A method of predicting casing annulus pressure

Abstract

This application provides a method for predicting annular pressure in oil and gas well production technology. The method includes a wellbore structure consisting of, from the inside out, layers of tubing, production casing, technical casing, surface casing, and cementing sheath. An annular protective fluid A is filled between the tubing and production casing, and an annular protective fluid B is filled between the production casing and technical casing. A packer is located between the tubing and production casing. The method includes: calculating and recording the ultimate pressure at the time of tubing failure; recording the ultimate pressure at the time of production casing rupture; comparing and analyzing the two pressures, and selecting the minimum value as the maximum annular pressure. Predicting the maximum annular pressure provides a reliable basis for safe well operation and design.

Description

Technical Field

[0001] This application relates to the field of oil and gas well development technology, and more specifically, to a method for predicting annular pressure in oil wells. Background Technology

[0002] In oil and gas extraction, to ensure the safety of the connection between the formation and the surface, wellbore structures often employ nested casing layers. This complex wellbore structure includes the annulus formed by the nesting of tubing and casing, and vice versa. During oil well operations, the annulus pressure directly affects downhole safety. If the annulus pressure exceeds the maximum allowable range, it can cause deformation of the tubing and production casing, leading to a blowout. The issue of annulus pressure is receiving increasing attention, and accurately predicting the safe range of annulus pressure is crucial for safe well operation and wellbore design optimization. It is necessary to conduct research on the maximum allowable annulus pressure and develop a method for predicting it to comprehensively and intuitively manage annulus pressure and prevent damage caused by exceeding the pressure-bearing capacity of the tubing and production casing. Therefore, how to systematically and accurately calculate annulus pressure values ​​has become a pressing problem in this field. Summary of the Invention

[0003] This application provides a method for predicting annular pressure in an oil jacket, aiming to solve the problem of how to accurately calculate the annular pressure value.

[0004] The first aspect of this application provides a method for predicting annular pressure in an oil well casing. The well structure consists of nested layers from the inside out: tubing, production casing, technical casing, surface casing, and cementing sheath. The tubing and production casing are filled with an annular protective fluid A; the production casing and technical casing are filled with an annular protective fluid B; and the technical casing and surface casing are filled with an annular protective fluid C. A packer is located between the tubing and the production casing. The method includes: When the tubing bursts, calculate and record the maximum permissible annular pressure in annulus A; When the production casing ruptures, calculate and record the maximum permissible annular pressure in annulus A; The maximum permissible annular pressure of the A annulus when the tubing is crushed is compared with the maximum permissible annular pressure of the A annulus when the production casing is ruptured, to obtain the maximum permissible pressure of the A annulus.

[0005] In one alternative implementation, taking into account the corrosion of the tubing, the maximum permissible annulus pressure at the time of tubing failure is calculated using the following formula:

[0006] in, The maximum permissible annular pressure (MPa) in the A annulus during tubing failure, taking into account the effects of tubing corrosion; The remaining resistance to crushing of the tubing, in MPa; Oil pressure, MPa; Density of annular protective fluid A, kg / m³ 3 ; The density of the fluid inside the tubing is kg / m. 3 H is the packer vertical depth, in meters; g is the natural acceleration.

[0007] In one optional implementation, calculating the remaining crush resistance of the tubing includes: When the oil pipe is subjected to external extrusion force When the oil pipe is subjected to external extrusion stress, the following formula is used to calculate the stress:

[0008] in, The oil pipe is subjected to external extrusion stress, MPa; The initial outer diameter of the tubing is in mm; The initial wall thickness of the tubing is in mm; External extrusion force, MPa; After the oil pipe has been used for time t, the wall thickness of the oil pipe is calculated using the following formula:

[0009] in, The wall thickness of the tubing after a service time t, in mm; The corrosion rate of the oil pipe material is expressed in mm / a. The initial wall thickness of the tubing is in mm; The remaining crush resistance of the tubing is calculated using the following formula:

[0010] in, The remaining resistance to crushing of the tubing, in MPa; The oil pipe yield strength is given by MPa. The corrosion rate of the oil pipe material is expressed in mm / a. The wall thickness of the tubing after a service time t, in mm; The initial outer diameter of the tubing is in mm; a represents the usage time of the oil pipeline.

[0011] In one alternative implementation, considering the effects of tubing corrosion and temperature, the maximum permissible annulus pressure at the time of tubing failure is calculated using the following formula:

[0012] in, The maximum annular pressure (MPa) of annulus A during tubing failure, taking into account the effects of tubing corrosion and temperature. The oil pipe yield strength is given by MPa. The corrosion rate of the oil pipe material is expressed in mm / a. The initial outer diameter of the tubing is in mm; Oil pressure, MPa; Density of annular protective fluid A, kg / m³ 3 ; The density of the fluid inside the tubing is kg / m. 3 t represents the oil pipe usage time, a; denoted as initial tubing wall thickness (mm); n is the tubing wall thickness reduction factor due to temperature influence; g is natural acceleration; and H is packer vertical depth (m).

[0013] In one alternative implementation, taking into account the corrosion of the production casing, the maximum permissible annular pressure A when the production casing ruptures is calculated using the following formula:

[0014] in, To account for the impact of production casing corrosion, the maximum permissible annular pressure (MPa) in annulus A during a production casing rupture is calculated. The remaining internal pressure resistance of the casing is measured in MPa. B is the annular pressure value, MPa; H is the packer vertical depth, m; Density of the annulus fluid in region A, kg / m³ 3 ; The density of the annular fluid in region B is kg / m³. 3 g represents natural acceleration.

[0015] In one optional implementation, calculating the remaining internal pressure resistance of the production casing includes: When the production casing is subjected to internal pressure The circumferential stress of the production casing is calculated using the following formula:

[0016] in, The circumferential stress of the casing is measured in MPa. Internal pressure, MPa; The initial outer diameter of the casing during production, in mm; The initial wall thickness of the casing during production, in mm; When the production sleeve is used After a certain period of time, the circumferential stress of the production sleeve is:

[0017] in, The circumferential stress of the casing is measured in MPa. Internal pressure, MPa; The initial outer diameter of the casing during production, in mm; The initial wall thickness of the casing during production, in mm; The corrosion rate of the production casing is measured in mm / a. a; This refers to the service life of the production sleeve. The remaining internal pressure resistance of the production casing is calculated using the following formula:

[0018] in, The remaining internal pressure resistance of the casing during production; MPa; The yield strength required for producing the casing; The initial wall thickness for producing the casing; The corrosion rate of the casing pipe is measured in mm / a. The initial outer diameter of the casing during production, in mm; a represents the usage time of the production sleeve.

[0019] In one alternative implementation, considering the effects of corrosion and temperature on the production casing, the maximum annular pressure at annulus A during the rupture of the production casing is calculated using the following formula:

[0020] in, To account for the effects of production casing corrosion and temperature, the maximum permissible annular pressure (MPa) in case of production casing rupture in annulus A; The yield strength of the casing is measured in MPa. The initial outer diameter of the casing during production, in mm; The corrosion rate of the casing pipe is expressed in mm / a. a; This refers to the service life of the production sleeve. Density of the annulus fluid in region A, kg / m³ 3 ; The density of the annular fluid in region B is kg / m³. 3 ; n1 represents the initial wall thickness of the production casing, in mm; n1 is the reduction factor of the production casing wall thickness under the influence of temperature. denoted as B, where the annulus is pressurized (MPa); g is the natural acceleration.

[0021] In one optional implementation, the wall thickness reduction factor n or n1 may take the following values: When the temperature is less than or equal to 120℃, the wall thickness reduction factor n or n1 is 1; When the temperature is greater than 120℃ and less than or equal to 150℃, the wall thickness reduction factor n or n1 is 0.967; When the temperature is greater than 150℃ and less than or equal to 180℃, the wall thickness reduction factor n or n1 is 0.933; When the temperature is greater than 180℃ and less than or equal to 200℃, the wall thickness reduction factor n or n1 is 0.9; When the temperature is greater than 200℃ and less than or equal to 230℃, the wall thickness reduction factor n or n1 is 0.867.

[0022] In an optional implementation, the method further includes: When the tubing is crushed and / or the production casing ruptures, the upward pressure differential of the packer sleeve is calculated using the following formula:

[0023] in, The pressure differential above the packer sleeve, in MPa; The packer sleeve is rated to withstand differential pressure, MPa; The bottom hole flowing pressure is in MPa. Density of the annulus fluid in region A, kg / m³ 3 H is the packer vertical depth, in meters; g is the natural acceleration. The maximum permissible annular pressure of the A annulus when the tubing is crushed, the maximum permissible annular pressure of the A annulus when the production casing is ruptured, and the upward pressure difference of the packer sleeve are compared and analyzed, and the minimum value is selected as the maximum permissible pressure of the A annulus.

[0024] In one optional embodiment, comparing the maximum permissible annular pressure of annulus A when the tubing is crushed with the maximum permissible annular pressure of annulus A when the production casing ruptures to obtain the maximum permissible pressure of annulus A includes: The maximum permissible annular pressure of the A annulus when the tubing is crushed is compared and analyzed with the maximum permissible annular pressure of the A annulus when the production casing is ruptured, and the minimum value is selected as the maximum permissible pressure of the A annulus.

[0025] Beneficial effects: This application provides a method for predicting annular pressure in oil and gas well production technology. The method includes a wellbore structure consisting of, from the inside out, layers of tubing, production casing, technical casing, surface casing, and cementing sheath. An annular protective fluid A is filled between the tubing and production casing; an annular protective fluid B is filled between the production casing and technical casing; a packer is located between the tubing and production casing; and an annular protective fluid C is filled between the technical casing and surface casing. The method includes: calculating and recording the maximum permissible annular pressure A when the tubing fails; calculating and recording the maximum permissible annular pressure A when the production casing ruptures; and comparing the maximum permissible annular pressure A at the time of tubing failure with that at the time of production casing rupture to obtain the maximum permissible pressure of the annulus A. Predicting the maximum annular pressure provides a reliable basis for safe well operation and design, reducing the accident rate. Attached Figure Description

[0026] To more clearly illustrate the technical solutions of the embodiments of this application, the drawings used in the description of the embodiments of this application will be briefly introduced below. Obviously, the drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0027] Figure 1 This is a schematic cross-sectional view of a well shaft structure proposed in one embodiment of this application; Figure 2 This is a top view schematic diagram of the well structure proposed in one embodiment of this application; Figure 3 This is a flowchart of a method for predicting annular pressure of an oil jacket according to an embodiment of this application; Figure 4 This is a schematic diagram of a device for predicting the annular pressure of an oil jacket according to an embodiment of this application; Detailed Implementation The technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0028] In oil and gas extraction, to ensure the safety of the connection between the formation and the surface, wellbore structures often employ nested casing layers. This complex wellbore structure includes the annulus formed by the nesting of tubing and casing, and vice versa. During oil well operations, the annulus pressure directly affects downhole safety. If the annulus pressure exceeds the maximum allowable range, it can cause tubing crushing, production casing rupture, and ultimately, a blowout. The issue of annulus pressure is receiving increasing attention, and accurately predicting the safe range of annulus pressure is crucial for safe well operation and wellbore design optimization. It is necessary to conduct research on the maximum allowable annulus pressure and develop a method for predicting it to comprehensively and intuitively manage annulus pressure and prevent damage caused by exceeding the pressure-bearing capacity of the tubing and production casing.

[0029] In view of this, embodiments of this application propose a method for predicting the annular pressure of an oil jacket. Figure 1 This is a cross-sectional view of a well shaft structure proposed in an embodiment of this application, as shown below. Figure 1 As shown, the wellbore structure consists of, from the inside out, tubing, A-annular protective fluid, production casing, B-annular protective fluid, technical casing, C-annular protective fluid, surface casing, and cementing sheath nested in layers. The cementing sheath is located directly below the B-annular protective fluid and the C-annular protective fluid. The packer is located between the tubing and the production casing. Figure 2 This is a top view of the wellbore structure proposed in one embodiment of this application, as shown below. Figure 2 As shown, the tubing is installed inside the production casing, the production casing is installed inside the technical casing, the technical casing is installed inside the surface casing, and the surface casing is installed inside the cementing sheath. Annular fluid A is filled between the tubing and the production casing, annular fluid B is filled between the production casing and the technical casing, and annular fluid C is filled between the technical casing and the surface casing.

[0030] Figure 3 A flowchart of a method for predicting annular pressure in an oil casing according to an embodiment of this application is shown, as follows: Figure 3 As shown, the method includes the following steps: S101. When the tubing is crushed, calculate and record the maximum permissible annulus pressure in annulus A.

[0031] Annular pressure refers to the pressure exerted on the tubing or production casing by the annular protective fluid between the tubing and the production casing, or between the production casing and the technical casing. Specifically, when performing step S101, the maximum annular pressure of annulus A is calculated according to the method described below.

[0032] S102. When the production casing is crushed, calculate and record the maximum permissible annular pressure in annulus A.

[0033] Specifically, when performing step S102, the maximum annular pressure of annulus A is calculated according to the method described below.

[0034] S103. Compare the maximum permissible annular pressure of the A annulus when the tubing is crushed with the maximum permissible annular pressure of the A annulus when the production casing is ruptured to obtain the maximum permissible pressure of the A annulus.

[0035] When the tubing fails, calculate the maximum permissible annular pressure in annulus A; when the production casing fails, calculate the maximum permissible annular pressure in annulus A. By comparing the two pressure values, the smaller value is selected as the maximum permissible annular pressure in annulus A.

[0036] In an alternative implementation, taking into account the corrosion of the tubing, the maximum permissible annulus pressure at the time of tubing failure is calculated using the following formula:

[0037] in, The maximum permissible annular pressure (MPa) in the A annulus during tubing failure, taking into account the effects of tubing corrosion; The remaining resistance to crushing of the tubing, in MPa; Oil pressure, MPa; Density of A-type annular protective fluid, kg / m³ 3 ; The density of the fluid inside the tubing is kg / m. 3 H is the packer vertical depth, in meters; g is the natural acceleration.

[0038] hydraulic The density of the A-ring protective fluid can be measured using a pressure gauge. Fluid density inside the oil pipe Packer vertical depth The natural acceleration g is a known value, and the remaining crush resistance of the tubing is... The pressure is calculated using the formula described below. The maximum annular pressure (A-ring) under tubing corrosion conditions is calculated using the above formula, and the pressure magnitude is recorded. Furthermore, when designing the wellbore, the yield strength of the tubing can be calculated based on the A-ring pressure, allowing for the selection of appropriate tubing materials in the wellbore design.

[0039] In one optional implementation, calculating the remaining crush resistance of the tubing includes: When the oil pipe is subjected to external extrusion force When the oil pipe is subjected to external extrusion stress, the following formula is used to calculate the stress:

[0040] in, The oil pipe is subjected to external extrusion stress, MPa; The initial outer diameter of the tubing is in mm; The initial wall thickness of the tubing is in mm; External extrusion force, MPa; Initial outer diameter of the tubing The initial wall thickness of the oil pipe External extrusion force can be obtained through actual measurement. Given the values, the above formula can be used to calculate the external extrusion stress on the tubing based on different external extrusion forces, and the maximum external extrusion stress that the tubing can withstand can also be calculated based on the yield strength of the tubing.

[0041] After the oil pipe has been used for time t, the wall thickness of the oil pipe is calculated using the following formula:

[0042] in, The wall thickness of the tubing after a service time t, in mm; The corrosion rate of the oil pipe material is expressed in mm / a. The initial wall thickness of the tubing is in mm; Initial wall thickness of the tubing The corrosion rate of the oil pipe material was obtained through actual measurement. This can be obtained through experimental measurement. The above formula is used to calculate the actual wall thickness of the oil pipe during a usage time t. It can also be used to calculate the usable time of the oil pipe based on the wall thickness for safe use.

[0043] The remaining crush resistance of the tubing is calculated using the following formula:

[0044] in, The remaining resistance to crushing of the tubing, in MPa; The oil pipe yield strength is given by MPa. The corrosion rate of the oil pipe material is expressed in mm / a. The wall thickness of the tubing after a service time t, in mm; The initial outer diameter of the tubing is in mm; a represents the usage time of the oil pipeline.

[0045] Oil pipe wall thickness Initial outer diameter of the oil pipe Oil pipe yield strength All values ​​are known; corrosion rate of oil pipe material. The residual extrusion strength of the tubing after a service time t can be calculated using the above formula when the external extrusion stress is greater than or equal to the material's yield strength. This residual extrusion strength is then used to calculate the maximum annular pressure in the B annulus. The calculated residual extrusion strength is used to assess the tubing's load-bearing capacity under annular pressure in corrosive conditions. By calculating the residual extrusion strength, it can be determined whether the tubing can maintain its structural integrity under the influence of formation and wellbore external pressures, thus preventing deformation, compression, or rupture.

[0046] In one alternative implementation, considering the effects of tubing corrosion and temperature, the maximum permissible annular pressure at the time of tubing failure (A annulus) is calculated using the following formula:

[0047] in, The maximum annular pressure (MPa) of annulus A during tubing failure, taking into account the effects of tubing corrosion and temperature. The oil pipe yield strength is given by MPa. The corrosion rate of the oil pipe material is expressed in mm / a. The initial outer diameter of the tubing is in mm; Oil pressure, MPa; Density of A-type annular protective fluid, kg / m³ 3 ; The density of the fluid inside the tubing is kg / m. 3 t represents the oil pipe usage time, a; denoted as initial tubing wall thickness (mm); n is the tubing wall thickness reduction factor due to temperature influence; g is natural acceleration; and H is packer vertical depth (m).

[0048] Considering the combined effects of corrosion and temperature on the tubing, the maximum annular pressure at point A after tubing use (t) can be calculated using the above formula. This helps to more accurately predict the maximum permissible annular pressure.

[0049] In one alternative implementation, taking into account the corrosion of the production casing, the maximum permissible annular pressure A when the production casing ruptures is calculated using the following formula:

[0050] in, To account for the impact of production casing corrosion, the maximum permissible annular pressure (MPa) in annulus A during a production casing rupture is calculated. The remaining internal pressure resistance of the casing is measured in MPa. B is the annular pressure value, MPa; H is the packer vertical depth, m; Density of the annulus fluid in A, kg / m³ 3 ; The density of the annular fluid in region B is kg / m³. 3 g represents natural acceleration.

[0051] Remaining internal pressure resistance of the casing The annular pressure value of B was calculated using the method described below. The packer vertical depth was measured using a pressure gauge. A. Annular fluid density B. Annular fluid density Both the natural acceleration g and g are known values.

[0052] The above formula calculates the maximum annular pressure in annulus A, taking into account the corrosion of the production casing. Furthermore, when designing the wellbore, the yield strength of the tubing can be calculated based on the annular pressure in annulus A, allowing for the selection of appropriate tubing material for the production casing in the wellbore design.

[0053] In one optional implementation, calculating the remaining internal pressure resistance of the production casing includes: When the production casing is subjected to internal pressure The circumferential stress of the production casing is calculated using the following formula:

[0054] in, The circumferential stress of the casing is measured in MPa. Internal pressure, MPa; The initial outer diameter of the casing during production, in mm; The initial wall thickness of the casing during production, in mm; Based on the internal pressure exerted on the production casing, the circumferential stress on the production casing can be calculated using the above formula. Furthermore, based on the maximum circumferential stress that the production casing can withstand, the maximum internal pressure that the production casing can withstand can be calculated.

[0055] When the production sleeve is used After a certain period of time, the circumferential stress of the production sleeve is:

[0056] in, The circumferential stress of the casing is measured in MPa. Internal pressure, MPa; The initial outer diameter of the casing during production, in mm; The initial wall thickness of the casing during production, in mm; The corrosion rate of the production casing is measured in mm / a. a; This refers to the service life of the production sleeve. Based on the initial wall thickness and corrosion rate of the production casing Calculate the wall thickness of the production sleeve after a usage time t1. Then, considering the usage time t1 of the production sleeve according to the above formula, the circumferential stress of the production sleeve is calculated.

[0057] The remaining internal pressure resistance of the production casing is calculated using the following formula:

[0058] in, The remaining internal pressure resistance of the casing during production; MPa; The yield strength required for producing the casing; The initial wall thickness for producing the casing; The corrosion rate of the casing pipe is measured in mm / a. The initial outer diameter of the casing during production, in mm; a represents the usage time of the production sleeve.

[0059] When the circumferential stress of the casing Greater than the yield strength of the casing When the casing fails, the remaining internal pressure resistance of the casing is calculated using the formula above. After corrosion, the yield strength of the production casing decreases; the remaining extrusion resistance is the yield strength after corrosion. The formula above considers the impact of casing corrosion to calculate the remaining extrusion resistance of the production casing. This remaining extrusion resistance can be used to calculate the maximum annular pressure in annulus A, and also to assess whether the yield strength of the production casing meets the operating requirements after a certain period of use. Calculating the remaining internal pressure resistance allows for the assessment of the casing's load-bearing capacity under internal pressure during corrosion, ensuring it can safely withstand pressure from well fluids and preventing safety issues such as leakage, failure, or rupture, thus maintaining the safety of downhole operations.

[0060] In one alternative implementation, considering the effects of corrosion and temperature on the production casing, the maximum annular pressure at annulus A during the rupture of the production casing is calculated using the following formula:

[0061] in, To account for the effects of production casing corrosion and temperature, the maximum permissible annular pressure (MPa) in case of production casing rupture in annulus A; The yield strength of the casing is measured in MPa. The initial outer diameter of the casing during production, in mm; The corrosion rate of the casing pipe is expressed in mm / a. a; This refers to the service life of the production sleeve. Density of the annulus fluid in region A, kg / m³ 3 ; The density of the annular fluid in region B is kg / m³. 3 ; n1 represents the initial wall thickness of the production casing, in mm; n1 is the reduction factor of the production casing wall thickness under the influence of temperature. denoted as B, where the annulus is pressurized (MPa); g is the natural acceleration.

[0062] The formula contains B annular pressure. The reduction factor of the production casing wall thickness under the influence of temperature, obtained by measuring with a pressure gauge, is obtained by the method described below.

[0063] Considering the combined effects of corrosion and temperature on the production casing, the maximum annular pressure at point A after the production casing has been in use for t can be calculated using the above formula. This helps to more accurately predict the maximum permissible annular pressure.

[0064] In one optional implementation, the wall thickness reduction factor n or n1 may take the following values: When the temperature is less than or equal to 120℃, the wall thickness reduction factor n or n1 is 1; When the temperature is greater than 120℃ and less than or equal to 150℃, the wall thickness reduction factor n or n1 is 0.967; When the temperature is greater than 150℃ and less than or equal to 180℃, the wall thickness reduction factor n or n1 is 0.933; When the temperature is greater than 180℃ and less than or equal to 200℃, the wall thickness reduction factor n or n1 is 0.9; When the temperature is greater than 200℃ and less than or equal to 230℃, the wall thickness reduction factor n or n1 is 0.867.

[0065] The value of the wall thickness reduction factor n or n1 depends on the ambient temperature of the tubing or production casing. The higher the temperature, the greater the wall thickness reduction, i.e., the larger the wall thickness reduction factor. The values ​​of the wall thickness reduction factor n or n1 are as follows: when the temperature is less than or equal to 120℃, the wall thickness reduction factor n or n1 is 1; when the temperature is greater than 120℃ and less than or equal to 150℃, the wall thickness reduction factor n or n1 is 0.967; when the temperature is greater than 150℃ and less than or equal to 180℃, the wall thickness reduction factor n or n1 is 0.933; when the temperature is greater than 180℃ and less than or equal to 200℃, the wall thickness reduction factor n or n1 is 0.9; when the temperature is greater than 200℃ and less than or equal to 230℃, the wall thickness reduction factor n is 0.867.

[0066] In an optional implementation, the method further includes: When the tubing is crushed and / or the production casing ruptures, the upward pressure differential of the packer sleeve is calculated using the following formula:

[0067] in, The pressure differential above the packer sleeve, in MPa; The packer sleeve is rated to withstand differential pressure, MPa; The bottom hole flowing pressure is in MPa. Density of the annulus fluid in region A, kg / m³ 3 H is the packer vertical depth, in meters; g is the natural acceleration. The maximum permissible annular pressure of the A annulus when the tubing is crushed, the maximum permissible annular pressure of the A annulus when the production casing is ruptured, and the upward pressure difference of the packer sleeve are compared and analyzed, and the minimum value is selected as the maximum permissible pressure of the A annulus.

[0068] The packer sleeve in the formula is rated to withstand differential pressure. Given a value The bottomhole flowing pressure is measured by instruments. The formula above can be used to calculate the upward pressure differential of the packer sleeve when the tubing is crushed or the production casing ruptures. Comparing this calculated upward pressure differential with the actual upward pressure differential of the packer sleeve indicates that the tubing has been crushed or the production casing has ruptured, and the well is in a dangerous operating condition. Conversely, if the actual upward pressure differential is less than the calculated pressure differential, it indicates that the tubing has been crushed or the production casing has not been damaged, and the well is in a safe operating condition. This formula can be used to indirectly assess whether the well is in a safe operating condition.

[0069] The maximum permissible annular pressure is determined by the minimum of three factors: the maximum permissible annular pressure at point A when the tubing ruptures, the maximum permissible annular pressure at point A when the production casing ruptures, and the upward pressure differential on the packer sleeve (the downward pressure differential borne by the packer sleeve). By applying these formulas, the maximum permissible annular pressure at both the casing and tubing annulus under different influencing factors can be predicted, as well as the packer sleeve pressure differential at the time of tubing or casing rupture, thus enabling an assessment of their safety performance. These formulas, which incorporate the material properties and strength characteristics of the tubing and casing, allow for the early prediction and prevention of potential safety hazards.

[0070] In one optional embodiment, comparing the maximum permissible annular pressure of annulus A when the tubing is crushed with the maximum permissible annular pressure of annulus A when the production casing ruptures to obtain the maximum permissible pressure of annulus A includes: The maximum permissible annular pressure of the A annulus when the tubing is crushed is compared and analyzed with the maximum permissible annular pressure of the A annulus when the production casing is ruptured, and the minimum value is selected as the maximum permissible pressure of the A annulus.

[0071] When the tubing fails, calculate the maximum permissible annular pressure in annulus A; when the production casing fails, calculate the maximum permissible annular pressure in annulus A. By comparing the two pressure values, the smaller value is selected as the maximum permissible annular pressure in annulus A. The effects of factors such as the rated strength of the tubing and casing, packer differential pressure, wellbore temperature, and corrosion are considered to calculate the maximum permissible annular pressure more comprehensively. Generally, the pressure ratings of the tubing head and packer are relatively high, so only the tubing and casing need to be considered, providing a more reliable basis for safe operation and design optimization.

[0072] By using an annulus model based on tubing and production casing, and considering factors such as the rated strength of tubing and casing, packer pressure differential, wellbore temperature, and corrosion, the allowable annulus pressure can be quantitatively calculated by incorporating structural parameters into the annulus pressure calculation formula. This enables the static and dynamic calculation and analysis of annulus pressure in oil and gas wells, providing guidance for the static and dynamic management of annulus pressure in oil and gas wells.

[0073] This application provides a method for predicting annular pressure in oil and gas well production technology. The method includes a wellbore structure consisting of, from the inside out, layers of tubing, production casing, technical casing, surface casing, and cementing sheath. An annular protective fluid A is filled between the tubing and production casing, and an annular protective fluid B is filled between the production casing and technical casing. A packer is located between the tubing and production casing. The method includes: calculating and recording the maximum permissible annular pressure A when the tubing fails; calculating and recording the maximum permissible annular pressure A when the production casing ruptures; comparing the maximum permissible annular pressure A at the time of tubing failure with that at the time of production casing rupture to obtain the maximum permissible pressure of the annulus A. Predicting the maximum annular pressure provides a reliable basis for safe well operation and design, reducing the accident rate.

[0074] Based on the same inventive concept, this application discloses a device for calculating the predictive annular pressure of an oil jacket. Figure 4 A schematic diagram of a device for predicting annular pressure in an oil casing is shown, as follows: Figure 4 As shown, the device includes: First calculation module: used to calculate and record the maximum permissible annulus pressure in annulus A when the tubing is crushed; The second calculation module is used to calculate and record the maximum permissible annulus pressure in annulus A when the production casing ruptures. The judgment module is used to compare the maximum permissible annular pressure of the A annulus when the tubing is crushed with the maximum permissible annular pressure of the A annulus when the production casing is ruptured, and to obtain the maximum permissible pressure of the A annulus.

[0075] The various embodiments in this specification are described in a progressive manner, with each embodiment focusing on the differences from other embodiments. The same or similar parts between the various embodiments can be referred to each other.

[0076] This application describes embodiments with reference to flowchart illustrations and / or block diagrams of methods, apparatuses, electronic devices, and computer program products according to embodiments of this application. It should be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing terminal device to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing terminal device, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0077] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing terminal device to operate in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0078] These computer program instructions can also be loaded onto a computer or other programmable data processing terminal equipment, causing a series of operational steps to be performed on the computer or other programmable terminal equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable terminal equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0079] Although preferred embodiments of the present application have been described, those skilled in the art, upon learning the basic inventive concept, can make other changes and modifications to these embodiments. Therefore, the appended claims are intended to be interpreted as including the preferred embodiments as well as all changes and modifications falling within the scope of the embodiments of the present application.

[0080] Finally, it should be noted that in this document, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or terminal device 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 terminal device. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or terminal device that includes said element.

[0081] The above provides a detailed description of a method for predicting annular pressure in an oil casing provided by this application. Specific examples have been used to illustrate the principles and implementation methods of this application. The descriptions of the above embodiments are only for the purpose of helping to understand the method and its core ideas. At the same time, for those skilled in the art, there will be changes in the specific implementation methods and application scope based on the ideas of this application. Therefore, the content of this specification should not be construed as a limitation of this application.

Claims

1. A method for predicting the annular pressure of an oil casing, characterized in that, The wellbore structure consists of, from the inside out, layers of tubing, production casing, technical casing, surface casing, and cementing sheath nested together. The tubing and production casing are filled with annular protective fluid A; the production casing and technical casing are filled with annular protective fluid B; and the technical casing and surface casing are filled with annular protective fluid C. A packer is located between the tubing and the production casing. The method includes: When the tubing bursts, calculate and record the maximum permissible annular pressure in annulus A; When the production casing ruptures, calculate and record the maximum permissible annular pressure in annulus A; The maximum permissible annular pressure of annulus A when the tubing is crushed is compared with the maximum permissible annular pressure of annulus A when the production casing is ruptured, to obtain the maximum permissible pressure of annulus A.

2. The method for predicting annular pressure of an oil casing according to claim 1, characterized in that, Considering the corrosion of the oil pipe, the maximum permissible annular pressure at point A during oil pipe failure is calculated using the following formula: in, The maximum permissible annular pressure (MPa) in the A annulus during tubing failure, taking into account the effects of tubing corrosion; The remaining resistance to crushing of the tubing, in MPa; Oil pressure, MPa; Density of annular protective fluid A, kg / m³ 3 ; The fluid density inside the tubing is kg / m. 3 H is the packer vertical depth, in meters; g is the natural acceleration.

3. The method for predicting annular pressure according to claim 2, characterized in that, The calculation of the remaining crush resistance of the tubing includes: When the oil pipe is subjected to external extrusion force When the oil pipe is subjected to external extrusion stress, the following formula is used to calculate the stress: in, The oil pipe is subjected to external extrusion stress, MPa; The initial outer diameter of the tubing is in mm; The initial wall thickness of the tubing is in mm; External extrusion force, MPa; After the oil pipe has been used for time t, the wall thickness of the oil pipe is calculated using the following formula: in, The wall thickness of the tubing after a service time t, in mm; The corrosion rate of the oil pipe material is expressed in mm / a. The initial wall thickness of the tubing is in mm; The remaining crush resistance of the tubing is calculated using the following formula: in, The remaining resistance to crushing of the tubing, in MPa; The oil pipe yield strength is given by MPa. The corrosion rate of the oil pipe material is expressed in mm / a. The wall thickness of the tubing after a service time t, in mm; The initial outer diameter of the tubing is in mm; a represents the usage time of the oil pipeline.

4. The method for predicting annular pressure according to claim 1, characterized in that, Considering the effects of tubing corrosion and temperature, the maximum permissible annular pressure at point A during tubing failure is calculated using the following formula: in, The maximum annular pressure (MPa) of annulus A during tubing failure, taking into account the effects of tubing corrosion and temperature. The oil pipe yield strength is given by MPa. The corrosion rate of the oil pipe material is expressed in mm / a. The initial outer diameter of the tubing is in mm; Oil pressure, MPa; Density of annular protective fluid A, kg / m³ 3 ; The fluid density inside the tubing is kg / m. 3 t represents the oil pipe usage time, a; denoted as initial tubing wall thickness (mm); n is the tubing wall thickness reduction factor due to temperature influence; g is natural acceleration; and H is packer vertical depth (m).

5. The method for predicting annular pressure according to claim 1, characterized in that, Considering the corrosion of the production casing, the maximum permissible annular pressure at point A when the production casing ruptures is calculated using the following formula: in, To account for the impact of production casing corrosion, the maximum permissible annular pressure (MPa) in annulus A during a production casing rupture is calculated. The remaining internal pressure resistance of the casing is measured in MPa. B is the annular pressure value, MPa; H is the packer vertical depth, m; Density of the annulus fluid in region A, kg / m³ 3 ; The density of the annular fluid in region B is kg / m³. 3 g represents natural acceleration.

6. The method for predicting annular pressure according to claim 5, characterized in that, The calculation of the remaining internal pressure resistance of the production casing includes: When the production sleeve is subjected to internal pressure The circumferential stress of the production casing is calculated using the following formula: in, The circumferential stress of the casing is measured in MPa. Internal pressure, MPa; The initial outer diameter of the casing during production, in mm; The initial wall thickness of the casing during production, in mm; When the production sleeve is used After a certain period of time, the circumferential stress of the production sleeve is: in, The circumferential stress of the casing is measured in MPa. Internal pressure, MPa; The initial outer diameter of the casing during production, in mm; The initial wall thickness of the casing during production, in mm; The corrosion rate of the production casing is measured in mm / a. a; This refers to the service life of the production sleeve. The remaining internal pressure resistance of the production casing is calculated using the following formula: in, The remaining internal pressure resistance of the casing during production; MPa; The yield strength required for producing the casing; The initial wall thickness for producing the casing; The corrosion rate of the casing material is measured in mm / a. The initial outer diameter of the casing during production, in mm; a represents the usage time of the production sleeve.

7. The method for predicting annular pressure according to claim 1, characterized in that, Considering the effects of corrosion and temperature on the production casing, the maximum annular pressure at point A when the production casing ruptures is calculated using the following formula: in, To account for the effects of production casing corrosion and temperature, the maximum permissible annular pressure (MPa) in case of production casing rupture in annulus A; The yield strength of the casing is measured in MPa. The initial outer diameter of the casing during production, in mm; The corrosion rate of the casing pipe is expressed in mm / a. a; This refers to the service life of the production sleeve. Density of the annulus fluid in region A, kg / m³ 3 ; The density of the annular fluid in region B is kg / m³. 3 ; n1 represents the initial wall thickness of the production casing, in mm; n1 is the reduction factor of the production casing wall thickness under the influence of temperature. denoted as B, where the annulus is pressurized (MPa); g is the natural acceleration.

8. A method for predicting annular pressure according to claim 4 or 7, characterized in that, The values ​​of the wall thickness reduction factor n or n1 include: When the temperature is less than or equal to 120℃, the wall thickness reduction factor n or n1 is 1; When the temperature is greater than 120℃ and less than or equal to 150℃, the wall thickness reduction factor n or n1 is 0.967; When the temperature is greater than 150℃ and less than or equal to 180℃, the wall thickness reduction factor n or n1 is 0.933; When the temperature is greater than 180℃ and less than or equal to 200℃, the wall thickness reduction factor n or n1 is 0.9; When the temperature is greater than 200℃ and less than or equal to 230℃, the wall thickness reduction factor n or n1 is 0.

867.

9. The method for predicting annular pressure according to claim 1, characterized in that, The method further includes: When the tubing is crushed and / or the production casing ruptures, the upward pressure differential of the packer sleeve is calculated using the following formula: in, The pressure differential above the packer sleeve, in MPa; The packer sleeve is rated to withstand differential pressure, MPa; The bottom hole flowing pressure is in MPa. Density of the annulus fluid in region A, kg / m³ 3 H is the packer vertical depth, in meters; g is the natural acceleration. The maximum permissible annular pressure of the A annulus when the tubing is crushed, the maximum permissible annular pressure of the A annulus when the production casing is ruptured, and the upward pressure difference of the packer sleeve are compared and analyzed, and the minimum value is selected as the maximum permissible pressure of the A annulus.

10. The method for predicting annular pressure of an oil casing according to claim 1, characterized in that, The process of comparing the maximum permissible annular pressure of annulus A when the tubing is crushed with the maximum permissible annular pressure of annulus A when the production casing ruptures to obtain the maximum permissible pressure of annulus A includes: The maximum permissible annular pressure of the A annulus when the tubing is crushed is compared and analyzed with the maximum permissible annular pressure of the A annulus when the production casing is ruptured, and the minimum value is selected as the maximum permissible pressure of the A annulus.

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