Patent Application
20130000909
The present invention relates generally to downhole tools and methods and more particularly, but without limitation, to tools and methods used to deliver jarring impacts to objects downhole.
Jarring tools are used to jar or shake loose a downhole tool or object that has become stuck or lodged in the well bore. In hydraulic or reciprocating type jars, a metering or release section inside telescopically arranged inner and outer tubular members resists allowing the jar to extend, which provides sufficient time for the tubing string to be stretched before a hydraulic release mechanism within the jar allows rapid extension and impact within the tool. This creates a large dynamic load on the stuck tool or object. Most hydraulic jars are designed for repetitive or cyclic action to continue jarring the stuck object until it is dislodged. The cyclic firing and resetting or recocking of the jar is accomplished by pushing and pulling the tubing string.
Hydraulic jars are often run on coiled tubing. However, there are several disadvantages to using coiled tubing to run a hydraulic jar. It is particularly difficult to push or “snub” coiled tubing into a horizontal well, making it difficult to cycle the jar.
Additionally, problems may arise related to the wear and tear on the tubing. Each time the coiled tubing passes through the surface equipment (the injector head, etc.) used to secure and seal the coiled tubing at the wellhead, the tubing undergoes stress and strain. This substantially reduces the service life of the tubing. During a hydraulic jarring operation, the same small section of the coiled tubing is subject to repeated high-load cycles, which can rapidly degrade the condition of the tubing at this section and thus compromise the entire operation and indeed the well. This is especially true in the case of high pressure wells; the high pressure loads put even more stress on the tubing. When the tubing becomes worn, the degraded section must be removed or replaced, which is both time consuming and expensive. Under some high pressure conditions, the coiled tubing may be limited to only three to four jar cycles.
The jarring tool of the present invention offers an improvement in methods and tools for jarring operations using coiled tubing. In accordance with the method of the present invention, the jar is cycled using fluid pressure; repeatedly raising and lowing of the coiled tubing is eliminated. This is made possible by including one or more hydraulic pressure chambers in the tool in addition to the jar assembly. Although the jarring tool and method of this invention is particularly useful with coiled tubing, those skilled in the art will appreciate that it can be employed with other tubular well conduits, such as jointed well tubing and drill pipe.
Turning now to the drawings in general to and to
A fishing tool 28 on the end of the tubing 14 in the wellbore 30 is used to attach a jar 32 to the stuck object 34. The combination of tools connected at the downhole end of the tubing 14 forms a bottom hole assembly 36. The bottom hole assembly 36 and tubing combined are referred to herein as the tubing string 38. The bottom hole assembly 36 may include a variety of tools including but not limited to a bit, a mud motor, hydraulic disconnect, jarring tools, back pressure valves, and connector tool.
Fluid is introduced into the coiled tubing 14 through a system of pipes and couplings in the reel assembly, designated herein only schematically at 40. In accordance with conventional techniques, the jar 26 is cycled by raising and lowering the section of tubing in the injector assembly 18 repeatedly until the object 34 is dislodged.
In some instances, the jar 26 is connectable directly to the stuck object 34 in the wellbore 30. In other instances, the jar 26 is connected as one member of a bottom hole assembly comprising several tools. When the jar 26 is described as being connectable to a “stationary object downhole,” it is intended to mean that the tool is connectable to another tool in the tool string, which may have become lodged in the wellbore, or to the fishing tool 28 that is in turn attached to the stuck object 34 in the well, or even directly to the stuck object.
The coiled tubing injection system 10 illustrated in
The jar is set or cocked by “slacking off” on the tubing string to allow downward movement of the housing on the mandrel forcing the piston past the narrow portion into the upper chamber. The jar is fired by raising the tubing, which pulls the piston back through the narrow portion of the chamber. As the piston moves into the lower chamber, a sudden pressure release creates a jarring impact in the tool. This process is repeated until the stuck object is dislodged.
The surface area on the end of the mandrel exposed to the fluid entering the tool is designated as A1. When the internal pressure of the flow through the tool exceeds the fluid pressure in the wellbore, the force exerted by fluid pressure inside the tool tends to extend the tool. This is referred to as the Pressure Induced Extension Force (“PIEF”) and may be expressed by the following formula, where Pint represents the internal fluid pressure and Pext represents the external fluid pressure in the wellbore:
PIEF=A1×(Pint−Pext).
Thus, the PIEF for a standard 2.88 short stroke jar, such as the one shown in
PIEF=1.77×(Pint−Pext).
The inventive tool includes a hydraulic reset system to provide a pressure-induced contraction force (“PICF”) that is counteractive to PIEF when the internal pressure exceeds the wellbore pressure. To that end, two additional hydraulic chambers C2 and C3 are created by annular recesses in the sidewall of the H, and two pistons P2 and P3 are formed on the outer perimeter of the mandrel.
The hydraulic chambers C2 and C3 are fluidly connected to the lumen of the mandrel by fluid ports F1 and F2. below (downhole) of the pistons P2 and P3 Thus, fluid pressure on the surface areas in these chambers, designated as A2 and A3, respectively, is a pressure-induced contraction force that tends to move the housing down relative to the mandrel, that is, it tends to contract the tool. Thus, by selecting the dimensions of the tool components, an “over-balanced” tool is made in which fluid pressure can be employed to reset or re-cock the jarring mechanism in the tool.
The hydraulic operation of the tool shown in
Now it will be understood that if A1>A2+A3 and Pint>Pext, then the net pressure-induced force, PIF, tends to extend the tool, that is, the PIEF exceeds the PICF. Whereas, if A1<A2+A3 and Pint>Pext, then the net force PIF tends to contract the tool, that is, the contraction force exceeds the extension force. It will be noted that the number of additional hydraulic chambers exerting an “up” force may vary as may the relative dimensions of the tool and its component parts.
In some cases, it is advantageous to have a jarring tool where the net extension and contraction forces are balanced, that is, where the net extension/contraction force, PIF, on the tool is zero. For example, if the jar is under balanced (PIF creates an extension force) the occurrence of high internal fluid pressures (which can occur during pumping) can cause the pressure-induced force on A1 to become so high that the mandrel and housing expand making it difficult or impossible to reset the jar. By providing an additional hydraulic chamber configured to provide a balancing force in the opposite direction, unwanted extension of the jar is avoided.
A diagrammatic depiction of a balanced tool is shown in
However, the hydraulic system provides a PICF that is equal to the PIEF. To that end, one additional hydraulic chamber C2, piston P2 and fluid port F1 is provided so that A2 equals A1. By selecting the dimensions of the tool components, a “balanced” tool is made in which fluid pressure does not affect the resetting of the tool. Additionally, this balanced jar would allow back-pressure valves to be run above or below the jar in the bottom hole assembly without creating hydraulic locking issues if the flow path below the tool becomes plugged.
Having explained the hydraulic principles related to the present invention, one preferred embodiment of the jarring tool will described in more detail with references to
In its preferred form, the jarring tool 100 generally comprises a housing such as the outer tubular assembly 102 and an inner tubular assembly 104. The inner tubular assembly 104 is telescopically received inside the outer tubular assembly 102. One of the tubular assemblies is connectable to well conduit, and the other is attachable to the downhole object.
In the embodiment shown, the inner tubular assembly 104 comprises a lower or downhole end that connects directly or by means of intervening tools to the stationary object 34 downhole, and the outer assembly 102 has an upper end that attaches to the coil tubing or other well conduit 14. In this way, the outer assembly 102 is movable up or down relative to the inner assembly 104. However, it will be appreciated that this arrangement may be reversed, that is, the outer assembly may be attachable to the downhole object 34 (or other tool 28) and the inner assembly attachable to the well conduit 14. A flow path 106 extends through tool 100 to allow fluid to pass from the coiled tubing 14 through the tool.
As used herein, the terms “up,” “upward,” “upper,” and “uphole” and similar terms refer only generally to the end of the drill string nearest the surface.
Similarly, “down,” “downward,” “lower,” and “downhole” refer only generally to the end of the drill string furthest from the well head. These terms are not limited to strictly vertical dimensions. Indeed, many applications for the tool of the present invention include non-vertical well applications.
Throughout this specification, the outer and inner tubular assemblies 102 and 104 and the jarring assembly components are described as moving “relative” to one another. This is intended to mean that either component may be stationary while the other is moved. Similarly, where a component is referred to as moving “relatively” downwardly or upwardly, it includes that component moving downwardly as well as the other, cooperative component moving upwardly.
Both the outer tubular assembly 102 and inner tubular assembly 104 preferably are composed of several interconnected tubular members. The number and configuration of these tubular members may vary. Preferably all these members are interconnected by conventional threaded joints, but other suitable connections may be utilized.
Shown in
The lower end 120 of the oil port sub 116 connects to a third member such as the upper end 124 of an upper piston housing 126. The lower end 128 of the upper piston housing 126 connects to a fourth member such as the upper end 130 of a lower piston housing 132. The lower end 134 of lower piston housing 132 connects to a fifth member, such as the upper end 136 of a spline housing 138. The lower end 140 of the spline housing 138 connects to a sixth member such as the upper end 142 of a split end cap 144, secured together by bolts (not shown) through the transverse bolt holes 145 (
The top sub 108, the oil port sub 116, the upper piston housing 126, the lower piston housing 132, the spline housing 138, and the end cap 144 all are interconnected with threaded joints for fixed movement with the coil tubing or other well conduit 14. Those joints forming part of fluid chambers are equipped with seals, such as O-rings, designated collectively by the reference number 150.
With continued reference to
The upper mandrel 160, the center mandrel 168, the mandrel 86, the upper and lower piston mandrels 174 and 180, and the bottom sub 186 all are connected together for fixed movement with the object in the well. Thus, axial movement of the coil tubing 14, or other well conduit, causes the outer assembly 102 to move relative to the inner assembly 104. Preferably, these members are interconnected by conventional threaded joints, but other suitable connections may be utilized. Those joints forming part of fluid chambers are equipped with seals, such as O-rings, designated collectively by the reference number 190. Additionally, seal members, such as backup rings 192 are provided between the inner and outer tubular members 102 and 104 to provide a fluid tight but sliding engagement therebetween.
The outer diameter of the inner tubular assembly 104 and the inner diameter of the outer tubular assembly 102 are configured to provide an annular hydraulic chamber 200 therebetween for the jarring mechanism yet to be described. This hydraulic chamber 200, seen best in
With continuing reference to
Since the jarring assembly shown is well known, its structure and operation will be summarized. The jarring assembly 210 comprises a restricted section 212 positioned within the hydraulic chamber 200, and preferably on the inner wall of the outer assembly 102 that forms the outer wall of the hydraulic chamber. More specifically, the restricted section 212 in this embodiment is provided by a reduced diameter section on the inner surface of the oil port sub 116.
As seen in
The outer diameter of the piston 216 and the inner diameter of the restricted section 212 are selected to create resistance as the piston passes through the restricted section. Once the restricted section clears the end of the piston 216, the resistance drops and full flow resumes, resulting in an upward jar. As shown in
In the preferred “overbalanced” tool shown and described herein, the contraction force is generated by two hydraulic reset assemblies. The uppermost reset assembly is shown in
The second, lowermost reset assembly is shown in
As fluid is forced into the coiled tubing 14 to a predetermined pressure to achieve an internal pressure greater than the external pressure, depending on the dimensions of the tool, the fluid exerts a force that moves the pistons 232 and 242 from the neutral position shown in
To permit transmission of torque through the tool 100, the tool may include some anti-rotation structure between the outer and inner tubular assemblies 102 and 104. For example, interengaging splines, designated generally at 260 and 262 in
Referring still to
Having described the structure of the tool 100, its use and operation in accordance with a preferred embodiment of the method of the present invention now will be explained. The tubing string 38 is run downhole and latched onto the stuck object 34 preferably using the fish 28.
Next, striking tension is applied to the tubing 14 using the injector assembly 18. “Striking tension” means the tension necessary to extend and maintain the tool in the extended position, thereby maintaining the jar assembly in the fired or discharged position. Once the striking tension is achieved, the tubing 14 is secured or locked in the injector assembly 18 to prevent reciprocal movement of the tubing. Where the jarring tool is deployed or conveyed on jointed well tubing or drill pipe, the well conduit support assembly may include slips or a “dog collar” to secure the conduit above the wellhead, instead of a coiled tubing injector assembly.
With tubing string secured, fluid is introduced to pressurize the tubing. The pressure is increased until the desired reset pressure is achieved. Referring again to
Next, the fluid pressure is “bled off” to release the extension. When the jar 210 fires, the outer tubular assembly 102 snaps back up and create an upward impact. After the jar assembly 210 fires, the procedure is repeated as often as necessary until the fish 28 and the stuck object 34 are jarred loose. The tubing string 38 then may be retracted to the surface.
It will be apparent that the length of the deployed tubing affects the capacity of the tubing to stretch under pressure. This, in turn, affects the length of the stroke that can be achieved in the jarring tool by stretching the tubing. If the tubing is too short, excessive tension would be required to extend the tool. Consequently, the induced load from fluid pressure will be insufficient to stroke the jar.
In such cases, in accordance with the one embodiment of the method of the present invention, fluid pressure may be used to maintain the tool in the contracted or cocked position while applying the striking tension to the coiled tubing. Then, when the striking tension is achieved, the tubing is secured in the injector assembly. Now, bleeding off the internal pressure will allow the tool to extend and cause an initial an initial jarring action. Then, the internal pressure is varied as before to cock and release the jar repeatedly.
Now it will be appreciated that the tool and method of the present invention allows jarring operations on coiled tubing with minimal wear on the tubing. Additionally, the present invention permits reliable, fluid-controlled jarring operations on coiled tubing especially in horizontal or deviated wellbores where tubing reciprocation is particularly difficult if not impossible.
The embodiments shown and described above are exemplary. Many details are often found in the art and, therefore, many such details are neither shown nor described. It is not claimed that all of the details, parts, elements, or steps described and shown were invented herein. Even though numerous characteristics and advantages of the present inventions have been described in the drawings and accompanying text, the description is illustrative only. Changes may be made in the details, especially in matters of shape, size, and arrangement of the parts, within the principles of the invention to the full extent indicated by the broad meaning of the terms. The description and drawings of the specific embodiments herein do not point out what an infringement of this patent would be, but rather provide an example of how to use and make the invention. Likewise, the abstract is neither intended to define the invention, which is measured by the claims, nor is it intended to be limiting as to the scope of the invention in any way. Rather, the limits of the invention and the bounds of the patent protection are measured by and defined in the following claims.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13044785 | Mar 2011 | US |
| Child | 13471881 | US |
