GB2504101A

GB2504101A - Apparatus for stimulating a well with downhole electrical tooling and protection sleeve

Info

Publication number: GB2504101A
Application number: GB1212692.6A
Authority: GB
Inventors: Philip Head
Original assignee: Artificial Lift Co Ltd
Current assignee: Artificial Lift Co Ltd
Priority date: 2012-07-17
Filing date: 2012-07-17
Publication date: 2014-01-22
Also published as: GB201212692D0

Abstract

An apparatus and method for stimulating a well, comprising production tubing (20, figure 1B) in the well, the tubing having a side pocket 29, a first wet connector 30 located in the side pocket. There is an insulated electrical conductor connecting the first connector to surface equipment (4, figure 1A) via a wellhead (3, figure 1A). There is an electrically powered tool, which may be an electric submersible pump (ESP), which has a second wet connector which is arranged to engage the first connector after the tool is lowered down the tubing. A protection sleeve (50, figure 2A) is deployed down the tubing where it is sealingly engaged to cover the side pocket to prevent damage to components therein during treatment or stimulation of the well, for example using acid. The protection sleeve may have a recovery profile (55, figure 2B) and resilient fingers (57, figure 2B).

Description

Apparatus and method for stimulating a well with downhole electrical tooling This invention relates to the deployment of electrical tools in wells, particularly but not exclusively the deployment of electrical submersible pumps (ESPs) in hydrocarbon wells where stimulation using acids or other aggressive fluids is anticipated.

It is often necessary to stimulate production from hydrocarbon wells by pumping acids or othcr aggressive fluids into thc productive formation, either to dissolve deposits which block the matrix or to create ncw productive pathways, e.g. by fracture aeidizing, in the immediate vicinity of the wellbore. I lowever, the acids or other fluids used for this purpose can damage electrical tools such as sensors, valves, and pumps which are deployed in the wellbore.

It is known to deploy downhole tooling by connecting the tool to a fixed power or other electrical conductor via a wet connector located in a side pocket in the casing or other tubing within the well. The tool can then be recovered to surface during well stimulation operations. I lowever, the fixed part of the wet connector is permanently installed in the wellbore so that it is vulnerable to failure resulting from acid erosion of the exposed parts.

An alternative approach is to deploy the tool on the electrical cable so that both elements are recovered together from the well. This however requires a cable having sufficient tensile strength to support its own weight together with the weight of the tool, which obstructs the central bore of the well and makes it difficult to deploy several tools at the same time.

Alternatively, the tool can be deployed on a detachable wireline and the cable deployed separately and connected to the tool using a wet connector. The cable can then be somewhat smaller but must still be arranged in the central bore.

It is the object of the present invention to provide a more satisfactory method or apparatus whereby downholc electrical tooling may be installed in a well which is subject to stimulation with acids or the like.

In accordance with the present invention there are provided a method and an apparatus as defined in the claims.

Further features and advantages will he evident from the illustrative embodiment which will now be described, purely by way olexample and without limitation to the scope of the claims, and with reference to the accompanying drawings, in which: Fig. 1A shows a well in longitudinal section; Fig. tB is an enlarged view of part of Fig. 1A; Fig. 2A shows a protection sleeve; Fig. 2B is an enlarged view of the lower end of the protection sleeve; Fig. 3 shows an electrical submersible pump (ESP); Fig. 4A shows the protection sleeve installed in the well; Fig. 4B is an enlarged view of part of Fig. 4A; Fig. 5A shows the well being acidized via coiled tubing inserted through the protection sleeve; Fig. SB is an enlarged view of part of Fig. SA; Fig. 6A shows the ESP installed in place of the protection sleeve; and Fig. 6B is an enlarged view of part of Fig. 6A.

Corrcsponding reference numerals indicate corresponding parts in each of the figures.

Referring to Figs. IA and I B, a well 1 comprises a borehole lined with a easing 2 connected to a wel]head 3 and surface equipment 4 at the ground surface 5.

Production tubing 20 extends down inside the casing from the welihead, with the annulus (annular gap) 6 between the production tubing and the casing being sealed S by a packer 7. For simplicity, only single strings of casing and production tubing are shown, although in practice there may he several strings with successively smaller diameters connected end to end and extending down to the productive formation 8.

The inner surface 21 of the tubular wall 22 of the production tubing defines a bore 23 which terminates at the open lower end 24 of the production tubing in fluid communication with the wellbore 9 in the region of the productive formation. The bore 23 also communicates with the annulus 6 below the packer 7 via perforations 32 in the wall 22 of the production tubing.

The inner surface 21 also defines an orientation profile 25 which is formed in the bore 23 just above its open lower end 24, comprising an upwardly facing partially elliptical ledge 26 (half of which can be seen in the drawings) with a radially inward and downward bevel, the long axis X2 -X2 of the ellipse being inclined with respect to the longitudinal axis Xl -Xl of the well. The elliptical profile is downwardly elongated at its lowermost point to form a short vertical groove 27 between two opposed walls (one of which can be seen in the drawings) so that the orientation profile resembles an inverted teardrop.

The bore 23 of the production tubing also features a landing profile 28 comprising an annular internal recess just below the orientation profile, the upper wall 28' of the recess being radially inwardly and upwardly bevelled.

Two side pockets 29, 29' arc formed in the wall 22 oC the production tubing above the orientation profile, with a respective first wet connector 30, 30' being located in each side pocket. Each first wet connector comprises a socket lined with an electrical contact and wiper seals, optionally containing a nonconductivc fluid, and housing a spring loaded plunger which normally occupies the socket but can be displaced by a corresponding conductive male probe. The contact of each wet conncctor is connected to the surface equipment 4 via a respective insulated electrical conductor 3 1, 31' which extends through the annulus 6 and packer 7 to the welihead.

The two wet connectors provide redundant connection points and also allow more 1 0 than one tool to bc installed; in altcrnativc embodiments, only one side pocket and one first wet connector may be provided.

Wet connectors are well known in the art and so will not be described further.

Each first wet connector can be either male or female, and other conventional designs may be adopted.

In this specification, a "side pocket" is any recess, aperture or window in the tubing through which the respective wet connector is accessible, and "located in the side pocket" means that the respective wet connector is located in such a position thai it is accessible via thc side pocket. In the embodiment shown, the side pocket is an aperture, and the wet connector is mounted on the wall 22 of the production tubing so that it extends into the annulus 6. In alternative embodiments, the side pocket may be a recess formed within a thickened portion of the wall 22 of the tubing, or can have a easing extending outwardly from the tubing wall 22 so as to form a barrier between the first connector and the annulus 6. Each first connector may be fixed with respect to the tubing wall, or may be moveable. for example, slideable, or extendible from the side pocket into the bore of the tubing, as known in the art.

Referring to Fig. 3 and Figs. 6A and 611, fluid is produced from the well by means of an ESP 40 comprising a pump module 41 with an inlet 42 and outlet 43 and driven by a motor module 44 which is powered via a retractable second wet connector 45. (In practice, there will usually be several modules arranged above the inlet.) The ESP is lowered down the production tubing on a detachable wireline (not shown) engaged in the outlet 43 until an abutment 46 near the lower end of the ESP engages the ledge 26 of the orientation profile. After reaching this position the ESP continues to descend while the abutment travels slidingly along the ledge until it enters the vertical groove 27, rotating the ESP into an engagement position in which the connector 45 extends radially outwardly to enter the side pocket 29 as known in the art. Further downward movement of the ESP causes the abutment 46 to travel down the groove 27 while the male probe 45' of the connector 45 engages in the socket of the first wet connector 30 to connect the motor module via the conductor 31 to a power supply at the surface equipment 4.

The ESP is sealed in the bore 23 by means of a packer 47 so that the produced fluid is drawn from the productive formation 8 via the annulus 6 below the packer and through the perforations 32 into the inlet 42 and expelled from the outlet 43 to surface via the bore 23 of the production tubing. Of course, the ESP can be arranged in alternative configurations as known in the art.

Referring to Figs. 2A and 2B and Figs. 4A and 4B, a tubular protection sleeve 50 comprises a tubular wall 51 defining a central bore 52 with open upper and lower ends 53, 54. A recovery profile 55 is arranged at the upper end, comprising an annular recess which is engageable by a tool on a wireline. An annular seal 59 is arranged on the external surface 51' of the sleeve just below the upper end.

The lower end of the sleeve is reduced in diameter and comprises an engagement portion 56, which in the illustrated embodiment is formed as an internal collet, which is to say, a tubular array of radially moveable elements configured to engage the landing profile within which the collet is received. The collet comprises a plurality of rcsilicnt fingers 57 forming an integral part of the protection sleeve 50, which is made from a suitably resilient material, for example, beryllium copper. Each finger terminates in a radially outwardly extending portion 58 having a bevelled upwardly facing surface 58' and an S opposite, lower surface 58" normal to the longitudinal axis of the sleeve.

Before commencing acidization or other aggressive fluid treatment of the well, the ES? is withdrawn on a conventional wireline tool (not shown) which is then rcleasahly engaged in the recovery profile 55 and the protection sleeve lowered via the wcllhcad 3 down the bore 23 of the production tubing into the position previously occupied by the ESP. The fingers 57 of the collet are compressed radially inwardly as they pass over the bevelled ledge 26 of the orientation profile, allowing the sleeve to travel downwards until the outwardly extending portions 58 of the fingers releasably engage in the landing profile 28. The lower surface 58" of each finger abuts the upwardly facing lower annular wall of the landing profile, preventing further downward movement, while the upper surface 58' abuts the corresponding bevelled upper wall 28' which retains the protection sleeve in the deployed position as shown in Figs. 4A, 411 but allows it to he released and recovered to the surface by jarring it up on the wireline.

In the deploycd position the protection sleeve is sealingly engaged within the bore 23 of the production tubing so as to cover the side pockets 29, 29' as well as the perforations 32 in the wall 22 of the production tubing, so that the first wet connectors 30, 30' are separated and protected by the sleeve from any fluids or objects in the bore of the production tubing. The bore 52 of the protection sleeve opens at its upper and lower ends 53, 54 into the bore 23 of the production tubing, whereby the respective bores of the protection sleeve and production tubing are aligned to Form a single flowpath which also serves to permit the introduction of tools or conduits into the wellbore 9 beneath the sleeve.

In the illustrated embodiment, the seal 59 sealingly engages the inner surface 21 of thc production tubing at the upper end of the sleeve. Since the packer 7 prevents fluid from flowing to the surface via the annulus 6, this substantially prevents any flow of fluid between the tubular walls of the sleeve and the production tubing without requiring any corresponding seal at the lower end of the sleeve.

In alternative embodiments, one or more annular seals can be provided at both the upper and lower ends of the sleeve or elsewhere between the outer wall of the protection sleeve and the inner wall 21 of the production tubing. The or each seal may comprise a static elastomeric seal or expanding packer or any other suitable arrangement as known in the an, depending on the pressure differential (if any) across the sleeve and on how much flow is acceptable between the sleeve and the tubing. The sleeve functions to provide mechanical protection to the first wet connectors 30, 30' as well as excluding aggressive fluids. Depending on the fluids employed in the well, sufficient protection may be obtained without completely excluding wellbore fluids from the side pockets, and it will be understood that the protection sleeve may thus be sealingly engaged within the production tubing, merely by providing metal to metal contact with the inner surface 21 of the production tubing at one or more points along its length, and without necessarily requiring the seal 59 or any other specific scaling means. In some embodiments, a reasonably close fit as shown between the tubular walls of the protection sleeve and the production tubing, which are preferably arranged concentrically in the deployed position, and/or the flow resistance provided by a mechanical engagement portion such as the engagement portion 56, may adequately seal the protection sleeve in the production tubing.

Referring to Figs. 5A and SB, the well may then be stimulated by pumping a treatment fluid 100 (indicated by the flow arrows) into the well through the

S

aligned bores 23, 52 of the production tubing 20 and protection sleeve 50, while the protection sleeve effectively excludes the fluid from the side pockets.

In the illustrated embodiment, a conduit 60 comprising coiled tubing is deployed from a reel 61 via the wellhead 3 through the production tubing 20 and the protection sleeve 50 so as to define an annulus 62 between the conduit 60 and the production tubing 20 and protection sleeve 50. The acid or other treatment fluid is then pumped down the conduit, displacing fluid from the welibore which is discharged via the annulus 62 to surface so that the treatment fluid and displaced well fluid 100' circulate through the conduit and the annulus 62 comprising the bore 52 of the protection sleeve as shown.

In alternative embodiments, the packer 7 may be omitted, in which case the valves communicating with the annulus 6 may be closed at the wellhead to prevent flow to surface via the annulus through the perforations 32 or side pockets 29, 29', so that the single seal 59 creates a dead zone between the closely abutting surfaces of the protection slccvc and the production tubing in which no flow occurs. Fxcn without the seal 59, thc absence of any significant pressure differential across the protection sleeve may be sufficient to substantially prevent the treatment fluid From reaching the side pockets.

After treatment, the protection sleeve may be recovered via the wellhead to the surface on the wireline, and the ESP redeployed via the wellhead as described above.

In alternative embodiments, the tubing comprising the side pocket need not necessarily be production tubing; it could he for example the well casing or any other tubing installed in the borehole. The tool need not be an ESP, but could be a logging tool, valve, or any other electrically powered downhole equipment, which could also bc located in the rcspective side pocket rather than in the bore of the production tubing.

in alternative embodiments, the protection sleeve could be made from steel or any other suitable material, and the engagement portion could be any part adapted to engage the landing profile. The engagement portion need not be an integral part of the sleeve; for example, it could be a separate, unitary part made from a different material and attached to the main body of the sleeve, or it could comprise an asscmbly of parts, perhaps extendible and retractable by sliding movement of a collar, or any other convenient arrangement. The landing profile can be any feature adapted to be engaged by the corresponding cngagement portion of the protection sleeve so as to locate or retain the protection slcevc in its deployed position. Alternatively, the protection sleeve could be formed without any engagement portion, and retained in the deployed position by an expanding packer or the like.

In summary, in a preferred embodiment an electrical submersible pump or other downhole tool is powered via a wet connector located in a side pocket in production tubing and recovered to surface prior to acidizing the well. The side pocket is covered and protected from the treatment fluid by a tubular protection sleeve which is deployed from the surface and sealingly engaged in the production tubing in the position occupied by the pump. The bore of the protection sleeve opens into the bore of the production tubing so as to form a combined flowpath through which coiled tubing and other tooling can be inserted, the treatment fluid being pumped down the coiled tubing to displace wellbore fluid via the annulus within the production tubing and protection slccvc to the surface.

Further adaptations failing within the scope of the claims will be readily apparent to those skilled in the art.

Claims

CLAIMS1. An apparatus comprising: a tubing arranged within a vell, the tubing including a side pocket; a first wet connector located in the side pocket of the tubing; an insulated electrical conductor connecting the first wet connector to surface equipment via a welihead of the well; and an electrically powered tool including a sccond wct connector, the second wet connector being arranged to engage the first wet connector after the tool is lowered down the tubing so as to connect the tool to the conductor; characterised by a tubular protection sleeve, the protection sleeve being deployable via the wellhead down the tubing to a deployed position in which it is sealingly engaged within the tubing so as to cover the side pocket, and recoverable to surface via the wellhead from the deployed position.
2. An apparatus according to claim 1. wherein the protection sleeve is arranged concentrically within the tubing in thc deployed position.
3. An apparatus according to claim 1, wherein an upper end portion of the protection sleeve includes a recovery profile which is engageable by a tool on a wireline.
4. An apparatus according to claim 1, wherein thc tubing includes a landing profile and the sleeve includes an engagement portion which relcasably cngagcs the landing profile in the deployed position.II
5. An apparatus according to claim 4, wherein the engagement portion comprises an internal collet.
6. An apparatus according to claim 1, wherein the tool is an electrical submersible pump.
7. An apparatus according to claim 6, wherein the tubing includes perforations, and the pump is arranged to cause fluid to flow through the perforations in use, and the protection sleeve is arranged to cover the perforations in the deployed position.
8. An apparatus according to claim 1, wherein the tubing includcs an orientation profile, and the tool is arranged to engage the orientation profile so as to rotate the tool into an engagement position as the tool is lowered down the tubing, the second wet connector being arranged to engage the first wet connector when the tool is in the engagement position so as to connect the tool to the conductor.
9. A method for stimulating a well, the well including a tubing having a side pocket, a first wet connector located in the side pocket, and an insulated electrical conductor connecting the first wet connector to surface equipment via a wellhead of the well; the method comprising: lowering a tubular protection sleeve via the wellhead down the tubing and sealingly engaging the protection sleeve within the tubing in a deployed position so that it covers the side pocket; pumping a treatment fluid into the well through the tubing and the protectionsleeve;andthen recovering the protection sleeve to surface via the welihead from the dcploycd position; and then lowering an electrically powered tool via the welihead down the tubing and engaging a second wet connector on the tool with the first wet connector so as to connect the tool to the conductor.
10. A method according to claim 9, including lowering a conduit through the tubing and the protection slccvc so as to define an annulus between the conduit and the tubing; and circulating the treatment fluid and well fluid displaced by the treatment fluid through the conduit and the annulus.
11. An apparatus substantially as described with reference to the accompanying drawings.
12. A method substantially as described with reference to the accompanying drawings.