Background

This disclosure relates to the field of deployment and recovery of tools installed in subterranean wells. More particularly, the disclosure relates to devices and methods for assisting recovery of such tools after having been deployed in a well for an extended time.

Certain tools used in subterranean wells, for example, electrically powered, submersible well pumps (ESPs) may be installed in a well at the end of an electrical cable. After such deployment, the well pump may remain in the well for an extended period of time. During such time, as the well pump lifts fluids to surface, deposits such as paraffin and scale may accumulate on the interior of a well tubular, such as a production tubing. Accumulation of such deposits may interfere with removing the well pump if it requires service or replacement, or if the well is no longer desired to have the well pump deployed. In instances where the well pump is deployed at the end of the well tubing, such deposits generally do not present an obstacle to pump recovery

U.S. Patent No. 10,036,210 issued to Maclean et al. describes a system and method for deploying a well pump on electrical cable such as tubing encapsulated cable, wherein the well tubing is already in place. The well pump remains connected to the electrical cable after deployment in the well, and remains in place on such cable until it is desired to retrieve the well pump. In such instances, presence of deposits as explained above may cause the well pump to become stuck in the well tubular. Such sticking may lead to expensive and difficult to perform “fishing” operations to recover the well pump. The fishing operation is complicated by the presence of the electrical cable in the well between the well pump and surface.

It is desirable to have a method and devices to assist in recovery of a cable-deployed tool such as a well pump in the presence of deposits on the interior of a well tubular. Summary

Disclosed is a method for retrieving a well tool from a well. The method includes retracting a deployment cable coupled to the well tool. The well tool has connected on a longitudinal proximate the connection to the deployment cable an impact jar, which has an anvil slidably disposed on an exterior of a mandrel and a gauge cutter. The anvil is held in place by at least one shear pin or shear screw. When the anvil becomes lodged in a well tubular, retracting the deployment cable is continued until the at least one shear pin or shear screw ruptures and enables resumed upward movement of the mandrel until a first shoulder on the mandrel strikes the anvil.

In some examples, the first shoulder may be proximate a connection between the mandrel and the well tool.

Some examples may comprise extending the deployment cable until the anvil strikes a second shoulder on the mandrel at a longitudinally spaced apart location from the first shoulder.

Some examples may comprise retracting the deployment cable after the anvil strikes the first shoulder.

Some examples may comprise repeating the extending the cable after the anvil strikes the first shoulder at least two times and repeating the retracting the cable and extending the cable until the anvil is dislodged from the well tubular.

In some examples, the well tool may comprise an electrically operated well pump.

In some examples, the deployment cable may comprise an electrical cable.

In some examples, the electrical cable may comprise a tubing encapsulated cable.

In some examples, the well tool may have a function independent of use of the impact jar and the gauge cutter.

Also disclosed is an impact jar for a well tool. The impact jar has a mandrel including a connection at one longitudinal end. The connection has a feature to enable connection to the well tool. The mandrel has a through bore enabling passage of a deployment cable connectable at one end to the well tool. The mandrel has a first shoulder proximate one longitudinal end and a second shoulder proximate the connection. The impact jar includes an anvil slidably disposed on the mandrel and held in longitudinal position by at least one shear pin or shear screw. The anvil has a gauge cutter on its exterior and a plurality of circumferentially spaced apart, tapered diameter centralizer blades on the exterior. The centralizer blades define at least one fluid passage therebetween longitudinally traversing the gauge cutter.

Other examples and possible advantages will be apparent in the description and claims that follow.

Brief Description of the Drawings

FIG. 1 shows a cross sectional view of a cable-conveyed well tool having an impact jar apparatus on the cable end of the tool in arrangement as the tool and jar are deployed in a well.

FIG. 2 shows a cross sectional view of the well tool and impact jar after a retainer holding a gauge cutter in place is released.

FIG. 3 shows a side view of the well tool and impact jar after the well tool has been pulled toward the gauge cutter.

Detailed Description

FIG. 1 shows a cable-conveyed well tool 10 connected to an impact jar 20 as they would be arranged for deployment in a well (not shown). The well tool 10 may be a pump, such as an electrically operated submersible pump (ESP) coupled at one longitudinal end to a deployment cable 12 The deployment cable 12 may be a spoolable metal tube having one or more insulated electrical conductors therein, such cable 12 being known as a tubing encapsulated cable (TEC). Deployment of a well tool such as an ESP in a well using electrical cable such as TEC is described, for example, in U.S. Patent No. 10,036,210 issued to Maclean et al.

The impact jar 20 may comprise a mandrel 11 coupled at one end to a housing 10A portion of the well tool 10. The mandrel 11 A may comprise an interior through bore 11 A to enable passage therethrough of the deployment cable 12. The opposed longitudinal end of the mandrel 11 may comprise a fishing neck 13 of types known in the art to facilitate connection to the impact jar 20, and thence the well tool 10 to a fishing tool (not shown) in the event it becomes necessary to disconnect the deployment cable 12 to retrieve the well tool 10 and impact jar using axial force greater than the tensile load capacity of the deployment cable 12.

The mandrel 11 may comprise a first or lower shoulder 11B proximate the connection to the well tool 10, and may comprise a second or upper shoulder 11C proximate to, and in some examples defined by the fishing neck 13.

An anvil 14 may be disposed on the exterior surface of the mandrel 11 between the lower shoulder 1 IB and the upper shoulder 11C. At the time of deployment of the well tool 10 and impact jar 20 in a well, the anvil 14 may be held in the longitudinal position shown in FIG. 1, for example, using shear pins or shear screws 17 that engage a retaining groove (19 in FIG. 2) on the exterior surface of the mandrel 11. A longitudinal distance LI between one longitudinal end of the mandrel 11 and the lower shoulder 11B may be chosen to enable the well tool 10 to be accelerated in the direction of the fishing neck 13 in the event the anvil 14 becomes stuck in the well as a result of deposits on the interior of a well tubular (not shown).

The anvil 14 may comprise a centralizer 16 on one longitudinal end. The centralizer 16 may comprise a plurality of circumferentially spaced apart, tapered diameter “ribs” or blades, to be explained further with reference to FIG. 3. The centralizer 16 may be provided to reduce the incidence of the impact jar 20, and thus the well tool 10 from being stopped during retrieval operations by obstructions such as changes in internal diameter of the well tubular (not shown). The anvil 14 may comprise a gauge cutter 15 on its exterior. The gauge cutter 15 may be shaped similarly to well-known gauge cutters used in connection with other well tools for scraping accumulated deposits from the interior wall of a well tubular.

During deployment of the impact jar 20 and the well tool into a well (not shown) the assembled devices as shown in FIG. 1 may be suspended over the well (not shown) using techniques and apparatus known in the art, and the deployment cable 12 extended, such as from a winch or similar spooling device (not shown) to move the assembled impact jar 20 and well tool 10 to a chosen axial position (depth) in the well (not shown). The well tool 10 may then be operated according to its specific purpose.

Referring to FIG. 2, after the well tool 10 has been deployed in a well (not shown) for a length of time, and it becomes desirable or necessary to retrieve the well tool 10, the well operator may undertake operations to remove the well tool 10 and impact jar 20, such as connecting a winch or other spooling device (not shown) to the deployment cable 12 and retracting the deployment cable 12 from the well (not shown). During such retraction, the gauge cutter 15 may become stuck due to the force required to scrape certain deposits from the wall of the well tubular (not shown) being greater than the load capacity of the deployment cable 12. In such cases, continued upward pull on the deployment cable 12 may be applied so as to break the shear pins or screws (17 in FIG. 1). When the shear pins or screws (17 in FIG. 1) are broken, the anvil 14 becomes free to move axially along the mandrel 11 between the lower shoulder 1 IB and the upper shoulder 11C. In FIG. 2, the anvil 14 is shown having moved along the mandrel 11 such that a distance L2 between the anvil 14 and the lower shoulder 1 IB is smaller than the corresponding distance (LI in FIG. 1) shown in FIG. 1. As will be appreciated by those skilled in the art, continue upward movement of the deployment cable 12 while the anvil 14 is lodged in such obstruction as scale or paraffin deposits will cause the tool 10 and the mandrel 11 to move with the deployment cable 12 until the anvil is stopped by the lower shoulder 14B. Extending the deployment cable 12 will allow the mandrel 11 and the well tool 10 to move downwardly, away from the anvil 14 until the anvil 14 reaches the upper shoulder 14C.

During retrieval of the well tool 10, upward movement of the well tool 10 and the impact jar 20 will cause corresponding upward movement of the anvil 14. Upward movement of the anvil 14 will cause the gauge cutter 15 to scrape away any deposits on the interior of the well tubular (not shown), which would otherwise cause the well tool 10 to become stuck in the well tubular (not shown) in the absence of the gauge cutter 15. During such retrieval, a winch operator may observe when it appears that the gauge cutter 15 is trapped by deposits, an indication of which is that tension on the deployment cable 12 increases, frequently quite rapidly, above the free weight (tension) of the deployment cable 12 corresponding to the length of the deployment cable extended into the well (not shown).

In the event of such cable tension indication of a stuck anvil 14, the winch operator may continue to retract the deployment cable 12 until the shear screws or pins (17 in FIG. 1) break, at which point the cable tension may be observed to decrease, possibly down to the free weight of the cable. Continued retraction of the deployment cable 12 may enable the well tool 10 and the mandrel 11 to accelerate until the lower shoulder 14B strikes the anvil 14. The impact resulting from such strike may dislodge the anvil 14, or may cause it to further engage the deposits that caused it to become stuck. The winch operator may observe such impact as a rapid increase in tension on the deployment cable 12 as retraction continues. In the latter event, the winch operator may extend the deployment cable relatively rapidly, causing the well tool 10 and mandrel 11 to accelerate downwardly. Such downward acceleration may continue until the upper shoulder 11C strikes the anvil 14. The impact of such strike may dislodge the anvil 14 or at least move it downwardly to some extent.

The winch operator may then repeat a cycle of retracting and extending the deployment cable 12 until which time as the anvil 14 is released from the deposits. If the anvil 14 is dislodged during retraction of the deployment cable 12, such dislodging may be observed as a rapid decrease in tension on the deployment cable 12. If dislodging occurs during extension of the deployment cable 12, such event may be observed as a rapid increase in tension on the deployment cable 12 up to the free weight at the relevant depth of the well tool 10 in the well (not shown). In some instances, freeing the anvil 14 will enable full retrieval of the well tool 10 and the impact jar 20 from the well (not shown) using the deployment cable 12 alone. In some instances, it may be necessary to move the well tool 10 back to a longitudinal position in the well (not shown) where the well tool 10 can engage a locking device (not shown) to hold the well tool 10 in place longitudinally to enable disengagement of the deployment cable 12 and subsequent recovery of the well tool 10 and the impact jar 20 using higher tensile load capacity tools such as coiled tubing or a “workover” pipe string in connection with fishing techniques known in the art. Provision of the fishing neck 13 on the mandrel 11 may provide a convenient place to connect such coiled tubing or workover string for recovery operations. FIG. 3 shows a side view of the well tool 10 and the impact jar to point out some features of the anvil 14 that provide the impact jar 20 with some desirable functionality. The centralizer 16 may comprise a plurality of circumferentially spaced apart, narrowing taper (in the direction away from the well tool) ribs or blades 16A, which as explained above may reduce the chance of the anvil 14 becoming lodged in the well tubular (not shown) at certain obstructions such as internal diameter change in the well tubular (not shown). Flow passages 16B may be defined between the ribs or blades 16A to enable fluid flow relatively unrestricted across the gauge cutter 15 so that the impact jar 20 may be deployed along with well tools such as ESPs.

A well tool assembled to an impact jar as explained herein may be deployed in a well for an extended time, wherein extensive deposits may form in a well tubular. The deposits may be removed using a gauge cutter deployed with the impact jar such that the gauge cutter may be dislodged by impact using only the well tool deployment cable to move the assembled well tool and impact jar.

While the foregoing description is made in terms of the well tool being an ESP, it will be appreciated that other types of well tools may be deployed on a cable and recovered in essentially the same way as described herein. Accordingly, the disclosure is not limited in scope to deployment and recovery of ESPs. It will be appreciated that the scope of well tools that may be used with an impact jar according to the present disclosure are those that have a function independent of use with an impact jar having a gauge cutter as described herein, that is, such well tools may deployed for their intended use without the need to have an impact jar or gauge cutter as described herein.

In light of the principles and examples described and illustrated herein, it will be recognized that the examples can be modified in arrangement and detail without departing from such principles. The foregoing discussion has focused on specific examples, but other configurations are also contemplated. As a rule, any example referenced herein is freely combinable with any one or more of the other examples referenced herein, and any number of features of different examples are combinable with one another, unless indicated otherwise. Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible within the scope of the described examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.