GB2425136A

GB2425136A - Removing debris from a wellbore

Info

Publication number: GB2425136A
Application number: GB0519247A
Authority: GB
Inventors: Daniel Purkis
Original assignee: Petrowell Ltd
Current assignee: Petrowell Ltd
Priority date: 2005-04-13
Filing date: 2005-09-21
Publication date: 2006-10-18
Anticipated expiration: 2025-09-21
Also published as: GB0507408D0; GB2425136B; GB0519247D0; WO2006109008A1

Abstract

A wellbore is cleaned by inserting a conduit 10 into the wellbore, sealing off an annular portion of the wellbore with seals 20, 21, e.g. cup seals, and operating a jet pump 12 within the conduit to move debris located within the sealed area into the conduit for removal from the wellbore. The conduit is centred in the wellbore by a packer 15 and a swivel sub 16 is provided to isolate rotational movement between the two ends of the conduit.

Description

1 Apparatus 3 This invention relates to apparatus and a method for 4

removing debris from a welibore.

6 The invention is particularly useful in the removal 7 of the debris from the perforated region of a 8 welibore, after the perforations have been made into 9 the formation.

11 When a new wellbore is drilled into a reservoir, the 12 wellbore is lined with casing or liner, which is 13 subsequently perforated in the region of the 14 reservoir from which fluids are to be produced. The liner is perforated using explosive charges from a 16 perforation gun, which blasts holes through the wall 17 of the liner, and into the reservoir payzone. This 18 perforation process is intended to enhance 19 production of fluids from the perforated area, but the process is inherently destructive, and the 21 payzone region of the reservoir can be damaged by 22 the blast from the perforation gun. Also, the 1 debris generated by the blast can often reduce 2 recovery of useful produced fluids through the 3 perforations.

According to the present invention there is provided 6 apparatus for removing debris from a welibore, the 7 apparatus comprising a conduit for insertion into 8 the weilbore, a device for generating a pressure 9 difference in the weilbore, a seal defining a sealed area within the wellbore, wherein the device for 11 generating the pressure difference is arranged to 12 create a pressure differential between the inner 13 bore of the conduit and the sealed area, whereby 14 debris located in the sealed area is caused to move into the conduit for removal from the we].lbore.

17 The apparatus is typically deployed within the 18 welibore, so as to create an annulus between the 19 wellbore and the conduit. The seal is typically located in the annulus, and typically seals the 21 conduit to the wellbore, so as to seal off a part of 22 the annulus in the sealed area.

24 In some embodiments, an anchor device is provided to fix the position of the conduit and the sealed area 26 with respect to the welibore. Typically, the anchor 27 device can also seal the annulus between the 28 wellbore and the conduit. In some embodiments, the 29 anchor device can be a packer, which can be a tension or compression packer. Other designs of 31 packer can be used. In some embodiments, the packer 32 can provide both the sealing and anchoring 1 functions. Other anchors such as slips etc can be 2 used instead of packers.

4 In some embodiments, a swivel sub can be provided to isolate rotational movement of upper and lower parts 6 of the conduit.

8 In typical embodiments, the sealed area has an 9 aperture that communicates with the conduit in order to permit debris from the sealed area to move 11 through the conduit. The sealed area typically has 12 upper and lower seals, and in some embodiments, two 13 upper seals, and two lower seals are provided.

14 Typically, the seals are cup seals, and are optionally annular cup seals.

17 In some embodiments, the device for generating a 18 pressure difference can comprise a pump, typically a 19 jet pump. In typical embodiments, the pump can generate a pressure drop across the sealed area, so 21 that the pressure in the sealed area is higher than 22 the pressure in the conduit, and a vacuum is created 23 in the area of the annulus. The debris arising from 24 the perforation process is thereby drawn from the perforations, and from the annulus, through the 26 aperture and into the conduit. Thus, the pump can 27 draw fluids and debris from the sealed area into the 28 conduit for removal from the wellbore.

In some embodiments, the apparatus has a bypass 31 conduit that enables fluids to flow through the 32 apparatus without communicating with the conduit for 1 removing the debris from the weilbore. This is a 2 useful optional feature, as it permits the apparatus 3 to be moved axially within the welibore without 4 inducing pressure changes across the seals, because the fluids displaced by the movement of the 6 apparatus through the weilbore travel through the 7 bypass conduit, without being exposed to the seals.

9 In some embodiments, a valve assembly is provided in the apparatus to open and close the bypass conduit, 11 and to control fluid flow through the apparatus.

13 The bypass conduit and valve assembly reduce the 14 risk of buliheading when running into a well (forcing fluids into the formation under pressure), 16 and the risk of swabbing during recovery from the 17 well (excessive suction of fluids from the 18 formation).

An embodiment of the invention will now be described 21 by way of example, and with reference to the 22 accompanying drawings, in which; 24 Fig. 1 is a part sectional side view of apparatus for removing debris from a weilbore; 27 Fig. 2 is a detailed sectional side view of a 28 second embodiment of apparatus for removing 29 debris from a weilbore; 31 Figs. 3-6 are expanded views of sequential 32 parts of the Fig. 2 apparatus; 2 Fig. 7 is an expanded view of the end of the 3 Fig. 2 apparatus, showing two alternative 4 configurations; and 6 Fig. 8 is a further alternative configuration 7 of the end of the Fig. 2 apparatus, showing in 8 Fig. 8a the configuration adopted in flushing 9 and in pulling out of hole, and in Fig. 8b, the configuration adopted in reverse flushing.

12 Referring now to the drawings, apparatus for 13 removing debris from a wellbore is located at the 14 end of a section of casing C, crossing the junction between the casing C and a section of liner L 16 containing a perforation zone P in which the liner L 17 has been perforated by a conventional perforation 18 gun (not shown) . The apparatus comprises a central 19 conduit 10 that houses a jet pump 12 (or similar) which is arranged to create a pressure differential 21 across the pump so that the pressure below the pump 22 is lower than the pressure above it. Thus, fluids 23 below the jet pump 12 are drawn upwards through the 24 conduit 10.

26 The apparatus is centered in the weilbore by means 27 of a packer 15. The packer 15 can be of any 28 convenient design, but suitable packers include 29 tension and compression packers. The packer 15 is set to expand its outer surface against the inner 31 surface of the casing C, so as to anchor the 32 apparatus in the desired axial location within the 1 welibore. The packer 15 also typically seals the 2 annulus between the conduit 10 and the casing C, 3 especially when a jet pump is used, as the jet pump 4 can then be driven by pumping fluid down the annulus between the conduit 10 and the casing C, and 6 diverting it into the inlet of the jet pump 12 by 7 means of the seal on the packer 15.

9 Below the packer 15, an optional swivel sub 16 is provided. The swivel sub isolates rotational 11 movement between the two ends of the conduit 10.

13 Below the swivel sub 16, an upper seal assembly 20 14 seals the annulus between the conduit 10 and the liner L. A lower seal assembly 21 is provided below 16 the upper seal assembly 20, and between the two seal 17 assemblies 20, 21, at least one aperture 25 is 18 provided in the body of the conduit 10 that permits 19 fluid communication through the wall of the conduit 10. The upper and lower seal assemblies 20, 21 21 comprise cup type seals that define a sealed area in 22 the annulus between the conduit 10 and the liner L. 23 The apertures 25 are positioned in the sealed area.

The apparatus is deployed in the wellbore on tubing 26 or drill pipe etc, and is lowered to a depth at 27 which the upper and lower seals 20, 21 straddle the 28 perforation zone P in the formation. At that point, 29 the packer 15 is set to anchor the apparatus at the set depth, and to seal off the annulus. The cup 31 type seals 20, 21 are automatically energised in the 32 narrower liner L, and the two seals 20, 21 define 1 between them a sealed area S of the annulus in the 2 vicinity of the perforation zone P. The sealed area 3 S is in fluid communication with the conduit 10 4 through the apertures 25, and is in communication with the reservoir through the perforations.

7 In use, the jet pump 12 is activated in order to 8 draw fluids from the conduit 10 below the pump 12.

9 The conduit 10 below the pump opens into the sealed area S, and thus any fluids and particulate matter 11 resident in the sealed area S are drawn through the 12 apertures 25 into the conduit 10, and upwards 13 through the conduit 10 to the surface. This process 14 removes the particulate debris from the perforation zone P that is left after the perforation process is 16 completed. Removal of the particulate debris from 17 the perforation zone P enhances the flow of 18 production fluids through the perforations in the 19 production phase of the well.

21 The upper and lower seal assemblies 20, 21 isolate 22 the sealed area S, and focus the suction from the 23 pump 12 onto the sealed area S. The jet pump 12 can be a conventional pump of a 26 Venturi design, and is typically activated by 27 pumping fluids into the annulus between the conduit 28 10 and the casing C. The packer 15 isolates the 29 annulus above the packer 15 from the annulus below, so all fluid pumped into the annulus from above the 31 packer is diverted into the inlet of the jet pump 32 12, and so drives the suction applied by the jet ) 1 pump 12 to the portion of the conduit 10 below the 2 pump. Other designs of pump can be employed with 3 other embodiments of the invention, and the 4 invention is not limited to the use of jet pumps.

6 When the particulate debris has been removed from 7 the sealed area S, the packer 15 can be unset, and 8 the apparatus can be moved axially upwards or 9 downwards in the well, so that the upper and lower seals 20, 21 straddle a different area of the 11 perforations. When a new target area of the 12 perforations is straddled in this manner, the packer 13 15 can be reset to anchor the apparatus in the new 14 position and define a second sealed area, and the process repeated to clear the second sealed area of 16 particulate debris caused by the perforation 17 process. In this way, different areas of the well 18 can be treated using the apparatus.

In the embodiment shown in Fig 1, a valve 26 can be 21 provided at the lower end of the assembly.

22 Typically the valve can open when pressure within 23 the conduit is too high, but remains closed when the 24 vacuum is being applied to the sealed area S. 26 A second embodiment of the invention shown in figs 27 2-8, in which the packer and the jet pump are 28 similar to those used for the first embodiment, but 29 which are not shown in these figures. It will be appreciated that the Figs. 2-8 show sequential 31 segments of the same apparatus, and that the lower 32 end of the component in Fig. 3 is connected to the ) 1 upper end of the component in Fig. 4 etc. 3 The second embodiment is deployed in casing C, and 4 has a connection sub 30 at its upper end, with a typical pin/box connector 31 for a connection to 6 drill pipe in a conventional manner. Above the box 7 connector is disposed a suitable packer and pump as 8 previously described, but not shown in these 9 figures. The second embodiment has an inner conduit 32 with a central bore 32b, concentrically located 11 within an outer conduit 33, with an annulus 34 12 therebetween. The inner and outer conduits 32, 33 13 are continuous throughout the length of the 14 apparatus. The central bore 32b of the inner conduit 32 provides the recovery conduit for extraction of 16 the particulate debris and fluids from the sealed 17 area S as previously described. The annulus 34 18 between the inner and outer conduits 32, 33 provides 19 a bypass for fluid to move through the apparatus without passing through the recovery conduit 32b.

22 The outer conduit 33 is sealed to the inner surface 23 of the wellbore by an upper seal sub 35 (Fig. 4) and 24 a lower seal sub 45 (Fig. 6) . Between the upper and lower seal subs, an aperture sub 40 (Fig. 5) has a 26 circumferential arrangement of apertures through the 27 outer conduit and inner conduits, thereby connecting 28 the inner bore 32b with the sealed area S of annulus 29 between the outer conduit 34 and the inner surface of the casing C. Below the lower seal sub 45, a 31 valve sub 50 controls the access of fluids to the 32 annulus 34, to be described. n

2 Turning now to the detail of Fig. 3, the connection 3 sub 30 has a yoke 30y with a narrow throat that is 4 internally threaded to receive an external thread on the end of the inner conduit 32. Below the narrow 6 throat, a wider portion 30w is internally threaded 7 to receive the external thread on the outer conduit 8 33. Thus, the yoke 30y connects the inner and outer 9 conduits together concentrically, defining the annulus 34 therebetween. The junction between the 11 narrow throat and the wider portion has a 12 circumferential arrangement of apertures 30a that 13 connect the annulus 34 between the inner and outer 14 conduits with the annulus between the outer conduit 33 and the casing C, so that fluids flowing through 16 the apertures 30a enter the annulus 34.

18 Turning now to Fig. 4, the upper seal sub 35 19 continues the inner and outer conduits 33, 32, maintaining the continuity of the inner bore 32b and 21 the annulus 34. The upper seal sub 35 has external 22 cup type seals 36 and 37 arranged on the outer 23 surface of the outer conduit 33, and directed 24 towards the upper end of the apparatus, so that they are energised against the inner wall of the casing C 26 in the event that the pressure in the annulus above 27 the seals exceeds the pressure below the seals.

29 Turning now to Fig. 5, and the upper seal sub 35 is connected at its lower end to the aperture sub 40.

31 The aperture sub 40 comprises an upper connector 41, 32 a bypass manifold 42, and a lower connector 43. The 1 continuity of the annulus 34 is maintained through 2 the aperture sub 40, by annulus channels 34a 3 extending axially through the bypass manifold 42, 4 and into the annulus 34 below the bypass manifold.

The bypass manifold 42 also has radially extending 6 channels 42b connecting the bore 32b with the 7 annulus between the outer surface of the aperture 8 sub 40 and the inner surface of the casing C. The 9 apertures 34a and 42b do not intersect, and the aperture sub maintains the barrier between the 11 annulus 34 and the bore 32b.

13 Referring now to Fig. 6, the lower end of the 14 aperture sub 40 is connected to the upper end of the lower seal sub 45. The lower seal sub 45 has upper 16 and lower seals 46, 47, and is essentially the same 17 as the upper seal sub 35, but is inverted with 18 respect to the upper seal sub, so that the seals are 19 energised when the pressure below them exceeds the pressure above them. The continuity of the inner 21 bore 32b and the annulus 34 is maintained throughout 22 the lower seal sub 45.

24 Referring now to Fig. 7, the inner and outer conduits 32, 33 terminate in the valve sub 50. The 26 outer surface of the outer conduit 33 has a collar 27 51 connected and sealed thereto by means of a shear 28 pin or collet and 0-rings. The lower end of the 29 collar 51 extends radially inwards at 511 into the annulus 34 to engage the outer surface of the inner 31 conduit 32. Axial apertures Sla permit fluid 32 communication through the collar 51, maintaining the 1 fluid communication through the annulus 34.

3 The collar 51 is located within the bore of a neck 4 52 having a wide upper portion that engages with the outer surface of the collar 51, and a narrower lower 6 portion. Between the upper and lower portions of 7 the neck 52, a circumferential arrangement of 8 apertures 52a is formed connecting the outside of 9 the neck 52 with the inner bore thereof. The lower end of the neck 52 carries a nose portion 53.

12 The lower end of the inner conduit 32 is located 13 within the bore of an end sleeve 55 slidable on the 14 outer surface of the inner conduit 32. The bore of the end sleeve 55 is continuous with the central 16 bore 32b. The end sleeve 55 is sealed to the outer 17 surface of the inner conduit 32 by means of 0-rings, 18 and is biased upwardly by a spring 52s. The outer 19 surface of the sleeve 55 has a shoulder portion 55s facing the upper end of the sleeve 55, and extending 21 radially outwards.

22 A further sleeve 56 (designated the upper sleeve) is 23 located within the bore of the neck 52, and between 24 the neck 52 and the lower portion 511 of the collar 51. The upper sleeve 56 is biased downwards by 26 means of a spring, and has a downward facing 27 shoulder 56s at its inner surface.

29 Under normal conditions, the upper sleeve 56 is biased downwards, and the end sleeve 55 is biased 31 upwards within the bore of the upper sleeve 56, such 32 that the shoulders 55s and 56s overlap, and close 1 off the annulus 34, substantially preventing fluid 2 passage of fluid from the annulus 34 through the 3 apertures 52a.

When the apparatus is being run into the hole as 6 shown in Fig. 7b, buliheading may tend to result, 7 resulting in higher pressure below the tool than 8 above it. This is undesirable, as it may lead to 9 forcing of fluids and particulate matter into the formation ahead of the tool, which can damage the 11 formation. The strength of the springs that bias 12 the sleeves 55, 56 is selected so that the pressure 13 of fluid ahead of the apparatus while running in is 14 generally sufficient to force the upper sleeve 56 back against the force of its spring, thereby 16 separating the sleeves 55, 56 as shown in Fig. 7a, 17 allowing fluid pressure building up the below the 18 apparatus to escape into the neck 52 through 19 apertures 52s, and between the shoulders 56s and 55s, thereby bypassing the restriction of the packer 21 in the casing by passing through the annulus 34, and 22 eventually exhausting through the apertures 30a in 23 the connection sub 30. When the pressure equalises 24 across the shoulders 55s, 56s (for example, if the string stops moving during the run in) the sleeves 26 55, 56 will close together, thereby returning the 27 ra1ve sub to the configuration shown in Fig. 7b.

29 Referring now to Fig. 8, the apparatus can also be used to circulate fluids in the wellbore in various 31 configurations. This can be helpful in order to 32 move particulate debris away from certain areas of 1 the well. Flushing and reverse flushing can 2 optionally be carried out to free tools that are 3 stuck in sand or otherwise unable to move axially 4 within the casing C. During flushing and reverse flushing, the packer is generally unset, and fluids 6 are pumped through the apparatus to create a flow 7 regime around the lower end of the apparatus, to 8 wash away sand and other debris that might cause the 9 apparatus to stick in the well.

11 In the configuration shown in Fig. 8a, fluid is 12 circulated through the central bore 32b, into the 13 lower sleeve 55, 50 that the buildup of pressure 14 within the bore 32b causes the lower sleeve 55 to move downwards against the force of its spring 52s.

16 This exposes the apertures 55a in the lower sleeve, 17 and allows the fluid to flow from the lower end of 18 the tool, and re-enter the annulus 34 through the 19 apertures 52a as shown in Fig. 8a. The annulus 34 is exposed to admit the fluid when the pressure 21 builds up sufficiently to move the sleeves 55, 56 as 22 described above for the running in procedure.

23 When the pressure equalises, the springs with return 24 the valve sub 50 to the fig 7b configuration, and the shoulders 555, 56s will close off the annulus 26 34.

28 With reference to Fig. 8b, the fluid can also be 29 circulated down the annulus 34, past the shoulders 55s, 56s (subject to sufficient pressure 31 differential across the shoulders) and out of the 32 apertures 52a, whereupon the fluid can re-enter the ) 1 lower end of the tool through the apertures 55a, and 2 be recovered through the central bore 32b. Again, 3 when the pressure differential drops, the shoulders 4 will be forced together by the biasing action of the springs, and the annulus 34 will close. The radial 6 apertures Slb, allow pressure equalisation across 7 the upper sleeve 56.

9 Modifications and improvements can be incorporated without departing from the scope of the invention.

Claims

1 Claims 3 1. Apparatus for removing debris from a welibore, 4 the

apparatus comprising a conduit for insertion into the welibore, a device for generating a 6 pressure difference in the wellbore, a seal defining 7 a sealed area within the wellbore, wherein the 8 device for generating the pressure difference is 9 arranged to create a pressure differential between the inner bore of the conduit and the sealed area, 11 whereby debris located in the sealed area is caused 12 to move into the conduit for removal from the 13 weilbore.

2. Apparatus as claimed in claim 1, wherein the 16 sealed area is an annulus between the conduit and 17 the weilbore.

19 3. Apparatus as claimed in claims 1 or 2, having an anchor device to fix the position of the conduit 21 and the sealed area with respect to the weilbore.

23 4. Apparatus as claimed in claim 3, wherein the 24 anchor device is adapted to seal an annulus between the wellbore and the conduit.

27 5. Apparatus as claimed in claims 3 or 4, wherein 28 the anchor device is a packer.

6. Apparatus as claimed in any preceding claim, 31 having a swivel device to isolate rotational 32 movement of different parts of the conduit.

2 7. Apparatus as claimed in any preceding claim, 3 wherein the sealed area has an aperture that 4 communicates with the conduit in order to permit debris from the sealed area to move through the 6 conduit.

8 8. Apparatus as claimed in any preceding claim, 9 wherein the sealed area has at least one upper seal and at least one lower seal.

12 9. Apparatus as claimed in any preceding claim, 13 wherein the seals are annular seals.

10. Apparatus as claimed in claim 8, wherein the 16 seals are cup seals.

18 11. Apparatus as claimed in any preceding claim, 19 wherein the seals are arranged to maintain a lower pressure in the sealed area than in the conduit.

22 12. Apparatus as claimed in any preceding claim, 23 wherein the seals on opposing sides of the sealed 24 area are oriented in opposite directions.

26 13. Apparatus as claimed in any preceding claim, 27 wherein the device for generating a pressure 28 difference comprises a jet pump.

14. Apparatus as claimed in any preceding claim, 31 wherein the apparatus has a bypass conduit that 32 enables fluids to flow through the apparatus without 1 communicating with the conduit for removing the 2 debris from the welibore.

4 15. Apparatus as claimed in any preceding claim, having a valve assembly to control fluid flow 6 through the apparatus.

8 16. A method of cleaning a weilbore, the method 9 comprising the steps of inserting a conduit into the welibore, at least partially sealing off a portion 11 of a weilbore, generating a pressure differential 12 between the inner bore of the conduit and the sealed 13 area, whereby debris located in the sealed area is 14 caused to move into the conduit for removal from the wellbore.

17 17. A method as claimed in claim 16, wherein the 18 sealed area comprises an annulus between the 19 welibore and the conduit.

21 18. A method as claimed in claims 16 or 17, wherein 22 the pressure differential is a pressure drop across 23 the sealed area, so that the pressure in the sealed 24 area is higher than the pressure in the conduit, and a vacuum is created in the area of the annulus, 26 thereby drawing debris from the sealed area into the 27 conduit.