Shaft pressure drop loss calculation method, device, equipment, medium and program

Abstract

According to the technical scheme, the method comprises the steps that a stratum corresponding to an upper pipe column of a production well production layer is equally divided into n sections from high to low, the bottom pressure value of the nth section is determined according to a flow temperature gradient curve, 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 pressure drop loss of an upper pipe column shaft according to the bottom pressure value of the nth section; m production sections are divided according to the sounding depth of the production well, the bottom hole pressure value is calculated according to a 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. According to the method, a large inclined shaft pressure drop loss calculation model considering the angle change of the upper pipe column and the production section, the gas production distribution of the production section shaft and the water production distribution of the production section is finally established, and the pressure drop loss of the highly-deviated well shaft of the thick-layer strong-heterogeneity gas reservoir can be accurately calculated.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas exploration, and in particular to a method, device, equipment, medium and program for calculating wellbore pressure drop loss. Background Art

[0002] For offshore thick and highly heterogeneous gas reservoirs, high-angle wells or horizontal wells are usually used for production. When the well inclination angle entering the production layer is greater than 60°, the downhole pressure gauge cannot reach the production layer, and the bottom hole flow pressure cannot be directly obtained through the measured data. Only relatively complete wellhead oil pressure data is available.

[0003] Conventional wellbore pressure drop calculation methods regard the mass flow rate in the wellbore as a constant. However, the mass flow rate in the wellbore from the bottom of the wellbore to the top of the reservoir in a highly heterogeneous gas reservoir with thick layers gradually increases. The existing method of calculating the wellbore pressure drop loss of the entire well section using variable mass flow is not suitable for calculating the wellbore pressure drop loss of highly inclined wells in thick gas reservoirs, and lacks verification with measured data.

[0004] Therefore, it is urgent to establish a verifiable method that can accurately calculate the wellbore pressure drop loss of highly deviated wells in thick and highly heterogeneous gas reservoirs. Summary of the invention

[0005] The present invention provides a method, device, equipment, medium and program for calculating wellbore pressure drop loss, which can accurately calculate the wellbore pressure drop loss of a highly deviated well in a thick layer and highly heterogeneous gas reservoir.

[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 production layer is divided into n sections from high to low, and the bottom pressure value of the nth section is determined 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 includes the bottom temperature value of each section;

[0008] Determine the wellbore pressure drop loss of the upper tubing string according to the bottom pressure value of the nth section;

[0009] Divide the production well into m production sections according to the measured depth, and calculate the bottom hole pressure value according to the flow temperature gradient curve and the flow value of each production section, wherein the flow temperature gradient curve includes the top temperature value of each production section;

[0010] The wellbore pressure drop loss is determined according to the wellbore pressure drop loss of the upper tubing string and the bottom hole pressure value.

[0011] Optionally, the average physical property parameters include: deviation factor, viscosity, friction and Reynolds number; accordingly, when the production well has been pressure tested and the pressure gauge has been lowered to the upper part of the production layer, the bottom pressure of the nth section is determined according to the flow temperature gradient curve, including:

[0012] Calculating the deviation factor, viscosity, friction and Reynolds number of the first section according to the bottom temperature value of the first section and the pressure value of the upper part of the production layer measured by the pressure gauge;

[0013] determining the bottom pressure of the first section according to the deviation factor, viscosity, friction and Reynolds number of the string of the first section;

[0014] The bottom pressure value of the second section is calculated according to the bottom pressure of the first section and the bottom temperature value of the second section and the deviation factor, viscosity, friction resistance and column Reynolds number of the second section, until the bottom pressure of the nth section is calculated.

[0015] Optionally, the deviation factor, viscosity, friction and column Reynolds number are calculated by the following formula:

[0016]

[0017] Wherein, D is the inner diameter of the upper pipe column; e is the inner surface roughness of the upper pipe column; R e,H,i is the Reynolds number of the i-th section of the pipe, dimensionless; f H,i is the friction coefficient of the i-th segment; q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas; Z H,i is the gas deviation factor of the i-th segment; P H,i is the lower pressure corresponding to the i-th segment. When i=1, P H,i is the pressure value of the upper part of the production layer measured by the pressure gauge; T H,i is the temperature; g,i is the relative density of natural gas; M g is the gas molecular weight; R is the universal gas constant.

[0018] Optionally, calculate the bottom pressure value using the following formula:

[0019]

[0020] p h,i =p h,i-1 +Δp h,i ;

[0021] In, p h,i is the bottom pressure value of the i-th section; Δp h,i is the pressure difference of the i-th segment, p h,i-1 is the bottom pressure value of the previous section of the i-th section. When i=1, ph,i-1 is the pressure value of the upper part of the production layer measured by the pressure gauge; θ is the inclination angle of the i-th section; a is the unit conversion coefficient; g is the gravity acceleration; f i is the friction coefficient of the i-th segment, q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas, D is the inner diameter of the upper pipe string, ρ i is the gas density of the ith section; Δh is the height difference between the ith section and the production layer.

[0022] In the embodiment of the present invention, the flow value of each production section is calculated according to the following formula:

[0023]

[0024] Among them, q i is the flow value of the i-th production section, K i is the average permeability of each section, h wf,i is the thickness of the i-th production section, q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas; H is the total thickness of the production layer, ρ i is the gas density of the i-th production section.

[0025] Optionally, the calculating of the bottom hole pressure value according to the flow value of each production section includes:

[0026] Calculate the top pressure value of the first production section according to the order of height values ​​from high to low by using the reservoir top pressure and the top temperature value of the first production section;

[0027] Calculating the top pressure value of the second production section according to 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 mth production section is calculated, to obtain the bottom hole pressure value;

[0028] Among them, the top pressure value is calculated by the following formula:

[0029]

[0030]

[0031] P wf,i =P wf,i-1 +ΔP wf,i ;

[0032] Among them, P wf,i is the top pressure value of the i-th production section, P wf,i-1 is the top pressure value of the previous production section of the i-th production section. When i=1, P wf,i-1 is the set pressure value; ΔP wf,iis the top pressure difference of the i-th production section; a is the unit conversion coefficient; g is the gravitational acceleration; ρ i is the gas density of the i-th production section; Δh wf is the distance difference between the ith production section and the bottom of the well; θ is the inclination angle of the ith section.

[0033] Optionally, when the production well is not pressure tested, the flow-temperature gradient curves of other production wells in the gas reservoir where the production well is located are used as the flow-temperature gradient curve of the production well.

[0034] Optionally, the method further includes:

[0035] Obtaining the average original formation pressure of the mth segment of the production layer according to the static pressure gradient curve of the gas reservoir;

[0036] According to the top pressure value and the bottom temperature value of each production section, the average bottom hole pressure and the average temperature of the mth section are obtained, and according to the average bottom hole pressure and the average temperature, the equilibrium viscosity and the average deviation factor are obtained;

[0037] The flow value of the mth section is calculated according to the average bottom hole pressure, the average temperature, the equilibrium viscosity and the average deviation factor, and the total mass flow is calculated from the mth section to the upper section of the wellbore to the first section at the top of the production layer;

[0038] A wellhead flow rate is obtained based on the total mass flow rate, and the flow temperature gradient curve is evaluated according to a comparison result between the wellhead flow rate and the actually measured wellhead flow rate.

[0039] According to another aspect of the present invention, there is provided a wellbore pressure drop loss calculation device, comprising:

[0040] A pressure value calculation unit is used to divide the formation corresponding to the upper pipe string of the production well into n sections from high to low, and determine 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 includes the bottom temperature value of each section;

[0041] A wellbore pressure drop loss calculation unit, used to determine the wellbore pressure drop loss of the upper tubing string according to the bottom pressure value of the nth section;

[0042] A bottom hole pressure value calculation unit, used for dividing the production well into m production sections according to the measured depth, and calculating the bottom hole pressure value according to the flow temperature gradient curve and the flow value of each production section, wherein the flow temperature gradient curve includes the top temperature value of each production section;

[0043] A processing unit is used to determine the wellbore pressure drop loss according to the wellbore pressure drop loss of the upper tubing string and the bottom hole pressure value.

[0044] According to another aspect of the present invention, there is provided an electronic device, the electronic device comprising:

[0045] 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, and the computer program is executed by the at least one processor so that the at least one processor can execute the wellbore pressure drop loss calculation method described in any embodiment of the present invention.

[0046] According to another aspect of the present invention, a computer-readable storage medium is provided, wherein the computer-readable storage medium stores computer instructions, and the computer instructions are used to enable a processor to implement the method for calculating wellbore pressure drop loss described in any embodiment of the present invention when executed.

[0047] According to another aspect of the present invention, a computer program product is provided. The computer program product includes a computer program. When the computer program is executed by a processor, the method for calculating the wellbore pressure drop loss described in any embodiment of the present invention is implemented.

[0048] The technical solution of the embodiment of the present invention is to divide the formation corresponding to the upper tubular column of the production well into n sections from high to low, and determine 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 includes the bottom temperature value of each section; determine the upper tubular column wellbore pressure drop loss according to the bottom pressure value of the nth section; divide m production sections according to the sounding of the production well, calculate 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 includes the top temperature value of each production section; determine the wellbore pressure drop loss according to the upper tubular column wellbore pressure drop loss and the bottom hole pressure value. The solution of the embodiment of the present invention divides the reservoir section into n small layers, draws on the research results of variable mass flow in horizontal wells, and considers the additional pressure drop caused by variable mass flow in the open hole section and the mixed friction pressure drop at the junction of the open hole and the formation. Finally, a calculation model for the pressure drop loss in highly inclined wellbores is established, which takes into account the changes in the angles 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 in highly inclined wellbores in thick and highly heterogeneous gas reservoirs.

[0049] It should be understood that the contents described in this section are not intended to identify the key or important features of the embodiments of the present invention, nor are they intended to limit the scope of the present invention. Other features of the present invention will become easily understood through the following description. BRIEF DESCRIPTION OF THE DRAWINGS

[0050] In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the following briefly introduces the drawings required for use in the description of the embodiments. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without creative work.

[0051] Figure 1 is a flow chart of a method for calculating wellbore pressure drop loss provided according to Embodiment 1 of the present invention;

[0052] Figure 2 is a schematic structural diagram of a wellbore pressure drop loss calculation device applicable to the second embodiment of the present invention;

[0053] Figure 3 It is a schematic diagram of the structure of an electronic device for implementing the wellbore pressure drop loss calculation method of an embodiment of the present invention. DETAILED DESCRIPTION

[0054] In order to enable those skilled in the art to better understand the scheme of the present invention, the technical scheme in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work should fall within the scope of protection of the present invention.

[0055] It should be noted that the terms "first", "second", etc. in the specification and claims of the present invention and the above-mentioned drawings are used to distinguish similar objects, and are not necessarily used to describe a specific order or sequence. It should be understood that the data used in this way can be interchanged where appropriate, so that the embodiments of the present invention described herein can be implemented in an order other than those illustrated or described herein. In addition, the terms "including" and "having" and any variations thereof are intended to cover non-exclusive inclusions, for example, a process, method, system, product or device that includes a series of steps or units is not necessarily limited to those steps or units that are clearly listed, but may include other steps or units that are not clearly listed or inherent to these processes, methods, products or devices.

[0056] Embodiment 1

[0057] Figure 1This is a flow chart of a method for calculating wellbore pressure drop loss provided by the first embodiment of the present invention. This embodiment can be applied to the case of calculating the wellbore pressure drop loss of a highly deviated well in a thick layer and highly heterogeneous gas reservoir. The method can be executed by a wellbore pressure drop loss calculation device, which can be implemented in the form of hardware and / or software, and the wellbore pressure drop loss calculation device can be configured in an electronic device. Figure 1 As shown, the method includes:

[0058] S110. Divide the formation corresponding to the upper tubing of the production well production layer into n sections from high to low, and determine 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 includes the bottom temperature value of each section.

[0059] In the embodiment of the present invention, the average physical property parameters include: deviation factor, viscosity, friction and Reynolds number; accordingly, when the production well has been pressure tested and the pressure gauge has been lowered to the upper part of the production layer, the bottom pressure of the nth section is determined according to the flow temperature gradient curve, including:

[0060] Calculating the deviation factor, viscosity, friction and Reynolds number of the first section according to the bottom temperature value of the first section and the pressure value of the upper part of the production layer measured by the pressure gauge;

[0061] determining the bottom pressure of the first section according to the deviation factor, viscosity, friction and Reynolds number of the string of the first section;

[0062] The bottom pressure value of the second section is calculated according to the bottom pressure of the first section and the bottom temperature value of the second section and the deviation factor, viscosity, friction resistance and column Reynolds number of the second section, until the bottom pressure of the nth section is calculated.

[0063] In an embodiment of the present invention, the deviation factor, viscosity, friction and column Reynolds number are calculated by the following formula:

[0064]

[0065] Wherein, D is the inner diameter of the upper pipe column; e is the inner surface roughness of the upper pipe column; R e,H,i is the Reynolds number of the i-th section of the pipe, dimensionless; f H,i is the friction coefficient of the i-th segment; q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas; Z H,i is the gas deviation factor of the i-th segment; P H,i is the lower pressure corresponding to the i-th segment. When i=1, P H,i is the pressure value of the upper part of the production layer measured by the pressure gauge; T H,i is the temperature; g,iis the relative density of natural gas; M g is the gas molecular weight; R is the universal gas constant.

[0066] Among them, for the production gas wells that are undergoing pressure testing but with the pressure gauge lowered to the upper part of the production layer, the formation corresponding to the upper pipe string is divided into n equal parts, and the thickness of each section is h. Through the depth h, the bottom temperature T of the first section is calculated in combination with the measured flow temperature gradient curve H,1 , according to P H,0 、T H,1 The average physical property parameters of the first section are calculated using the above formula, and the deviation factor Z is calculated using the DPR method. H,1 , using Lee-Gonzalez semi-empirical method viscosity μ H,1 , calculate the friction f H,1 and the Reynolds number R e,H,1 . The Reynolds number is a dimensionless number used to describe the flow state of a fluid. The Reynolds number is defined as the ratio of inertial force to viscous force. When the Reynolds number is small, the viscous force is dominant and the fluid flow is laminar; when the Reynolds number is large, the inertial force is dominant and the fluid flow is turbulent. The flow temperature gradient curve refers to a curve showing the change of fluid temperature with depth or distance. The flow temperature gradient curve is used in some fields such as geology, geothermal science, and reservoir engineering. For example, when studying underground thermal conditions, by measuring the fluid temperature at different depths and drawing a flow temperature gradient curve, we can understand the change of underground temperature with depth, and then infer the underground heat flow distribution, geological structure, etc. In an oil reservoir, the flow temperature gradient curve can help analyze the temperature distribution of the oil reservoir, which is of great significance for the development and management of the oil reservoir.

[0067] S120, determining the wellbore pressure drop loss of the upper tubing string according to the bottom pressure value of the nth section.

[0068] In the embodiment of the present invention, the bottom pressure value is calculated by the following formula:

[0069]

[0070] p h,i =p h,i-1 +Δp h,i ;

[0071] Among them, p h,i is the bottom pressure value of the i-th section; Δp h,i is the pressure difference of the i-th segment, p h,i-1 is the bottom pressure value of the previous section of the i-th section. When i=1, p h,i-1 is the pressure value of the upper part of the production layer measured by the pressure gauge; θ is the inclination angle of the i-th section; a is the unit conversion coefficient; g is the gravity acceleration; f i is the friction coefficient of the i-th segment, q sc is the wellhead flow rate; ρ scis the density of the wellhead gas, D is the inner diameter of the upper pipe string, ρ i is the gas density of the ith section; Δh is the height difference between the ith section and the production layer.

[0072] Substituting the average physical property parameters into the above formula, the bottom pressure P of the first section is calculated. H,1 , according to h H,1 , P H,1 and the bottom temperature of the second section T H,2 , calculate the bottom pressure P of the second section H,1 , and so on, calculate the bottom pressure P of the i-1th section, the ith section, the i+1th section, and even the nth section h,n , the calculated P h,n The pressure gauge measured P h,0 Compare and if the error is less than 0.05MPa, output P h,n , the pressure drop loss of the upper tubing string is P d =P h,n -P H,0 If the error is not less than 0.05MPa, modify the h value and recalculate P h,n , until the error requirement is met.

[0073] In the embodiment of the present invention, the flow value of each production section is calculated according to the following formula:

[0074]

[0075] Among them, q i is the flow value of the i-th production section, K i is the average permeability of each section, h wf,i is the thickness of the i-th production section, q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas; H is the total thickness of the production layer, ρ i is the gas density of the i-th production section.

[0076] Assuming that the inflow rate of each production section varies linearly with the permeability and thickness of the section, the flow rate of each small section is calculated. Similar to the previous article, the reservoir top pressure is defined as P wf,1 , calculated based on the flow temperature gradient wf,1 , use the above formula to calculate the top pressure of the second section of the production layer, and so on, until the calculation reaches the bottom of the well, and the final bottom hole pressure is obtained.

[0077] S130, dividing the production well into m production sections according to the measured depth, and calculating the bottom hole pressure value according to the flow-temperature gradient curve and the flow value of each production section, wherein the flow-temperature gradient curve includes the top temperature value of each production section.

[0078] S140, dividing the production well into m production sections according to the measured depth, and calculating the bottom hole pressure value according to the flow-temperature gradient curve and the flow value of each production section, wherein the flow-temperature gradient curve includes the top temperature value of each production section.

[0079] In an embodiment of the present invention, the bottom hole pressure value is calculated according to the flow value of each production section, including:

[0080] Calculate the top pressure value of the first production section according to the order of height values ​​from high to low by using the reservoir top pressure and the top temperature value of the first production section;

[0081] Calculating the top pressure value of the second production section according to 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 mth production section is calculated, to obtain the bottom hole pressure value;

[0082] Among them, the top pressure value is calculated by the following formula:

[0083]

[0084] P wf,i =P wf,i-1 +ΔP wf,i ;

[0085] Among them, P wf,i is the top pressure value of the i-th production section, P wf,i-1 is the top pressure value of the previous production section of the i-th production section. When i=1, P wf,i-1 is the set pressure value; ΔP wf,i is the top pressure difference of the i-th production section; a is the unit conversion coefficient; g is the gravitational acceleration; ρ i is the gas density of the i-th production section; Δh wf is the distance difference between the ith production section and the bottom of the well; θ is the inclination angle of the ith section.

[0086] Divide the production section into n sections according to the depth of the production well. Assume that the inflow rate of each production section varies linearly with the permeability and thickness of the section, and calculate the flow rate of each small section. Define the reservoir top pressure as P wf,1 , according to P wf,1 and T calculated from the flow temperature gradient wf,1 , use the above formula to calculate the top pressure P of the second section of the production layer wf,2 , and so on, until the calculation reaches the bottom of the well, and the final bottom hole pressure P' is obtained wf Wellbore pressure drop loss P D =P' wf -P H,0 .

[0087] In the embodiment of the present invention, when the production well is not pressure tested, the flow-temperature gradient curves of other production wells in the gas reservoir where the production well is located are used as the flow-temperature gradient curve of the production well.

[0088] For the production gas wells that have not been pressure tested, the formation corresponding to the upper string is divided into n equal parts, each with a thickness of h. Assuming that the wellhead flow rate is q sc,H , calculate the bottom temperature T of the first section by combining the measured flow temperature gradient curves of other wells in the gas reservoir through the depth h H,1 , according to P H,0 、T H,1 The average physical property parameters of the first section were calculated as described above, the deviation factor was calculated using the DPR method, the viscosity was calculated using the Lee-Gonzalez semi-empirical method, and the friction and Reynolds number were calculated.

[0089] Substitute the parameters calculated in step 1 into the formula to calculate the bottom pressure P of the first section. H,1 , according to h H,1 , P H,1 and the bottom temperature of the second section T H,2 , calculate the bottom pressure P of the second section H,1 , and so on, calculate the bottom pressure P of the i-1th section, the ith section, the i+1th section, and even the nth section h,n .

[0090] Assuming that the inflow rate of each production section varies linearly with the permeability and thickness of the section, the flow rate of each small section is calculated, where K i is the average permeability of each section, h i is the thickness of each section, H is the total thickness of the pay zone, ρ i is the gas density of this section. The bottom pressure of the nth section is the top pressure of the production layer, which is P wf,1 , according to h wf,1 , P wf,1 and T calculated from the flow-temperature curve wf,1 , calculate the top pressure P of the second section of the production layer wf,2 , and so on, until the calculation reaches the bottom of the well, and the final bottom hole pressure P is obtained. wf,n .

[0091] In an embodiment of the present invention, the method may further include:

[0092] Obtaining the average original formation pressure of the mth segment of the production layer according to the static pressure gradient curve of the gas reservoir;

[0093] According to the top pressure value and the bottom temperature value of each production section, the average bottom hole pressure and the average temperature of the mth section are obtained, and according to the average bottom hole pressure and the average temperature, the equilibrium viscosity and the average deviation factor are obtained;

[0094] The flow value of the mth section is calculated according to the average bottom hole pressure, the average temperature, the equilibrium viscosity and the average deviation factor, and the total mass flow is calculated from the mth section to the upper section of the wellbore to the first section at the top of the production layer;

[0095] A wellhead flow rate is obtained based on the total mass flow rate, and the flow temperature gradient curve is evaluated according to a comparison result between the wellhead flow rate and the actually measured wellhead flow rate.

[0096] The average original formation pressure of the lowest segment of the production layer is obtained according to the static pressure gradient curve of the gas reservoir Using the calculated P wf,n , P wf,n-1 、T wf,n and T wf,n-1 , and the average bottom hole pressure of this section is obtained The average temperature of this section Calculate the average viscosity of this section The average deviation factor of this segment According to the general formula of capacity binomial, the flow rate q can be calculated g,n-1 and q g,n-1 , calculated from the lower section of the wellbore to the upper section of the wellbore until the top of the production layer, the total mass flow rate W wfsc =W g,n-1 +W g,n-2 +……+W g,2 +W g,1 The calculation formula is as follows:

[0097]

[0098] W g,n-1 =q g,n-1 *ρ g,n-1 ;

[0099] Where: r e is the well control radius; r w is the wellbore radius.

[0100] According to the calculated bottom pressure P of the nth section h,n 、The bottom pressure of the n-1th section P h,n-1 , the bottom temperature of the nth section is T H,n , the bottom temperature of the n-1th section T H,n-1 , the average pressure of the nth segment is calculated as The average temperature of the nth segment is The calculated flow rate of the nth segment is Q sc,1 , calculate upwards in sequence to obtain the wellhead flow rate, Q sc,H , and the measured wellhead flow rate Q H A comparison is performed. If the calculation error is not satisfied, the flow temperature gradient curve is re-given until the calculation result satisfies the error.

[0101] The invention has the following beneficial effects: through the data of well depth, wellbore structure, well inclination angle, wellhead pressure, wellhead flow rate, etc., the pressure drop difference caused by the inflow of gas in each section of the thick reservoir is taken into account, and the problem of inaccurate calculation of the pressure drop loss of the wellbore of the high-angle well caused by the inability of the pressure gauge to reach the production layer is solved. At the same time, for the production gas wells without downhole pressure gauges, a method for calculating the wellbore pressure drop loss using the wellhead flow rate for correction is given, which provides a new idea for the evaluation of the productivity of offshore gas wells.

[0102] Embodiment 2

[0103] Figure 2 Schematic diagram of the structure of a wellbore pressure drop loss calculation device provided by the second embodiment of the present invention. Figure 2 As shown, the device comprises:

[0104] The pressure value calculation unit 210 is used to divide the formation corresponding to the upper tubular string of the production well into n sections from high to low, and determine 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 includes the bottom temperature value of each section;

[0105] A wellbore pressure drop loss calculation unit 220, used to determine the wellbore pressure drop loss of the upper tubing string according to the bottom pressure value of the nth section;

[0106] A bottom hole pressure value calculation unit 230, for dividing the production well into m production sections according to the measured depth, and calculating the bottom hole pressure value according to the flow temperature gradient curve and the flow value of each production section, wherein the flow temperature gradient curve includes the top temperature value of each production section;

[0107] The processing unit 230 is used to determine the wellbore pressure drop loss according to the wellbore pressure drop loss of the upper tubing string and the bottom hole pressure value.

[0108] The wellbore pressure drop loss calculation device provided in the embodiment of the present invention can execute the wellbore pressure drop loss calculation method provided in any embodiment of the present invention, and has the corresponding functional modules and beneficial effects of the execution method.

[0109] Embodiment 3

[0110] Figure 3A schematic diagram of the structure of an electronic device 10 that can be used to implement an embodiment 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 processing, cellular phones, smart phones, wearable devices (such as helmets, glasses, watches, etc.) and other similar computing devices. The components shown herein, their connections and relationships, and their functions are merely examples and are not intended to limit the implementation of the present invention described and / or required herein.

[0111] like Figure 3 As shown, the electronic device 10 includes at least one processor 11, and a memory connected to the at least one processor 11, such as a read-only memory (ROM) 12, a random access memory (RAM) 13, etc., wherein the memory stores a computer program that can be executed by at least one processor, and the processor 11 can perform various appropriate actions and processes according to the computer program stored in the read-only memory (ROM) 12 or the computer program loaded from the storage unit 18 to the random access memory (RAM) 13. In the RAM 13, various programs and data required for the operation of the electronic device 10 can also be stored. The processor 11, the ROM 12, and the RAM 13 are connected to each other through a bus 14. An input / output (I / O) interface 15 is also connected to the bus 14.

[0112] A number of components in the electronic device 10 are connected to the I / O interface 15, including: an input unit 16, such as a keyboard, a mouse, etc.; an output unit 17, such as various types of displays, speakers, etc.; a storage unit 18, such as a disk, an optical disk, etc.; and a communication unit 19, such as a network card, a modem, a wireless communication transceiver, etc. The communication unit 19 allows the electronic device 10 to exchange information / data with other devices through a computer network such as the Internet and / or various telecommunication networks.

[0113] The processor 11 may be a variety of general and / or special processing components with processing and computing capabilities. Some examples of the processor 11 include, but are not limited to, a central processing unit (CPU), a graphics processing unit (GPU), various special artificial intelligence (AI) computing chips, various processors running machine learning model algorithms, a digital signal processor (DSP), and any appropriate processor, controller, microcontroller, etc. The processor 11 executes the various methods and processes described above, such as a wellbore pressure drop loss calculation method.

[0114] In some embodiments, the wellbore pressure drop loss calculation method may be implemented as a computer program, which is tangibly contained in a computer-readable storage medium, such as a storage unit 18. In some embodiments, part or all of the computer program may be loaded and / or installed on the electronic device 10 via the ROM 12 and / or the communication unit 19. When the computer program is loaded into the RAM 13 and executed by the processor 11, one or more steps of the wellbore pressure drop loss calculation method described above may be performed. Alternatively, in other embodiments, the processor 11 may be configured to execute the wellbore pressure drop loss calculation method in any other appropriate manner (e.g., by means of firmware).

[0115] Various implementations 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 chips (SOCs), load programmable logic devices (CPLDs), computer hardware, firmware, software, and / or combinations thereof. These various implementations can include: being implemented in one or more computer programs that can be executed and / or interpreted on a programmable system including at least one programmable processor, which can be a special purpose or general purpose programmable processor that can receive data and instructions from a storage system, at least one input device, and at least one output device, and transmit data and instructions to the storage system, the at least one input device, and the at least one output device.

[0116] Computer programs for implementing 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, so that when the computer program is executed by the processor, the functions / operations specified in the flow chart and / or block diagram are implemented. The computer program may be executed entirely on the machine, partially on the machine, partially on the machine and partially on a remote machine as a stand-alone software package, or entirely on a remote machine or server.

[0117] In the context of the present invention, a computer-readable storage medium may be a tangible medium that may contain or store a computer program for use by or in conjunction with an instruction execution system, device, or equipment. A computer-readable storage medium may include, but is not limited to, electronic, magnetic, optical, electromagnetic, infrared, or semiconductor systems, devices, or equipment, or any suitable combination of the foregoing. Alternatively, a computer-readable storage medium may be a machine-readable signal medium. A more specific example of a machine-readable storage medium may include an electrical connection based on one or more lines, a portable computer disk, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or flash memory), an optical fiber, a portable compact disk read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing.

[0118] To provide interaction with a user, the systems and techniques described herein may 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 a pointing device (e.g., a mouse or trackball) through which the user can provide input to the electronic device. Other types of devices may also be used to provide interaction with the user; for example, the feedback provided to the user may be any form of sensory feedback (e.g., visual feedback, auditory feedback, or tactile feedback); and input from the user may be received in any form (including acoustic input, voice input, or tactile input).

[0119] The systems and techniques described herein may be implemented in a computing system that includes backend components (e.g., as a data server), or a computing system that includes middleware components (e.g., an application server), or a computing system that includes frontend components (e.g., a user computer with a graphical user interface or a web browser through which a user can interact with implementations of the systems and techniques described herein), or a computing system that includes any combination of such backend components, middleware components, or frontend components. The components of the system may be interconnected by any form or medium of digital data communication (e.g., a communication network). Examples of communication networks include: a local area network (LAN), a wide area network (WAN), a blockchain network, and the Internet.

[0120] A computing system may include a client and a server. The client and the server are generally remote from each other and usually interact through a communication network. The client and server relationship is generated by computer programs running on the corresponding computers and having a client-server relationship with each other. The server may be a cloud server, also known as a cloud computing server or cloud host, which is a host product in the cloud computing service system to solve the defects of difficult management and weak business scalability in traditional physical hosts and VPS services.

[0121] It should be understood that the various forms of processes shown above can be used to reorder, add or delete steps. For example, the steps described in the present invention can be executed in parallel, sequentially or in different orders, as long as the desired results of the technical solution of the present invention can be achieved, and this document does not limit this.

[0122] The above specific implementations do not constitute a limitation on the protection scope of the present invention. It should be understood by those skilled in the art that various modifications, combinations, sub-combinations and substitutions can be made according to design requirements and other factors. Any modification, equivalent substitution and improvement made within the spirit and principle of the present invention should be included in the protection scope of the present 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 production layer is divided into n sections from high to low, and the bottom pressure value of the nth section is determined 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 includes the bottom temperature value of each section; Determine the wellbore pressure drop loss of the upper tubing string according to the bottom pressure value of the nth section; Divide the production well into m production sections according to the measured depth, and calculate the bottom hole pressure value according to the flow temperature gradient curve and the flow value of each production section, wherein the flow temperature gradient curve includes the top temperature value of each production section; The wellbore pressure drop loss is determined according to the wellbore pressure drop loss of the upper tubing string and the bottom hole pressure value.

2. The method according to claim 1, characterized in that The average physical property parameters include: deviation factor, viscosity, friction and Reynolds number; accordingly, when the production well has been pressure tested and the pressure gauge has been lowered to the upper part of the production layer, the bottom pressure of the nth section is determined according to the flow temperature gradient curve, including: Calculating the deviation factor, viscosity, friction and Reynolds number of the first section according to the bottom temperature value of the first section and the pressure value of the upper part of the production layer measured by the pressure gauge; determining the bottom pressure of the first section according to the deviation factor, viscosity, friction and Reynolds number of the string of the first section; The bottom pressure value of the second section is calculated according to the bottom pressure of the first section and the bottom temperature value of the second section and the deviation factor, viscosity, friction resistance and column Reynolds number of the second section, until the bottom pressure of the nth section is calculated.

3. The method according to claim 2, characterized in that The deviation factor, viscosity, friction and column Reynolds number are calculated by the following formula: Wherein, D is the inner diameter of the upper pipe column; e is the inner surface roughness of the upper pipe column; R e,H,i is the Reynolds number of the i-th section of the pipe, dimensionless; f H,i is the friction coefficient of the i-th segment; q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas; Z H,i is the gas deviation factor of the i-th segment; P H,i is the lower pressure corresponding to the i-th segment. When i=1, P H,i is the pressure value of the upper part of the production layer measured by the pressure gauge; T H,i is the temperature; g,i is the relative density of natural gas; M g is the gas molecular weight; R is the universal gas constant.

4. The method according to claim 3, characterized in that The bottom pressure value is calculated by the following formula: p h,i =p h,i-1 +Δp h,i ; Among them, p h,i is the bottom pressure value of the i-th section; Δp h,i is the pressure difference of the i-th segment, p h,i-1 is the bottom pressure value of the previous section of the i-th section. When i=1, p h,i-1 is the pressure value of the upper part of the production layer measured by the pressure gauge; θ is the inclination angle of the i-th section; a is the unit conversion coefficient; g is the gravity acceleration; f i is the friction coefficient of the i-th segment, q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas, D is the inner diameter of the upper pipe string, ρ i is the gas density of the ith section; Δh is the height difference between the ith section and the production layer.

5. The method according to claim 1, characterized in that The flow rate value of each production section is calculated according to the following formula: Among them, q i is the flow value of the i-th production section, K i is the average permeability of each section, h wf,i is the thickness of the i-th production section, q sc is the wellhead flow rate; ρ sc is the density of the wellhead gas; H is the total thickness of the production layer, ρ i is the gas density of the ith production section.

6. The method according to claim 5, characterized in that The method of calculating the bottom hole pressure value according to the flow value of each production section includes: Calculate the top pressure value of the first production section according to the order of height values ​​from high to low by using the reservoir top pressure and the top temperature value of the first production section; Calculating the top pressure value of the second production section according to 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 mth production section is calculated, to obtain the bottom hole pressure value; Among them, the top pressure value is calculated by the following formula: P wf,i =P wf,i-1 +ΔP wf,i ; Among them, P wf,i is the top pressure value of the i-th production section, P wf,i-1 is the top pressure value of the previous production section of the i-th production section. When i=1, P wf,i-1 is the set pressure value; ΔP wf,i is the top pressure difference of the i-th production section; a is the unit conversion coefficient; g is the gravitational acceleration; ρ i is the gas density of the i-th production section; Δh wf is the distance difference between the ith production section and the bottom of the well; θ is the inclination angle of the ith section.

7. The method according to claim 1, characterized in that When the production well is not pressure tested, the flow-temperature gradient curves of other production wells in the gas reservoir where the production well is located are used as the flow-temperature gradient curve of the production well.

8. The method according to claim 7, characterized in that Further including: Obtaining the average original formation pressure of the mth segment of the production layer according to the static pressure gradient curve of the gas reservoir; According to the top pressure value and the bottom temperature value of each production section, the average bottom hole pressure and the average temperature of the mth section are obtained, and according to the average bottom hole pressure and the average temperature, the equilibrium viscosity and the average deviation factor are obtained; The flow value of the mth section is calculated according to the average bottom hole pressure, the average temperature, the equilibrium viscosity and the average deviation factor, and the total mass flow is calculated from the mth section to the upper section of the wellbore to the first section at the top of the production layer; A wellhead flow rate is obtained based on the total mass flow rate, and the flow temperature gradient curve is evaluated according to a comparison result between the wellhead flow rate and the actually measured wellhead flow rate.

9. A wellbore pressure drop loss calculation device, characterized in that: include: A pressure value calculation unit is used to divide the formation corresponding to the upper pipe string of the production well into n sections from high to low, and determine 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 includes the bottom temperature value of each section; A wellbore pressure drop loss calculation unit, used to determine the wellbore pressure drop loss of the upper tubing string according to the bottom pressure value of the nth section; A bottom hole pressure value calculation unit, used for dividing the production well into m production sections according to the measured depth, and calculating the bottom hole pressure value according to the flow temperature gradient curve and the flow value of each production section, wherein the flow temperature gradient curve includes the top temperature value of each production section; A processing unit is used to determine the wellbore pressure drop loss according to the wellbore pressure drop loss of the upper tubing string and the bottom hole pressure value.

10. An electronic device, characterized in that: The electronic device comprises: 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, and the computer program is executed by the at least one processor so that the at least one processor can execute the wellbore pressure drop loss calculation method described in any one of claims 1-8.

11. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores computer instructions, and the computer instructions are used to enable a processor to implement the wellbore pressure drop loss calculation method according to any one of claims 1-8 when executed.

12. A computer program product, characterized in that The computer program product comprises a computer program, which, when executed by a processor, implements the method for calculating wellbore pressure drop loss according to any one of claims 1-8.

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