IADC/SPE

IADC/SPE 14777

Liner Cementing Techniques and Case Histories Offshore Western Gulf of Mexico by R.N. Hebert, Tenneco Oil Co. E&P

SPE Member

Copyright 1986, IADCISPE 1986 Drilling Conference

This paper was prepared for presentation at the 1986 IADCISPE Drilling Conference held in Dallas, TX, February 10-12, 1986.

This paper was selected for presentation by an IADCISPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or International Association of Drilling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any posItIOn of the IADC or SPE, .'tS of­ficers, or members. Papers presented at IADCISPE meetings are subject to publication by EditOrial Committees of the IADC and SPE. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL.

ABSTRACT

Liner cementing success in Tenneco Oil Company's Western Gulf of Mexico Division increased from 44% between 1979-1982 to near 80% for the period of 1983-1985. The improvement in cementi ng success can be partially attributed to implementation of a planned 1 i ner top squeeze after the bottom of the 1 i ner has been cemented conventionally. This is accomplished by runni ng a retri evab 1 e squeeze packer above the 1 i ner run-in tool. This method of liner cementing was pioneered and had been used successfully for over ten years by Superior Oil Company. It was studied and adapted by Tenneco with the emphasis placed on improv­ing liner cementing success through the designation of a liner cementing specialist. Twenty-three liners have been run using this technique. Case histories with successes and failures wi 11 be revi ewed in thi s paper.

INTRODUCTION

maximize efficiency. The responsibilities of this position were to monitor design and testing of cement i ng s 1 urri es, wi tness make-up and testi ng of 1 i ner hanger assemb 1 i es, and to supervi se the running and cementing of the 1 iner setting at the well site.

Thi s paper wi 11 not di scuss in depth each of the above problems and methods. These topi cs have been previously addressed in other articles and papers. Instead, a basic philosophy will be pre­sented in this paper explaining why the planned 1 i ner top squeeze method was chosen. The resu 1 ts wi 11 be analyzed exp 1 a in i ng what was 1 earned from the failures that occurred.

Often when cementing ali ner sett i ng you are trying to accomplish three objectives:

1) Obtain a good shoe test in order to drill ahead. Why do 1 i ner cement jobs fail? There are many

and varying reasons. Some pf the major causes of 2) liner cementing failures are: 3)

Cover any pay behind pipe with cement. Effect a hydraulic seal in the liner overlap.

1) Close tolerances between pipe and hole sizes -inability to use centralizers.

2) Inability to move pipe while cementing. 3) Restricted circulation rates - lost circulation. 4) Insufficient cement volumes. 5) Cement contamination. 6) Over retardation of cement - gas migration

through cement.

To improve 1 iner cementing success, various operators use different methods. The most popular are rotating liner hangers, liner top packers, and planned 1 i ner top squeezes. At Tenneco, ali ner cementi ng specialist was designated to study, develop and implement 1 iner cementing techniques that would

References and Illustrations at end of paper.

In most cases with tight clearance liners, it is too much to ask for the same cement slurry to do all three jobs at once. The slurry is usually designed for high temperature bottom hole conditions. The hole in most cases has just been drilled through a trans it i on zone wi th temperature on bottom severa 1 degrees hotter than the previ ous cas i ng shoe. By the time the cement is circulated down through the drill pipe and casing and up the annulus, what cement does get into the overlap may well be contam­inated enough to never set. The additives that give the cement the propert i es that are des i red for the bottom of the 1 i ner wi 11 usually work against you when the cement gets into the over 1 ap. The usual response to this problem is to pump more cement, but how much cement is enough? If enough cement is pumped to leave 500 to 1000 feet of cement above the liner top, a real well control problem could develoD

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2 LINER CEMENTING TECHNIQUES AND CASE HISTORIES OFFSHORE WESTERN GULF OF MEXICO SPE 14777

when the cement starts to set and a microannulus forms on the high side of the hole. If the well starts flowing after a liner cement job, several days may be spent attempt i ng to get out of the ho 1 e in order to trip back in with a squeeze packer. Often after this gas migration occurs, a pump-in r!te cannot be estab-1 ished to re-cement the overlap. The only alterna­tive is to run a liner packer which will require several more days.

Superior Oi 1 Company pioneered a method of cement i ng 1 i ners in wh i ch the 1 i ner top is squeezed i mmed i ate 1 y after the bottom of the 1 i ner has been cemented conventionally. Tenneco has used this method on 23 of 25 liner jobs since late 1983. The tool that makes this method possible is a squeeze packer with a left hand jay which sets by left hand rotation. This allows the 1 i ner to be set and released by regul ar right hand rotation without engaging the packer. When using this method, it is not advisable to pump cement into the dri 11 pipe annu 1 us around the packer. The preferred procedure is to circulate cement until the ca 1 cu 1 ated top of the cement is above any potentia 1 pay zone and then close the annu 1 ar preventer. Th is will force cement into the formation at a weaker zone wh i ch theoret i ca 11 y wi 11 be near the previ ous cas i ng shoe as depicted in figure 2. The tool is then pulled 5 stands (+450 feet) above the liner top and the over 1 ap area is cemented (fi gure 3). If the zone that originally broke down on the bottom job is close to the previous casing shoe, the cement from the top job should go into the same place and the two cement columns wi 11 be joined. This has been verified by cement bond logs on 1 i ners typi ca 11 y 1 ess than 1000 feet in length.

When dea 1 i ng wi th longer 1 i ners, 2000 feet in length or longer, it will be more difficult to connect the cement columns. The reasoning is that as you dr ill deeper, the formati on pore pressures and frac­ture gradients move closer together. Fi gure 1 ill us­trates an example of a South Texas pore pressure plot. At 11,000 feet the pore pressure is 12.5 lb./gal. equivalent (ppg) and the calculated fracture pressure is 17.8 ppg. At 16,000 feet the pore pressure and fracture gradients are less than 1 ppg apart. If a 1 i ner is run over the i nterva 1 in fi gure 1 between 13,000 and 15,000 feet, the difference between the calculated fracture pressures at the 9-5/8" liner shoe and the 7-5/8" liner shoe is roughly 0.3 ppg. When performing the bottom cement job, the point where the formation will break down could be much lower than the 9-5/8" cas i ng shoe. However, exper i ence has shown that the format i on does not break down on bottom. Shoe tests results have been 100% successful when the liners are run to bottom.

Taking the above information into consideration, it is very important to c i rcu 1 ate cement above pay sands before closing the blowout preventer and pumping into the formation. A detailed procedure, along with a list of special equipment, is provided at the end of this paper.

RESULTS

Results of the 23 1 i ners run in thi s survey are summarized in Table 1. The sizes of casing run ranged from 5-1/2" to 9-5/8". The length of the liners ranged from 900 to 3600 feet. Of the 23 1 i ners run, 14 were run in directional wells. Only the 7" X 9-5/8" 1 i ners were run wi th central i zers. All 1 i ner

hangers but one were mechani ca 1 ri ght hand set and release.

Six failures occurred while employing this method of liner cementing. Only 2 of 17 liners that were drilled out failed to obtain a good shoe test. One of these failures, the first liner cemented using this method, was 900' of 7-5/8" drilling liner run in 500' of open hole. Calculated open hole volume was less than 7 barrels. Roughly 15 barrels of cement was pumped for the bottom job which subsequent 1 y suffered a shoe test fa i 1 ure. I twas obviously not a sufficient amount of cement to avoid contamination with drilling mud. After this failure no 1 ess than 40 to 50 barre 1 s of cement has been pumped on a bottom job. The on 1 yother shoe test failure was on a 9-5/8" liner that was set 20 feet off bottom purpose 1 y to evaluate a potentia 1 pay sand.

There were 3 failures of top squeeze jobs, 2 on 9-5/8" 1 i ners and a 7-5/8" dri 11 i ng 1 i ner. Two of these fail ures were cement re 1 ated. The other was attributed to lack of centralization in the overlap.

The sixth failure caused block squeeze work to be performed on a 7-5/8" drilling liner. When the liner was cemented, an insufficient amount of cement was circulated around the float shoe before the annular preventer was closed. A potential pay zone was 1 eft uncovered and had to be block squeezed before drill stem testing began.

An examp 1 e of the versatil i ty of th is method was seen when a 7" production 1 i ner was run and total returns were lost when circulation was at­tempted. Seawater had to be pumped into the annulus to attain a stabilized fluid level in the well. The cement job was pumped with no returns throughout the job. After the liner wiper plug bumped, the running too 1 was pu 11 ed out of the 1 i ner top and the sea­water ci rcu 1 ated out of the we 11 . The top cement job was then performed and tested without any other problems. Both the overlap and shoe were tested and the we 11 dri 11 ed to tota 1 depth without addi tiona 1 squeeze work. Because of the lost circulation that occurred during the primary cement job, the pay sands in the 7" liner were later isolated by block squeezing.

434

On the 46 separate cement jobs performed on the 23 liners in this report, the only equipment failure that occurred was one squeeze too 1 that wou 1 d not set after the bottom job was performed. The too 1 was tr i pped for a con venti ona 1 ri ght-hand set squeeze tool and the top job completed without inci­dence. No fishing jobs precipitated from any of the liner jobs.

RECOftfo1ENDATIONS

The following paragraphs deal with specific types of equipment and cement blends used during the period in which these liners were run.

Liner equi pment used on 22 of 23 1 i ners con­sisted of a mechanical set liner hanger with a ri ght-hand set and release mechan ism. The 1 i ner hangers had honed ins ide diameters and doub 1 ed as polished bore receptacles for the retrievable pack-off bushi ngs. A 10 foot long tieback sleeve with right hand release setting collar was run with

SPE 14777 R. N. HEBERT

the liner hanger. This assembly comprised a simple, easy to set and re 1 ease system. I t was chosen over hydraulic liner hangers for the following reasons:

1. Mechani ca 1 1 i ner hangers set and release without having to drop balls and pressure up on the hanger. Also, shearing pins in ball catcher subs sometimes results in lost circulation due to the sudden release of pressure.

2.

3.

4.

Entire liner can be rotated to the right without fear of releasing until hanger is set.

High circulating pressures will not prematurely set hanger. If hanger sets while tripping in hole, straight pick up places it back in run-in position.

Because of inherent des i gn characteri st i cs, mechanical hangers hav! a higher burst rating than hydraulic hangers.

5. Entire hanger assemb 1 y can be pressure tested before being sent to job.

When mechani ca 1 1 i ner hangers were 1 eft hand set and right hand release they were not run in directional holes for fear that the drill string would be backed off while attempting to work left hand torque down to the liner hanger. Now most liner equipment companies have setting tools that will allow right hand torque to be delivered to the setting mechanism without releasing the liner. On occasion, a liner is run to bottom in a directional hole and becomes stuck. When this happens, it makes no differ­ence whether the 1 i ner hanger is set or not because the liner is stuck tight in the hole and can't be moved up or down. The weight of a stuck liner becomes supported by the low side of the hole. The 1 iner sett i ng too 1 is then re 1 eased and the 1 i ner cemented as planned.

Several types of cementing methods have been used duri ng thi s study that are des i gned to prevent gas migration after cementing. These methods include use of gas-generating cement slurries, low fluid loss cements, and decreasing the transition time at which the cement reaches suffi ci ent ge 1 strength to res i st annular gas migration. The best method known to decrease transition time is using thixotropic cement.

Thi xotropi c cement has been used on 90% of the

2) Liner overlap (top job) - (recommended length -400 feet, minimum - 200 feet) - no less than 50 bbls. of cement for 5-1/2" and smaller liners, 70-80 bbls. for 7" to 7-5/8" liners and 80-90 bbls.for 9-5/8" liners.

It is very important to use a sufficient volume of cement to prevent slurry contamination with mud. Using excess cement is less expensive than perform­ing remedial cement work on liner shoes and tops.

It is also highly recommended when cementing a liner top to leave a 1000 psi underbalance of water in the drill pipe at the end of the cement displace­ment. This prevents fluid migration through the cement by keeping it in a static condition until it sets. Recommended waiting on cement time is 8 hours for liner top cement jobs.

CONCLUSION

As wi th any other aspect of our industry, the better the planning the more successful the project. The same th i ng can be said about 1 i ner cementi ng. Reliability of liner equipment, float equipment, centralizers, cementing equipment, and the personnel that make the equi pment work all play key ro 1 es in the success or failure of a particular job. Operators have invested a 1 arge amount of time and effort over the last three years to improve primary cementing success. Job planning and analysis is given much higher priority than in the "Boom" era. Tenneco assigned a "specialist" to oversee liner cementing. This has provided for better planning, execution and consistency. But even the most thoroughly planned and executed job still falls prey to the unexpected occurrence such as stuck pi pe or lost circulation as can occur on a directional hole wi th a ti ght clearance. When th is happens and the 1 i ner is on bottom its too 1 ate to change the game plan, all that can be done is to muddle through the process and hope for decent results.

Before the planned liner top squeeze method was employed, other liner cementing methods such as rotating liner hangers were considered. Studies have shown that rotating liner hanger jobs are most successful in straight holes and not nearly as successSul in directional wells with tight clearance 1 i ners.. Therefore, the two step cement i ng ap­proach was chosen for the following advantages:

top cement jobs in this study and has now been incor- 1) po rated into the program on bottom jobs also. I n a recently published study, Conoco's Corpus Christi division has used thixotropic cement to conventionally 2) cement 15 liners and obsfrved no gas migration through any of the cement jobs. Cement evaluation logs also 3)

Allows use of two spec i a 1 cement blends; one designed for the open hole section and one designed to cement the overlap. Prevents gas mi grat i on by ho 1 ding pressure on cement column as cement sets. Allows repeat squeeze of overlap without having to trip packer. showed improved bondi ng in the 1 i ners where th i xo-

tropic cement was used. 4)

Recommended vo 1 urnes of cement to pump on 1 i ner 5) jobs are:

1) Open hole section (bottom job) - no less than 50

Ability to continue with cement job as planned even if total circulation is lost. Allows overlap to be cemented with freshly mixed cement without having to circulate large amounts of cement into the drill pipe annulus.

bb 1 s. of cement and at 1 east 200% of the theo- The purpose of th is paper was to share i nforma­retical open hole volume. If a good caliper log tion and ideas with the industry. Other operators is availiible, use 25% in excess of calipered and turn-key drilling contractors have been using volume. this method of liner cementing for years to save

435

time and money. Although this method has improved liner cementing success, it has not been 100% successful. Tenneco will continue to look at this

3

4 LINER CEMENTING TECHNIQUES AND CASE HISTORIES OFFSHORE WESTERN GULF OF MEXICO SPE 14777

and other methods of 1 i ner cementing that wi 11 reduce cementing problems and costs.

SPECIAL EQUIPMENT

Extra equipment needed for this method are lis~ed below and illustrated in Figures 2 and 3:

1) Bumper jars - 6-3/S" 0.0. X 3-1/S" I .0. with drill pipe connections that make up directly into 1 iner setting tool without cross-overs, usually 4-1/2" IF. Jars with 4-3/4" 0.0. X 2" 1.D. are run with 5-1/2" or smaller liner running tools. Bumper jars will have 16-1S" of free travel. This free travel wi 11 give positive indication that the liner is set and when the liner is released.

2) Oil jars - 6-3/4" 0.0. X 2-1/2" 1.0. with 5-1/2" regu 1 ar connecti ons needs to be crossed over to dri 11 pi pe connecti ons. Oi 1 jars are run above squeeze packer for safety.

3) Squeeze packer - has dri 11 pi pe connecti ons and left hand jay setting cage with integral bypass.

Oi 1 and bumper jars can be provi ded by 1 i ner hanger company and run by thei r servi ce supervi sor. Squeeze packer run by squeeze tool company supervisor.

PROCEDURE

Picking Up and Running Liner:

1. Pullout of hole from wiper trip. 2. Pick up double of drill pipe. 3. Make up oil jars to bottom of double. 4. Make up left hand set squeeze packer to jars. 5. Make up bumper jars to squeeze packer and torque

to specs. 6. Stand entire assemb 1 yin derri ck. Rig up to run

casing. 7. For drilling liners: Pick up float shoe, 2

joints of casing, float collar, 4 joints of casing, and landing collar. Thread lock all connections from the float shoe to the top of the landing collar. For production liners: Amount of rat hole below producing interval may limit the number of joints run between shoe and landing collar. Run a~ many as possible leaving at least 150-200 feet between the 1 and i ng co 11 a r and the bottom of the pay sand. Note: Casing rams are not required. If the well should start flowing while the pipe is being run, the safety bushing assembly can be made up to the cas i ng wi th a ba 11 type safety valve to secure the ins i de of the cas i ng. If necessary, cas i ng can be lowered into the hole on drill pipe and pipe rams closed to secure the well.

S. Pick up remainder of liner, filling every joint with mud while running. Stop every 10 joints and insure liner is full. After last joint has been picked up, change to drill pipe elevators.

9. Pi ck up 1 i ner hanger assemb 1 y and make up to casing string. Check travel on hanger slips for freedom of movement (mechani ca 1 set hangers only). Change out casing spider for dri 11 pipe slips.

436

10. Latch stand with jars and squeeze packer and makeup to 1 iner hanger running tool. The oi 1 jars are in the cocked position and must be bled off before the weight of the liner can be pi cked up and lowered in the hole. Thi s wi 11 take rough 1 y 15 mi nutes. The cas i ng crew can be rigging down and the rig floor cleaned during this time. Install drill pipe wiper rubber when tripping drill pipe into the hole.

11. Filling the drill pipe during the trip in the ho 1 e can be accomp 1 i shed by us i ng the cas i ng fi 11 up 1 i ne. Some mud can be put in the pi pe on every stand. In any case, you shou 1 d not run more than 15 stands before stopping to fill drill pipe completely. This method will trap less air in the drill pipe than picking up the kelly and may be less time consuming.

12. Running speed will depend on the length of liner and clearance between the casing strings. Surge pressures should be calculated so as not to exceed the previous casing shoe test. If in doubt as to accuracy of surge pressure calcula­t ions, use a runn i ng speed of between 40-60 ft/min or 1-1/2 to 2 minutes per stand. (Note: This is the time it takes the driller to lower the stand into the hole after the connecti on has been made.)

13. When 1 i ner shoe reaches previ ous cas i ng shoe, rig up plug dropping manifold on a single of drill pipe and place in V-door for use as landing joint. Fill drill pipe with mud and continue in hole with liner.

14. Calculate spaceout so that casing will tag bottom with landing joint. Attempt to break circulation while working pipe. If circulation cannot be estab 1 i shed or if pi pe is tryi ng to stick, leave casing as close to bottom as possible and set hanger.

15. If good circulation is established and pipe moves freely, circulate and work the pipe in 20' strokes. Monitor returns and pit volume while increasing circulating rate 1 or 2 pump strokes at a time until desired circulating rate is reached. Cauti on shou 1 d be taken not to exceed an equivalent circulating density that will cause a loss of mud to formation at the previ ous cas i ng shoe. Mud shou 1 d be circulated until all trip gas is out of the wellbore, mud weight in is equal to mud weight out, and viscosity out is within a few points of viscosity in.

16. Shut pump off and set 1 i ner hanger. Loss of liner weight will be noted on weight indicator, then 2' of travel from oi 1 and bumper jars before drill pipe weight is set on hanger. Release setting tool from liner hanger and pick up 2-3' after seeing jar travel to insure that liner is released. Slack off drill pipe weight on liner hanger and re-establish circulation.

Cementing the Liner: 17. Line up cementing unit to upper choke line and

ci rcu 1 ate mud through choke 1 i ne into annu 1 us to insure lines are open. Close blow-out preventer and pump into annulus until formation starts taking mud at 2 barrels per minute. Note the pressure on choke manifold at which formation breaks down. Theoretically, the mud should be going into the weaker formations close to the previous casing shoe.

IS. Pump cement spacer from mi xing tank with ri g pump. Hook up cementing lines and test to 5000 psi.

~S~PE~1~47~7~7 ____________________________ ~R~.~N~.rH~EB~E~RTL-________________________________ ~5

19. Mi x and pump cement for bottom job and re 1 ease drill pipe dart. Follow dart with enough water to give a 300 psi differential in hydrostatic pressure into the 1 i ner (usua 11 y 25-35 bb 1 s. ) . The purpose of the differential is to insure that the floats will close and to keep heavy mud from swapping places with the cement in the shoe joints or contaminating the cement at the liner shoe. Follow water with mud.

20. Displace dart to wiper plug with cement unit and shear out wiper plug. Displace cement at a rate at least equal to previous circulating rate. Slow pumps to 2 barrels per minute, 6 barrels before the dart 1 ands in the wi per plug. When dart latches, shear out same with 1500-2000 psi, but don I t be alarmed if it takes 4000 ps i to shear plug. When plug re 1 eases start from zero on barrel count and displace the calculated volume of the liner from the wiper plug to landing collar. At the point where the leading edge of the cement is above the pay sands, slow pump down to 2-3 bbls/min and close blowout preventer. When previ ous i nj ect i on pressure is estab 1 i shed, speed pumps up to normal di sp 1 ace­ment rates. The cement shou 1 d cont i nue up the hole and go into the weaker formations near the previous casing shoe. If not, enough cement will have been circulated to cover the pay sands.

21. Fi n ish di sp 1 acement and bump plug with .22 ps i /ft. TVD and hold pressure for 5 mi nutes to insure that plug is holding. Release pressure and check floats for back flow.

22. Bleed off any pressure on casing annulus through choke and open blowout preventer. Since mud and cement were pumped away into the formation, mud may flow back from the well for several minutes but wi 11 eventua 11 y stop. Th is does not mean that a kick situation exists. Careful observa­ti on wi 11 acknow1 edge that the returns from the well will diminish and finally stop.

23. Break out 1 and i ng j oi nt with plug droppi ng head and place in mouse hole. Reverse out 1-1/2 times the drill pipe volume. Pull five stands of drill pipe. If plug bumped on bottom job, go directly to squeeze job. If plug did not bump, wait on cement 4-6 hours before squeezing liner top.

24. Install drill pipe wiper ball in plug dropping head and make up 1 and i ng joi nt to stri ng. Set squeeze packer and test. Rig up squeeze manifold and test lines to 5000 psi. Establish injection rate.

25. Mi x and pump squeeze cement and kick out dri 11 pipe wiper ball. Displace cement to within 15 barrels of squeeze tool, close tool and put 1000 psi on casing annulus, finish displacing cement unt i 1 top of cement is 200 feet above 1 i ner top. An increase in pump pressure (about 200 psi) will be observed when the dri 11 pi pe wi per is di s­placed through the end of the stinger be low the squeeze tool. Leave +1000 psi differential underba1ance of water in drill pipe at end of displacement (usually 30-40 bbls.). Shut in for 8 hours and wait on cement. Dri 11 pi pe pressure should rise above initial 1000 psi shut in pressure during 8 hours waiting on cement.

26. Reverse water out of drill pipe. Test squeeze job to 1000 psi above final injection pressure. If cement job does not test, pu 11 two stands of drill pipe and perform another cement job similar to fi rst job but d i sp 1 ace cement to 300 I above the liner top.

27. Pullout of hole. and test. Dri 11 shoe.

ACKNOWLEDGEMENTS

Dri 11 cement to 1 i ner top out cement plugs and test

This paper is dedicated to the memory of Dennis Hebert, former employee of Brown Oil Tools Inc., who spent 27 years of his life serving the oil industry in the liner business. He is sadly missed by family, friends, and colleagues.

The author wi shes to extend speci a 1 thanks to Jerry Anderson of Mobil Oi 1 Company for his advi ce and he 1 p when thi s method of 1 i ner cement i ng was undertaken by the Western Gulf Division of Tenneco.

METRIC CONVERSIONS

1 inch (in.) = 2.54 E-02 meter (m) 1 foot (ft.) = 3.048 E-01 m 1 ft./min 2 = 5.080 E-03 m/s 1 1b./in. (psi) = 6.894 757 E+03 pascal (Pa) 1 1bfgal. jppg) = 1.198 264 E+02 kilogram per meter (kg/m) 3 1 barrel (bbl.) = 1.589 873 E-01 m

REFERENCES

1Lindsey, H.E. and Bateman, S.J., "Improve Cementing of Drilling Liners in Deep Wells", World Oil, October 1983.

2Agnew, J.W. and Klein, R.S., "The Leaking Liner Top", SPE 12614, SPE Deep Dri 11 i ng and Produc­tion Symposium, Amarillo, Texas, April 1984.

3Lindsey, H.E., "Liner Cementing Equipment and Techniques", 24th Annual Meeting of the South­western Petroleum Short Course, Texas Tech University, Lubbock, Texas, April 1977.

4Steh1e, D.E., Sabins, F., Gibson, J., Theis, K., Venoitto, J.J., "Conoco Stops Annular Gas Flow with Special Cement", Petroleum Engineer, April 1985.

5Lindsey, H.E. and Durham, K.S., "Field Results of Liner Rotation During Cementing", SPE 13047, 59th Annual Technical Conference and Exhibi­tion, Houston, Texas, September 1984.

437

SPE

TABLE 1 - SUI't1ARY OF LINER JOBS

LINER SIZE LENGTH DEVIATION DRLG. OR TOP SHOE BOND LOG AREA (IN.) ...ill.,l (DEGREES) PROD. LNR TEST TEST RESULTS REMARKS

MUSTANG ISLAND 9-5/8 X 11-7/8 2500 20 Drl g. Yes Yes N/A

HIGH ISLAND 9-5/8 X 11-7/8 2000 25 Drlg. Yes No N/A Lost circ. at 9-5/8" shoe.

MUSTANG ISLAND 9-5/8 X 11-7/8 2400 20 Drlg. No Yes N/A Re-squeeze I iner top.

WEST CAMERON 9-5/8 X 11-7/8 1100 16 Drlg. Yes Yes N/A

MUSTANG ISLAND 9-5/8 X 11-7/8 2400 SH Drl g. Ves Ves N/A

HIGH ISLAND 9-5/8 X 11-7/8 2200 SH Drlg. Yes Yes N/A

MUSTANG ISLAND 9-5/8 X 11-7/8 3000 40 Drlg. No Yes N/A Re-squeeze liner top.

MUSTANG ISLAND 7-5/8 X 9-5/8 3500 25 Drlg. Yes Yes N/A

MUSTANG ISLAND 7-5/8 X 9-5/8 2500 20 Drlg. Yes Yes N/A

HIGH ISLAND 7-3/4 X 9-5/8 1000 25 Drlg. Yes Yes N/A

MUSTANG ISLAND 7-5/8 X 9-5/8 3100 30 Drlg. No Yes N/A Cement failure.

WEST CAMERON 7-5/8 X 9-5/8 2800 16 Prod. Ves N/A Good

MUSTANG ISLAND 7-5/8 X 9-5/8 3000 SH Drlg. Yes Yes No Block squeeze I iner for DST.

HIGH ISLAND 7-5/8 X 9-5/8 1300 SH Drlg. Ves Yes N/A

MUSTANG ISLAND 7-5/8 X 9-5/8 3400 SH Orlg. Ves Yes N/A

WEST CAMERON 7-5/8 X 9-5/8 900 SH Both Ves Yes Good

SABINE PASS 7-5/8 X 9-5/8 900 SH Drlg. Yes No N/A I nsuf. vo I. pumped.

MUSTANG ISLAND 7" X 9-5/8 3600 25 Prod. Ves N/A N/R Waiting on completion.

MUSTANG ISLAND 7" X 9-5/8 2000 40 Both Yes Ves No Lost circulation.

HIGH ISLAND 7" X 9-5/8 1500 50 Prod. Ves N/A N/R Waiting on completion.

MUSTANG ISLAND 5-1/2 X 7-5/8 2200 SH Prod. Ves N/A Good

HIGH ISLAND 5-1/2 X 7-5/8 1900 SH Prod. Ves N/A N/R Waiting on comp let i on .

MUSTANG ISLAND 5-1/2 X 7-5/8 2100 25 Prod. Ves N/A N/R Waiting on completion.

SPE 14 7Z 7

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Fig. 1-Typical offshore Texas pore-pressure plot.

___ DRILL PIPE

LEFT HAND SET SQUEEZE PACKER

LINER SETTING TOOL

I TIE-BACK SLEEVE

:!: 400' OVERLAP

j COMBINATION LINER HANGER & PBR

PREVIOUS CASING SHOE

ZONE

Fig. 2-Liner equipment configuration while cementing bottom of liner.

T :!:450'

~

•• > ,

'A,·' .',' '<.- --A:

. " ~ '. , :

, .

___ LEFT HAND SET SQUEEZE PACKER

T --- TOP OF CEMENT (TOP JOB)

:!: 200'

~ ___ TOP OF LINER

Fig. 3-Liner equipment configuration while cementing overlap.