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MANAGED PRESSURE DRILLING

An extreme HPHT

exploratory well reached TD

with optimal hole size, using

MPD methods to maintain an

overbalanced wellbore and

handle breathing events.

S.K. NaeSheim, Frode LeFdaL, n ToryviNd oFTedaL, BG NorGe; n heNriK

SveiNaLL, Wtf intntnl Lt.

The Mandarin East well exhibited themost extreme temperature and pressureever encountered while drilling a Norwe-gian well. Planning for this exploratory wellhad anticipated a surface pressure of nearly1,000 psi and extremely high tempera-tures. To understand and control wellboredynamics while maintaining an overbal-anced wellbore, operator BG Norge in-stalled a managed pressure drilling (MPD)system to provide early kick detection andallow for wellbore breathing mitigation.

A key objective of using MPD was toset the 97/8-in. production casing shoe asclose to the reservoir as possible, to allowthe optimal -in. section to be drilled toTD within a very narrow (0.4-ppg) drill-ing window. Well breathing events pre-sented a significant challenge in this dif-ficult wellbore environment, which madepore pressure evaluation and kick detec-

tion critical to drilling.Using the service companys auto-mated MPD system to mitigate drillinghazards allowed the entire -in. sectionto be drilled to ,933 m (19,46 ft) TD.The system saved an estimated 10 rig daysand $. million, while reducing risk andimproving safety. Controlling gas influxesand precisely weighting up the mud sys-tem saved five of those days when com-pared to a conventional system.

PLANNING THE WELL

Once the constant bottomhole pres-sure (CBHP) methodology was selected,

rigorous planning and preparation wereinitiated. Prior MPD operations in Nor-

way were drilled while maintaining a stati-cally underbalanced mud weight. Annularfriction and surface backpressure wereused to maintain bottomhole pressureabove the pore pressure. These existingprocedures could not be applied directlyto the Mandarin East well. Maintenanceof an overbalanced mud weight limited

the operational envelope to an extent,but the extreme HPHT environmentprompted a cautious approach.

A project team of operator and MPDpersonnel was established four monthsahead of the spud date. A rig survey de-termined that major rig modifications

were required, because the area betweenthe rigs annular preventer and divertercouldnt accommodate the rotating con-trol device (RCD). Thus, the riser had to

be nippled down in the yard, and a new,shorter, overshot mandrel and packerassembly were manufactured to providethe necessary space between the annularand diverter.

Most of the existing MPD procedureshad to be modified, because underbal-anced drilling (UBD) techniques couldnot be applied at any stage, and surface

backpressure would only be applied if aninflux was detected. It was necessary to in-clude the MPD procedures in the conven-tional HPHT procedures and establishguidelines for the use of MPD and con-

ventional rig equipment. Several work-shops and HPHT training sessions wereconduced for rig and MPD personnel.

A full suite of integrated proceduresand decision trees was prepared. It wasdecided that any kicks above 1 bbl would

be handled by the standard rig equip-ment, due to a risk of taking a second-ary kick, if a kick greater than 1 bbl wascirculated undetected to the surface, Fig.1. The training, risk assessments, work-shops and discussions with the crewsprior to spudding were a very important

factor in the success of applying MPDtechniques.

MPD RIG-UP

Two rig surveys were conducted todetermine where the MPD equipment

would be placed. Due to limitations onvariable deck load, space and overshotmandrel modifications, none of the MPDequipment could be rigged up before theintermediate 135/8-in. casing had been run

and cemented in place. Norwegian regu-lations also specified that electric cablingon the rig must be upgraded to NORSOKstandards. A total of 2 km (1 mi) of newcables had to be put in place before theequipment could be installed.

The MPD equipment package fea-tured an MPD manifold unit that includ-ed computer-controlled chokes, Coriolisflowmeters and an Intelligent ControlUnit. A passive, self-lubricating, large-

bore RCD (able to handle pipe up to 65/8-in. OD) was connected to the BOP annu-

lar. A removable bearing assembly for theRCD allowed for an 1.69-in. ID when

Record HPHT Norwegian well drilled with

MPD fow detection and controlFig. 1. conventionl well ontol o mPDetods? Tis deision tee desibeste pt to king tt ll o engineesdilling n extee hPhT well osoeNowy.

Drilling in securestandard (auto

control on)chokes fully open

Influx largerthan 1 bbl

Influx detected

- Stop drilling

- Space outdrill string- Close upper

pipe rams- Stop drilling- Reduce rotation

to 10 rpm- Keep circulating

Divert returns toMGS when influx

at 1,200 m

Evaluate if toincrease mud weight

to accommodateincreased pore

pressure

Further influxdetected

Combinedinflux > 1 bbl

Commence wellcontrol operation

Circulateout Influx

Resume drillingensure chokesare fully open

NoYes

NoYes

NoYes

Oiginlly ppeed inWorld Oil

march 2011 issue, pgs 77-80. Posted wit peission.

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MANAGED PRESSURE DRILLING

the bearing was removed. The RCD mod-el used is the first certified to API 16Dspecification. Its pressure rating is 2,000psi static and 00 psi at 200 rpm, Fig. 2.

The equipment package also includedvarious MPD sensors in the flowlines andmud pits. Hard, flexible piping was usedto connect the MPD equipment to theRCD, the rigs choke manifold, the triptank and the rigs poor-boy degasser. Atop flange tied the RCD back to the rigs

bell nipple. This equipment was rigged upprior to drilling out of the 135/8-in. casing.

About four days were lost, because of rigspace limitations that required installa-tion of MPD equipment after intermedi-ate casing was landed.

DRILLING THE SECTION

An extensive flushing, pressure test-ing and fingerprinting program was con-ducted prior to drilling out of the 135/8-in.casing. The MPD system was engaged forthe bottom 600 m (1,969 ft) of the 12-in. hole to acquaint crews with new pro-cedures and equipment in advance of thelower, more difficult section.

Before drilling out of the 97/8 x 10-in. production casing, the 1.-ppg

OBM used for drilling out the cement andfloats was fingerprinted again. At ,40 m(1,40 ft), a LOT to 19. ppg was ob-tained. Drilling continued toward the res-ervoir at about ,90 m (1,340 ft) with a1.-ppg mud weight circulating throughthe MPD system. Background gas (BG)

was moderate, with levels of about 1%.From approximately , m to ,60 m(1,22 to 1,241 ft), a gradual 1-to-%increase in BG levels was experienced.Two flow checks were negative. At ,62m (1,24 ft), a sudden 10% increase in

the gas level was observed. Drilling wasstopped, and the well was circulated with-

out any significant decrease in gas levels.Surface backpressure (SBP) was added

in 100-psi increments until the gas flowstopped. The flow and density param-

eters stabilized at 30 psi SBP, indicatinga pore pressure of 1.-1.6 ppg. To verifyan underbalanced state, the MPD choke

was opened briefly. The bottom-up gaswas about 33%, and underbalanced con-ditions were confirmed.

The bit was held stationary at ,62 m(1,24 ft), and the mud weight was in-creased from 1. ppg to 1.0 ppg in onecirculation cycle, to slowly reduce the SBPon the MPD system to an equivalent 1.6-ppg dynamic mud weight. To confirmthat formation integrity had not changedat the casing shoe (19. ppg), the MPDequipment was used to perform an openhole leak-off test. The 19.1-ppg test figureindicated that the pore-pressurefracturegradient window had been reduced toonly 0. ppg. Mud weight was ramped upto 1.2, 1.3, 1.4 and 1.6 ppg to care-fully maintain a bottom hole circulatingpressure less than 19.0 ppg, ensuring a 0.1ppg safety margin, Fig. 3.

Total rig time was only 40 hr from theinitial small gas influx at ,62 m (1,24

ft) through a sequence of steps that ac-curately determined the pore pressure(at 1.6 ppg) with full pressure control,

weighted up from 1. ppg to 1.6 ppg,and accurately determined the new forma-tion integrity. Handled conventionally, theprocess might have taken to 6 days. Keep-ing ECD below 19.0 ppg required that theflowrate be maintained below 200 gpm forthe remainder of the well. Small losses wereexperienced through the sandy intervals.

After the gas incident had been re-solved, confidence in the system increased.

It was decided to apply SBP on connection,to reduce wellbore breathing and time re-

quired to circulate the gas out of hole. Theavailable pressure window did not allowfor a trip margin when pulling the BHA for

bit changes and coring. Swabbing the wellwas avoided by stripping out pipe throughthe RCD with a backpressure equivalent to19.0 ppg from TD to approximately 1,400

m (4,93 ft) inside the production casing.A heavy, 20.0-ppg mud cap pill was placedat 4,000 m (13,123 ft) to give the neces-sary margin for the rest of the trip. Whiletripping back in, the pill had not strung outmuch in the wellbore, and it had to be cir-culated out in steps, very carefully, to avoidlosses. Although some losses were experi-enced, they decreased toward the bottomof the pill and completely stopped once thepill was out of the hole.

Extensive use of the MPD system andthe application of new techniques for

tripping enabled the -in. hole to reachTD at ,932 m (19,463 ft) in to 10 dayssooner than offset wells, where an inter-mediate liner was required. The -in.hole size benefited wireline logging, cor-ing, fishing operations and DST testing,compared to carrying out the same opera-tions in a 6-in. or 5/8-in. hole. The MPDstripping technique was much faster thanthe standard process. It saved an estimat-ed, minimum 12 hr on every trip.

The MPD operations were also usedin the well's P&A phase. Common experi-ence is that placing balanced cement plugsat almost 6,000 m (19,6 ft) is very dif-ficult; often no plug is found when runningin to tag. On the Mandarin East well, witha solid float in the cement string, the MPDsystem was used to hold roughly 0-psi

backpressure on the plugs when pullingout of the cement. This kept the plugs inplace, and, in fact, all the deep plugs weretagged on the first attempt. In addition,the 2,000-psi static pressure rating of theequipment allowed its use to pressure-test

the cement plugs after tagging.

COST SAVINGS

Using MPD led to significant opera-tional and economic advantages. In total,using the MPD system saved 1. days orabout $13.9 MM. Less the time for MPDrig-up and testing the net savings were 10days and about $. MM.

Four days, or about $3.0 MM, weresaved compared to a conventional set-up

when controlling gas influxes, determin-ing the pore pressure and enabling con-

trolled weighting up. About tens days($. MM) were saved by successfully

Fig. 2. Te mPDpkge, inluding oke niold,coiolis owete,intelligent ontol unitnd otting ontoldevie.

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MANAGED PRESSURE DRILLING

drilling the -in. hole to TD in the nar-row pore pressurefracture gradient mar-gin. The elimination of gas check trips

when pulling out for bit changes and cor-ing saved 2 days ($1. MM) The MPDsystem allowed stripping out with back-pressure to control swabbing. Other sav-ings include two days, because no dummyconnections were required, and a half-dayfrom conducting open hole LOTs andpressure tests of cement plugs.

Time savings were achieved by lockingin the ECD pressure during connections,

which totally eliminated long circula-tion periods. However, this is difficult toquantify and is not included in the timecalculation. A total of . days was spenton critical rig time for rigging up, flushing,

pressure testing, fingerprinting and carry-ing out a full-scale drill.

OPERATIONAL ADVANTAGES

Using MPD and sophisticated flowdetection equipment allowed the well to

be safely drilled to TD in an in. holewith a 0.4-ppg pressure window. Doing soadded significant value to the formationevaluation program, and in case of a DST.

The MPD system accurately de-termined the pore pressure in the well

without the need for any wireline tools,

including a sudden rise in pore pressurefrom 1. to 1.6 ppg. Locking in the

ECD pressure during connections in acontrolled, safe way eliminated all extracirculation time resulting from gas from

wellbore breathing during connections.MPD procedures can be tailored for

the application and can be used to savetime and cost, even when UBD is notrequired. Using MPD-controlled strip-ping techniques can eliminate the needfor the conventional pump out to theshoe check trip. The MPD flowlines onthis extreme HPHT well raised crew con-fidence, because gas was not escaping atthe bell nipple on every bottoms-up.

An advanced MPD flow detection de-vice successfully detected an influxlossof less than bbl. The faith gained in theMPD flow detection equipment eliminat-

ed the need for dummy connections nor-mally used when drilling HPHT wells.Lessons learned included the impor-

tance of a line large enough to avoid ex-cessive backpressure, when large gas vol-umes are circulated through the rigs poor

boy system. Experience also illustratedthat it is essential to minimize off-centerdrill pipe versus the rotary table. Mis-alignment of more than 2 in. could leadto time-consuming problems to install anRCD sleeve or bearing. So that the ECDpressure can be accurately locked in dur-

ing connections the system should usea 2-in., ,000-psi line from the rig stand

pipe to the MPD choke manifold.The MPD flowlines should also be

tied in with the rigs trip tank system. Thisallows circulation across the wellhead us-ing the trip tank system with the RCDelement installed. A 2-in. NRV should beinstalled in the line.

CONCLUSION

The change to a closed-loop, MPD sys-tem provided the data and control to drill

within a very narrow window in this ex-treme wellbore and still maintain an over-

balanced mud weight throughout the op-eration. Understanding pore pressure and

well dynamics provided information for anautomated control system using annular

backpressure to effectively manage smallinfluxes and losses. This capability allowedthe well to reach TD with the optimal hole

diameter.

SIGVE KROHN NAESHEIM is

wells pojet nge o teKn Developent wit BG

Goup in Nowy. he s oe

tn 30 yes o expeiene, in

vious positions onsoe nd

osoe, wit bot dillingonttos nd jo opetos. his expeiene

oves Euope, te U.S., Sout aei, te

middle Est nd Soutest asi. he olds n mS

degee in petoleu engineeing oUnivesity o Stvnge.

FRODE LEFDAL is well

engineeing nge o BGGoup in Nowy. he olds nmS degee in petoleu

engineeing o Nowegin

Univesity o Siene nd

Tenology. he s 15 yeso industy expeiene wit jo opetos,

woking in Euope nd Sout aei. he

is BGs Subjet mtte Expet o nged

pessue dilling.

TOR YVIND OFTEDAL is ie

well engineeing nge o

BG. he is petoleu enginee

o roglnd Univesity nds 32 yes o expeiene wit

te ollowing opnies:

Pillips Petoleu, SgPetoleu, Nosk hydo, conooPillips ndBG. he s eld engineeing positions in:

plto/pipeline inspetions, dilling nd

wokoves, well intevention nd plto

opetions in Nowy, Denk nd UK. he s

been nge/supeviso sine 1986.

HENRIK SVEINALL is te

Podut nd Sevie Line

nge o Weteods

Seue Dilling Sevies inNowy. he stted is ee

wit Weteod s UBD

tinee enginee, nd s

woked s n enginee nd pojet nge onUBD nd mPD pplitions in Not aei,

ontinentl Euope nd osoe in te Not

Se. he olds n mS degee in petoleu

engineeing o Univesity o Stvnge.

Fig. 3. Sue bkpessue (SBP) (wite line) ws inesed until tue pessuews edued, oped to te oiginl test. One te SBP eed 500 psi, te ed linediveged o te blue line. Te blue l ine sows tt uid ws injeted into te otionnd tt te lek o pessue ws identifed. One SBP is eoved, te well etuns to nol stte wit no losses o gins.

Article copyright 2012 by Gulf Publishing Company. All rights reserved. Printed in U.S.A.

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