Embodiments described relate to oilfield well operations. In particular, back-off tools and techniques for separating tubular portions from one another are described. For example, such techniques may be employed for removing an uphole portion of a tubular from the well when a downhole portion thereof has been stuck for any number of reasons. Subsequent fishing operations may thus be employed for removal of the downhole portion of the tubular. The tubular itself may be production tubing, drill pipe or other conventional jointed hydrocarbon tubing.
Exploring, drilling, completing, and operating hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of these expenses, added emphasis has been placed on monitoring and managing all phases of well completion and production. This may include monitoring and maintaining the positioning and placement of well tubulars within a well. For example, the initial drilling of a well may be achieved through use of a drill bit at the end of drill pipe which serves as a tubular for directing fluid flow during the operation. In another example, a tubular in the form of production tubing may be positioned in the well to serve as a conduit for hydrocarbon recovery therefrom. Regardless of the tubular type, proper monitoring and maintenance thereof may substantially lower the cost of well completion and production in the long run.
Monitoring of such tubulars as noted above often reveals problems with their deployment in the well. For example, problems associated with differential pressure, well architecture, obstructions and other factors often lead to the tubular becoming stuck at a location in a well. In the case of drill pipe, this may lead to a stoppage of drilling whereas in the case of production tubing, this may lead to improper or incomplete positioning for hydrocarbon recovery.
Fortunately, techniques have been developed for reversing or “backing-off” tubulars from within the well when such circumstances arise. These techniques take advantage of the jointed nature of tubulars. That is, tubulars are generally made up of a series of tubular portions that are threadably jointed to one another to form a unitary tubular of extended length. Thus, a technique for tubular removal from a well may include breaking a joint of the tubular that is located immediately above the stuck portion of the tubular. In this manner, the portion of the tubular that is located above the stuck portion may be withdrawn from the well, followed by a conventional fishing operation in order to remove the remainder of the stuck tubular.
Unfortunately, techniques such as those noted above for removing the stuck tubular are often fairly hazardous and imprecise. For example, a technique referred to as “stringshot” is often employed. That is, an explosive charge or “stringshot” is delivered downhole to a location adjacent the joint in order to break the tubular thereat. The stringshot technique is hazardous in that the operator is left handling hazardous explosives. However, it is also a fairly imprecise method of breaking the tubular at exactly the location of the noted joint. That is, the tubular may include a series of joints distanced from one another every 20 to 30 feet or so. Thus, given the inherent imprecise nature of explosives, the use of an explosive charge adjacent the intended joint may lead to the breaking of multiple joints both above and below the intended joint. Furthermore, as a result of uneven corrosion or a host of other factors, the intended joint may be more difficult to dislodge or unscrew than other neighboring joints. Therefore, in many cases, neighboring joints may be broken through a stringshot technique while the intended joint remains intact. All in all, employing the stringshot technique to break a tubular at an intended joint is generally considered to be about a 50-50 prospect.
Given the drawbacks to employing a stringshot technique to break a tubular at a desired joint, some added measures have been developed. For example, with the tubular lifted from surface to a vertically compression-free state and having an unscrewing torque applied thereto, a ‘back-off’ tool may be deployed into the tubular to the location of the joint of interest. The back-off tool may be configured to anchor to the upper portion of the joint and rotate in the direction of the unscrewing torque imparted from surface. Thus, the remainder of the unscrewing torque necessary to break the joint may be directed directly to the joint via the back-off tool. Furthermore, the exact joint of interest may more assuredly be broken.
Unfortunately, spacing within the tubular is quite limited. For example, a 5 inch diameter tubular is fairly standard for use in a 12 inch diameter well. Therefore, to ensure that sufficient power is provided to the noted back-off tool, a substantial amount of power may be provided from surface as opposed to disposing large amounts of powering equipment into the tubular. This power may be provided by way of a hydraulic line run from surface to the back-off tool, perhaps several thousand feet into the well and tubular. However, employing hydraulics over such a vast distance may be quite cumbersome and expensive, particularly when dealing with wells of extended reach. Thus, as a practical matter, operators today generally elect to bypass use of such a back-off tool in favor of the more hazardous and less precise stringshot techniques as described above.
A back-off tool is provided for disposing in a well relative to a tubular therein. The tool includes first and second anchors for engaging first and second tubular locations at either side of a joint in the tubular. A downhole powered rotation mechanism of the tool is coupled to the anchors to induce a rotation thereof relative to one another along with each tubular portion.
Embodiments are described with reference to back-off applications with respect to certain tubular well operations. In particular, back-off applications as applied to production tubing are described. However, embodiments of back-off tools and applications as detailed herein may be applied to other types of tubing. For example, joints within drill pipe and other tubular varieties may be broken according to techniques described herein. Regardless, back-off tools and techniques employed herein may utilize downhole power by way of straddled dual anchoring at the location of a tubular joint to be broken.
Referring now to
In order to address the situation, an embodiment of the dual anchor back-off tool 100 may be employed to break a targeted joint 129 of the tubing 120. The targeted joint 129 may be located uphole of the sticking point and debris 197 such that its breaking would allow for removal of all tubing 125 thereabove (i.e. ‘uphole tubing’ 125). Thus, perhaps following a standard clean out of the debris 197, remaining downhole tubing 127 may then be fished out through conventional techniques. As such, production tubing 120 may then be redeployed.
Continuing with reference to
With particular reference to
More specifically, the wireline operation and equipment 250 of
Continuing with reference to
While the anchors 165, 175 are depicted as discrete elements radially extending in a lateral fashion from each anchor portion 160, 170, a variety of anchoring mechanisms may be employed. For example, in an alternate embodiment the discrete anchors 165, 175 may be replaced with vertically oriented anchors configured to span a significant vertical distance at an interface of the anchor portions 160, 170 and the tubing 125, 127. Additionally, in other embodiments, anchoring mechanisms of alternate orientation and/or for supporting a variety of different engaged interfacing with the tubing 125, 127 may be employed.
As depicted in
In the embodiment shown, the joint 129 is made up of the tapered end of uphole tubing 125 mated with an end of the downhole tubing 127. This mating may be maintained mechanically, perhaps with matching threading between each of the ends of the tubing 125, 127. Additionally, natural corrosion and/or introduced adhesive may serve to further the mating between the ends of each tubing 125, 127 at the joint 129. Nevertheless, as detailed below, sufficient power may be converted downhole at the location of the joint 129 so as to effect a break thereof.
With continued reference to
In addition to reduction of compression at the joint 129, the tubing 120 may be rotated to a degree at surface. This surface rotation of the tubing 120 may be in a direction opposite the rotation of the downhole anchor portion 170 as directed by the rotation mechanism 150. Ultimately, as detailed below, this may translate to a degree of rotational tension imparted at the joint 129 from surface which is supportive of the actuation of the tool 100 and its rotation mechanism 150. As a result, the amount of downhole power necessary to induce a break in the joint 129 may be kept at a level that avoids self-inflicted damage to the tool 100 through actuation of the rotation mechanism 150. Given the presence of the control unit 254 and the deployment of the tool 100 through communicative wireline techniques, regulating downhole power so as to avoid tool damage as a result of overpowering may be achieved. This is particularly true where, as described here, the likelihood of overpowering is further reduced by lifting and pre-torquing or rotating the tubular 120, so as to minimize the amount of downhole power required to break the joint 129.
Referring now to
As indicated above, given the dual anchoring nature of the back-off tool 100 sufficient power for breaking the joint 129 via the rotation noted by arrow 375 may be provided from a downhole source or ‘torque generator’. With added reference to
Continuing with reference to
Referring now to
Referring now to
As noted above, powering of the tool 100 in terms of rotation for breaking the joint 129 may be achieved through a downhole power source such as a motor and hydraulic pump assembly 400. In the embodiment of
Continuing with reference to
Radially extending and setting the anchors 165, 175 as depicted in
Referring now to
In the embodiments described herein, the noted translation of vertical movement to rotation may be achieved through mismatched threading as between the piston 300 and internal dimensions of the downhole anchor portion 170. However, alternate vertical to rotational translating mechanisms may be employed. Regardless, with anchoring of the tubular 120 in mind as shown in
Referring now to
Once the joint is broken as described above, the tubular above the joint may readily be withdrawn from the well as indicated at 580. Of particular note, is the reliability with which breaking of the tubular is achieved right at the joint due to the dual anchoring nature of the back-off tool. Thus, the need for multiple break attempts and/or multiple withdrawals of tubing uphole of the targeted joint may be substantially avoided, thereby saving significant time and cost. As such, subsequent fishing and potentially clean out operations may immediately ensue so as to remove the remaining tubular portions and place the well in condition for redeployment of another tubular.
Embodiments detailed hereinabove provide tools and techniques for breaking a downhole tubular at a targeted location without the need for reliance on stringhshot or other potentially hazardous methods. Furthermore, the embodiments described herein include a degree of precision and downhole power capacity such that alternative substantially heavier tool assemblies may similarly be avoided.
The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, embodiments of the back-off tool may be employed for use with tubulars other than production tubing. Such tubulars may include drill pipe as noted, as well as drill collars and casing. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.
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Number | Date | Country |
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2341621 | Mar 2000 | GB |
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Number | Date | Country | |
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20100319929 A1 | Dec 2010 | US |