US20230121791A1

US20230121791A1 - Pre-emptive jarring apparatus and methods of use thereof

Info

Publication number: US20230121791A1
Application number: US17/503,519
Authority: US
Inventors: Mohammed M. Otaibi
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2021-10-18
Filing date: 2021-10-18
Publication date: 2023-04-20
Also published as: SA122440381B1

Abstract

Methods of preventing stuck pipe include drilling a wellbore with a pipe comprising a multidirectional jarring apparatus. The multidirectional jarring apparatus comprises an internal helical groove that at least partially translates substantially vertical motion to rotational motion. The methods further include measuring a wellbore proximity of the multidirectional jarring apparatus to a sidewall of the wellbore, measuring drilling speed variability, analyzing the wellbore proximity of the multidirectional jarring apparatus to the sidewall of the wellbore and the drilling speed variability, and determining a torque value less than a required operating torque. The methods further include applying a load to the multidirectional jarring apparatus, thereby oscillating the multidirectional jarring apparatus along the internal helical groove to pre-emptively prevent stuck pipe.

Description

BACKGROUND

The present disclosure relates to jarring devices for stuck pipe. More specifically, it relates to jarring devices that pre-emptively apply load to the pipe to prevent stuck pipe.

BRIEF SUMMARY

In accordance with one embodiment of the present disclosure, a method of preventing stuck pipe, comprising: drilling a wellbore with a pipe comprising a multidirectional jarring apparatus, wherein the multidirectional jarring apparatus comprises an internal helical groove that at least partially translates substantially vertical motion to rotational motion; measuring a wellbore proximity of the multidirectional jarring apparatus to a sidewall of the wellbore; measuring drilling speed variability; analyzing the wellbore proximity of the multidirectional jarring apparatus to the sidewall of the wellbore and the drilling speed variability; determining a torque value less than a required operating torque; and applying a load to the multidirectional jarring apparatus, thereby oscillating the multidirectional jarring apparatus along the internal helical groove to pre-emptively prevent stuck pipe.
In accordance with another embodiment of the present disclosure, a method of preventing stuck pipe includes drilling a wellbore with a pipe comprising a multidirectional jarring apparatus, wherein the multidirectional jarring apparatus comprises an internal helical groove that at least partially translates substantially vertical motion to rotational motion; measuring a wellbore proximity of the multidirectional jarring apparatus to a sidewall of the wellbore with a proximity sensor positioned on a sidewall of the multidirectional jarring apparatus; measuring drilling speed variability with a velocity sensor positioned on the sidewall of the multidirectional jarring apparatus proximate to a drillbit; analyzing the wellbore proximity of the multidirectional jarring apparatus to the sidewall of the wellbore and the drilling speed variability; determining a torque value less than a required operating torque; determining the wellbore proximity is less than a required operating proximity; determining an applicable load to apply to the multidirectional jarring apparatus based on the torque value and the wellbore proximity; and applying the applicable load to the multidirectional jarring apparatus, thereby oscillating the multidirectional jarring apparatus along the internal helical groove to pre-emptively prevent stuck pipe.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING

The following detailed description of specific embodiments of the present disclosure can be best understood when read in conjunction with the following drawing, where like structure is indicated with like reference numerals and in which:

FIG. 1 illustrates a jarring system, according to one or more embodiments described in this disclosure.

FIG. 2A illustrates schematic cross section of a multidirectional jarring apparatus, according to one or more embodiments described in this disclosure.

FIG. 2B illustrates schematic cross section of a multidirectional jarring apparatus, according to one or more embodiments described in this disclosure.

FIG. 3 is a block diagram of a control unit for a multidirectional jarring apparatus, according to one or more embodiments described in this disclosure.

DETAILED DESCRIPTION

Jarring mechanisms are conventionally used to produce shocks along the longitudinal axis of the tool (also referred to herein as ‘the longitudinal tool axis’ or simply, ‘the longitudinal axis’) by colliding a plurality of impact surfaces. Typically a first impact surface, often carried on a mandrel and referred to as a “hanimer,” is axially accelerated toward a second impact surface, often referred to as the “anvil.” A release mechanism is used to accelerate the impact surfaces to collision. Embodiments discussed herein below disclose various implementations within the scope of the present disclosure.
As described in the present disclosure, the impact surfaces may be configured to generate rotation, such as through helical segments or by having axially or radially offset impact loads. It should be appreciated that impact surfaces may be placed in any convenient location in the tool. In some embodiments, a plurality of sets of impact surfaces may be placed in multiple locations on the tool, as understood in the art. Several types of constraints utilizing a variety of mechanisms may be employed to collide the impact surfaces. Typically these will fall into one of the following categories: mechanical release, hydraulic release, and hybrid release. Each type stores energy and then releases the energy to jar the tool. While mechanical jars may used in either wireline or drilling contexts, hydraulic jars may be too lengthy to be used in wireline tools or coiled tubing applications, or in some instances of deviated boreholes.
A hydraulic jarring apparatus may employ separate fluid reservoirs with a small passage in a moveable piston for movement of the fluid between. The size of the passage restrains upward movement of a mandrel within a housing while a strain is taken in the pipe string to store potential energy. Once a release position of the piston is reached, the mandrel is allowed to move freely upward. Contraction of the string accelerates the mandrel upward to violently collide a hammer surface on the mandrel against an anvil surface on the housing. In variations, a similar principle may be employed by using a hydraulic valve and a spring.
A mechanical jarring apparatus may include a release mechanism having a spring to resist movement of the mandrel relative to the housing. As the spring is compressed under applied force, the mandrel moves toward a release point. A collet attached to the mandrel may release at the release point, allowing the mandrel accelerate toward a violent collision between the impact surfaces. The mechanism is configured so that the release point is reached when the applied force on the mandrel exceeds a predetermined amount (i.e., the applicable load).
A hybrid jarring apparatus may combine some elements of both mechanical and hydraulic jars. One design utilizes both a slowly metered fluid and a mechanical spring element to resist relative axial movement of the mandrel and a housing. Other examples may use a mechanical brake. The multidirectional jarring apparatus of the present disclosure may include any of the features of conventional jarring apparatuses as described above, while incorporating the
The jarring system of the present disclosure incorporates the combination of a jar operating on a helical groove along with utilizing sensors to pre-emptively prevent stuck pipe, which conventional methods do not address. Specifically, the present disclosure includes a sensor to measure the proximity of the pipe to the wall of the wellbore and a sensor to measure drilling speed variability placed on the end of the jar closer to the drill bit. Measurements from these sensors are then analyzed to determine whether the torque of the pipe and/or the proximity of the multidirectional jarring apparatus to a sidewall of the wellbore are within acceptable values (i.e. required operating values) or outside of acceptable values. If the torque and/or proximity are outside of (i.e. greater than or less than) acceptable values, then a load is applied to the multidirectional jarring apparatus to pre-emptively prevent stuck pipe.
Referring now to FIGS. 1, 2A, and 2B, a jarring system 100 includes a pipe 110 having a longitudinal axis 112 and a multidirectional jarring apparatus 200. The pipe 110 is positioned within a wellbore 102 within a subsurface formation 120. The multidirectional jarring apparatus 200 of the present disclosure may include an internal helical groove 214 along all or a portion of an internal face 212 of a housing 210. The multidirectional jarring apparatus 200 proceeds along a travel path when a load is applied to the multidirectional jarring apparatus 200. In embodiments where the internal helical groove 214 is along all of the internal face 212 of the housing 210, the multidirectional jarring apparatus 200 will proceed along a helical travel path when a load is applied, resulting in an oscillating swaying motion rather than a conventional linear travel path. However, in embodiments where the internal helical groove 214 is along only a portion of the internal face 212 of the housing 210, the travel path of the multidirectional jarring apparatus 200 will include a conventional linear path of motion when the internal helical groove 214 is not engaged when the load is applied. In embodiments, the multidirectional jarring apparatus 200 may proceed along a conventional linear travel path where an upper end 211 of the internal face 212 of the housing 210 does not include the internal helical groove 214 but the multidirectional jarring apparatus 200 will proceed along a helical travel path where a lower end 213 of the internal face 212 includes the internal helical groove 214, thereby placing the multidirectional jarring apparatus 200 at an angle to the longitudinal axis 112. The angle may cause the multidirectional jarring apparatus 200 to move in an oscillating swaying motion rather than the linear direct one axle motion. It is contemplated that the helical motion will generate enough vibrating force to enhance the efficiency of the jarring action.
In embodiments, the upper section of the multidirectional jarring apparatus 200 may be boosted with an accelerator (not shown) or any other element that may amplify the action. It is contemplated that the course of the multidirectional jarring apparatus 200 itself will be deviated along the helical travel path to generate intermittent shifts from one side to the other as it travels the internal helical groove 214. Those of skill in the art will know that the pitch and the diameter of the helical groove may be modified as appropriate based on the size and lengths of the required operation. In embodiments where the upper end 211 of the internal face 212 of the housing 210 does not include the internal helical groove 214, the beginning linear motion may initiate a spiral motion on the lower end 213 of the multidirectional jarring apparatus 200 due to the internal helical groove 214 present on the lower end 213 of the housing 210. This may cause the multidirectional jarring apparatus 200 to bang against the interior of the pipe 110 and vibrate at the same time.
FIGS. 2A and 2B illustrate jarring assembly components in accordance with embodiments of the present disclosure. FIG. 2A shows the housing 210 of the multidirectional jarring apparatus 200, where the housing 210 includes an internal helical groove 214 on the internal face 212. FIG. 2B shows an inner revolving barrel 216. The inner revolving barrel 216 is connected to a mandrel 202 allowing free rotation of the inner revolving barrel 216. The inner revolving barrel 216 may be connected to the mandrel 202 through any known means, such as a coupler. The housing 210 includes a central passage 204 so it can be mounted over the barrel face 219 of the inner revolving barrel 216.
The internal face 212 of the housing 210 is spirally cut in at least one internal helical groove 214. The internal helical groove 214 meshes with groove keys 218 present on the barrel face 219 of the inner revolving barrel 216. As the mandrel 202 and housing 210 move with respect to one another, the meshing of the groove keys 218 with the internal helical groove 214 induces rotational motion. At the end of the path of travel of the impact surface on the free member, the impact surfaces 710 and 712 collide, generating vibration along the pipe 110 and an impact load. In this way, rotational motion about the tool axis is induced.
By operatively connecting the multidirectional jarring apparatus 200 as described above with existing features of conventional jarring assemblies, generating vibrations and impact loads along the longitudinal tool axis 112, jarring operations are improved. Specifically, the enhanced efficiency of the jarring operation stems from the principle of increased and decreased rotational inertia forces which are a function of the combined effects of core object mass and the initial torque applied to the upper part of the jar as well as the generation of linear and rotational torque forces on the different sections of the pipe 110. Through the application of rotational inertial forces in a helical course banging on the pipe 110 and causing intermittent vibrations, the multidirectional jarring apparatus 200 of the present disclosure bolsters conventional longitudinal jarring actions with angular horizontal and helical impacts due to the modified course design of the travel path of the multidirectional jarring apparatus 200.
Referring again to FIG. 1 , the multidirectional jarring apparatus 200 may include a proximity sensor 222 positioned on a sidewall 220 of the multidirectional jarring apparatus 200. Alternatively or additionally, the multidirectional jarring apparatus 200 may include a velocity sensor 224 positioned on the sidewall 220 of the multidirectional jarring apparatus 200 proximate to a drillbit. In embodiments, a control unit 230 may be communicatively coupled to the proximity sensor 222, the velocity sensor 224, and the multidirectional jarring apparatus 200.
Referring to FIG. 3 , certain embodiments of the present disclosure may be implemented with a control unit 230 that is communicably coupled to the multidirectional jarring apparatus 200, the proximity sensor 222, the velocity sensor 224, or combinations thereof. Although the control unit 230 is described as being a single control unit 230, the use of multiple devices and/or systems to perform the functions described herein is contemplated. The control unit 230 includes a processor 232 communicatively coupled to a memory 234. The control unit 230 may be in the well (for example, positioned above the multidirectional jarring apparatus 200), at the rig, or at a remote location. Moreover, the several components of the control unit 230 may be distributed among those locations.
The processor 232 may include any processing component(s), such as a central processing unit or the like, configured to receive and execute computer readable and executable instructions stored in, for example, the memory 234. In the embodiments described herein, the computer readable and executable instructions for controlling the multidirectional jarring apparatus 200 are stored in the memory 234 of the control unit 230. The memory 234 is a non-transitory computer readable memory. The memory 234 may be configured as, for example and without limitation, volatile and/or nonvolatile memory and, as such, may include random access memory (including SRAM, DRAM, and/or other types of random access memory), flash memory, registers, compact discs (CD), digital versatile discs (DVD), and/or other types of storage components.
In the embodiments described herein, the processor 232 of the control unit 230 is configured to provide control signals to (and thereby actuate) the multidirectional jarring apparatus 200. The control unit 230 may also be configured to receive signals from proximity sensor 222 and the velocity sensor 224 and, based on these signals, actuate the multidirectional jarring apparatus 200.
Referring to FIGS. 1-3 , methods of preventing stuck pipe 110 using the multidirectional jarring apparatus 200 are also described. The methods include drilling a wellbore 102 in a subsurface formation 120 with a pipe 110 comprising a multidirectional jarring apparatus 200. The multidirectional jarring apparatus 200 comprises an internal helical groove 214 that at least partially translates motion substantially along the longitudinal axis 112 to rotational motion. The methods further include measuring a wellbore proximity of the multidirectional jarring apparatus 200 to a wellbore sidewall 104 and measuring drilling speed variability. The method further includes analyzing the wellbore proximity of the multidirectional jarring apparatus 200 to the wellbore sidewall 104 and the drilling speed variability. The method further includes at least determining a torque value less than a required operating torque and applying a load to the multidirectional jarring apparatus 200, thereby oscillating the multidirectional jarring apparatus 200 along the internal helical groove 214 to pre-emptively prevent stuck pipe 110. The method may further include producing hydrocarbons from the wellbore 102. In embodiments, the method includes tripping the pipe 110 out of the wellbore 102.
As stated, above the method includes determining a torque value less than a required operating torque. In embodiments, the required operating torque may be, for example, from 50 to 90 rpm, from 50 to 80 rpm, from 50 to 75 rpm, from 50 to 70 rpm, from 50 to 65 rpm, from 50 to 60 rpm, from 50 to 55 rpm, from 55 to 90 rpm, from 55 to 80 rpm, from 55 to 75 rpm, from 55 to 70 rpm, from 55 to 65 rpm, from 55 to 60 rpm, from 65 to 90 rpm, from 65 to 80 rpm, from 65 to 75 rpm, from 65 to 70 rpm, from 70 to 90 rpm, from 70 to 80 rpm, from 70 to 75 rpm, from 75 to 90 rpm, from 75 to 80 rpm, from 80 to 90 rpm, or approximately 80 rpm. The method may additionally include determining the wellbore proximity is less than a required operating proximity. The method may then include determining an applicable load to apply to the multidirectional jarring apparatus 200 based on the torque value, the wellbore proximity, or both.
The applicable loads as described above may include at least two loads, such as a first load and a second load. It is contemplated that the first load may be less than the second load. Specifically, the first load may be applied to pre-emptively prevent a potential stuck pipe 110. For example, if the conditions in the wellbore 102 are relatively close to normal operating conditions, such as if the torque value is from 71% to 80% of the required operating torque and/or the wellbore proximity is from 71% to 80% of the required operating proximity, but a stuck pipe 110 has not yet been detected, the first load may be applied. Therefore, the method may include applying the first load if the torque value is from 71% to 80% of the required operating torque, the wellbore proximity is from 71% to 80% of the required operating proximity, or both. In embodiments, the first load may be applied if the torque value is from 71% to 80%, from 71% to 75%, or from 75% to 80% of the required operating torque. In embodiments, the first load may be applied if the wellbore proximity is from 71% to 80%, from 71% to 75%, or from 75% to 80% of the required operating proximity.
As previously described, the second load may be greater than the first load. The first load may be applied when wellbore 102 conditions are relatively close to normal operating conditions and the second load may be applied when drilling conditions are slightly more severe. For example, the method may include applying the second load if the torque value is from 56% to 70% of the required operating torque, the wellbore proximity is from 56% to 70% of the required operating proximity, or both. A stuck pipe 110 may or may not have been detected in these circumstances, so applying the second load may pre-emptively avoid a stuck pipe 110. In embodiments, the second load may be applied if the torque value is from 56% to 70%, from 56% to 65%, from 56% to 60%, from 60% to 70%, from 60% to 65%, or from 65% to 70% of the required operating torque. In embodiments, the second load may be applied if the wellbore proximity is from 56% to 70%, from 56% to 65%, from 56% to 60%, from 60% to 70%, from 60% to 65%, or from 65% to 70% of the required operating proximity.
In embodiments, the applicable loads may further include a third load. The third load may be greater than both the second load and the first load. Although the first and second loads may be applied before a stuck pipe 110 has occurred, if the third load is applied it is likely that a stuck pipe 110 has occurred. The method may include applying the third load if the torque value is from 0% to 55% of the required operating torque, the wellbore proximity is from 0% to 55% of the required operating proximity, or both. In embodiments, the third load may be applied if the torque value is from 0% to 55%, from 0% to 50%, from 0% to 45%, from 0% to 40%, from 0% to 35%, from 0% to 30%, from 0% to 25%, from 0% to 20%, from 0% to 15%, from 0% to 10%, from 0% to 5%, from 0% to 1%, from 1% to 55%, from 1% to 50%, from 1% to 45%, from 1% to 40%, from 1% to 35%, from 1% to 30%, from 1% to 25%, from 1% to 20%, from 1% to 15%, from 1% to 10%, from 1% to 5%, from 5% to 55%, from 5% to 50%, from 5% to 45%, from 5% to 40%, from 5% to 35%, from 5% to 30%, from 5% to 25%, from 5% to 20%, from 5% to 15%, from 5% to 10%, from 10% to 55%, from 10% to 50%, from 10% to 45%, from 10% to 40%, from 10% to 35%, from 10% to 30%, from 10% to 25%, from 10% to 20%, from 10% to 15%, from 15% to 55%, from 15% to 50%, from 15% to 45%, from 15% to 40%, from 15% to 35%, from 15% to 30%, from 15% to 25%, from 15% to 20%, from 20% to 55%, from 20% to 50%, from 20% to 45%, from 20% to 40%, from 20% to 35%, from 20% to 30%, from 20% to 25%, from 25% to 55%, from 25% to 50%, from 25% to 45%, from 25% to 40%, from 25% to 35%, from 25% to 30%, from 30% to 55%, from 30% to 50%, from 30% to 45%, from 30% to 40%, from 30% to 35%, from 35% to 55%, from 35% to 50%, from 35% to 45%, from 35% to 40%, from 40% to 55%, from 40% to 50%, from 40% to 45%, from 45% to 55%, from 45% to 50%, or from 50% to 55% of the required operating torque. In embodiments, the third load may be applied if the wellbore proximity from 0% to 55%, from 0% to 50%, from 0% to 45%, from 0% to 40%, from 0% to 35%, from 0% to 30%, from 0% to 25%, from 0% to 20%, from 0% to 15%, from 0% to 10%, from 0% to 5%, from 0% to 1%, from 1% to 55%, from 1% to 50%, from 1% to 45%, from 1% to 40%, from 1% to 35%, from 1% to 30%, from 1% to 25%, from 1% to 20%, from 1% to 15%, from 1% to 10%, from 1% to 5%, from 5% to 55%, from 5% to 50%, from 5% to 45%, from 5% to 40%, from 5% to 35%, from 5% to 30%, from 5% to 25%, from 5% to 20%, from 5% to 15%, from 5% to 10%, from 10% to 55%, from 10% to 50%, from 10% to 45%, from 10% to 40%, from 10% to 35%, from 10% to 30%, from 10% to 25%, from 10% to 20%, from 10% to 15%, from 15% to 55%, from 15% to 50%, from 15% to 45%, from 15% to 40%, from 15% to 35%, from 15% to 30%, from 15% to 25%, from 15% to 20%, from 20% to 55%, from 20% to 50%, from 20% to 45%, from 20% to 40%, from 20% to 35%, from 20% to 30%, from 20% to 25%, from 25% to 55%, from 25% to 50%, from 25% to 45%, from 25% to 40%, from 25% to 35%, from 25% to 30%, from 30% to 55%, from 30% to 50%, from 30% to 45%, from 30% to 40%, from 30% to 35%, from 35% to 55%, from 35% to 50%, from 35% to 45%, from 35% to 40%, from 40% to 55%, from 40% to 50%, from 40% to 45%, from 45% to 55%, from 45% to 50%, or from 50% to 55% of the required operating proximity.
In embodiments, measuring the wellbore proximity includes measuring the wellbore proximity with a proximity sensor 222 positioned on a sidewall 220 of the multidirectional jarring apparatus 200. The proximity sensor 222 may be any proximity sensor 222 known in the art capable of determining the spacing between the sensor and a proximate surface. The proximity sensor 222 may include a sonic and ultrasonic transient time monitoring sensor that is used to measure the proximity of the pipe 110 to the wellbore sidewall 104. Similarly, measuring drilling speed variability may include measuring the drilling speed variability with a velocity sensor 224 positioned on a sidewall 220 of the multidirectional jarring apparatus 200 proximate to a drillbit. The velocity sensor 224 may be any velocity sensor 224 known in the art. In embodiments, the velocity sensor 224 may include sonic velocity sensors 224 where the velocities are measured with a dipole shear imager (DSI). The DSI employs a combination of monopole and dipole transducers to make accurate measurements of sonic wave propagation in a wide variety of lithologies. In addition to compressional wave velocity measurements, the DSI excites a flexural mode in the borehole, which may be used to determine shear wave velocity in all types of formations. The configuration of the DSI also allows recording of cross-line dipole waveforms, which can be used to estimate shear wave splitting caused by preferred mineral and/or structural orientations in consolidated formations. A low-frequency source enables Stoneley waveforms to be acquired as well. These “guided” waves are associated with the solid/fluid boundary at the borehole wall and their amplitude exponentially decays away from the boundary in both the fluid and the formation. The velocity sensor 224 measures the real time drilling speed and monitors any drilling speed variation as compared to the expected drilling speed. These measurements are communicated to the control unit 230 which determines if there is any deceleration in drilling speed, indicating the possibility of stuck pipe conditions. Specifically, measurements from the velocity sensor 224 are analyzed to determine the current torque on the pipe 110.
In embodiments where the multidirectional jarring apparatus 200 comprises a proximity sensor 222 positioned on a sidewall 220 of the multidirectional jarring apparatus 200, the multidirectional jarring apparatus 200 comprises a velocity sensor 224 positioned on the sidewall 220 of the multidirectional jarring apparatus 200 proximate to a drillbit, and a control unit 230 is communicatively coupled to the proximity sensor 222, the velocity sensor 224, and the multidirectional jarring apparatus 200, the applicable load may be determined and applied to the multidirectional jarring apparatus 200 by the control unit 230.
The proximity and velocity sensors 224 as previously described may be powered through any known downhole protocols to send signals via a transmitter to the control unit 230 above the multidirectional jarring apparatus 200. The control unit 230 processes the information coming both from the velocity and proximity sensors 222 and would the actuate the pistons and hold the spring system above the jar at the applicable load position with specially designed clamps that would keep the spring at the desired position with the applicable load.
It is noted that recitations herein of a component of the present disclosure being “configured” in a particular way, to embody a particular property, or to function in a particular manner, are structural recitations, as opposed to recitations of intended use. More specifically, the references herein to the manner in which a component is “configured” denotes an existing physical condition of the component and, as such, is to be taken as a definite recitation of the structural characteristics of the component.
For the purposes of describing and defining the present invention it is noted that the term “substantially” is utilized herein to represent the inherent degree of uncertainty that may be attributed to any quantitative comparison, value, measurement, or other representation. The term “substantially” is also utilized herein to represent the degree by which a quantitative representation may vary from a stated reference without resulting in a change in the basic function of the subject matter at issue.
Having described the subject matter of the present disclosure in detail and by reference to specific embodiments thereof, it is noted that the various details disclosed herein should not be taken to imply that these details relate to elements that are essential components of the various embodiments described herein, even in cases where a particular element is illustrated in each of the drawings that accompany the present description. Further, it will be apparent that modifications and variations are possible without departing from the scope of the present disclosure, including, but not limited to, embodiments defined in the appended claims. More specifically, although some aspects of the present disclosure are identified herein as preferred or particularly advantageous, it is possible that the present disclosure is not necessarily limited to these aspects.
It is noted that one or more of the following claims utilize the term “wherein” as a transitional phrase. For the purposes of defining the present invention, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.”

Claims

What is claimed is:

1. A method of preventing stuck pipe, comprising:

drilling a wellbore with a pipe comprising a multidirectional jarring apparatus, wherein the multidirectional jarring apparatus comprises an internal helical groove that at least partially translates motion substantially along the longitudinal axis to rotational motion;

measuring a wellbore proximity of the multidirectional jarring apparatus to a sidewall of the wellbore;

measuring drilling speed variability;

analyzing the wellbore proximity of the multidirectional jarring apparatus to the sidewall of the wellbore and the drilling speed variability;

determining a torque value less than a required operating torque; and

applying a load to the multidirectional jarring apparatus, thereby oscillating the multidirectional jarring apparatus along the internal helical groove to pre-emptively prevent stuck pipe.

2. The method of claim 1, wherein measuring the wellbore proximity comprises measuring the wellbore proximity with a proximity sensor positioned on a sidewall of the multidirectional jarring apparatus.

3. The method of claim 1, wherein measuring drilling speed variability comprises measuring the drilling speed variability with a velocity sensor positioned on a sidewall of the multidirectional jarring apparatus proximate to a drillbit.

4. The method of claim 1, wherein:

the multidirectional jarring apparatus comprises a proximity sensor positioned on a sidewall of the multidirectional jarring apparatus;

the multidirectional jarring apparatus comprises a velocity sensor positioned on the sidewall of the multidirectional jarring apparatus proximate to a drillbit; and

a control unit is communicatively coupled to the proximity sensor, the velocity sensor, and the multidirectional jarring apparatus.

5. The method of claim 1, further comprising determining the wellbore proximity is less than a required operating proximity.

6. The method of claim 5, further comprising determining an applicable load to apply to the multidirectional jarring apparatus based on the torque value, the wellbore proximity, or both.

7. The method of claim 6, wherein the applicable loads comprise a first load and a second load and the method further comprises:

applying the first load if the torque value is from 71% to 80% of the required operating torque, the wellbore proximity is from 71% to 80% of the required operating proximity, or both;

and applying the second load if the torque value is from 56% to 70% of the required operating torque, the wellbore proximity is from 56% to 70% of the required operating proximity, or both.

8. The method of claim 7, wherein the applicable loads further comprise a third load and the method further comprises applying the third load if the torque value is from 0% to 55% of the required operating torque, the wellbore proximity is from 0% to 55% of the required operating proximity, or both.

9. The method of claim 7, wherein:

the multidirectional jarring apparatus comprises a velocity sensor positioned on the sidewall of the multidirectional jarring apparatus proximate to a drillbit;

a control unit is communicatively coupled to the proximity sensor, the velocity sensor, and the multidirectional jarring apparatus; and

the applicable load is determined and applied to the multidirectional jarring apparatus by the control unit.

10. The method of claim 1, further comprising producing hydrocarbons from the wellbore.

11. The method of claim 1, further comprising tripping the pipe out of the wellbore.

12. A method of preventing stuck pipe, comprising:

measuring a wellbore proximity of the multidirectional jarring apparatus to a sidewall of the wellbore with a proximity sensor positioned on a sidewall of the multidirectional jarring apparatus;

measuring drilling speed variability with a velocity sensor positioned on the sidewall of the multidirectional jarring apparatus proximate to a drillbit;

determining a torque value less than a required operating torque;

determining the wellbore proximity is less than a required operating proximity;

determining an applicable load to apply to the multidirectional jarring apparatus based on the torque value and the wellbore proximity; and

applying the applicable load to the multidirectional jarring apparatus, thereby oscillating the multidirectional jarring apparatus along the internal helical groove to pre-emptively prevent stuck pipe.

13. The method of claim 12, wherein the applicable loads comprise a first load and a second load and the method further comprises:

14. The method of claim 13, wherein the applicable loads further comprise a third load and the method further comprises applying the third load if the torque value is from 0% to 55% of the required operating torque, the wellbore proximity is from 0% to 55% of the required operating proximity, or both.

15. The method of claim 13, wherein: