GB2406348A - Removal of cement residue obstruction - Google Patents

Abstract

A method of completing a well comprises cementing well production tubing 16 within a wellbore 10. Residual cement remaining in the tubing is confined within the bore of an axially transportable tube 36. The obstruction of the residual cement is removed by moving the said transportable tube to a position where fluid flow can bypass the tube.

Description

1 2406348 1 WELL COMPLETION METHOD AND APPARATUS

3 BACKGROUND OF THE INVENTION

4 Field of the Invention

The present invention relates to deep well 6 completion and production procedures and apparatus.

7 More particularly, the invention relates to 8 completion procedures and apparatus that avoid a 9 final cement plug drilling procedure and a corresponding tool change trip.

12 Description of the Prior Art

13 The process and apparatus by which deep production 14 wells for fluids such as oil and gas are completed and prepared for production involves the step of 16 sealing the production zone or earth strata from 17 contamination by foreign fluids from other strata, 18 above or below. Additionally, the tubing through 19 which the produced fluid flows to the surface must be secured and sealed within the well bore. Often, 21 the production zones are thousands of feet below the 22 earth's surface. Consequently, prior art procedures 1 for accomplishing these steps are complex and often 2 dangerous. Any procedural or equipment improvement 3 that eliminates a downhole "trip" is a welcomed 4 improvement.

6 Consistent with prior art practice, production tube 7 setting and opening are separate "trip " events.

8 First, the raw borehole wall casing is secured by 9 placing cement in the annulus between the raw borehole wall and the outer surface of the casing 11 pipe. A string of fluid production tubing is then 12 positioned where desired within the borehole and the 13 necessary annulus sealing packers are set by a 14 controlled fluid pressure increase internally of the tubing bore, for example. After the packers are 16 set, a cementing circulation valve in the production 17 tube assembly is opened by another controlled change 18 in the tubing bore pressure. Cement is then pumped 19 into the segment of annulus around the production tubing that extends upwardly from the upper 21 production zone packer.

23 This prior art procedure leaves a section of cement 24 within the tubing below the cementing valve that blocks the upper tubing bore from production flow.

26 The cement blockage is between the upper tubing bore 27 and the production screen at or near the terminal

28 end of the tubing string. Pursuant to prior art

29 practice, the residual cement blockage is usually removed by drilling. A drill bit and supporting 31 drill string must be lowered into the well, 1 internally of the production tubing, on a costly, 2 independent "trip" to cut away the blockage.

4 SUMMARY OF THE INVENTION

An objective of the present invention, therefore, is 6 to position well production tubing within the 7 wellbore, secure the tubing in the well by suitable 8 means such as cement or epoxy, and open the tubing 9 to production flow in one downhole trip.

11 Another objective of the invention is a completion 12 assembly having the capacity for complete removal of 13 the cement tubing plug without drilling.

It is also an object of the present invention to 16 provide a more expeditious method of well completion 17 by the elimination of at least one downhole trip.

19 In pursuit of these and other objectives to hereafter become apparent, the present invention 21 includes a production tubing string having the 22 present well completion tool body attached above the 23 upper production packer and the production screen.

24 The completion tool body includes upper and lower pipe subs that are linked by concentric radially 26 spaced tubular walls. The tubular walls are 27 perforated by flow bans for ports. With the 28 annular space between the concentric walls are a 29 pair of axially sliding sleeve pistons. Both sleeve pistons may be axially displaced by fluid pressure 31 within a central flow bore of the tool to close flow 32 continuity through the flow transfer ports between 1 the central flow bore and the surrounding well 2 annulus. An elongated mandrel tube is secured to 3 the internal bore surface of the tool body at a 4 point below the flow transfer ports. From the tool body attachment point, the mandrel tube extends 6 downwardly and concentrically within the production 7 tubing. A retainer socket terminates the lower end 8 of the mandrel tube. The mandrel tube wall is 9 perforated along the upper portion of its length above the plug seat.

12 Also secured within the internal bore surface of the 13 tool body at a point above the flow transfer port is 14 an elongated dart transport tube having a dart seat at each distal end. The dart transport tube extends 16 longitudinally within the internal bore of the 17 perforated mandrel and is releasably secured to the 18 internal bore surface of the tool body by a set of 19 locking dogs. Proximate of its upper end, the dart transport tube is perforated for flow continuity 21 with the flow transfer ports in the tool body 22 tubular walls.

24 The completion assembly is placed downhole with all tubes open. When in place, a first closing dart is 26 dropped along the production string bore from the 27 surface to be transferred by gravity and/or pumping 28 onto the closure seat at the downhole end of the 29 dart transport tube. Closure of the downhole seat permits the internal bore of the tubing string to be 31 pressurized independently of the of the production 32 zone wall.

2 The normal procedural sequence provides for a 3 relatively low tubing string pressure to set the 4 zone isolation packers. A second and greater fluid pressure within the production tubing opens the flow 6 transfer ports in the tool body by shifting one of 7 the closure sleeves. Cement is then delivered down 8 the tubing bore under a pressure head sufficient to 9 discharge the cement through the dart transport tube perforation and flow transfer ports in the tool body 11 into the annulus between the tubing string and the 12 casing wall.

14 When the appropriate quantity of cement has been delivered into the production tubing, a second 16 closure dart is placed in the tubing bore to cap the 17 surface of the cement column standing in the tubing 18 bore. A finishing fluid such as water is pumped 19 against the second dart thereby completing the flow displacement of the cement remaining in the 21 production tube. When the second dart engages the 22 upper seat of the dart transport tube, all cement is 23 displaced into the well annulus except that 24 remaining in the dart transport tube between the dart seats. Upon closure of the upper transport 2 6 tube seat, internal tubing bore pressure may be 27 increased to shift the second sleeve piston in the 28 tool body that simultaneously closes the flow 29 transfer ports and releases the locking dogs from the dart transport tube. When released, the dart 31 transport tube travels down the perforated mandrel 32 taking all of the residual cement with it.

2 At the end of the perforated mandrel is a retainer 3 socket that receives and engages a nose dart on the 4 dart transport tubing. This retainer socket secures the dart transport tube within and along a lower 6 segment of the mandrel. Above the dart transport 7 tube, the perforated mandrel is preferably pierced 8 by numerous large apertures to accommodate a free 9 flow of formation fluid into the internal bore of the production tube.

12 BRIEF DESCRIPTION OF THE DRAWINGS

13 The advantages and further aspects of the invention 14 will be readily appreciated by those of ordinary skill in the art as the same becomes better 16 understood by reference to the following detailed 17 description when considered in conjunction with the 18 accompanying drawings in which like reference 19 characters designate like elements throughout the several figures of the drawings and wherein: 22 FIG. 1 is a schematic well having the present 23 invention in place for completion and production; 24 FIG. 2 is an axial quarter section view of the invention as configured for initial downhole 26 placement; 27 FIG. 3 is an axial quarter section view of the 28 invention as configured for cement displacement into 29 the well bore; FIG. 4 is an axial quarter section view of the 31 invention as configured to purge the upper 32 production tube bore of residual cement; 1 FIG. 5 is an axial quarter section of the invention 2 as configured for formation fluid production; 4 FIG. 6 is an axial section view of the first conduit closure dart; 6 FIG. 7 is an axial section view of the second 7 conduit closure dart; 8 FIG. 8 is an axial quarter section view of an 9 alternative transport tube end dart within the perforated section of the perforated mandrel; 11 FIG. 9 is an axial quarter section view of the 12 alternative transport tube end dart with the 13 rectifying barb engaged with an internal ledge; 14 FIG. 10 is an axial quarter section view of the alternative transport tube end dart projecting from 16 the end of the perforated mandrel.

18 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 19 The utility environment of this invention is typified by the schematic of FIG. 1, which 21 illustrates a well bore 10 that is normally 22 initiated from the earth's surface in a vertical 23 direction. By means and procedures well known to

24 the prior art, the vertical well bore may be

continuously transitioned into a horizontal bore 26 orientation as desired for bottom hole location or 27 the configuration of a fluid production zone 12.

28 Usually, a portion of the vertical, surface borehole 29 10 is internally lined by steel casing pipe 14, which is set into place by cement in the annulus 31 between the borehole wall and outer surface of the 32 casing 14.

1 Valuable fluids such as petroleum and natural gas 2 held within the production zone 12 are efficiently 3 conducted to the surface for transport and refining 4 through a production tubing string 16. Herein the term "fluid" is given its broadest meaning to 6 include liquids gases, mixtures and plastic flow 7 solids. In many cases, the annulus between the 8 outer surface of the production tube 16 and the 9 inner surface of the casing 14 or raw well bore 10 will be blocked with some form of annulus barrier 11 such as a production packer 18. The most frequent 12 need for an annulus barrier such as a production 13 packer 18 is to shield the lower production zone 12 14 from contamination by fluids drained along the borehole 10 from higher zones and strata.

17 The terminal end of a production string 16 may be an 18 uncased open hole. However, the terminal end is 19 also often equipped with a liner or casing shoe 20 and a production screen 22. In lieu of a screen, a 21 length of drilled or slotted pipe may be used. The 22 production screen 22 is effective to grossly 23 separate particles of rock and earth from the 24 desired fluids carried by the formation 12 structure and admits the production zone fluids into the inner 26 bore of the tubing string 16. Accordingly, the term 27 "screen" is used expansively herein as the point of 28 well fluid entry into the production tube.

Pursuant to practice of the present invention, a 31 production string 16 is provided with the present 32 well completion tool assembly 30. The tool assembly 1 is positioned in the uphole direction from the 2 production screen 22 but usually in close proximity 3 therewith. As represented by FIG. 1, the production 4 packer 18, the completion tool assembly 30, the production screen 22 and the casing shoe 20 are 6 preassembled with the production tube 16 as the 7 production string is lowered into the wellbore 10.

9 Referring to FIG. 2, the tool assembly comprises a tool body 32, a perforated mandrel 34 and a dart 11 transport tube 36. The tool body 32 is terminated 12 at opposite ends by a top sub 40 and a bottom sub 13 42, respectively. The subs 40 and 42 are joined by 14 an internal sleeve 44 and an external sleeve 46.

Between the sleeves 44 and 46 is an annular cylinder 16 space. Axially slidable along the annular cylinder 17 space are two annular pistons 50 and 52. The upper 18 annular piston 50 is secured to the external sleeve 19 46 at an initial position by several shear pins 54.

The lower annular piston is secured at an initial 21 position by several shear pins 56.

23 The internal sleeve 44 is perforated by several 24 cement flow transfer ports 58 distributed around the sleeve circumference. The external sleeve 46 is 26 also perforated by several flow transfer ports 60 27 distributed around the sleeve circumference. The 28 flow transfer ports 58 and 60 are aligned to 29 facilitate fluid flow continuity through both ports from the interior bore of the internal sleeve 44 31 when the lower annular piston 52 is translated from 32 an initial, flow blocking position as illustrated by 1 FIG. 2, into the lower annular space 62. However, 2 radial alignment of the flow transfer ports is not 3 essential.

The inner sleeve 44 also includes several 6 perforations 48 around the circumference thereof 7 that provide fluid pressure communication between 8 the internal bore of the tool body 32 and the upper 9 piston pressure chamber 67. (See Fig. 4A) The inside surface of the upper piston 50 is circumferentially 11 channeled as a relief detent 66 for radial locking 12 dogs 68. The locking dogs 68 are carried by caging 13 apertures in the internal sleeve 44.

The perforated mandrel 34 is a subassembly of a 16 connecting sub 70 and a perforated flow tube 72.

17 The connecting sub 70 threads internally to the 18 lower tool body sub 42 and provides an internal 19 assembly thread for the perforated flow tube. An annulus sealing device such as a sand barrier, plug 21 or packer tube 18 assembles over the external 22 threads of the lower sub 42. An O-ring ridge and 23 seal 74 isolates an annular space between the outer 24 surface of the perforated flow tube and the inner surface of the packer tube bore. At the end of the 26 flow tube 72 is a dart plug retainer socket 76 27 around a bore end aperture 78. A plurality of 28 production flow perforations 80 penetrate the flow 29 tube 72 wall along an upper end length section.

31 The dart transport tube 36 slidably assembles 32 coaxially within the internal bore of the internal 1 sleeve 44 and extends coaxially into the internal 2 bore of the mandrel flow tube 72. The transport 3 tube is axially retained by the locking dogs 68 in 4 meshed cooperation with a circumferential detent channel 82. The upper end of the transport tube 6 form a dart plug seat 85. Below the dart plug seat 7 are several fluid flow apertures 87 distributed 8 around the transport tube circumference. The lower 9 end of the transport tube is terminated by a finale 89 having a projecting dart plug 90 and an internal 11 plug seat 92. An axial bore 94 extends through the 12 finale 89 and plug 90.

14 The dart plugs 100 and 102 of FIGS. 6 and 7 are essentially the same except for size. The smaller 16 dart plug 100 comprises a pintle nose 104 and 17 several dart fins 106. The pintle nose 104 is sized 18 and shaped to engage the transport tube seat 92 with 19 a fluid seal fit. The fins 106 facilitate the pumped transfer of the dart along the length of a 21 production string. The larger dart plug 102 has a 22 pintle nose 108 that is appropriately sized to make 23 a fluid tight seal with the upper transport tube 24 seat 85. The nose of dart plug 90 at the terminal end of the transport tube 36 is sized to fit the 26 retainer socket 76 at the terminal end of the 27 perforated flow tube 72. A mechanical latching 28 relationship between the retainer socket 78 and dart 29 plug 90 secures the transport tube 36 at the lower end of the mandrel flow tube 72 once the dart plug 31 90 engages the socket 78.

1 For purposes of this preferred embodiment, the plugs 2 100 and 102 have been described as "darts". It 3 should be understood, however, that the plugs may 4 also be configured as balls, sponges or rods.

6 As an additional note to the perforated mandrel 34 7 design, the length of the mandrel flow tube 72 8 preferably includes a non-perforated section below 9 the perforated section. The length of the non perforated section of flow tube 72 generally 11 corresponds to the length of the dart transport tube 12 36. An anti-reversing clip 96 is secured to the 13 flow tube wall preferably at numerous point along 14 the mandrel flow tube. Once the dart transport tube 36 has been translated to the lower end of the 16 mandrel flow tube 72, the anti-reversing clips 96 17 will prevent a reverse translation of the transport 18 tube 36 by engaging the trailing edges of the 19 terminal fins 110.

21 The machine element alignments for running into a 22 well are as illustrated by FIG. 2. Specifically, 23 flow continuity between the cement flow transfer 24 ports 58, 60 and 87 are aligned but closed between the ports 58 and 60 is interrupted by the annular 26 piston 52. The closed position of the piston 52 is 27 secured by the shear pin 56. The annular piston 50 28 is confined in the annular cylinder space above the 29 lower piston 52 by the shear pin 54 and the end of the lower piston 52. In the upper position, the 31 upper piston 50 confines the locking dogs 68 within 32 respective caging apertures in the internal sleeve 1 44 to penetrate the detent channel 82 in the dart 2 transport tube 36. Consequently, the transport tube 3 36 is secured at the required axial position. There 4 are no plugs in the bore so there is a free transfer of well fluids along the tubing bore.

7 With respect to FIG. 3, the completion string 8 assembly is positioned along the borehole length at 9 the desired set position. At this point, the dart plug 100 is placed in the production tubing bore at ll the well surface and either pumped or permitted to 12 gravitate down onto the transport tube bore seat 92 13 to close the flow bore 94. With the flow bore 94 14 closed, the fluid pressure within the tubing string bore may be increased by surface pumps (Not Shown) 16 to set the packer 18 against the well wall, whether 17 cased or raw borehole.

19 With the packer 18 set, the tubing bore pressure is further increased to bear against the upper end of 21 the annular piston 52. When sufficient, the 22 pressure load on the piston 52 shears the retainer 23 pins 56 and drives the piston 52 down into the 24 annular cylinder space 62 and away from the openings of flow transfer ports 58 and 60. Well completion 26 cement may now be pumped along the bore of tubing 16 27 into the production tube annulus. Due to the 28 presence of the packer 18, downflow of the cement 29 between the screens 22 and the production zone face is prevented. The cement is forced to flow upward 31 from outer flow ports 60 around the production tube.

1 When the predetermined quantity of cement has been 2 placed in the production tube bore, the tail end of 3 the cement column is capped by the larger dart plug 4 102. Another well working fluid such as water is then pumped against the dart fins 110 thereby 6 driving the column of cement in the production tube 7 bore out through the flow ports 58, 60 and 87.

8 Cement displacement by the dart plug 102 ends when 9 the dart plug engages the transport tube upper seat 85 as illustrated by FIG. 4. The only residual 11 cement remaining within the production tube is that 12 filling the transport tube 36 between the seats 85 13 and 92.

With the dart plug 102 set against the transport 16 tube seat 85, tubing borehole pressure may again be 17 increased. Such increased pressure bears now 18 against the upper end of the upper piston 50 through 19 the pressure ports 48. When the resultant force on the piston end face is sufficient, the retainer pins 21 54 will fail thereby permitting the upper piston to 22 translate down the annular space against the end 23 face of the lower piston 52 to obstruct the cement 24 flow path between ports 58 and 60. Simultaneously, the down position of the upper piston 50 aligns the 26 detent channel 66 with the locking dogs 68 thereby 27 permitting the dogs to translate radially out of 28 interfering engagement with the detent channel 82 in 29 the dart transport tube 36.

31 A body lock ring 64 that is secured to the upper end 32 of the upper piston 50 engages strategically 1 positioned circumferential threads or serrations on 2 the outer perimeter of the internal sleeve 44 to 3 secure the displaced position of the piston 50 and 4 the closure of flow continuity between flow transfer ports 58 and 60.

7 Upon withdrawal of the locking dogs 68, the dart 8 transport tube is free to translate down the length 9 of the perforated mandrel 34 to latch the dart 90 into the retainer socket 76 as illustrated by FIGS. 11 4 and 5. This shift opens a formation fluid flow 12 channel from the screens 22, along an annulus 13 between the screen tubing bore and the perforated 14 mandrel 34, through the mandrel perforations 80 and into the internal flow bore of the tool body 16 internal sleeve 44.

18 FIGS. 8, 9 and 10 illustrate an alternative design 19 embodiment for securing the transport tube 36 to the distal end of the perforated mandrel.

21 Primarily, the alternative dart plug 120 comprises a 22 projecting stinger 122 having several radially 23 projecting spring barbs 124. As shown by FIG. 8, 24 the barb 124 flexes away from the inside bore wall of the perforated mandrel flow tube 72 as it passes 26 through the section of perforations 80. Below the 27 perforations 80 but above the distal end of the 28 mandrel flow tube 72, one or more sharp bottom 29 grooves 128 may be cut into the inside wall of the flow tube as shown by FIG. 9, to latch the barbs 31 intermediate of the flow tube end. FIG. 10 32 illustrates the stinger 122 projecting from the end 1 of the mandrel flow tube 72 and the dart shoulder 2 126 effectively engaging the shoulder 76.

4 The foregoing preferred embodiment of the invention has been described in relation to a previously cased 6 and perforated well bore. It should be understood, 7 however, that the invention is equally applicable to 8 an uncased borehole. It should also be understood 9 that "production tubing", "tubing string", "production string", production casing", etc. are 11 all equivalent terms in the lexicon of the art.

13 Although the invention has been described in terms 14 of certain preferred embodiments, it will become apparent to those of ordinary skill in the art that 16 modifications and improvements can be made to the 17 inventive concepts herein without departing from the 18 scope of the invention. The embodiments shown herein 19 are merely illustrative of the inventive concepts and should not be interpreted as limiting the scope 21 of the invention.

Claims (2)

1 CLAIMS 3 1. A method of producing a well comprising the 4 steps of: 6

(a) positioning well fluid production tubing within 7 a well borehole in flow communication with a 8 well production zone; 9 (b) cementing said production tubing within said well borehole above said well production zone; 11 (c) confining substantially all residual cement 12 remaining in said production tubing within the 13 bore of an axially transported tube; and, 14 (d) opening the internal bore of said production tubing to fluid flow from said production zone 16 by moving said axially transported tube within 17 said production tubing from a flow obstructing 18 position.

2. A method of producing a well as described by 21 claim 1 wherein an annulus barrier is erected 22 in said borehole around said production tubing 23 and above said well production zone.