Patent Application
20150129220
Aspects of the disclosure relate to downhole drilling and subsurface investigation. More specifically, aspects of the disclosure relate to a pump actuated jar mechanism for downhole sampling tools.
Tool sticking is a leading source of nonproductive time in field operations for both wireline and drilling operations in the oilfield industry. Typically, when a tool string becomes “stuck” in a borehole, a mechanism called a “jar” is used to dislodge the stuck tool string. The jar is actuated by applying tension to a wireline cable up to approximately one thousand (1000) to three thousand (3000) pounds force above tool weight. Applying this force causes the jar to release under tension and travel freely for approximately 6 inches (15.24 centimeters). The moving portion of the jar impacts the stationary portion of the jar and an impact force is generated. This sudden impact force is transmitted to the tool string in the hopes of freeing the stuck tool. Jar function is similar to slide hammer operations used to remove plugs, pistons and tight tolerance components in industrial applications. The process described above for the jar can be repeated by slacking the cable and allowing the jar to move back 6 inches (15.24 centimeters) of travel at which point a trigger is reset and the process is repeated, applying tension to the cable.
There are several disadvantages to conventional jar systems. First, existing jars are run at the top of the tool string while sampling tools most often become stuck at the probe or packer located near the bottom of the tool string. The rapid attenuation of the jarring force along the length of the tool string means that jars have to be set to a very high jarring force to ensure sufficient force reaches the stuck portion of the tool to free the tool. This high force often results in damage to the tools nearest to the jar. Second, the existing wireline jars depend on the stretch of the cable to provide the potential energy force. This high tension, followed by the release and impact, causes rapid degradation of the wireline cable. Third, conventional jars are excessively long and have significant weight as well as being expensive.
Conventional jars used in drilling apparatus have slightly different configurations, but have similar challenges. The defects of conventional jars limit their usefulness in many applications.
In one example embodiment, an apparatus is presented wherein the apparatus is configured to impart a force on a downhole component, having a piston configured to expand from a movement of a drilling fluid in a downhole environment, a weight configured to move from a first position to a second position, wherein the weight contacts the piston and the piston is configured to move the weight from the first position to the second position when the piston expands from movement of the drilling fluid, a spring configured to contact a bearing surface and the weight, wherein movement of the weight toward the second position compresses the spring; a return spring configured to impart a force on the weight to return the weight to the first position from the second position and a trigger mechanism configured to actuate a return of the weight from the second position to the first position by the return spring. The preceding summary is not intended to limit the scope of the invention, but rather provide but one example embodiment that may be used to accomplish the features and methods described.
In another embodiment, a method for creating a force on a downhole tool is provided having features of pumping a fluid to a downhole location, expanding a piston in the downhole location, an expansion of the piston caused by the fluid entering the piston, moving a weight through the expansion of the piston, the movement of the weight compressing a spring from an uncompressed position to a compressed position, triggering a mechanism such that the weight is allowed to move and the spring returns from the compressed position to the uncompressed position, and impacting the weight upon a surface to deliver a force to a downhole environment.
In accordance with the present disclosure, a wellsite with associated wellbore and apparatus is described in order to describe a typical, but not limiting, embodiment of the application. To that end, apparatus at the wellsite may be altered, as necessary, due to field considerations encountered.
An example well site system is schematically depicted in
Although illustrated with a mud pulse telemetry, the drill string 105 may employ any type of telemetry system or any combination of telemetry systems, such as electromagnetic, acoustic and\or wired drill pipe, however in the preferred embodiment, only the mud pulse telemetry system is used. A bottom hole assembly (“BHA”) is suspended at the end of the drill string 105. In an embodiment, the bottom hole assembly comprises a plurality of measurement while drilling or logging while drilling downhole tools 125, such as shown by numerals 6a and 6b. For example, one or more of the downhole tools 6a and 6b may be a formation pressure while drilling tool.
Logging while drilling (“LWD”) tools used at the end of the drill string 105 may include a thick walled housing, commonly referred to as a drill collar, and may include one or more of a number of logging devices. The logging while drilling tool may be capable of measuring, processing, and/or storing information therein, as well as communicating with equipment disposed at the surface of the well site.
Measurement while drilling (“MWD”) tools may include one or more of the following measuring tools: a modulator, a weight on bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and inclination measuring device, and\or any other device.
Measurements made by the bottom hole assembly or other tools and sensors with the drill string 105 may be transmitted to a computing system 185 for analysis. For example, mud pulses may be used to broadcast formation measurements performed by one or more of the downhole tools 6a and 6b to the computing system 185.
The computing system 185 is configured to host a plurality of models, such as a reservoir model, and to acquire and process data from downhole components, as well as determine the bottom hole location in the reservoir 115 from measurement while drilling data. Examples of reservoir models and cross well interference testing may be found in the following references: “Interpreting an RFT-Measured Pulse Test with a Three-Dimensional Simulator” by Lasseter, T., Karakas, M., and Schweltzer, J., SPE 14878, March 1988. “Design, Implementation, and Interpretation of a Three-Dimensional Well Test in the Cormorant Field, North Sea” by Bunn, G. F., and Yaxley, L. M., SPE 15858, October 1986. “Layer Pulse Testing Using a Wireline Formation Tester” by Saeedi, J., and Standen, E., SPE 16803, September 1987. “Distributed Pressure Measurements Allow Early Quantification of Reservoir Dynamics in the Jene Field” by Bunn, G. F., Wittman, M. J., Morgan, W. D., and Curnutt, R. C., SPE 17682, March 1991. “A Field Example of Interference Testing Across a Partially Communicating Fault” by Yaxley, L. M., and Blaymires, J. M., SPE 19306, 1989. “Interpretation of a Pulse Test in a Layered Reservoir” by Kaneda, R., Saeedi, J., and Ayestaran, L. C., SPE 21337, December 1991.
The drill rig 101 or similar looking/functioning device may be used to move the drill string 105 within the well that is being drilled through subterranean formations of the reservoir, generally at 115. The drill string 105 may be extended into the subterranean formations with a number of coupled drill pipes (one of which is designated 120) of the drill string 105. The drill pipe 120 comprising the drill string 105 may be structurally similar to ordinary drill pipes, as illustrated for example and U.S. Pat. No. 6,174,001, issued to Enderle, entitled “Two-Step, a Low Torque, Wedge Thread for Tubular Connector,” issued Aug. 7, 2001, which is incorporated herein by reference in its entirety, and may include a cable associated with each drill pipe 120 that serves as a communication channel.
The bottom hole assembly at the lower end of the drill string 105 may include one, an assembly, or a string of downhole tools. In the illustrated example, the downhole tool string 105 may include well logging tools 125 coupled to a lower end thereof. As used in the present description, the term well logging tool or a string of such tools, may include at least one or more logging while drilling tools (“LWD”), formation evaluation tools, formation sampling tools and other tools capable of measuring a characteristic of the subterranean formations of the reservoir 115 and\or of the well.
Several of the components disposed proximate to the drill rig 101 may be used to operate components of the overall system. These components will be explained with respect to their uses in drilling the well 110 for a better understanding thereof. The drill string 105 may be used to turn and urge a drill bit 116 into the bottom the well 110 to increase its length (depth). During drilling of the well 110, a pump 130 lifts drilling fluid (mud) 135 from a tank 140 or pits and discharges the mud 135 under pressure through a standpipe 145 and flexible conduit 150 or hose, through a top drive 155 and into an interior passage inside the drill pipe 105. The mud 135 which can be water or oil-based, exits the drill pipe 105 through courses or nozzles (not shown separately) in the drill bit 116, wherein it cools and lubricates the drill bit 116 and lifts drill cuttings generated by the drill bit 116 to the surface of the earth through an annular arrangement.
When the well 110 has been drilled to a selected depth, the well logging tools 125 may be positioned at the lower end of the pipe 105 if not previously installed. The well logging tools 125 may be positioned by pumping the well logging downhole tools 125 down the pipe 105 or otherwise moving the well logging downhole tools 125 down the pipe 105 while the pipe 105 is within the well 110. The well logging tools 125 may then be coupled to an adapter sub 160 at the end of the drill string 105 and may be moved through, for example in the illustrated embodiment, a highly inclined portion 165 of the well 110, which would be inaccessible using armored electrical cable to move the well logging downhole tools 125.
During well logging operations, the pump 130 may be operated to provide fluid flow to operate one or more turbines in the well logging downhole tools 125 to provide power to operate certain devices in the well logging tools 125. When tripping in or out of the well 110, (turning on and off the mud pumps 130) it may be in feasible to provide fluid flow. As a result, power may be provided to the well logging tools 125 in other ways. For example, batteries may be used to provide power to the well logging downhole tools 125. In one embodiment, the batteries may be rechargeable batteries and may be recharged by turbines during fluid flow. The batteries may be positioned within the housing of one or more of the well logging tools 125. Other manners of powering the well logging tools 125 may be used including, but not limited to, one-time power use batteries. A wireline may also power the downhole components.
As the well logging tools 125 are moved along the well 110 by moving the drill pipe 105, signals may be detected by various devices, of which non-limiting examples may include a resistivity measurement device, a bulk density measurement device, a porosity measurement device, a formation capture cross-section measurement device 170, a gamma ray measurement device 175 and a formation fluid sampling tool 610, 710, 810 which may include a formation pressure measurement device 6a and/or 6b. The signals may be transmitted toward the surface of the earth along the drill string 105.
An apparatus and system for communicating from the drill pipe 105 to the surface computer 185 or other component configured to receive, analyze, and/or transmit data may include a second adapter sub 190 that may be coupled between an end of the drill string 105 and the top drive 155 that may be used to provide a communication channel with a receiving unit 195 for signals received from the well logging downhole tools 125. The receiving unit 195 may be coupled to the surface computer 185 to provide a data path therebetween that may be a bidirectional data path.
Though not shown, the drill string 105 may alternatively be connected to a rotary table, via a Kelly, and may suspend from a traveling block or hook, and additionally a rotary swivel. The rotary swivel may be suspended from the drilling rig 101 through the hook, and the Kelly may be connected to the rotary swivel such that the Kelly may rotate with respect to the rotary swivel. The Kelly may be any mast that has a set of polygonal connections or splines on the outer surface type that mate to a Kelly bushing such that actuation of the rotary table may rotate the Kelly.
An upper end of the drill string 105 may be connected to the Kelly, such as by threadingly reconnecting the drill string 105 to the Kelly, and the rotary table may rotate the Kelly, thereby rotating the drill string 105 connected thereto.
Although not shown, the drill string 105 may include one or more stabilizing collars. A stabilizing collar may be disposed within or connected to the drill string 105, in which the stabilizing collar may be used to engage and apply a force against the wall of the well 110. This may enable the stabilizing collar to prevent the drill pipe string 105 from deviating from the desired direction for the well 110. For example, during drilling, the drill string 105 may “wobble” within the well 110, thereby allowing the drill string 105 to deviate from the desired direction of the well 110. This wobble action may also be detrimental to the drill string 105, components disposed therein, and the drill bit 116 connected thereto. A stabilizing collar may be used to minimize, if not overcome altogether, the wobble action of the drill string 105, thereby possibly increasing the efficiency of the drilling performed at the well site and/or increasing the overall life of the components at the wellsite.
Referring to
At a preset extension of the piston 18, the weight 20 and the spring 22 are released and the spring 22 pushes the weight 20 back against the end of the jar 10, creating a jarring event, consequently releasing the energy. Pressure can then be released from the flowline by opening a valve 24 in the packer or probe and the piston 18 returns to the starting position by a second, lower force return spring 30 that has the purpose of pushing the piston 18 back to the start position. The second, lower force return spring 30 is located inside a guide sleeve 31. A trigger mechanism 29 may be used to trigger motion in the jar 10. Such trigger mechanisms 29 are to be considered non-limiting.
Once the piston 18 is returned to the start position, the valve 24 in the packer and/or probe can be closed and pressure built in the flowline again, extending the piston 18 and trigger the jar 10 for a second actuation. The process can be repeated the number of times required for freeing the tool string.
As provided in the FIGS. that follow, there are different trigger mechanisms that may be used with the jar 10. In one optional embodiment, pistons are used. In one embodiment, a configuration is presented that prevents the jar from triggering unintentionally during the normal operation (i.e. when inflating packers). Additionally, a second flow line may be used in a downhole testing apparatus to control the jarring force with the pressure of a second flowline.
As provided in
This actuation effectively resets the trigger 29 for the overall mechanism. The valve in the probe or packer can then be closed and the pump started again to repeat jarring.
The spring 22, in one non-limiting embodiment, is a stiff spring with a high spring constant. In one example embodiment, the spring 22 has two hundred pounds of force per inch of compression. The assembly of the tool is envisioned to be such that the jarring spring is “pre-compressed” by some amount to preload the spring 22 with sufficient force to prevent movement of the piston/weight until a pressure above the packer inflation pressure is applied to the flowline.
The sampling tool builds pressure in the flow line as part of the normal operation to “inflate” the packer. In order to prevent unintentional jarring as a result of normal packer inflation, the jarring spring would be pre-loaded as described above. Typical inflation pressures for the packer are approximately five hundred (500) pounds per square inch. In one non-limiting example, a pre-load of the jar spring would entail a flowline pressure of seven hundred fifty (750) pounds per square inch or greater to begin moving the weight. The pressure required to trigger the device can be designed to be variable as a function of the “stroke” of the piston prior to the trigger mechanism releasing the weight. A typical piston stroke length is, for example, six (6) inches or less.
As provided in
As provided in
Referring to
The piston 605 has a catch, which may be a three prong tip of the piston 605. The three catches travel in slots 604 in the guide sleeve 607 turn the catches 606 and the piston until they align with openings in the weight 602, releasing the weight 602 and triggering the jar. The alignment between the weight openings and the piston catches 606 is performed through rotation of the tracks in the guide sleeve arrangement 608. The piston 605 is returned and the process is repeated as desired.
As will be understood, the above concepts will work for either a one or two flowline tool. There are concepts specific to a two flowline tool that allow the use of the second flowline to do one or several of the following:
Referring to
In one non-limiting embodiment, an apparatus configured to impart a force on a downhole component is described, comprising a piston configured to expand from a movement of a fluid, a weight configured to move from a first position to a second position, wherein the weight contacts the piston and the piston is configured to move the weight from the first position to the second position when the piston expands from movement of the drilling fluid, a spring configured to contact a bearing surface and the weight, wherein movement of the weight toward the second position compresses the spring, a return spring configured to impart a force on the weight to return the weight to the first position from the second position and a trigger mechanism configured to actuate a return of the weight from the second position to the first position by the return spring.
In an alternative embodiment, the apparatus may be configured such that the fluid is a drilling fluid.
In an alternative embodiment, the apparatus may be configured wherein the component is a downhole component.
In an alternative embodiment, the apparatus may be configured wherein the drilling fluid is in a downhole environment.
In an alternative embodiment a method for creating a force on a downhole tool, is described comprising pumping a fluid to a downhole location, expanding a piston in the downhole location, an expansion of the piston caused by the fluid entering the piston, moving a weight through the expansion of the piston, the movement of the weight compressing a spring from an uncompressed position to a compressed position, triggering a mechanism such that the weight is allowed to move and the spring returns from the compressed position to the uncompressed position and impacting the weight upon a surface to deliver a force to a downhole environment.
In another alternative embodiment, the method may be accomplished wherein the force is delivered to a tool string.
In another alternative embodiment, the method may be accomplished wherein the fluid is a drilling mud.
In an alternative embodiment, the method may be accomplished wherein the mechanism used for triggering is a ball bearing mechanism.
In an alternative embodiment, the method may be accomplished wherein the mechanism used for triggering is a keyed, twisting track trigger mechanism.
In an alternative embodiment, the method may be accomplished wherein the pumped fluid expands the piston through one flowline.
In an alternative embodiment, the method may be accomplished wherein the pumped fluid expands the piston through one of two flowlines.
While the aspects have been described with respect to a limited number of embodiments, those skilled in the art, having benefit of the disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the disclosure herein.
