Wellbore structure design method based on wellbore ECD calculation

Abstract

The invention relates to the technical field of petroleum engineering, in particular to a wellbore structure design method based on wellbore ECD calculation, and the method comprises the steps: drawing a full-well-section pressure profile curve based on well pressure prediction data, and then calculating to obtain first chart data; sequentially calculating construction parameters based on the first chart data, and sequentially calculating the setting depth of each layer of casing pipe according to the construction parameters; according to the method, the dynamic drilling fluid equivalent density of different well depths in the current open hole well section is accurately calculated through the drilling fluid density, the rheological parameters, the drilling construction parameters and the like, and the accurate well bore structure design of the narrow-density window well is realized by taking the well bore drilling fluid equivalent density in the dynamic construction process as a reference judgment condition; the problem that a series of well control safety accidents such as well leakage, overflow and blowout are caused due to the fact that the actual equivalent density is higher than the fracturing pressure equivalent density and the leakage pressure equivalent density of a safe stratum in a current open hole well section by taking the static drilling fluid equivalent density as a judgment condition is avoided.

Description

Technical Field

[0001] The invention relates to the technical field of petroleum engineering, and in particular to a wellbore structure design method based on wellbore ECD calculation. Background Art

[0002] Wellbore structure design is the basic design of drilling engineering, which refers to the basic spatial form of oil and gas wells after the implementation of drilling engineering. Its main task is to determine the casing's lowering level, lowering depth, cement slurry return depth, cement ring thickness, production casing size and drill bit size. At present, existing design methods and patents use static drilling fluid density and safety factor, accident complexity law, must-seal layer and other factors to compare with the three-pressure prediction profile of the formation to complete the wellbore structure design, corresponding to the problems of not being able to cover the actual working conditions on site, high well control safety risks, and excessive design that increases drilling costs. This innovative achievement intends to select the maximum drilling fluid equivalent density under actual working conditions, and establish a corresponding relationship with the four-pressure prediction profile of the formation, so as to achieve the purpose of avoiding accident complexity and reducing well control safety risks. Summary of the invention

[0003] The purpose of the present invention is to provide a wellbore structure design method based on wellbore ECD calculation to improve the above technical problems.

[0004] In order to achieve the above objectives, the present application provides the following technical solutions:

[0005] On the one hand, an embodiment of the present application provides a wellbore structure design method based on wellbore ECD calculation, which is applied to electronic equipment. The method includes: drawing a full-well section pressure profile curve based on the pressure prediction data of the well, and calculating the safe formation fracture pressure equivalent density according to the preset single-well geological fracture pressure prediction data, and adding a safe formation fracture pressure equivalent density change curve to the full-well section pressure profile curve based on the safe formation fracture pressure equivalent density, and marking the added full-well section pressure profile curve as the first plate data; based on the first plate data, the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the pressure differential drilling constraint condition parameters are calculated in sequence; based on the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the pressure differential drilling constraint condition parameters, the depth of each layer of casing is calculated in sequence.

[0006] In some embodiments, the step of drawing a full-well pressure profile curve based on the pressure prediction data of the well includes:

[0007] The geological vertical depth data and pressure prediction data in the single well geological data are obtained, and the pore pressure equivalent density change curve, the collapse pressure equivalent density change curve, the leakage pressure equivalent density change curve and the fracture pressure equivalent density change curve with the vertical depth are respectively plotted, so as to obtain the full-well section pressure profile curve, wherein the ordinate of the full-well section pressure profile curve is the well depth data, the minimum value is the ground reference plane, the maximum value is the maximum designed vertical depth, and the abscissa is the predicted pressure equivalent density, the minimum value is the minimum value of the four pressure equivalent densities, and the maximum value is the maximum value of the four pressure equivalent densities.

[0008] In some embodiments, calculating the dynamic wellbore drilling fluid equivalent density based on the first plate data includes:

[0009] The static equivalent density of the drilling fluid and the circulating pressure loss equivalent density of the drilling fluid are calculated based on the drilling data and the first plate data, respectively, and the dynamic wellbore drilling fluid equivalent density is calculated by summing the static equivalent density of the drilling fluid and the circulating pressure loss equivalent density of the drilling fluid.

[0010] In some embodiments, calculating the static equivalent density of the drilling fluid based on the first plate data includes:

[0011] The static equivalent density of the drilling fluid is calculated based on the first calculation formula, where the first calculation formula is:

[0012]

[0013] In the formula, ρ ESD is the static equivalent density of drilling fluid, K is the viscosity coefficient of drilling fluid, Pa·s n ; h is the well depth, m; F is the drilling fluid temperature at the current well depth, ℉; a is the coefficient, a function of the drilling fluid fluidity index n.

[0014] In some embodiments, calculating the drilling fluid circulation pressure loss equivalent density based on the first plate data includes:

[0015]

[0016]

[0017] p c =p p +p a ;

[0018]

[0019] Note:

[0020] G 2 =3nb-4b+5; G 3 =nb-2b+2;

[0021] k 1 =2b-nb-2; k 2 =5bn-7b+5;

[0022] k 4 =ρ b-1 ;

[0023] k 6 =nb-2b+2;

[0024]

[0025] Where: p p is the circulating pressure loss in the drill string, Pa; p a is the annular circulation pressure loss, Pa; p c is the total pressure loss of drilling fluid circulation, Pa; ρ AECD G is the equivalent density of drilling fluid circulation pressure loss; 0 , G 1 , G 2 , G 3 , B 0 , k 1 , k 2 , k 3 , k 4 , k 5 , k 6 are substitution coefficients; K is the drilling fluid viscosity coefficient, Pa·s n ; n is the drilling fluid flow index; a, b are coefficients, functions of the drilling fluid flow index n; Q is the drilling fluid displacement, m 3 / s; N 1 is the number of laminar flow segments in the drill string, N 2 is the number of turbulent flow segments; L is the length of the laminar flow segment or turbulent flow segment, m, L i is the length of the laminar flow section or turbulent flow section in the drill string, L j is the length of the laminar flow section or turbulent flow section in the annulus; d is the inner diameter of the drill string, in m, d i is the inner diameter of the laminar flow section or turbulent flow section in the i-th drill string; A is the annular cross-sectional area, m 2 , A i is the annular cross-sectional area corresponding to the laminar flow section or turbulent flow section in the i-th drill string, A j is the cross-sectional area of ​​the annulus corresponding to the laminar flow section or turbulent flow section in the jth annulus; M 1 is the number of laminar flow segments in the annulus, M 2 is the number of turbulent flow segments; d 1 is the borehole diameter, in m, d 1jis the borehole diameter corresponding to the laminar flow section or turbulent flow section in the jth annulus; d 2 is the outer diameter of the drill string, in m, d 2j is the outer diameter of the drill string corresponding to the laminar flow section or turbulent flow section in the jth annulus; d b is the drill bit diameter, m; R is the mechanical drilling speed, m / h; ρ s is the density of drill cuttings, g / cm 3 ρ mmax is the maximum drilling fluid density in the well section; g is the gravity acceleration; k′ is the velocity correction coefficient; v s is the cuttings sliding velocity, m / s; h is the well depth, m.

[0026] In some embodiments, calculating the equivalent density of the overflow shut-in drilling fluid based on the first plate data includes:

[0027] The overflow shut-in drilling fluid equivalent density is calculated based on a third calculation formula, wherein the third calculation formula is:

[0028]

[0029] Where: D m D is the top well depth corresponding to the maximum formation pore pressure equivalent density in the open hole section, m; x is the depth of the calculation point in the open hole section, m; S k It is the overflow allowable value, generally ranging from 0.05-0.10g / cm 3， ρ mmax is the maximum drilling fluid density in the well section; is ρ bax is the equivalent density of overflow shut-in drilling fluid.

[0030] In some embodiments, calculating the differential pressure stuck drill constraint condition parameter based on the first plate data includes:

[0031] Δp=0.00981×(ρ ECD -ρ pn )×D n ≤Δp n ;

[0032] Where: pn is the formation pore pressure equivalent density corresponding to the maximum pressure difference in the open hole section, g / cm 3 ;D n is the well depth corresponding to the maximum pressure difference in the open hole section, m; △p n is the critical value of formation pressure difference causing drill bit sticking, and △p is the maximum pressure difference between the drilling fluid column pressure and the formation pore pressure in the open hole section.

[0033] In some embodiments, based on the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the differential pressure sticking constraint condition parameters, the running depth of each layer of casing is calculated in sequence, including:

[0034] Determine the wellbore structure design parameters, and draw a horizontal line to the horizontal axis from the intersection of the dynamic wellbore drilling fluid equivalent density and the safe formation fracture pressure equivalent density curve. The well depth at the intersection is the initial casing running depth.

[0035] Starting from the initial casing running depth, compare the safe formation fracture pressure equivalent density and the minimum loss pressure equivalent density at each well depth from top to bottom;

[0036] If each well depth satisfies the condition that the dynamic wellbore drilling fluid equivalent density is less than the minimum loss pressure equivalent density, the primary selected running depth is the reselected running depth, and the stuck pipe condition is checked;

[0037] If the safe formation fracture pressure equivalent density at a single point or multiple points in the well section is greater than or equal to the minimum leakage pressure equivalent density, then the well depth D corresponding to the last point where the safe formation fracture pressure equivalent density is greater than or equal to the minimum leakage pressure equivalent density is selected. 2 This well depth is the depth of the secondary casing in the selected upper opening, and the stuck drill condition is checked;

[0038] Verify the casing depth D 2 Whether there is a risk of differential pressure sticking or casing stuck, and calculate and compare the relationship between the maximum pressure difference between the drilling fluid column pressure and the formation pore pressure and the critical value of differential pressure sticking;

[0039] If the maximum pressure difference is less than or equal to the critical value of formation pressure difference stuck drill, then check the depth D 2 That is, the depth D is selected again. 1 , to check the overflow conditions;

[0040] If the maximum pressure difference is greater than the critical value of formation pressure difference sticking, then calculate the maximum well depth allowed by the dynamic wellbore drilling fluid equivalent density under the pressure of the critical value of formation pressure difference sticking. At this time, the maximum well depth is the selected entry depth D. 1 , to check the overflow conditions;

[0041] Since D 1 First, the equivalent density of the overflow shut-in drilling fluid at each well depth is compared with the equivalent density of the minimum leakage pressure from top to bottom;

[0042] If the equivalent density of the overflow shut-in drilling fluid is less than the minimum loss pressure equivalent density at each well depth, then the next entry depth D 1 This is the final descent depth D;

[0043] If the drilling fluid equivalent density of overflow shut-in at a single point or multiple points in the well section is greater than or equal to the minimum loss pressure equivalent density, then the well depth corresponding to the last overflow shut-in drilling fluid equivalent density greater than or equal to the minimum loss pressure equivalent density is selected, and this well depth plus the corresponding safety well depth is the final running depth D;

[0044] Repeat the above steps to design other layers of technical casing one by one until the surface casing is designed.

[0045] In a second aspect, an embodiment of the present application provides a wellbore structure design device based on wellbore ECD calculation, wherein the device includes a memory and a processor.

[0046] The memory is used to store computer programs; the processor is used to implement the steps of the wellbore structure design method based on wellbore ECD calculation when executing the computer program.

[0047] In a third aspect, an embodiment of the present application provides a medium having a computer program stored thereon, and when the computer program is executed by a processor, the steps of the wellbore structure design method based on wellbore ECD calculation are implemented.

[0048] The beneficial effects of the embodiments of the present invention are:

[0049] The embodiment of the present invention accurately calculates the dynamic drilling fluid equivalent density at different well depths in the current open hole section through drilling fluid density, rheological parameters and drilling construction parameters, and uses the wellbore drilling fluid equivalent density in the dynamic construction process as a reference judgment condition, thereby realizing accurate wellbore structure design of narrow density window wells, avoiding the problem of using static drilling fluid equivalent density as a judgment condition, resulting in the actual equivalent density being higher than the safe formation fracture pressure equivalent density and the leakage pressure equivalent density in the current open hole section, causing a series of well control safety accidents such as well leakage, overflow, and blowout.

[0050] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or be understood by implementing the embodiments of the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the written description, claims, and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0051] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings required for use in the embodiments are briefly introduced below. It should be understood that the following drawings only show certain embodiments of the present invention and therefore should not be regarded as limiting the scope. For ordinary technicians in this field, other related drawings can be obtained based on these drawings without creative work.

[0052] Figure 1It is a schematic flow chart of a wellbore structure design method based on wellbore ECD calculation described in an embodiment of the present invention;

[0053] Figure 2 It is a schematic diagram of the design step flow described in Example 2 of the present invention;

[0054] Figure 3 It is a schematic diagram of the structure of a wellbore structure design device based on wellbore ECD calculation described in an embodiment of the present invention. DETAILED DESCRIPTION

[0055] In order to make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, rather than all of the embodiments. The components of the embodiments of the present invention generally described and shown in the drawings here can be arranged and designed in various different configurations. Therefore, the following detailed description of the embodiments of the present invention provided in the drawings is not intended to limit the scope of the claimed invention, but merely represents selected embodiments of the present invention. Based on the embodiments in the present invention, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of the present invention.

[0056] It should be noted that similar reference numerals or letters represent similar items in the following drawings, so once an item is defined in one drawing, it does not need to be further defined and explained in the subsequent drawings. At the same time, in the description of the present invention, the terms "first", "second", etc. are only used to distinguish the description and cannot be understood as indicating or implying relative importance.

[0057] Example 1

[0058] like Figure 1 As shown, this embodiment provides a wellbore structure design method based on wellbore ECD calculation, which is applied to electronic equipment. The method includes step S100, step S200, step S300 and step S400.

[0059] Step S100, drawing a full-well section pressure profile curve based on the well pressure prediction data, and calculating the safe formation fracture pressure equivalent density according to the preset single-well geological fracture pressure prediction data, and adding the safe formation fracture pressure equivalent density change curve to the full-well section pressure profile curve based on the safe formation fracture pressure equivalent density, and marking the added full-well section pressure profile curve as the first plate data;

[0060] Step S200, based on the first plate data, sequentially calculating the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the differential pressure sticking constraint condition parameters;

[0061] Step S300, based on the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the differential pressure sticking constraint condition parameters, the running depth of each layer of casing is calculated in sequence.

[0062] Secondly, in step S100 described in this embodiment, the drawing of the full-well pressure profile curve based on the single-well geological data includes:

[0063] Step S110, obtaining geological vertical depth data and pressure prediction data in the single well geological data, and respectively plotting the pore pressure equivalent density change curve, collapse pressure equivalent density change curve, leakage pressure equivalent density change curve and fracture pressure equivalent density change curve that change with vertical depth, and then obtaining the full-well section pressure profile curve, wherein the ordinate of the full-well section pressure profile curve is the well depth data, the minimum value is the ground reference plane, the maximum value is the maximum designed vertical depth, and the abscissa is the predicted pressure equivalent density, the minimum value is the minimum value of the four pressure equivalent densities, and the maximum value is the maximum value of the four pressure equivalent densities.

[0064] Secondly, in step S200 described in this embodiment, the dynamic wellbore drilling fluid equivalent density is calculated based on the first plate data, including:

[0065] Step S210, based on the drilling data and the first plate data, respectively calculate the static equivalent density of the drilling fluid and the circulating pressure loss equivalent density of the drilling fluid, and obtain the dynamic wellbore drilling fluid equivalent density by summing the static equivalent density of the drilling fluid and the circulating pressure loss equivalent density of the drilling fluid.

[0066] Secondly, in step S200 described in this embodiment, the static equivalent density of the drilling fluid is calculated based on the first plate data, including:

[0067] Step S220, calculating the static equivalent density of the drilling fluid based on a first calculation formula, wherein the first calculation formula is:

[0068]

[0069] In the formula, ρ ESD is the static equivalent density of drilling fluid, K is the viscosity coefficient of drilling fluid, Pa·s n ; h is the well depth, m; F is the drilling fluid temperature at the current well depth, ℉; a is the coefficient, a function of the drilling fluid fluidity index n.

[0070] Secondly, in step S200 described in this embodiment, the equivalent density of the circulating pressure loss of drilling fluid is calculated based on the drilling data and the first plate data, including:

[0071]

[0072]

[0073] p c =p p +p a ;

[0074]

[0075] Note:

[0076] G 2 =3nb-4b+5; G 3 =nb-2b+2;

[0077] k 1 =2b-nb-2; k 2 =5bn-7b+5;

[0078] k 4 =ρ b-1 ;

[0079] k 6 =nb-2b+2;

[0080]

[0081] Where: p p is the circulating pressure loss in the drill string, Pa; p a is the annular circulation pressure loss, Pa; p c is the total pressure loss of drilling fluid circulation, Pa; ρ AECD G is the equivalent density of drilling fluid circulation pressure loss; 0 , G 1 , G 2 , G 3 , B 0 , k 1 , k 2 , k 3 , k 4 , k 5 , k 6 are substitution coefficients; K is the drilling fluid viscosity coefficient, Pa·s n ; n is the drilling fluid flow index; a, b are coefficients, functions of the drilling fluid flow index n; Q is the drilling fluid displacement, m 3 / s; N 1is the number of laminar flow segments in the drill string, N 2 is the number of turbulent flow segments; L is the length of the laminar flow segment or turbulent flow segment, m, L i is the length of the laminar flow section or turbulent flow section in the drill string, L j is the length of the laminar flow section or turbulent flow section in the annulus; d is the inner diameter of the drill string, in m, d i is the inner diameter of the laminar flow section or turbulent flow section in the i-th drill string; A is the annular cross-sectional area, m 2 , A i is the annular cross-sectional area corresponding to the laminar flow section or turbulent flow section in the i-th drill string, A j is the cross-sectional area of ​​the annulus corresponding to the laminar flow section or turbulent flow section in the jth annulus; M 1 is the number of laminar flow segments in the annulus, M 2 is the number of turbulent flow segments; d 1 is the borehole diameter, in m, d 1j is the borehole diameter corresponding to the laminar flow section or turbulent flow section in the jth annulus; d 2 is the outer diameter of the drill string, in m, d 2j is the outer diameter of the drill string corresponding to the laminar flow section or turbulent flow section in the jth annulus; d b is the drill bit diameter, m; R is the mechanical drilling speed, m / h; ρ s is the density of drill cuttings, g / cm 3 ρ mmax is the maximum drilling fluid density in the well section; g is the gravity acceleration; k′ is the velocity correction coefficient; v s is the cuttings sliding velocity, m / s; h is the well depth, m.

[0082] Secondly, in step S200 described in this embodiment, the equivalent density of the overflow shut-in drilling fluid is calculated based on the first plate data, including:

[0083] Step S230: Calculate the equivalent density of the overflow shut-in drilling fluid based on a third calculation formula, wherein the third calculation formula is:

[0084]

[0085] Where: D m D is the top well depth corresponding to the maximum formation pore pressure equivalent density in the open hole section, m; x is the depth of the calculation point in the open hole section, m; S k It is the overflow allowable value, generally ranging from 0.05-0.10g / cm 3， ρ mmax is the maximum drilling fluid density in the well section; is ρ bax is the equivalent density of overflow shut-in drilling fluid.

[0086] Secondly, in step S200 described in this embodiment, the differential pressure sticking constraint condition parameters are calculated based on the first plate data, including:

[0087] Δp=0.00981×(ρ ECD -ρ pn )×D n ≤Δp n ;

[0088] Where: pn is the formation pore pressure equivalent density corresponding to the maximum pressure difference in the open hole section, g / cm 3 ;D n is the well depth corresponding to the maximum pressure difference in the open hole section, m; △p n is the critical value of formation pressure difference causing drill bit sticking, and △p is the maximum pressure difference between the drilling fluid column pressure and the formation pore pressure in the open hole section.

[0089] Secondly, in step S300 described in this embodiment, based on the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the differential pressure sticking constraint condition parameters, the running depth of each layer of casing is calculated in sequence, including:

[0090] Step S310, determine the wellbore structure design parameters, and draw a horizontal line to the horizontal axis from the intersection of the dynamic wellbore drilling fluid equivalent density and the safe formation fracture pressure equivalent density curve, and the well depth at the intersection is the primary casing running depth;

[0091] Step S320, starting from the initially selected casing running depth, compare the safe formation fracture pressure equivalent density and the minimum leakage pressure equivalent density at each well depth from top to bottom;

[0092] If each well depth satisfies the condition that the dynamic wellbore drilling fluid equivalent density is less than the minimum loss pressure equivalent density, the primary selected running depth is the reselected running depth, and the stuck pipe condition is checked;

[0093] If the safe formation fracture pressure equivalent density at a single point or multiple points in the well section is greater than or equal to the minimum leakage pressure equivalent density, then the well depth D corresponding to the last point where the safe formation fracture pressure equivalent density is greater than or equal to the minimum leakage pressure equivalent density is selected. 2 This well depth is the depth of the secondary casing in the selected upper opening, and the stuck drill condition is checked;

[0094] Step S330: Verify the casing depth D 2 Whether there is a risk of differential pressure sticking or casing stuck, and calculate and compare the relationship between the maximum pressure difference between the drilling fluid column pressure and the formation pore pressure and the critical value of differential pressure sticking;

[0095] If the maximum pressure difference is less than or equal to the critical value of formation pressure difference stuck drill, then check the depth D2 That is, the depth D is selected again. 1 , to check the overflow conditions;

[0096] If the maximum pressure difference is greater than the critical value of formation pressure difference sticking, then calculate the maximum well depth allowed by the dynamic wellbore drilling fluid equivalent density under the pressure of the critical value of formation pressure difference sticking. At this time, the maximum well depth is the selected entry depth D. 1 , to check the overflow conditions;

[0097] Step S340: 1 First, the equivalent density of the overflow shut-in drilling fluid at each well depth is compared with the equivalent density of the minimum leakage pressure from top to bottom;

[0098] If the equivalent density of the overflow shut-in drilling fluid is less than the minimum loss pressure equivalent density at each well depth, then the next entry depth D 1 This is the final descent depth D;

[0099] If the drilling fluid equivalent density of overflow shut-in at a single point or multiple points in the well section is greater than or equal to the minimum loss pressure equivalent density, then the well depth corresponding to the last overflow shut-in drilling fluid equivalent density greater than or equal to the minimum loss pressure equivalent density is selected, and this well depth plus the corresponding safety well depth is the final running depth D;

[0100] Step S350, repeat the above steps to successively design other layers of technical casings until the surface casing is designed.

[0101] In the embodiment, the dynamic drilling fluid equivalent density at different well depths in the current open hole section is accurately calculated by using the drilling fluid density, rheological parameters and drilling construction parameters, and the wellbore drilling fluid equivalent density during the dynamic construction process is used as a reference judgment condition, thereby realizing the precise wellbore structure design of the narrow density window well, avoiding the problem of using the static drilling fluid equivalent density as a judgment condition, resulting in the actual equivalent density being higher than the safe formation fracture pressure equivalent density and the leakage pressure equivalent density in the current open hole section, causing a series of well control safety accidents such as well leakage, overflow, and blowout.

[0102] Example 2

[0103] like Figure 2 As shown, this embodiment is used to further illustrate the design method and steps of the overall technical solution, including:

[0104] 5.1 Draw the pressure profile curve of the entire well section:

[0105] Based on the single well geological vertical depth data and pressure prediction data, the pore pressure equivalent density ρ of the well is plotted as it changes with vertical depth. p , collapse pressure equivalent density ρ c , leakage pressure equivalent density ρ l , burst pressure equivalent density ρf Curves, such as Figure 2 The vertical coordinate (Y axis) of the curve graph is the depth data of the well, the minimum value is the ground reference plane, and the maximum value is the maximum designed vertical depth; the horizontal coordinate (X axis) of the curve graph is the predicted pressure equivalent density, the minimum value is the minimum value of the four pressure equivalent densities, and the maximum value is the maximum value of the four pressure equivalent densities.

[0106] 5.2 Plotting the safe formation fracture pressure equivalent density ρ for the entire well section ffmin curve:

[0107] According to the single well geological fracture pressure prediction data, calculate the safe formation fracture pressure equivalent density ρ ffmin , and add the safe formation fracture pressure equivalent density ρ to the pressure profile graph ffmin curve, and finally form a plate, such as Figure 2 shown.

[0108] ρ ffmin =ρ f -S f ;

[0109] Where: S f ——Safety allowable value of formation fracture pressure equivalent density, g / cm 3 ;

[0110] 5.3 Calculation of the maximum drilling fluid density ρ in the well section mmax

[0111] 5.3.1 To prevent well kick, the drilling fluid density should be greater than or equal to the maximum formation pore pressure equivalent density in the open hole section plus the additional value of drilling fluid density Δρ.

[0112] ρ m1 ≥ρ pmax +Δρ;

[0113] 5.3.2 To prevent well collapse, the drilling fluid density should be greater than or equal to the equivalent density of the maximum formation collapse pressure in the open hole section.

[0114] ρ m2 ≥ρ cmax ;

[0115] 5.3.3 The drilling fluid density must meet the requirements of preventing well kick and well collapse at the same time, that is, the maximum drilling fluid density in the well section is the maximum value of ρm1 and ρm2.

[0116] ρ mmax =max(ρ m1 , ρ m2 );

[0117] 5.4 Calculation of dynamic wellbore drilling fluid equivalent density ρ ECD

[0118] Dynamic wellbore drilling fluid equivalent density ρ ECD is the maximum drilling fluid density ρ in the open hole section mmax During construction or circulation, the static equivalent density of drilling fluid under different well depth conditions ρ ESD and drilling fluid circulation pressure loss equivalent density ρ AECD The sum of .

[0119] 5.4.1 Static equivalent density of drilling fluid ρ ESD Calculation formula

[0120]

[0121] Where: K——Drilling fluid viscosity coefficient, Pa·s n ;

[0122] h——well depth, m;

[0123] F——drilling fluid temperature at current well depth, °F;

[0124] a——coefficient, function of drilling fluid fluidity index n.

[0125] 5.4.2 Drilling fluid circulation pressure loss equivalent density ρ AECD Calculation formula:

[0126]

[0127]

[0128] p c =p p +p a ;

[0129]

[0130] Note: G 2 =3nb-4b+5; G 3 =nb-2b+2;

[0131] k 1 =2b-nb-2; k 2 =5bn-7b+5; k 4 =ρ b-1 ;

[0132] k 6 =nb-2b+2;

[0133]

[0134] Where: p p ——Circulation pressure loss in drill string, Pa;

[0135] p a ——Annular circulation pressure loss, Pa;

[0136] p c ——Total pressure loss of drilling fluid circulation, Pa;

[0137] K——Drilling fluid viscosity coefficient, Pa·s n ;

[0138] n——drilling fluid fluidity index;

[0139] a, b – coefficients, functions of drilling fluid fluidity index n;

[0140] L——the length of the laminar flow section or turbulent flow section in the drill string (or annulus), m;

[0141] d——inner diameter of drill string, m;

[0142] A——Annulus cross-sectional area, m 2 ;

[0143] Q——Drilling fluid displacement, m 3 / s;

[0144] d 1 ——wellbore diameter, m;

[0145] d 2 ——Drill string outer diameter, m;

[0146] d b ——drill bit diameter, m;

[0147] R——mechanical drilling speed, m / h;

[0148] ρ s ——Drill cuttings density, g / cm 3 ;

[0149] g——acceleration due to gravity;

[0150] k——speed correction factor;

[0151] v s ——Drill cuttings sliding speed, m / s;

[0152] h——well depth, m.

[0153] 5.4.3 Dynamic wellbore drilling fluid equivalent density ρ ECD Calculation formula

[0154] ρ ECD =ρ ESD +ρ AECD;

[0155] 5.6 Calculation of the equivalent density ρ of the overflow shut-in drilling fluid bax :

[0156] When overflow and well shut-in occur, the pressure equivalent density at each well depth in the open hole section should be less than or equal to the loss pressure equivalent density at that well depth.

[0157]

[0158] Where: D m ——The top well depth corresponding to the maximum formation pore pressure equivalent density in the open hole section, m;

[0159] D x ——Well depth at the calculated point in the open hole section, m;

[0160] S k ——Overflow allowable value, generally ranging from 0.05-0.10g / cm 3 .

[0161] 5.5 Calculation of differential pressure drilling constraints:

[0162] During drilling operations, the maximum pressure difference △p between the drilling fluid column pressure and the formation pore pressure in the open hole section should be less than or equal to the critical value of formation pressure difference for pipe sticking △p n .

[0163] Δp=0.00981×(ρ ECD -ρ pn )×D n ≤Δp n ;

[0164] Where: pn ——Equivalent density of formation pore pressure corresponding to the maximum pressure difference in the open hole section, g / cm 3 ;

[0165] D n ——Well depth corresponding to the maximum pressure difference in the open hole section, m;

[0166] Δp n ——The critical value of formation pressure difference causing drilling stuck is generally in the range of 12-15MPa for normal pressure formations and 15-20MPa for abnormal pressure formations.

[0167] 5.7 Determine the casing insertion depth:

[0168] 5.7.1 Determine the wellbore structure design parameters.

[0169] 5.7.2 Dynamic wellbore drilling fluid equivalent density ρ ECD and safe formation fracture pressure equivalent density ρffmin Draw a horizontal line from the intersection of the curves to the horizontal axis, and the depth of the intersection is the initial casing depth D3. Figure 2 After determining the initial casing depth, conduct leakage condition verification, see 5.7.2;

[0170] 5.7.3 Self-D 3 First, compare the ρ of each well depth from top to bottom. ECD and the minimum leakage pressure equivalent density ρ llmin ;

[0171] (a) If every well depth satisfies ρ ECD Less than ρ llmin , then the initial selection is down to depth D 3 That is the check-in depth D 2 , check the drill sticking condition, see 5.6.3;

[0172] (b) If the depth of a single point or multiple points in the well section is ECD Greater than or equal to ρ llmin , then choose the last point ρ ECD Greater than or equal to ρ llmin The corresponding well depth D 2 This well depth is the depth of the secondary casing in the reselected upper opening. See 5.7.3 for the check of the stuck drill condition;

[0173] 5.7.3 Verify the casing depth D 2 Whether there is a risk of differential pressure sticking or casing sticking, calculate and compare the maximum pressure difference △p between the drilling fluid column pressure and the formation pore pressure and the critical value of formation differential pressure sticking △p according to formula (11) n relation;

[0174] (a) If △p≤Δp n , then check the entry depth D 2 That is, the depth D is selected again. 1 , perform overflow condition verification, see 5.7.4;

[0175] (b) If △p>△p n , then use formula (11) to calculate ρ ECD In △p n The maximum well depth D allowed under pressure n , at this time D n That is, the depth D is selected again. 1 , perform overflow condition verification, see 5.7.4;

[0176] 5.7.4 Self-D 1 First, compare the ρ of each well depth from top to bottom. bax and the minimum leakage pressure equivalent density ρ llmin ;

[0177] (a) If every well depth satisfies ρ bax Less than ρ llmin , then select the depth D 1 This is the final descent depth D;

[0178] (b) If the depth of a single point or multiple points in the well section is bax Greater than or equal to ρ llmin , then choose the last point ρ bax Greater than or equal to ρ llmin The corresponding well depth, after adding the corresponding safety well depth, is the final descent depth D;

[0179] 5.7.5 Repeat steps 5.7.1 to 5.7.4 to design other layers of technical casing one by one until the surface casing is designed.

[0180] Example 3

[0181] Corresponding to the above method embodiments, the embodiments of the present disclosure also provide a wellbore structure design device based on wellbore ECD calculation. The wellbore structure design device based on wellbore ECD calculation described below and the wellbore structure design method based on wellbore ECD calculation described above can refer to each other.

[0182] Figure 3 FIG. 8 is a block diagram of a wellbore structure design device 800 based on wellbore ECD calculation according to an exemplary embodiment. Figure 3 As shown, the electronic device 800 may include: a processor 801 and a memory 802. The electronic device 800 may also include one or more of a multimedia component 803, an I / O interface 804, and a communication component 805.

[0183] The processor 801 is used to control the overall operation of the electronic device 800 to complete all or part of the steps in the wellbore structure design method based on wellbore ECD calculation. The memory 802 is used to store various types of data to support the operation of the electronic device 800, and these data may include instructions for any application or method used to operate on the electronic device 800, as well as application-related data, such as contact data, sent and received messages, pictures, audio, video, etc. The memory 802 can be implemented by any type of volatile or non-volatile storage device or a combination thereof, such as static random access memory (Static Random Access Memory, referred to as SRAM), electrically erasable programmable read-only memory (Electrically Erasable Programmable Read-Only Memory, referred to as EEPROM), erasable programmable read-only memory (Erasable Programmable Read-Only Memory, referred to as EPROM), programmable read-only memory (Programmable Read-Only Memory, referred to as PROM), read-only memory (Read-Only Memory, referred to as ROM), magnetic memory, flash memory, magnetic disk or optical disk. The multimedia component 803 may include a screen and an audio component. The screen may be, for example, a touch screen, and the audio component is used to output and / or input audio signals. For example, the audio component may include a microphone, which is used to receive external audio signals. The received audio signal may be further stored in the memory 802 or sent through the communication component 805. The audio component also includes at least one speaker for outputting audio signals. The I / O interface 804 provides an interface between the processor 801 and other interface modules, and the above-mentioned other interface modules may be keyboards, mice, buttons, etc. These buttons may be virtual buttons or physical buttons. The communication component 805 is used for wired or wireless communication between the electronic device 800 and other devices. Wireless communication, such as Wi-Fi, Bluetooth, Near Field Communication (NFC), 2G, 3G or 4G, or a combination of one or more of them, so the corresponding communication component 805 may include: Wi-Fi module, Bluetooth module, NFC module.

[0184] In an exemplary embodiment, the electronic device 800 can be implemented by one or more application specific integrated circuits (ASIC), digital signal processors (DSP), digital signal processing devices (DSPD), programmable logic devices (PLD), field programmable gate arrays (FPGA), controllers, microcontrollers, microprocessors or other electronic components to execute the above-mentioned wellbore structure design method based on wellbore ECD calculation.

[0185] In another exemplary embodiment, a computer-readable storage medium including program instructions is also provided, and when the program instructions are executed by a processor, the steps of the wellbore structure design method based on wellbore ECD calculation are implemented. For example, the computer-readable storage medium can be the memory 802 including the program instructions, and the program instructions can be executed by the processor 801 of the electronic device 800 to complete the wellbore structure design method based on wellbore ECD calculation.

[0186] Example 4

[0187] Corresponding to the above method embodiment, the embodiment of the present disclosure further provides a readable storage medium. The readable storage medium described below and the wellbore structure design method based on wellbore ECD calculation described above can refer to each other.

[0188] A readable storage medium stores a computer program, which, when executed by a processor, implements the steps of the wellbore structure design method based on wellbore ECD calculation of the above method embodiment.

[0189] The readable storage medium may specifically be a U disk, a mobile hard disk, a read-only memory (ROM), a random access memory (RAM), a magnetic disk or an optical disk, or other readable storage medium that can store program codes.

[0190] The foregoing is merely a specific embodiment of the present invention, which enables those skilled in the art to understand or implement the present invention. Various modifications to these embodiments will be apparent to those skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of the present invention. Therefore, the present invention will not be limited to the embodiments shown herein, but rather to the widest scope consistent with the principles and novel features claimed herein.

Claims

1. A wellbore structure design method based on wellbore ECD calculation, It is characterized in that Applied to electronic equipment, the method comprises: Based on the pressure prediction data of the well, a full-well section pressure profile curve is drawn, and the safe formation fracture pressure equivalent density is calculated according to the preset single-well geological fracture pressure prediction data, and based on the safe formation fracture pressure equivalent density, a safe formation fracture pressure equivalent density change curve is added to the full-well section pressure profile curve, and the added full-well section pressure profile curve is marked as the first plate data; Based on the first plate data, the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the differential pressure sticking constraint condition parameters are calculated in sequence; Based on the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the differential pressure sticking constraint condition parameters, the running depth of each layer of casing is calculated in turn.

2. The wellbore structure design method based on wellbore ECD calculation according to claim 1, It is characterized in that The method of drawing a full-well section pressure profile curve based on the well pressure prediction data includes: The geological vertical depth data and pressure prediction data in the single well geological data are obtained, and the pore pressure equivalent density change curve, the collapse pressure equivalent density change curve, the leakage pressure equivalent density change curve and the fracture pressure equivalent density change curve with the vertical depth are respectively plotted, so as to obtain the full-well section pressure profile curve, wherein the ordinate of the full-well section pressure profile curve is the well depth data, the minimum value is the ground reference plane, the maximum value is the maximum designed vertical depth, and the abscissa is the predicted pressure equivalent density, the minimum value is the minimum value of the four pressure equivalent densities, and the maximum value is the maximum value of the four pressure equivalent densities.

3. The wellbore structure design method based on wellbore ECD calculation according to claim 1, It is characterized in that Calculating the dynamic wellbore drilling fluid equivalent density based on the first plate data includes: The static equivalent density of the drilling fluid and the circulating pressure loss equivalent density of the drilling fluid are calculated based on the drilling data and the first plate data, respectively, and the dynamic wellbore drilling fluid equivalent density is calculated by summing the static equivalent density of the drilling fluid and the circulating pressure loss equivalent density of the drilling fluid.

4. The wellbore structure design method based on wellbore ECD calculation according to claim 3, It is characterized in that Calculating the static equivalent density of the drilling fluid based on the first plate data includes: The static equivalent density of the drilling fluid is calculated based on the first calculation formula, where the first calculation formula is: In the formula, ρ ESD is the static equivalent density of drilling fluid, K is the viscosity coefficient of drilling fluid, Pa·s n ; h is the well depth, m; F is the drilling fluid temperature at the current well depth, ℉; a is the coefficient, a function of the drilling fluid fluidity index n, ρ mmax is the maximum drilling fluid density in the well section.

5. The wellbore structure design method based on wellbore ECD calculation according to claim 3, It is characterized in that Calculate the equivalent density of drilling fluid circulation pressure loss based on the data in the first plate, including: p c =p p +p a ; Note: G 2 =3nb-4b+5;G 3 =nb-2b+2; <h2 style=";text-align:left;direction:ltr">k<h2 style=";text-align:left;direction:ltr"> 1 <h2 style=";text-align:left;direction:ltr"> =2b-nb-2;k<h2 style=";text-align:left;direction:ltr"> 2 <h2 style=";text-align:left;direction:ltr"> =5bn-7b+5; k 4 =ρ b-1 ; k 6 =nb-2b+2; Where: p p is the circulating pressure loss in the drill string, Pa; p a is the annular circulation pressure loss, Pa; p c is the total pressure loss of drilling fluid circulation, Pa; ρ AECD G is the equivalent density of drilling fluid circulation pressure loss; 0 , G 1 , G 2 , G 3 , B 0 , k 1 , k 2 , k 3 , k 4 , k 5 , k 6 are substitution coefficients; K is the drilling fluid viscosity coefficient, Pa·s n ; n is the drilling fluid flow index; a, b are coefficients, functions of the drilling fluid flow index n; Q is the drilling fluid displacement, m 3 / s; N 1 is the number of laminar flow segments in the drill string, N 2 is the number of turbulent flow segments; L is the length of the laminar flow segment or turbulent flow segment, m, L i is the length of the laminar flow section or turbulent flow section in the drill string, L j is the length of the laminar flow section or turbulent flow section in the annulus; d is the inner diameter of the drill string, in m, d i is the inner diameter of the laminar flow section or turbulent flow section in the i-th drill string; A is the annular cross-sectional area, m 2 , A i is the annular cross-sectional area corresponding to the laminar flow section or turbulent flow section in the i-th drill string, A j is the cross-sectional area of ​​the annulus corresponding to the laminar flow section or turbulent flow section in the jth annulus; M 1 is the number of laminar flow segments in the annulus, M 2 is the number of turbulent flow segments; d 1 is the borehole diameter, in m, d 1j is the borehole diameter corresponding to the laminar flow section or turbulent flow section in the jth annulus; d 2 is the outer diameter of the drill string, in m, d 2j is the outer diameter of the drill string corresponding to the laminar flow section or turbulent flow section in the jth annulus; d b is the drill bit diameter, m; R is the mechanical drilling speed, m / h; ρ s is the density of drill cuttings, g / cm 3 ρ mmax is the maximum drilling fluid density in the well section; g is the gravity acceleration; k′ is the velocity correction coefficient; v s is the cuttings sliding velocity, m / s; h is the well depth, m.

6. The wellbore structure design method based on wellbore ECD calculation according to claim 1, It is characterized in that Calculating the equivalent density of the overflow shut-in drilling fluid based on the first plate data includes: The overflow shut-in drilling fluid equivalent density is calculated based on a third calculation formula, wherein the third calculation formula is: Where: D m D is the top well depth corresponding to the maximum formation pore pressure equivalent density in the open hole section, m; x is the depth of the calculation point in the open hole section, m; S k It is the overflow allowable value, generally ranging from 0.05-0.10g / cm 3， ρ mmax is the maximum drilling fluid density in the well section; ρ bax is the equivalent density of overflow shut-in drilling fluid.

7. The wellbore structure design based on wellbore ECD calculation according to claim 1, It is characterized in that Calculating the differential pressure sticking constraint condition parameter based on the first plate data includes: Δp=0.00981×(ρ ECD -r pn )×D n ≤Δp n ; Where: pn is the formation pore pressure equivalent density corresponding to the maximum pressure difference in the open hole section, g / cm 3 ;D n is the well depth corresponding to the maximum pressure difference in the open hole section, m; △p n is the critical value of formation pressure difference causing drill bit sticking, and △p is the maximum pressure difference between the drilling fluid column pressure and the formation pore pressure in the open hole section.

8. The wellbore structure design method based on wellbore ECD calculation according to claim 1, It is characterized in that Based on the maximum drilling fluid density in the well section, the dynamic wellbore drilling fluid equivalent density, the overflow shut-in drilling fluid equivalent density and the differential pressure sticking constraint condition parameters, the running depth of each layer of casing is calculated in turn, including: Determine the wellbore structure design parameters, and draw a horizontal line to the horizontal axis from the intersection of the dynamic wellbore drilling fluid equivalent density and the safe formation fracture pressure equivalent density curve. The well depth at the intersection is the initial casing running depth. Starting from the initial casing running depth, compare the safe formation fracture pressure equivalent density and the minimum loss pressure equivalent density at each well depth from top to bottom; If each well depth satisfies the condition that the dynamic wellbore drilling fluid equivalent density is less than the minimum loss pressure equivalent density, the primary selected running depth is the reselected running depth, and the stuck pipe condition is checked; If the safe formation fracture pressure equivalent density at a single point or multiple points in the well section is greater than or equal to the minimum leakage pressure equivalent density, then the well depth D corresponding to the last point where the safe formation fracture pressure equivalent density is greater than or equal to the minimum leakage pressure equivalent density is selected. 2 This well depth is the depth of the secondary casing in the selected upper opening, and the stuck drill condition is checked; Verify the casing depth D 2 Whether there is a risk of differential pressure sticking or casing stuck, and calculate and compare the relationship between the maximum pressure difference between the drilling fluid column pressure and the formation pore pressure and the critical value of differential pressure sticking; If the maximum pressure difference is less than or equal to the critical value of formation pressure difference stuck drill, then check the depth D 2 That is, the depth D is selected again. 1 , to check the overflow conditions; Since D 1 First, the equivalent density of the overflow shut-in drilling fluid at each well depth is compared with the equivalent density of the minimum leakage pressure from top to bottom; If the equivalent density of the overflow shut-in drilling fluid is less than the minimum loss pressure equivalent density at each well depth, then the next entry depth D 1 This is the final descent depth D; Repeat the above steps to design other layers of technical casing one by one until the surface casing is designed.

9. The wellbore structure design method based on wellbore ECD calculation according to claim 8, It is characterized in that Verify the casing depth D 2 Whether there is a risk of differential pressure sticking or casing stuck, and after calculating and comparing the relationship between the maximum pressure difference between the drilling fluid column pressure and the formation pore pressure and the critical value of differential pressure sticking, it also includes: If the maximum pressure difference is greater than the critical value of formation pressure difference sticking, then calculate the maximum well depth allowed by the dynamic wellbore drilling fluid equivalent density under the pressure of the critical value of formation pressure difference sticking. At this time, the maximum well depth is the selected entry depth D. 1 , to check the overflow conditions; Since D 1 First, the overflow shut-in drilling fluid equivalent density and the minimum loss pressure equivalent density are compared at each well depth from top to bottom.

10. The wellbore structure design method based on wellbore ECD calculation according to claim 8, It is characterized in that Since D 1 First, compare the equivalent density of the overflow shut-in drilling fluid and the equivalent density of the minimum leakage pressure at each well depth from top to bottom, and then include: If the equivalent density of the drilling fluid for overflow and shut-in at a single point or multiple points in the well section is greater than or equal to the minimum loss pressure equivalent density, then the well depth corresponding to the last point where the equivalent density of the drilling fluid for overflow and shut-in is greater than or equal to the minimum loss pressure equivalent density is selected. This well depth plus the corresponding safety well depth is the final immersion depth D.

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