Wellbore trip advisor

Abstract

A method for determining a maximum trip speed for tripping a downhole tool string in a wellbore includes obtaining contextual data including wellbore data, tool string data, and drilling fluid data; calculating downhole drilling fluid pressures at a plurality of tool string velocities and accelerations using the obtained contextual data and wellbore hydraulics models; generating an equivalent cyclic density (ECD) isoline along a two-dimensional acceleration and velocity parameter space according to the calculated downhole drilling fluid pressure; and evaluating the ECD isoline using at least one of a formation pore pressure or a formation fracture pressure to generate the maximum trip speed.

Description

[0001] Cross - reference to related applications

[0002] None Background art

[0003] When operating in a wellbore (such as drilling), tripping is an essential activity. Tripping (also known as tripping pipe) is generally defined as the action of pulling a tool string (such as a drill string) out of the wellbore and / or lowering the tool string into the wellbore. Common reasons for tripping include starting and / or completing a section of the wellbore, replacing a worn bit, and replacing a damaged or malfunctioning tool in the string.

[0004] During tripping operations, the moving tool string acts like a piston and causes changes in the fluid pressure in the wellbore. When running in hole, the downward movement of the tool string increases the fluid pressure below the string (known in the industry as surge). When pulling out of hole, the upward movement of the tool string decreases the fluid pressure below the string (known in the industry as swab). If the pressure drops below the pore pressure of the formation or rises above the fracture pressure of the formation, these surge and swab pressures will have a negative impact on well integrity. For example, a well kick is more likely to occur when pulling out of hole.

[0005] Surge and swab effects are generally affected by a variety of variables, including tripping speed, the geometry of the wellbore and the tool string, and various properties of the drilling fluid, such as fluid density and fluid viscosity. Whether the drilling fluid is circulated during tripping also affects surge and swab effects. Tripping is usually carried out with the drilling fluid not circulating, but sometimes circulation is also required. Although hydraulic manuals and software can be used to predict surge and swab pressures, there is still room for further improvement, for example, suggesting safe and timely tripping speeds and accelerations. Brief description of the drawings

[0006] To more fully understand the disclosed subject matter and its advantages, reference is now made to the following description taken in conjunction with the accompanying drawings, in which:

[0007] Figure 1 An exemplary rig including a system for monitoring and / or suggesting tripping operations of a tool string in a wellbore is depicted.

[0008] Figure 2A And Figure 2B (collectively referred to as Figure 2) schematically depicts tripping operations of pulling a drill string out of a wellbore (2A) and lowering the drill string into the wellbore (2B).

[0009] Figure 3 A flowchart of an exemplary method for suggesting and / or monitoring tripping operations is depicted.

[0010] Figure 4A flow chart of another exemplary method for advising and / or monitoring a tripping operation is depicted.

[0011] Figure 5 Depicted is a graph of traveling block position versus time for a hypothetical tripping operation, showing acceleration intervals, constant speed intervals, and deceleration intervals.

[0012] Figure 6A , Figure 6B , Figure 6C and Figure 6D (collectively, FIG. 6 ) depict ECD pressure surge and suction contours for exemplary tripping operations at drilling fluid flow rates of 0, 500, 1000, and 1500 liters per minute.

[0013] Figure 7A and Figure 7B (collectively, FIG. 7 ) depicts trip time ( 7A ) and acceleration ( 7B ) contours and corresponding isotime and isoacceleration contours.

[0014] Figure 8A and Figure 8B (collectively, FIG. 8 ) depicts iso-ECD contours of pressure surge ( 8A) and suction ( 8B) for an exemplary tripping operation with a drilling fluid flow rate of 1500 liters / minute.

[0015] Figure 9A and Figure 9B (collectively, FIG. 9 ) depicts a flow chart of an exemplary method for evaluating ECD contours for exemplary tripping-out operations ( 9A) and tripping-out operations ( 9B).

[0016] Figure 10A and Figure 10B (collectively, FIG. 10 ) depicts iso-ECD and iso-time contours ( 10A) and iso-ECD and iso-acceleration contours ( 10B) in an exemplary pull-out operation at a drilling fluid flow rate of 500 L / min.

[0017] Figure 11A and Figure 11B (collectively, FIG. 11 ) depicts iso-ECD and iso-time contours ( 11A) and iso-ECD and iso-acceleration contours ( 11B) in an exemplary run-in operation at a drilling fluid flow rate of 500 L / min.

[0018] Figure 12A and Figure 12B (collectively, FIG. 12 ) depicts an exemplary pumping ( 12A) and pressure surge ( 12B) advisor for the exemplary tripping operations described above with respect to FIGS. 10 and 11 . DETAILED DESCRIPTION

[0019] Embodiments of the present disclosure include methods and systems for determining a maximum tripping speed for tripping a downhole tool string in a wellbore. In one exemplary embodiment, a method includes obtaining situational data including wellbore data, tool string data, and drilling fluid data; calculating downhole drilling fluid pressures at multiple tool string speeds and accelerations using the obtained situational data and a wellbore hydraulics model; generating equivalent circulating density (ECD) contour lines along a two-dimensional acceleration and speed parameter space based on the calculated downhole drilling fluid pressures; and evaluating the ECD contour lines using at least one of a formation pore pressure or a formation fracture pressure to generate the maximum tripping speed.

[0020] Figure 1 An exemplary rig 20 is depicted that includes a system 60 for monitoring and / or advising on tripping operations of a tool string in a wellbore. The rig 20 may be positioned above a subterranean formation (not shown) and may be configured to drill a geothermal well or a hydrocarbon exploration and / or production well. The rig 20 may include, for example, a derrick and hoisting equipment (also not shown) for raising and lowering a drill string 30, which, as shown, extends into a wellbore 40 and includes a bottomhole assembly 50, which may also include, for example, a drill bit 32, a steering tool 34 (such as a rotary steering tool), a logging-while-drilling (LWD) tool 36, and a measurement-while-drilling (MWD) tool 38. It should be understood that the disclosed embodiments are not limited to any particular drill string or BHA configuration, or even to tripping a drill string. The disclosed embodiments are equally applicable to tripping substantially any tool string, including, for example, a completion string or a production string.

[0021] The wellbore 40 may be formed in a subterranean formation by rotary drilling or sliding drilling in a manner known to those skilled in the art (e.g., via known directional drilling techniques). For example, the drill string 30 may be rotated at the surface and / or via a downhole-deployed mud motor to drill the well. A pump may deliver drilling fluid into the interior of the drill string 30 such that the drilling fluid flows downward through the drill string 30. The drilling fluid exits the drill string 30, for example, via ports in the drill bit 32 and then circulates upward through the annulus 42 between the exterior of the drill string 30 and the wall of the wellbore 40. In this known manner, the drilling fluid lubricates the drill bit 32 and carries formation cuttings to the surface. The drilling fluid then typically flows through return piping and solids control equipment to a mud pit (not shown), where the drilling fluid is recovered. It should be understood that the terms drilling fluid and mud are used synonymously herein.

[0022] Those of ordinary skill in the art will readily understand that during a drilling operation (or other downhole operations), it may sometimes be necessary to pull out and lower back into the wellbore 40 a drill string (or other tool string). For example, a drill string may be lowered into the wellbore at the start of a drilling operation and pulled out of the wellbore when the drilling operation is completed. Additionally, the drill string may be pulled out of the wellbore, for example, to replace a worn bit or some other damaged or malfunctioning tool, and then the drill string may be lowered back into the wellbore together with a new or repaired bit or tool. Other tool strings are also commonly lowered into and pulled out of subterranean wellbores. This tripping in and out will be described in more detail below with reference to Figure 2A and Figure 2B More detailed description of this tripping in and out will be provided.

[0023] Various sensors (not shown) may be located around the wellsite to collect data (or drilling parameters) related to the drilling operation, such as riser pressure, pump pressure, hook load, traveling block height and speed, surface torque, rotary speed, etc. The bottom hole assembly (BHA) 50 may also include downhole sensors disposed in the bit 32, steering tool 34, LWD tool 36, and / or MWD tool 38 to provide information about downhole conditions, such as wellbore pressure, weight on bit, bit torque, wellbore direction or attitude (inclination and azimuth), drill collar rotation speed, tool temperature, annulus temperature, and tool face. These sensors (both surface and downhole) may be configured to provide data to the system 60 to monitor the tripping in and out operation.

[0024] Continuing to refer to Figure 1 , in an exemplary embodiment, the system 60 may advantageously be deployed at the drilling site (e.g., in a field laboratory or on the drill floor). Of course, the disclosed embodiments are not limited in this regard. The system 60 may include computer hardware and software configured to monitor and / or recommend tripping in and out operations of a tool string in the wellbore. To perform these functions, the hardware may include one or more processors (e.g., microprocessors), which may be connected to one or more data storage devices (e.g., hard disk drives or solid state memories). As is known to those of ordinary skill in the art, the processor may also be connected to a network (e.g., to receive various sensor data from networked sensors) or another computer system. It should also be understood that the disclosed embodiments may include processor-executable instructions stored in the data storage device. For example, the executable instructions may be configured to execute method 100 to provide a recommended tripping in and out speed and tripping in and out acceleration. Of course, it should be understood that the disclosed embodiments are not limited to the use or configuration of any particular computer hardware and / or software.

[0025] Figure 2A and Figure 2B(Collectively referred to as Figure 2) schematically depicts the tripping operations of a drill string being pulled out of wellbore 40 (2A) and run into the wellbore (2B). In Figure 2A , as the drill string 30 is being pulled out, it is pulled towards surface 72 and out of wellbore 40. The drilling fluid in annulus 42 moves downward (towards the well bottom) 74 around bit 32 to displace the volume previously occupied by the string. This upward movement of the string 30 (like a piston) causes a decrease in downhole pressure (referred to as swab pressure), which in turn can draw formation fluid into the well. In Figure 2B , as the drill string 30 is being run in, it is pushed downhole 76 into wellbore 42. The fluid in wellbore 42 is forced upward (towards the surface) 78 into annulus 42 to provide volume for the string. This downward movement of the string 30 (like a piston) causes an increase in downhole pressure (referred to as surge pressure), which in turn can damage or fracture the formation. It should be understood that surge and swab pressures can also vary along the length of the drill string, depending on the configuration of the string and local geometry. If these local surge and swab pressures are high enough or low enough, they can cause local formation fracturing (surge) or local formation fluid being drawn into the well (swab).

[0026] The magnitudes of surge and swab pressures are typically affected by a variety of variables, including tripping speed, the geometry of the wellbore and tool string, and various properties of the drilling fluid, such as fluid density and fluid viscosity. For example, increasing the tripping speed typically increases the surge and swab pressures. Similarly, surge and swab pressures typically increase with increasing fluid density and viscosity. Certain downhole tools, such as packers, scrapers, and stabilizers with smaller annular clearances, can also increase the surge and swab pressures.

[0027] During many downhole operations, safety protocols typically require real-time monitoring of downhole pressure to ensure that it is maintained within a predefined pressure window. This pressure monitoring is particularly important in managed pressure drilling and underbalanced drilling operations. Pressure monitoring is also important in offshore operations because the pitching effect can affect the equivalent circulating density at the bottom of the well. During tripping operations, it is typically not possible to measure downhole pressure (because the tool string is being run into or pulled out of the well). Various software applications are used to model downhole pressure, but there is still room for further improvement.

[0028] During tripping in or out (tripping out or tripping in), the pipe string is typically tripped in or out one stand or one drill pipe at a time. For example, during tripping out, the pipe string can be pulled out of the wellbore (POOH) by the length of one stand (e.g., 30 meters), and then the pulled-out stand is disconnected. Then the pipe string is pulled up again, and subsequently the next pulled-out stand is disconnected. And so on until the entire pipe string is removed from the well. This process results in a discontinuous velocity profile. For example, initially the pipe string can be accelerated to an approximately constant velocity, then decelerated and stopped, and then the stand (or drill pipe) is disconnected. The disclosed embodiments are intended to consider the acceleration and velocity of the drilling pipe string during tripping in or out and recommend to the drilling crew an appropriate range of velocities and accelerations to achieve fast and safe tripping in or out.

[0029] Figure 3 FIG. 4 depicts a flowchart of an exemplary method 100 for recommending and / or monitoring tripping operations. Method 100 includes receiving static (contextual) and optional dynamic (transient, real-time) data at 102. The static data may include wellbore / tool string geometry and drilling fluid rheology data. The geometry data can include, for example, wellbore diameter, diameters of individual components in the tool string, etc. The drilling fluid rheology data can include, for example, fluid viscosity, fluid density, and fluid gel strength. The dynamic data may include time series data that includes real-time inputs of drilling fluid pressure (such as riser or pump pressure), drilling fluid flow rate, and bit depth in the wellbore. The bit depth can also be included in the static data, indicating the start, end, or average depth when tripping a stand.

[0030] The received data is input into a hydraulic model and evaluated at 104 using the model to calculate downhole pressures with respect to the acceleration and velocity of the tool string in the wellbore. The downhole pressures can include, for example, downhole surge and swab pressures and / or equivalent circulating density (ECD) in the wellbore. The model can advantageously generate pressures and / or ECDs with respect to the tool string acceleration and velocity, e.g., showing the effect of acceleration and velocity on the pressures and / or ECDs. The model output (e.g., output pressures and / or ECDs) can be compared with known and / or estimated pore pressures and fracture pressures (and other formation properties) to calculate the recommended tripping acceleration and velocity at 106. The recommended acceleration and velocity can include, for example, maximum acceleration and velocity values or a range of acceptable tripping acceleration and velocity values. Optionally, the tool string can be tripped in or out at 108 below the recommended maximum or within the recommended range to facilitate safe tripping operations.

[0031] Further reference Figure 3It will be appreciated that the hydraulic model may be a transient model that advantageously accounts for tool string acceleration and various non-Newtonian fluid effects (such as gelation). For example, the model may be configured to calculate wellbore surge and suction pressure and / or ECD relative to tool string acceleration and velocity based on input static data and optional dynamic data. The model may also be configured to receive dynamic pressure, flow rate, depth, and / or temperature data and update the calculated pressure and / or ECD in real time while tripping (e.g., from one stand to another).

[0032] In an exemplary embodiment, the model can be a transient hydraulic model configured to receive static data and optional real-time measurements (dynamic data) of drilling fluid flow rate and depth, and calculate drilling fluid parameters (e.g., pressure) along the depth of the well and at the surface (e.g., in a riser). In an exemplary embodiment, the model can include a one-dimensional (1D) compressible isothermal model for mud flow through a region that varies with depth. The model can include flow rates within a tool string (e.g., a drill pipe) and a wellbore annulus. The modeled flow path can include flow rates within a tool string (e.g., a drill pipe and a BHA), and can then be associated with flow rates entering the wellbore and entering the annulus at the end of the tool string (e.g., at the drill bit). The model can capture isothermal flow in a wellbore and drill pipe of varying area by changing the cross-sectional area along the length of the string and the wellbore. In an exemplary embodiment, the area can be modeled as a time- and space-varying function to replicate the physical behavior of a moving tool string.

[0033] In certain embodiments, the entire well (or rig) system can be modeled as a coupling between two one-dimensional pipe flow solvers for single-phase flow with appropriate boundary conditions and coupling between them. The equations for the tool string can be written in the reference frame of the string because when the tool string is accelerated, it can be considered to be in a non-inertial reference frame. For flow along the bell joint, a point model of the flow transition from pipe flow to streamlines can be considered, and for circular streamlines, an open channel flow model based on the one-dimensional shallow water equations can be considered along with bypass conditions. In an exemplary embodiment, the model can take into account the compressibility and gelation of the drilling fluid in the well, as well as incompressible drilling fluids with gel effects in open channel flow.

[0034] As described above, the hydraulic model can be configured to calculate downhole pressure relative to the acceleration and velocity of the tool string in the wellbore. In an exemplary embodiment, the hydraulic model can account for acceleration and fluid gelation in the pipeline flow and fluid friction model. For example, the conservation of mass and momentum for isothermal fluid flow in a pipeline can be expressed as follows, where U is a conservative variable vector for mass and momentum, and F is a flux function of the conservative variables, and S 1 and S 2A source term composed of a hydrostatic term and a frictional force and with a geometric gradient.

[0035]

[0036] The source term can be divided into two terms, one of which represents a constant term without a spatial gradient and the other of which has a spatial gradient. The components of the vector can be given as follows:

[0037]

[0038] where ρ represents the density of the fluid, u represents the velocity, p represents the pressure, A represents the average cross-sectional area of the entire unit, h represents the gravitational constant, represents the inclination of the well with respect to the horizontal plane, M in(S,I) represents the point source of mass injection, and sf i and sf o represent the frictional loss terms for the inner and outer parts of the basin. The friction coefficient f can be defined based on the Churchill model and the gel model of the fluid. The velocity of the pipeline written in the equation is V p , where represents the pipeline acceleration.

[0039] The general form of the frictional term based on the Churchill model can be given as follows:

[0040]

[0041]

[0042] where Re is the Reynolds number, A is a coefficient depending on the pipeline roughness, pipeline diameter, and Reynolds number, B is a coefficient depending on the Reynolds number, f i and f o represent the Churchill coefficients for the inner and outer surfaces of the pipeline, and represent the wetted perimeters of the inner and outer surfaces of the pipeline, λ represents the transient gel parameter, and τ 0 , k and n represent the Herschel - Buckley parameters defining the rheology of the fluid. Frictional losses can be defined for the interior of the pipeline / annulus section and the outer edge of the section. The transient gel parameter can be modeled, for example, as follows:

[0043]

[0044] The value of λ is restricted between 1 and the equilibrium value (λ 平衡 ), and α, β represent the gel breakdown and gel formation coefficients. The value 1 is used when the mud is fully gelled, and the value (λ 平衡)。This corresponds to the yield stress value measured by the rheometer. Since it is difficult to measure the gel parameters in real time, the gel parameters can be estimated by calibration through the pump start-stop scenario.

[0045] Now turning to Figure 4 , a flowchart of another exemplary method 120 for monitoring tripping operations is depicted. At 122, situational data is received. As described above with respect to Figure 3 , the situational data can include, for example, wellbore / tool string geometry and drilling fluid rheology data such as wellbore diameter, diameters of individual components in the tool string, drilling fluid viscosity, drilling fluid density, and drilling fluid gel strength. At 124, the expected drilling fluid flow rate is also received. The expected drilling fluid flow rate can include, for example, the expected or measured flow rate during pipe handling, or the expected time series flow rate or flow distribution during pipe handling.

[0046] At 126, a hydraulic model can be run to calculate the fluid pressure (and other parameters such as ECD) during pipe handling at a set of various acceleration and velocity distributions. The model output can be evaluated to generate ECD contour lines at 128 in a parametric two-dimensional acceleration and velocity space. The ECD contour lines can then be evaluated at 130 using the formation pore pressure and fracture pressure to generate a tripping advisory panel indicating the maximum acceptable velocity and / or acceleration (or the acceptable range of tripping speed and acceleration).

[0047] Continuing to refer to Figure 4 , in one exemplary embodiment, the ECD contour lines generated at 128 can be contour lines along the parametric acceleration length and steady-state tripping speed. Referring to Figure 5 , in an exemplary embodiment, it can be assumed that the acceleration distribution of the pipe includes an initial acceleration interval, followed by an approximately constant velocity interval, and then a deceleration interval. For example, in a common tripping operation, the tool string can first be accelerated from zero velocity to an approximately steady-state velocity V and then decelerated back to zero velocity (at the end of the tripping). In the example depicted in Figure 5 , the acceleration interval and deceleration interval are labeled S 0 and S 2 , while the constant velocity interval is labeled S 1 . In certain exemplary embodiments, the acceleration parameter S can be defined such that S = S 0 = S 2 , such that the acceleration parameter defines the acceleration and deceleration distances during pipe handling (e.g., the change in the position of the block during pipe acceleration or deceleration). In such an embodiment (and assuming that the acceleration and deceleration are constant from zero initial velocity to zero initial velocity), the acceleration parameter S can be expressed in terms of the steady-state velocity and acceleration as follows: S = v 2 / 2a, where v represents the steady-state velocity and a represents the magnitude of the acceleration.

[0048] The isocontours calculated at 128 may include, for example, the maximum and minimum ECD values when running or pulling drill pipe out of the wellbore. As described above, in an exemplary embodiment, isocontours may be generated relative to the acceleration length (e.g., expressed as a fraction of the drill pipe length) and the critical or steady-state velocity. Figure 6A 、 Figure 6B 、 Figure 6C and Figure 6D (collectively referred to as Figure 6) depict exemplary ECD isocontours at drilling fluid flow rates of 0, 500, 1000, and 1500 liters per minute. In this particular example, the ECD isocontours are in pounds per gallon (where one pound per gallon (ppg) is equal to approximately 0.11 kilograms per liter). The ECD isocontours are depicted relative to the normalized acceleration parameter S (normalized by the length of the drill pipe) and the steady-state velocity (in meters per second).

[0049] As depicted in Figure 6, the ECDs of the swab 112 and the surge 114 are not symmetric, and the lack of symmetry becomes more pronounced as the circulation rate increases. Although not wishing to be bound by theory, it is believed that the lack of symmetry can be explained by different flow distributions during tripping in and tripping out. When tripping out, a void may be created below the drill string, which is filled by the fluid in the annulus when the flow is small or there is no flow. During circulation, the flow can overcome this void depending on the tripping speed and the flow rate. When tripping in, the flow typically surges in the upward direction, so an obvious void usually does not form. The change in slope with velocity may be due to the transition of the flow from the laminar to the turbulent state.

[0050] As described above with respect to Figure 4 The ECD isocontours, as well as the formation pore pressure and / or fracture pressure, may be evaluated at 130 to generate a tripping advisor that indicates the maximum recommended speed and / or acceleration during tripping in and tripping out. It should be understood that two important objectives during tripping operations are typically to ensure safety and to minimize the time required to trip drill pipe in and out. It should also be understood that these two objectives are often conflicting. For example, minimizing the tripping time may increase the swab and surge pressures and endanger safety. Similarly, maximizing safety by minimizing the swab and / or surge pressures comes at the cost of increasing the tripping time. Achieving an appropriate balance between safety and tripping time can be a difficult and delicate balance.

[0051] Figure 7A and Figure 7B (collectively referred to as Figure 7) depict tripping time (7A) and acceleration (7B) isocontours, as well as the corresponding equal-time and equal-acceleration isocontours plotted relative to the normalized acceleration parameter S and the steady-state velocity.

[0052] Figure 8A and Figure 8B (collectively referred to as Figure 8) depict the equivalent circulating density (ECD) contours for surge (8A) and swab (8B) for an exemplary tripping operation at a drilling fluid flow rate of 1500 liters per minute. In this example, the ECD contours for both swabbing and surging are given by vertical lines. Vertical ECD contours indicate minimal acceleration effects. Deviations from the vertical direction indicate the influence of acceleration on the ECD. In certain tool string configurations, acceleration effects are mainly observed when the steady-state velocity is higher than 1 m / s.

[0053] Figure 9A and Figure 9B (collectively referred to as Figure 9) depict flowcharts of exemplary methods 140 and 160 for evaluating ECD contours for tripping out (9A) and tripping in (9B). In Figure 9A , the formation pore pressure is obtained at 142. The formation pore pressure can be estimated or measured using any suitable technique known to those skilled in the art. A safety buffer or factor can be applied to the formation pore pressure to obtain a range of formation pore pressures at 144, including an upper limit pore pressure and a lower limit pore pressure. The upper limit pore pressure contour and the lower limit pore pressure contour can be determined at 146 with respect to the normalized acceleration parameter S and the steady-state velocity (e.g., plotted together with the ECD contours shown in Figure 8). The upper limit pore pressure contour and the lower limit pore pressure contour can be evaluated at 148 to determine the maximum and minimum velocities for tripping stands (e.g., the velocity range that facilitates safe and timely tripping). The constant acceleration contours can be overlaid with the upper limit pore pressure contour and the lower limit pore pressure contour and evaluated at 150 to determine the maximum and minimum accelerations for tripping stands (e.g., the acceleration range that facilitates safe and timely tripping). The constant time contours can optionally be overlaid with the upper limit pore pressure contour and the lower limit pore pressure contour and evaluated at 152 to determine the maximum and minimum tripping times for the determined velocities and accelerations. At 154, the maximum and minimum velocities, accelerations, and optionally the tripping times can optionally be displayed on a tripping advisor board.

[0054] In Figure 9BIn [the context], the formation fracture pressure can be obtained at 162. The formation fracture pressure can be estimated or measured using any suitable technique known to those skilled in the art. A safety buffer can be applied to the received formation fracture pressure to obtain a formation fracture pressure range at 164, including an upper fracture pressure and a lower fracture pressure. The upper fracture pressure contour and the lower fracture pressure contour can be determined at 166 relative to the normalized acceleration parameter S and the steady-state velocity (e.g., plotted together with the equivalent circulating density (ECD) contours shown in FIG. 8). The upper fracture pressure contour and the lower fracture pressure contour can be evaluated at 168 to determine the maximum and minimum velocities for tripping in and out of the drill pipe (e.g., a velocity range that facilitates safe and timely tripping). The constant acceleration contours can be overlaid with the upper fracture pressure contour and the lower fracture pressure contour and evaluated at 170 to determine the maximum and minimum accelerations for tripping in and out of the drill pipe (e.g., an acceleration range that facilitates safe and timely tripping). The constant time contours can optionally be overlaid with the upper fracture pressure contour and the lower fracture pressure contour and evaluated at 172 to determine the maximum and minimum tripping times for the determined velocities and accelerations. At 174, the maximum and minimum velocities, accelerations, and optionally the tripping times can optionally be displayed on a tripping advisor board.

[0055] Method 140 and 160 are now described in more detail by the following non-limiting examples. Figure 10A and Figure 10B (collectively referred to as FIG. 10) depicts the equivalent circulating density (ECD) 202 and constant time 204 contours (10A) and the ECD 202 and constant acceleration 206 contours (10B) for an exemplary pipe-pulling operation at a drilling fluid flow rate of 500 liters per minute. The upper formation pore pressure contour and the lower formation pore pressure contour are also depicted as thick dashed lines at 212 and 214. Figure 11A and Figure 11B (collectively referred to as FIG. 11) depicts the equivalent circulating density (ECD) 222 and constant time 224 contours (11A) and the ECD 222 and constant acceleration 226 contours (11B) for an exemplary pipe-running operation at a drilling fluid flow rate of 500 liters per minute. The upper formation fracture pressure contour and the lower formation fracture pressure contour are also depicted as thick dashed lines 232 and 234.

[0056] In Figure 10A the maximum and minimum velocities for tripping in and out of the drill pipe can be determined based on the intercepts 242, 244 of the upper pore pressure contour and the lower pore pressure contour with the velocity (tripping velocity) axis. In Figure 10A the maximum and minimum tripping times can also be determined based on the intercepts of the upper pore pressure contour and the lower pore pressure contour with the constant time contours (the intercepts are not shown but occur at approximately 52 seconds and 27 seconds). InFigure 10B In [context], the maximum and minimum accelerations during making and breaking out stands can be determined based on the intercepts 246 and 248 of the upper and lower pore pressure isocontours with the isoa- cceleration isocontours. Note that the theoretical maximum acceleration is at S = 0 (essentially infinite acceleration), however, in practice, it may be more realistic to choose the intercept 246 at S = 1.

[0057] In Figure 11A In [context], the maximum and minimum speeds during making and breaking out stands can be determined based on the intercepts 252 and 254 of the upper and lower fracture pressure isocontours with the velocity (make / break out speed) axis. In Figure 11A In [context], the maximum and minimum make / break out times can also be determined based on the intercepts of the upper and lower fracture pressure isocontours with the isochron isocontours (the intercepts are not shown, but occur at approximately 45 seconds and 23 seconds). Figure 11B In [context], the maximum and minimum accelerations during making and breaking out stands can be determined based on the intercepts 256 and 258 of the upper and lower pore pressure isocontours with the isoa- cceleration isocontours. Note that the theoretical maximum acceleration is at S = 0 (essentially infinite acceleration), however, in practice, it may be more realistic to choose the intercept 256 at S = 1.

[0058] Now turning to Figure 12A and Figure 12B (collectively referred to as Figure 12), which depict an exemplary drawdown (12A) and surging (12B) advisor (or velocimeter) for an exemplary flow rate of 500 liters per minute for the example described above with respect to Figures 10 and 11. In Figure 12A and Figure 12B In [context], the exemplary make / break out advisor includes a visual depiction of the recommended make / break out speed 302, make / break out acceleration 312, and make / break out time 322. The depiction can optionally be pseudo-colored, where the recommended make / break out speed, make / break out acceleration, and make / break out time are depicted in green. The make / break out advisor can also indicate speeds and accelerations above the recommended levels 304, 314 and make / break out times below the recommended make / break out time 324. These can optionally be depicted in red, indicating a potential safety hazard. The make / break out advisor can also indicate speeds below the recommended level 306 and make / break out times above the recommended make / break out time 326. These can optionally be depicted in yellow or orange, indicating that the make / break out may be slower than necessary. Of course, the disclosed embodiments are not limited to any particular make / break out advisor configuration or graphical depiction.

[0059] It should be understood that the present disclosure includes many embodiments. These embodiments include but are not limited to the following embodiments.

[0060] In a first embodiment, a method for determining a maximum tripping speed for tripping a downhole tool string in a wellbore includes obtaining situational data including wellbore data, tool string data, and drilling fluid data; using the obtained situational data and a wellbore hydraulics model to calculate downhole drilling fluid pressures at a plurality of tool string speeds and accelerations; generating equivalent circulating density (ECD) contour lines in a two-dimensional acceleration and speed parameter space based on the calculated downhole drilling fluid pressures; and evaluating the ECD contour lines using at least one of a formation pore pressure or a formation fracture pressure to generate the maximum tripping speed.

[0061] A second embodiment may include the first embodiment, wherein the wellbore data includes a wellbore diameter; the tool string data includes a tool string diameter and a tool string depth; and the drilling fluid data includes a drilling fluid viscosity, a drilling fluid density, and a drilling fluid gel strength.

[0062] A third embodiment may include any one of the first to second embodiments, wherein the ECD contour lines include surge contour lines and swab contour lines.

[0063] A fourth embodiment may include any one of the first to third embodiments, wherein the two-dimensional acceleration and speed parameter space includes a two-dimensionally parameterized acceleration length and a steady-state tripping speed, the two-dimensionally parameterized acceleration length and the steady-state tripping speed being based on a tripping acceleration profile including an initial acceleration interval, a steady-state speed interval, and a deceleration interval.

[0064] A fifth embodiment may include any one of the first to fourth embodiments, wherein evaluating the ECD contour lines further includes generating a maximum tripping acceleration.

[0065] A sixth embodiment may include any one of the first to fifth embodiments, wherein evaluating the ECD contour lines further includes: obtaining a formation pore pressure; applying a safety buffer to the obtained formation pore pressure to obtain an upper limit pore pressure and a lower limit pore pressure; determining an upper limit pore pressure contour line and a lower limit pore pressure contour line; and determining a minimum tripping speed and the maximum tripping speed based on the upper limit pore pressure contour line and the lower limit pore pressure contour line.

[0066] A seventh embodiment may include the sixth embodiment, further including: determining a minimum tripping acceleration and a maximum tripping acceleration based on intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and corresponding constant-acceleration contour lines; or determining a minimum tripping time and a maximum tripping time based on intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and corresponding constant-time contour lines.

[0067] The eighth implementation scheme may include any one of the first to seventh implementation schemes, wherein the evaluation of the ECD contour lines further includes: obtaining the formation fracture pressure; applying a safety buffer to the obtained formation fracture pressure to obtain an upper limit fracture pressure and a lower limit fracture pressure; determining the upper limit fracture pressure contour line and the lower limit fracture pressure contour line; and determining the maximum tripping-in speed and the minimum tripping-in speed according to the upper limit pore pressure contour line and the lower limit pore pressure contour line.

[0068] The ninth implementation scheme may include the eighth implementation scheme, which further includes: determining the maximum tripping-in acceleration and the minimum tripping-in acceleration according to the intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and the corresponding constant acceleration contour lines; or determining the maximum tripping-in time and the minimum tripping-in time according to the intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and the corresponding constant time contour lines.

[0069] The tenth implementation scheme may include any one of the first to ninth implementation schemes, which further includes displaying the maximum tripping speed on the tripping advisor board.

[0070] In the eleventh implementation scheme, a system for tripping a tool string in a wellbore includes a tool string deployed in the wellbore; a processor configured to: receive context data including wellbore data, tool string data, and drilling fluid data; calculate the downhole drilling fluid pressure at multiple tool string speeds and accelerations using the obtained context data and a wellbore hydraulics model; generate equivalent circulating density (ECD) contour lines along a two-dimensional acceleration and speed parameter space according to the calculated downhole drilling fluid pressure; and evaluate the ECD contour lines using at least one of the formation pore pressure or the formation fracture pressure to generate a maximum speed for tripping the tool string; and a tripping advisor board configured to display the maximum tripping speed.

[0071] The twelfth implementation scheme may include the eleventh implementation scheme, wherein the two-dimensional acceleration and speed parameter space includes two-dimensionally parameterized acceleration lengths and steady-state tripping speeds, and the two-dimensionally parameterized acceleration lengths and steady-state tripping speeds are based on a tripping acceleration profile including an initial acceleration interval, a steady-state speed interval, and a deceleration interval.

[0072] The thirteenth implementation scheme may include any one of the eleventh to twelfth implementation schemes, wherein the evaluation of the ECD contour lines further includes generating a maximum tripping acceleration.

[0073] The fourteenth implementation scheme may include any one of the eleventh to thirteenth implementation schemes, wherein the evaluating the ECD isopleth further includes: obtaining a formation pore pressure; applying a safety buffer to the obtained formation pore pressure to obtain an upper limit pore pressure and a lower limit pore pressure; determining an upper limit pore pressure isopleth and a lower limit pore pressure isopleth; and determining a minimum tripping speed and a maximum tripping speed according to the upper limit pore pressure isopleth and the lower limit pore pressure isopleth.

[0074] The fifteenth implementation scheme may include any one of the eleventh to fourteenth implementation schemes, wherein the evaluating the ECD isopleth further includes: obtaining a formation fracture pressure; applying a safety buffer to the obtained formation fracture pressure to obtain an upper limit fracture pressure and a lower limit fracture pressure; determining an upper limit fracture pressure isopleth and a lower limit fracture pressure isopleth; and determining a maximum running speed and a minimum running speed according to the upper limit pore pressure isopleth and the lower limit pore pressure isopleth.

[0075] In the sixteenth implementation scheme, a method for tripping a tool string in a wellbore includes obtaining context data including wellbore data, tool string data, and drilling fluid data; using the obtained context data and a wellbore hydraulics model to calculate downhole drilling fluid pressures at multiple tool string speeds and accelerations; generating equivalent circulating density (ECD) isopleths along a two-dimensional acceleration and speed parameter space according to the calculated downhole drilling fluid pressures; evaluating the ECD isopleths using at least one of a formation pore pressure or a formation fracture pressure to generate a maximum tripping speed and a minimum tripping speed; and tripping the tool string at a speed between the minimum tripping speed and the maximum tripping speed.

[0076] The seventeenth implementation scheme may include the sixteenth implementation scheme, wherein the two-dimensional acceleration and speed parameter space includes a two-dimensionally parameterized acceleration length and a steady-state tripping speed, and the two-dimensionally parameterized acceleration length and the steady-state tripping speed are based on a tripping acceleration profile including an initial acceleration interval, a steady-state speed interval, and a deceleration interval.

[0077] The eighteenth implementation scheme may include any one of the sixteenth to seventeenth implementation schemes, wherein: the evaluating the ECD isopleth further includes generating a maximum tripping acceleration; and the tripping further includes tripping the tool string in the wellbore at an acceleration less than the maximum tripping acceleration.

[0078] The nineteenth implementation may include any one of the sixteenth to eighteenth implementations, wherein the evaluating the ECD contour lines further includes: obtaining a formation pore pressure; applying a safety buffer to the obtained formation pore pressure to obtain an upper limit pore pressure and a lower limit pore pressure; determining an upper limit pore pressure contour line and a lower limit pore pressure contour line; and determining a minimum tripping speed and a maximum tripping speed based on the upper limit pore pressure contour line and the lower limit pore pressure contour line.

[0079] The twentieth implementation may include any one of the seventeenth to nineteenth implementations, wherein the evaluating the ECD contour lines further includes: obtaining a formation fracture pressure; applying a safety buffer to the obtained formation fracture pressure to obtain an upper limit fracture pressure and a lower limit fracture pressure; determining an upper limit fracture pressure contour line and a lower limit fracture pressure contour line; and determining a maximum running speed and a minimum running speed based on the upper limit pore pressure contour line and the lower limit pore pressure contour line.

[0080] Although the wellbore tripping advisor has been described in detail, it should be understood that various changes, substitutions, and alterations may be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.

Claims

1. A method for determining a maximum tripping speed for tripping a downhole tool string in a wellbore, the method comprising: Obtaining contextual data including wellbore data, tool string data, and drilling fluid data; using the acquired scenario data and a wellbore hydraulics model to calculate downhole drilling fluid pressure at multiple tool string velocities and accelerations; Generate equivalent circulation density (ECD) contour lines along the two-dimensional acceleration and velocity parameter space according to the calculated downhole drilling fluid pressure; as well as The ECD contour is evaluated using at least one of a formation pore pressure or a formation fracture pressure to generate the maximum tripping speed.

2. The method according to claim 1, wherein: The wellbore data includes the wellbore diameter; The tool string data includes the tool string diameter and the tool string depth; The drilling fluid data include drilling fluid viscosity, drilling fluid density and drilling fluid gel strength.

3. The method of claim 1, wherein the ECD contours include pressure surge contours and suction contours.

4. The method of claim 1 , wherein the two-dimensional acceleration and velocity parameter space comprises a two-dimensional parameterized acceleration length and a steady-state tripping velocity, wherein the two-dimensional parameterized acceleration length and the steady-state tripping velocity are based on a tripping acceleration distribution comprising an initial acceleration interval, a steady-state velocity interval, and a deceleration interval.

5. The method of claim 1, wherein said evaluating said ECD contour further comprises generating a maximum tripping acceleration.

6. The method of claim 1, wherein said evaluating said ECD contour further comprises: Obtain formation pore pressure; applying a safety buffer to the obtained formation pore pressure to obtain an upper pore pressure limit and a lower pore pressure limit; Determine the upper limit pore pressure contour line and the lower limit pore pressure contour line; as well as The minimum drilling speed and the maximum drilling speed are determined according to the upper limit pore pressure contour line and the lower limit pore pressure contour line.

7. The method according to claim 6, further comprising: Determine the minimum drilling acceleration and the maximum drilling acceleration according to the intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and the corresponding isoacceleration contour lines; or The minimum drilling start time and the maximum drilling start time are determined according to the intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and the corresponding isotime contour lines.

8. The method of claim 1, wherein said evaluating said ECD contour further comprises: Obtaining formation fracture pressure; applying a safety buffer to the obtained formation fracture pressure to obtain an upper fracture pressure and a lower fracture pressure; Determine the upper limit burst pressure contour line and the lower limit burst pressure contour line; as well as The maximum drilling speed and the minimum drilling speed are determined according to the upper limit pore pressure contour line and the lower limit pore pressure contour line.

9. The method according to claim 8, further comprising: Determine the maximum drilling acceleration and the minimum drilling acceleration according to the intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and the corresponding isoacceleration contour lines; or The maximum drilling time and the minimum drilling time are determined according to the intercepts between the upper limit pore pressure contour line and the lower limit pore pressure contour line and the corresponding isotime contour lines.

10. The method of claim 1, further comprising displaying the maximum tripping speed on a tripping advisory board.

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