A method for evaluating the remaining strength of a H2S and CO2 containing horizontal well casing

Abstract

The present disclosure relates to a kind of H2S and CO2 level well casing residual strength evaluation method containing, based on Newton microelement method, for multiple factors such as real borehole trajectory, drilling fluid viscous friction and drilling parameter, analysis model of accurately describing the contact force of drill pipe and casing is established;Based on four-order Runge-Kutta, the analysis model is solved, and the contact force size and distribution of drill pipe and casing at different well depth are obtained;Using energy transfer theory and White-Fleisher wear theory, the thickness reduction of casing after wear is determined;Based on indoor corrosion test data, the thickness reduction caused by casing corrosion is determined;The total thickness reduction caused by casing wear and corrosion is superimposed, and the residual strength of technical casing after wear and corrosion is calculated;The method of the present application has higher precision and applicability for the residual strength evaluation and full life cycle integrity evaluation of large displacement well and horizontal well casing containing acid gas.

Description

Technical Field

[0001] This disclosure relates to the field of oil and gas drilling and production technology, and in particular to a method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2. Background Technology

[0002] Existing methods for calculating the contact force between the drill pipe and casing, which only consider the weight of the drill pipe and the well inclination angle, deviate significantly from the actual contact force. Firstly, the actual wellbore trajectory does not match the designed trajectory, resulting in the drill pipe's weight not being fully transferred to the bottom of the well. Furthermore, a curved wellbore increases friction between the drill pipe and casing, further reducing the transfer of weight and thus affecting the distribution of contact force throughout the wellbore, i.e., the degree of casing wear.

[0003] Current technologies rarely consider the impact of actual wellbore trajectory and drilling fluid properties. They focus on the source of casing wear—the contact friction between the tubing and casing—and conduct mechanical analysis to study casing wear. However, they lack precise descriptions of the wear location and contact forces, resulting in imprecise assessments of the wear amount. Furthermore, casing safety evaluation is a life-cycle process, especially for wells containing acidic gases (CO2, H2S). With prolonged production time, the weakening of casing strength due to corrosion becomes increasingly pronounced, and corrosion following casing wear will accelerate casing failure. Currently, methods for predicting the remaining strength of casing under conditions of simultaneous casing wear and corrosion are unavailable.

[0004] Existing methods for evaluating the remaining strength of casing in oil and gas drilling and production all have shortcomings. The analytical method for the remaining strength of casing worn under non-uniform loads in deep wells (CN202210875654.3) establishes a model of the remaining strength of the casing after wear, performs uncertainty analysis on the remaining strength, and identifies the wear factor. By introducing probability theory, it obtains a confidence interval representation method for the remaining strength of deep well casing after wear under a certain probability. However, this method can only analyze the remaining resistance to external extrusion of the worn casing, without addressing the casing's resistance to internal pressure. Furthermore, it is not applicable to oil and gas wells containing corrosive gases, and corrosion must be considered. A method for evaluating the remaining strength of oil casing with corrosion defects (CN202011124087.5) collects actual parameters of the oil casing, combines Monte Carlo mathematical statistics, and derives a formula for the remaining strength of the oil casing based on conventional evaluation standards, establishing a multivariate evaluation function. However, it does not consider the impact of casing wear. A real-time early warning method for casing wear risk (CN2) 01711348194.4) By calculating the maximum lateral force between the drill pipe joint and the casing, the wear time is determined using the drilling rate equation, and the wear area and depth of the casing are obtained. Then, the remaining internal pressure resistance and remaining extrusion resistance of the casing are calculated, and the remaining internal pressure resistance safety factor and remaining extrusion resistance safety factor of the casing are calculated. Based on the obtained remaining internal pressure resistance safety factor and remaining extrusion resistance safety factor of the casing, the risk level is divided. Finally, the casing wear condition is determined according to the risk level and a real-time early warning is given. This method is suitable for predicting casing wear during drilling, but it cannot evaluate the remaining strength of the casing after drilling and does not involve the impact of acid gas corrosion during production. A method for evaluating casing wear in gas wells with complex wellbore trajectories (CN112196515A) collects and organizes static and dynamic data of gas wells to establish a casing wear equation in three-dimensional space; based on the law of conservation of energy, a casing wear efficiency model is established; using the obtained maximum casing wall thickness reduction and wear efficiency, combined with the casing wear evaluation method standard, a casing wear evaluation method is performed. This method has good accuracy in predicting casing wear, but it cannot predict the strength reduction caused by corrosion of the casing after production. Summary of the Invention

[0005] In view of this, this disclosure proposes a method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2, which solves the problem that the existing technology lacks a method for evaluating the remaining strength of casing in the entire well section of horizontal wells containing H2S and CO2 throughout their entire life cycle.

[0006] To achieve the above-mentioned objective, the method for evaluating the remaining strength of H2S and CO2-containing horizontal well casing includes:

[0007] By establishing a contact force analysis model between the drill pipe and casing during the drilling process, the magnitude and distribution of the contact force between the drill pipe and casing at different well depths are clarified.

[0008] Based on the magnitude and distribution of the contact force, calculate the wall thickness reduction of the casing due to wear after drilling and completion.

[0009] Based on indoor corrosion test data, the corrosion rate at different locations of the casing was obtained by fitting, and the wall thickness reduction of the casing due to corrosion at different well depths was calculated.

[0010] The remaining strength of the sleeve is calculated using the amount of wall thickness reduction caused by corrosion and wear.

[0011] In this disclosure and possible embodiments, the method for establishing a contact force analysis model between the drill pipe and the casing during drilling includes:

[0012] Based on Newton's infinitesimal method, considering the influence of drilling fluid properties, viscous friction, buoyancy, casing size, drill string size, gravity, elastic modulus, and drilling parameters on the contact force between the drill pipe and casing, an analysis model for the contact force between the drill pipe and casing is established.

[0013] In this disclosure and possible embodiments, the contact force analysis model between the drill pipe and the casing is as follows:

[0014]

[0015] In the formula: S is a function of the wellbore trajectory; ds is a differential element of the wellbore trajectory; M b —Inner bending moment of the tubing string, N·m; κ—Wellbore curvature, rad / m; τ—Wellbore deflection, rad / m; N—Contact normal pressure between the tubing string and the wellbore, N; N n —Contact pressure between the tubing string and the wellbore along the main normal direction, N; N b —Contact pressure between the tubing string and the wellbore along the normal direction, N; μ α —Axial friction coefficient; μ t — Tangential friction coefficient; f λ —Viscous resistance of the tubing to fluids inside and outside the tubing, N / m; v—Drilling speed, m / s; τ f — Fluid shear stress, N / m 2 μ—dynamic viscosity of the fluid, Pa·s; R—outer radius of the tubing, m; D w — Wellbore diameter, m; K f —Buoyancy coefficient; —Azimuth rate of change, rad / m; k α — Rate of change of well inclination angle, rad / m; P i P o — Fluid pressure inside and outside the tubing, MPa; A i A o —Internal and external cross-sectional areas of the tubular column, in m² 2 ;ρi ρ o —Fluid density inside and outside the tubing, kg / m³ 3 α is the well inclination angle, °; β is the azimuth angle, °; EI—string stiffness, N / m; q m —Weight per unit length of tubing, N; T —Axial force on the tubing, N.

[0016] In this disclosure and possible embodiments, the method for determining the magnitude and distribution of contact forces between the drill pipe and casing at different well depths includes:

[0017] The model is solved using the fourth-order Runge-Kutta method.

[0018] In this disclosure and possible embodiments, the method for solving the model using the fourth-order Runge-Kutta method includes:

[0019] If the axial load on the tubing string and the contact pressure on the main / secondary normals are functions of the well depth, then the model can be expressed as:

[0020]

[0021] The function value of the initial node position is denoted as

[0022] Taking a step size of h, after n iterations, the solution at the (n+1)th step can be expressed using the fourth-order Runge-Kutta method as follows:

[0023]

[0024] In the formula:

[0025] In the formula, the superscript of all variables indicates the iteration step, the subscript indicates the parameter type, y1 represents the axial force, y2 represents the contact pressure between the tubing sub-normal direction and the well wall, y3 represents the contact pressure between the tubing main normal direction and the well wall, and a, b, c, and d are all intermediate parameters with no real meaning.

[0026] In this disclosure and possible embodiments, the method for calculating the wall thickness reduction of the casing due to wear after drilling and completion operations based on the magnitude and distribution of the contact force includes:

[0027] Using energy transfer theory and White-Fleisher wear theory, a prediction model for the wall thickness reduction caused by wear of drill pipe and casing is established. The prediction model is used to calculate the wall thickness reduction of the casing caused by wear after drilling and completion operations.

[0028] In this disclosure and possible embodiments, the method for establishing a prediction model for wall thickness reduction due to wear of drill pipe and casing, and calculating the wall thickness reduction of the casing due to wear after drilling and completion operations using the prediction model, includes:

[0029] An energy wear formula for the tubing and casing is established using energy transfer theory, where the expression for the work done by friction between the tubing and casing is:

[0030] W = μNL h ;

[0031] In the formula, μ is the coefficient of friction, which is dimensionless; L h The relative sliding distance between the working tubing and casing, in meters; N—the contact normal pressure between the tubing and the wellbore, in kilometres.

[0032] Based on the White-Fleisher wear theory, the relationship between the wear volume of the casing and the energy used is as follows:

[0033] U=V′H b ;

[0034]

[0035] In the formula, V′ is the wear volume of the casing, m 3 H b The Brinell hardness of the casing material, in Pa; η / H b For wear efficiency, 1 / Pa;

[0036] The wear between the working string and the casing is crescent-shaped. A rectangular coordinate system is established with the center of the working string as the origin. The crescent-shaped wear concave surface intersects the inner wall of the casing at two points with horizontal coordinates x1 and x2, respectively. The wear area S... w (m 2 )for:

[0037]

[0038] There are also

[0039]

[0040] Wall thickness reduction Δh due to wear w (mm) is:

[0041]

[0042] In the formula, D is the inner diameter of the casing (mm); d is the outer diameter of the drill pipe (mm).

[0043] In this disclosure and possible embodiments, the method for fitting the corrosion rate at different locations of the casing based on indoor corrosion test data includes:

[0044] The corrosion rate of the bushing under different temperatures and different H2S and CO2 partial pressures is fitted using the following formula:

[0045]

[0046] In the formula, v corr The corrosion rate is expressed in mm / a.

[0047] The partial pressure of hydrogen sulfide is MPa;

[0048] The partial pressure of carbon dioxide is MPa;

[0049] R is the gas constant, specifically 8.314 J / (mol·K);

[0050] T is absolute temperature, in K;

[0051] v0 is the medium velocity, in m·s. -1 ;

[0052] A, B, K, C, E, and M are calculation parameters and are dimensionless.

[0053] In this disclosure and possible embodiments, the method for calculating the wall thickness reduction of the casing due to corrosion at different well depths includes:

[0054] Based on the corrosion rate of the casing at different temperatures and with different H2S and CO2 partial pressures, multiplied by the production time, the distribution curve of the casing wall thickness reduction caused by corrosion as a function of well depth is obtained.

[0055] In this disclosure and possible embodiments, the method for calculating the remaining strength of the sleeve using the wall thickness reduction caused by corrosion and wear includes:

[0056] Based on the ISO10400 standard, the remaining strength of the sleeve after wear and corrosion is calculated by adding the wall thickness reduction caused by corrosion and wear.

[0057] In this disclosure and possible embodiments, the method for calculating the residual strength of the casing after wear and corrosion includes:

[0058] According to the ISO 10400 standard, the residual extrusion strength σ of a casing with defects is recommended. o for:

[0059]

[0060] In the formula, σ1 and σ2 are the elastic crushing strength and elasto-plastic crushing strength of the ideal circular pipe, respectively, in MPa; D is the outer diameter of the casing, in m; σ Rσ is the residual stress in the casing, MPa; S λ is the minimum yield strength of the casing, MPa; λ is the comprehensive image coefficient of the casing defect, dimensionless; B and C are empirical constants in the API casing crush strength calculation formula; e and ε are the out-of-roundness and non-uniformity of the casing inner wall, dimensionless; t is the nominal wall thickness of the casing, mm.

[0061] Wherein, the out-of-roundness e and the non-uniformity ε are expressed as:

[0062]

[0063] in,

[0064] h a =Δh w +v corr T c ;

[0065] In the formula, T c v represents the time in years for the casing to be run into the wellbore; corr T c This represents the wall thickness reduction caused by corrosion, in mm;

[0066] The remaining resistance to external extrusion after wear and corrosion of the casing is expressed as follows:

[0067]

[0068] in,

[0069]

[0070] In the formula, σ θ，ω p represents the circumferential stress on the remaining wall surface of the worn casing. i p o R represents the internal and external pressures borne by the casing, in MPa; i R o Let be the inner and outer radii of the non-destructive sleeve, respectively, in meters (m).

[0071] make

[0072]

[0073] Then, the remaining internal pressure resistance p after casing wear and corrosion. bi for:

[0074]

[0075] The beneficial effects of this invention are:

[0076] This application's method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2 firstly establishes an analytical model based on Newton's infinitesimal method, considering the influence of multiple factors such as the actual wellbore trajectory, drilling fluid viscous friction, and drilling parameters, to accurately describe the contact force between the drill pipe and casing. Then, based on the fourth-order Runge-Kutta method, the analytical model is solved to obtain the contact force distribution between the drill pipe and casing at different well depths. Furthermore, using energy transfer theory and White-Fleisher wear theory, a method for predicting the wall thickness reduction of the drill pipe and casing is established. Subsequently, based on indoor corrosion experimental data, the corrosion rate of the casing at different well depths is fitted to further determine the wall thickness reduction caused by corrosion at different well depths. Finally, based on the ISO 10400 standard, the total wall thickness reduction caused by casing wear and corrosion is superimposed to establish a method for calculating the remaining strength of the casing after wear and corrosion. This invention's method has higher accuracy and applicability for evaluating the remaining strength and life-cycle integrity of casing in extended reach wells and horizontal wells containing acidic gases. Attached Figure Description

[0077] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with this disclosure and, together with the specification, serve to illustrate the technical solutions of this disclosure.

[0078] Figure 1 This is a schematic diagram of the force on a micro-element segment of the tubular column according to an embodiment of this disclosure;

[0079] Figure 2 This is a schematic diagram of the calculation process for the method of evaluating the remaining strength of horizontal well casing containing H2S and CO2 according to an embodiment of this disclosure;

[0080] Figure 3 This is a schematic diagram of sleeve wear in an embodiment of this disclosure;

[0081] Figure 4 This is an example of the average contact force distribution between the four-section drilling casing and the drill pipe in this disclosure embodiment;

[0082] Figure 5 The amount of wall thickness reduction of the three-sleeve sleeve due to wear in this embodiment of the disclosure;

[0083] Figure 6 The corrosion rate of the third casing of the Tongshen X well in this embodiment of the present disclosure;

[0084] Figure 7 The amount of wall thickness reduction of the three-sleeve sleeve caused by corrosion in the embodiments of this disclosure;

[0085] Figure 8 This refers to the remaining external extrusion resistance of the three-slit sleeve in this embodiment of the present disclosure;

[0086] Figure 9The remaining internal pressure resistance of the three-slit bushing in this embodiment of the present disclosure is given. Detailed Implementation

[0087] Various exemplary embodiments, features, and aspects of this disclosure will now be described in detail with reference to the accompanying drawings. The same reference numerals in the drawings denote elements that have the same or similar functions. Although various aspects of the embodiments are shown in the drawings, they are not necessarily drawn to scale unless specifically indicated otherwise.

[0088] To address the problems in the background technology, this application provides a method for evaluating the remaining strength of horizontal well casing containing H2S and CO2. The overall inventive concept is as follows:

[0089] First, a mechanical analysis model of the tubing string during the 3D wellbore lowering process is established to clarify the contact force between the tubing string (drill string, tubing, etc.) and the casing. Then, the remaining wall thickness of the casing after drilling and completion is analyzed using a wear efficiency model. Finally, by combining formation acid gas partial pressure data with laboratory experimental data, corrosion rates at different depths are fitted, and the reduction in wall thickness and wear caused by superimposed corrosion are used to comprehensively evaluate the remaining strength of the casing after wear and corrosion.

[0090] Based on the above inventive concept, this application provides the following technical solution:

[0091] First, based on Newton's infinitesimal method, an analytical model accurately describing the contact force between the drill pipe and casing is established, taking into account the influence of multiple factors such as the actual wellbore trajectory, the viscous friction of the drilling fluid, and drilling parameters. Then, the analytical model is solved using the fourth-order Runge-Kutta method to obtain the contact force distribution between the drill pipe and casing at different well depths. Furthermore, an energy transfer theory and White-Fleisher wear theory are used to establish a method for predicting the wall thickness reduction of the drill pipe and casing. Subsequently, based on indoor corrosion experimental data, the corrosion rate of the casing at different well depths is fitted to further determine the wall thickness reduction caused by corrosion at different well depths. Finally, based on the ISO 10400 standard, the total wall thickness reduction caused by casing wear and corrosion is superimposed to establish a method for calculating the remaining strength of the casing after wear and corrosion.

[0092] The following are preferred embodiments provided by this disclosure based on the above technical solutions.

[0093] Figure 2 This is a schematic diagram of the calculation process for the evaluation method of residual strength of horizontal well casing containing H2S and CO2 according to an embodiment of this disclosure, combined with... Figure 2 As shown, the method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2 includes the following steps:

[0094] Step one: First, establish a contact force analysis model between the drill pipe and the casing during drilling to accurately analyze the location and magnitude of the contact force between the drill pipe and the casing, as detailed below:

[0095] This model, based on the infinitesimal element method, considers the influence of multiple factors on the contact force between the drill pipe and casing, including the actual wellbore trajectory, drilling fluid properties, viscous friction of the drilling fluid, buoyancy, casing size, drill string size, gravity, elastic modulus, and drilling parameters. It establishes a mechanical analysis model of the drill string within a three-dimensional curved wellbore. Figure 1 As shown, Figure 1 In coordinate system O s In TNB, take a small element segment AB of length ds, denoted by s at point A and s+ds at point B, and establish a force analysis model for the drill string element.

[0096] The contact force analysis model between the drill pipe and the casing during drilling can be expressed as:

[0097]

[0098] In the formula: S is a function of the wellbore trajectory; ds is a differential element of the wellbore trajectory; M b —Inner bending moment of the tubing string, N·m; κ—Wellbore curvature, rad / m; τ—Wellbore deflection, rad / m; N—Contact normal pressure between the tubing string and the wellbore, N; N n —Contact pressure between the tubing string and the wellbore along the main normal direction, N; N b —Contact pressure between the tubing string and the wellbore along the normal direction, N; μ α —Axial friction coefficient; μ t — Tangential friction coefficient; f λ —Viscous resistance of the tubing to fluids inside and outside the tubing, N / m; v—Drilling speed, m / s; τ f — Fluid shear stress, N / m 2 μ—dynamic viscosity of the fluid, Pa·s; R—outer radius of the tubing, m; D w — Wellbore diameter, m; K f —Buoyancy coefficient; — Rate of change of azimuth angle, rad / m; k α — Rate of change of well inclination angle, rad / m; P i P o — Fluid pressure inside and outside the tubing, MPa; A i A o —Internal and external cross-sectional areas of the tubular column, in m² 2 ;ρ i ρ o —Fluid density inside and outside the tubing, kg / m³ 3 α is the well inclination angle, °; β is the azimuth angle, °; EI—string stiffness, N / m; q m—Weight per unit length of tubing, N; T —Axial force on the tubing, N.

[0099] Step 2: Based on the contact force analysis model between the drill pipe and casing established in Step 1, solve the model. The specific solution process is as follows:

[0100] Since the contact force analysis model between the tubing and the casing is quite complex and cannot be solved analytically, the fourth-order Runge-Kutta method is used to solve the model.

[0101] If the axial load on the tubing string and the contact pressure on the main / secondary normals are functions of the well depth, then the model can be expressed as:

[0102]

[0103] The function value of the initial node position is denoted as

[0104] Taking a step size of h, after n iterations, the solution at the (n+1)th step can be expressed using the fourth-order Runge-Kutta method as follows:

[0105]

[0106] In the formula:

[0107] In the formula, the superscript of all variables indicates the iteration step, the subscript indicates the parameter type, y1 represents the axial force, y2 represents the contact pressure between the tubing sub-normal direction and the well wall, y3 represents the contact pressure between the tubing main normal direction and the well wall, and a, b, c, and d are all intermediate parameters with no real meaning.

[0108] Step 3: Based on the magnitude and distribution of the contact force between the drill pipe and the casing obtained in Step 2, calculate the wall thickness reduction after casing wear. The specific calculation method is as follows:

[0109] An energy wear formula for the tubing and casing is established using energy transfer theory, where the expression for the work done by friction between the tubing and casing is:

[0110] W = μNL h ;

[0111] In the formula, μ is the coefficient of friction, which is dimensionless; L h The relative sliding distance between the working tubing and casing, in meters; N—the contact normal pressure between the tubing and the wellbore, in kilometres.

[0112] Based on the White-Fleisher wear theory, the relationship between the wear volume of the casing and the energy used is as follows:

[0113] U=V′H b ;

[0114]

[0115] In the formula, V′ is the wear volume of the casing, m 3 H b The Brinell hardness of the casing material, in Pa; η / H b For wear efficiency, 1 / Pa.

[0116] The wear between the working string and the casing is crescent-shaped, with the center of the working string as the origin. Figure 3 As shown, a rectangular coordinate system is established. The crescent-shaped wear concave surface intersects the inner wall of the sleeve at two points with horizontal coordinates x1 and x2, respectively. The wear area S can be obtained. w (m 2 )for:

[0117]

[0118] There are also

[0119]

[0120] Wall thickness reduction Δh due to wear w (mm) is:

[0121]

[0122] In the formula, D is the inner diameter of the casing (mm); d is the outer diameter of the drill pipe (mm).

[0123] This allows us to determine the amount of wall thickness reduction in the casing after drilling is complete.

[0124] Step 4: Predict the corrosion rate at different locations on the casing. The specific prediction method is as follows:

[0125] The corrosion rate of the casing under different temperatures and different H2S and CO2 partial pressures can be obtained by fitting the following formula:

[0126]

[0127] In the formula, v corr The corrosion rate is expressed in mm / a.

[0128] The partial pressure of hydrogen sulfide is MPa;

[0129] The partial pressure of carbon dioxide is MPa;

[0130] R is the gas constant, specifically 8.314 J / (mol·K);

[0131] T is absolute temperature, in K;

[0132] v0 is the medium velocity, in m·s. -1 ;

[0133] A, B, K, C, E, and M are calculation parameters and are dimensionless.

[0134] Step 5: Based on the corrosion rate at different locations on the casing obtained from the fitting in Step 4, calculate the uniform thinning of the wall thickness caused by corrosion. The specific calculation method is as follows:

[0135] Based on the corrosion rate of the casing obtained from step four under different temperatures and different H2S and CO2 partial pressures, and then multiplied by the production time, the distribution curve of casing wall thickness reduction caused by corrosion with well depth can be obtained.

[0136] Step Six: Based on the wall thickness reduction caused by sleeve wear and the uniform wall thickness reduction caused by corrosion obtained in Steps Three and Five, calculate the remaining strength of the sleeve. The specific calculation method is as follows:

[0137] Due to machining precision limitations, the casing cannot be a perfect circle; it will inevitably contain out-of-roundness and residual stress. According to the ISO 10400 standard, the residual extrusion strength σ of a defective casing should be... o for:

[0138]

[0139] In the formula, σ1 and σ2 are the elastic crushing strength and elasto-plastic crushing strength of the ideal circular pipe, respectively, in MPa; D is the outer diameter of the casing, in m; σ R σ is the residual stress in the casing, MPa; S λ is the minimum yield strength of the casing, MPa; λ is the comprehensive image coefficient of the casing defect, dimensionless; B and C are the empirical constants in the API casing crush strength calculation formula (see SY / T5322-2008); e and ε are the out-of-roundness and non-uniformity of the casing inner wall, dimensionless; t is the nominal wall thickness of the casing, mm.

[0140] Since the wear of the casing is crescent-shaped, the worn casing can be simplified as a defective casing with both non-circular and non-uniform inner walls. Considering the reduction in casing wall thickness due to uniform corrosion, the non-circularity e and non-uniformity ε of the casing after wear and corrosion are expressed as:

[0141]

[0142] in,

[0143] h a =Δh w +v corr T c ;

[0144] In the formula, Tc v represents the time in years for the casing to be run into the wellbore; corr T c This represents the wall thickness reduction caused by corrosion, in mm.

[0145] The remaining resistance to external extrusion after wear and corrosion of the casing is expressed as follows:

[0146]

[0147] in,

[0148]

[0149] In the formula, σ θ，ω p represents the circumferential stress on the remaining wall surface of the worn casing. i p o R represents the internal and external pressures borne by the casing, in MPa; i R o , respectively, are the inner and outer radii of the non-destructive sleeve, in meters (m).

[0150] make

[0151]

[0152] Then, the remaining internal pressure resistance p after casing wear and corrosion. bi for:

[0153]

[0154] The following are specific application examples of the method provided in this application.

[0155] Application examples

[0156] Taking the Tongshen X well as an example, the remaining strength evaluation of the casing is carried out according to the method disclosed in this paper. The specific process is as follows:

[0157] Step 1: Basic Data Preparation

[0158] Prepare basic data such as wellbore trajectory, drill string parameters, drilling parameters, mud parameters, drilling time, production start time, and acid gas content (H2S, CO2).

[0159] Tongshen X Well is a gas well in the Sichuan-Chongqing region containing H2S and CO2, with an H2S content of 0.89% and a CO2 content of 2.11%. Drilling began on April 5, 2022, and was completed on September 15 of the same year, employing a four-section wellbore structure. The third section features a casing with an outer diameter of 177.8 mm, a wall thickness of 12.65 mm, and is made of BG110ss material. The casing reached a depth of 4298 m, and the wear efficiency of this type of casing was 1.365 × 10⁻⁶. -14 m 2 / N. The fourth drilling operation reached a depth of 4424m, with an effective drilling time of 20 days, a drilling rate of 80r / min, and a drilling pressure of 70kN.

[0160] The drilling tooling structure for the fourth section of this well is as follows: Φ149.2mm drill bit + Φ120.0mm single-bend screw + drill string float valve + Φ120.0mm MWD + Φ145mm stabilizer × 2m + Φ120.0mm directional joint + Φ88.9mm non-magnetic drill collar × (8.5~9.0)m + Φ88.9mm auger drill collar × (17~18)m + Φ120mm bypass valve + Φ88.9mm inclined weighted drill pipe × 288m + Φ121.0mm drilling shock absorber + Φ88.9mm inclined weighted drill pipe × 57.6m + Φ88.9mm drill pipe × 2400m + Φ101.6mm drill pipe. The drill pipe density is 7850kg / m³. 3 Elastic modulus 2.3×10 11 Pa.

[0161] The drilling fluid parameters used in the fourth drilling phase of this well are shown in Table 1:

[0162] Table 1. Performance of drilling fluids used in the fourth drilling phase of Tongshen X well.

[0163]

[0164] The measured wellbore trajectory after drilling is shown in Table 2.

[0165] Table 2. Measured wellbore trajectory data of Tongshen X Well

[0166]

[0167]

[0168]

[0169] Step 2: Solve the model to obtain the contact force distribution curve between the drill pipe and the casing, such as... Figure 4 As shown.

[0170] Step 3: Calculate the wall thickness reduction of the sleeve due to wear, such as... Figure 5 As shown.

[0171] Step 4: Fit the corrosion rate of the casing under different H2S and CO2 partial pressures.

[0172] Based on indoor experiments, under the conditions of acidic gas content in the Tongshen X well formation, the corrosion rate of BG110SS casing at different temperatures and pressures is shown in Table 3:

[0173] Table 3 Corrosion rates at different depths in Well X, Tongnan

[0174]

[0175] The corrosion rate of the three-section casing at different depths in the well, obtained from fitting, can be expressed by the following formula:

[0176]

[0177] The corrosion rate of the casing in the Tongshen X well obtained by fitting is as follows: Figure 6 As shown.

[0178] Step 5: Based on the corrosion rate fitted in Step 3, the wall thickness reduction caused by corrosion in Tongshen X well over the past 1.5 years (from completion to present) is as follows: Figure 7 As shown.

[0179] Step Six: Combine the wall thickness reduction caused by sleeve wear and the uniform wall thickness reduction caused by corrosion obtained in Steps Three and Five to calculate the remaining strength of the sleeve.

[0180] The remaining external extrusion resistance and internal pressure resistance of the casing are respectively determined by Figure 8 and Figure 9 As shown.

[0181] It is understood that the various method embodiments mentioned above in this disclosure can be combined with each other to form combined embodiments without violating the principle and logic. Due to space limitations, this disclosure will not elaborate further.

[0182] The various embodiments of this disclosure have been described above. These descriptions are exemplary and not exhaustive, and are not limited to the disclosed embodiments. Many modifications and variations will be apparent to those skilled in the art without departing from the scope and spirit of the described embodiments. The terminology used herein is chosen to best explain the principles, practical applications, or technical improvements to the technology in the market, or to enable others skilled in the art to understand the embodiments disclosed herein.

Claims

1. A method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2, characterized in that, include: By establishing a contact force analysis model between the drill pipe and casing during the drilling process, the magnitude and distribution of the contact force between the drill pipe and casing at different well depths are clarified. Based on the magnitude and distribution of the contact force, calculate the wall thickness reduction of the casing due to wear after drilling and completion. Based on indoor corrosion test data, the corrosion rate at different locations of the casing was obtained by fitting, and the wall thickness reduction of the casing due to corrosion at different well depths was calculated. The remaining strength of the sleeve is calculated using the amount of wall thickness reduction caused by corrosion and wear.

2. The method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2 according to claim 1, characterized in that, The method for establishing a contact force analysis model between the drill pipe and casing during drilling includes: Based on Newton's infinitesimal method, considering the influence of drilling fluid properties, viscous friction, buoyancy, casing size, drill string size, gravity, elastic modulus, and drilling parameters on the contact force between the drill pipe and casing, an analysis model for the contact force between the drill pipe and casing is established.

3. The method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2 according to claim 2, characterized in that, The contact force analysis model between the drill pipe and the casing is as follows: In the formula: S is a function of the wellbore trajectory; ds is a differential element of the wellbore trajectory; M b —Inner bending moment of the tubing string, N·m; κ—Wellbore curvature, rad / m; τ—Wellbore deflection, rad / m; N—Contact normal pressure between the tubing string and the wellbore, N; N n —Contact pressure between the tubing string and the wellbore along the main normal direction, N; N b —Contact pressure between the tubing string and the wellbore along the normal direction, N; μ α —Axial friction coefficient; μ t — Tangential friction coefficient; f λ —Viscous resistance of the tubing to fluids inside and outside the tubing, N / m; v—Drilling speed, m / s; τ f — Fluid shear stress, N / m 2 μ—dynamic viscosity of the fluid, Pa·s; R—outer radius of the tubing, m; D w — Wellbore diameter, m; K f —Buoyancy coefficient; — Rate of change of azimuth angle, rad / m; k α — Rate of change of well inclination angle, rad / m; P i P o — Fluid pressure inside and outside the tubing, MPa; A i A o —Internal and external cross-sectional areas of the tubular column, in m² 2 ; ρ i ρ o —Fluid density inside and outside the tubing, kg / m³ 3 α is the well inclination angle, °; β is the azimuth angle, °; EI—string stiffness, N / m; q m —Weight per unit length of tubing, N; T —Axial force on the tubing, N.

4. The method for evaluating the remaining strength of H2S and CO2-containing horizontal well casing according to claim 4, characterized in that, The method for determining the magnitude and distribution of contact forces between the drill pipe and casing at different well depths includes: The model is solved using the fourth-order Runge-Kutta method.

5. The method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2 according to claim 4, characterized in that, The method for solving the model using the fourth-order Runge-Kutta method includes: If the axial load on the tubing string and the contact pressure on the main / secondary normals are functions of the well depth, then the model can be expressed as: The function value of the initial node position is denoted as Taking a step size of h, after n iterations, the solution at the (n+1)th step can be expressed using the fourth-order Runge-Kutta method as follows: In the formula: In the formula, the superscript of all variables indicates the iteration step, the subscript indicates the parameter type, y1 represents the axial force, y2 represents the contact pressure between the tubing sub-normal direction and the well wall, y3 represents the contact pressure between the tubing main normal direction and the well wall, and a, b, c, and d are all intermediate parameters with no real meaning.

6. The method for evaluating the remaining strength of H2S and CO2-containing horizontal well casing according to any one of claims 1-5, characterized in that, The method for calculating the wall thickness reduction of the casing due to wear after drilling and completion operations based on the magnitude and distribution of the contact force includes: Using energy transfer theory and White-Fleisher wear theory, a prediction model for the wall thickness reduction caused by wear of drill pipe and casing is established. The prediction model is used to calculate the wall thickness reduction of the casing caused by wear after drilling and completion operations.

7. The method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2 according to claim 6, characterized in that, The method for establishing a prediction model for wall thickness reduction due to wear between drill pipe and casing, and for calculating the wall thickness reduction of the casing due to wear after drilling and completion operations using the prediction model, includes: An energy wear formula for the tubing and casing is established using energy transfer theory, where the expression for the work done by friction between the tubing and casing is: W=μNL h ; In the formula, μ is the coefficient of friction, which is dimensionless; L h The relative sliding distance between the working tubing and casing, in meters; N—the contact normal pressure between the tubing and the wellbore, in kilometres. Based on the White-Fleisher wear theory, the relationship between the wear volume of the casing and the energy used is as follows: U=V′H b ; In the formula, V′ is the wear volume of the casing, m 3 H b The Brinell hardness of the casing material, in Pa; η / H b For wear efficiency, 1 / Pa; The wear between the working string and the casing is crescent-shaped. A rectangular coordinate system is established with the center of the working string as the origin. The crescent-shaped wear concave surface intersects the inner wall of the casing at two points with horizontal coordinates x1 and x2, respectively. The wear area S... w (m 2 )for: There are also Wall thickness reduction Δh due to wear w (mm) is: In the formula, D is the inner diameter of the casing (mm); d is the outer diameter of the drill pipe (mm).

8. The method for evaluating the residual strength of H2S and CO2-containing horizontal well casing according to any one of claims 1-5 or 7, characterized in that, The method for fitting the corrosion rate at different locations of the casing based on indoor corrosion test data includes: The corrosion rate of the bushing under different temperatures and different H2S and CO2 partial pressures is fitted using the following formula: In the formula, v corr The corrosion rate is expressed in mm / a. The partial pressure of hydrogen sulfide is MPa; The partial pressure of carbon dioxide is MPa; R is the gas constant, specifically 8.314 J / (mol·K); T is absolute temperature, in K; v0 is the medium velocity, in m·s. -1 ; A, B, K, C, E, and M are calculation parameters and are dimensionless.

9. The method for evaluating the remaining strength of casing in horizontal wells containing H2S and CO2 according to claim 8, characterized in that, The method for calculating the casing wall thickness reduction due to corrosion at different well depths includes: Based on the corrosion rate of the casing at different temperatures and with different H2S and CO2 partial pressures, multiplied by the production time, the distribution curve of the casing wall thickness reduction caused by corrosion as a function of well depth is obtained.

10. The method for evaluating the residual strength of H2S and CO2-containing horizontal well casing according to any one of claims 1-5, 7, or 9, characterized in that, The method for calculating the remaining strength of the sleeve by utilizing the wall thickness reduction caused by corrosion and wear includes: Based on the ISO10400 standard, the remaining strength of the sleeve after wear and corrosion is calculated by adding the wall thickness reduction caused by corrosion and wear.

11. The method for evaluating the remaining strength of H2S and CO2-containing horizontal well casing according to claim 10, characterized in that, The method for calculating the remaining strength of the casing after wear and corrosion includes: According to the ISO 10400 standard, the residual extrusion strength σ of a casing with defects is recommended. o for: In the formula, σ1 and σ2 are the elastic crushing strength and elasto-plastic crushing strength of the ideal circular pipe, respectively, in MPa; D is the outer diameter of the casing, in m; σ R σ is the residual stress in the casing, MPa; S λ is the minimum yield strength of the casing, MPa; λ is the comprehensive image coefficient of the casing defect, dimensionless; B and C are empirical constants in the API casing crush strength calculation formula; e and ε are the out-of-roundness and non-uniformity of the casing inner wall, dimensionless; t is the nominal wall thickness of the casing, mm. Wherein, the out-of-roundness e and the non-uniformity ε are expressed as: in, h a =Δh w +v corr T c ; In the formula, T c v represents the time in years for the casing to be lowered into the wellbore; corr T c This represents the wall thickness reduction caused by corrosion, in mm; The remaining resistance to external extrusion after wear and corrosion of the casing is expressed as follows: in, In the formula, σ θ，ω p represents the circumferential stress on the remaining wall surface of the worn casing. i p o R represents the internal and external pressures borne by the casing, in MPa; i R o Let be the inner and outer radii of the non-destructive sleeve, respectively, in meters (m). make Then, the remaining internal pressure resistance p after casing wear and corrosion. bi for:

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