A well bottom flow pressure calculation method, device, storage medium and electronic equipment

Abstract

The present application relates to the technical field of shale condensate gas phase change, and particularly relates to a well bottom flow pressure calculation method and device, a storage medium and an electronic device. The method comprises: segmenting a wellbore, and sequentially calculating the outlet end pressure of each segment from the wellhead end of the wellbore to the well bottom end of the wellbore, wherein the segment being calculated is a current segment; when the current segment reaches the middle depth of the reservoir, the outlet end pressure of the current segment is taken as the well bottom flow pressure; wherein, when calculating the outlet end pressure of the current segment, the outlet end pressure of the current segment is obtained based on the sum of the inlet end pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion; the pressure drop of the current segment can be calculated under the condition of considering oil and gas conversion, the influence of oil and gas phase change on the calculation error of liquid holdup is reduced, and the calculation accuracy of the well bottom flow pressure is improved.

Description

Technical Field

[0001] This invention relates to the field of shale condensate gas phase change technology, and in particular to a method, apparatus, storage medium, and electronic device for calculating bottom hole flowing pressure. Background Technology

[0002] Most continental shale gas reservoirs are shallow to semi-deep lacustrine sediments with relatively low thermal evolution, primarily in the wet gas and condensate stages. Regarding condensate gas reservoirs, under initial conditions, the heavier hydrocarbon components in the natural gas are in a vapor state within the reservoir. During development, as the reservoir pressure decreases, the heavier components condense from the natural gas into lighter oil, known as condensate oil. This process is called reverse condensation, and gas reservoirs exhibiting this characteristic are called condensate gas reservoirs.

[0003] The development of condensate gas reservoirs can be viewed as an isothermal depressurization process. However, the temperature and pressure of the fluid change as it flows from the bottom of the well to the surface separator, and the phase state of the condensate gas also changes. This leads to significant deviations in the calculation of the bottom hole flowing pressure.

[0004] There is an urgent need in this field for a solution to address the technical problem of significant deviations in the calculation of bottom hole flowing pressure. Summary of the Invention

[0005] This invention provides a method, apparatus, storage medium, and electronic device for calculating bottom hole flowing pressure, which solves the technical problem of large deviations in the calculation of bottom hole flowing pressure.

[0006] In a first aspect, the present invention provides a method for calculating bottom hole flowing pressure, comprising:

[0007] The wellbore is divided into sections, and the outlet pressure of each section is calculated sequentially from the wellhead end to the bottom end of the wellbore. The section being calculated is the current section.

[0008] When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottom hole flowing pressure;

[0009] Specifically, when calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion.

[0010] In some embodiments, the outlet pressure of the current segment is obtained based on the sum of the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion, including:

[0011] Calculate the outlet pressure of the current segment based on the inlet pressure, gravity pressure drop, friction pressure drop, and acceleration pressure drop of the current segment.

[0012] In some embodiments, the method further includes: determining the dew point pressure of the current segment using a phase diagram of the condensate gas or a first preset model, including:

[0013] For shale condensate gas wells with PVT tube phase state experiments, the condensate gas dew point pressure at different temperatures is determined by using the phase diagram of condensate oil and gas, thereby determining the dew point pressure of the current segment.

[0014] For shale condensate gas wells without PVT tube phase experiments, the condensate gas dew point pressure at different temperatures is determined based on the first preset model, thereby determining the dew point pressure of the current segment.

[0015] In some embodiments, the current segment's oil and gas production rate, taking into account the effects of condensate phase change, is calculated based on the oil and gas production rate at the ground separator location, the inlet pressure of the current segment, and the dew point pressure of the current segment.

[0016] In some embodiments, calculating the current segment oil and gas production considering the effects of condensate phase change includes:

[0017] Calculate the number of moles of oil and natural gas under ground separator conditions;

[0018] Based on the inlet pressure and dew point pressure of the current segment, establish the molar number equations for oil and natural gas in the current segment;

[0019] Establish a set of mass conservation equations for the molar number of oil and natural gas;

[0020] Solve the system of mass conservation equations to obtain the natural gas production and oil production of the current segment.

[0021] In some embodiments, when the wellbore is segmented, the segment closest to the wellhead is designated as the first segment.

[0022] When the current segment is the first segment, the inlet pressure of the current segment is determined based on the source pressure;

[0023] When the current segment is not the first segment, the pressure at the outlet of the segment connected to the inlet of the current segment is used as the inlet pressure of the current segment.

[0024] In some embodiments, when the current segment is the first segment, determining the inlet pressure of the current segment based on the source pressure includes:

[0025] When the source pressure is the casing pressure, the inlet pressure of the current segment is determined based on the casing pressure;

[0026] When the source pressure is oil pressure, the inlet pressure of the current segment is determined based on the oil pressure.

[0027] In some embodiments, the gravitational pressure drop of the current segment is calculated based on the following expression:

[0028] Δp si =ρ m gΔZ i

[0029] Where, Δp si Let ρ be the gravitational pressure drop of the current segment. m Let g be the density of the oil-gas-water mixture, g be the acceleration due to gravity, and ΔZ be the acceleration due to gravity. i denoted as the elevation difference of the current segment, where i is the segment number.

[0030] In some embodiments, the density of the oil-gas-water mixture is calculated based on the following expression:

[0031] ρ m =ρ l ×E L +ρ g ×(1-E L )

[0032]

[0033] Where, ρ l E is the density of the liquid phase. L ρ represents the liquid holdup of the current segment. g ρ is the relative density of the current segmented condensate gas. o n is the density of oil. o n represents the current molar yield of the segmented oil. w ρ represents the current molar yield of water in the segment. w This is the density of water.

[0034] In some embodiments, the frictional voltage drop of the current segment is calculated based on the following expression:

[0035]

[0036] V m =V sl +V sg

[0037] V sl =[q w ×B w +q o，i ×B o ] / A

[0038] V sg =q g，i ×B g / A

[0039] Where, Δp fi f is the frictional voltage drop of the current segment. n ρ is the Fanning coefficient for the current segment.m V is the density of the oil-gas-water mixture. m V is the apparent velocity of the mixture, L is the length of the current segment, D is the equivalent hydraulic diameter of the wellbore flow section, and V is the apparent velocity of the mixture. sl V is the apparent flow rate of the liquid phase. sg Let q be the apparent velocity in the gas phase. w For water production, B w q is the volume coefficient of the aqueous phase. o，i For the current segment's oil production, B o Let q be the oil volume coefficient, A be the wellbore flow cross-sectional area, and q be the flow coefficient. g，i B represents the total gas production of the current segment. g This is the condensate gas volume coefficient.

[0040] In some embodiments, the total gas production of the current segment is calculated based on the following expression:

[0041]

[0042] Where, q gf，i R represents the natural gas production of the current segment. v (p) represents the condensate oil content per unit volume of natural gas at pressure p, M o ρ is the molar molecular weight of condensate oil. osc This represents the density of condensate oil under surface conditions.

[0043] In some embodiments, the Fanning coefficient is calculated based on the Reynolds number to determine the flow regime:

[0044] If the Reynolds number of the current segment is less than or equal to the first preset value, then the flow in the current segment is laminar, and the Fanning coefficient is:

[0045]

[0046] Among them, f n Here, Fanning coefficient is denoted as Re, and Re is the Reynolds number.

[0047] If the Reynolds number of the current segment is greater than the first preset value and less than or equal to the second preset value, then the flow in the current segment is a transient flow, and the Fanning coefficient is:

[0048]

[0049] If the Reynolds number of the current segment is greater than the second preset value, then the flow in the current segment is turbulent, and the Fanning coefficient satisfies:

[0050]

[0051] Where D is the equivalent hydraulic diameter of the wellbore flow section, and ε is the wellbore roughness.

[0052] In some embodiments, the acceleration voltage drop of the current segment is calculated based on the following expression:

[0053]

[0054] Where, Δp g,i To accelerate the pressure drop, ρ m V is the density of the oil-gas-water mixture. m The apparent flow rate of the mixture.

[0055] In a second aspect, the present invention provides a bottom-hole flowing pressure calculation device, comprising:

[0056] The outlet pressure calculation module is used to segment the wellbore and calculate the outlet pressure of each current segment sequentially from the wellhead to the bottom of the wellbore. Specifically, when calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion.

[0057] The bottom hole flowing pressure determination module is used to determine the bottom hole flowing pressure when the current segment reaches the middle depth of the reservoir.

[0058] Thirdly, the present invention provides a computer-readable storage medium having a computer program stored thereon, wherein the computer program, when executed by a processor, implements the method of any one of the first aspects.

[0059] Fourthly, the present invention provides an electronic device including a processor and a memory, wherein a computer program is stored in the memory, and the processor executes the computer program to implement the method of any one of the first aspects.

[0060] The technical solution of this invention involves segmenting the wellbore and sequentially calculating the outlet pressure of each segment from the wellhead to the bottom of the wellbore, wherein the segment being calculated is the current segment. When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottomhole flowing pressure. Specifically, when calculating the outlet pressure of the current segment, the outlet pressure is obtained based on the sum of the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion. This allows for the calculation of the pressure drop of the current segment while considering oil and gas conversion, reducing the impact of oil and gas phase change on the calculation error of liquid holdup and improving the calculation accuracy of bottomhole flowing pressure. Attached Figure Description

[0061] The invention will now be described in more detail with reference to embodiments and the accompanying drawings:

[0062] Figure 1 This is a schematic diagram of a bottom hole flowing pressure calculation method provided in an embodiment of the present invention;

[0063] Figure 2 This is a schematic diagram of a bottom hole flowing pressure calculation device provided in an embodiment of the present invention;

[0064] Figure 3 The condensate oil content under different pressures provided in the embodiments of the present invention;

[0065] Figure 4 This is a schematic diagram of the curve showing the change in condensate production along a vertical pipe section with depth, provided in an embodiment of the present invention.

[0066] Figure 5 A schematic diagram of the total gas production (dry gas + condensate oil) along a vertical pipe section as a function of depth, provided for an embodiment of the present invention.

[0067] Figure 6 This is a schematic diagram of the pressure versus depth curve provided in an embodiment of the present invention.

[0068] In the accompanying drawings, the same parts are referred to by the same reference numerals, and the drawings are not drawn to scale. Detailed Implementation

[0069] To enable those skilled in the art to better understand the present invention and to fully understand and implement the process of how the present invention uses technical means to solve technical problems and achieve corresponding technical effects, 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, not all embodiments. The embodiments of the present invention and the various features therein can be combined with each other without conflict, and the resulting technical solutions are all within the protection scope of the present invention. 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 protection scope of the present invention.

[0070] 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.

[0071] It should be noted that the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions, and although a logical order is shown in the flowchart, in some cases the steps shown or described may be executed in a different order than that shown here.

[0072] my country has a wide distribution of terrestrial basins, with terrestrial mudstone and shale developed in multiple Mesozoic and Cenozoic strata, making it one of the important successor areas for shale gas exploration and development. Currently, breakthroughs have been achieved in domestic terrestrial shale gas exploration, with multiple wells in the Triassic strata of the Ordos Basin and the Jurassic strata of the Sichuan Basin yielding industrial gas flows, demonstrating the promising prospects for Jurassic terrestrial shale gas exploration and development.

[0073] Most continental shale gas reservoirs are shallow to semi-deep lacustrine sediments with relatively low thermal evolution, primarily in the wet gas and condensate stages. Regarding condensate gas reservoirs, under initial conditions, the heavier hydrocarbon components in the natural gas are in a vapor state within the reservoir. During development, as the reservoir pressure decreases, the heavier components condense from the natural gas into lighter oil (called condensate oil). This process is called reverse condensation, and gas reservoirs exhibiting this characteristic are called condensate gas reservoirs.

[0074] The development of condensate gas reservoirs can be viewed as an isothermal depressurization process. The temperature and pressure of the fluid change as it flows from the bottom of the well to the surface separator, causing changes in the phase state of the condensate gas. However, existing methods for calculating the pressure drop in three-phase pipeline flow of condensate gas wells do not consider the impact of wellbore phase changes on the pressure drop calculation. Therefore, these methods are not applicable to the wellbore pressure drop calculation of shale condensate gas reservoirs.

[0075] This invention belongs to the field of shale gas exploration and development, and mainly relates to a method and system for calculating the bottom-hole flowing pressure of shale condensate gas reservoirs, in order to solve the problems existing in the above-mentioned prior art.

[0076] Example 1

[0077] Figure 1 This is a schematic diagram illustrating a bottom-hole flowing pressure calculation method provided in an embodiment of the present invention. Figure 1 As shown, a method for calculating bottom hole flowing pressure includes:

[0078] The wellbore is divided into sections, and the outlet pressure of each section is calculated sequentially from the wellhead end to the bottom end of the wellbore. The section being calculated is the current section.

[0079] When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottom hole flowing pressure;

[0080] Specifically, when calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion.

[0081] In this embodiment, shale condensate gas reservoirs are exploited through a wellbore. Surface equipment such as separators is installed on the surface. For ease of description, the gas production at any location in the shale condensate gas well is divided into two parts: dry gas production and condensate oil production (heavy hydrocarbons in the gas phase); the oil production at any location in the wellbore is the liquid phase oil production. The gas production at the surface separator location is the dry gas production at any location in the wellbore; the oil production at the surface separator location is composed of two parts: the oil production (liquid phase) at any location in the wellbore and the condensate oil production (heavy hydrocarbons in the gas phase).

[0082] The technical solution of this embodiment divides the wellbore into segments and calculates the outlet pressure of each segment sequentially from the wellhead to the bottom of the wellbore. The segment being calculated is the current segment. When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottomhole flowing pressure. In calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion. This allows the pressure drop of the current segment to be obtained while considering oil and gas conversion, reducing the impact of oil and gas phase change on the calculation error of liquid holdup and improving the calculation accuracy of bottomhole flowing pressure.

[0083] Example 2

[0084] Based on the above embodiments, this embodiment provides a bottomhole flowing pressure calculation method, wherein the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion, including:

[0085] Calculate the outlet pressure of the current segment based on the inlet pressure, gravity pressure drop, friction pressure drop, and acceleration pressure drop of the current segment.

[0086] In some embodiments, the method further includes: determining the dew point pressure of the current segment using a phase diagram of the condensate gas or a first preset model, including:

[0087] For shale condensate gas wells with PVT tube phase state experiments, the condensate gas dew point pressure at different temperatures is determined by using the phase diagram of condensate oil and gas, thereby determining the dew point pressure of the current segment.

[0088] For shale condensate gas wells without PVT tube phase experiments, the condensate gas dew point pressure at different temperatures is determined based on the first preset model, thereby determining the dew point pressure of the current segment.

[0089] In some implementations, the current segment's oil and gas production rate, taking into account the effects of condensate phase change, is calculated based on the oil and gas production rate at the ground separator location, the inlet pressure of the current segment, and the dew point pressure of the current segment.

[0090] In some implementations, the calculation of the current segment's oil and gas production, taking into account the effects of condensate phase change, includes:

[0091] Calculate the number of moles of oil and natural gas under ground separator conditions;

[0092] Based on the inlet pressure and dew point pressure of the current segment, establish the molar number equations for oil and natural gas in the current segment;

[0093] Establish a set of mass conservation equations for the molar number of oil and natural gas;

[0094] Solve the system of mass conservation equations to obtain the natural gas production and oil production of the current segment.

[0095] In this embodiment, the condensate oil content and the relative density of the condensate gas in the current segment are also calculated to incorporate the phase change effect of condensate oil and gas into the condensate oil content and the relative density of the condensate gas in the current segment.

[0096] Some existing technologies, when calculating the oil content and relative density of condensate gas in the current segment, do not consider oil-gas conversion or directly use the oil production of the ground separator as the oil content of the current segment, resulting in significant deviations in the calculation of the oil content and relative density of condensate gas in the current segment. In contrast, the technical solution of this embodiment calculates the oil-gas production of the current segment considering the effect of condensate phase change by using the oil-gas production at the location of the ground separator, the inlet pressure of the current segment, and the dew point pressure of the current segment. Then, based on the mass conservation of the current segment and the ground separator, it calculates the natural gas production and oil production of the current segment. It can convert oil and gas based on the effect of condensate phase change, improving the calculation accuracy of the fluid production and multiphase pipe flow liquid holdup of the current segment, and improving the accuracy of the pressure drop of the current segment.

[0097] Example 3

[0098] Based on the above embodiments, this embodiment provides a method for calculating bottom hole flowing pressure, wherein when the wellbore is segmented, the segment closest to the wellhead is taken as the first segment;

[0099] When the current segment is the first segment, the inlet pressure of the current segment is determined based on the source pressure;

[0100] When the current segment is not the first segment, the pressure at the outlet of the segment connected to the inlet of the current segment is used as the inlet pressure of the current segment.

[0101] In some implementations, when the current segment is the first segment, the inlet pressure of the current segment is determined based on the source pressure, including:

[0102] When the source pressure is the casing pressure, the inlet pressure of the current segment is determined based on the casing pressure;

[0103] When the source pressure is oil pressure, the inlet pressure of the current segment is determined based on the oil pressure.

[0104] The technical solution of this embodiment, by taking the segment near the wellhead as the first segment and determining the inlet pressure of the first segment based on the source pressure, can provide a calculation basis for the first segment and improve the accuracy of the bottom hole flowing pressure calculation.

[0105] Example 4

[0106] Based on the above embodiments, this embodiment provides a method for calculating bottom hole flowing pressure, wherein the gravity pressure drop of the current segment is calculated based on the following expression:

[0107] Δp si =ρ m gΔZ i

[0108] Where, Δp si Let ρ be the gravitational pressure drop of the current segment. m Let g be the density of the oil-gas-water mixture, g be the acceleration due to gravity, and ΔZ be the acceleration due to gravity. i denoted as the elevation difference of the current segment, where i is the segment number.

[0109] In some implementations, the density of the oil-gas-water mixture is calculated based on the following expression:

[0110] ρ m =ρ l ×E L +ρ g ×(1-E L )

[0111]

[0112] Where, ρ l E is the density of the liquid phase. L ρ represents the liquid holdup of the current segment. g ρ is the relative density of the current segmented condensate gas. o n is the density of oil. o n represents the current molar yield of the segmented oil. w ρ represents the current molar yield of water in the segment. w This is the density of water.

[0113] Some existing technologies do not consider oil and gas conversion when calculating gravity pressure drop, resulting in significant deviations. In contrast, the technical solution of this embodiment calculates the gravity pressure drop of the current segment by using the elevation difference of the current segment, the liquid holdup of the current segment, the relative density of condensate gas in the current segment, the oil density, the molar yield of oil in the current segment, the molar yield of water in the current segment, and the density of water. This incorporates the phase change of condensate gas into the calculation of gravity pressure drop, reducing the impact of oil and gas phase change on the calculation error of liquid holdup and improving the calculation accuracy of gravity pressure drop.

[0114] Example 5

[0115] Based on the above embodiments, this embodiment provides a method for calculating bottom hole flowing pressure, wherein the frictional pressure drop of the current segment is calculated based on the following expression:

[0116]

[0117] V m =V sl +V sg

[0118] V sl =[q w ×B w +q o，i ×B o ] / A

[0119] V sg =q g，i ×B g / A

[0120] Where, Δp fi f is the frictional voltage drop of the current segment. n ρ is the Fanning coefficient for the current segment. m V is the density of the oil-gas-water mixture. m V is the apparent velocity of the mixture, L is the length of the current segment, D is the equivalent hydraulic diameter of the wellbore flow section, and V is the apparent velocity of the mixture. sl V is the apparent flow rate of the liquid phase. sg Let q be the apparent velocity in the gas phase. w For water production, B w q is the volume coefficient of the aqueous phase. o，i For the current segment's oil production, B o Let q be the oil volume coefficient, A be the wellbore flow cross-sectional area, and q be the flow coefficient. g，i B represents the total gas production of the current segment. g This is the condensate gas volume coefficient.

[0121] In some implementations, the total gas production of the current segment is calculated based on the following expression:

[0122]

[0123] Where, q gf，i R represents the natural gas production of the current segment. v (p) represents the condensate oil content per unit volume of natural gas at pressure p, M o ρ is the molar molecular weight of condensate oil. osc This represents the density of condensate oil under surface conditions.

[0124] In some implementations, the Fanning coefficient is calculated based on the Reynolds number to determine the flow regime:

[0125] If the Reynolds number of the current segment is less than or equal to the first preset value, then the flow in the current segment is laminar, and the Fanning coefficient is:

[0126]

[0127] Among them, f n Here, Fanning coefficient is denoted as Re, and Re is the Reynolds number.

[0128] If the Reynolds number of the current segment is greater than the first preset value and less than or equal to the second preset value, then the flow in the current segment is a transient flow, and the Fanning coefficient is:

[0129]

[0130] If the Reynolds number of the current segment is greater than the second preset value, then the flow in the current segment is turbulent, and the Fanning coefficient satisfies:

[0131]

[0132] Where D is the equivalent hydraulic diameter of the wellbore flow section, and ε is the wellbore roughness.

[0133] The technical solution of this embodiment incorporates the phase change of condensate gas into the calculation of the frictional pressure drop of the current segment by taking into account factors such as the oil production of the current segment and the total gas production of the current segment. This improves the calculation accuracy of the frictional pressure drop of the current segment and thus improves the calculation accuracy of the bottom hole flowing pressure.

[0134] Example 6

[0135] Based on the above embodiments, this embodiment provides a method for calculating bottom hole flowing pressure, wherein the acceleration pressure drop of the current segment is calculated based on the following expression:

[0136]

[0137] Where, Δp g,i To accelerate the pressure drop, ρ m V is the density of the oil-gas-water mixture. m The apparent flow rate of the mixture.

[0138] Some existing technologies do not consider oil and gas conversion when calculating accelerated pressure drop, resulting in significant deviations in the accelerated pressure drop calculation. In contrast, the technical solution in this embodiment incorporates the condensate gas phase change into the calculation of accelerated pressure drop by using the density of the oil-gas-water mixture, thereby improving the calculation accuracy of the accelerated pressure drop in the current segment and consequently improving the calculation accuracy of the bottom hole flowing pressure.

[0139] Example 7

[0140] Figure 2 This is a schematic diagram of a bottom-hole flowing pressure calculation device provided in an embodiment of the present invention. Figure 2 As shown, based on the above embodiments, this embodiment provides a bottom hole flowing pressure calculation device, including:

[0141] The outlet pressure calculation module is used to segment the wellbore and calculate the outlet pressure of each current segment sequentially from the wellhead to the bottom of the wellbore. Specifically, when calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion.

[0142] The bottom hole flowing pressure determination module is used to determine the bottom hole flowing pressure when the current segment reaches the middle depth of the reservoir.

[0143] In this embodiment, the wellbore is segmented, and the outlet pressure of each segment is calculated sequentially from the wellhead to the bottom of the wellbore. The segment being calculated is the current segment. When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottomhole flowing pressure. In calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion. This allows the pressure drop of the current segment to be obtained while considering oil and gas conversion, reducing the impact of oil and gas phase change on the calculation error of liquid holdup and improving the calculation accuracy of bottomhole flowing pressure.

[0144] The bottom hole flowing pressure calculation device is used to execute the bottom hole flowing pressure calculation method in the above embodiments. A description of the bottom hole flowing pressure calculation method can be found in the description of the above embodiments, and will not be repeated in this embodiment.

[0145] Example 8

[0146] Based on the above embodiments, this embodiment also provides a storage medium, such as flash memory, hard disk, multimedia card, card-type memory (e.g., SD or DX memory), random access memory (RAM), static random access memory (SRAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), programmable read-only memory (PROM), magnetic memory, disk, optical disk, server, etc., which stores a computer program. When the computer program is executed, it can implement a bottom hole pressure calculation method in the above embodiments.

[0147] In this embodiment, the wellbore is segmented, and the outlet pressure of each segment is calculated sequentially from the wellhead to the bottom of the wellbore. The segment being calculated is the current segment. When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottomhole flowing pressure. In calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion. This allows the pressure drop of the current segment to be obtained while considering oil and gas conversion, reducing the impact of oil and gas phase change on the calculation error of liquid holdup and improving the calculation accuracy of bottomhole flowing pressure.

[0148] Example 9

[0149] Based on the above embodiments, this application provides an electronic device, which may be a mobile phone, computer, or tablet computer, or a potential tapping device, including a memory and a processor. The memory stores a calculator program, and when the computer program is executed by the processor, it implements a bottom hole flowing pressure calculation method as described in the above embodiments.

[0150] In this embodiment, the wellbore is segmented, and the outlet pressure of each segment is calculated sequentially from the wellhead to the bottom of the wellbore. The segment being calculated is the current segment. When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottomhole flowing pressure. In calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion. This allows the pressure drop of the current segment to be obtained while considering oil and gas conversion, reducing the impact of oil and gas phase change on the calculation error of liquid holdup and improving the calculation accuracy of bottomhole flowing pressure.

[0151] It is understood that electronic devices may also include multimedia components, input / output (I / O) interfaces, and communication components.

[0152] The processor is used to execute all or part of the steps in the compaction correction method as described in the above embodiments. The memory is used to store various types of data, which may include, for example, instructions for any application or method in the electronic device, as well as application-related data.

[0153] The processor may be implemented as an Application Specific Integrated Circuit (ASIC), Digital Signal Processor (DSP), Digital Signal Processing Device (DSPD), Programmable Logic Device (PLD), Field Programmable Gate Array (FPGA), controller, microcontroller, microprocessor, or other electronic components, and is used to perform all or part of the steps in the compaction correction method in the above embodiments.

[0154] Memory can be implemented from any type of volatile or non-volatile storage device or a combination thereof, such as Static Random Access Memory (SRAM), Electrically Erasable Programmable Read-Only Memory (EEPROM), Erasable Programmable Read-Only Memory (EPROM), Programmable Read-Only Memory (PROM), Read-Only Memory (ROM), magnetic storage, flash memory, magnetic disk or optical disk.

[0155] Example 10

[0156] Based on the above embodiments, this application provides an application example of the bottom hole flowing pressure calculation method.

[0157] This embodiment includes the following steps S1 to S14.

[0158] Step S1: Testing and collecting basic geological parameters, PVT tube phase state experiments, and PVT basic parameters, etc.

[0159] Basic geological parameters include: initial formation pressure, gas reservoir temperature, etc.

[0160] PVT (Potential Dynamic Testing) experiments include: well fluid composition testing, dew point pressure testing at different temperatures, constant mass expansion (CCE) experiments at different temperatures, and constant volume depletion (CVD) experiments at reservoir temperatures.

[0161] The basic parameters of PVT include: the original dew point pressure of the condensate gas reservoir, the initial condensate oil content, the initial gas-oil ratio, the surface separator temperature, the separator pressure, the relative density of natural gas, and the relative density of condensate oil.

[0162] Step S2: Collect gas well completion and wellbore tubing parameters

[0163] This includes wellbore trajectory, perforation range, casing inner diameter, tubing running time, tubing running depth, tubing inner and outer diameters, and gas well production methods (casing production, annular production, tubing production, etc.).

[0164] Step S3: Collect dynamic production data and pressure measurement data from gas wells;

[0165] This includes daily gas production, daily oil production, daily water production, wellhead casing pressure, oil pressure; wellhead temperature, bottom hole temperature; bottom hole test pressure, etc.

[0166] Step S4: Select the multiphase pipe flow well bottom pressure calculation model and initialize the PVT parameters and other attribute parameters;

[0167] Step S5: Check the basic PVT parameter settings and tubing configuration parameters. If an error is found, exit the calculation; if no errors are found, calculate the bottomhole flowing pressure based on the selected source pressure (e.g., casing pressure or oil pressure) and check other settings. If oil pressure is selected to calculate the bottomhole flowing pressure, check if tubing has been installed and if oil pressure data is available in the production data. If an error is found, exit the calculation.

[0168] Step S6: Divide the wellbore into sections and obtain the inlet pressure of the first section.

[0169] Divide the wellbore into 40-50 segments. Choose an appropriate number of segments so that the impact of pressure changes within each segment on the PVT properties of natural gas can be ignored and approximated as a constant.

[0170] The temperature of each segment is determined by linear interpolation of the wellhead temperature and the bottom hole temperature; the inlet pressure of each segment is equal to the outlet pressure of the previous segment connected to it; wherein, the inlet pressure of the first segment closest to the wellhead is set according to the selection of the source pressure; if the source pressure is the casing pressure, the bottom hole flowing pressure is calculated based on the casing pressure, and the inlet pressure of the first segment is set as the wellhead casing pressure; if the source pressure is the oil pressure, the bottom hole flowing pressure is calculated based on the oil pressure, and the inlet pressure of the first segment is set as the wellhead oil pressure;

[0171] Step S7: When starting the calculation of bottom hole flowing pressure, calculate the outlet pressure of each segment sequentially from the wellhead direction to the bottom hole direction. Therefore, first select the first segment closest to the wellhead as the current segment.

[0172] Step S8: Based on the above principles, set the inlet pressure and segment temperature of the current segment; determine the flow space of the current segment based on the tubing insertion time, tubing insertion depth, and gas extraction method, and calculate the equivalent hydraulic diameter D corresponding to the current segment.

[0173] Step S9: Calculate the dew point pressure of the current segment condensate gas;

[0174] Based on the available data, the condensate dew point pressure at different temperatures can be determined using two methods:

[0175] (1) Determine the dew point pressure of condensate gas at different temperatures based on the phase diagram of condensate oil and gas, and thus determine the dew point pressure of the current segment.

[0176] For shale condensate gas wells with PVT tube phase phase experiments, the condensate gas dew point pressure at different temperatures is determined by using the phase diagram of condensate oil and gas, thereby determining the dew point pressure of the current segment.

[0177] (2) For shale condensate gas wells without PVT tube phase state experiments, the condensate gas dew point pressure at different temperatures is determined based on empirical models, thereby determining the dew point pressure of the current segment.

[0178] ln(p d = 8.48 + 0.32239z + 0.00477z 2

[0179] In the formula:

[0180]

[0181] Considering the effect of temperature, based on the reservoir temperature T calculated above... ref Calculate the dew point pressure at the wellbore temperature:

[0182]

[0183] In the formula: p d R is the dew point pressure. sp1d API (Average Pressure Ratio) is the gas-oil ratio produced by the first-stage separator above the dew point pressure. d API specific gravity of condensate oil from the surface separator above the dew point pressure; γ gRd This represents the relative density of the condensate gas reservoir above the dew point pressure.

[0184] Step S10: Based on the principle of conservation of total molar number of oil and gas, calculate the current segment oil and gas production considering the influence of condensate phase change according to the oil and gas production at the ground separator location, the current segment inlet pressure, and the current segment dew point pressure.

[0185] During the flow of condensate oil and gas from the bottom of the well to the wellhead, the fluid temperature and pressure gradually decrease. As can be seen from the phase diagram of condensate gas, the phase state of the condensate oil and gas system will also change with the change of temperature and pressure. However, the total number of moles in the oil and gas system is conserved. Therefore, the oil and gas production at different locations in the wellbore (i.e., each segment) can be determined according to the principle of conservation of the total number of moles.

[0186] In any section of the wellbore, the fluid can be divided into three phases: oil, gas, and water. According to the principle of conservation of mass, the oil production at the surface separator location is equal to the sum of the oil production (liquid phase) and the condensate production (heavy hydrocarbons in the gas phase) at any location in the wellbore. Similarly, the gas production at any location in the wellbore consists of the dry gas production from the surface separator and the condensate production (heavy hydrocarbons in the gas phase). The condensate production (heavy hydrocarbons in the gas phase) can be determined from the dry gas production by the condensate content Rv.

[0187] Step S10.1: Calculate the condensate oil content Rv of the current segment.

[0188] Condensate oil is formed by the back-condensation of heavy components in condensate gas when the pressure or temperature decreases. Above the dew point pressure, it exists in the gas phase as natural gas, but under surface separator conditions, it will condense into condensate oil. The condensate oil content can be expressed as the volume of condensate oil contained in a unit volume of natural gas (dry gas) at the surface, denoted by Rv, which is a function of temperature and pressure.

[0189] Once the condensate oil content Rv of the current segment is determined, the dry gas production, oil production (liquid phase), and condensate oil (heavy hydrocarbons in the gas phase) production in the current segment can be determined according to the principle of molar conservation.

[0190] Based on the current segment temperature T i Inlet pressure P i1 This section calculates the condensate oil content Rv(p) per unit volume of natural gas in the current segment and the dissolved gas content Rs(p) per unit volume of condensate oil, i.e., the dissolved gas-oil ratio. The dissolved gas-oil ratio Rs can be calculated using models such as Standing, VasquezBess, or Glaso; this section primarily presents the calculation method for the condensate oil content Rv(p).

[0191] If downhole pressure-holding samples and indoor PVT cylinder phase state experiments are conducted on condensate gas reservoirs before production, the condensate oil content Rv under different pressures can be determined based on the experimental results.

[0192] In cases where phase state experiments are not available for reference, the condensate oil content R under different pressures can be calculated using the following first preset model. v :

[0193] ln(R v = 3.684 + 0.61967z + 0.015359z 2

[0194] In the formula:

[0195]

[0196] In the formula: R v γ represents the condensate oil content per unit volume of natural gas at pressure p; p is the pressure; gRd T is the relative density of the condensate gas when the pressure is higher than the dew point pressure. R For temperature.

[0197] Step 10.2: Calculate the molar number of oil and gas under ground separator conditions:

[0198] Moles of natural gas:

[0199] Molar number of condensate oil:

[0200] in,

[0201] Where: n g，0 The molar number of natural gas under ground separator conditions;

[0202] q gsc For natural gas production;

[0203] n o，0 The number of oil moles under ground separator conditions;

[0204] q osc Oil production under surface separator conditions;

[0205] ρ osc This refers to the density of condensate oil under surface conditions.

[0206] M o The value represents the molar molecular weight of the condensate oil.

[0207] Step 10.3: Establish the mole number equations for oil and natural gas in the current segment (e.g., the i-th segment):

[0208]

[0209]

[0210]

[0211]

[0212] Where: n g，i This represents the total number of moles of natural gas in the current segment, including both natural gas and dissolved gas.

[0213] q gf，i This represents the current natural gas production for that segment;

[0214] n o，i This represents the total number of moles of oil in the current segment, which consists of two parts: oil (liquid phase) and condensate oil (gas phase).

[0215] q o，i This represents the current oil production (liquid phase);

[0216] R s (p) is the dissolved gas-oil ratio at pressure p calculated based on the empirical relationship of PVT for condensate oil.

[0217] Step 10.4: During the process of the oil and gas system flowing from the bottom of the well through the wellbore to the surface separator, mass is conserved, and the total number of moles of oil and gas remains constant in any segment i. Therefore, based on the principle of mass conservation, the mass conservation equation for the number of moles of oil and gas can be established:

[0218] n g，0 =n g，i

[0219] n o，0 =n o，i

[0220] Step 10.5: Solve the system of mass conservation equations to obtain the natural gas production q for the current segment. gf，i Oil production q o，i ;

[0221]

[0222] q gf，i =(24.055×n) g，0 -q o，i ×R s ) / 10000

[0223] Condensate oil production (heavy hydrocarbons in the gas phase) can be calculated based on gas production and condensate oil content Rv.

[0224] Step 10.6: Calculate the relative density of the current segmented condensate gas.

[0225] As condensate gas flows from the bottom of the well to the wellhead, the content of heavy hydrocarbons (Rv) in the condensate gas gradually decreases with the gradual decrease in temperature and pressure. This leads to a gradual decrease in the content of heavy components in the condensate gas, and the condensate gas components gradually become lighter. It is necessary to accurately calculate the influence of the gas phase relative density on the back condensation of heavy components.

[0226] In the current segment (e.g., segment i), the condensate gas component consists of two parts: (1) natural gas (dry gas), which has almost no phase change in the wellbore and surface separator; (2) condensate oil (heavy hydrocarbons in the gas phase). According to the phase equilibrium theory, some heavy components exist in the gas phase in the form of natural gas above the dew point pressure. When the temperature or pressure gradually decreases, some heavy hydrocarbons will condense back into the liquid phase, and the condensate oil content will also change. It can be represented by the condensate oil content Rv in a unit volume of natural gas.

[0227] The dry gas production, condensate oil production (heavy hydrocarbons in the gas phase), and oil production (liquid phase) in the current segment have been calculated in the above steps. Therefore, the relative density of the condensate gas in the current segment can be calculated according to the definition of relative density:

[0228] The number of moles of natural gas in the current segment:

[0229]

[0230] The molar number of condensate oil (heavy hydrocarbons in the gas phase) in the current segment:

[0231]

[0232] The average molecular weight of the condensate gas in the current segment:

[0233]

[0234] The relative density of the condensate gas in the current segment:

[0235]

[0236] Step 11, Liquid holdup E of the current segment L calculate:

[0237] Among numerous gas-liquid multiphase flow wellbore pressure drop calculation models, the methods for calculating liquid holdup vary considerably. However, after considering the impact of condensate gas phase changes in the wellbore on oil and gas production and relative density through the aforementioned steps, the new oil and gas production and condensate gas relative density can be used to calculate the natural gas PVT properties and current section pressure drop for each segment. Taking the Gray model as an example:

[0238]

[0239]

[0240]

[0241]

[0242]

[0243]

[0244] In the formula,

[0245] E L This represents the liquid holdup of the current segment;

[0246] ρ m The density of the oil-gas-water mixture;

[0247] σ l The interfacial tension between gas and liquid;

[0248] g is the acceleration due to gravity;

[0249] ρ l The density of the liquid;

[0250] ρ g The density of the gas;

[0251] D is the equivalent hydraulic diameter;

[0252] V m The velocity of the gas-liquid mixture;

[0253] f is the Fanning coefficient of friction;

[0254] V sl The apparent flow rate of the liquid phase;

[0255] V sg The apparent flow rate in the gas phase is denoted as ρ.

[0256] The existing method does not consider the effects of temperature and pressure changes in the wellbore flow on the condensate dew point pressure, oil and gas phase state, and oil and gas production. In the calculation of pressure drop in different segments of the entire wellbore flow, the gas production and oil production remain unchanged, and the effects of oil and gas phase state changes on oil and gas production and the relative density changes of natural gas are not considered.

[0257] In this invention, after calculating the dry gas production, condensate oil production (gas phase), and oil production (liquid phase) of the i-th segment according to the above steps, the oil and gas production of each segment will reflect the influence of temperature and pressure changes on phase state, oil and gas production, and relative density of natural gas.

[0258] Step 12: Calculation of current segmented voltage drop

[0259] The current segment pressure drop consists of three parts: gravity pressure drop (also known as hydraulic pressure drop), friction pressure drop, and acceleration pressure drop. When calculating the current segment pressure drop, the water production at the segment inlet is taken as the wellhead water production, and the gas production is taken as the sum of the dry gas production and condensate oil production (heavy hydrocarbons in the gas phase) of the current segment. The conversion process of oil and gas two-phase production is shown in step 10.

[0260] Step 12.1 Gravitational pressure drop

[0261] The gravitational pressure drop of the current segment can be calculated using the following formula:

[0262] Δp si =ρ m gΔZ i

[0263] In the formula: Δp si ρ represents the gravitational pressure drop of the current segment. m ρ is the density of the oil-gas-water mixture; g is the acceleration due to gravity; ΔZ i This represents the elevation difference of the current segment.

[0264] The density of the oil-gas-water mixture can be calculated using the following formula:

[0265] ρ m =ρ l ×E L +ρ g ×(1-E L )

[0266]

[0267] In the formula:

[0268] ρ l The liquid phase density is calculated as a weighted average of the current mole fractions of oil and water.

[0269] E L The liquid holdup of the current segment is calculated as described above;

[0270] ρ g The relative density of the condensate gas in the current segment is calculated using the relative density value of the condensate gas calculated in step 10.6 above;

[0271] ρ o The density of the oil;

[0272] n o This represents the current molar yield of the segmented oil.

[0273] n w This represents the current molar yield of water in the segment.

[0274] ρ wThis is the density of water.

[0275] Step 12.2 Frictional Voltage Drop

[0276] The frictional voltage drop of the current segment can be calculated using the following formula:

[0277]

[0278] V m =V sl +V sg

[0279] V sl =[q w ×B w +q o，i ×B o ] / A

[0280] V sg =q g，i ×B g / A

[0281] In the formula: Δp fi This represents the frictional voltage drop of the current segment;

[0282] f n The Fanning coefficient for the current segment;

[0283] V m The apparent flow rate of the mixture;

[0284] D is the equivalent hydraulic diameter of the wellbore flow section;

[0285] L is the length of the current segment;

[0286] V sl The apparent flow rate of the liquid phase;

[0287] V sg This refers to the apparent flow rate in the gas phase.

[0288] q w Water production;

[0289] B w The volume coefficient for the aqueous phase;

[0290] B o This is the oil volume coefficient;

[0291] B g The volume coefficient of condensate gas;

[0292] A is the cross-sectional area of ​​the wellbore flow; q g，i The total gas production of the current segment is the sum of the dry gas production and the condensate (gas phase) production of the current segment.

[0293]

[0294] Among them, the Fanning coefficient f n The flow regime can be determined based on the Reynolds number Re. In this example, the first preset value is, for example, 2000, and the second preset value is, for example, 4000.

[0295] (1) If the Reynolds number Re ≤ 2000 for the current segment, then the flow in the current segment is laminar, and the Fanning coefficient is...

[0296] (2) If 2000 < Reynolds number Re ≤ 4000 for the current segment, then the flow in the current segment is a transitional flow, and the Fanning coefficient is:

[0297]

[0298] (3) If the Reynolds number Re > 4000 in the current segment, then the flow in the current segment is turbulent, and the Fanning coefficient satisfies:

[0299]

[0300] In the formula, ε is the well wall roughness;

[0301] 12.3 Accelerated Pressure Drop

[0302] The acceleration voltage drop of the current segment can be calculated using the following formula:

[0303]

[0304] In the formula: Δp g,i To accelerate the pressure drop.

[0305] Step 13: Calculate the outlet pressure of the current segment based on the inlet pressure, hydraulic pressure drop, frictional pressure drop, and acceleration pressure drop of the current segment.

[0306] Outlet pressure = Inlet pressure + Hydraulic pressure drop + Frictional pressure drop + Acceleration pressure drop

[0307] Step 14: Determine whether the current segment has reached the middle depth of the reservoir. If it has not reached the middle depth of the reservoir, use the outlet pressure of the current segment as the inlet pressure of the next segment and return to step 8; if it has reached the middle depth of the reservoir, use the outlet pressure of the current segment as the bottom hole pressure.

[0308] This invention addresses condensate gas wells in continental shale, considering the impact of condensate gas phase changes caused by temperature and pressure variations along the wellbore on the calculation of multiphase flow liquid holdup, as well as the impact of changes in heavy hydrocarbon components in the condensate gas on the calculation of PVT properties. It establishes a method for calculating the bottom pressure of the three phases of oil, gas, and water in shale condensate gas wells, taking into account phase changes in the wellbore.

[0309] This invention considers the effects of temperature and pressure changes on the phase state, natural gas composition, and relative density of shale condensate gas reservoirs, and establishes a method and system for calculating the three-phase wellbore pressure of shale condensate gas wells. This addresses the technical problem that existing shale gas well bottom-flow pressure calculation methods do not consider the impact of changes in condensate gas phase change, natural gas composition, and relative density caused by wellbore temperature and pressure variations on the calculation of three-phase pipeline pressure drop.

[0310] This method has the following advantages:

[0311] (1) Consider the effects of temperature and pressure changes along the wellbore on the condensate gas phase state and the composition and relative density of natural gas;

[0312] (2) Consider the impact of three-phase flow of oil, gas and water on wellbore pressure calculation;

[0313] (3) No complex component model phase equilibrium calculation is required, making it simple to implement.

[0314] To further illustrate the beneficial effects of this method, the following example is taken from Taiye B-1HF, a horizontal well in the Lianggaoshan Formation of the Jurassic system in the Sichuan Basin, to explain the bottom-hole flowing pressure calculation method for multi-stage fracturing of shale condensate gas in horizontal wells and its beneficial effects.

[0315] Step 1: Test and collect basic geological parameters, shale condensate gas phase experiments, and PVT parameters, etc.

[0316] Collect basic geological parameters of the shale condensate gas well, including original formation pressure and reservoir temperature;

[0317] Phase variability tests (PVTs) were conducted on downhole pressure-maintaining samples, including well fluid molar composition, dew point pressure at different temperatures, constant mass expansion (CCE) at different temperatures, and constant volume depletion (CVD) at reservoir temperatures. Other basic PVT parameters included the original dew point pressure of the condensate gas reservoir, initial condensate oil content, initial gas-oil ratio, surface separator temperature and pressure, dry gas relative density, and condensate oil relative density.

[0318] Table 1 shows the relevant basic geological parameters of Taiye B-1HF in this embodiment, Table 2 shows the basic PVT parameters for oil and gas, and Table 3 shows the composition of well fluids. Figure 3 It is the condensate oil content Rv under different pressures.

[0319] Table 1. Basic Geological Parameters of Thai Page B-1HF

[0320] <![CDATA[Original formation pressure p i (MPa)]]> 31.45 <![CDATA[Formation temperature t₀ (℃)]]> 69.49

[0321] Table 2. Basic parameters of condensate oil and gas in Taiye B-1HF well.

[0322] Wellhead temperature 25 Separated gas temperature (°C) 20 Separator pressure (MPa) 0.689 relative density of natural gas in ground separator 0.742 relative density of condensate oil from ground separator 0.7768 Dew point pressure (MPa) of shale condensate gas reservoir under initial conditions 27.2 <![CDATA[Initial gas-oil ratio above dew point pressure (m 3 / 1000m 3 )]]> 0.95 <![CDATA[Solution gas-oil ratio at dew point pressure (m 3 / m 3 )]]> 338.47

[0323] Table 3. Composition of fluids in the Taiye B-1HF well.

[0324]

[0325]

[0326] Step 2: Collect parameters such as wellbore trajectory, wellbore string, and gas production method.

[0327] Parameters such as wellbore trajectory, completion section, casing size, tubing running time, running depth, and tubing inner and outer diameters are collected, as shown in Table 4.

[0328] Table 4 Completion and tubing parameters for the Taiye B-1HF fractured horizontal well

[0329] Layer Dongyue Temple Group Horizontal segment length (m) 1500 Number of fracturing sections / clusters 20 / 146 Perforation depth (m) 2570 Inner diameter of the sleeve (mm) 115.5 Oil pipe inner and outer diameters (mm) 62 / 72 Tubing insertion time Production begins Tubing depth (m) 2370

[0330] Step 3: Collect test production data and pressure measurement data from the gas well.

[0331] The collected gas well test production data includes daily gas production, daily oil production, daily water production, wellhead oil pressure, and casing pressure; the collected pressure measurement data of the gas well (actual bottom hole flowing pressure or static pressure) are shown in Table 5.

[0332] Table 5. Measured Pressure Gauge for Thai Page B-1HF

[0333]

[0334]

[0335] Step 4: Check the basic PVT parameter settings, tubing configuration, and production data. If any errors are found, exit the calculation.

[0336] Step 5: Select the Gray model as the calculation model for multiphase pipe flow bottom hole pressure and initialize the PVT and other attribute tables;

[0337] Step 6: Divide the wellbore string into, for example, 50 sections, and select to calculate the bottom hole flowing pressure based on casing pressure;

[0338] Step 7: Calculate the pressure drop of each segment from the wellhead to the bottom of the well until the middle depth of the reservoir is reached to obtain the bottom hole flowing pressure.

[0339] 1. Bottomhole Flow Pressure Calculation Method. Based on the wellbore string structure and gas well production method (e.g., tubing production or casing production), the bottomhole flow pressure in the gas reservoir is calculated from the wellhead casing pressure, gas production, water production, and oil production. Here, the Gray model is used to calculate the bottomhole flow pressure; the pressure gradient calculation expression is as follows:

[0340]

[0341] in,

[0342] ρ m =ρ l H l +ρ g (1-H l )

[0343]

[0344]

[0345]

[0346]

[0347]

[0348]

[0349] In the formula, ρ l ρ is the density of the liquid. g V is the gas density; sl V sg These represent the apparent liquid velocity and apparent gas velocity of the gas well, respectively; D is the equivalent hydraulic diameter; v m denoted as ρ, where ρ is the flow velocity of the gas-liquid mixture; f is the Fanning coefficient of friction.

[0350] 2. Calculation results of bottom hole flowing pressure.

[0351] Based on the wellhead casing pressure, gas production, water production, and condensate production data given in Table 5, and according to the wellbore string and other PVT parameters, the bottom hole flowing pressure corresponding to each data point was calculated according to the steps of this method. The results are shown in Table 6.

[0352] Table 6. Results of Bottomhole Flow Pressure Calculation for Taiye B-1HF

[0353] 2021 / 2 / 26 17.57 15.27 23.93 23.41 2021 / 3 / 19 13.77 9.88 17.33 18.58 2021 / 6 / 17 14.71 10.99 19.34 18.9 2021 / 7 / 6 14.28 11.10 18.82 19.33 2021 / 7 / 30 13.03 10.08 16.42 17.48

[0354] 3. Taking data from July 30, 2021 as an example, the curve showing the change in condensate production along the vertical pipe section with depth, calculated using this method, is as follows: Figure 4 As shown, the curve of total gas production (dry gas + condensate oil) along the vertical pipe section varies with depth. Figure 5 As shown, the pressure variation curve with depth is as follows: Figure 6 As shown.

[0355] Therefore, the purpose of this invention is to solve the problems existing in the prior art. For continental shale condensate gas wells, considering the impact of changes in the phase state of condensate gas caused by changes in temperature and pressure along the wellbore, and changes in the relative density caused by changes in the heavy components in natural gas on the calculation of the pressure drop of the three-phase oil-gas-water pipeline, a method for calculating the bottom pressure of the three-phase oil-gas-water pipeline considering the phase change of the shale condensate gas wellbore is established.

[0356] In the embodiments provided by this invention, it should be understood that the disclosed apparatus and methods can also be implemented in other ways. The apparatus embodiments described above are merely illustrative; for example, the flowcharts and block diagrams in the accompanying drawings illustrate the architecture, functionality, and operation of possible implementations of apparatus, methods, and computer program products according to various embodiments of the present invention. In this regard, each block in a flowchart or block diagram may represent a module, segment, or portion of code containing one or more executable instructions for implementing a specified logical function. It should also be noted that in some alternative implementations, the functions marked in the blocks may occur in a different order than those marked in the drawings. For example, two consecutive blocks may actually be executed substantially in parallel, and they may sometimes be executed in reverse order, depending on the functions involved. It should also be noted that each block in a block diagram and / or flowchart, and combinations of blocks in block diagrams and / or flowcharts, can be implemented using a dedicated hardware-based system that performs the specified function or action, or using a combination of dedicated hardware and computer instructions.

[0357] It should be noted that, in this invention, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitation, an element limited by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0358] While the embodiments disclosed in this invention are as described above, the above content is merely for the purpose of facilitating understanding of this invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope disclosed in this invention; however, the scope of patent protection of this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for calculating bottom-hole flowing pressure in a horizontal well, characterized in that, include: The wellbore is divided into sections, and the outlet pressure of each section is calculated sequentially from the wellhead end to the bottom end of the wellbore. The section being calculated is the current section. When the current segment reaches the middle depth of the reservoir, the outlet pressure of the current segment is taken as the bottom hole flowing pressure; In calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion. The pressure drop of the current segment considering oil and gas conversion includes gravity pressure drop, friction pressure drop and acceleration pressure drop. The calculation of the pressure drop of the current segment considering oil and gas conversion includes: calculating the oil and gas production of the current segment considering the effect of condensate phase change based on the oil and gas production at the location of the ground separator, the inlet pressure of the current segment, and the dew point pressure of the current segment. The calculation of the current segment oil and gas production, which takes into account the effects of condensate phase change, includes: Calculate the number of moles of oil and natural gas under ground separator conditions; Based on the inlet pressure and dew point pressure of the current segment, establish the molar number equations for oil and natural gas in the current segment; Establish a set of mass conservation equations for the molar number of oil and natural gas; Solve the system of mass conservation equations to obtain the natural gas production and oil production of the current segment; The frictional voltage drop of the current segment is calculated based on the following expression: in, The frictional voltage drop of the current segment is... The Fanning coefficient for the current segment. The density of the oil-gas-water mixture, The apparent flow rate of the mixture. The length of the current segment. Let be the equivalent hydraulic diameter of the wellbore flow section. The apparent flow rate of the liquid phase is... The apparent flow rate in the gas phase is... For water production, The volume coefficient of the aqueous phase. This represents the current oil production of the segment. The volume coefficient of oil. The cross-sectional area of ​​the wellbore flow is... This represents the total gas production of the current segment. This is the condensate gas volume coefficient.

2. The method for calculating bottom hole flowing pressure according to claim 1, characterized in that, The method of obtaining the outlet pressure of the current segment by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion includes: Calculate the outlet pressure of the current segment based on the inlet pressure, gravity pressure drop, friction pressure drop, and acceleration pressure drop of the current segment.

3. The method for calculating bottom hole flowing pressure according to claim 2, characterized in that, Calculating the pressure drop of the current segment considering oil and gas conversion includes: determining the dew point pressure of the current segment through the phase diagram of condensate oil and gas or a first preset model, including: For shale condensate gas wells with PVT tube phase state experiments, the condensate gas dew point pressure at different temperatures is determined by using the phase diagram of condensate oil and gas, thereby determining the dew point pressure of the current segment. For shale condensate gas wells without PVT tube phase experiments, the condensate gas dew point pressure at different temperatures is determined based on the first preset model, thereby determining the dew point pressure of the current segment.

4. The method for calculating bottom hole flowing pressure according to any one of claims 2 to 3, characterized in that, When dividing the wellbore into sections, the section closest to the wellhead is designated as the first section. When the current segment is the first segment, the inlet pressure of the current segment is determined based on the source pressure; When the current segment is not the first segment, the outlet pressure of the segment connected to the inlet end of the current segment is used as the inlet pressure of the current segment.

5. The method for calculating bottom hole flowing pressure according to claim 4, characterized in that, When the current segment is the first segment, determining the inlet pressure of the current segment based on the source pressure includes: When the source pressure is the sleeve pressure, the inlet pressure of the current segment is determined based on the sleeve pressure; When the source pressure is oil pressure, the inlet pressure of the current segment is determined based on the oil pressure.

6. The method for calculating bottom hole flowing pressure according to any one of claims 2 to 3, characterized in that, The gravitational pressure drop of the current segment is calculated based on the following expression: in, The gravity pressure drop of the current segment. Let g be the density of the oil-gas-water mixture, and g be the acceleration due to gravity. denoted as the elevation difference of the current segment, where i is the segment number.

7. The method for calculating bottom hole flowing pressure according to claim 6, characterized in that, The density of an oil-gas-water mixture is calculated based on the following expression: in, The density of the liquid phase is... The liquid holdup of the current segment. This represents the relative density of the current segmented condensate gas. For oil density, This represents the current molar yield of the segmented oil. The current molar yield of water in the segment. This is the density of water.

8. The method for calculating bottom hole flowing pressure according to claim 1, characterized in that, The total gas production of the current segment is calculated based on the following expression: in, This represents the current natural gas production for the segment. This represents the condensate oil content per unit volume of natural gas at pressure p. The molar molecular weight of condensate oil is... This represents the density of condensate oil under surface conditions.

9. The method for calculating bottom hole flowing pressure according to claim 1, characterized in that, Calculate the Fanning coefficient based on the flow regime determined by the Reynolds number: If the Reynolds number of the current segment is less than or equal to the first preset value, then the flow in the current segment is laminar, and the Fanning coefficient is: in, Here, Fanning coefficient is denoted as F, and Re is the Reynolds number. If the Reynolds number of the current segment is greater than the first preset value and less than or equal to the second preset value, then the flow in the current segment is a transient flow, and the Fanning coefficient is: If the Reynolds number of the current segment is greater than the second preset value, then the flow in the current segment is turbulent, and the Fanning coefficient satisfies: in, ε is the equivalent hydraulic diameter of the wellbore flow section, and ε is the wellbore roughness.

10. The method for calculating bottom hole flowing pressure according to any one of claims 2 to 3, characterized in that, The acceleration voltage drop of the current segment is calculated based on the following expression: in, To accelerate the pressure drop, The density of the oil-gas-water mixture, The apparent flow rate of the mixture.

11. A bottom-hole flowing pressure calculation device based on any one of the bottom-hole flowing pressure calculation methods according to claims 1 to 10, characterized in that, include: The outlet pressure calculation module is used to segment the wellbore and calculate the outlet pressure of each current segment sequentially from the wellhead to the bottom of the wellbore. Specifically, when calculating the outlet pressure of the current segment, the outlet pressure of the current segment is obtained by summing the inlet pressure of the current segment and the pressure drop of the current segment considering oil and gas conversion. The bottom hole flowing pressure determination module is used to determine the bottom hole flowing pressure when the current segment reaches the middle depth of the reservoir.

12. A computer-readable storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by a processor, it implements the method of any one of claims 1 to 10.

13. An electronic device comprising a processor and a memory, characterized in that, The memory stores a computer program, and the processor executes the computer program to implement the method of any one of claims 1 to 10.

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