respective computers and having a client-server relationship with each other. The server can be a cloud server, also known as a cloud computing server or cloud host, which is a hosting product within the cloud computing service system to address the shortcomings of traditional physical hosts and VPS services, such as high management difficulty and weak business scalability.

[0126] It should be understood that the various forms of processes shown above can be used, with steps reordered, added, or deleted. For example, the steps described in this invention can be executed in parallel, sequentially, or in different orders, as long as the desired result of the technical solution of this invention can be achieved, and this is not limited herein.

[0127] The specific embodiments described above do not constitute a limitation on the scope of protection of this invention. Those skilled in the art should understand that various modifications, combinations, sub-combinations, and substitutions can be made according to design requirements and other factors. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of this invention should be included within the scope of protection of this invention.

Claims

1. A method for calculating wellbore pressure drop loss, characterized in that, include: The formation corresponding to the upper tubing string of the production well is divided into n segments from high to low. The bottom pressure value of the nth segment is determined according to the flow-temperature gradient curve, where n is a positive integer. The height value of each segment is the same preset height value. The flow-temperature gradient curve includes the bottom temperature value of each segment. The pressure drop loss of the upper tubing wellbore is determined based on the bottom pressure value of the nth segment. The production well is divided into m production sections based on the well depth. The bottom pressure is calculated based on the flow-temperature gradient curve and the flow rate of each production section. The flow-temperature gradient curve includes the top temperature of each production section. The wellbore pressure drop loss is determined based on the pressure drop loss of the upper tubing string and the bottom hole pressure value. Average physical properties include: deviation factor, viscosity, friction, and Reynolds number; correspondingly, when the production well has undergone pressure testing and the pressure gauge has been lowered to the upper part of the production formation, determining the bottom pressure of the nth segment based on the flow-temperature gradient curve includes: The deviation factor, viscosity, friction and tubing Reynolds number of the first segment are calculated based on the bottom temperature value of the first segment and the pressure value of the upper part of the production layer measured by the pressure gauge. The bottom pressure of the first section is determined based on the deviation factor, viscosity, friction, and Reynolds number of the tubing in the first section. The bottom pressure of the second segment is calculated based on the bottom pressure of the first segment, the bottom temperature of the second segment, and the deviation factor, viscosity, friction, and Reynolds number of the tubing of the second segment, until the bottom pressure of the nth segment is calculated. Calculate the bottom hole pressure value based on the flow rate value of each production section, including: The top pressure of the first production section is calculated based on the top pressure of the reservoir and the top temperature of the first production section, in descending order of height. The top pressure value of the second production section is calculated based on the top pressure value of the first production section and the top temperature value of the second production section, until the top pressure value of the m-th production section is calculated, and the bottom pressure value is obtained. The top pressure value is calculated using the following formula: ； ； in, Let be the top pressure value of the i-th production stage. This represents the top pressure value of the production section preceding the i-th production section. When i=1, The set pressure value; denoted as the top pressure difference of the i-th production section; a is the unit conversion coefficient; g is the gravitational acceleration. Let be the gas density of the i-th production stage; θ is the distance difference between the i-th production section and the bottom of the well; θ is the inclination angle of the i-th section; D is the inner diameter of the upper tubing string; Let be the friction coefficient of the i-th segment; Let be the average penetration rate of the i-th production stage; The wellhead flow rate; H represents the density of the gas at the wellhead; H represents the total thickness of the producing formation; the pressure at the top of the reservoir is defined as... Calculated based on the flow temperature gradient The pressure at the top of the second section of the producing layer is calculated using the above formula, and so on, until the bottom of the well is calculated to obtain the final bottom-hole pressure.

2. The method according to claim 1, characterized in that, The deviation factor, viscosity, friction, and string Reynolds number are calculated using the following formula: ； ； ； ； Where D is the inner diameter of the upper tubular column; e is the surface roughness of the upper tubular column. Let be the Reynolds number of the i-th segment of the tubing, which is dimensionless; Let be the friction coefficient of the i-th segment; The wellhead flow rate; This represents the density of the gas at the wellhead. Let be the gas deviation factor for the i-th segment; For the lower pressure corresponding to the i-th segment, when i=1, The pressure value measured by the pressure gauge at the upper part of the production layer; For temperature; The relative density of natural gas; R is the molecular weight of the gas; R is the universal gas constant. The viscosity is [value].

3. The method according to claim 2, characterized in that, The bottom pressure value is calculated using the following formula: ； ； in, Let be the bottom pressure value of the i-th segment; Let i be the pressure difference value of the i-th segment. This represents the bottom pressure value of the segment preceding the i-th segment. When i=1, θ is the pressure value measured by the pressure gauge at the upper part of the production layer; θ is the slope angle of the i-th segment; a is the unit conversion coefficient; g is the gravitational acceleration. Let be the friction coefficient of the i-th segment. The wellhead flow rate; Where D is the density of the gas at the wellhead, and D is the inner diameter of the upper tubing string. Let be the gas density of the i-th segment; Let be the height difference between the i-th segment and the producing layer.

4. The method according to claim 1, characterized in that, The flow rate of each production section is calculated using the following formula: ； in, Let i be the flow rate value of the i-th production segment. The average permeability of each segment. Let the thickness of the i-th production segment be . The wellhead flow rate; H represents the density of the gas at the wellhead; H represents the total thickness of the producing formation. Let be the gas density of the i-th production stage.

5. The method according to claim 1, characterized in that, In the absence of pressure testing on the production well, the flow-temperature gradient curve of other production wells in the gas reservoir where the production well is located is used as the flow-temperature gradient curve of the production well.

6. The method according to claim 5, characterized in that, Further includes: The average original formation pressure of the m-th segment of the producing layer is obtained from the static pressure gradient curve of the gas reservoir. Based on the top pressure and bottom temperature values ​​of each production section, the average bottom pressure and average temperature of the m-th section are obtained, and the equilibrium viscosity and average deviation factor are obtained based on the average bottom pressure and the average temperature. The flow rate value of the m-th segment is calculated based on the average bottom hole pressure, the average temperature, the equilibrium viscosity, and the average deviation factor. The total mass flow rate is obtained by calculating from the m-th segment to the upper section of the wellbore up to the first segment at the top of the producing layer. The wellhead flow rate is obtained based on the total mass flow rate, and the flow temperature gradient curve is evaluated based on the comparison between the wellhead flow rate and the measured wellhead flow rate.

7. A wellbore pressure drop loss calculation device based on any one of the wellbore pressure drop loss methods described in claims 1-6, characterized in that, include: The pressure value calculation unit is used to divide the formation corresponding to the upper part of the production well tubing into n segments from high to low, and determine the bottom pressure value of the nth segment according to the flow temperature gradient curve, where n is a positive integer, and the height value of each segment is the same preset height value. The flow temperature gradient curve includes the bottom temperature value of each segment. The wellbore pressure drop loss calculation unit is used to determine the wellbore pressure drop loss of the upper tubing string based on the bottom pressure value of the nth segment. The bottom hole pressure calculation unit is used to divide the production well into m production sections based on the production well depth, and to calculate the bottom hole pressure value based on the flow-temperature gradient curve and the flow rate value of each production section. The flow-temperature gradient curve includes the top temperature value of each production section. The processing unit is used to determine the wellbore pressure drop loss based on the pressure drop loss of the upper tubing string and the bottom hole pressure value.

8. An electronic device, characterized in that, The electronic device includes: At least one processor; and a memory communicatively connected to the at least one processor; wherein the memory stores a computer program executable by the at least one processor, the computer program being executed by the at least one processor to enable the at least one processor to perform the wellbore pressure drop loss calculation method according to any one of claims 1-6.

9. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores computer instructions that cause a processor to execute the wellbore pressure drop loss calculation method according to any one of claims 1-6.

10. A computer program product, characterized in that, The computer program product includes a computer program that, when executed by a processor, implements the wellbore pressure drop loss calculation method according to any one of claims 1-6.

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