WO2011153180A2 - Selective control of charging, firing, amount of force, and/or direction of fore of one or more downhole jars - Google PatentsSelective control of charging, firing, amount of force, and/or direction of fore of one or more downhole jars Download PDF
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- WO2011153180A2 WO2011153180A2 PCT/US2011/038665 US2011038665W WO2011153180A2 WO 2011153180 A2 WO2011153180 A2 WO 2011153180A2 US 2011038665 W US2011038665 W US 2011038665W WO 2011153180 A2 WO2011153180 A2 WO 2011153180A2
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- drill string
- command device
- surface command
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B31/00—Fishing for or freeing objects in boreholes or wells
- E21B31/107—Fishing for or freeing objects in boreholes or wells using impact means for releasing stuck parts, e.g. jars
- E21B31/113—Fishing for or freeing objects in boreholes or wells using impact means for releasing stuck parts, e.g. jars hydraulically-operated
SELECTIVE CONTROL OF CHARGING, FIRING,
AMOUNT OF FORCE, AND/OR DIRECTION OF FORCE OF
ONE OR MORE DOWNHOLE JARS
 This application claims priority to U.S. Provisional Application No. 61/351, 177, filed on June 3, 2010, which is incorporated herein by reference in its entirety for all purposes.
 BACKGROUND INFORMATION
 Technical Field
 The present disclosure relates in general to methods of operating downhole jars used during drilling, completing, or producing products from wellbores, for example, but not limited to, wellbores for producing hydrocarbons from subterranean formations, and more particularly to methods of controlling the charging, firing, amount of force, and/or direction of force exerted by one or more downhole jars.
 Background Art
 Drilling jars are tools used to free stuck drill pipe or drill collars (herein referred to generically as "drilling apparatus") by storing energy through application of axial load to an end of the jar, then releasing that energy in rapid motion to jar the pipe free from the point where it is stuck. "Jarring" is the process of trying to free a stuck drill string through delivery of impact loads to the stuck components. Drilling jars aid the process. The jarring direction, impact intensity and jarring times can be controlled from the rig floor. In one known apparatus, two jars are arranged in a series, with collars or drill pipe therebetween, on a drill string. The jars can be selectively fired to effect a stress wave in the wellbore. By using an electronically actuated jar, a series of jars could be set off at slightly different times to maximize the stress wave propagation and impulse.
 So-called "downhole transmission systems" for transmitting power and/or signals from the surface to downhole components (including jars) and vice versa are known. Certain of these known apparatus and methods for integrating transmission cable into the body of selected downhole tools, such as drilling jars, can have variable or changing lengths. Certain wireless systems used in a different context (time-lapsed seismic data acquisition system) are also known.
 Jars are most effective at freeing stuck pipe when located above and yet close to the point where the pipe is stuck. The further the jars are located above the stuck point, the more the jarring force is diminished. Furthermore, as far as is known to the inventors herein, when a jar is below the stuck point the jar cannot be cocked or fired. Even more problematic, however, is that even with the recent capabilities of downhole transmission systems to offer real time data, and even if multiple jar sets are employed in making up a drill string, jars are rarely if ever optimally positioned with respect to the stuck point(s), which of course cannot be known in advance. It would be advantageous if multiple jars could be disposed on a drillstring, and their cocking (charging), firing, amount of force and/or direction of force controlled from the surface in a coordinated manner, to satisfy many drilling and well workover needs, including helping to locate stuck points and accomplish the goal of unsticking stuck drill string components in a logical, efficient manner. The methods of the present disclosure are directed to these needs.
 In accordance with the present disclosure, it has now been determined that one or more of charging, firing, the amount of force exerted, and/or the direction of the forces exerted by multiple downhole jars and/or jar accelerators can be digitally controlled from the surface, and many advantageous operations are available to the driller or well operator that heretofore have not been described.
 These and other needs are addressed in the art by a method of jarring. The method of jarring can include communicating between a surface command device and communication components in two or more jars of a drill string, the drill string comprising a plurality of spaced jars positioned in a corresponding plurality of wired pipe sections; and selectively controlling at least one of charging, firing, amount of force, and direction of force, and two or more of these parameters, of two or more of the jars via at least one of the surface command devices.
 According to various embodiments, the present teachings can also include a method of freeing stuck components of a drill string in a subterranean borehole. The method can include drilling a borehole using the drill string, the drill string comprising a plurality of spaced apart jars and a plurality of wired drill pipe sections, the drill pipe section and jars each comprising electromagnetic components allowing communication at least between the jars and a surface command device; communicating between the surface command device and the communication components in two or more of the jars; and selectively controlling at least one of charging, firing, amount of force, and direction of force, of two or more of the jars via the surface command device.
 According to various embodiments, the present teachings can further include a method of jarring. The method can include communicating between a surface command device and communication components in one or more jars of a drill string, the drill string comprising a plurality of spaced apart jars positioned in a corresponding plurality of wired pipe sections; digitally selectively controlling at least one of charging, firing, amount of force, and direction of force, of one or more of the jars with the surface command device; firing a sub-set or all of the jars in a digitally controlled manner and determining depth of a stuck drill string section through analysis of behavior or performance of the fired jars; and subsequently digitally selectively controlling firing one or more of the jars below the stuck drill string section via the surface command device.
 According to various embodiments, the present teachings can also include a method of jarring. The method can include communicating between a surface command device and communication components in two or more jars of a drill string, the drill string comprising a plurality of spaced apart jars positioned in a corresponding plurality of wired pipe sections; digitally selectively controlling at least one of charging, firing, amount of force, and direction of force, of two or more of the jars via the surface command device; selectively firing, using one or more digitally controlled signals from the surface command device, two or more jars sequenced in time so that their forces meet in one of a constructive and destructive manner at a preselected point in the drill string.
 According to various embodiments, the present teachings can also include a method of jarring including communicating between a surface command device and communication components in one or more jars of a drill string, the drill string comprising a plurality of spaced apart jars positioned in a corresponding plurality of wired pipe sections; selectively controlling at least one of charging, firing, amount of force, and direction of force, of one or more of the jars using the surface command device; charging one or more of the jars from the surface command device by actuating a digitally-controlled valve in the jar which directs hydraulic pressure from within the drill string to charge the jar.
 According to various embodiments, the present teachings can also include a method of jarring including electromagnetically communicating between a surface command device and electromagnetic communication components in one or more jars of a drill string, the drill string comprising a plurality of spaced apart jars positioned in a corresponding plurality of wired pipe sections; and selectively controlling at least one of charging, firing, amount of force, and direction of force, of two or more of the jars using the surface command device; wherein the electromagnetically communicating is selected from the group consisting of i) sending a wireless electromagnetic signal from the surface command device to two or more of the jars, or from two or more jars to the surface command device, ii) sending an electromagnetic signal through wired connections from the surface command device to two or more of the jars, or from two or more of the jars to the surface command device, and iii) combinations thereof.
 As used herein, the term "digital" when applied to the term "signal" means signals that have outputs of only two discrete levels. Examples: 0 or 1, high or low, on or off, true or false. The phrases "digital control" and "digitally controlled signals" mean that controllers used have the advantages and disadvantages of digital controllers. Advantages can include flexibility, multiplicity of function, the ability to make use of advanced design and analysis techniques (as further explained herein), and implementation of hierarchal control schemes. The main disadvantages in digital control are that the signals are sampled and quantized. Also, digital control implies that a model of the system being controlled is available, or may be generated by observing similar processes. The model is used for extracting more information from the process being controlled, and predicting the result of taking certain actions and then being able to choose values of inputs to achieve particular outputs. Digital signals may be selected from electronic (wired and/or wireless), optical, and acoustic (for example, mud-pulse techniques, and through-pipe acoustic signals). Certain methods of this disclosure can include generating a drill string model, including the jars, and using the model to digitally control the cocking, firing, direction, and/or amount of force used in the various jars.
 These and other features of the methods of the disclosure will become more apparent upon review of the brief description of the drawings, the detailed description, and the claims that follow.  BRIEF DESCRIPTION OF THE DRAWINGS
 The manner in which the objectives of this disclosure and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:
 FIGS. 1 and 2 schematically illustrate a downhole transmission network according to the prior art;
 FIGS. 3 through 5, schematically illustrate various embodiments and features of methods in accordance with the present disclosure;
 FIGS. 6 through 15 schematically illustrate non-limiting embodiments of a downhole force generator including a downhole valve (FIGS. 6-7), a force multiplier with hydraulic reservoir and gas chamber (FIGS. 7-9), an energy source (FIG. 10), a lockable latch including a downhole valve, force generator, and energy source (FIG. 11-12), and a serially connected valve, force multiplier, hydraulic reservoir, gas chamber and energy source in assembled form (FIG. 13), and a valve actuator (FIGS. 14-15) useful in methods and apparatus of this disclosure; and
 FIG. 16 illustrates one method of the present disclosure in flowchart form according to exemplary embodiments herein.
 It is to be noted, however, that the appended drawings are not to scale and illustrate only typical embodiments of this disclosure, and are therefore not to be considered limiting of its scope, for the methods and apparatus described may admit to other equally effective embodiments.  DETAILED DESCRIPTION
 In the following description, numerous details are set forth to provide an understanding of the exemplary disclosed methods and apparatus. However, it will be understood by those skilled in the art that the methods and apparatus may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. Identical reference numerals are used throughout the several views for like or similar elements.
 As noted above, it has now been determined, and will be described in the exemplary embodiments herein, that multiple jars can be connected together (either electromagnetically (via wired pipe, or wirelessly connected), optically, or acoustically through mud-pulse or through-pipe communication) to control cocking (charging), firing, adjusting the amount of force, or the directions of force (either applied to and imparted by) of the jars. Multiple jars can be placed in the drillstring, and digital signals can be used to select which jar is to be fired, which direction to jar the pipe, and the amount of force to be exerted by the jars alone or added together, either constructively or destructively. In certain embodiments, the methods can include redirecting hydraulic pressure inside a drill pipe to the jar cocking mechanism using digital command, allowing jars below the stuck point to be cocked and actuated. This same hydraulic mechanism is used in certain embodiments to control the amount of energy the jars will store thereby allowing the force exerted to be digitally controlled from the surface with greater precision than previously possible.
 Digital control of multiple jars can enable firing of two or more jars in synchronization so that jarring forces can be either constructive or destructive when the pulses from multiple jars meet.
 Constructively summed forces can be non-exclusively used to (1) reinforce one with another to deliver stronger impacts at the stuck point; (2) simultaneously apply jarring loads from below and above the stuck point; (3) time-delay the firing of multiple jars one slightly behind the other to deliver a lengthier impulse to the stuck point; and (4) generate buckling loads which will create lateral forces which can dislodge materials that have bridged around the pipe or can be used to lift the pipe away from a point where it is differentially stuck due to wellbore fluid pressures being much greater than formation fluid pressures.
 The firing of two or more jars in a phased sequence can be used to concentrate forces in a particular area of the drill string or to prolong the duration of the application of the force. By configuring the timing sequence of the firing of two or more jars, the drill string can be used to create a buckling load which can in turn be used to lift the drill pipe off of a differentially stuck area or to compact drill cuttings which have packed off around the drill pipe, creating space between the drillpipe and those cutting to allow the operator to re-establish circulation and to restore movement of the pipe so that the hole can be properly cleaned and the drill string safely withdrawn or to continue to drill further.
 The extension of the duration of the firing by using multiple jars fired in sequence can enhance the success of freeing differentially stuck drill pipe. A single firing can begin to free a portion of the interval stuck as the pipe is effectively peeled off the wall of the hole where it is exposed to the differential pressure. However, if the pipe is stuck at multiple sands down the well or over lengthy sand, then the force decays before it can reach those deeper intervals, while the upper portion is working free. By firing in phases or from opposite directions, the energy can be made available to work rapidly on the additional stuck areas.
 Additionally, the jars that are fired can be either on the same side of the stuck point or on opposites of the stuck point which allows forces to be applied to the stuck point from two directions, allowing the problem to be worked from both sides at the same time or by alternating sides, which will be more effective than simply working the stuck point from the top as existing jars work.  Destructively summed forces can be used to create high tension in the drill pipe at the point where the forces meet, which can then be used to separate the pipe at a tool joint thereby eliminating the need to trip wireline into the well to fire a "string" charge to jump a drill pipe connection.
 The depth of a stuck point, points or length of stuck area can be determined by selectively firing a jar or jars at certain depth(s) then monitoring the drill string response at the surface or downhole via accelerometers.
 Jars can also be fired in sequence to concentrate their forces at a particular tool joint which will allow the operator to jump that joint and separate the drill sting into two parts. Traditionally, this has been done with explosives (string shots) to create the force that allow the pin to "jump" a box without damaging the box. Then the operator is able to pull the upper half of the drill string and change components to aid in retrieving the lower stuck sting and then trip back in the well and screw back into the same box and continue the fishing operation. Phased firing can be conducted where one jar above and another below are fired such that the energy arrives at the connection where the operator wants to jump the pin at precisely the same moment.
 Certain method embodiments can include coordinated firing of two or more independent jars in a phased firing arrangement so that energy arrives from two directions at the same time at a particular targeted point in the drill string. Due to the very high speed of the shock wave in the pipe, timing precision may not always be available on digital communication networks used along drillpipe due to noise on the network. An untimely miscommunication due to delays created in the bit checking protocols of the network could create an improper sequence of firings. In accordance with certain exemplary method embodiments, the methods described herein can include synchronizing the firing clocks in the individual jars. The individual clocks can continually synchronize themselves to a network clock and then be instructed to fire themselves at some predetermined time (in some embodiments determined by a signal from the surface, in other embodiments, pre-loaded while making up the drill string) to assure that all bit checking protocols are assured to have been completed before any of the jars are actually fired. In certain embodiments, two or more jars can communicate between each other on the network to ensure that they have all received and understood the same firing time with a checking scheme directly between them.
 Methods of the present disclosure are applicable to both on-shore (land- based) and offshore (subsea-based) drilling.
 In order to better understand the methods of the present disclosure; a discussion of one useable downhole network (or downhole transmission system) is presented in relation to FIGS. 1 and 2. It will be understood that this is but one embodiment of a suitable downhole transmission system useable to carry out the methods of the present disclosure. Referring to FIG. 1, a drill rig 10 may include a derrick 12 and a drill string 14 including multiple sections of drill pipe 16 and other downhole tools. Drill string 14 is typically rotated by drill rig 10 to turn a drill bit 20 that is loaded against the earth 19 to form a borehole 11. Rotation of drill bit 20 may alternately be provided by other downhole tools such as drill motors, or drill turbines (not illustrated) located adjacent to drill bit 20.
 A bottom-hole assembly may include drill bit 20, sensors, and other downhole tools such as logging-while-drilling ("LWD") tools, measurement- while-drilling ("MWD") tools, diagnostic-while-drilling ("DWD") tools, or the like. Other downhole tools may include heavyweight drill pipe, drill collar, stabilizers, hole openers, sub-assemblies, under-reamers, rotary steerable systems, drilling jars, drilling shock absorbers, and the like, which are all well known in the drilling industry. Note that in prior art systems as illustrated, it is not known to utilize multiple jar sets spaced apart in the drill string, as heretofore it would have been a large expense to do so without any return on investment.  While drilling, a drilling fluid is typically supplied under pressure at drill rig 10 through drill string 14. The drilling fluid typically flows downhole through a central bore of drill string 14 and then returns uphole to drill rig 10 through an annulus 9 formed between borehole 11 and drill string 14. Pressurized drilling fluid is circulated around drill bit 20 to provide a flushing action to carry the drilled earth cuttings to the surface.
 FIG. 2 illustrates further features of a prior art downhole transmission system. A downhole network 17 may be used to transmit information along drill string 14. Downhole network 17 may include multiple nodes 18a-e spaced at desired intervals along drill string 14. Nodes 18a-e may be intelligent computing devices, such as routers, or may be less intelligent connection devices, such as hubs, switches, repeaters, or the like, located along the length of network 17. Each of nodes 18 may or may not have a network address. Node 18e may be located at or near the bottom hole assembly. The bottom hole assembly may include drill bit 20, drill collar, and other downhole tools and sensors designed to gather data, perform various functions, or the like.
 Other intermediate nodes 18b-d may be located or spaced along network 17 to act as relay points for signals traveling along network 17 and to interface to various tools or sensors (but not jars) located along the length of drill string 14. Likewise, a top-hole node 18a may be positioned at the top or proximate the top of drill string 14 to interface with an analysis device 26, such as a personal computer 28.
 Communication links 24a-d may be used to connect the nodes 18a-e to one another. Communication links 24a-d may include cables or other transmission media integrated directly into the tools configuring the drill string 14, routed through the central bore of drill string 14, or routed externally to drill string 14. Likewise, in certain embodiments, communication links 24a-d may be wireless connections. In selected embodiments, downhole network 17 may function as a packet-switched or circuit-switched network 17.  To transmit data along drill string 14, packets 22a, 22b may be transmitted between nodes 18a-e. Packets 22b may carry data gathered by downhole tools (but not heretofore jars) or sensors to uphole nodes 18a, or may carry protocols or data necessary to the function of network 17. Likewise, some packets 22a may be transmitted from uphole nodes 18a to downhole nodes 18b-e. For example, these packets 22a may be used to carry control signals or programming data from a top- hole node 18a to tools or sensors interfaced to various downhole nodes 18b-e. Thus, downhole network 17 may provide a high-speed path for transmitting data and information between downhole components and devices located at or near the earth's surface 19, but as yet has not been used as taught herein for methods of jarring including electromagnetically communicating between at least one surface command device and electromagnetic communication components in one or more jars of a drill string comprising a plurality of spaced apart jars positioned in a corresponding plurality of wired pipe sections; and selectively controlling at least one of charging, firing, amount of force, and direction of force, and two or more of these parameters, of one or more of the jars using at least one of the surface command devices.
 As used herein the phrase "surface command device" means an apparatus such as a personal computer, server computer, hand-held computer, laptop computer, and the like, which may have data manipulation, data storage, and data acquisition software, as well as computation algorithms and software models accessible and usable by humans, or by another device accessible by humans, and is does not include surface devices such as pipes, BOPs, pumps, top drives, compressors, rigs, tanks, and other surface or downhole tools.
 Referring now to FIGS. 3, 4 and 5, non-limiting exemplary embodiments of the present disclosure are illustrated. It should be readily apparent to one of ordinary skill in the art that the schematics depicted in FIGS. 3, 4 and 5 represent generalized illustrations and that other components can be added or existing components can be removed or modified. To avoid undue repetition, the embodiments illustrated in FIGS. 3, 4 and 5 can include more than one feature of the methods of the present disclosure, but it will be understood that only one feature need be used to be within the methods of this disclosure.
 Referring first to FIG. 3, embodiment 100 includes a drill string 14 as previously described drilling toward a hydrocarbon-bearing subterranean formation 190, with addition of multiple jars 102a, 102b, and 102c electromagnetically connected through a wired network represented by arrowed lines 108 to a surface device 28, such as a personal computer or server computer. Jars 102a, 102b, and 102c interact with nodes 18b, 18c, and 18d, respectively, in drill string 14. More than three jars 102 can be present, in certain embodiments many more than three. In certain embodiments, one jar 102 can be positioned between adjacent drill string pipe segments 16, but this is not necessary in every embodiment.
 As illustrated schematically in FIG. 3, dashed curved lines representing impact force 106b emanating downward from jar 102b and impact force 106c emanating upward from jar 102c, respectively, can meet constructively (in certain embodiments destructively) at a "stuck point" 104, where drill string 14 is differentially stuck in the wellbore. Stuck point 104 can actually extend several meters axially along drill string 14. In all exemplary embodiments herein, it will be appreciated that the term "point" is not necessarily limiting to a tangential type point, but can include a surface area or region over which a drill pipe is stuck, typically against an inner surface of the wellbore 11. Assuming the location of stuck point 104 was already known, and if the constructive force is great enough, drill string 14 will be freed. In certain embodiments, drill string can be rotated or twisted during application of the jar impact forces, and/or lifted up or pushed down further into wellbore 11. The charging and firing of jars 102 is digitally- controlled by the operator inputting commands into computer 28.
 In certain embodiments, two or more jars may be fired in quick succession. This is illustrated in FIG. 3, wherein jar 102a, creating downward force 106a, can be fired first, then jar 102b, creating downward force 106b is fired next. This technique can be carried on through all jars between jar 102a and stuck point 104, with the firing time of each successive jar time-delayed compared to the previous jar, so that a relatively constant jarring impact force is carried through along the drill string to the stuck point 104. This can be helpful in situations where the exact location of the stuck point, or its length, is uncertain, because the impact force decreases with distance away from the impact.
 The location of the stuck point can be determined by monitoring the reaction of one or more accelerometers 110a, 110b, and 110c, as illustrated in embodiment 200 of FIG. 4. FIG. 4 schematically illustrates an exemplary method embodiment 200 employing a wired network 108, and FIG. 5 schematically illustrates an exemplary method 300 employing a wireless network, indicated by dashed lines 112. Accelerometers 110a, 110b, and 110c are illustrated in FIG. 4 as electromagnetically connected via hard-wire connections to surface device 28 through nodes 18, as indicated by double-headed solid arrows 108. In FIG. 5, accelerometers 110a, 110b, and 110c are illustrated as electromagnetically connected via wireless signals between wireless components in nodes 18 to surface device 28, as indicated by double-headed dashed arrows 112. Electromagnetic wired connections also exist between valves 114a, 114b, and 114c and surface device 28 in embodiment 200, via nodes 18, and in embodiment 300 via wireless electromagnetic signals. Valves 114 allow pressurized fluid in drill pipe 16, such as drilling fluids, to charge (cock or set, or adjust a setting) of a jar 102, and in certain embodiments can fire one or more jars 102.
 Embodiment 300 of FIG. 5 also illustrates that in certain embodiments of this disclosure, one or more, or all of jars 102 can include a jar accelerator 116. As described previously herein, jar accelerators can be useful in shallow well depths, where the shallow depth can limit the available pipe stretch or compression to obtain strong jarring impacts. Friction in high angle and horizontal wells can impede drill string rebound when the jars are tripped, thus damping the jarring impacts. In such embodiments, a "jar accelerator" (sometimes referred to as "jar intensifier" and "jar enhancer" in the art) is placed above the jar. Embodiments wherein the accelerator is placed adjacent the jar, as illustrated in FIG. 5 at 116, or with a few drill collars between the jar and accelerator are intended to be included within the scope of the exemplary embodiments herein. The telescoping accelerator can serve as an elastic spring to store energy until the jar is triggered. When the jar is triggered, the accelerator quickly releases its stored energy and accelerates the hammer of the drilling jar to a relatively high speed. The impact force is related to the square of the velocity, thus, the accelerator greatly increases the hammer force. The spring medium can be steel (mechanical accelerator), compressible oil (hydraulic accelerator) or nitrogen (gas accelerator). Useful jar accelerators for practicing the methods of this disclosure can be single- or double-acting jar accelerators.
 FIGS. 6-15 schematically illustrate exemplary non-limiting embodiments of a downhole force generator including a downhole valve (FIGS. 6-7), a force multiplier with hydraulic reservoir and gas chamber (FIGS. 7-9), an energy source (FIG. 10), a lockable latch including a downhole valve, force generator, and energy source (FIG. 11-12), and a serially connected valve, force multiplier, hydraulic reservoir, gas chamber and energy source in assembled form (FIG. 13), and a valve actuator (FIGS. 14-15) useful in methods and apparatus of this disclosure. It should be readily apparent to one of ordinary skill in the art that the schematics depicted in FIGS. 6-15 represent generalized illustrations and that other components can be added or existing components can be removed or modified.
 Referring to FIGS. 6 A and 6B, the downhole force generator of embodiment 500 can include an outer cylindrical sleeve 502, typically a drill pipe or drill collar, and a series of inner cylindrical sleeves 504, 506, and 508, as well as a valve 514. A force multiplier can also be included, as illustrated schematically in FIG. 7, and which will be described after describing FIGS. 6A and 6B. FIG. 6A schematically illustrates valve 514 in a flow-through position, where drilling fluid 512 may flow through ball valve 514 via a passage formed by a first ball port 528, and an inner passage 509 formed through hollow piston rods 522a, 522b, and 522c, and through piston heads 524a, 524b, and 524c. FIG. 6B illustrates valve 514 in a force-generate position, after a ball member 516 has rotated clockwise about a valve pivot 526. Valve 514 is depicted in this embodiment as a rotatable ball valve, having ball member 516 rotatably positioned in a valve block 518. Ball valve member 516 is actuated upon command (via surface-to-downhole telemetry) by a downhole motor (not illustrated in FIGS 6A and 6B, see FIG. 13 and description) powered by a downhole power source (which may be one or more batteries, or power cables).
 The flow-through position of valve 514 illustrated in FIG. 6A is used during most drilling operations. The force-generate position illustrated in FIG. 6B is created by rotating ball member 516 clockwise 90° from the flow-through position whereupon pressurized drilling fluid is diverted through a second ball valve port 530, through outer passages 510 in sleeves 504, 506, and 508, and then to the force multiplier (FIG. 7). It will be understood that ball member 516 can be made to rotate counter-clockwise, with suitable design changes, to effect the change from the flow-through position to the force-generate position. Upon drilling fluid being forced to flow into outer passages 510, it then traverses into spaces on the under-sides of pistons 524, this in turn causing piston heads 524 to move in cavities 521 (in the illustration of FIG. 6B, to the right). Cavities 521 are defined by internal surfaces 520 of inner cylindrical sleeves 504, 506, and 508 of force generator 500 and by outer surfaces of respective hollow piston rods 522.
 Embodiment 600 of FIG. 7 illustrates the valve and force generator of embodiment 500 in the force-generate position of FIG. 6B, and also illustrates schematically a force multiplier connected in series therewith. The force multiplier can include, in this non-limiting embodiment, a selectable number of power sections threadably attached (threads not shown) in series, each power section including a hollow piston rod 522c, 522d, and 522e, as well as piston heads 524c, 524d. Each piston head 522 can be threadably connected to its respective hollow piston rod, or welded thereto. Piston head 524c slides within inner cylindrical sleeve 532 and piston head 524d slides within inner cylindrical sleeve 534. Another inner cylindrical sleeve 536 completes the embodiment. Each power section (piston rod, piston head, inner cylindrical sleeve combination) of the force multiplier provides a certain piston area upon which fluid pressure is applied thereby generating axial force transmitted along the center shaft. For example, if the piston area is ca. 7.1 in2 (i.e., via a 4-¼" x 3" piston) and 5,000 psi pressure is applied from surface through the drillstring, then each piston develops 35.5 klbf (disregarding friction and other offsetting forces) and 4 power sections (as depicted in FIG. 7) can produce in total 142 klbf. The amount of force generated is selectively controlled by the applied pressure and number of power sections, within reasonable operating limits of all components.
 FIGS. 8 and 8A illustrate the force multiplier of embodiment 600 in greater detail. In this detail of embodiment 600, inner cylindrical sleeve 536 encompasses outer and inner hydraulic fluid cylinders 546 and 547, respectively. A passage 542 allows flow of hydraulic fluid 544 into a hydraulic fluid reservoir 548 defined between hydraulic fluid cylinders 546, 547. A floating piston 550 separates hydraulic fluid reservoir 548 from an inert gas chamber 558 formed between cylinders 546, 547, floating piston 550, and a closed distal end 552 of cylinders 546, 547. Another inner cylindrical sleeve 538 abuts against distal end 552. Appropriate seals 540 are provided, which maintain clean hydraulic fluid from being contaminated by drilling fluid. Hydraulic fluid is displaced by the force generator pistons 524b, 524c, and 524d into hydraulic reservoir 548 appropriately sized to receive the total fluid volume displaced from the total number of force multiplier power sections. Moderate hydraulic fluid pressure is applied against a floating piston 550 over an inert gas charge in gas chamber 558. The gas charge provides a highly compressible volume to limit the rise of hydraulic fluid pressure acting against drilling fluid pressure applied to force generator pistons 524. The gas charge also stores sufficient energy to aid return of force generator pistons 524 to their starting positions. Clean hydraulic fluid serves to lubricate and keep clean the piston bores. Seals 540 are used to achieve required pressure differentials and minimize contamination between drilling and hydraulic fluids. An effective hydraulic seal formed by the outer case 502 around all inner cylindrical sleeves 504, 506, 508, 532, 534, 536, 538, 539, and 541 (the latter two are illustrated in FIG. 11B) is assumed, which in practice can be achieved through appropriately selected and located seal elements (not illustrated). Hydraulic fluid reservoir 548 includes an open-end cap 554, defining an entry/exit passage 556 through which hydraulic fluid is allowed to pass in this embodiment.
 FIGS. 6-8 are schematic illustrations and not meant to suggest relative dimensions. FIGS. 9A and 9B depict an embodiment having rough probable relative dimensions for the various components of force multipliers useful in the methods and apparatus of this disclosure. The 8-¼ inch OD x 5-¼ inch ID of the outer cylindrical sleeve 502 is consistent with a 6-5/8 inch nominal diameter drill pipe tool joint dimensions. Because the assembled apparatus presented herein are typically located in the drillstring, it is important they do not introducing structural weakness into the drill string. The 2-¾ inch flow-through bore 509 is consistent with an 8 inch OD x 2-¾ inch ID 150 lb/ft drill collar dimensions, as it is also important that the assembled apparatus not introduce undue hydraulic or drift ID restrictions in the drillstring.
 FIGS. 10A and 10B schematically illustrate an energy source, in this embodiment a coiled steel spring 560 that has been compressed into a loaded position by the combined action of drilling fluid acting on piston head 524d, which in turn exerts axial force onto hollow piston rod 522e and piston head 524e, compressing spring 560. Piston head 524d also forces hydraulic fluid 544 into reservoir 548. Hydraulic fluid 548 lubricates hollow piston rod 522e as it travels through inner cylinder 547 and through inner cylindrical sleeve 538. Spring 560 can store and releases force created by the force multiplier, described above. In this exemplary embodiment, coiled steel spring 560 is compressed to store energy then controllably released to decompress on demand. Spring 560 is, in this embodiment, centered about hollow piston rod 522f. Upon digitally- controlled decompression of spring 560, piston head 524f exerts a jarring axial force on inner sleeve 539, and piston head 524e exerts a jarring axial force on inner sleeve 538, as illustrated in FIG. 10B, which illustrates the unloaded position of spring 560.
 Referring now to FIGS. 11A, 11B, and 11C, a hydraulic latch is schematically illustrated. A latch is defined in this embodiment as a combination of valve 514, a force generator mechanism, the latter defined by a selected number of inner cylindrical sleeves 504, 506, and 538 and hollow piston rods 522a, 522e, and 522f, and piston heads 524a, 524e, and coil spring 560 in the illustrated embodiment of FIGS. 11A and 1 IB. The latch operates to hold and release coiled spring 560. Latching (or locking) of coil spring 560 is achieved by rotating ball member 516 by 1/8 turn clockwise from the force-generate position, as illustrated in FIG. l lC. A hollow piston rod 522g is guided by inner cylindrical sleeve 541 in this embodiment.
 FIG. 12A is essentially the same as FIG. 11C, and illustrates the position of ball member 516 when coil spring 560 is locked into position. FIG. 12B illustrates how the hydraulic latch is released by further rotating ball member 516 by 1/8 turn clockwise from the locked position, whereupon resistance against the coiled spring 560 is relaxed via release of drilling fluid pressure from the force multiplier. The sliding piston/piston rod assembly 524e/522e rebounds to its starting position whereupon a portion of the stored axial load is transferred from the piston/piston rod 524e/522e to the inner sleeve 538 opposite the direction from which it was created. Ball member 516 is returned to the flow-through position (FIG. 6A) by rotating about 180°.
 FIG. 13 illustrates the valve/latch, force multiplier, hydraulic reservoir and energy source in composite. The components are serially assembled to form one embodiment of a working jar device useful in apparatus and methods of the present disclosure. Coil spring 560 is illustrated in a cocked or loaded position, and can be locked into that position using the ball member 516, as described in reference to FIG. 12.  FIGS. 14A and 14B are schematic axial cross-sectional views of the valve 514 of FIG. 6, illustrating probable relative dimensions of the components. In one view (FIG. 14B) a representation of a DC motor 562 and linear actuator 564 combination are superimposed upon and in approximate relation to the valve cross-section. The DC motor 562 and linear actuator 564 can in certain embodiments be from about 12 to about 18 inches (30 to about 45 centimeters) in length, and can be housed in a separate assembly immediately upstream of the valve. Motor 562 can be battery powered in certain embodiments, or can be served by a power cable in certain other embodiments. DC motor 562 actuates an axially extendable rod 564 suitably geared to the ball pivot 526 to bidirectionally rotate ball member 516 on digital command in angular increments, thereby effecting the required flow-through, force-generate, locked and released positions, as described herein.
 FIGS 15A and 15B are schematic side elevation and front end views, respectively, of a prior art DC motor linear actuator useful in methods and apparatus of the present disclosure. In this embodiment, a DC motor 562 is illustrated connected to a gear box 563, which in turn connects to a housing 566 which houses and guides linear actuator 564. Clevis pins 568 and 570 can be used in certain embodiments to connect the linear actuator to other components in apparatus described herein, such as to an inner cylindrical sleeve. While the DC motor 562 can run on local battery power, an electric power cable 572 can also be provide in certain embodiments, supplying power from the surface, or from anther downhole power source, such as another downhole tool receiving power from the surface.
 In accordance with the present exemplary embodiments, a primary interest lies in digitally controlling, from the surface, the charging, firing, and/or setting the amount of impact force and/or direction of those forces of a plurality of jars positioned along a drill string, in order to more efficiently and effectively free stuck drill strings. The skilled drilling operator or designer will determine which method and apparatus is best suited for a particular well situation and formation to achieve the highest efficiency without undue experimentation.
 In actual operation, the status and/or operation of the jars (and jar accelerators, if present) can be presented in paper format, or more likely today, in electronic format on surface command device 28, or a device communicating with surface command device 28. The change in one or more of the charging, firing, amount of impact force, and direction of impact force of each jar, as well as other parameters, such as mud parameters, drilling parameters, formation parameters, and the like and properties can be tracked, trended, and changed by a human operator (open-loop system) or by an automated system of sensors, controllers, analyzers, pumps, mixers, agitators (closed-loop system).
 Any of the jars and jar accelerators currently in use in the drilling industry can be used in practicing the methods of this disclosure, including bumper jars, mechanical jars, hydraulic jars, mechanical-hydraulic jars, electro-mechanical jars, and so on. The only requirement is that the jars be able to, or can be modified to be able to interface electromagnetically with nodes in wired, wireless, or a combination of wired and wireless downhole transmission networks as described herein. The jar is basically a telescopic slip joint including a hammer, anvil and internal trigger that resists movement until the desired tension or compression has been applied. Potential energy stored in the drill string is suddenly released when the jar fires. The slip joint then accelerates rapidly until it shoulders, delivering an impact blow. A related device called ajar accelerator can be used in combination with a drilling jar to intensify the jarring impact.
 To jar upward, the drill pipe is stretched via an axial tensile load applied at the surface. This tensile force is resisted by the jar trigger mechanism long enough to allow the pipe to stretch and store potential energy. When the jar trips, this stored energy is converted to kinetic energy causing the hammer and anvil to come together rapidly. To jar downward, the pipe weight is slacked off at the surface and, if necessary, additional compressive force is applied to put the pipe in compression. This compressive force is resisted by the jar trigger mechanism to allow the pipe to compress and store potential energy. When the jar trips, the potential energy of the pipe weight and compression is converted to kinetic energy, causing the impact surfaces to come together rapidly. Upon impact, some of the jarring kinetic energy is transmitted to the stuck point. If the resultant force at the stuck point is great enough, the stuck drill string will slide during the impulse period and eventually be freed after a sufficient number of jarring cycles. "Impact" is the initial instantaneous force generated by the jar. "Impulse" is a residual force of the impact, including of reverberations occurring in milliseconds following impact. The objective of a jar is to create a sufficiently strong impact and sufficiently strong and long impulse.
 There are many types of drilling jars, and all may be useful in carrying out methods of this disclosure. The types include, but are not limited to, bumper, mechanical, hydraulic, mechanical-hydraulic, electro-mechanical, and so on. The bumper jar is used primarily to provide a downward jarring force. The bumper jar ordinarily contains a splined joint with sufficient axial travel to allow the pipe to be lifted and dropped, causing the impact surfaces inside the bumper jar to come together to deliver a downward jarring force to the string. Mechanical, hydraulic, mechanical-hydraulic, and electro-mechanic jars differ from the bumper jar in that they contain some type of tripping mechanism which retards the motion of the impact surfaces relative to each other until an axial strain, either tensile or compressive, has been applied to the drill string. Mechanical jars have a mechanical latch mechanism with a preset release force. The release force cannot be adjusted downhole, except for one particular type of mechanical jar whose release force can be adjusted by torque. The jar fires (moves from latched position into the free stroke) as soon as the applied load exceeds the jar release force. Hydraulic drilling jars provide a wide variety of possible triggering loads, determined by the actual tensile or compressive load at the jar. This can be accomplished by a hydraulic mechanism and so-called metering stroke in which oil is forced to flow through a small orifice. At the end of the metering stroke, oil bypasses the orifice causing the hydraulic resistance to drop to a very low value (free stroke). The metering stroke creates a delay time, allowing the jarring operator to set the desired release force. This selective, wide operating range of jar release force is the major advantage of hydraulic jars. Disadvantages can include unintended jar firing during normal drilling operations, long metering times for low overpull, overheating the oil during repeated jarring and risk of overloading the jar during the metering stroke.
 Many hydraulic drilling jars have a disadvantageous ly long metering stroke. The metering stroke is the amount of relative movement between the mandrel and the housing that must occur for the jar to trigger after it is cocked by application of an axial load. When an ordinary hydraulic drilling jar is cocked by application of axial load, fluid is pressurized in a chamber to resist relative movement of the mandrel and the housing. One or more metering orifices in the jar allow the compressed fluid to bleed off at a relatively slow rate. As the fluid is bleeding off, there is some relative axial movement between the mandrel and the housing. The amount of relative axial movement between the mandrel and the housing that occurs after the jar is cocked, but before the jar triggers, is known as bleed off. The bleed off represents lost potential energy that might otherwise be converted to additional jarring force. Many hydraulic drilling jar designs have a relatively long metering stroke of 12 inches of more and, therefore, a significant amount of bleed off. A long metering stroke leads to heat buildup in the hydraulic fluid, which may require costly intervals between firings and lead to degradation of fluid. Electro-mechanical jars utilize a magnetorestrictive material that responds to a predetermined pressure to open one or more orifices in a shoulder of a mandrel to allow rapid pressure communication between the upper and lower chambers.
 Mechanical-hydraulic (aka hydro mechanical) jars are hybrid jars that combine initial mechanical release (to avoid uncontrolled firing) with hydraulic action to provide flexibility and adjustable release force.  In certain embodiments more jarring force than is obtainable from jars alone is desired. Shallow depths can limit the available pipe stretch or compression to obtain strong jarring impacts. Friction in high angle and horizontal wells can impede drill string rebound when the jars are tripped, thus damping the jarring impacts. In such cases a "jar accelerator" (sometimes referred to herein as "jar intensifier") is placed above the jar, normally with a few drill collars between the jar and accelerator. The telescoping accelerator serves as an elastic 'spring' to store energy until the jar is triggered. When the jar is triggered, the accelerator quickly releases its stored energy and accelerates the hammer of the drilling jar to a relatively high speed. The impact force is related to the square of the velocity, thus, the accelerator greatly increases the hammer force. The spring medium can be steel (mechanical accelerator), compressible oil (hydraulic accelerator) or nitrogen (gas accelerator). Jar accelerators can be single- or double-acting.
 Those of ordinary skill in the hydrocarbon exploration and drilling arts will already be familiar with some aspects of wired and wireless downhole networks.
 Wireless systems used in a different context (time-lapsed seismic data acquisition system) are known. Electromagnetic transmission of signals to and from surface command devices and jars, and other optional components such as sensors, may be "completely wireless", wherein all wires, cables, and fibers (such as optical fibers) for communication are substantially eliminated. This does not rule out the use of wires, cables, or optical fibers for example in recording station equipment and jars, for example for power. Wireless systems and methods can offer improvements over systems and methods that use wire or optical fiber for communications in terms of one or more of robustness, scalability, cost, and power-efficiency. Electromagnetic signals can be used to transfer data to and/or from the jars, to transmit power, and/or to receive instructions to charge and/or fire jars.  Systems and methods described in the present disclosure can employ a wireless data network comprising one or more surface command units transmitting commands to one or more surface nodes 18a via first wireless links, which in turn transmit commands to downhole nodes and then jars 102 via second wireless links. Commands can be sent from node to node via wireless links, and, to the extent data is exchanged between nodes and surface command units, wireless links may also be considered part of the wireless data network.
 The first wireless links can be characterized as Wireless Personal-Area Networks (WPAN). A "WPAN" is a personal area network (PAN) using wireless connections. WPAN is currently used for communication among devices such as telephones, computers and their accessories, as well as personal digital assistants, within a short range. The second and third wireless links between nodes can be individually selected from any wireless communication protocol that supports point to multi-point (PMP) broadband wireless access.
 As used in the context of the present disclosure (coordinated charging and firing of downhole jars), the nodes and surface command devices can be compared to a metropolitan area networking (MAN), as given in the 802.16 standard, sometimes referred to as fixed wireless. In fixed wireless, a backbone of base stations is connected to a public network. As with a MAN, each node 18 supports many "fixed subscriber stations" (jars, sensors, and the like), which are akin to either public WiFi hot spots or fire walled enterprise networks. Nodes 18 can use a media access control (MAC) layer, and allocate uplink and downlink bandwidth to "subscribers" (jars, sensors, etc.) as per their individual needs. This is basically on a real-time need basis. The MAC layer is a common interface that makes networks interoperable.
 Systems and methods of this disclosure can include provision of multi- antenna signal processing (MAS) software architectures for implementation of the second and/or third wireless links employing WiMAX. The WiMAX profiles support both adaptive antenna system (AAS) and multiple-input/multiple-output (MIMO) architectures in baseline form.
 "Drilling" as used herein can include, but is not limited to, rotational drilling, directional drilling, non-directional (straight or linear) drilling, deviated drilling, geosteering, horizontal drilling, and the like. Rotational drilling can involve rotation of the entire drill string, or local rotation downhole using a drilling mud motor, where by pumping mud through the mud motor, the bit turns while the drillstring does not rotate or turns at a reduced rate, allowing the bit to drill in the direction it points. A turbodrill may be one tool used in the latter scenario. A turbodrill is a downhole assembly of bit and motor in which the bit alone is rotated by means of fluid turbine which is activated by the drilling mud. The mud turbine is usually placed just above the bit.
 FIG. 16 illustrates an exemplary method 400 of the present disclosure in flowchart form. It should be readily apparent to one of ordinary skill in the art that the method depicted in FIG. 16 represent generalized illustration and that other steps can be added or existing steps can be removed or modified.
 First, as indicated in box 402, the drilling supervisor, probably in conjunction with a mud engineer, geologist or other person in charge can choose downhole network components, jars, and optionally jar accelerators; and assemble the drill string, either on-site or at a site removed from the well.
 In box 404, drilling is then begun, drilling toward a target formation at a known azimuth and dip angle using the selected drilling mud, drill bit, and assembled drill string.
 At box 406, upon sticking of the drill string at one or more unknown locations in the wellbore, locate sticking point using one or more digitally- controlled jars using one or more surface command devices. The step also includes charging selected jars and selecting force magnitude and direction using one or more surface command devices, and firing the jars.
 At box 408, upon locating the sticking point, charge selected jars and select force magnitude and direction using one or more surface command devices.
 At box 410, fire the charged jars using one or more surface command devices, selecting constructive or destructive addition of the forces.
 At box 412, analyze results using one or more surface command devices. If drill string is unstuck, continue drilling. If drill string is not unstuck, repeat steps 408-412 until drill string is unstuck.
 From the foregoing detailed description of specific embodiments, it should be apparent that patentable methods and apparatus have been described. Although specific embodiments of the disclosure have been described herein in some detail, this has been done solely for the purposes of describing various features and aspects of the methods and apparatus, and is not intended to be limiting with respect to the scope of the methods and apparatus. It is contemplated that various substitutions, alterations, and/or modifications, including but not limited to those implementation variations which may have been suggested herein, may be made to the described embodiments without departing from the scope of the appended claims. For example, drilling jars, jar accelerators, and downhole transmission systems other than those specifically described above can be employed, and are considered within the scope of the disclosure.
Priority Applications (2)
|Application Number||Priority Date||Filing Date||Title|
Applications Claiming Priority (4)
|Application Number||Priority Date||Filing Date||Title|
|EP11724902.9A EP2576963A2 (en)||2010-06-03||2011-06-01||Selective control of charging, firing, amount of force, and/or direction of fore of one or more downhole jars|
|AU2011261574A AU2011261574A1 (en)||2010-06-03||2011-06-01||Selective control of charging, firing, amount of force, and/or direction of fore of one or more downhole jars|
|CA2800607A CA2800607A1 (en)||2010-06-03||2011-06-01||Selective control of charging, firing, amount of force, and/or direction of force of one or more downhole jars|
|EA201201575A EA201201575A1 (en)||2010-06-03||2011-06-01||Method of liberation of drilling column components staking in the underground well, and method of use at this jask (options)|
|Publication Number||Publication Date|
|WO2011153180A2 true WO2011153180A2 (en)||2011-12-08|
|WO2011153180A3 WO2011153180A3 (en)||2013-01-03|
Family Applications (1)
|Application Number||Title||Priority Date||Filing Date|
|PCT/US2011/038665 WO2011153180A2 (en)||2010-06-03||2011-06-01||Selective control of charging, firing, amount of force, and/or direction of fore of one or more downhole jars|
Country Status (6)
|US (1)||US20110297380A1 (en)|
|EP (1)||EP2576963A2 (en)|
|AU (1)||AU2011261574A1 (en)|
|CA (1)||CA2800607A1 (en)|
|EA (1)||EA201201575A1 (en)|
|WO (1)||WO2011153180A2 (en)|
Cited By (1)
|Publication number||Priority date||Publication date||Assignee||Title|
|US10294745B2 (en)||2014-04-18||2019-05-21||Halliburton Energy Services, Inc.||Reaction valve drilling jar system|
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|CA2813999C (en)||2010-12-16||2017-04-11||Exxonmobil Upstream Research Company||Communications module for alternate path gravel packing, and method for completing a wellbore|
|US9291019B2 (en)||2011-12-20||2016-03-22||Exxonmobil Upstream Research Company||Systems and methods to inhibit packoff formation during drilling assembly removal from a wellbore|
|US9453388B2 (en) *||2012-04-11||2016-09-27||MIT Innovation Sdn Bhd||Apparatus and method to remotely control fluid flow in tubular strings and wellbore annulus|
|WO2014113025A1 (en) *||2013-01-18||2014-07-24||Halliburton Energy Services, Inc.||Multi-stage setting tool with controlled force-time profile|
|WO2014120873A1 (en) *||2013-01-30||2014-08-07||Schlumberger Canada Limited||Jarring tool|
|WO2014178825A1 (en) *||2013-04-30||2014-11-06||Halliburton Energy Services, Inc.||Jarring systems and methods of use|
|US9631446B2 (en)||2013-06-26||2017-04-25||Impact Selector International, Llc||Impact sensing during jarring operations|
|AU2014302227B2 (en)||2013-06-26||2018-05-17||Impact Selector International, Llc||Downhole-adjusting impact apparatus and methods|
|US9790756B2 (en) *||2013-10-28||2017-10-17||Keith McNeilly||Wireline down jar|
|US9951602B2 (en)||2015-03-05||2018-04-24||Impact Selector International, Llc||Impact sensing during jarring operations|
|US10450859B2 (en)||2015-08-24||2019-10-22||Bitswave Inc.||Mud pulser with vertical rotational actuator|
|CN105927178B (en) *||2016-06-27||2018-07-06||中石化石油工程技术服务有限公司||A kind of cable releasing method|
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|US3955634A (en) *||1975-06-23||1976-05-11||Bowen Tools, Inc.||Hydraulic well jar|
|US4416494A (en) *||1980-10-06||1983-11-22||Exxon Production Research Co.||Apparatus for maintaining a coiled electric conductor in a drill string|
|US4508174A (en) *||1983-03-31||1985-04-02||Halliburton Company||Downhole tool and method of using the same|
|DE3513123C1 (en) *||1985-04-12||1986-08-14||Christensen Inc Norton||Mechanical shears|
|US4688649A (en) *||1985-11-12||1987-08-25||Buck David A||Mechanical drill string jar|
|US4807709A (en) *||1986-10-06||1989-02-28||Pioneer Fishing And Rental Tools, Inc.||Fluid Powered drilling jar|
|US5033557A (en) *||1990-05-07||1991-07-23||Anadrill, Inc.||Hydraulic drilling jar|
|US5086853A (en) *||1991-03-15||1992-02-11||Dailey Petroleum Services||Large bore hydraulic drilling jar|
|US6296066B1 (en) *||1997-10-27||2001-10-02||Halliburton Energy Services, Inc.||Well system|
|US6290004B1 (en) *||1999-09-02||2001-09-18||Robert W. Evans||Hydraulic jar|
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|US7291028B2 (en) *||2005-07-05||2007-11-06||Hall David R||Actuated electric connection|
- 2011-06-01 CA CA2800607A patent/CA2800607A1/en not_active Abandoned
- 2011-06-01 AU AU2011261574A patent/AU2011261574A1/en not_active Abandoned
- 2011-06-01 EA EA201201575A patent/EA201201575A1/en unknown
- 2011-06-01 EP EP11724902.9A patent/EP2576963A2/en not_active Withdrawn
- 2011-06-01 WO PCT/US2011/038665 patent/WO2011153180A2/en not_active Application Discontinuation
- 2011-06-03 US US13/152,484 patent/US20110297380A1/en not_active Abandoned
Cited By (1)
|Publication number||Priority date||Publication date||Assignee||Title|
|US10294745B2 (en)||2014-04-18||2019-05-21||Halliburton Energy Services, Inc.||Reaction valve drilling jar system|
Also Published As
|Publication number||Publication date|
|US7273109B2 (en)||Puller-thruster downhole tool|
|CA2558318C (en)||Providing a local response to a local condition in an oil well|
|CA2599802C (en)||Downhole isolation valve and methods for use|
|AU2003210744B2 (en)||Well system|
|EP0500341B1 (en)||Downhole tool apparatus actuatable by pressure differential|
|CA2382171C (en)||Smart shuttles to complete oil and gas wells|
|US8464794B2 (en)||Wellbore laser operations|
|US6494260B2 (en)||Single trip perforating and fracturing/gravel packing|
|US7121364B2 (en)||Tractor with improved valve system|
|CA2351270C (en)||Drilling method and measurement-while-drilling apparatus and shock tool|
|US7219726B2 (en)||Method and apparatus to vibrate a downhole component|
|CA2358015C (en)||Resonant acoustic transmitter apparatus and method for signal transmission|
|EP0911483B1 (en)||Well system including composite pipes and a downhole propulsion system|
|CA2449506C (en)||Downhole tool|
|US8960296B2 (en)||Complex fracturing using a straddle packer in a horizontal wellbore|
|US6397946B1 (en)||Closed-loop system to compete oil and gas wells closed-loop system to complete oil and gas wells c|
|US20070151732A1 (en)||Downhole impact generator and method for use of same|
|US5180012A (en)||Method for carrying tool on coil tubing with shifting sub|
|US6427786B2 (en)||Electro-hydraulically controlled tractor|
|DE60305733T2 (en)||Drilling a drill|
|AU2013205837B9 (en)||Hydraulic pulse valve with improved pulse control|
|US1892517A (en)||Well drilling apparatus|
|US7836948B2 (en)||Flow hydraulic amplification for a pulsing, fracturing, and drilling (PFD) device|
|US7424922B2 (en)||Rotary valve for a jack hammer|
|CA2824522C (en)||Telemetry operated circulation sub|
|121||Ep: the epo has been informed by wipo that ep was designated in this application||
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