Casing Repair

FICHE FEED BACK N Date: 02/99 Auteur: J.CAUREL B.GRIMBERT

9 5/8 CASING REPAIR: Filiale: TOTAL ABK

TEP/DO/FPL/MTH - INTERNAL CASING PATCH- CASING BACK OFF & RECONNECTION Page: 1/ 15

File : H:\section-DO-D\Procedure\fiches de feedback\Casing patch\958repair.doc

RUBRIQUES: CASING REPAIR

TECHNIQUES: INTERNAL CASING PATCH

CASING BACK-OFF & RECONNECTION

KEYWORDS: CORROSION LOG, CASING DAMAGE, CASING REPAIRINTERNAL CASING PATCH,HYDRAULIC CASING BACK OFF TOOLCASING RECONNECTION, CASING ALIGNEMENT TOOL

SUMMARY: The 9 5/8 casing in well AK-13-1 was damaged @ 300 m,MDfollowing an heavy fishing operation. A USIT Corrosion logindicated 1) oval casing and strain hardening (jarring effect), 2)deep marks resulting in reduced thickness of the casing (millingeffect).The casing was first successfully repaired in June 1998 with anexpandable internal casing patch, in order to complete andproduce the well as quick as possible.In January 1999, the well was to be side tracked. Uncertainty onactual ID of the patch led to the decision to recover the topsection of the 9 5/8 casing, including the patch and toreconnect new 9 5/8 casing.The 9 5/8 top casing was successfully cut, then backed-off. Anew top 9 5/8 casing was successfully reconnected.The damaged top section of the 9 5/8 casing was then studiedin detail.

TYPE OF FICHE: OPERATIONAL REPORT

CONTACT: J. CAUREL, X. CHASSERIAUD, B. GRIMBERT, L. LEGURUN,Y. MOINEL, A. RAZIMBAUD, DO/D, TOTAL ABK.

REF. DOCUMENTS: AK-13-1, WELL REPORT, TOTAL ABKAK-13-2, WELL PROGRAMME, TOTAL ABKAK-13-2, WELL REPORT, TOTAL ABK





TABLE OF CONTENT

1. WELL AK-13-1 SITUATION (June 1998)

2. USIT CORROSION LOG and RESULTS

3. INTERNAL CASING PATCH

4. OPTIONS TO SIDE TRACK AK-13-1 (January 1999)

5. CASING RECOVERY, CASING RECONNECTION

5.1. OPERATION PREPARATION5.2. CUTTING AND PULLING THE CASING5.3. BACK-OFF5.4. RECONNECTION OF THE NEW CASING5.5. LANDING CASING ON EMERGENCY HANGER (CAMERON MC2)

6. COSTS & CONCLUSIONS

7. DETAILED ANALYSIS OF THE CASING AND PATCH AFTER RECOVERY





1. WELL AK-13-1 SITUATION (June 1998):

A whipstock accidentally set at 303 m (vertical section of the well) in the 9 5/8 casing in well AK-13-1. It was jarred (up to 200 klbf overpull) and milled (washed over) until it was recovered.The resulting damage to the 9 5/8 casing was evaluated with a USIT corrosion log (cf. 2).Analysis of the results indicated that the casing had to be repaired.Well AK-13-1 was expected to be a good producer (Horizontal drain in Thamama 1 reservoir) andwas to be drilled to TD and completed as quickly as possible. It was decided to repair the damagecasing with an expandable casing patch (cf. 3).

2. USIT CORROSION LOG and RESULTS

After the fishing job, the casing was positively tested to 3000 psi. A USIT corrosion log was runfrom 350 m to 150 m. Two types of damage to the casing were detected:

- Oval casing, from 281.5 to 282.25 m, reduction of the casing thickness to 7 mm (strain hardeningof the casing due to jarring effect). The resulting burst capacity for the damaged casing is 3842psi.

- Milling damage (deep marks), 279 to 281.5 m, reduction of the casing thickness to 6.3 mm. Theresulting burst capacity for the damaged casing is 3393 psi.

Figure 1: USIT corrosion log showing jarring and milling damage.

The milling damage to the casing was not taken as a matter of concern because the corrosionrate could be reduced to less than 0.01 mm/ year with corrosion inhibitor.

The cold work of the casing resulted in a plastic deformation largely exceeding the yield strength of thematerial. The deformed section would be a zone of stress concentration under internal pressure and would





render it sensitive to Sulphide Stress Corrosion Cracking (highly likely in sour wet gas environment). Thissituation was not acceptable.Although the safest recommendation was to remove the top damaged 9 5/8 casing, it was urgent to completeand produce the well. It was decided to repair the damaged 9 5/8 casing using an internal casing patch thatwould cover the stress concentration zone in the damaged casing with an excess of 2 meters on each side.

3. INTERNAL CASING PATCH

The Homco internal expandable casing patch (weatherford) was available inAbu Dhabi. Its technology had been looked in the past and was felt reliable.

The patch is a corrugated shape liner (star shaped cross section), withfiberglass cloth on the outside (epoxy applied to the fiberglass when runningin hole) that is forced to expand and anchored against the casing wall by anexpanding cylinder. The expanding cylinder is driven inside the patch (forcingit to expand) by a dual hydraulic cylinder assembly (slide valve, bumper jar,hydraulic hold down, dual cylinder).

1 - Setting assy.

2 - Tubing is raised to close the circulating valve.

3 - Hydraulic pressure is applied to force out buttons on the hydraulic holddown. This anchors the cylinder firmly and isolates the work string from alltensile loads caused by the setting operations.

4 - Pressure on underside the pistons pulls expander assy into the bottomof the patch. As pressure increases, the expander assembly is forced furtherinto the patch, expanding it against the inside of the casing (5 of patchexpanded per stroke). The circulating valve is opened by lowering tubing andtelescoping the slide valve. Tubing is raised again to pull up the cylinders inrelation to pistons held down by the expander assembly. Expanded sectionof patch is anchored to the casing wall by friction caused by compressivehoop stress. Hydraulic pressure is again applied to tubing after closing thecirculating valve. Hydraulic hold down buttons expand to anchor the cylinderin a new, higher position.

5 - The expander assembly is again forced through the corrugated patch,expanding it against the inside of casing. This procedure is continued untilthe entire patch is set. The epoxy resin coating is extruded into any leaks orcavities in the casing wall and acts as a gasket and additional sealing agent.Setting time normally requires less than 30 mn for a 20 patch. The tool isthen removed from the hole and the patch is pressure tested as required.

Figure 2: Patch design and summarised setting procedure(from Weatherford document)

14

5

3





The patch was successfully set from 285.75 m to 273.75 m (40) in June 1998 to cover thedamaged section of 9 5/8 casing. The first 5 were set with 3200 psi, the rest with 3000 psi(theoretical capacity: 9850 psi internal, 894 psi external pressure).

The theoretical ID of the patch, once set, is 8.381, based on a circular 9 5/8, not taking intoaccount the 9 5/8 casing deformation, the thickness of epoxy and the surface defects of bothcasing and patch. The actual ID of the patch, once set, has not been measured.

The well was completed as a gas lift horizontal producer immediately after the patch operation.

4. OPTIONS TO SIDE TRACK AK-13-1 (January 1999)

In January 1999, AK-13-1 was to be abandoned and side-tracked to a new location. The new welldesign involved pulling out completion, abandoning the drain in AK-13-1, opening a window in the 95/8 casing (permanent whipstock), 8 drilling and 7 liner.

The results of the USIT corrosion log were further investigated. The deformation of the casing(strain hardening, marks, thickness reduction) was confirmed but the definitive ID of the patch

could not be deducted. The patch ID would be in the interval [8.25 8.38].Figure 3: Uncertainty on the ID of the patch, from USIT corrosion log (data can be used as

qualitative indications but not strictly quantitative).IR: internal radius (MX, MN, AV: minimum, maximum, average)ER: external radius (MX, MN, AV: minimum, maximum, average)

This uncertainty led to several options for the side-track of the well:

1. leave the patch in the well, drift it, down-size the drilling tools and liner equipment:- The drift would be known just before running the whipstock, which would lead to ultra short notice

before under-sizing the equipment.- The mills for the window milling in the 9 5/8 casing could easily be down-sized to the required ID

(the body of the whipstock is 8).- 8 3/8 drilling instead of 8 would be conventional (if compatible with the drift of the patch),

smaller size would lead in difficulties to find bits and problems of compatibility with the liner size.The use of bi-centre bits would be a back-up option.





- The smallest dimension of the liner hanger (Nodeco) can be reduced to 8.29. This minimum linerID would be acceptable or not depending on the actual drift of the patch.This option led to very heavy contingencies with several batches of equipment dimensions requiredfor the operation. It would even not be acceptable if the patch is drifted to an ID < 8.29.

2. Mill the patch: Milling operation was studied with Smith and Baker. It was felt risky and notsatisfactory as an additional patch would be required after the side track operation, until thenext re-entry.

3. Recover the top casing section (patch included) and reconnect new casing, retrieving fullcasing integrity and drift. This option was studied with Baker, Smith and Enterra. The top sectionof the 9 5/8 casing is not cemented, recovering the casing should therefore be possible. Using anhydraulic back-off machine provides great confidence in backing-off exactly where required. Smithalso proposes a casing alignment tool in order to re-connect the new casing without damaging theconnection left in hole after back-off. This option was chosen because confidence was gained inthe tools proposed for the operation and because it was the most comfortable for the future of thewell.

Remark: an external casing patch option (Bowen, rubber, 5K) had been looked as an alternative tothe new casing reconnection. When comparing the two options, reconnection of new casing looksfar more practical.

The operation could be planned in 2.5 days (first conservative estimate), which makes iteconomically attractive.

Option 3 was the best: recovering the top 9 5/8 casing (300 m), replacing with new casing.

5. CASING RECOVERY, CASING RECONNECTION

The operation was successfully carried out in January 1999. None of the anticipated problems occurso that it was a particularly smooth operation. The complete 9 5/8 integrity and full drift wererecovered.

5.1. PREPARATION

- (AK-13-1 is killed, the completion is removed, the well is abandoned with a cement plug acrossthe top 7" liner)

- Cut the casing below the patch with casing cutters, conventional operation,

- Check the depth of the casing left in hole with same cutters. The casing left in hole should not betagged between back-off and reconnection of new casing in order not to damage the connectionleft in hole (pin or box) after back-off.

- Pull the cut top casing with Casing Hanger Running Tool. The 9 5/8 is not cemented above 1050m. However, cement bridge could prevent from pulling the top 9 5/8 casing. In this case, the top 95/8 casing would be cut and pulled in slices.

- Back-off the cut joint with the hydraulic back-off machine. The machine is a torque tool, anchoredon two packer across the coupling to back-off. The machine has been chosen because it allows toback-off exactly at a given coupling. It can provide up to 48 klbf.ft torque per cycle [1/2 turn percycle]). The indication of back-off is based on torque for each cycle.

- Complete back-off and pull the backed-off joint with the casing spears.





- Check whether the connection left in hole is a pin or a coupling (note that statistically, most of theleft in hole connections after back-off are pins).

- Adapt the casing alignment tool to the situation. The casing alignment tool is based on the use ofa bushing to guide the new casing and re-connect without damaging the connection left in hole. 2bushings are available depending on the situation: Pin or Box left in hole.

- Reconnect and Torque up new casing from surface with the casing tongs,

- Land casing on emergency hanger.





Coupling

289.4 m

Coupling

301.7 m

Casing Patch

273 - 286 m

Casing cut

@ 291.5 m

BOX UP

left in holePIN UP

left inhole

Casing back-off @ 301.7 m

Casing Connection

with Casing Alignment tool

Casing

Alignment

Tool

Top Sub

Vam Pro Boxx

New Vam Pin

New Vam Boxx

New Vam Box

X-Over

New Vam Pinx

Vam Pro Box

X-Over

fitted inside tool

Vam Pro Coupling(if Pin Up left in hole)

Guide, according to Pin or Box left in hole

Figure 4: Recovering top 9 5/8, casing, connecting new 9 5/8 casing.

Smith was chosen for the operation for their Hydraulic Casing Back-off Tool, their casingalignment tool and the quick availability of their equipment. They actually provided a completepackage for the entire operation and were involved at the earliest stage of the decision process.





The preparation of the casing alignment tools (with 2 bushings to be able to cope with thesituation: Pin or Box left in hole) was slightly more complex due to the use of Vam Pro connection(Vam Pro connection cannot be cut locally, gauges are not available). The top Casing alignmenttool was cut in New Vam, a New Vam x Vam Pro X-over was made up on top. A Pin x Pin, NewVam x Vam Pro X-over was fitted inside the tool. Would a coupling be left in hole, the Vam ProPin down would be run (inside the proper bushing); would a Pin be left in hole, a Vam Pro couplingwould be made up to this X-over, the Vam Pro Box down would run (inside the proper bushing).

1:1 scaled schematics of the various possible situations before reconnection clearly indicated thatit would be impossible for the casing alignment tool to miss the left in hole connection. The re-connection should therefore be straight forward. Would a coupling be backed-off and fall in thehole while being pulled out, it would still be easy to re-connect new casing.

An external casing Patch (Bowen rubber type, 5000 psi) had been mobilized in the very unlikelypossibility of failure to reconnect the 9 5/8 new casing. However, would the first reconnection beimpossible, a second back-off (1 joint deeper) and a second reconnection would be attempted,then a third, .The probability to run the external casing patch was close to zero.

5.2. CUTTING AND PULLING CASING

The casing was cut @ 291.5 m,MD, 7 below coupling to leave a 30 cut joint in hole, as per Smithrecommendation (3.25 hours for the entire operation). The left in hole casing moved 20 cm down.The casing hanger + casing were straight pulled out (5.5 hr for the entire operation).

The recovered 9 5/8 casing and couplings were in excellent condition, looking new. It has beencut and analyzed in details.

5.3. BACK-OFF

The Hydraulic Casing Back-off Machine was run across the joint to be backed-off. 10 cycles (5000psi pressure up/ bleed-off), equivalent to 5 turns were applied to back-off the coupling.

6 h for the entire operation (M/U: 2 h, RIH: 2 h, M/U circulating head + test line + back-off: 1.5 h,Drop ball to restore circulation: 0.5, POOH: 1 h).

Casing spears were run in hole. 3 turns were applied to complete the back-off. The joint waspulled to surface.

A coupling was backed-off and pulled out (as per statistics). The connection was looking so new(with original grease) that it was decided not to attempt to clean it before re-connection.

5.4. RECONNECTION OF THE NEW CASING

New 9 5/8 casing was run with the Casing Alignment Tool fitted with a bushing designed to coverthe Pin left in hole and a Vam Pro coupling down a short X-over inside.

The casing was run in hole slowly, with rotation (casing tong: coordination between casingelevator and the air winch). No sign showed on surface when the guide covered the casing left inhole. 400 lbf slack-off indicated casing contact. The connection was made up to 12200 ft.lbf, inone go, working the string with +/- 50 klbf. It was then made up to 12700 ft.lbf with an additional turn, working the string with +/- 30 to 70 klbf. The casing would not turn more and the torquewould not increase from this final torque value.

12650 ft.lbf is the optimum make-up torque for 9 5/8, 47#, Vam Pro connection, it is assumedthat the torque @ 300 m vertical is similar to the surface torque.





The casing was positively tested to 3000 psi for a few minutes. 4.75 h for the entire operation.





5.5. LANDING CASING ON EMERGENCY HANGER (CAMERON MC2)

BOP were lifted, emergency slips set (with 125 klbf tension on casing) and casing cut. The top 95/8 was machined. Although this operation was straight forward, it is reported here as the firstuse of the 9 5/8 Cameron C22 emergency hanger

6. COSTS

There is a significant difference between the two types of operation. Nevertheless, the results areof course not the same. In one case, it is a temporary repair allowing to put the well on productionas quick as possible and giving a casing integrity which cannot be guaranteed at 100%,especially with H2s and C02 contents. In the second case, the well is fully repaired and comesback to its original status.

Internal Casing Patch:

Total cost for the Patch: Patch: 38600 US$Associated rig time: 11000 US$TOTAL: 49600 US$

Casing Back-off and reconnection:

Lump Sum for the Smith operation: 92000 US$Associated rig time: 11000 US$New 9 5/8: 19400 US$Associated rig time: 50416 US$TOTAL: 172816 US$

7. DETAILED ANALYSIS OF THE CASING AND PATCH AFTER RECOVERY

A. CONCLUSION

Five main points:-The Homco patch was necessary the 1st time (sulfide stress corrosion cracking) andconfirmed by the results of analysis identifying heavy metallurgical changes on the steel.-The Homco patch was not properly deployed and the life of the casing would have been mustprobably shorter than expected.-The change of the casing top part is the best solution if the equipment is available, despite ofa cost which is not negligible. It also allows the re-entry with the standard bit.-USIT in caliper mode is an accurate tool.-Damages on casing are due to the heavy jarring at shallow depth, causing pipe deformationsand the thickness reduction due to the milling (and washing over).

B. CASING PART RECOVERED

The casing was cut in the hole @ 291.5 m MD, 1.99 m below the (last) coupling. Oncearriving in surface, due to the internal Homco patch the N-1 connection was not able to beunscrewed. The casing was torched-cut above this connection. The last piece recovered wascomposed of a full casing joint 12.97m long (collar 0.21m) and a casing butt of 2.20m long(collar 0.21m).





C. CASING INSPECTION

(i) Visual inspectionThe visual inspection of the last casing part shows outside heavy damages,particularly in the middle of the pipe where big humps are located caused by steeldeformation. The torched-cut (picture1) end does not allow inspecting the sealingbetween the patch and the casing at this level (like welded), but it is possible todiscover that the patch was not fully applied inside the casing (picture2). A significantwave aspect proves that the setting tool did not deploy fully the patch (when run thepatch is compressed with large undulations).

Picture1 Picture2

Heavy damages on the pipe

(ii) GaugingA special gauge was manufactured to drift the casing in order to verify the expectedrestriction inside the patch due to the heavy casing deformation and its ovality. The8.29 drift gauge was stuck at 3.79m after the torch-cut end. The ovality was up to7% of the diameter.





(iii) Outside measurementsThe outside measurement was made with a caliper. Depending on deformations 4then 8 on reference generating lines (refer to drawing). Each section measured wasalso referenced to the top the casing.

OUTSIDE DIAMETERS

8.8

9

9.2

9.4

9.6

9.8

10

10.2

10.4

10.6

289.29

288.29

287.29

286.29

285.29

284.29

283.29

282.65

282.55

282.45

282.35

282.29

282.24

282.19

282.14

282.09

281.99

281.89

281.79

281.29

280.29

279.29

278.29

277.29

276.54

(iv) Thickness and inside diameterThe thickness of the pipe was measured at the same referenced points as per theoutside records. This led to calculate the internal diameter.

INTERNAL DIAMETER

8

8.5

9

9.5

10

10.5

11

289.

29

288.

29

287.

29

286.

29

285.

29

284.

29

283.

29

282.

65

282.

55

282.

45

282.

35

282.

29

282.

24

282.

19

282.

14

282.

09

281.

99

281.

89

281.

79

281.

29

280.

29

279.

29

278.

29

277.

29

276.

54





LENGTH 279.29M

200

250

1

2

3

4

5

6

7

8

LENGTH 280.29M

200

250

1

2

3

4

5

6

7

8

LENGTH 281.29M

200

250

1

2

3

4

5

6

7

8

LENGTH 281.79M

200

250

1

2

3

4

5

6

7

8

LENGTH 281.89M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 281.99M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.09M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.14M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.19M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.24M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.29M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.35M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.45M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH282.55M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

LENGTH 282.65M

200

250

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

Non-scaled schematic of pipe measurements (red= ID, blue=thickness)

D. COMPARISON WITH USIT CORROSION LOG

The results we found on surface after having measured the casing demonstrated that theanalysis and the interpretation of the USIT (run as caliper) was correct. The USIT showed aminimum thickness of less than 6.3 millimeters and we measured in reality 6.5 millimeters.All the deformations highlighted by the USIT were found and located at the right place.

E. PATCH INSPECTION AFTER CASING CUTS

The pipe with the internal patch was cut in10 sections to allow a visual internal inspection.It was noticed that the patch was never deployed fully as waves were systematically foundwhat ever the inspected section. A particular check was done at the beginning and at the end





of the patch, to ensure that the gluing was efficient. The waves phenomena was alsoidentified at those levels. We cannot ascertain that the gas would not have been able tomigrate between the casing patch and the pipe.

F. HARDNESS CONTROLS

The hardness tests were done in three different zones at the bump level, at the place wherethe thickness was minimum and above and below the damaged part.The standard Vickers hardness measurement for L80 steel is Hv=230.

We found:Hv< 170 at bump level which means very soft steelHv> 300 at thickness mini which means steel harder than normal. It is due to the matting.Hv =+/- 210 on the pipe which means a slight change (no given interpretation).

Documents

Casing Repair