A method of pressure-controlled casing lowering

Abstract

The application provides a casing pressure control method, and belongs to the field of oil drilling. The application can solve the problems of narrow safe drilling fluid density window, overflow and leakage coexistence, and difficult formation pressure stabilization in a fractured reservoir, and meets the casing safe running requirements. In addition, the "heavy mud cap + gas check" tripping mode can greatly increase the safe operation time, and meets the safe operation time of tripping and conventional casing running well section. Before the casing pressure control, the well mouth is opened, a certain depth of casing string is pre-run in a conventional casing running mode, the casing top can be avoided during the casing running process, and the setting requirement of the centralizer in the key well section is met. The well bottom pressure control method can adjust the well bottom pressure in real time, and realizes the near balance of the well bottom pressure during the casing running process.

Description

Technical Field

[0001] This application relates to the field of oil drilling, and more specifically, to a method for controlled-pressure casing installation. Background Technology

[0002] Currently, key exploration areas both domestically and internationally exhibit strata with narrow pressure windows, pressure sensitivity, multiple pressure systems, pressure exhaustion, and coexistence of overflows and leaks, such as the Sichuan Basin, the Tarim Piedmont structure, and the Songliao Basin, with relatively narrow safe density windows (0.02 g / cm³). 3 ~0.10g / cm 3 During casing installation, complex wellbore losses can easily occur, causing reservoir damage and resulting in significant losses of drilling fluid and plugging materials, as well as extending the drilling and completion cycle. If wellbore leakage is not properly controlled during casing installation, insufficient annular hydrostatic pressure to balance formation pressure may induce leakage followed by overflow, or wellbore collapse may cause casing jamming, preventing the completion of casing installation, severely impacting cementing quality, and even leading to safety accidents.

[0003] Currently, for formations prone to leakage and overflow, conventional casing running operations primarily involve increasing the formation's pressure-bearing capacity before casing running through methods such as pressure plugging to achieve the highest equivalent circulating density (ECD) during casing running or cementing; or by controlling the casing lowering speed, reducing kinetic pressure, adjusting drilling fluid properties, and designing drilling fluid density in stages to keep the bottom hole ECD within a safe density window. If leakage occurs during casing running, it is often addressed by forcibly running the casing to the bottom of the well and completing cementing operations despite the leakage; or by re-drilling the casing, treating the wellbore, and resuming casing running once the conditions for casing running are met. If overflow occurs during casing running, well control operations are required, and casing running can only continue after the formation has been stabilized.

[0004] Conventional casing running technology has the following main drawbacks: (1) For fractured formations, gas layers are active and leakage is complex and prominent, often requiring multiple pressure-bearing plugging operations to meet the formation's pressure-bearing capacity, which not only causes serious damage to the reservoir but also prolongs the drilling and completion cycle; (2) During casing running, the bottom hole ECD is adjusted by controlling engineering parameters and drilling fluid properties, which involves many influencing factors and is difficult to operate. For example, controlling the casing running speed, or even the acceleration, within a very small range, places high demands on the driller's operation; (3) If leakage or loss occurs during casing running, the casing needs to be pulled out, the wellbore needs to be re-treated, or a well-killing procedure needs to be initiated to stabilize the formation. This method consumes a large amount of drilling fluid and causes reservoir damage.

[0005] Therefore, how to solve the above problems is an urgent issue that needs to be addressed. Summary of the Invention

[0006] This application provides a controlled-pressure casing method that can solve the problems of formation stabilization before casing operation and leakage during casing operation caused by the narrow safe drilling fluid density window in fractured formations, thus achieving safe casing installation.

[0007] Based on this, this application provides a controlled-pressure casing running method, which includes: pumping a gas sludge plug and a heavy slurry cap into the wellbore; calculating the length of the casing string required to prevent the casing from overrunning and calculating the number of centralizers to be run; determining the conventional casing running section based on the casing string length and the number of centralizers; determining whether the safe operating time for the conventional casing running section is met; if so, controlling the casing to run to the conventional casing running section, installing a rotary control head, and continuing the casing running operation; determining whether gas intrusion occurs during the casing running operation; if gas intrusion occurs, controlling the casing running and adjusting the bottom hole pressure.

[0008] In one possible embodiment, the pumping of the gas sludge plug and heavy slurry cap into the wellbore includes: calculating the liquid column pressure requiring additional compensation and the additional safety pressure; obtaining the heavy slurry density, the inner cross-sectional area between the upper casing and the drill pipe, and the drilling fluid density; determining the heavy slurry cap to be pumped into the wellbore based on the liquid column pressure, the additional safety pressure, the heavy slurry density, the inner cross-sectional area of ​​the casing, and the drilling fluid density; determining the length of the gas sludge plug pumping section; and determining the gas sludge plug to be pumped into the wellbore based on the length of the gas sludge plug pumping section.

[0009] In one possible embodiment, the heavy slurry cap satisfies:

[0010]

[0011] Where V1 is the amount of heavy slurry injected into the wellbore; p t For the liquid column pressure that requires additional compensation; p 附 The additional safety pressure (suction pressure during tripping in, taken as a positive value; excitation pressure during casing running, taken as a negative value); g is the acceleration due to gravity; ρ is the density of the drilling fluid; ρ 重 The density of the heavy slurry is S; S is the inner cross-sectional area between the upper casing and the drill pipe.

[0012] In one possible embodiment, determining the gas plug to be pumped into the wellbore based on the length of the gas plug pumping section includes: obtaining the wellbore size and drill pipe outer diameter; and determining the gas plug to be pumped into the wellbore based on the wellbore size, the drill pipe outer diameter, and the length of the gas plug pumping section.

[0013] In one possible embodiment, the gas slack satisfies:

[0014]

[0015] Where V2 is the gas sludge plug injected into the wellbore, and D b d is the wellbore size; d is the drill pipe outer diameter; L1 is the length of the section into which the gas plug is pumped.

[0016] In one possible embodiment, calculating the length of the casing string required to prevent the casing from overrunning includes: obtaining the casing linear weight, the drilling fluid density, the volume inside the casing, the sum of the wall volume and internal volume of the casing, the bottom cross-section of the casing, and the bottom annular pressure of the casing; and calculating the length of the casing string required to prevent the casing from overrunning based on the casing linear weight, the drilling fluid density, the volume inside the casing, the sum of the wall volume and internal volume of the casing, the bottom cross-section of the casing, and the bottom annular pressure of the casing.

[0017] In one possible embodiment, the sleeve string length of the sleeve satisfies:

[0018]

[0019] Where L is the length of the casing string; q is the weight of the casing line; ρ is the density of the drilling fluid; V4 is the volume inside the casing; V3 is the sum of the wall volume and internal volume of the casing; S2 is the bottom cross-section of the casing; P t ρ is the annular pressure at the bottom of the casing; g is the gravity coefficient.

[0020] In one possible embodiment, the controlled pressure lowering of the casing and regulation of the bottom hole pressure includes: opening the choke valve of the choke manifold to a preset opening to regulate the bottom hole pressure; and continuing to control the pressure lowering of the casing under the adjusted bottom hole pressure.

[0021] In one possible embodiment, the controlled pressure lowering of the casing and regulation of the bottom hole pressure includes: determining a pressure control mode for controlled pressure lowering of the casing, wherein the pressure control mode includes a wellhead pressure control mode and a bottom hole constant pressure control mode; if the pressure control mode is the wellhead pressure control mode, adjusting the opening of the choke valve to make the wellhead pressure tend to the wellhead pressure set value under the wellhead pressure control mode; and continuing to lower the casing under controlled pressure at the wellhead pressure.

[0022] In one possible embodiment, the method further includes: if the pressure control mode is a bottom hole constant pressure control mode, obtaining the bottom hole pressure value and calculating the required wellhead pressure value based on the bottom hole pressure set value under the bottom hole constant pressure control mode; adjusting the opening of the throttle valve to make the wellhead back pressure reach the target wellhead pressure value; and continuing to control the pressure of the casing at the target wellhead pressure value.

[0023] The controlled-pressure casing running method provided in this application involves: pumping gas plugs and heavy slurry caps into the wellbore; calculating the length of the casing string required to prevent casing from overshooting and the number of centralizers to be run; determining the conventional casing running section based on the casing string length and the number of centralizers; determining whether the safe operating time for the conventional casing running section is met; if so, controlling the casing to run to the conventional casing running section, installing a rotary control head, and continuing the casing running operation; determining whether gas intrusion occurs during the casing running operation; if gas intrusion occurs, controlling the casing running and adjusting the bottom hole pressure. This method can solve problems such as narrow drilling fluid density windows, simultaneous overflow and leakage, and difficulty in stabilizing the formation in fractured reservoirs, thus meeting the requirements for safe casing running. Furthermore, the "heavy slurry cap + gas plug" tripping method can significantly increase the safe operating time, meeting the safe operating time requirements for tripping and the conventional casing running section. Before running the casing under controlled pressure, the wellhead is opened, and a casing string of a certain depth is pre-run using conventional casing running methods. This prevents the casing from pushing against the bottom during the running process and also meets the placement requirements of centralizers in key well sections. The bottom hole pressure control method allows for real-time adjustment of the bottom hole pressure, achieving near-balance of the bottom hole pressure during casing running. Attached Figure Description

[0024] To more clearly illustrate the technical solutions of the embodiments of this application, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of this application and should not be regarded as a limitation of the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0025] Figure 1 A flowchart illustrating a pressure-controlled bushing method provided in this application embodiment;

[0026] Figure 2 for Figure 1 The diagram shows a pressure diagram in a pressure-controlled bushing method;

[0027] Figure 3 A flowchart of another pressure-controlled bushing method provided in an embodiment of this application. Detailed Implementation

[0028] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0029] Example

[0030] Reference Figure 1 The flowchart shown illustrates a pressure-controlled bushing method, which specifically includes the following steps:

[0031] Step S201: Pump an air slack plug and a heavy slurry cap into the wellbore.

[0032] It should be understood that before implementing controlled-pressure casing running operations, the wellhead needs to be opened, and a casing string of a certain depth needs to be pre-run using conventional casing running techniques to prevent the casing from jacking up during the controlled-pressure casing running process. To prevent complications such as overflows during conventional casing running, a "heavy slurry cap + gas sludge plug" technique is used during the tripping process before casing running to ensure sufficient time for tripping the last drilling run and for safe operation of the conventional casing running section.

[0033] The heavy slurry cap is mainly used to compensate for the additional fluid column pressure and safety pressure required during the tripping process. Its injection section follows the principle of not leaking into the formation and not entering the deviated or horizontal section, thus avoiding annular hydrostatic pressure loss.

[0034] In one implementation, step S201 includes: calculating the liquid column pressure requiring additional compensation and the additional safety pressure; obtaining the heavy slurry density, the inner cross-sectional area between the upper casing and the drill pipe, and the drilling fluid density; determining the heavy slurry cap to be pumped into the wellbore based on the liquid column pressure, the additional safety pressure, the heavy slurry density, the inner cross-sectional area of ​​the casing, and the drilling fluid density; determining the length of the gas sludge plug pumping section; and determining the gas sludge plug to be pumped into the wellbore based on the length of the gas sludge plug pumping section.

[0035] It should be noted that the additional compensation liquid column pressure and the additional safety pressure can be measured by testing equipment, which can be measured in real time.

[0036] Optionally, the re-slurry density is preset.

[0037] Alternatively, drilling fluid density can also be measured using external equipment.

[0038] Optionally, the inner cross-sectional area between the upper casing and the drill pipe can be calculated based on the casing parameters. Specifically, the inner cross-sectional area of ​​the casing satisfies:

[0039]

[0040] Where S is the inner cross-sectional area between the upper casing and the drill pipe, D is the inner diameter of the upper casing (usually the technical casing), and d is the outer diameter of the drill pipe.

[0041] Optionally, the heavy slurry cap satisfies:

[0042]

[0043] Where V1 is the amount of heavy slurry injected into the wellbore; p t For the liquid column pressure that requires additional compensation; p 附 The additional safety pressure (suction pressure during tripping in, taken as a positive value; excitation pressure during casing running, taken as a negative value); g is the acceleration due to gravity; ρ is the density of the drilling fluid; ρ 重 The density of the heavy slurry is S; S is the inner cross-sectional area of ​​the upper casing (generally a technical casing) and the drill pipe.

[0044] It should be noted that the additional compensation fluid column pressure cannot be directly replaced by the back pressure during normal drilling; it is equal to the difference between the formation pressure and the annular hydrostatic pressure, i.e., p. t =p p -p h The suction pressure generated during tripping can be calculated using either a steady-state model or a transient model. Taking the steady-state model as an example, based on the on-site drilling fluid properties, the influence of the drilling fluid's static shear force, viscosity force, and inertial force on the suction pressure is analyzed to determine the main controlling factors and calculate the suction pressure.

[0045] It should be noted that gas plugs significantly increase safe operating time by increasing viscosity, reducing the displacement reaction between formation gas and drilling fluid in the wellbore, and by decreasing the gas's ascent velocity in the annulus. For vertical wells, gas plugs should be injected into the section above the gas layer; for directional and horizontal wells, they should be injected into the build-up section and vertical section above the gas layer. For shallow gas horizontal wells, or other horizontal wells with particularly active gas layers, both the build-up section and the horizontal section can be injected simultaneously to further increase safe operating time.

[0046] Optionally, determining the gas plug to be pumped into the wellbore based on the length of the gas plug pumping section includes: obtaining the wellbore size and drill pipe outer diameter; and determining the gas plug to be pumped into the wellbore based on the wellbore size, the drill pipe outer diameter, and the length of the gas plug pumping section.

[0047] Wherein, the air stagnation block satisfies:

[0048]

[0049] Where V2 is the gas sludge plug injected into the wellbore, and D b d is the wellbore size; d is the drill pipe outer diameter; L1 is the length of the section into which the gas plug is pumped.

[0050] Step S202: Calculate the length of the sleeve string that needs to be pre-installed to prevent the sleeve from rising and calculate the number of centralizers to be installed.

[0051] It should be understood that if a blowout occurs during casing installation, or if a rotating control head is installed at the wellhead, casing pressure is generated in the annulus, creating an upward force on the casing string inside the well. This upward force is the force generated by the difference between formation pressure and drilling fluid column pressure acting on the cross-sectional area of ​​the casing, pushing the entire drill string inside the well towards the wellhead (e.g., Figure 2 (As shown). In the initial stage of casing running, the casing string is relatively light, and if the upward force exceeds the buoyancy of the casing string, an accident may occur where the drill string is pushed out of the wellhead. To prevent casing from being pushed out, before implementing controlled casing running, a casing string of a certain depth should be pre-run using conventional casing running methods, and then a rotary control head should be installed before implementing controlled casing running operations in the remaining well section.

[0052] Its force is represented as follows:

[0053] F1+F2>F3+F4;

[0054] F1 is the weight of the casing string, kN; F2 is the weight of the drilling fluid inside the casing string, kN; F3 is the buoyancy of the casing string, kN; F4 is the upward force exerted by the annular pressure at the bottom of the casing string on the bottom of the casing, kN. That is:

[0055] qLg×10 -3 +V4ρg×10 -3 >V3ρg×10 -3 +SP t ×10 3 ;

[0056] To prevent casing from overshooting, the casing depth (i.e., the length of the pre-installed casing string) must meet the following conditions:

[0057]

[0058] Where L is the casing string length, m; q is the casing line weight, kN / m; and ρ is the drilling fluid density, kg / m³. 3 V4 is the volume inside the casing, in meters. 3 V3 is the sum of the wall volume and internal volume of the casing, in meters. 3 S2 is the cross-sectional area at the bottom of the sleeve, m 2 ;P t ρ is the annular pressure at the bottom of the casing, MPa; g is the gravity coefficient, N / kg.

[0059] In other words, the length of the casing string to be pre-installed can be calculated as follows: obtain the casing linear weight, the drilling fluid density, the volume inside the casing, the sum of the casing wall volume and the internal volume, the bottom cross-section of the casing, and the bottom annular pressure of the casing; calculate the length of the casing string required to prevent the casing from overshooting based on the casing linear weight, the drilling fluid density, the volume inside the casing, the sum of the casing wall volume and the internal volume, the bottom cross-section of the casing, and the bottom annular pressure of the casing.

[0060] The number of centralizers inserted is proportional to the length of the pre-inserted sleeve string. This ratio can be set based on human experience; no specific limitation is made here.

[0061] Step S203: Determine the conventional casing section based on the casing string length and the number of centralizers installed.

[0062] It should be noted that during controlled casing installation, the rotary control head seals the wellhead, making it impossible to install a centralizer. For horizontal wells, or vertical and directional wells with high requirements for casing centering, a conventional casing installation method must be used to first run a casing string with a centralizer to a certain depth to meet the casing centering requirements of that section. Then, the rotary control head is installed, and controlled casing installation is carried out.

[0063] Before the controlled-pressure casing is lowered, the casing insertion depth must simultaneously meet the requirements for preventing the casing from pushing up and for the number of casing strings to be inserted for the placement of the centralizer.

[0064] Step S204: Determine whether the safe operating time for the conventional casing section is met.

[0065] Step S205: If yes, control the casing to be lowered to the conventional casing section, install the rotary control head, and continue the casing lowering operation.

[0066] In other words, after the conventional casing section is run into the well, a rotary control head is installed to continue the casing running operation.

[0067] In one possible embodiment, after step S204, the method further includes: if the safe operating time for the conventional casing section is not met, then step S201 is executed.

[0068] Step S206: Determine whether gas intrusion occurred during the casing installation.

[0069] Step S207: If gas intrusion occurs, control the pressure of the casing and adjust the bottom hole pressure.

[0070] As one implementation method, the controlled pressure lowering of the casing and regulation of the bottom hole pressure includes: opening the choke valve of the choke manifold to a preset opening to regulate the bottom hole pressure; and continuing to control the pressure lowering of the casing under the adjusted bottom hole pressure.

[0071] As another implementation, the controlled pressure lowering of the casing and regulation of the bottom hole pressure includes: determining a pressure control mode for controlled pressure lowering of the casing, wherein the pressure control mode includes a wellhead pressure control mode and a bottom hole constant pressure control mode; if the pressure control mode is the wellhead pressure control mode, adjusting the opening of the choke valve to make the wellhead pressure tend to the wellhead pressure set value under the wellhead pressure control mode; and continuing to lower the casing under controlled pressure at the wellhead pressure.

[0072] In one possible embodiment, the method further includes: if the pressure control mode is a bottom hole constant pressure control mode, obtaining the bottom hole pressure value and calculating the required wellhead pressure value based on the bottom hole pressure set value under the bottom hole constant pressure control mode; adjusting the opening of the throttle valve to make the wellhead back pressure reach the target wellhead pressure value; and continuing to control the pressure of the casing at the target wellhead pressure value.

[0073] For example, suppose a shallow gas well, XX, has a depth of 1778m, a vertical depth of 1050m, a horizontal section length of 562m, a second-stage wellbore size of 215.9mm, and a drilling fluid density of 1.50g / cm³. 3 The reservoir section in this work area has well-developed fractures and a narrow drilling fluid safety density window, resulting in frequent overflows and leaks, highlighting the conflict between formation stabilization and leakage prevention. During the drilling of the adjacent well's horizontal section, multiple conventional plugging operations and three cementing attempts failed to stabilize the formation; multiple overflows occurred during casing running, requiring four push-kill wells, each of which only lasted about 20 minutes before overflowing again. Well XX employed controlled pressure drilling technology in its horizontal section, with a maximum casing pressure of 4.5 MPa. Drilling to the completed well depth, and using controlled pressure casing running, the Φ139.7mm production casing was successfully run. The implementation process of controlled pressure casing running in Well XX is as follows:

[0074] 1. "Air sludge plug + heavy slurry cap" drilling design:

[0075] Additional compensation for liquid column pressure p t =1.0×10 6 Pa, additional safety pressure p 附 = -0.3 × 10 6 Pa, density of heavy pulp ρ 重 1.8×10 3 The drilling fluid density ρ is 1.5 × 10⁻⁶. 3 , (D is the inner diameter of the casing, 244.5 mm, and d is the outer diameter of the drill pipe, 127 mm). According to the aforementioned formula, we can obtain:

[0076] V1=(1.0×10 6 -0.3×10 6 ) / (1.8×10 3 -1.5×10 3 )*0.034=8.1m 3 ;

[0077] The calculated required pumping density is 1.80 g / cm³. 3 The heavy slurry cap is 8.1m. 3 .

[0078] Simultaneously, gas plugs are pumped to 800m above the gas layer and into the horizontal section (i.e., the 600m to 1778m well section). The pumping volume of the gas plugs is calculated as follows:

[0079]

[0080] 2. Since the maximum casing pressure during normal drilling is 4.5 MPa, according to The required pre-installed casing string depth to prevent casing from jacking up is calculated to be 284.62m; the calculation is as follows:

[0081]

[0082]

[0083] S2 is the cross-sectional area of ​​the bottom of the inserted sleeve. P t = 4.5 MPa; q is the linear weight of the casing, q = 29.79 kg / m; g is the gravity coefficient, g = 9.8 N / kg; ρ is the drilling fluid density, ρ = 1.5 × 10⁻⁶ 3 kg / m 3 .

[0084] 3. To ensure the centering of the horizontal casing section and improve cementing quality, a centralizer is installed on the horizontal casing section of this well. Considering the required casing run-in depth to prevent casing from overrunning, the section using conventional casing running methods is 0–562m.

[0085] 4. The well tripping operation will take approximately 5.1 hours (based on a tripping speed of 350 m / h), the conventional casing installation will take 2.8 hours (based on a casing installation speed of 100 m / h), and the rotary control head bearing installation will take 1 hour (the rotary control head installation time is generally 0.3 to 1 hour; the upper limit is used here). Therefore, the safe operating time before pressure-controlled casing installation should not be less than 8.9 hours. Field testing shows that the safe operating time for the above-mentioned "gas sludge plug + heavy slurry cap" setup is approximately 10.3 hours, which meets the safe operating time requirements for tripping, conventional casing installation, and rotary control head bearing installation.

[0086] 5. After the drilling is completed, switch to the standard casing running procedure, install the centralizer as required, and grout into the casing in a timely manner. When the casing reaches 562m, install the rotary control head to prepare for pressure-controlled casing running.

[0087] 6. When the casing reaches 700m, gas intrusion occurs. Open the throttle valve to approximately 60% opening and switch to controlled pressure casing running procedure. During controlled pressure casing running, the wellhead back pressure control mode is adopted, and the throttle valve opening is dynamically adjusted to control the back pressure at approximately 3MPa.

[0088] 7. During the casing installation process, ignition was performed while throttling and venting, which enabled the smooth installation of the 1171m, Φ139.7mm production casing.

[0089] Please refer to Figure 3 This application also provides another method for controlled-pressure bushing, which specifically includes the following steps:

[0090] Step S301, drilling start-up design of "air sludge plug + heavy slurry cap";

[0091] Step S302, analysis to prevent casing from overshooting;

[0092] Step S303, Analysis of the number of centralizers;

[0093] Step S304: Establish the conventional casing section;

[0094] Step S305: Does the safe operating time for the conventional casing section be met?

[0095] Step S306: If yes, run the casing to the conventional casing running section, install the rotary control head, and continue the casing running operation;

[0096] Step S307: Select pressure control mode;

[0097] Step S308: Control the casing pressure to regulate the bottom hole pressure;

[0098] Step S309: Circulation and cementing operation.

[0099] In other words, the casing is run to the designed well depth, drilling fluid is circulated, and subsequent cementing operations are carried out.

[0100] It should be noted that the above implementation process can be referred to the description of steps S201-S207, and will not be repeated here.

[0101] It should be noted that the above embodiments can be implemented, in whole or in part, by software, hardware (such as circuits), firmware, or any other combination thereof. When implemented using software, the above embodiments can be implemented, in whole or in part, in the form of a computer program product. The computer program product includes one or more computer instructions or computer programs. When the computer instructions or computer programs are loaded or executed on a computer, all or part of the processes or functions described in the embodiments of this application are generated. The computer can be a general-purpose computer, a special-purpose computer, a computer network, or other programmable device. The computer instructions can be stored in a computer-readable storage medium or transmitted from one computer-readable storage medium to another. For example, the computer instructions can be transmitted from one website, computer, server, or data center to another website, computer, server, or data center via wired (e.g., infrared, wireless, microwave, etc.) means. The computer-readable storage medium can be any available medium that a computer can access or a data storage device such as a server or data center that includes one or more sets of available media. The available medium can be a magnetic medium (e.g., floppy disk, hard disk, magnetic tape), an optical medium (e.g., DVD), or a semiconductor medium. A semiconductor medium can be a solid-state drive.

[0102] It should be understood that the term "and / or" in this article is merely a description of the relationship between related objects, indicating that three relationships can exist. For example, A and / or B can represent: A alone, A and B simultaneously, or B alone. A and B can be singular or plural. Additionally, the character " / " in this article generally indicates an "or" relationship between the preceding and following related objects, but it can also represent an "and / or" relationship. Please refer to the context for a more accurate understanding.

[0103] In this application, "at least one" means one or more, and "more than one" means two or more. "At least one of the following" or similar expressions refer to any combination of these items, including any combination of single or multiple items. For example, at least one of a, b, or c can mean: a, b, c, a-b, a-c, b-c, or a-b-c, where a, b, and c can be single or multiple.

[0104] It should be understood that in the various embodiments of this application, the order of the above-mentioned processes does not imply the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of this application.

[0105] Those skilled in the art will recognize that the units and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this application.

[0106] Those skilled in the art will understand that, for the sake of convenience and brevity, the specific working processes of the systems, devices, and units described above can be referred to the corresponding processes in the foregoing method embodiments, and will not be repeated here.

[0107] In the several embodiments provided in this application, it should be understood that the disclosed systems, apparatuses, and methods can be implemented in other ways. For example, the apparatus embodiments described above are merely illustrative; for instance, the division of units is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple units or components may be combined or integrated into another system, or some features may be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection shown or discussed may be through some interfaces; the indirect coupling or communication connection between apparatuses or units may be electrical, mechanical, or other forms.

[0108] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of this embodiment according to actual needs.

[0109] In addition, the functional units in the various embodiments of this application can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit.

[0110] The above description is merely a preferred embodiment of this application and is not intended to limit this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the protection scope of this application. It should be noted that similar reference numerals and letters in the following figures indicate similar items; therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

Claims

1. A method for controlled-pressure bushing installation, characterized in that, The method includes: Pump air sludge plugs and heavy slurry caps into the wellbore; Calculate the length of the casing string that needs to be pre-installed to prevent the casing from pushing upwards, and calculate the number of centralizers to be installed. The conventional casing section is determined based on the casing string length and the number of centralizers installed. Determine whether the safe operating time for the conventional casing section is met; If so, control the casing to be lowered to the conventional casing section, install the rotary control head, and continue the casing lowering operation; Determine whether gas intrusion occurred during the casing installation; If gas intrusion occurs, the casing is lowered under pressure and the bottom hole pressure is regulated; The pumping of gas sludge plugs and heavy slurry caps into the wellbore includes: Calculate the additional liquid column pressure that needs to be compensated and the additional safety pressure; Obtain the density of the heavy slurry, the internal cross-sectional area between the upper casing and the drill pipe, and the density of the drilling fluid; The amount of heavy slurry cap to be pumped into the wellbore is determined based on the fluid column pressure, the additional safety pressure, the density of the heavy slurry, the inner cross-sectional area of ​​the casing, and the drilling fluid density. Determine the length of the gas slack plug pumped into the well section; The gas plug to be pumped into the wellbore is determined based on the length of the gas plug pumping section. The step of determining the gas plug to be pumped into the wellbore based on the length of the gas plug pumping section includes: Obtain wellbore dimensions and drill pipe outer diameter; The gas plug to be pumped into the wellbore is determined based on the wellbore size, the drill pipe outer diameter, and the length of the gas plug pumping section. The calculation of the length of the casing string required to prevent the casing from overshooting includes: The casing linear weight, drilling fluid density, casing internal volume, the sum of casing wall and internal volume, casing bottom cross-section, and casing bottom annular pressure are obtained. The length of the casing string required to prevent the casing from overshooting is calculated based on the casing linear weight, the drilling fluid density, the volume inside the casing, the sum of the casing wall and internal volume, the bottom cross-section of the casing, and the bottom annular pressure of the casing.

2. The method according to claim 1, characterized in that, The heavy slurry cap satisfies: ； Where V1 is the amount of heavy slurry injected into the wellbore; For the liquid column pressure that requires additional compensation; The additional safety pressure (the suction pressure during tripping in is positive; the excitation pressure during casing running is negative); g is the acceleration due to gravity; ρ is the density of the drilling fluid. The density of the heavy slurry is S; S is the inner cross-sectional area between the upper casing and the drill pipe.

3. The method according to claim 1, characterized in that, The air slack valve satisfies: ; Wherein, V2 is the gas sludge plug injected into the wellbore. d is the wellbore size; d is the drill pipe outer diameter; L1 is the length of the section into which the gas plug is pumped.

4. The method according to claim 1, characterized in that, The length of the sleeve string satisfies: ； Where L is the length of the sleeve string; ρ is the weight of the casing; ρ is the density of the drilling fluid; The volume inside the sleeve; This is the sum of the wall volume and the internal volume of the sleeve; This refers to the bottom cross-section of the sleeve; ρ is the annular pressure at the bottom of the casing; g is the gravity coefficient.

5. The method according to claim 1, characterized in that, The controlled pressure control of the casing and regulation of the bottom hole pressure includes: Open the choke valve in the choke manifold to the preset opening to regulate the bottom hole pressure; The casing is continued to be lowered under controlled pressure at the adjusted bottom hole pressure.

6. The method according to claim 1, characterized in that, The controlled pressure control of the casing and regulation of the bottom hole pressure includes: Determine the pressure control mode of the casing under controlled pressure, wherein the pressure control mode includes a wellhead pressure control mode and a bottom hole constant pressure control mode; If the pressure control mode is the wellhead pressure control mode, adjust the throttle valve opening to make the wellhead pressure tend to the wellhead pressure set value under the wellhead pressure control mode. The casing is continued to be lowered under controlled pressure at the wellhead pressure.

7. The method according to claim 6, characterized in that, The method further includes: If the pressure control mode is the bottom hole constant pressure control mode, obtain the bottom hole pressure value, and calculate the required wellhead pressure value based on the bottom hole pressure set value under the bottom hole constant pressure control mode. Adjust the throttle valve opening to bring the wellhead back pressure to the target wellhead pressure value; Continue to lower the casing under controlled pressure at the target wellhead pressure value.

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