Parque Das Conchas - Special Edition

PARQUE DASCONCHASA Supplement to E&P Magazine

An Ultra-Deepwater Success

Shell Cover-FINAL04_30_10_Layout 1 5/26/10 1:26 PM Page cvr1


Parque das ConChas n June 2010 1

The successful execution of the Parquedas Conchas (BC-10) project by Shellin the ultra-deep water offshore Brazildemonstrates that a dedicated andfocused team of highly skilled individu-als working together can rise to thechallenges presented by this highlycomplex project and safely and effec-tively deliver amazing results. From atechnical perspective alone, this is anoteworthy accomplishment. Yet in myopinion, it is far more.

The three keys to our successful execu-tion are our people, our processes,and our focus on new technologydevelopment.

When I think of our people, I think ofthe multitude of diverse groups located

all over the world, working dili-gently and enthusiasticallytoward a common goal. I thinkof the partnering and collabo-rative spirit that permeated themindsets of each project teammember. representatives ofmore than 20 different cultures speak-ing more than 20 different languagesworked simultaneously on the project.I think of their commitment to excellenceand their total dedication to safety andthe environment during the execution ofthis project. I also think of the peopleof the state of espirito Santo in Brazil,each of whom will benefit from the success of this development.

When I think of the processes, I remem-ber the meticulous planning, down tothe last detail, that enabled the seam-less integration of all the componentsand activities that needed to be coordi-nated, scheduled, and executed. I think

of the many legal, tax, finance, con-tracting, and permitting activities thatneeded to be coordinated with an enterprise-first mindset.

The accomplishments of our engineersand geoscientists on the developmentof cutting-edge, fit-for-purpose designsare impressive indeed, proving onceagain that our people are our mostimportant resource.

I congratulate each and every one ofthe individuals who took part in the BC-10 Parque das Conchas’ develop-ment. each of them can take greatpride in achieving world-class perform-ance on this world-class project.

Muito Obrigado!

Kent H. StinglProject Manager

Parque daSCOnCHaS

Kent H. StinglProject Manager Parque das Conchas

The 327,000-ton FPSO Espirito Santotakes its place as a visible symbol ofShell’s ultra-deepwater leadership.(Photos courtesy of Shell)

Foreword

Shell Foreword_05_24_10_Layout 1 5/26/10 1:42 PM Page 1

PARQUE DAS CONCHASAn Ultra-Deepwater SuccessA Supplement to E&P Magazine

HART ENERGY PUBLISHING1616 S. Voss, Suite 1000Houston, Texas 77057Tel: +1 (713) 260-6400Fax: +1 (713) 840-8585www.epmag.com

Group Publisher, E&P RUSSELL LAAS

Associate Publisher, E&P DARRIN WEST

Director ofBusiness Development ERIC ROTH

Editor JUDY MAKSOUD

Manager, Special Projects JO ANN DAVY

Contributing Editor DICK GHISELIN

Profiles Editor MJ SELLE

Assistant Editor ASHLEY ORGAN

Corporate Art Director ALEXA SANDERS

Assistant Art Director MELISSA RITCHIE

Graphic Artist FELICIA JONES

Production Director JO LYNNE POOL

For additional copies of this publication, contact Customer Service +1 (713) 260-6442.

Vice President, Consulting E. KRISTINE KLAVERS

Executive Vice President and Chief Financial Officer KEVIN F. HIGGINS

Executive Vice President FREDERICK L. POTTER

President and Chief Executive Officer RICHARD A. EICHLER

contEntS

On the cover: Parque das Conchas (“ShellPark”) lies almost 1 mile (1.6 km) beneath theFPSO Espirito Santo about 75 miles (121 km) southeast of Vitória, Brazil. It is operated by Shell on behalf of co-venturers Petrobrasand ONGC Videsh. (Photo courtesy of Shell)

1 Foreword: Parque das Conchas

4 OverviewExploration to Production: An Ultra-Deepwater Success A remarkable effort came to a successful climax when first oil flowed from Shell’s BC-10 ultra-deepwater development offshore Brazil in July 2009.

14 Health,�Safety,�Security,�and�the�Environment�Total�Commitment�Characterizes�BC-10�ProjectA proactive strategy on health, safety, security, and the environment pays off.

19 Surface�Production�Production�Facilities�Are�World-Class��Designed in Monaco and assembled in Singapore, the surface production facilities can efficiently process 75,000 b/d of water injection, 100,000 b/d of oil,and 50 MMscf/d of gas.

28 Subsea�Production�A�‘Subsea�City’�Rises�on�the�Seafloor�Most of the BC-10 construction was conducted onshore in Brazil.

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39 Development�Drilling�and�CompletionDrilling�Challenges�and�Innovations�Drilling the BC-10 development wells required great precision and careful control of equivalent circulation density. Many drilling records were set in the process.

48 Future�PlansToday�and�Tomorrow�Plans include development of a fourth field, with first oil in 2013.

49 Acknowledgements�The�Parque�das�Conchas�TeamThe BC-10 project required the expertise and dedication of many individuals.

50 Company�Profiles�It�Takes�Teamwork�Shell had many partners on the BC-10 project.

(Photos courtesy of Shell)

Shell Table of Contents_05_25_10_Layout 1 5/26/10 1:40 PM Page 3

BC-10 production flows to the FPSO Espirito Santo,where it enters the massive turret assembly in theforepeak, then through the swivel tower on topbefore being routed to the two processing trains.(All images courtesy of Shell)

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Vitoria

~120 km

ES

RJ

Porto de Ubu

~Gasoduto

BC-60

BC-60

BC-10 Ostra

Abalone

Argonauta

Nautilus

The BC-10 block is located about 75 miles (120 km) south southeast of the city of Vitóriaand lies offshore of the Brazilian state of Espirito Santo. it lies just east of several prolificblocks developed by Petrobras.

ExPlOrATiON TOPrOduCTiON: AN ulTrA-dEEPwATErSuCCESSA remarkable effort came to a suc-cessful climax when first oil flowedfrom Shell’s BC-10 ultra-deepwaterdevelopment offshore Brazil in July2009. This is the story of a singularcombination of people, process, and technology to reach a goal in a challenging environment.

The BC-10 block offshore Brazil isoperated by Shell with a 50% equityshare. Co-venturers are Petrobras with35% and ONGC Videsh with 15%.The license was awarded on Aug. 6,1998. After an intensive exploration

campaign, a declaration of commer-ciality was issued in 2005. Operatedby Shell, the BC-10 project representsa complete field development projectfrom exploration to first oil production,and is now proceeding to long-termfield management. Every phase of fielddevelopment was accomplished underShell’s control, and although thisaccount implies a sequence of events,in actual fact, it was not performed insequence; rather, several activities wereconducted simultaneously like a sym-phony orchestra performing a concerto.Each “instrument” played its role in a

Overview



coordinated way, so that the entire proj-ect came together seamlessly like a finepiece of music. The diverse aspects ofoffshore field development transcenddrilling and completion. They alsoinclude permitting, contracting, humanresources, health, safety, and the envi-ronment, all of which were essentialand critical to success. That the projectwas accomplished on time and onbudget is a tribute to the hundreds ofworkers both within Shell and within theranks of its co-venturers, its contractorsand suppliers, and those of the variousagencies of the government of Brazil.

Field descriptionSometimes discoveries are attributed togood fortune or blind luck. In fact, arecently discovered deepwater field inthe Gulf of Mexico is unabashedlynamed “Blind Faith.” However, in mostcases, discoveries are all about knowingwhere to look, and interpreting the subtleclues that encourage additional explo-ration until a scientifically supporteddrilling case can be postulated. Startingwith the investment in existing seismicdata, the search began, culminating in the decision to purchase the BC-10

block and launch a five-well explorationdrilling campaign. During the searchand evaluation phase, additional seismicin the form of a more definitive 3-D survey was acquired. A large area span-ning some 4,900 sq miles (12,500 km2)was acquired from which the BC-10joint venture partnership purchasedabout 1,172 sq miles (3,000 km2).Shell geoscientists participated in theprocessing of this data. Approximatelyone dozen prospects were identifiedand detailed from these seismic data.

The four fields constituting the BC-10block were not easy to evaluate. Thefirst well drilled in 2000, the 1-Shell-01-ESS, probed what later becameArgonauta B-West and penetrated the oil/water contact, which in itself is a powerful clue to evaluating theprospect’s possibilities. The plannedfive-well program quickly grew to eightwells that were drilled between 2000and 2004 as geoscientists built theirinitial models. Ultimately, a total of 13 exploration and appraisal wellswere drilled and evaluated in theexploration phases from 1999 to2006. Eight successful wells discov-

Great care was taken to ensure that thelocal fishing community was kept informed,and that field development activities didnot interfere with their livelihoods.

6 June 2010 n Parque das ConChas


ered and delineated six separate oilaccumulations—an admirable successratio in anyone’s book—still significantuncertainties remained. The gaps inpre-development reservoir knowledgewere so significant that plans were in astate of flux right up to the time the fielddevelopment wells were drilled. Tounderstand why the prospect was sopuzzling, it is worthwhile to look at itsgeology and morphology.

Situated at the northern extent of theCampos Basin, offshore Brazil, are sev-eral prolific fields on the South Americancontinental shelf. These have been devel-oped over several years by Petrobras, thenational oil company of Brazil, and oth-ers. The fields lie closer to the coastlinethan the BC-10 block, which is about 75miles (120 km) southeast of the coastalcity of Vitória. But they are in much shal-lower water. Nevertheless, there are several correlations between sedimentarysequences penetrated by these shelf wellsand those found in the BC-10 block.These correlations provided encourage-ment to the BC-10 explorationists.

Shell geophysicist Gunnar Holmes provided details of the regional geol-ogy. Like a complex puzzle, the geo-logical description was put together byconsidering all available information.The challenge in these situations is virtu-ally the same everywhere. The informa-tion does not come simultaneously, noris it in an actionable form. As a result,each clue must be evaluated and care-fully weighed. The geoscientists must beskeptical, because often, early theoriesare contradicted by subsequent revela-tions as more, definitive data areacquired. Raw data must be processedand assumptions must be validated—itis an iterative process that requires infi-nite patience and inquiring minds.

The earliest studies involved a regional 2-D seismic survey that had beenacquired prior to entering the block.After committing to explore Block BC-10, a 3-D survey was acquired from

WesternGeco. Encouragement wasprovided by the identification of “fullstack bright spots” that usually signalthe presence of structures compatiblewith hydrocarbon accumulation.Holmes wrote in a geological descrip-tion of the region, “The BC-10 surveyarea covers a passive margin basin.The discovered BC-10 fields to dateare post-salt, occurring in deepwaterUpper Cretaceous through Paleogeneturbidites overlying or adjacent to salt-induced structures. Piercing salt wallsand diapirs are dominant to the east of the block while salt swells are domi-nant toward the west. Sediment sourcesare interpreted from the west and north-west. Amalgamated sand-filled chan-nels and turbidite aprons, with largeareas of overbanks (sands, silts, andshales) are the dominant depositionalfeatures.

“All of the BC-10 oil fields are deepwa-ter sand-dominated turbidite reservoirswith different structure and stratigraphyclosures. Ostra is an Upper Cretaceousage sandy turbidite valley systemdraped over a salt dome. Abalone is

a salt flank, mini-basin ponded Ceno-manian turbidite system. Argonauta-BWis a Lower Paleogene channel beltcomplex of turbidite sands with a com-bination of structure drape and strati-graphic closure. Argonauta-ON is anEocene age stratigraphically controlled,sandy turbidite apron.”

BC-10 is off the continental shelf, on thelower slope, in waters ranging in depthbetween 4,600 and 6,560 ft (1,400and 2,000 m). There is evidence ofextensive subsea landslides throughoutthe area as vast masses of sedimentsloughed off the shelf and cascadeddown the slope. This is seen in the tur-biditic nature of the rock extending fromthe mudline down into the reservoir itself.Detailed geomechanical studies con-ducted for shallow-drilling hazards eval-uation from the seabed down about135 ft (41 m) below the mudline uncov-ered a field of scattered mass transportdeposits, which consisted of hugeburied chunks of sediment “floating” in a sea of debris, the artifacts of recentlandslides off the continental shelf. Atdeeper levels, as if to complicate the

The stratigraphic sequence at BC-10 indicates a complex column with post-salt discover-ies in the Ubatuba and Namorado formations.

Source Rock: Lagoa Feia

Cretaceous Salt - mobile substrate

Argonauta-BW, Nautilus Accumulation

Argonauta-ON, Argonauta-OS Accumulations

Ostra Accumulation

Abalone Accumulation

Nautilus Accumulation

BC-10 Discoveries



evaluation, several salt diapirs thrustupward from beneath the reservoir cre-ating extensive faulting. The reservoiritself is challenging, consisting of Paleo-gene and Cretaceous age sedimentsthat are largely unconsolidated withcomplex mineralogy. The strata at Ostrawere characterized by a very narrowwindow between the fracture pressuregradient; that is, the pressure at whichthe rock would fracture and pore pres-sure gradient, the pressure of the fluidoccupying pores in the rock. Drillingunder these conditions is inherentlyrisky. If mud pressure is too low, aninflux of formation fluid could enter theborehole, possibly initiating a blowoutor the formation may become unstableand collapse. Conversely, if mud pres-sure is too high, the formation couldfracture and drilling fluid could be lost,damaging the formation and leading toa potential blowout.

According to Holmes, “The rockphysics models derived from the welldata and the resulting modeled seismicresponses were validated early in thediscovery phase. Additional wells pro-vided refinements but no contradictionsto the rock physics model that sustainedsuccessful seismic amplitude and attrib-

ute work. Definition of direct hydrocar-bon indicators (DHI) amplitudes formany of the initial wells in the first tier,high probability of success (PoS)prospects, was not difficult: the ampli-tude extremes are highly correlated tothe hydrocarbon accumulations and theprospects generally had multiple DHI

BC-60 (PBR)

BC-10

The Parque das Conchas: Four Shell-operated BC-10 area production licenses are shown in red. Extensive Petrobras development can beseen to the west of the BC-10 fields in the Parque das Baleis.

“The rock physics modelsderived from the welldata and the resultingmodeled seismic

responses were validated early in the discovery phase.”—Shell geophysicist Gunnar Holmes



attributes. On the other hand, the sec-ond tier of prospects with spotty to lowamplitudes was often difficult to refine,and even with additional analyses, the PoS could not be improved above50%. To resolve geologic and geo-physical questions within BC-10, weconducted reprocessing projects onsmaller field areas within BC-10, to follow up specific field discoveries and support appraisal work, as well as development activities.”

The determination of Shell’s geoscientiststo follow the clues revealed by the dataenabled the generation of increasinglyvaluable information through additionalanalyses. By collaborating with manyShell and vendor experts, an investment-grade reservoir model evolved that con-tinues to provide useful information andthat will be invaluable when additionaldevelopment wells are considered.

ChallengesDespite the drilling risks, seismic explo-ration of the area was promising andwas complemented by data from wellson the continental shelf and continentalslope between the BC-10 block and theBrazilian coast. Further encouragementto proceed on the BC-10 developmentcame from the fact that the task was wellwithin the realm of possibility—proventechnology existed to characterize thereservoir and implement its exploitation.With the technical hurdles deemed solv-able, the only remaining challengeswere purely economic ones—could aneconomically attractive and sustainablesolution be found to achieve reasonablerecovery factors for the medium to heavycrude, safely and with concern for theenvironment?

Shell’s involvementWhen thinking about the BC-10 project,one theme consistently rises to the surface. The project is a textbookexample of coordination. How elsecould one characterize a program whosediverse and technologically complexphases were simultaneously conducted in

different locations around the world, andultimately executed so successfully?Using a multinational, multicultural teamoperating in a number of different timezones and integrating the hardware,software, and labor of more than twodozen separate suppliers amounted toorchestration on a global scale.

In a macro-sense, the major compo-nents of the project can be segmented

into seven separate efforts: explorationand appraisal, permitting, developmentdrilling, facilities construction, well completion, subsea installation andtieback, final assembly and commis-sioning. But most of these activitieswere carried out concurrently on aglobal scale. That they all cametogether seamlessly on time and onbudget is a tribute to the ingenuity andperseverance of the team members.

The Enhanced Pacesetter design, six-column semisubmersibleStena Tay was converted for deepwater service in 1999 asthe demand for deepwater units soared. Its water depthcapacity is 7,546 ft (2,300 m).



Coordination was the name of thegame, both in the macro sense and inthe micro sense. Like the precise move-ment of chess pieces on a chessboard,individual offshore activities had to becarefully sequenced, so there were noclashes, and no gaps in critical workflows. The comings and goings ofeach vessel were not only timed toensure no two vessels were scheduledto occupy the same space at the sametime, but the needs of indigenous fishermen in the area had to be takeninto account. If even one vessel wasdelayed for any reason, the result wasa “domino-effect’ that cascadedthrough the plan, often necessitating a total plan rebuild.

Shell offshore coordinator Mark Kiteexplained the challenges of coordinat-ing simultaneous operations (SIMOPS).“A key objective was to minimize thetime from project launch to first oil.Coordinating the activities of multiplevessels, sometimes numbering as manyas 10, was a major challenge. Ourgoal was to minimize vessel downtimeor standby time. Many of the vessels’work scopes conflicted with each otherdue to their physical location, and

coordination was required so somecould work simultaneously without com-promising safety. This required gainingthe respect and cooperation of severalworkgroups both within and outside thecompany. Naturally each group waslooking after its own interests. I hadto convince them to focus on ‘best-for-project’ solutions.”

Kite continued, “Deepwater offshorevessel costs are very high. For example,rig spread costs were more than US $1million/day. Pipeline lay barges costupwards of $700,000/day, and agreat deal of money might have beenlost if a vessel were required to standbywhile another vessel completed anactivity. In addition, the added timewould have delayed first oil.”

Asked to explain how the challengeswere successfully addressed, Kite said,“Planning and communications. Weneeded to have good plans that werecommunicated to all stakeholders. Butmost important, we needed built-in flexi-bility to react to changes. A big part ofour success was gaining the coopera-tion and respect of the other [Shell]team leaders and the clear understand-ing that we were all working towards acommon goal. The success we experi-enced was exceptional. We had verylittle downtime and first oil was in linewith the P10 [most optimistic] schedule.Many times delays were avoided byonly a matter of a few hours, andoften, when one vessel experiencedproblems, another pitched in to helpout. I recall a specific example whenthe umbilical cable laying vesselhelped the drilling rig by providingremotely operated vehicle support.”

A well-coordinated SIMOPS plan rever-berates throughout the project, and caneliminate or at least minimize logisticsproblems, project delays, conflicts, andmost important, safety incidents. “Coor-dination is not something you do once,”Kite concluded. “It is a continuous 24/7job from launch to first oil. No matterhow well the project is planned, some-thing will come up that requires achange. Fortunately, we knew this fromthe start, so we had contingency planswe could implement while we re-grouped to get back on the main plan.I’m proud to say that the project wascompleted with minimum to no vesselstandby charges and early first oil.”

Argo-BW Ostra Abalone

Dep

th (m

bsl)

Dep

th (m

bsl)

1200m 950m

2450m

Salt

Salt Salt

Location Map

Ostra

Aba.

Argo-BW

Depths Below Mud Line

Ostra is very shallow and it is difficult to turn the boreholes to the horizontal through these relatively soft overburden muds into the reservoir oil sands.

A 3-D seismic line through the BC-10 block illustrates the complex post-salt structure andcloseness to the mudline (seabed), the principle challenge for the drillers.


“Coordination is notsomething you do once; itis a continuous 24/7 jobfrom launch to first oil.”

—Shell offshore coordinator Mark Kite


Good citizenshipThe coordination involved more thanlogistics. Government permits had to beobtained, bids tendered, and contractswritten. The local population had to bekept informed and their rights taken intoaccount. Unlike many nations with off-shore production, Brazil has given cer-tain rights to the inhabitants of coastalcommunities regarding the developmentof offshore areas lying opposite their vil-lages. These rights must be honored,and permission must be obtained at thelocal level before operations could com-mence. Coastal communities actuallyhold a stake in the hydrocarbons pro-duced from off their shores, and thesestakes must be clearly established andagreed to in advance. In addition, allequipment and supplies brought to theproject from outside Brazil had to receivecustoms clearance and any duties paid.This was true even for items that neveractually landed in Brazil, but werebrought into the coastal waters with thefloating production storage and offload-ing (FPSO) vessel. All of the above itemsfall under the category of “good citizen-ship” and Shell was determined andtotally committed to be a good citizen.This meant going above and beyond theminimum requirements, and taking a pro-active stance to ensure that Shell, itsemployees, and its contractors wereviewed as highly desirable members ofthe community at large.

Two areas stand out as excellent exam-ples of community stewardship. Notsurprisingly, the first was the extensionof Shell’s HSSE initiatives to all contrac-tors, subcontractors, and stakeholders.Not satisfied to simply establish a safeworkplace offshore with “zero incident”objectives, the company rigorouslyenforced its Life Saving Rules on allservice and supply companies, on landor offshore, engaged in the project. Secondly, the company supported environmental groups in monitoringactivities to ensure that none were detrimental to the local populations ofwhales or other sea creatures. This

extended to fish and oyster farms alongthe coast. The concerns of the commer-cial fishing community were addressed.

A perfect example of Shell’s safetycommitment played out onshore. ABrazilian pipe yard was engaged toassemble and apply protective coatingto the miles of riser pipe that would beneeded. On an initial inspection of thefacility, it was observed that a pipe-coating machine had no emergencyshut-down switch. Shell insisted that theoperation be discontinued until themachine could be retrofitted. A fewdays later, a worker’s coat becameentangled in the feed mechanism.Trapped, he was being inexorablydrawn into the machine where he mostcertainly would have been maimed orkilled. The worker was able to push

the emergency button, stopping themachine, and was subsequently disen-gaged from the feed mechanism by hiscolleagues. By refusing to turn a blindeye to workplace hazards not on com-pany property, the Shell inspector likelywas responsible for saving a life.

Early planningBetween the initial BC-10 discovery in 2000 and 2005, an aggressive

The Transocean Deepwater Naviga-tor underwent a US $305 millionconversion in 2000 to bring it backto drilling mode, increasing its waterdepth capacity from 2,500 to7,218 ft (762 to 2,200 m) andmodernizing its drill floor equipment.Added flotation sponsons can beseen along the sides of the drillship.



exploration and appraisal program wasfollowed to map the field and delineateits reservoirs. Four separate reservoirswere identified: Ostra, Abalone, Arg-onauta B-West, and Argonauta O-North. The decision was made todevelop the prospect as a cluster devel-opment in two phases. First, the Ostra,Abalone, and Argonauta B-West fieldswould be developed in Phase I; thenArgonauta O-North would follow inPhase II. The fields were named afterindigenous shellfish from the area, usingtheir Portugese names. Accordingly, the BC-10 area was named “Parque dasConchas,” meaning “Shell Park.” InDecember 2005, a Declaration ofCommerciality was signed with ANP(the Brazilian National PetroleumAgency) and the project was sanctionedin November 2006.

During the exploration period, the objec-tive was to gather sufficient informationto put together a development plan.Seismic analyses were conducted byShell to refine specific prospect areasand the uncertainties prior to drilling.

As each well was drilled, it was loggedextensively. All seismic, drilling and log-ging data were integrated, forming thekernel from which a comprehensive 3-Dreservoir model would be derived. In all,13 wells were drilled with six field dis-coveries, and all of the subsurface infor-mation enabled the partners to write acompelling Declaration of Commercial-ity for submission to the government.

The exploration drilling was conductedby the dynamically positioned semisub-mersible drilling unit Stena Tay and the dynamically positioned drillshipDeepwater Navigator.

Because of the water depth, a subseadevelopment and production schemewas envisaged. The decision wasmade to gather all production fromeach field, perform initial processing onthe seabed, then boost the productionup to an FPSO vessel, moored at amore-or-less central location. During theearly planning stage, a search wasbegun for such a vessel. n

Trained teams tagged and monitored thewhale population using sophisticated elec-tronic beacons and GPS devices, analyz-ing the animals’ movements and behaviorin the vicinity of the BC-10 block to preventinfringement on habitats or traditionalmigration lanes.

A series of community meetings washeld, and members of the local pop-ulation were encouraged to shareany concerns.



(L1) = D & C, trees and ALM installation; (L2) = Risers, flowlines, jumpers, manifolds and flying leads installation

NOTE:

Management

BC-10 Execution Level 1 Schedule

Phase I

Status: January 2010

FPSO

Start Finish2007 2008 2009 2010

Subsea

Wells

Commissioning&

First Oil

= Offshore = Design = Fabrication = Deliveries = Permits = Integration

Jun-06

Nov-06Nov-06

Nov-06

Jun-07

Nov-06May-07

Apr-08

Nov-06Jul-07

Sep-07 Nov-08

Feb-09

Nov-06Apr-07Mar-08

Sep-08

Nov-08

Jan-09

Nov-06

Nov-06Oct-07

Oct-08

Nov-06Mar-07

Jul-08

Aug-08

Oct-08

Nov-08

Nov-08

Feb-07

Mar-08

May-08

Nov-08

Jan-09

Jan-09

Mar-09

Mar-09

Jul-08Aug-08

Jun-08Jul-08

Apr-08May-08

Jun-08

Jun-08Jul-08

Oct-08

Dec-08

Jun-09

Sep-07Jul-08Apr-09

Jun-09

Dec-08

Apr-10

Apr-08Apr-08Sep-08

Nov-08

Sep-07Jun-09

Jul-09

May-09

Oct-08

Nov-08

Dec-08

May-09

Feb-07

Jan-10

Feb-10

Jan-09

Apr-09

Feb-10

Feb-10

Jul-09

HULL

TURRET

MOORING

TOPSIDES

PIPELINES &FLOWLINES

UMBILICALS

SUBSEAHARDWARE

Transport & Install

Pipeline & Flowline Installations

Manifold Installations

Jumper Installations

THS/Tree Deliveries

PLET Deliveries

PM1 & ALM1 Manifold Deliveries

PM2 & ALM2 Manifold Deliveries

Subsea Control System Deliveries

Complete Precom F/L & Umbl.

Abalone Appraisal - AW

BW Production

OSTRA-PM1

OSTRA-PM2

First Oil Abalone (A West)

Abalone Production - AW

Gas Disposal

Riser Pull-ins

1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J

CONTRACTAWARD

P7H

VAR 4 FID PREVIOUS (LP) (L1) (L2) (L3) (L4) START UP (L5)

Preinstall Mooring

SAIL AWAY

Install Umbilicals

BW Appraisal

Design & Precurement



Hull Conversion

Fabrication

Fabrication


Design

Design

Design

Prototype/TestingFabrication

Fabrication

Mill Run & Coating

Integration & Commissioning

Fabrication

Fabrication

A typical projecttime/activity chart illustrates how simul-taneous componentsof the project weremanaged to result in a seamless assembly, on timeand on budget.



TOTAl COMMITMEnTCHARACTERIzES BC-10PROjECTA proactive strategy on health,safety, security, and the environmentpays off.

The BC-10 saga is a story of great technical and scientific achievement. But it would never have been told withouta simultaneous proactive and aggressivecommitment to health, safety, security,and the environment (HSSE).

Shell’s HSSE record on the BC-10 projectserves as a shining example of what canbe achieved through total commitment.Impressive records were set in many

areas, but HSSE cannot be measured bythe number of plaques on a manager’swall; it is a mind-set―an attitude― thatmust permeate the conscious and uncon-scious acts of every employee, every contractor, and every stakeholder. HSSE begins with sharing a culture ofcommitment with all affected parties, by setting the example, employing bestindustry practices in every endeavor, andproviding leadership.

Fostering this attitude in such a waythat it permeates the vast universe thatconstitutes the BC-10 area of influence

starts at the top. Robert Patterson,Shell’s vice president of UpstreamMajor Projects, Americas, said, “Ourability to work as a team internally,and our ability to partner with othersexternally, should stand as an exampleof cultural, technological, and sustain-able diversity. The conventional wis-dom is that you can’t do this sort ofthing; you can’t break the team up,spread them over multiple time-zones,challenge them on several levels, someoutside their discipline, and expectresults—but we did. The BC-10 story isone of bringing people together in a


Health, Safety, Security, and the Environment

CH2-Shell-05_24_10_Layout 1 5/26/10 1:51 PM Page 14

common theme, working together toachieve a goal, bringing the very bestto bear, and accomplishing somethingthat’s truly remarkable.”

Kent Stingl, BC-10 project manager,added, “This element of partnering isnot just an internal one, nor is it limitedto our suppliers. It also includes thelocal community and the environment inwhich we work. We wanted to ensurethat our immediate neighbors wereinformed and involved from the begin-ning, just as we wanted the globalcommunity to know we were protectingtheir environmental interests as well. Inthis regard, our corporate policies of noharm to people and protection of theenvironment stood us in good stead.”

Ignorance is the worst enemy of a proj-ect of this sort. If the stakeholders don’tknow what’s going on or whether itaffects them personally, speculation

and conjecture can poison their abilityto behave or think reasonably. Accord-ingly, Shell adopted an “open-stance”from the very beginning of the project,holding popular town meetings withinterested and affected parties from all over Brazil. These events includedtransportation and accommodationsfor three days. Every aspect of the

project was discussed, questions wereaddressed, and follow-ups were imple-mented where necessary.

In Brazil, the indigenous populationshares in the profit from development inthe sea offshore from its communities,so the people were indeed stakehold-ers. Others, like the fishermen, were

Shell was determined to leave thebeautiful Brazilian coastal environmentuntouched by hydrocarbon developmentjust offshore. (Photo courtesy of Shell)


“Our ability to work as ateam internally, and…topartner with others exter-nally, should stand as an

example of cultural, technological,and sustainable diversity.”—Robert Patterson, Shell’s vice president of Upstream Major Projects, Americas



BC-10 TOP 10 HSSE Risks 26 Jun 09

Note: This is to support regular discussion (based on judgement, not structured assessment), and ensure focus; items may move upand others move down. This list can also aid those visiting worksites to maximise their contribution by focussing in the right place.– BC-10 covers a very wide geographical area; risks vary by location. Focus is on controls required now (rather than design stage).– Visible management commitment to HSSE is acknowledged as the most important management system component.

Have the risks been identified? Are the barriers in place? Is there visible reinforcement at the worksite?

# δ RISK Main Barriers Comment

1. People falling from heights Risk assessment A number of fatal or near fatal injuries recently in other projects when(into holes, from working Competent supervision workers removed boards or planks and fell through a hole below.platforms, collapse of Effective toolbox talksstructures) resulting in major Physical, clearly visible barriers Recent MOB with plywood board covering hole and earlierinjury or death Adequate lighting fall down ladder on vessel.

Good housekeepingApproved scaffolding structure Fatal incidents elsewhere: The addition of the hatch in the Fall arrestor securely in place walkway should have been risk assessed and a MOC process

followed. Better to not install these hatches.

Risk assessment hierarchy: Avoid, prevent or mitigate falls.

Leadership reinforcement of toolbox talks required.

2. Failure of objects under Inspection of lines Spooling, guy & support cables, anchor chains, tension, resulting in major Assessment by competent persons of loading tow & barge tie-off ropes, slings.injury or death Toolbox talks

Physical barriers, separation distance Testing of vessel propulsion system shall not be carried out whilst moored.

Review of spooling activities has taken place.

Shell lifting and hoisting.

Numerous high potential consequence incidents recently eg during riser pull-in.

3. Assaults on personnel or Security induction Brazil mostly, numerous incidents involving attack their families Avoidance of high risk areas on pedestrians and car jacking.

Awareness and minimisation of profileAppropriate response if confronted Exposure increased by travelling alone.Selection of suitable location and housingJMP compliance A means of contact when travelling and location details are

helpful for recovery and assurance if delayed return.

Location for residence, temporary stay and travel.

Residence should meet security recommendations.

Recent incident in Copacabana involving spiked drinks.

4. Dropped objects – falling For lifts: Incident in Nov 08 resulted in fractures.onto people resulting in PTW and associated controlsmajor injury or death Competence of L1 & 2 critical positions Huge amount of lifts has taken place; both major lifts of

Competent supervision items onto the FPSO and more routine lifts. Major lifts ontoEffective toolbox talks FPSO now complete.Controlled lift areaEffective communications Numerous dropped object hi-potential incidents at Sound lifting procedure Singapore yards.Pre-use inspectionFunctioning safety devices For major lifts, lift plan signed off by technical authority.Operation within environmental limitsArea below remains clear of personnel Many of the controls listed will be within a specific PTW.Work carried out only when weather does not jeopardise safety Crane operators and riggers are L1 critical.

Hard hat has prevented significant injury in a number of recent small object incidents



# δ RISK Main Barriers Comment

4. Dropped objects – falling Non-lifts – objects being carried or Equipment and tools may fallonto people resulting in objects positioned at height:major injury or death Toolbox talks Tools not to be held when using ladders

HousekeepingInspections Incorrectly secured tools when using ladders or stairwaysProtect area below e.g. netting or restrict have led to injuries to others.access3 point contact when using laddersToe boards on scaffolding Kick plates Falling unsecured equipment or construction material has led to injuries.around openings in floors.

A window (1x.3 m) with a known hinge defect fell fromcrane cab fell 6 m, Jun 09.

For stacked pipes Leading causes of storage rack failure: Poor design; incorrectSuitable piperacks installation and assembly; wrong handling equipment to load and

pipe; operator error; and structural problems with the storage area.

5. Marine vessel collision Competence A significant marine presence now exists in Brazil, plusor sinking leading to Marine standards implemented the FPSO is heading to Brazil.major injury or death Adverse weather policy

A significant ballast incident occurred recently, rapidly causinga 10 deg+ list.

6. Helicopter crash Competence Mar 09, Nov 08: Crew change flight not meeting Shell Aircraft standards implemented requirements. Helicopter transport is always a noticeable Adverse weather policy component of offshore fatal accident rate.Simops plan

Competence includes escape and survival training for passengers.

Shell Aircraft involved in aviation contractor selection and Helideck audits.

7. Loss of control while Drivers Includes loss of control by third parties.driving – includes pipe Competent drivers inc no use of phones etc Ref EP2005.transport by forklift (with Fitness to drive Also links to security risks.and without pipe clamps) Implementation of JMPs Inc defensive driving training.resulting in major injury Suitable vehicles – inc seat belts Fitness includes not under influence of drugs or alcohol.or death. Consequence management for non-compliance

Secured loads – inc pipesPassengers Passenger’s refusal of unsafe transport.Intervention if necessaryUse of seatbelts

8. Electrocution Competence Risk increases at commissioning.Use of locks and tags at isolation pointsTesting and monitoring of isolation PTW should cover the control stated and other requirements.

9. Systems under pressure JSA, PTW, toolbox talks Hydro-testing, pigging. generating missiles, Physical barriers, separation distance Recent incident on FPSO during leak testing.resulting in major injury Signs warning of hazard Avoid pneumatic testing.or death.

10. Fire or explosion due to Competence Emerging risk as we move towards first oil.ignition of hydrocarbons Effective management of change

Inspection and verification of critical systemsPtW system

(Table courtesy of Shell)


concerned that the project mightdestroy their livelihood with pollution,or in some way drive the fish awayfrom their traditional spawning or feeding areas. Farther offshore, environ-mentalists were interested to learn ifoperations would disturb the habits of sea mammals like whales.

Every single one of these issues wasaddressed. Shell assisted in mariculture,helping establish oyster breedinggrounds and fish farms. The companymaintained a “whale watch” and sup-ported a whale tagging and monitor-ing program so environmentalists couldstudy and evaluate any changes in thewhales’ behavior possibly attributableto offshore development. In a practicalsense, Shell closely coordinated themovement of the myriad of vessels nec-essary for such a comprehensive devel-opment project to ensure that marinetraffic jams did not materialize thatwould disturb the local fishing, recre-ational, and sea transport activities.

Do no harm, leave no footprintThe process was not limited to the sea.Shell also recognized the impact of airand land transport on the local commu-nities. Major freeways and road net-works are not found in the coastal areaof Espirito Santo state, and clogging theexisting roads with 18-wheelers haulingsupplies to support Shell projects didnot project the good neighbor imageShell was determined to create. Allthese activities were coordinated withsustainable development objectives inmind. Do no harm, leave no footprint.

Another aspect of being a good neigh-bor and desirable development partneris scrupulous adherence to the law.Shell proactively implemented a strictlyenforced and clearly communicatedpolicy governing contracts, taxes,import/export duties, and local content.As many of the contracts as possiblewere negotiated with Brazilian compa-nies or companies with manufacturingfacilities in Brazil. Brazilian nationals

were hired. These policies were commu-nicated to all would-be subcontractorsand suppliers who were expected tobecome good neighbors too.

The main contractors included BrazilianDeepwater Floating Terminals, a jointventure of SBM and MISC which ownand operate the floating productionstorage and offloading (FPSO) vessel;Subsea 7, onshore fabricators and off-shore installers of pipelines, flowlines,risers and jumpers, and installation ofumbilicals manifolds and subsea distri-bution hardware; FMC-Brazil, fabrica-tors of subsea trees, controls, andartificial lift modules; and Transocean,drilling and completion operations.Contracts with these providers includedHSSE compliance elements, as well astax, legal, and financial aspects.

By insisting on an open operationaland negotiating culture, Shell won theconfidence of Brazil’s Federal Environ-mental Agency and the Brazilian Navy,two agencies that wield considerableinfluence in the granting of operatinglicenses. A total of six critical licenseswere applied for, vetted, and approvedwith no delays to ongoing constructionand operations.

Robert Parker, HSSE manager,explained how the team implementedthe commitment to continuous improve-ment: “We addressed the risks andidentified the most appropriate controlsfrom the boardroom to the worksite.We supported our contractors directly,

by deploying safety coaches, and indi-rectly, by conducting focused reviews ofsafety at the workplace. But we alsochallenged our contractors to drive theirown improvements. We created adynamic Top-10 list of HSSE risks, andfocused on the barriers that need to bein place to manage those risks.”

A popular newsletter was launched. Itnot only spread risk awareness but keptthe BC-10 team apprised of progress ineach facet of the project, no matterwhere the activity was located. Staff inBrazil could see the shape of things tocome by seeing photographs of progresson the FPSO halfway around the world.

In the area of health, proactive stepswere taken to protect workers fromlocal seasonal diseases such as den-gué fever. Shell’s Diving Center ofExcellence was called in early to pro-vide greater assurance over the divingactivities, where errors quickly developinto fatal accidents. Interactive healthand safety meetings were held in theshipyard to change the culture of hun-dreds of workers so they would under-stand the benefits of good practices forthemselves and their co-workers.Rewards were given for identificationand reporting of hazards. These werejust a few of the proactive steps initi-ated by Shell and its contractors.

By relentlessly pursuing its “no harm to people” philosophy, the BC-10 proj-ect has made significant strides towardShell’s “Goal Zero” target. n


“We addressed the risksand identified the mostappropriate controlsfrom the boardroom to

the worksite.”—Robert Parker, HSSE manager


PrODuCTION FACILITIeSAre WOrLD-CLASSDesigned in Monaco and assembled inSingapore, the surface production facili-ties can efficiently process 75,000 b/dof water injection, 100,000 b/d of oil,and 50 MMscf/d of gas.

Water depth limited the number ofoptions for producing the BC-10 fields.The fields could be developed 100%subsea with tieback to shore via a long pipeline similar to the technique employed at Ormen Lange, or by a com-bination of subsea production modulestied back to a floating production facil-ity. The great distance from the coast,water depth, and nature of the pro-duced well fluids favored the latter technique. Another important decisionwas to choose the type of floating production facility to be used.

In selecting the production facility type,the principle decision factors includedfluid volume capacity and productionrate, size and weight of required sur-face processing equipment, number of

risers, and, of course, cost. A wide variety of production systems is presentlyemployed offshore Brazil, so there is an excellent base of historical data and experience to support the decision-making process.

The FPSO

All factors being considered, Shell choseto use an FPSO. Although there aremany FPSOs in operation around theworld, it should be noted there is reallylittle similarity between them, except perhaps in the area of storage. The processing trains located topside on thevessels are custom-designed to handlethe specific production from the field(s)being produced. Accordingly, it ishighly unlikely that an FPSO designedfor one field can be relocated toanother. So the story of the BC-10 production starts with the story of theFPSO, and can be divided into threeparts—the hull, the topsides, and the turret. A fourth part, equally important, is the story of the mooring system.

Hull—Shell selected a very large crudecarrier, the Japanese-built, 1975-vintage,single-hull steam turbine tanker T.T. Niel-stor. The vessel was originally employedas a trading tanker until 1992; then it was converted to a floating storage andoff-take unit and re-named the XV Domy,operating offshore Nigeria until 2003.After being taken out of service for twoyears, the hull was taken to the KeppelShipyard in Singapore to be inspected forupgrading and conversion to an FPSO.

While the hull was marketed for conver-sion by owner SBM, Keppel Shipyardbegan the task of removing corrodedsteelwork. As work progressed, surveyorswere able to refine their estimates to returnthe vessel to a “like new” condition with a20-year life expectancy. With the feasi-bility study completed to the satisfactionof Shell, the vessel’s owners, the classingsociety (ABS), and the insurers, BDFT, ajoint venture between SBM and MISC,signed a contract with Keppel, and thesteel replacement and hull refurbishment


The hull was taken to the Keppel Shipyard in Singapore to be inspected for upgradingand conversion to an FPSO. (Photo courtesy of Shell)

Surface Production

CH3_Shell-05_24_10_Layout 1 5/26/10 1:47 PM Page 19


commenced. Meanwhile, naval archi-tects and marine engineers from Shelland SBM began the task of designingthe overall conversion and establishing areasonable expected time schedule. Thework was conducted at SBM’s offices inMonaco. Plans included upgrades thatShell felt were necessary, the most exten-sive of which was the vessel’s conver-sion to a double-sided design. Shell’scommitment to safety and environmentalprotection required that all prudent stepsbe taken to protect against a spill ofproduced fluids into the sea.

The double-sided protection was achievedby designing 10-ft (3-m) wide sponsonsthat extend for almost the full length of theship’s hull on both port and starboardsides from just below the gunwales to theempty-hull waterline.

Shell project engineer Tom Muirhead pro-vided oversight during the refurbishment

and conversion at the shipyard. He saidthat one of the biggest challenges wasensuring the safety of the workers. Withthe excellent cooperation of SBM andKeppel Shipyard, safe working condi-tions were established. These includedadequate lighting inside the hull as wellas positive ventilation in confinedspaces. Many of the shipyard workerswere immigrants from other countries; as a result, as many as 19 different lan-guages were known to be spoken. Withdifferent languages and cultures, one ofthe critical tasks was to establish effec-tive safety training. Safety is more thanwearing hard hats and safety boots, itinvolves communication so each workeris aware of what others around him are

doing and being alert to spot hazardsand warn co-workers. Shell, SBM, andKeppel established a program of safetyclasses during shift changes and breaksthat were very effective. Muirheadexplained, “Through a series of safetymeetings, workers learned the benefitsof safe work practices and cooperatedfully with enforced rules. To their credit,the workers responded positively andadapted quickly to the improved condi-tions and work practices.” The effects onquality and efficiency were so tangiblethat the program spread quickly to otherprojects ongoing in the area. Improve-ment was noticeable. “One of the mostdifficult habits to break was the failure to wear safety eye protection, but byproject’s end, we were getting excellentcompliance,” Muirhead said.

Not counting the sponsons, the totalsteel replaced in restoring the hull to a like-new condition was more than5,000 tons. The sponsons addedanother 5,400 tons. In all, the additionof tanks, bulkheads and foundationstructures to support the proposed top-sides and the turret amounted to17,700 tons. To restore its corrosionresistance, the hull was blasted to baremetal and six coats of marine paintwere applied. An impressed currentcathodic protection system wasinstalled. Internal tanks were also part

To achieve the required double-sidedconfiguration, 10-ft (3-m) wide sponsonswere attached to the FPSO hull on bothsides over 90% of the vessel’s length.(Photo courtesy of Shell)

Topsides modules comprise three separation trains of two stages each—a plumber’s dream. (Photo courtesy of Shell)



blasted and coated to protect the steel,as were the full internal surfaces of the sponsons.

The ship’s engines and boilers wererefurbished so the vessel could sailunder its own power to Brazil from Singapore. Subsequently, the ship’ssteam boilers will be used to operatesteam turbine generators to provideelectrical power to operate the FPSOand all seabed modules. The boilerscan be fueled by heavy oil, diesel, orfield gas. Field gas is the preferred fuelwith diesel as backup.

To honor the Brazilian state off ofwhich the BC-10 FPSO was to bemoored, the ship was named EspiritoSanto. It is owned by a joint venturebetween SBM and MISC and is undera long-term lease to Shell and its co-venturers, Petrobras, and ONGC.

Topsides—Consisting of three separa-tion trains of two stages each, the top-sides is capable of processing andmetering production from all four BC-10 fields. This is not as easy as itsounds. Argonauta B-West producesheavy crude oil in the 16° to 18°APIrange. Argonauta O-North, which will be developed as part of Phase IIscheduled for completion in 2013,is expected to contain similar heavycrude. However, the Ostra field contains24° API crude while Abalone containslight gas condensate of 42°API gravity.The topsides modules were built in Singa-pore by Dyna-Mac and BT Engineeringand were installed atop the hull usingheavy-lift mobile cranes.

The three separation trains are required tosatisfy Brazilian allocation and meteringregulations. One train serves Ostra andAbalone production which can be com-mingled. The other trains handle Arg-onauta B-West and O-North, respectively,even though the latter is not in operationat this time. The second stage separatorsare needed to heat and process the crudeto achieve allocation quality requirementsso they can be commingled later in theprocess. Following separation and meter-ing in their individual trains, the producedfluids from each source are combined andtreated in a single bulk oil treater. Gasreleased in the process is compressed androuted to the gas injection well locatedabout 5 ½ miles (9 km) away near theOstra subsea complex. Ultimately, the gaswill be transported via subsea pipeline tolink with a Petrobras line being constructedin 2010, and then to shore. As in mostfield processing facilities, some of thegas is siphoned off to run heaters, tur-bines, and engines on board the FPSOto satisfy various requirements.

A very innovative heat recovery and recycling technique was employed.

HELI-DECK

ACCOMMODATION METERINGSKID & LER

POWER GENMODULE

PEDESTRALCRANE

FLARESTACK PEDESTRAL

CRANE

SWIVEL STACK

TURRET

PROCESSMODULES

FPSO Espirito Santo with its modulesidentified. (Image courtesy of SBM Offshore)

“Through a series of safetymeetings, workers learnedthe benefits of safe workpractices and cooperated

fully with enforced rules.”—Shell project engineer Tom Muirhead



Heat application is critical at variousstages in the process to prevent the for-mation of scale, or the precipitation ofwax, asphal tenes and hydrates that clogtubulars. Heat also speeds up the sepa-ration process. Instead of allowing theheat from the bulk oil treater to dissipateinto the atmosphere, recycled water at250°F (121°C) from the treater waspiped to heat exchangers where a sig-nificant percentage of the heat was cap-tured and used to heat the second stageseparators up to 230°F (110°C) to facil-itate water separation in that stage. Thewater does not mix with the crude oil inthe separator; it merely transfers its heat. Up to 33% of the heat energy wasrecovered and reused to facilitate theprocess and reduce costs. After thewater transfers its heat, it is cleaned andtreated to acceptable environmentalstandards for safe disposal into the sea.

Another innovation that pays big divi-dends was the ability to re-circulateprocessed crude, called “dead oil”(meaning all dissolved gas and waterhave been removed). On the seabedare several very large pumps that

“boost” the produced liquids from theseafloor more than a mile (1.6 km) tothe FPSO. If these pumps lose their primeduring startup, they can undergo consid-erable damage up to and includingdestruction. Accordingly, arrangementswere made in the design to remove asmall amount of dead oil from theFPSO’s storage tanks and send it backto the seabed to maintain the prime onthe subsea pumps. While this is an effective solution as far as the pumps are concerned, any dead oil used for thispurpose must be carefully metered so it isnot counted twice. A total of 20 alloca-tion meters (M) are used throughout theprocess to keep track of the various liq-uids and gases as they travel through themaze. At the final stage are the fiscalmeters (FM) that measure the crude oiland gas that is leaving the FPSO. Fuelgas is considered to be consumed in the process and is not required to passthrough the fiscal meter.

Turret—The internal turret is the keycomponent linking the subsea system tothe FPSO. Built by SBM, the turret is amarvel of engineering. Occupying

FM

Hull Tanks

Export FM

M

Gas/A/BW

FM

Ostra Gas

Ostra Oil

Abalone

BW1

BW2

ON1

ON2 Swivel

Turret Topsides

Ostra

ON

BW/A

M

M

Prod.WaterTreatment

M

M

M

M

M

M

Gas Injection

M

M

M

M

M

M

P

R

O

C

E

S

S

M

M

M

MFuel Gas

M

2nd St.

2nd St.

2nd St.

Topsides processing schematic. (Image courtesy

of Shell)


about 20% of the bow space of theFPSO, the turret accepts all productionfluid that enters the vessel from theseabed modules. It also transmits allpower, hydraulic pressure, and databetween the FPSO and the subsea system using a series of highly complexumbilical conduits. Because the FPSOmoves with wind and current and theseabed modules are stationary, the tur-ret contains swivels that allow the FPSOto “weathervane” 360° as needed.The swivels are configured with an“over-pressurization” system to preventexternal leakage, and a leak recoverysystem to contain any hydrocarbon thatbypasses the swivel seals.

The turret acts as the upper terminus ofthe steel lazy-wave risers that carry pro-duced fluid from the seabed (or act asconduits for dead oil circulation) andthe umbilicals that control the subseamodules and wellheads. A total of 21riser and umbilical slots are containedin the turret. Some FPSOs, notablythose located in hurricane- or iceberg-prone seas, have “quick-disconnect”features so the FPSO can sail away tosafety in the event of an approachinghazard. Fortunately, neither hurricanesnor icebergs plague the seas off thecoast of Brazil, so this feature was notdeemed necessary.

The turret is also the upper terminus ofthe nine mooring lines. Three clustersof three lines each spaced at 120°intervals run from the turret down tosuction pile anchors driven deep intothe seabed. Mooring lines are combi-nations of chain and polyester rope.Polyester rope has been proven to bean excellent mooring material. It is notsubject to corrosion or rust like steelcable is and it is almost neutrallybuoyant in water, thus it does not addweight to the vessel or detract from itsvariable deck load capacity. The turretis equipped with numerous sets ofwheels, called bogies, that run ontracks surrounding the turret and allow360° movement of the FPSO as it

weathervanes due to the effects ofwind and/or sea currents. The multi-bogie design prevents axial andradial movement of the turret whileevenly distributing the weight of the ris-ers and mooring lines to the hull of theFPSO so there are no high-stress pointsno matter which direction the ship’skeel happens to be pointing at thetime. Offloading of crude is carried outby traditional shuttle tankers that con-nect to the FPSO using flexible transferhoses over the stern of the vessel. The FPSO mooring is suffi-ciently robust to moor the shuttletankers during crude transfer.

Because of occasional episodes ofslug flow, it is possible for a high pres-sure surge to hit the turret. To protectagainst a possible dangerous over-pressure condition, the turret manifold isequipped with a high-integrity pressureprotection system (HIPPS) that senses if


The turret is the “cornerstone” of theFPSO. It is the point through which allproduction, communication and moor-ing between the subsea system andthe FPSO must pass. The swivel stacktower atop the turret allows produc-tion, recirculation, hydraulics, powerand communications lines to maintain100% integrity while the vesselswivels with the wind and sea current.(Image courtesy of SBM Offshore)


turret pressure rises above safe limits(300 psi) and automatically opensvalves that blow down the riser pres-sure to prevent high-pressure fluid fromentering the turret swivels that are notrated to withstand high pressures.

Accommodations aboard the EspiritoSanto are designed ergonomically socrew members can get the rest, recre-ation, and nourishment they need tooperate safely and at peak efficiency.A maximum of 100 persons can beaccommodated in one- or two-bed

cabins, although normal crew strengthis 75 persons. A large galley and messarea is provided as well as TV loungesand a gymnasium. A hospital and treat-ment room has been included for crewsafety and health.

Safety firstThe central control room controls allonboard and subsea operations includ-ing offloading of production. Videocamera monitoring gives control roompersonnel a view of all critical areas ofthe vessel and topsides. The blast bulk-head that separates the crew area fromthe rest of the ship has been raised toan A60 rating, and a safety zone hasbeen established to the aft-most top-sides modules on deck. Sufficient lifeboats exist to accommodate the entire

crew, and there are strategically placedlife rafts around the ship also capableof accommodating the entire crew.Safety stations equipped with breathingapparatus, first-aid kits, and defibrilla-tors are also strategically located. Abuddy system ensures that no crewmember enters a hazard area without apartner to help or observe the activity.A helipad overhangs the ship’s stern.Although gas flaring is not anticipated,there is a flare stack amidships to beused in an emergency.

Mooring While the FPSO was being readied forits role in receiving and processing BC-10 production, a geoscience teamfrom Shell, SBM, and Fugro Geocon-sulting was carefully studying the BC-10 seabed data for the optimumplaces to embed the anchors thatwould moor the FPSO in place. Anchordesign has evolved greatly since thetraditional anchor-shape seen on theuniforms of naval personnel. In fact, theanchors used to moor floating drillingand production vessels do not resemblethose traditional anchors in the slightest.

The team used data from a combina-tion of piezocone penetrometer tests,jumbo piston cores, gravity cores, andside-scan sonar to analyze the seabed.They discovered that the entire areawas quite complex, the result of mas-sive sloughing off the continental shelf.Unlike oil and gas prospectors, theywere looking for very low permeability,uniform sedimentary sections; ones thatwould accept the anchors and main-tain the suction. Instead, they encoun-tered mixed geology containing severallarge rock masses “floating” in a sea offailed sediment. The plan was to try toidentify and locate these masses sothey could be avoided. It would be liketrying to drive a tent peg and encoun-tering a boulder just beneath the sur-face. Because of the turbiditic nature ofthe area, development of a predictivesoil model was undertaken by the teamfor the optimization of the mooring


The massive turret with its swivel stacktower on top dominates the bow section of the FPSO, and provides full,360-degree weathervaning for the vessel. (Photo courtey of Shell)



anchor locations. The model wasbased on the integration of the geo-physical survey and the geotechnicaldata in an area characterized by com-plex and discontinuous sand stratainterbedded with clays. The procedurethey employed was quite robust andthe nine anchor locations that werechosen performed as expected duringthe installation of the anchors.

Modern anchors intended for perma-nent mooring of vessels are called suc-tion piles and look like long cylindersopen at the bottom and closed at thetop. On the top there is an openingwhere a suction hose can be attached.

A length of anchor chain is attachedabout 20 ft (6 m) from the bottomend. During deployment, the anchor

A geoscience team from Shell, SBM, andFugro Geoconsulting carefully studiedthe BC-10 seabed data for the optimumplaces to embed the anchors that wouldmoor the FPSO in place.

A topsides module is lifted by afloating crane ready to be placedon the FPSO’s top deck. (Photo courtesy of Shell)



cylinder is suspended vertically on a cable and lowered to the seafloorby a special anchor handling vessel(AHV), with the open end down. The cable is slacked off, allowing theanchor to penetrate the seabed of its own weight. Once it stops, aremotely operated vehicle from theAHV attaches to the suction hose andstarts to pump out the water frominside the anchor, creating a vacuumcondition inside that literally sucks theanchor deep into the seabed. Depthvaries depending on the strength ofthe seabed; on the BC-10 project, thetips of the anchors reached between52 and 57 ft (16 and 17.5 m) belowthe mudline. The anchors planned forthe BC-10 installation were 16.5 ft-in-diameter (5.0-m) steel cylinders with a wall thickness slightly greater than 1 in., so they were quite massive.Anchors were set a good eight monthsin advance of the arrival of the FPSOand allowed to stabilize. Two weeksbefore the FPSO’s arrival, polyestermooring lines were attached to theanchor chains. The top end of thepolyester line was buoyed off, waiting

the arrival of the FPSO. Ultimately,another length of anchor chain waslinked to the top end of the polyesterlines. This upper chain was used tolock the mooring lines to the turret.

When the FPSO arrived, the AHVassisted in capturing the upper ends ofthe mooring chains and attaching themto their respective mooring sockets onthe bottom of the turret.

The Espirito Santo arrived in Brazil on Dec. 15, 2008, a short 25 months after project sanction. It sailedunder its own power from Singapore,a journey of some 9,000 nauticalmiles, and was finally moored on station in January 2009. Pull-in andconnection of the risers and umbilicalsfrom the subsea modules commencedimmediately. Through the excellentcooperation of Keppel Shipyard, SBM,and Shell, the project recorded 8.5million consecutive man-hours withouta lost-time incident. A total of 50major lifts amounting to more than22,000 tons were conducted to complete the conversion. n

100 200 300 400 500 600Offset (m):

2.3550

2.3600

2.3650

2.3700

2.3750

2.3800

2.3850

2.3900

EW

UPPER SAND SUBUNIT(SAND LENS ~0.75 m THICK)

~3.8 m

RAFTEDMTD BLOCK(SOIL BERG)

PARALLEL-LA YERED UNIT(CHIEFL Y STRA TIFIED CLA YS)

MTD UNIT(Mass T ransport Deposits;chiefly remolded clays with

some thin, discontinuous sandsand erratic shear strength profiles)

Notes:1.2. All depths and thicknesses are approximate and assume a speed of sound in sediments of 1,525 m/sec.3. Amplitudes above a relative value of 10,000 are displayed in to highlight the inferred presence of sands.

The high-amplitude seafloor also appears yellow .

All materials are inferred.

yyeelllloowwPortion of subbottom profiler line MG19.03

INTERBEDDED UNIT(CHIEFL Y CLAYS WITH

DISCONTINUOUS SANDS)

LOWER SANDSUBUNIT

TWO

-WAY

TRA

VEL

TIM

E BE

LOW

SEA

SU

RFA

CE

(s)

SEAFLOORHUMMOCK

SEAFLOOR

The seabed near proposedmooring sites was characterizedby permeable sand streaks andmass transport deposits, makingsite selection critical. (Image courtesy of Shell)


The huge turret module palls in comparison tothe gigantic crane, lifting its load for insertioninto the forward section of the FPSO hull. (Photo courtesy of Shell)




A ‘SUBSEA CITy’ RISESON ThE SEAFLOORMost of the BC-10 construction was

conducted onshore in Brazil.

Like the dream of Jules Verne’s intrepidCaptain Nemo, a virtual city was builton the seabed between 2007 and2009. Unlike Nemo’s fantasy worldthat was built subsea, most of the BC-10 construction was conductedonshore in Brazil. Starting with thebright yellow wellheads designed andmanufactured by FMC, seabed mod-ules were built and installed accordingto the field development master plan.Much of the work was conductedsimultaneously with drilling operations,so every step had to be carefullyorchestrated and coordinated.

For example, risers and mooring linespre-laid on the seabed had to be laidin reverse order of their scheduled

hookup to the FPSO so they would notbecome entangled with each other. Amyriad of pipelines, flowlines, andjumpers had to be laid to connectseafloor elements as well as to tie backto the FPSO. This activity had to becarefully designed and coordinated toprevent delays in the schedule, orworse, interference with other lines. TheBC-10 field water depth is beyond thereach of divers, so any required manip-ulation had to be conducted usingremotely operated vehicles (ROV) con-trolled by technicians on the mothershipusing joysticks and closed-circuit televi-sion cameras. Although the water isfairly clear, even with the high-intensitylighting systems of the ROVs, visibilitywas limited. Usually, each vessel oper-ates its own ROV, but at BC-10 theteam spirit prevailed, and different con-tractors provided ROV support to otherswhose equipment was temporarily

down for maintenance. This coopera-tive effort prevented major delays.

Pipelines, flowlines, and risersA network of pipelines connected thevarious wellheads to production mani-folds and then to the artificial lift mani-folds (ALM) that would separate andboost the produced fluids to the surface.Altogether, Phase I called for 10 flow-lines, seven risers, one gas exportpipeline, 15 pipeline end terminations(PLET), and four manifolds with 25 rigidsteel jumpers. All lines were fabricatedin Brazil and transported to the BC-10field for installation. Lines ranged from 6to 12 in. in diameter. Some werecoated to provide thermal insulation.The water temperature at extreme depthsis near freezing year-round, and thecold can cause unwanted precipitates,such as wax and hydrates, to form andclog the lines. In all, more than 94 miles

Field pipeline, flowline, and riserschematic includes proposedlayout for Argonauta O-North tobe completed during Phase 2. (Image courtesy of Shell)

Subsea Production



(150 km) of pipe was installed in PhaseI to connect the subsea modules and thefloating production storage and offload-ing (FPSO) vessel.

On the seabed, flowlines connect thevarious modules. The most extensive net-work to date is on Ostra, where two pro-duction manifolds are capable ofaccommodating four wells each. Initially,Ostra was developed using two clustersof three wells each. Each cluster wasserved by a production manifold (PM).Recently, it was decided to drill an addi-tional (seventh) well on Ostra, so havingthe extra PM capacity has proven to befortuitous. The seventh well, which hasjust been completed, is associated withwells 1, 2, and 3, and is tied in to theirPM. The Ostra PMs are a little more thana mile (1.6 km) apart, and are linked bytwo insulated flowlines. Besides trans-porting produced oil between the PMs,they permit hot-oil circulation duringstartup to free up the viscous crude andget it moving.

The PMs are connected by jumper linesto the huge ALMs that will separate the crude oil and water from the gasand sediment before boosting it up tothe FPSO.

Argonauta B-West is a smaller versionof Ostra, having only a single ALMand no PM to handle production fromits two wells. Lines from the subseawellheads go directly to the ALM at B-West. With only a single well,Abalone connects directly to the OstraALM via two 9.5-mile (15.2-km) flow-lines. Dual lines are used to permit hotoil circulation.

On all deepwater subsea field devel-opments, flow assurance is a major

concern. Scale, wax, hydrate, andasphaltene deposits can clog lines overtime, curtailing production or cutting itoff altogether. Installing a flowline net-work that allows circulation is a practi-cal step to keep the wells flowing.Maintaining the flow lines’ temperatureand pressure is the best protectionagainst flow assurance hazards. Injec-tion of chemical inhibitors to the flow-stream is also an effective techniqueagainst many of these problems.

Risers

The most challenging part of the pipingpart of the project was the design, con-struction, and installation of the risers.Three riser options were studied inpreparation for the BC-10 project: steelcatenary risers (SCR), steel lazy-waverisers (SLWR), and flexible risers.While flexible risers were preferred,largely due to considerable experiencewith this type offshore Brazil, there wasno way the flexible pipe manufacturerscould meet the delivery requirements,so they were ruled out. SCRs descendin a natural catenary arc from the float-ing production facility to the seabed.As the vessel heaves in the sea swells,the landing point of the catenarybecomes an area of some fatigue and

abrasion, and this was deemed unde-sirable. The SLWR includes buoyancyelements installed near the bottom thatcompensate for vessel motion andreduces riser wear at the touchdownpoint on the seabed.

In addition to fatigue at the touchdownpoint, the designers had to worryabout vortex-induced vibration (VIV).This phenomenon can be likened to the humming one hears as wind crosses high-tension lines or suspensionbridge cables. Meandering subsea currents can set up sympathetic vibra-tions in long risers that can actuallydestroy them over time. The traditionalway to mediate VIV is to attach fin-likestrakes to the riser that break up the vortices as the currents pass, thusdampening the vibrations.

Lastly, the designers had to considerinterference between adjacent risers andumbilical clusters as they approachedthe tight confines immediately beneaththe turret. They had to include cathodicprotection systems to forestall rusting orelectrochemical corrosion.

Another critical point in riser design is theupper terminus, where the riser attaches to

SLWR profile illustrates how buoyancyelements mitigate riser motion caused by wave action at the surface. (Image courtesy of Shell)



the FPSO. At this point all tension is trans-ferred to the turret, but riser flexure and lat-eral movement must be controlled as well.Long guides called I-tubes help workerspull the risers into position. First a heavysteel cable is threaded down from thepull-in winch on top of the turret throughthe I-tube. This cable will connect to theshackle at the riser top to reel them in.

The risers were assembled into “stalks” ofpredetermined lengths by Subsea 7 at itsUbu base on the Brazilian coast. Thejoints were specially welded using apulsed TIG process that produces ductilewelds, and thoroughly inspected using360-degree ultrasonic testing apparatus.Once the welds were certified, the pipewas coated with various types of insula-tion and/or corrosion protection mate-rial. The complete riser fabricationprocess comprised 11,000 welds andconsumed 15 months. When it was timeto install the riser, enough stalks to makeup a complete riser assembly werespooled onto a reel aboard the SevenOceans installation vessel. The stalkswere welded end to end, inspected,and the welded areas coated as theywere reeled onto the ship; so at the con-clusion of the process, a complete singleriser assembly was spooled onto the reelready for deployment at sea.

After sailing to BC-10, the SevenOceans vessel began the installationprocess. First, the subsea (bottom) endof the riser was connected to its PLETmodule onboard the vessel. The riserwas spooled into the sea and the PLETwas positioned adjacent to its ALM onthe seabed; then the remaining riserwas carefully spooled off and laid onthe seabed ready for attachment to theFPSO. Great coordination was requiredso the risers would be laid in reverseorder to their pull-in schedule so theywould not become tangled. Although acomplete pre-lay was planned, onlyhalf the risers were actually pre-laid; theremainder were attached to their PLETsand pulled in to the FPSO in a series ofcontinuous operations.

A pull-in shackle had already beenattached to the top end of the riseralong with a riser clamp and flex jointthat had also been attached a precisedistance from the riser top. While thesteel pull-in cable was being deployedthrough the I-tubes, the Seven Oceanssnared the riser shackle from the pre-laid

riser lying on the seabed and pulled it upward, suspending the riser justbeneath the FPSO. An ROV from the Seven Oceans made the final connection of the pull-in cable to theriser shackle and the Seven Oceansreleased the riser top. Next the pull-inwinch aboard the FPSO goes to work, pulling the riser up slowlythrough the I-tube until it can be hungoff in the hangoff collar that supportsthe axial load. The riser clamp is actuated by divers, clamping the risertightly to the I-tube, thus preventing lat-eral movement as the ship pitches andyaws in the ocean swells. Any remain-ing motion is absorbed by the flexjoint. The final step is to remove thepull-in shackle from the top of the riserand plumb-in the riser to the swivelmanifold in the upper part of the turret.The pull-in winch rides on a track ontop of the turret so it can be positioneddirectly over each I-tube to pull in therisers and umbilicals one at a time.

Assembled riser being reeled ontothe Seven Oceans installation vessel. (Photo courtesy of Shell)

A PLET is attached to the lower end of theriser and is lowered into position adjacentto its appropriate subsea module. (Photo courtesy of Shell)



The complexity and precision of the riser installation sequence is hardto describe. The intense dedication and cooperation of the Subsea 7,SBM, and Shell personnel resulted in a near flawless installation. The meticu-lously orchestrated sequence wasrepeated over and over until all risersand umbilicals had been safely pulledin to their I-tubes and hung off. A finalstep remained for the Subsea 7 crews to install the short steel jumpersconnecting the PLETs to the ALMs.These were installed at the rate of one per day until all 25 were succ-essfully landed in place. The entirepipeline/flowline/riser operation con-sumed nine months, most of which was accomplished before the EspiritoSanto arrived on station.

One of the last risers to be hooked uplinked the FPSO to the 5.5-mile (9-km)gas injection line that terminated at the gas injection well near the Ostracomplex. The well had been previouslydrilled into a deep aquifer downdip of Ostra that would serve as temporarystorage of the gas until the Petrobraspipeline has been completed. In antici-pation of that event, a 6-in. line 25miles (40 km) long had been laid fromthe FPSO to the approximate junctionpoint. The two lines are expected to belinked in late 2010, whereupon pro-duced gas not used in operating theBC-10 production facility will beexported for sale.

Umbilicals

Umbilicals are analogous to the humanspinal cord, transporting virtually allpower, command, and control func-tions to the subsea modules. Throughtheir complexity they simplify the instal-lation and operation of the myriad con-nections required between the FPSOand the various subsea operations.Most umbilicals are unique becausethey are designed to supply specificfunctions based on the requirements ofeach field. However, they have certaindegrees of commonality. At BC-10, the

umbilicals serve four main roles: con-duct high voltage power to operate the subsea booster pumps, transporthydraulic power to operate subseavalves, supply chemicals required forthe prevention of corrosion and solidsformation, and serve as two-way con-duits for hundreds of command andcontrol conductors, including high-bandwidth fiber-optic cables.

Designed jointly by Shell and Ocean -eering International and manufactured

by Oceaneering in its Panama City,Fla., plant, the BC-10 umbilicals are built with an inner core containingelectrical power and command con-duits, surrounded by an outer sheath of hydraulic lines. Shell’s Sean Eckerty,umbilicals team leader, explained, “Thehigh voltage cables were manufacturedin Cali, Colombia, and the super-duplex tubes were manufactured in theCzech Republic. It is a credit to theintense collaboration and coordinationof the members of the umbilical teamthat all these disparate componentswere delivered on time and on spec to the final cabling facility in Floridawhere the umbilicals were assembled.Bundling all these lines simplifies thelayout of the distribution and controlelements subsea.”

The completed umbilicals are anextremely robust package, strong andresilient, that can withstand thedynamic loading applied to themwhile suspended in 6,000 ft (1,829 m)of water, swaying in the subsea currentsfor 30 years. The main core containsthree trefoil high-voltage power cables:two live ones and a spare. There arealso three communications quads andtwo fiber-optic cables. The white ele-ments are polyethylene fillers intendedto provide mechanical support andkeep adjacent lines from shifting rela-tive to each other. The outer sheathcontains a communications quad and 15 hydraulic tubes (six largediameter tubes and nine small ones)along with additional filler elements.The steel hydraulic tubes actually sup-port the tensile load of the umbilical,

Like giant sea creatures, the pull-incable from the FPSO and the pull-inshackle at the riser top are linkedwith the help of a miniscule ROVunder the watchful eye of a subseavideo camera. (Photo courtesy of Shell)

Riser is firmly secured in the I-tube withaxial load transferred to the turret at thehangoff collar and radial movement constrained by the riser clamp. Bendingmotion is absorbed by the flex joint. (Photo courtesy of Shell)



a key to the BC-10 design, as thecopper conductors of the inner bundlecannot support their own weight when suspended in the water depthsencountered at BC-10. The yellowsheaths are made of a rugged thermo-plastic material that is extruded overthe bundles in the manufacturingprocess. In operation, the umbilicalsare designed to be flooded with sea-water, and all cables are designed tooperate in a wetted environment. Inaddition, each communications andcontrol quad was extensively shieldedagainst inductive interference from thehigh-voltage trefoils.

Manufacturing of 6½-mile-long (10.5-km) umbilicals such as those used atBC-10 is a complex operation, andonly a few companies in the world arecapable of performing the work to thescale and quality required for deepwa-ter offshore applications. The umbilicalsare made in a long rotating cablingmachine containing large reels or

“bobbins” that hold the individualcables that will make up the finishedumbilical. Because the bobbins canonly hold a finite length of cable, andbecause it would only be an incrediblecoincidence if that length coincidedwith the final length of umbilical,splices are required from time to timeduring the manufacturing process. Inthe BC-10 case, three splices wererequired for each power cable. Thesplices must be perfect. They cannot

cause a change in the outside diameterof the cable, and they must have totalelectrical or hydraulic integrity whencompleted. To control the splicing envi-ronment, splicing tents were set up onthe manufacturing floor adjacent to thecabling machine. Eckerty explained theprocedure, “To complete each electri-cal splice, the trefoils were unwoundand the cable ends prepped prior tothe conductors of the spent bobbinbeing brazed to those of the newspool. The insulation and screeningmaterial were reinstated with extremecare. Finally, each splice was sub-jected to rigorous testing to ensure itpassed electrical, hydraulic, andmechanical specifications before thecabling machine was re-started.

A typical steel jumper is suspendedover the side prior to lowering tolink the PLETs to their appropriatesubsea modules. (Photo courtesy of Shell)

Cross section of a typical BC-10 umbilical. (Photo courtesy of Shell)

The umbilicals are stabbed andlocked in to the turret using an inter-face that transfers both tension and bending moment to the turretstructure. (Image courtesy of SBM Offshore)



The cabling machine wraps the cables in a tight helical pattern beforethe application of a thermoplastic outer sheath.”

Like the risers, umbilicals were pre-installed to their respective subsea mod-ules as they were submerged inNovember 2008, the free (upper) endsterminated at a pulling shackle and werelaid out on the seafloor ready for tiebackto the FPSO. Umbilicals have their own I-tubes to guide them into place in the turret. However, the umbilicals terminatemuch higher in the turret than the risers,so they exist in a permanently dry area ofthe turret. Once they are hung off, theconductors, power cables, and hydrauliclines are routed to their respective swivelsin the swivel stack at the top of the turret.Umbilicals are hung in a lazy-wave con-figuration like the risers to allow for therise and fall of the FPSO in the sea.

Subsea hardware

The BC-10 complex looks like a smalltown of bright yellow modules arrayedacross the subsea landscape. First thereare the wellheads, each equipped withsafety shut-in valves and vertical accessfor well intervention services that may berequired later in the life of the field. Flow-lines connect the wellheads to subsea PMwhere produced fluid is measured andgathered for transmission to the ALM.Because produced fluid can contain vari-ous mixtures of liquids (oil and saltwater),gas, and gas condensate, multiphaseflowmeters are required to monitor andmeasure each well’s production. Pressureand temperature are also measured pre-cisely. The flowmeters were supplied bySchlumberger and use the Vx techniquepioneered by Framo Engineering of

Norway. This allows them to measureaccurately a very wide range of flowcomposition and flow regimes fromsteady-state fluid flow to severe gasslugging. Flowmeter data are continu-ously telemetered back to the FPSOcontrol room via one of the umbilicalcommunication lines.

The BC-10 field layout consists of subsea wellheads, pipeline end terminations, production manifolds,and artificial lift manifolds along withall connecting flowlines and risers. (Photo courtesy of Shell)

The 240-ton ALM starts its journey from theFMC fabrication yard. This is the top, orseabed section, that will sit precisely atopthe embedded caissons. (Photo courtesy of Shell)



Subsea trees–Subsea trees were provided by FMC, and were installed using an anchor handling vessel with anA-frame on the stern. A heave compen-sated lowering system ensured that theequipment would not crash-land on thewellhead if an ill-timed ocean swellcame by. The first step was to install atubing head spool (THD) to the wellheadflange. This could be accomplishedeither prior to drilling the well’s lateralsection or after installing the gravel packcompletion. Next, an enhanced verticaldeepwater tree (EVDT) was installed ontop of the THD after installing the uppercompletion package. The flowlinejumper attaches to the THD so if thetree must be removed for any reason,the flowline jumper is undisturbed. The EVDT offers through-bore accessfor wireline or coiled tubing so the wellcan be worked over with the tree inplace. A workover riser can also beconnected to the top of the tree, if nec-essary. For a major intervention or treereplacement, a subsurface safety valveis first deployed into the tubing hanger;then the tree can be safely removed.

Production manifolds–Provided bySubsea 7, production manifolds gatherproduced fluid from several wells androute it to the ALM, where it is sepa-rated and boosted to the surface.Weighing in at 100 tons each, thePMs were deployed from Subsea 7’sSeven Seas work vessel, which isequipped with a 400-ton capacitycrane. The PMs are sited on theseafloor where they can be jumperedto the subsea wellheads, and then,also by jumper, to the ALM. Jumpersare versatile adjustable-length steel conduits that can reach across shortdistances to connect subsea modules.

Artificial lift manifolds (ALM)–Likelysome of the most innovative subseamodules ever conceived, the ALMs hostthe booster pumps that move produc-tion up to the FPSO. The massive ALMsbuilt for BC-10 weighed in at 140 tonsand 235 tons for the Argonauta B-West

Pumped Liquid Outlet

Inlet

h g = Pfriction

Separated Gas (to be blended)

Tall Shroud (with holes at top)

Gas Liquid Interface

Reblending of gas andliquid at pump suction

PUMP

SEAL

MOTOR

Caisson cross-section from Argonauta B-Westshowing gas re-blending ports just below the ESP. (Photo courtesy of Shell)

“It is a credit to theintense collaborationand coordination of the members of the

umbilical team that all these disparate components weredelivered on time and on spec…”—Sean Eckerty, umbilicals team leader, Shell



and Ostra Fields, respectively. But likean iceberg, the visible portion of theALM concealed the massive separationcaissons that lay beneath the seabed.

Control systems–The entire BC-10complex is instrumented, on theseabed, downhole in the wells, and onthe FPSO. All data are transmitted inreal time to the control room aboardthe Espirito Santo. There, experiencedprofessionals monitor production opera-tions 24/7. They are assisted by auto-matic alarms that signal any operatingcondition that is out of establishednorms. All wells and processing mod-ules are equipped with two-level emer-gency shut-down devices. “Two level”means that first the operators receive awarning of an impending problem con-dition. They can implement a proce-dure to mitigate the problem or theycan manually initiate emergency shut-down. As an added safety factor, ifaction is not taken within a specifiedperiod (either time- or condition-based),an automatic shutdown is initiated.

Artificial lift

The artificial lift system employed at

BC-10 is believed to be unique. It hasbeen implemented because reservoirpressure is insufficient to lift the producedfluids naturally to surface. Even if a subsea well may flow naturally, artificiallift may be implemented because it ispredicted that the well will ultimatelyrequire it, and for subsea wells it ismore cost-effective to implement certainartificial lift techniques when the well isconstructed, rather than later in its life.

Caissons–Driven deep into the seabed,the caissons are each more than 300 ft(100 m) long. Each contains a 1,500-hpelectrical submersible booster pump tolift the produced fluid up through the risers to the FPSO. By encasing thepumps in such a long tube, it was predicted that they would not pump off,meaning that the gas liquid contactwould never fall below the pump intake,causing them to lose prime.

The Ostra caissons played a dual role.They had a gas/liquid centrifugalcyclonic (GLCC) separator in the top thatseparated out a large percentage of thegas and routed to a gas riser where itflowed naturally up to the FPSO.

The complexity of the chemical solution can be seen in thisoverview. Potential challenges are listed across the top row, andeach part of the BC-10 productionsystem is described in the left column. Color codes denote the relative risk. (Photo courtesy of Shell)



The GLCC concept was critical to thesuccess of the project. Accordingly, a full-scale pilot was constructed on land andfull simulation tests were run to qualifyevery detail of the caissons. For exam-ple, even the angle of the inlet pipe wasoptimized to complement the initial gasseparation process. By removing the gassubsea, it was believed that the forma-tion of hydrates would be minimized.Also, gas slugging in the liquid riserwould be curtailed. After gas was sepa-rated, the oil and water gravitated to thebottom of the caisson where the pumpcould boost the liquids to surface in aliquid riser. Any fine sand that managedto get past the gravel pack went to thebottom of the caisson where it wassucked into the pump intake and trans-ported to the surface. On most land orsurface-processing operations offshore, a300-ft long (91.4-m) vertical separator isimpractical, but at BC-10 there wasroom to spare, and the long, slender caissons were driven into theseabed with only their tops sticking out to mate with the ALM module. The combination of cyclonic force and gravity separated the gas in the topportion of the caisson, leaving theoil/water mixture to gravitate to the bot-tom where it entered the pump intake.

The Ostra/Abalone complex ALM hasfour caisson separators. The lightAbalone crude is commingled with themedium weight Ostra crude and thegas is separated and transported to sur-face using a dedicated gas riser. Theremaining crude oil/water mixture isboosted to surface. On the ArgonautaB-West ALM, the multiphase producedfluids are separated at the caisson; thenthey are reblended before beingpumped to surface. The reason this is

necessary is due to the high viscosity ofthe oil phase. By reblending the oil,gas, and water, viscosity control can bemaintained for the 5.5-mile (9-km) tripthrough the Argonauta B-West flowlinesto the riser connection on the seabed.Reblending was enabled by a row ofports at the pump intake that allowed aset volume of gas to enter the pump—enough to control viscosity, but notenough to cause the pump to stall. Bymaintaining a constant volume of gas inthe blend, the mixture viscosity can beheld steady, facilitating flow and pre-venting gas slugging.

Each caisson contains a junk basketnear the bottom to prevent large debrisfrom being sucked into the pump. Thecaisson bottom is also profiled to helpsweep fine-grained sand into the pumpfor transport to surface where it can bescreened out. This prevents sand accu-mulation in the bottom of the caisson.

MoBos–Named using a contraction ofthe Portugese words for modular pumps,the “MoBos” are 1,500-hp electricalsubmersible pumps (ESP) located in thelower ends of the caissons. The ESPswere provided by Baker Hughes.Because changing out a subsea pumpis non-trivial, great care was taken toensure that pump operation was opti-mized. Any condition that is known toshorten pump life was eliminated in thedesign. For example, the pumps wereshrouded to force fluid to pass at highvelocity to create a heat-transfer cell thatkept the pumps from overheating. Thedesign is such that pumps can be pulledand replaced, if necessary, using a lightrigless workover vessel assisted by anROV, but every means was taken to min-imize the frequency of intervention.

Pumps are instrumented so they can bemonitored to ensure that both pump andwell performance can be maintained atoptimum levels. They are powered usingvariable frequency drives, so pumpspeed can be adjusted simply by rais-ing or lowering the frequency of theelectrical current.

Production monitoring and controlThe key to operating an integrated pro-duction system effectively is monitoringand surveillance. Almost all problemscan be managed successfully if theyare detected early enough. At the BC-10 complex, Shell has implemented anetwork of temperature and pressuregauges and flowmeters that monitorproduction all the way from downholein the wells to the export lines on theFPSO. The purpose of most of this instru-mentation is to detect the early signs ofcorrosion or blockage caused by thebuildup of scale, wax, or hydrates. It isalso intended to monitor the flowregime to detect anomalies such as slugflow, liquid carryover into the gas line,or gas carryover into the liquid lines. Inthe wells themselves, monitors candetect the early signs of gas coning orwater encroachment from the reservoir.Changes in the gas or water phasefractions are detected by subsea multi-phase flowmeters.

Much of production control falls underthe general heading of flow assurance.At BC-10, flow assurance received anunusual amount of attention. A full-scalesimulator was built onshore to test theGLCC concept separator performanceand process control. The full spectrumof gas and liquid carryover in the risersand flowlines was simulated and stud-ied so that operating strategies couldbe refined, and monitoring systemsdesigned to ensure the systems wereoperating within design norms.

As previously described, the umbilicalscontained steel conduits designed totransport flow assurance chemicals fromthe FPSO to the wells and flowlines.

The key to operating an integratedproduction system effectively ismonitoring and surveillance.


But it was impractical to supply separatelines for each possible chemical treat-ment. Accordingly, the Nalco Co. wascontracted to study the situation anddevelop “chemical cocktails” that couldaccomplish multiple tasks and be trans-ported to the subsea field in a singleline. This task is not as easy as it sounds.

Production is often complicated by multi-phase flow, diverse fluid compositions,and high fluid velocities. Nalco’s chal-lenge was to address three main issues:corrosion and scale inhibition, foaming,and viscosity reduction. But it had to thor-oughly test the chemical-chemical com-patibility as well as the compatibility ofthe chemicals with the myriad materialswith which they might come in contactin the production system. The compati-bility tests had to take into account theextreme ranges of temperatures and pres-sures encountered in the production andprocessing flowstreams to ensure that thechemicals could maintain their potencyunder a wide variety of environmentalconditions, including the high shear andtemperatures of the ESPs.

The results were impressive. At BC-10, the first qualified combination of corro-sion and scale inhibiting chemistry wasinaugurated—a high shear corrosioninhibitor/methanol mix. In addition, thefirst chemical antifoam compound quali-fied for deepwater production that uti-lized subsea separation and boostingwas successfully implemented—a fluo-rosilicone product. Each productionstream required a slightly different treat-ment; in the end, a comprehensivechemical strategy was implemented thatwas both effective and economical.

In addition to chemical flow assurancetreatment, control of flowline and risertemperatures was critical to prevent the formation of hydrates and waxbuildups. Mostly, this was accom-plished by insulating the lines with lowthermal-conductivity coatings. As previ-ously discussed, the subsea separationof gas was a key factor in hydrate

suppression. The time factor had to beconsidered as well. Some productionhad to travel several kilometers to reachthe ALMs and risers and the insulationheat transfer coefficient had to be suffi-cient to maintain liquid temperatureabove precipitation thresholds. Thealternative was a very costly concentricpipe-in-pipe technique, or the employ-ment of electric line-heating elements.In the gas line, the combination of con-tinuous injection of methanol and highflow velocity keeps the line free.

A fine balance was maintained regard-ing liquid carryover (LCO) in the gasline and gas carryover (GCO) in theoil line. As mentioned, a certain levelof gas in the oil was beneficial as adeviscosifier. The gas’ presence alsolightened the load on the ESPs. A mini-mal amount of LCO is tolerable in thegas line as long as it does not causeslug flow. The cure for LCO was main-taining a high enough gas velocity tosweep the liquid from the line.

The recirculation of dead oil providedinsurance against the ESPs losing theirprime, but also brought a measure of sta-bility to the produced fluid flow. Insidethe caissons, pressure gauges monitoredthe gas/liquid level and automaticallyadjusted the pump speed to maintain thelevel within the optimum range. n


The compatibility tests had to takeinto account the extreme rangesof temperatures and pressuresencountered in the production andprocessing flowstreams to ensurethat the chemicals could maintaintheir potency under a wide varietyof environmental conditions.


Drilling the BC-10 development wellsrequired great precision and carefulcontrol of equivalent circulation density. Many drilling records wereset in the process.

The Bc-10 project introduced some sig-nificant well construction challenges.Perhaps the most daunting challengewas drilling successfully extended-reachlaterals through unconsolidated sedi-ments only a few hundred metersbelow the mudline. in fact, each of theBc-10 producing wells was close tothe extended-reach drilling record, andwas pushing the industry drilling enve-lope for wells in water depths greaterthan 3,280 ft (1,000 m). The forma-tion fracture pressure was only a fewpsi higher than pore pressure, soextreme care had to be taken to moni-tor continuously and accurately theequivalent circulating density (ecD) ofthe drilling fluid. Fortunately, technologyexists to monitor and control ecD, butadditional challenges taxed the ingenu-ity of the drilling engineers.

Because the reservoirs lay atop or imme-diately adjacent to salt domes, theywere highly faulted. in addition, post-depositional uplift added considerableundulation to the strata. The combinationof these structural features required inno-vative well design and the use of real-time geosteering techniques to ensure theresulting well bore maintained as muchcoverage in the pay section as possible.The requirement to land the well bore inthe shallow (close to the mudline) payzone required a fairly aggressive buildsection. achieving this can be problem-atic in unconsolidated sediments

because the rock provides little mechani-cal integrity for the rotary steerable sys-tems (rss). Finally, after experimentingwith directional mud motors and differenttypes of rss, the drilling group settled onthe PowerDrive Xceed rss from schlum-berger, a system specially designed fortough drilling environments.


Drilling challengesanD innOvaTiOns

Development Drilling and Completion

Transocean Arctic I is a third-generationsemisubmersible drilling rig normally ratedfor 3,100 ft (945 m) of water. With pre-setmooring and a dry BOP stack it is capableof drilling in at least 7,400 ft (2,250 m) of water. (All images courtesy of Shell)


The drilling objective was clear. Shell’sBC-10 project manager, Kent Stingl,elaborated, “Wells had to be con-structed that would produce at highrates. They had to be completed insuch a way as to minimize the need forinterventions. And they had to contactenough reservoir rock to ensure produc-tion longevity of at least 20 years.”

Success in achieving these goals wouldtranslate into a positive economic sce-nario that could produce the desired prof-itability to justify the investment. It was theconsensus that the only way to reachthese objectives was to drill a few per-fectly positioned lateral well bores extend-ing about 5,000 ft (1,524 m) or more.The actual lateral length depended onthe formation being penetrated and theprofile of the structure where the well wasdrilled. In fact, each of the initial six wellsexceeded the 5,000-ft minimum withone extending to almost 7,700 ft (2,350m). Collectively, the first six Shell BC-10wells were record-setters for extended-reach wells drilled in more than 3,281 ft(1,000 m) of water.

Numerous challenges addressedThe difficulty of drilling high-quality lateralboreholes under the prevalent conditionscannot be overstated. Penetrating thehighest-quality reservoir rocks requiredprecise geosteering technology. The firsttarget to be drilled was the Ostra reser-voir. A total of six wells were drilled,three at a time. A batch technique wasused for maximum efficiency. That is, therig drilled three top holes, then three inter-mediate holes, and finally, the lateral sec-tions. Each well bore was a 3-D designwith the first cluster of three wells drilledfrom one location and the second clusterof three drilled from another locationabout 6,900 ft (2,100 m) to the south-west of the first cluster. The seabed pene-trations corresponded to the plannedlocation of the two production manifolds.

Not only was the batch drilling tech-nique inherently efficient, it also allowedmaximum flexibility for the drilling groupas it was able to apply learnings fromthe well to immediately improve drillingperformance and hole quality on thesubsequent wells in each cluster.

Seeing where you’re going, learning where you’ve beenTo help mitigate the challenges of thedevelopment drilling program, a com-prehensive formation evaluation pro-gram added “eyes” to the drill bit. Thecombination of logging-while-drilling(LWD) conventional coring, and wire-line logging complemented the batchdrilling technique used in constructingthe development wells. Logs and coresfrom the exploration and appraisalwells were thoroughly analyzed andintegrated into the 3-D reservoir modelthat was evolving from the seismicdata. Each additional piece of infor-mation helped the development drillers and subsurface staff, but evenwith a data-rich model, the stakes weretoo high to risk drilling blind. Accord-ingly, bottomhole assemblies includedLWD tools that provided real-timevision of the formations being pene-trated by the bit.

The development of logging programsis not an exact science. Log data aregathered to answer geologists’ ques-tions or to validate their theories aboutthe subsurface. Some questions areknown in advance, others come up inthe course of developing the reservoir.If the information is to be used in steer-ing the well’s trajectory to intersect thehighest-quality reservoir volumes oravoid drilling hazards, it must beacquired in real time. If it is requiredto characterize the reservoir, it can beacquired subsequent to drilling usingwireline-conveyed logging tools.Some data can be acquired throughcasing, so its acquisition can bedelayed until the completion phase.Most, however, must be acquired inopen hole. Often, the well trajectoryinfluences the decision. Wireline toolsdepend on gravity to take them to bot-tom. In highly deviated well bores orhorizontal sections, they must beassisted to bottom by conveying themon drillpipe or pulling them with adownhole tractor. Both are time-con-suming and costly techniques. There is


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The first six Ostra development wells werebatch-drilled in two clusters of three 3-Dwells each.


no set formula for deciding how andwhen to acquire log data; each wellis different, and there is risk involved.

Shell petrophysicist Lee Stockwellexplained, “In the top and intermediatehole sections, we typically ran a limitedLWD string consisting of a Triple Combolog (resistivity, density, and neutron) toacquire basic data. Wireline was keptin reserve for backup in case of a prob-lem, causing gaps in the data. In addi-tion, we used specialty wireline tools toinvestigate questions or opportunitiesseen in the LWD data. These includedModular Formation Dynamics Tester(MDT), Nuclear Magnetic Resonance(NMR), and Check-shot borehole seis-mic logs. We took conventional coreswhile drilling and augmented them byshooting sidewall samples to fill in gaps.

“No clues are overlooked,” said Stock-well. “We’ve been building our reser-

voir database for eight years. If wedon’t need the information immediately,it will be useful later during the comple-tion and production phases. Our well-logging programs are designed toreduce uncertainties. For example, at


Expected Fault @ XX90m MD

Expected Fault @ XX00m MD

DD Instruction: Keep 86.5º to minimize shale High angle down dips – drilling down structure

Faults @ XX94, XX68, XX22, XX85, XX82, XX50m MD

Exit shale at XX77m MD.ROP slight increase. At XX70m DD reached 90º (XX61.5m TVDSS). Sand @ XX80m MD

Actual

Plan

XX31 - XX76m MD – Kept inclination at 86º to minimize shale. Build inclination to 90º due to TVD limit imposed due to OWC.

Geo-Steering – RTGS

Real-time geosteering software wasused to monitor drilling progress andmanage directional changes. It isworth noting that the logs revealedseven major faults where prior seismicinterpretation had suggested only two.

“We’ve been buildingour reservoir databasefor eight years. If wedon’t need the informa-

tion immediately, it will be usefullater during the completion andproduction phases.”– Shell petrophysicist Lee Stockwell


Abalone, our assumption based onearly data was that the field was simi-lar to some we have seen in the Gulfof Mexico with a gas/oil ratio (GOR)of 1,200 and crude oil gravity in the30°API range. However, our logsshowed us that the actual GOR was3,500 and the liquid was not crudeoil, but consisted of high gravity con-densate with a density of 42°API. Thisinformation prompted the decision todrill a gas injection well to dispose ofthe gas temporarily until a gas pipelinecould be laid to shore.

“The exploration seismic data providedmacro-scale information, such as thereservoir top and base. However, thebase data was inconclusive in places,”Stockwell said. “This led to extensivechanges in our evaluation programs,particularly in the horizontal productionsections. We beefed up our LWD pro-gram using Schlumberger’s Scope familyof services. This included the EcoScope

multifunction formation evaluation tool,the PeriScope real-time well placementand boundary mapping service, andthe TeleScope power, telemetry, andcombinability service. Other LWD serv-ices were added as needed, includingthe proVISION NMR tool. The Eco-Scope tool provided a baseline Sigmameasurement that will be extremelyvaluable as a benchmark for produc-tion logging programs performed laterin the life of the reservoir.

“Drilling unconsolidated sediments isparticularly challenging becauseabrupt directional changes are difficultto make,” Stockwell explained. “Weused Schlumberger’s Xceed RSS tool,which uses the point-the-bit principleand steered it using information fromthe PeriScope deep-reading propaga-tion resistivity device. This tool is ableto see 15 to 18 ft (4.5 to 5.5 m) radi-ally to give the driller early warning offormation changes or drilling hazards.


Zone 1 : 2469 m to 2600 m MD- Mid-Mio-Marl to Top Olig- Steering Ratio: 40%-60%- Average DLS: 3.7- ROP: 45 m/hr

• Mid Eocene to Top Maas Shale• Steering RATIO 20-50%• Average DLS = 2.4• ROP:42 m/hr• Severe Losses crossing Flt

Zone 2 (Hard Steering): 2600m to 2920m MD- Top Oligocene to Top Eocene- Steering Ratio: 80%-100%- Average DLS: 2.8- ROP: 25 m/hr

Drilling and steering efficiency canbe evaluated by superimposingactual directional drilling parame-ters onto the seismic section. Byunderstanding what works andwhat does not work, drillingparameters can be optimized forsubsequent wells.


For example, there was a remarkableincrease in the number of actual faultsencountered during drilling comparedto those anticipated from seismic inter-pretation. In later wells, we were ableto use the new PeriScope Ultra thatcan see up to 66 ft (20 m) radiallyinto the formation. Because of theunconsolidated pay sections, wedidn’t want to implement aggressivesteering to try to achieve 100% cover-age. We elected to take a conserva-tive approach guided by the logs toconstruct an optimum well path thatwould deliver the production resultswe wanted upon completion.”

As drilling progressed, cumulativeknowledge and experience combinedto improve drilling efficiency, narrowingthe gap between planned and actualdrilling days. With non-drilling NPTremoved, drilling of the second Ostrawell cluster experienced a 30%improvement in drilling efficiency com-pared to the first cluster.

Innovations add spice to a traditional approachThus, a typical well construction sce-nario included the following. First, 36-in. conductor pipe for each well wasdriven into place on the seabed withpositioning governed by the proposedsubsea production manifold layout.Depth of the conductor pipe wasabout 165 ft (50 m). A novel tech-nique was used by Intermoor to installthe conductor pipe. The assembledconductor was transported to a loca-tion above the proposed well siteusing a flat barge towed by a tug-boat. A hydraulic hammer wasattached to the top end, and the ham-mer was attached to a chain/cablearrangement that was connected to adynamically positioned anchor-han-dling vessel (AHV). The AHV wasequipped with a remotely operatedvehicle (ROV). After the AHV posi-tioned itself directly above the pro-posed well site and held its station,the tugboat pulled the flat barge out

from under the conductor, allowing itto fall into the sea and swing like agiant pendulum until it stabilized in thevertical position. The AHV then low-ered the now vertical conductor to theseabed, whereupon the hammer wasactivated to drive the conductor intothe seafloor. Meanwhile, the ROV wasdeployed to attach itself to the conduc-tor to help measure and maintain verti-cality as the conductor was drivenhome. This technique demonstrates thevalue of using the batch constructionscenario; all three conductors wereemplaced before the drilling rigarrived on location, so they were


Typical Ostra development wells followed this design.


ready in advance. No rig standbytime was required while conductorswere emplaced. The operation was aworld’s first for deepwater.

Next, the top-hole section was drilledusing a 12¼-in. bit and 17½-in.under reamer. This was not the originalplan, but was decided after difficultiesin achieving the desired dogleg in the soft, unconsolidated formationswere experienced with the first wellusing a mud motor and bent sub tobuild hole angle.

The final bottomhole assemblyincluded the Schlumberger Xceed RSS

in conjunction with the Halliburton XR-reamer, and this combination provedextremely successful, allowing penetra-tion rates (ROP) to be increased by afactor of three, thus reducing sectiondrill-time by half compared to the mudmotor technique. In addition to fastdrilling rates, hole quality was clearlyimproved with a smoother trajectorythat contributed to higher casing run-ning speeds and fewer casing prob-lems. It has been proven that tophole quality is a major factor affectingthe ability to reach extended lateraltarget depths.

The top holes were drilled and casedto about 8,528 ft (2,600 m) measureddepth, or 8,200 ft (2,500 m) verticaldepth, below the rig rotary table. Thetop holes were cased with 133⁄8-in.casing cemented back to approxi-mately 6,200 ft (1,900 m). Waterdepth at Ostra averaged 6,180 ft(1,884 m), so this means that the topholes bottomed out about 2,020 ft(616 m) true vertical depth below themudline (seabed).

Less is moreAnother first recorded on the BC-10project was the successful drilling andcompleting of all wells using a third-generation semisubmersible rig, theTransocean Arctic I. For each drill site,a pre-laid mooring system had beenemplaced to position the rig preciselyover each cluster of wells, greatlyreducing rig-up time. The use of a third-generation floating rig set a worldrecord for mooring and drilling at thiswater depth and was enabled by thedecision to use a surface blowout pre-venter (SBOP) stack and a high-pres-sure riser with an internal diameter of14½-in. Using a batch technique, threeproduction wells were drilled and com-pleted as horizontal, gravel packedsubsea oil production wells. It was thefirst time an SBOP system wasdeployed from a floating drilling vesselfor development drilling and comple-tion. At the mud line, a seabed isola-

tion device (SID) provided the means toshut in the well in case of an emer-gency The primary activation techniquewas with a through-water broadbandacoustic link, backed up by a controlline umbilical strapped to the outside ofthe riser. Accumulators on the SID thatpowered the rams were kept fullycharged from the surface using ahydraulic link built into the umbilical.An electrical link kept the SID’s batter-ies fully charged as well. Not only didthe SBOP system double the waterdepth capacity of the rig to more than6,000 ft (1,829 m), but together withthe pre-set mooring system, it enabledthe rig to move onto location and com-mence normal drilling operations thenext day.

Several innovations were added to provide safe and efficient means of configuring the rig for whichever opera-tion was scheduled. A new hoisting sys-tem was installed on the rig so the SBOPcould be quickly moved on and off well-center, depending if the rig would bedrilling or performing completion activi-ties. And a spacer spool the same heightas the tubing head spool was added tothe SBOP system. This kept dimensionalconsistency between drilling and com-pletion operations. Both systems couldbe installed using a heave compensatorand could be latched and unlatchedusing an ROV. The SID contained a setof shearing blind rams and a set of 75⁄8-in pipe rams.

Practice makes perfectTo ensure rig crews were fully comfort-able with the SBOP system, severaltraining simulation drills were held. Acolor-coded warning hierarchy wasdeveloped with each set of potentialconditions of sea state and offsetdefined. Green defined normal oper-ating range, followed by yellow,orange, red, and emergency discon-nect. During the drilling of the firstOstra cluster, foul weather necessi-tated a planned disconnect. The dis-connect operation was conducted


The use of the surface blowout pre-venter (SBOP) or dry stack allowedthe drilling rig to double its waterdepth capability, and is the first timea dry stack has been used for bothdrilling and well completion.”


and reconnect established with mini-mal problems. As a result, the rig crewwas confident that it could efficientlymanage an emergency disconnectshould the need occur.

A special, slimbore wellhead housingwas supplied by Vetco from which themain 95⁄8-in. casing would be hung.This wellhead housing had to be slimenough to pass through the 14½-in.riser and hang in the seabed wellheadassembly. No problems were experi-enced with the SBOP for the durationof drilling and completion operations ofBC-10. The result was considerablesavings of both time and money.

Once the top holes were drilled,cased, and cemented, the intermediatesections were batch-drilled to theirrespective landing targets. For a typicalOstra well, a 12¼-in. hole was drilledand steered so as to land nearly hori-zontally in the target formation. Theintermediate sections were cased with95⁄8--in. casing hung back to the slim-bore wellhead housing previouslydescribed. About 1,640 ft (500 m) ofcement was used to set the casing andensure well integrity. A synthetic-basedmud system (SBM) was used in theintermediate sections to optimize ROPand borehole quality. Drilling the inter-mediate holes was a critical step requir-ing top-quality steering and drilling fluidcontrol. During these sections, the wellangle was built at a rate of 4 degreesper 100 ft (30 m) while holding the

mud’s equivalent circulating density(ECD) precisely between the extremelynarrow pore pressure and fracture pres-sure limits. Because such tight controlsover drilling fluid density were main-tained, it was possible to drill the wellssafely with 9.2 ppg mud compared tothe 9.4 ppg to 9.8 ppg mud weightrequirements anticipated, all the whilemaintaining excellent hole cleaning. Inanticipation of drilling the lateral pro-duction sections, the SBM was dis-placed out during the cementingoperation. Special care was taken toclean all SBM from the inside of thedrilling riser so as not to contaminatethe water-based drilling fluid to beused in constructing the lateral sections.

The finishing touchThe final step in well construction wasthe delicate task of drilling and com-pleting the lateral sections. A numberof plan alterations occurred during thedrilling of the laterals based on experi-ences encountered. The initial planwas to drill the lateral sections usingthe RSS to drive an 8½-in. bit and theXR reamer to open the hole to 9½-in.in diameter. Despite formation fracturepressure gradients ranging from 9.8ppg to 10.0 ppg, some moderatelosses were encountered even with 9.0 ppg drilling fluid and ECDs main-tained between 9.7 ppg and 9.8ppg. It should be noted that most, ifnot all, of the drilling decisions at thispoint were predicated on ensuring thesuccess of the subsequent completion

phase. A key success factor in the ulti-mate well performance following com-pletion was the skillful handling of fluidECD to maintain borehole stabilitywhile not contributing to formationdamage. Ultimately, the team wasable to maintain ECD within 0.2 ppgof the fracture pressure gradient—aphenomenal achievement.

Developing the completion scenariosBecause the reservoir rock basicallyconsisted of unconsolidated turbidities,a sand management completion wasdesigned. Halliburton installed 5½-in.wire-wrapped screens, centralized with7¼-in. Spirolizer stand-offs to allow uniform gravel pack placement aroundthe entire screen. The screens weredesigned as stand-alone sand manage-ment media with the gravel pack asadded insurance.

Dowhhole completion techniques and resultsDuring the completion of the first sixOstra wells, difficulties were encoun-tered in placing the gravel pack onthree of the wells. The plan was topump the gravel in two waves. The ini-tial, or alpha, wave was intended tofill the bottom of the lateral sectionfrom toe to heel. The second, or beta,wave would attempt to pack theremaining half of the lateral from heelto toe. Because the gravel pack wasintended as a secondary sand man-agement technique, and primary sandmanagement would be performed bythe stand-alone screens, it wasdecided not to attempt to run costlyshunt tubes to try to improve gravel dis-tribution across the completions.

Premature screen-outs occurred on three of the Ostra wells predicating adetailed root-cause analysis that con-cluded the most likely cause was inad-equate hole cleaning sequences priorto gravel placement. As a result of theroot-cause analysis, for subsequentwells, four changes were made to theconstruction plan:


Another first recorded on the BC-10 project was the successfuldrilling and completing of all wells using a third-generation semisubmersible rig, theTransocean Arctic I.


The drillship Transocean Deepwater Navigatorused for BC-10 exploration/appraisal well drillingunderwent a multimillion dollar conversion toextend its water depth capabilities to 7,218 ft(2,200 m). (Photo courtesy of Shell)



n Raise the density of the solids-freedrilling fluid placed in the open holeslightly to maintain borehole stabilityby keeping the same hydrostaticpressure on the borehole duringgravel pack operations.

n Increase KCl concentration in thedrilling fluid to delay shale imbibition.

n Perform wellbore cleanout opera-tions before drilling out of the inter-mediate section to minimize theopen-hole time in the lateral beforethe gravel was emplaced.

n Minimize or eliminate azimuthal orinclination changes while drilling thelateral section.

The above changes were implementedwhen constructing the Argonauta wellswith clearly observable improvement.

Reservoir management planningPermanent downhole gauges havebeen installed to assist in reservoir man-agement. Over time, it is anticipatedthat reservoir parameters will change.Downhole measurements allow thesechanges to be anticipated and timelyremedial action to be taken to minimizeany potential negative effect. The umbil-ical control lines that service each well-head have the capability of transmittingvital production data in real time to thefield control center aboard the floatingproduction storage and offloading facil-ity (FPSO). They also contain conduitsso flow assurance chemicals can bedelivered to each well as needed tosustain production. The data from eachwell is stored and analyzed in adynamic 3-D reservoir model so theentire reservoir can be managed in a holistic way for production optimiza-tion over its economic life. The FPSO

has many more riser slots than are cur-rently being used. These can accommo-date additional development wells thatmay be required as reservoir conditionschange. Although the wells have beendesigned to minimize the necessity forintervention, the downhole measure-ments will prove to be valuable if suchactions are ultimately required.

Beneficial learningsFor Phase I of the project, six productionwells were constructed on Ostra, two onArgonauta B-West, and one on balone.In addition, one gas injection well wasdrilled in Ostra. A seventh well wasadded to the Ostra scope late in 2009,and this well will be hooked up later in2010. This latter well is a temporarysolution to avoid the necessity of flaringgas. Ultimately, all produced gas will betied back to a Petrobras gas pipelineprojected to be ready later in 2010.First oil from the BC-10 complex wasrecorded on July 12, 2009. As eachwell was drilled and completed, cumu-lative learnings were applied to subse-quent wells, making each operation alittle bit more efficient. n

For Phase 1 of the project, sixproduction wells were constructedon Ostra, two on Argonauta B-West, and one on Abalone.

Unique placement of conductor casinginvolves launching off a flat bargeand suspension beneath an AHV in a giant pendulum motion.


TODAy AND TOMORROWPlans include development of a fourthfield, with first oil in 2013.

The FPSO Espirito Santo has storagecapacity of 1.4 million bbls of oil. It ispresently equipped to process100,000 b/d and 50 MMscfg/d.The ship is 1,086 ft long (331 m) anddisplaces 327,000 tons. The topsidesprocessing unit is comprised of 25 sep-arate modules weighing more than8,000 tons and a 21-slot turret weigh-ing more than 4,500 tons.

To be safe, the FPSO does not produceto storage capacity, rather it is offloadedby shuttle tanker every time it reaches1.0 million bbl. With three of the fourBC-10 fields online, that amounts toabout once every 10 to 15 days. There is a floating flexible offtake linethat enters the sea from the stern of the floating production storage andoffloading vessel, and the shuttle tanker

can grapple it onboard, connect it, and signal the FPSO to start pumping. Fillingthe tanker takes about 24 hours. Sincethe FPSO is designed to weathervanearound the stationary moored turret, thestern is always downwind, allowing thetanker to naturally trail out behind theFPSO while it is loading.

At any time, additional producing wellscan be drilled and linked to unused portson the subsea production manifolds. Infact, well 7 at Ostra has just been com-pleted and will tie to PM-1 there. Reser-voir engineers are monitoring productionand may decide to drill additional pro-ducers or perhaps water injectors toimprove field recovery factors as needed.

Bringing in the fourth field Plans are already under way to developArgonauta O-North, with first oil from thatfield toward the end of 2013. ArgonautaO-North has similar crude to that of its

sister field Argonauta B-West, so the valuable learnings from the B-West devel-opment can be applied to O-North. Preliminary plans call for O-North to beproduced using seven wells producing toone ALM and then traveling about 5.5miles (9.0 km) to the risers and the FPSO.Tentative plans show four seawater injec-tor wells planned for the flanks of the O-North structure. Since the crude oil issimilar to that produced at B-West, it isanticipated that the caissons will be simi-lar and will recombine the gas to mixwith the crude at the pump intake to sta-bilize the flow.

Argonauta O-North is an Eocene-agestratigraphically controlled sandy tur-bidite apron. It was discovered with theexploratory well 1-SHELL-09-ESS. Devel-opment of the O-North field will benefitfrom the facilities installed during Phase1 of the project. n


Fishing activities keep growing in theCampos Basin area. A specific socialcommunication program is in placefrom Shell Brasil to dialogue with fish-ing communities about keeping a safedistance from the operational units.

Sustainable development means that peaceful scenes like this one will not beaffected by hydrocarbon production offshore.(Photos courtesy of Shell)

Future Plans



Shell’s Parque das Conchas(BC-10) project in the ultra-deep water offshore Brazilrequired the expertise anddedication of more individu-als than can be recognizedby name. Congratulations tothe following team membersand all those whose effortsresulted in this successful, historic achievement.

Robert Andringtopsides Lead

David AraujoProject Planning engineer

Wouter Bode completions Lead

Scott CommonsSenior ScM representative

Paul DorgantVenture Manager

Rob Dyerrisk Manager

Sean Eckerty umbilicals Lead

Cid FasanoVenture Services Lead

Jason GageSenior civil engineer

Glicia Gomescommunications associate

James Goodallcontracting

Keshav GorurProduction engineer

Steven GrantSubsea Lead

Robin HartmannWells Lead

Joe HoffmanPFr Lead

Gunner Holmes Senior operations Geophysicist

David Howeoperational readiness Lead

Chris HowellFPSo Lead

Mahmoud KhamissyProject Services Lead

Mark Kiteoffshore coordination team Lead

Steve LaBordeProject Planning engineer

Sada LyerSubsea Systems Lead

Justin Landreneaucost Planning engineer

Jason McNultycontracts Lead

Tom Muirhead hull Lead

Luiz Olijnik Subsea hardware Lead

Suheyl OzyigitWells delivery Manager

Albert Paarkdekam development Manager

Robert ParkerhSSe Lead

Robert Patterson Vice Presidentupstream Major Projects, americas

Tony PhillipsIM Lead

John Rehagecost Planning engineer

Flavio Rodriguesexternal affairs Manager

Olivier Rogaaroperations Manager

Wade SchoppaFlow assurance engineer

Lee Stockwell Senior Petrophysical engineer

Jan Henk VanKonijnenburg Subsurface Lead

Chris Wibner civil/Marine engineer

the Parque daS conchaS teaM

Parque das ConchasAn Ultra-Deepwater Success Story

Jaryl StrongShell Publications Lead

Ray VanNormanShell Publications Manager

Kent StinglProject Manager

Acknowledgements

Shell Acknowledge-05_24_10_Layout 1 5/26/10 2:06 PM Page 49


Delmar 51

Schlumberger 52

FMC Technologies 56

Transocean 58

Oil States Industries Inc. 59

SBM Offshore 60

Multiphase Solutions 61

Baker Hughes 62

Oceaneering 64

InterMoor 66

Bredero Shaw 68

PRofIlesTable of ConTenTs

(Photos courtesy of Shell)

BC-10 Profile TOC_05_24_10_Layout 1 5/26/10 2:09 PM Page 50

Heave compensated landing system minimizes cost, risk, and duration

Delmar Systems Inc. has yet again proven the capabilities of itsHeave Compensated Landing System (HCLS) by expanding itsuse to the South American waters of Shell Brasil’s Parque dasConchas project located in the BC-10 block. The HCLS systemhas been the primary method for the installation and recovery of subsea production equipment at the BC-10 development in water depths upto 6,234 ft (1,900 m). Employing this sys-tem has significantly reduced the cost ofinstallations and demonstrated an effectivealternative to the more costly installation vessels using heave compensated cranes.

The HCLS is specific to anchorhandling vessels (AHVs) and uses a vesselthat is included in the fleet associated withmoored rigs. The Richard M. Currence, an AHV leased to Shell, incorporates an A-frame integrated onto the aft of the vessel, enabling the subsea operations to be a standalone process, independent ofthe rig’s location. This further enhances installation flexibility as well as minimizes rig offline time, resulting insignificant cost savings.

The HCLS is a Shell-patented system composed of a syntacticbuoy assembly, a pendant line, anchor chain, and associated rigging. The subsea hardware is coupled to the buoy assemblyusing a pendant line, which is sized according to package weightand water depth. The buoy assembly is sized such that it maintains positive net buoyancy above the weight of the package, pendantline, and associated rigging weight. Anchor chain is added to thesystem below the buoys, providing the additional weight neededto submerge the buoys and coupling the system to the AHV. Theanchor chain forms a catenary that isolates the vessel motion withminimal weight transfer affecting the buoy assembly. This method-ology provides for the suspension of the system within the water column in a state of equilibrium. The motionless equipment canthen be lowered through the water column and soft landed withthe assistance of an ROV.

Delmar has been working closely with Shell in the develop-ment and operation of the HCLS since 1993 and has currentlyinstalled over 300 pieces of subsea hardware assisted by the

HCLS. This innovative technology has been proven worldwidein water depths nearing the 9,843 ft (3,000 m) mark and withpackage weights in excess of 82 tons. The HCLS is currentlybeing used by Shell to assist in some of the deepest and mostcomplex field developments in the Gulf of Mexico. The HCLS, atpresent, has facilitated the installation of a combination of over25 subsea trees, tubing heads, well jumpers and control systemequipment at the Parque das Conchas location since its introduc-tion into the Brazilian waters in June 2008. The use of the HCLS

in conjunction with the AHV hasallowed for several batch installationswith up to five pieces of subsea hard-ware in a single mobilization. It hasalso provided the ability to installequipment on wells adjacent to therig’s location, minimizing the amountof associated rig offline time typicallyassociated with installations facilitatedby the rig or some larger installationvessels.

Delmar's subsea project group hasprovided engineering, technical, andmanagement support to the BC-10 development. The subsea project group consists of project

management, engineering, operational support, and an off-shore installation team that is unparalleled in its field.

The work at BC-10 has marked another successful campaign in the long track record between Shell and Delmar. Delmar looksforward to continuing to work with Shell to extend the capabilitiesof this HCLS technology. n


Delmar

STRATEGIC TECHNICAL SOLUTIONSFOR SUBSEA INSTALLATIONS

Delmar Systems, Inc.8114 West Highway 90

Broussard, Louisiana 70518Tel: 337-365-0180 • Fax: 365-0037

[email protected]

Paid Sponsorship

The Richard M. Currence is positioned for deployment and installation of two subsea trees using Delmar’s HCLS. (Photo courtesy of Delmar)


Schlumberger overcomes challenging aspectsof Parque das Conchas project.

the parque das conchas project posed a unique challenge forshell and schlumberger: to successfully place nine 1,969- to3,937-ft (600- to 1,200-m) long horizontal wells in the develop-ment’s structurally complex reservoir.

the horizontal well option was chosen due to massive sandsof approximately 197 ft (60 m) thickness, the possibility of com-partmentalization, and the impact of heavy oil on the flow ratesand ultimate recoverable volumes. these issues, in addition tothe ultra-deepwater depth of 5,280 ft (1,610 m), made theprospect of successful well construction a demanding challenge.

“the well configurations included complex 3-D profiles that kickoff from vertical in a riser-less top hole section very close to theseabed, which starts with the challenge of a very unconsolidatedformation,” said santiago Zambrano, schlumberger D&m Drillingservices manager — shell brasil. “the profile continues in theintermediate hole where high turn and build rates are required inorder to land at challenging targets close to horizontal.”

schlumberger Drilling & measurements (D&m) played animportant role in the development and successful drilling operations on the project. “planning, directional drilling, and

measurements/logging-while-drilling services helped in manyaspects of the drilling process to improve performance, andwell placement maximized the productive reservoir penetratedby the wells,” he noted.

specifically, the shallow nature of the field, which occurred2,953 to 3,609 ft (900 to 1,100 m) total vertical depth (tvD)below the mudline, resulted in the need to start the buildup section near the mudline. “building the 171⁄2-in. hole to 40degrees inclination in the initial 1,804-ft (550-m) tvD subseawas found to be very challenging in the soft pliocene andmiocene sediments, which required several changes in thedrilling assembly and procedure,” said Zambrano.

using such platforms as the schlumberger perform* tool kitand petrel* seismic-to-simulation software, drilling and subsur-face data were integrated. “understanding the drilling behaviorof specific formations and the lithology at various depths helpedin the redesign of the bottomhole assemblies (bHas) and wellpaths, refinement of the steering program, and updating of thelwD [logging-while-drilling] requirements,” Zambrano said.

“this demanding project necessitated turning the wells invery shallow, soft sediments,” said alex kletzky, schlumbergerbrasil ioc account manager. “not every tool can do that, butthis was a technical challenge schlumberger was able to meet.”

the successful drilling solution used the powerDrive Xceed*900 rotary steerable system bit 121⁄4 in. enlarging the hole to171⁄2 in. with a reamer above the directional tools. “with thisconfiguration we were able to drill seven top sections, evenreaching 47 degree inclinations at the 133⁄8-in. casing shoe and

geoVISION imaging-while-drilling service.(Images courtesy of Schlumberger)

Schlumberger

Drilling, wireline, anDcementing services makeimportant contributions


EcoScope multifunction logging-while-drilling service.


reducing the drilling time to half when compared with the firstthree top sections, which were drilled with a conventional motorassembly,” Zambrano said.

“The 121⁄4 sections (the buildup section) included challenginghigh dogleg (DLS) requirements and complex lithology amonginterbedded shales, siltstones, and hard limestone layers,” said Zambrano. “That generated different directionalresponses that required additional work by Shell’s geology anddrilling departments and Schlumberger’s drilling engineeringteam in order to achieve a better understanding of the direc-tional performance and formation response to plan the correctdrilling parameters and improve the drilling performance.”

That teamwork, combined with the specific application ofthe PowerDrive Xceed* 900 rotary steerable system for harshrugged environments, were the keys to success that guaranteeda constant DLS generation up to 4.5 degrees/30 m.

Another drilling challenge that Shell and Schlumbergerencountered was the need to land the wells in the approximatedesired targets. “The correct surveying procedure became criticalin order to achieve this goal,” said Zambrano. “We correctedthe drillstring magnetic interference running while drilling with theSchlumberger DMAG* software, reducing the uncertainty of theMWD [measurement-while-drilling] reading in half.”

Induced fracturing, opening of minimum-stress faults, and the presence of high-permeability sands resulted in substantialsynthetic-base mud losses. “Hole cleaning management wasvery important in drilling this section,” Zambrano noted. “Onthis matter, the annular pressure while drilling and equivalent circulating density readings from the arcVISION* array resistivitycompensated tool were very important to the successful drilling,providing confidence to the drilling team of the operational limitsand improving the drilling and hole cleaning performance.

“The high net-to-gross reservoir model predicted from the ver-tical appraisal well and the need for gravel pack sand controlled to a completion interval design with a straight line well pathinclined near 88 degrees for the 81⁄2-in. by 91⁄2-in. reservoir section,” said Zambrano. “This philosophy proved too simplisticand changes to the well trajectories were made.”

For the 81⁄2-in. sections, the Shell operations team and theSchlumberger well placement team worked closely through theplanning and drilling of the last five horizontal wells, constantlyupdating the models and analyzing the real-time data to takeadvantage of all of the available data and minimizing theamount of non-reservoir interval drilled.

A variety of Schlumberger tools were used to improve thewell trajectories in real time. LWD tools used included Schlum-berger’s proVISION* real-time reservoir steering service (miner-alogy and permeabilty), geoVISION* image-while-drillingservice (bit & ring resistivity and resistivity image), PeriScope*bed boundary mapper, and EcoScope* multifunction LWD,which include resistivity, gamma ray, density-neutron, caliper,PEF, sigma, and image services.

The proVISION tool delivers reliable determination of mineralogy-independent porosity, bound- and free-fluid volumes,permeability, and pore size, as well as identification of fluids. Thisdeep-reading tool has a field-proven dual-wait-time capability fordirect hydrocarbon detection. Operating independently of resistivitymeasurements, the tool locates low-contrast, low-resistivity pay.

The answers provided by the proVISION tool may be used tooptimize wellbore length by matching the wellbore’s producibilitycharacteristics to the planned completion capabilities. The toolmaximizes production by drilling the highly permeable zones and avoiding water cut by using knowledge of irreductible watersaturation. The proVISION tool can be placed anywhere in theBHA with no detrimental effects on the drilling operation.

The geoVISION resistivity sub provides real-time high-resolution resistivity images to the WellEye 3-D borehole dataviewer. The WellEye software operates on a personal com-puter at the well site to provide 2-D and 3-D interactive dis-plays of the borehole along the well trajectory. The interpretercan readily visualize the spatial position of log features on thedynamically linked displays.

PowerDrive Xceed rotary steerable system.



The PeriScope bed boundary mapper is revolutionizing wellplacement by providing the ability to see the reservoir as wellsare being drilled, thereby eliminating sidetracks on wells andenhancing production. With the industry’s first deep and direc-tional electromagnetic LWD measurement, the position of theformation and fluid boundaries can be monitored up to 21 ft(6.4 m) away, thereby allowing horizontal well drilling entirelywithin the sweet spot. The deep measurement ranges givesearly warning when steering adjustments are required to avoidwater, drilling hazards, or exiting the reservoir target.

The EcoScope multifunction LWD service integrates the nextgeneration of LWD measurements into a single collar. By runningthe Orion II* telemetry platform, real-time data transmission of upto 120 bps is possible. Multiple real-time images can be seenwithout affecting the high resolution of the measurement curves.And measurement of the formation density without the side-mounted cesium source makes the service the first to offer commer-cial LWD nuclear logging without traditional chemical sources.

“This project marked the groundbreaking introduction ofPeriScope ultra-deep services in its first run for an IOC in Braziland the first run in conjunction with proVISION worldwide, pro-viding a wide, complete set of rock and formation propertieswhich, together with pre-drill, real-time, and post-well modeling

using the Schlumberger RTGS* real-time geosteering software,contributed to minimize the amount of non-reservoir interval penetrated,” Zambrano said. “The well found on average a 10 to 15% higher N/G than the first three wells drilled without it.”

“The modeling and pre-planning of the drilling contributed significantly to the project’s success,” said Kletzky. Those aspectscombined with the close cooperation between Schlumberger andShell personnel during the actual drilling brought good results. TheShell Brasil team provided very active support for Schlumberger onthis project and helped the team learn and perform better.

Schlumberger Wireline plays an integral roleEarly in the Parque das Conchas project, the services of Schlum-berger Wireline were used for formation evaluation purposes on some of the exploration and development wells. “Key petro-physical and reservoir evaluation answers on this field for Shellcame from Schlumberger Wireline tools,” said Eric Englehardt,Schlumberger Wireline IOC Account Manager.

Tools used included the Platform Express* integrated wireline logging tool, CMR* combinable magnetic resonancetool, DSI* dipole shear sonic imager, and the MDT* modularformation dynamics tester.

In 2009, as the project shifted to its gas disposal wells,Schlumberger Wireline was given the task of logging someunconventional openhole tool combinations in order to reducerig time. “A special switch was developed to help make thesecombinations compatible, thereby allowing logging the entirerequested logging suite in one single rigup. We were not forcedto come out of the hole to change tools,” said Englehardt. “Thesuccess of running these tools in this new configuration helpedreduce Wireline rig time by more than 50%, bringing huge savings to the project. With the proper planning and prepara-tion, Schlumberger Wireline has been able to and will continueto support Shell in the delivery of top quality data and efficiencythroughout the life of the Parque das Conchas project.”

Cementing also fulfills an important functionSchlumberger Well Services performed primary and remedialcementing jobs for the wells in the Parque das Conchas block.

“Shell requested a customized solution to adapt Schlum-berger’s Surface Dart Launcher [SDL] to existing casing hard-ware they had chosen,” said Luiz Picone, Schlumberger ClientSupport Engineer. The SDL is part of the DeepSea EXPRES* offshore plug launching system, which also includes a subseatool (SST.)

The SDL contains identical darts launched during cementing.The darts release casing wiper plugs when they reach the SST.Since the SDL is modular, adding segments is simple and thenumber of darts that can be launched can be easily increased.“Using darts instead of a ‘free fall’ ball helps prevent contami-nation, provides positive fluid displacement, and saves time,”said Picone.

Schlumberger


MDT modular formation dynamics tester.


After dart launch, mud flows down the drillpipe, through thesliding sleeve of the SST, and out of the orifices. The dart landson a rod and continued pumping forces the dart and roddown, pushing the plug out of a basket. A spring retracts thesliding sleeve, allowing complete, unobstructed flow throughthe orifices.

A pressure differential resists rapid rod motion and stops rodmovement after plug release. Combined with plug friction, thiscaused increased pumping pressure and provides indication ofplug launch. Spacers prevent plugs from sticking and areretrieved with the tool.

The downhole SST encases plugs inside a basket, eliminat-ing difficulties associated with pumping fluids through the insideof the plugs. Simplified plug design allows use of high-perfor-mance, easily drillable plugs.

“All of the 95⁄8-in. cementing jobs were successfully exe-cuted,” said Picone.

To prevent losses, CemNET* advanced fiber cement wasused in the cement slurry. The inert, fibrous material is capableof forming a network across the loss zone, allowing circulationto be regained and maintained. “Full returns were observed,”noted Picone.

Schlumberger, Shell – a team from the project’s beginningThe association between Schlumberger and Shell on the BC-10project began back in the early 2000s and will continuethrough the next decade.

“Schlumberger took part in the early exploratory work for theParque das Conchas project,” said Kletzky. “We look forwardto working with Shell on the second phase of the project thatwill start in late 2011. Our Schlumberger team members,along with those from Shell Brasil, utilize the best practices in asafe manner to produce the very best project results.” n

* Mark of Schlumberger

proVISION real-time reservoir steering service.


Schlumberger Serviços de Petroleo LimitadaAv. Presidente Wilson 231, 20th floor

Rio de Janeiro, BrazilPhone number: +55 21 3824-6923

www.slb.com

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Enhanced Vertical Deepwater Tree readilyconfigures to project’s specific need.

an award-winning technology by FMc technologies enabledshell’s parque das conchas project to better utilize a deepwaterdrilling rig and will help significantly reduce the amount of pro-duction downtime normally experienced during maintenanceand meter replacement.

FMc’s enhanced vertical Deepwater tree (evDt) has a num-ber of innovative features that provide versatility, installation sav-ings, and operational efficiencies for deepwater projects such asparque das conchas, located in the Bc-10 block offshore Brazil,operated by shell in a joint venture with petrobras and ongc.

Because of its slimbore completion system, the evDt allowsfor deepwater completions from a small drilling rig containing asurface blowout preventer (Bop), thus avoiding the need for anexpensive deepwater rig and subsea Bop system.

“the evDt tree system is an improved design that is moreflexible and standardized and allows for more efficient installa-tion,” said chris Bartlett, FMc product Development Manager.“By having a tree design that is standard in all of the core com-ponents, the system can be readily configured across a range ofoptions to meet the requirements of a particular field. It allowedus to deliver significant added value to shell because they canemploy the same standard tree design anywhere in the world.”

Milton villasboas, FMc technologies Bc-10 overall engi-neering Manager, said, “shell saw significant capeX savings byleveraging the evDt tree design which has been used on theshell perdido project in the gulf of Mexico and shell gumusut

project in Malaysia. since these designs have been used onother shell deepwater projects, the company was able to movefast and at less cost by using a global standard and avoiding thetime and cost to redesign the tree system for different projects.with the synergy at the components/tooling level, less shell proj-ect staff was needed during the engineering phase.”

the new subsea tree, which received the new technologyaward at the offshore technology conference in 2008, fea-tures a number of enhancements. the actuators, seal, and con-nectors have all been upgraded to FMc’s latest standardproduct offering, and the tree features a 135⁄8-in. oD tubinghanger system, allowing interface to the surface Bops.

the tree system also incorporates a retrievable flow controlmodule in place of the traditional insert retrievable choke, whichcan be configured to accommodate a choke as well as a sin-gle or multiphase flowmeter. this allows production downtimeto be cut from a matter of days to a matter of hours duringmaintenance and meter replacement. additional benefitsinclude the ability to shift a tree between production, waterinjection, or gas injection by changing the flow control module.

the evDt also allows for flexibility in installing tubing hangers,permitting a customer to either use a tubing head or to simplyland the tubing hanger directly into a wellhead without the needfor a tubing head. this results in a more efficient installation whencompletion and drilling operations are conducted and does notrequire a customer to retrieve the subsea Bop and riser.

FMC Technologies

InnovatIve technologyproves Its worth


Two gas/liquid separation and ESP boosting modules assem-bled on top of the artificial lift manifold are shown. Two ofthese manifolds were installed in Parque das Conchas.(Photos courtesy of FMC Technologies)

All subsea separation and production equipment for BC-10was manufactured at FMC’s plant in Brazil.


“FMC has a long relationship with Shell in the Gulf of Mex-ico,” said Villasboas. “Our subsea expertise and the seamlesswork environment developed between our companies throughoutthe years have resulted in successful teamwork. We believe that,after evaluating the local industry challenges and capabilities inBrazil, Shell saw that the successful business model created inHouston could be replicated with FMC Technologies do Brazilgiven our local subsea expertise and manufacturing capability.Besides the technologies’ engineering capability, FMC was ableto support Shell in dealing with logistics and other associatedbusiness matters in Brazil.”

FMC’s scope of supply on the project included 10 subseatrees with tree mounted controls rated at 10,000 psi; two subseaproduction manifolds; two subsea artificial lift manifolds (ALMs);six subsea separation and boosting modules; 15 PLETs; 26 rigidjumpers; one completion and workover riser system with interven-tion, workover, and control systems; topsides controls; and subseamounted controls. The subsea system was engineered and manu-factured at FMC’s facilities in Rio de Janeiro.

New technology used on the project included 1,500 elec-tric submersible pumps (ESPs) which were rated to provide sub-sea boosting of up to 2,300 psi.

Also, in the BC-10 Vertical Caisson Separator (VCS) System,the multiphase flow was introduced through a purposefully angledand tangential inlet. “This inlet allowed for smaller caisson diame-ters,” said Villasboas. The separation of the multiphase inlet flowinto liquid and gas components occurs as the stream spirals downinside of the VCS. Centrifugal and gravitational forces cause theheavier elements (solids and liquids) to be thrown outward to theVCS wall and downward to the Caisson Sump (CS). The ESP sus-pended from the ESP Hanger on the tubing pumps liquids andassociated solids from the CS to the Top End Assembly (TEA)flowloops through the Manifold Multibore Interface (MMI) anddownstream through in-field flowlines to the Production Host Facil-ity (PHF). The gas liberated from the multiphase stream rises natu-rally through the annulus created between the outside diameter(OD) of the ESP tubing and the internal diameter (ID) of the VCSinto the TEA flowloop, through the MMI and downstream throughthe in-field flowline to the PHF. The ESP string, TEA, and VCS maybe retrieved sequentially from the permanently installed manifold.

“There were many challenges in this project as it was thebiggest subsea system ever delivered by FMC Technologies inBrazil, and it also included a large portion of new productdevelopment,” said Villasboas. “The early development of theArtificial Lift System contributed to improvement in the projectschedule by enabling managers to order items with long leadtimes and immediately launch into the detail design engineeringat final investment decision (FID). Also, the System IntegrationTesting performed on the Arctic 1 rig enabled identification ofcritical interfaces, anticipation of problems, and avoided rigdowntime during boosting modules installation. This was a verygood practice that will be followed by future projects.”

By utilizing FMC’s subsea separation technology, the Parque dasConchas project became more economically viable. “The field wascharacterized by low reservoir pressure, which made it difficult tobring the hydrocarbons to the surface,” said Bill Houston, ProjectDevelopment Manager. “Subsea separation and boosting is anexcellent option for a low energy reservoir like Parque das Conchas.”

The FMC team in Brazil included 25 project management per-sonnel as well as 60 project management people supported byvarious other departments and plant employees at the FMC Tech-nologies’ facility in Rio de Janeiro. “This has been another success-ful project in the long track record of success enabled by thestrategic relationship between Shell and FMC,” said Villasboas.

And, following in the footsteps of the EDVT innovation, FMCTechnologies’ expertise again will be honored at the 2010 Off-shore Technology Conference with another Spotlight on NewTechnology Award – this time for its Self Configuring MultiphaseMeter. The meter has been rated at 15,000 psi and tempera-tures of up to 480°F (249°C). It also has been designed for useat water depths of 11,500 ft (3,500 m) and performs in multi-phase and wet gas applications. Through the use of 3-D tomog-raphy imaging, the meter significantly improves the measurementaccuracy and range of multiphase product flow. The self-calibratingmeter detects and measures water salinity in combination withother liquids in a flow stream, thus saving operators time andenhancing production knowledge.

Working together since the early 1990s, Shell and FMCTechnologies have successfully developed some of the world’smost challenging projects including Shell’s Mensa project, theShell Coulomb Field, and the Shell Princess Project.

“Shell and FMC have worked together on some of the indus-try’s most complex deepwater projects,” said Jeff Mathews, Shell Global Business Program Manager. “We continue to lookforward to supporting Shell’s projects throughout the globe.” n


1803 Gears Rd. Houston, Texas 77067 Tel: (281) 591-4000Fax: (281) 591-4102

E-mail: [email protected]

“Shell and FMC have worked togetheron some of the industry’s most complexdeepwater projects.”—Jeff Mathews, Shell Global Business Program Manager

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Transocean and Shell used their extensiveSBOP experience when partnering on theParque das Conchas project.

Working closely with Shell, transocean employed surface Bop (SBop) technology while conducting drilling and subseacompletion activities in several parque das Conchas reservoirs in up to 6,316 ft (1,925 m) of water. the GSF Arctic I drilledand completed 12 wells from the start of the campaign onmarch 21, 2008, finishing the project on schedule.

Using a pre-laid wire-and-polyester mooring system, the GSF Arctic I also achieved recognition for setting the Brazilianrecord for the deepest mooring of a mobile offshore drilling uniton the B West, Abalone well, working in 6,316 ft of water.

“over the years, transocean has drilled some 200 wellsusing SBop technology. this project created a great opportunityto work with Shell personnel to develop the unique SBop designfor the parque das Conchas project, building on both Shell’sand transocean’s extensive SBop experience,” said guilhermeCoelho, transocean’s managing Director in Brazil. “this projectshows the value of SBop technology and true teamwork.”

perhaps the most unique aspect of the project was the speciallydesigned SBop handling system in the moon pool of the GSFArctic I. it featured a circular track so that the complete Bop couldbe moved between the storage stump and the well center withoutremoving control hoses. this approach reduced time while mini-mizing exposure and over the side work during SBop handling.

operations also included the first application of a purpose-built16-in. buoyed high-pressure (6,000 psi) riser employing merlin™connections with metal-to-metal pre-loaded seals.

the GSF Arctic I also deployed all the subsea pumping sys-tem components at two flowline manifold locations.

Before the drilling and completion activities, Shell,transocean, and third-party service companies collaboratedclosely to optimize planning, equipment, and performance.

A key aspect of these activities was identifying the mosteffective equipment to support the drilling and completion oper-ations. For example, the triple-redundant subsea isolation device(SiD) control system was configured for optimal performancewith acoustic as the primary control system backed by umbilicaland roV intervention equipment. the SiD consisted of a dual-ram preventer, inverted hydraulically operated riser connector,and a hydraulically operated wellhead connector.

While Brazilian waters are relatively benign, the SBop sys-tem on the parque das Conchas project could still be discon-nected quickly in an emergency, if required.

to further optimize the rig’s performance, the GSF Arctic Iutilized an onboard computer system for Halliburton’s insite Any-where web delivery service. this real-time operations centerenabled Shell to track and optimize the rig’s drilling perform-ance data anywhere in the world through the worldwide web.

the experiences gained on the parque das Conchas drillingand completions campaign will undoubtedly be applied tofuture projects, and transocean and the crews of the GSF Arctic I congratulate Shell and its co-venturers petrobras andongC on a successful project and look forward to the nextopportunity. n

Transocean


4 Greenway PlazaHouston, Texas 77046

Telephone: (713) 232-7500www.deepwater.com

GSF ARCTIC I SetS FirStS inDrilling, CompletionS

Transocean used surface BOP technology in BC-10 drillingand completion activities. (Photo courtesy of Transocean)

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Working with Shell, Oil States Industriesmade significant contributions to the Parque das Conchas project by using proven technologies adapted in new ways.

From oil states industries (UK) ltd. in aberdeen, scotland, camethe 16-in. diameter marine drilling riser that employed the merlinconnector – a connector for use in water depth of up to 7,500 ft(2,286 m) – ideal for parque das conchas’ deepwater environment.

the merlin connector has a low profile that minimizes weightand the subsequent requirement for expensive buoyancy. theweight savings allow lower cost second- and third-generation rigs tobe used in water depths they are unable to achieve conventionally.

“a total of 170 riser joints of 50 ft (15 m) length were sup-plied to X80 pipe specification together with 18 pup joints ofvarious lengths,” said John gallagher, Development manager.“a riser spider together with two connector makeup tools alsowas provided. the spider was fitted with a gimbal to minimizestress in the riser due to vessel motion. all the risers wereshipped in custom-designed frames, each accommodating fourstandard riser joints.”

since the riser needs to be installed and retrieved frequentlywithout suffering any loss in performance of the metal seals that are integral to the merlin connector design, an extensive testingprogram was implemented to demonstrate seal integrity and structural capacity after multiple connector make ups.

assembly tooling for the merlin connector was specifically

designed to maintain orientation with the spider gimbal toallow make up to proceed when the riser was departing at anangle. “weld procedures were specially developed for the project and carried out by the highly skilled work force in ouraberdeen facility. the procedures were validated by full-scaleresonance fatigue testing,” said gallagher.

meanwhile, across the atlantic, the oil states industries inc.group in arlington, texas, adapted its proven scr FlexJoint®technology to accommodate shell’s turret connection system forthe floating production, storage, and offloading (Fpso) vesselfor the parque das conchas project.

“oil states provided scr FlexJoints® and associated riserhang off assemblies to allow flexible interface between thesteel lazy wave riser (slwr) and i-tubes for the espírito santoFpso,” said Jim norris, program manager – projects. “a total ofeight assemblies with five 10-in. production units, one 8-in.service unit, and two 6-in. gas units were provided.”

the use of the turret interface to connect scrs to the Fpsowas one of the challenges on this project, according to norris.“oil states worked with shell during its development to ensure the flexible joint design would interface directly with the turret connection system. our work included geometry constraints, sizing, and engineering to confirm that the loading reacted throughthe connection system would be suitable for the flexible joint.”

he continued, “the close working relationship between theengineering, project management, and material assessment groupsin both shell and oil states allowed us to be proactive in solvingparticular issues that arose during the fast-track developmentprocess. maintaining these core group relationships between companies is an essential element to effectively bringing future projects of this type to a successful and satisfying conclusion.” n

Corporate Headquarters Oil States Industries Inc.

P. O. Box 670 • Arlington, Texas 76004-0670 7701 South Cooper Street • Arlington, Texas 76001

Tel. +1 817 548 4200 Fax. +1 817 548 4250

E-mail: [email protected]

Riser joints for the BC-10 development. (Photo courtesy of Oil

States Industries)

proven technologies overcome new challenges

Oil States Industries

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SBM's innovative riser use opens new deepwater possibilities.

the operations center of the Parque das Conchas project in the BC-10 field is FPso Espirito Santo, jointly owned by sBmoffshore and misC, and currently the deepest moored FPso of the sBm fleet. this floating production facility is the world’sfirst turret-moored FPso using steel risers for fluid transfer. in thisproject, the steel risers are configured as steel Lazy Wave risers(sLWr) and became an effective strategy to reduce the path tofirst oil. shell operates this joint venture with partners Petrobrasand onGC.

during the Feed phase of the Parque das Conchas project,shell considered a number of riser systems including steel cate-nary risers, flexible risers, and hybrid risers. shell also conducteda study to verify that the use of flexible risers was feasible basedon the project’s riser diameters and water depths. since fatigueof the riser at the touchdown point ruled out sCrs and the cost of hybrid risers was deemed too high, sLWrs and flexibles werethen evaluated based on payload, cost, and schedule.

While costs of the two systems were comparable, the sLWrsystem payload proved to be approximately 50% of the flexibleriser system. scheduling for the flexibles also became a problemsince the offshore market was booming at that time and the flex-ible manufacturer’s lead time to deliver the risers was incompati-ble with the project schedule.

the choice of the sLWr system necessitated the use of aninternal turret system on the FPso instead of an external bow-mounted turret. since large riser pay loads were expected dueto the Parque das Conchas water depth, this internal turret solu-tion permitted the pitch motions of the risers to be significantlyreduced, resulting in an improved fatigue performance from therisers. specifically designed for the Parque das Conchas proj-ect, the Espirito Santo’s turret is comprised of a total of 21 riserand umbilical slots. the swivel stack includes eight toroidal fluidswivels, one double-drum HP/LP multipath utility swivel, two HVelectric swivels, and one power/control/optical swivel.

“this innovation opens up opportunities for fields in ultra-deepwater where flexible riser technology is not considered tobe feasible, due to high pressure, extreme water depth, largediameter, or a combination of all these,” said mike Wyllie,sBm Chief technology officer. “the capability to connect steelrisers to a turret-moored FPso is an enabling technologythat will open exciting new opportunities for challenging fielddevelopments.”

the internal turret was modified so that the risers and umbili-cals would be terminated in the lower turret cylinder. thisallowed a shortened straight inclined riser i-tube to mitigate anypipe interference for the pull-in of the sLWrs. Clamps retain therisers at the top of the i-tubes, thus transferring axial loads fromthe riser to the turret. A clamp casting welded at the bottom ofthe i-tubes houses a stopper arrangement designed to transfershear forces and movements from the riser to the turret.

to accomplish the termination, a new lower turret configura-tion was developed by sBm with three deck levels in the lowerturret cylinder. to facilitate a straight pull-in path for the risers,the location of the pull-in winch was located on the Collardeck, as opposed to the traditional upper deck, and a specialmovable platform was developed to locate the winch in linewith each of the i-tubes. the increased complexity of the turretdesign was compensated by the reduced riser payload and theoverall mooring and riser cost efficiency.

since this was the first time an sLWr had been used on a turret moored FPso, a new interface mechanism was designed tofix the riser to the guide tubes. the design consisted of a flex joint,journal forging, and upper attachment assembly on the riser end;and a clamp casting and hangoff collar on the guide tube.

“the challenge was to integrate the sLWr design and theFPso design, to ensure that the vessel motions and the sLWrfatigue were jointly optimized,” noted Wyllie.

SBM Offshore

First industry use oF sLWrson turret-moored FPso

The Espirito Santo at anchor in Singapore.(Photo courtesy of SBM Offshore)



sBm offshore designed and supplied the slWr and umbili-cal pull-in equipment while working closely with the shell teamto ensure the compatibility of rigging pulling head and key inter-face equipment. all the offshore operations of pull-in through thei-tubes were performed successfully as part of the site integrationtests. Working hand-in-hand, shell’s design of the riser clampcasting enabled sufficient tolerance while providing an efficientway to secure the structural interface with the i-tube bottom.meanwhile, sBm offshore’s winch platform design enabled perfect alignment of the winch cable to the i-tube axis. as aresult, the pull-in team would have been ready for another pull-inwithin six to eight hours, which indicates that the pre-installationof slWr and recovery of the slWrs and umbilicals from theseabed is an effective strategy to reduce the path to first oil. n

Monaco Engineering Office24 Avenue de Fontvielle

P.O. Box 199, Monaco CedexMC 98007 Principality of Monaco

Tel: +377 92.05.15.00www.sbmoffshore.com

BC-10 subsea system addresses several operational constraints.

the Bc-10 subsea system consists of dual flowlines that connect tolazy-wave risers connected to the floating production, storage, andoffloading (fpso) vessel. msi’s scope was to determine a feasibleoperating scenario to avoid slugging throughout field life. theoperating scenarios considered a range of production variablessuch as flow rates, water cut, and gas/oil ratio (gor) over the lifeof the Bc-10 fields. as a result, msi was able to suggest mitigationstrategies for predicted slugging and avoid any topsides liquidhandling issues for a wide variety of operating conditions.

for Bc-10, slugging is an issue for low-flow-rate scenariosdue to the down-sloping flowline as it approaches the riser baseand the lazy-wave riser configuration. after a detailed analysis ofvarious cases, we identified a slugging envelope bounded byflow rate, gas/liquid ratio, and water cuts. after the sluggingenvelope was developed, various slug mitigation methods suchas gas lifting, combining flow, and topsides choking were ana-lyzed. topsides choking was recommended to mitigate slugging,since this method produces a back pressure on the arriving slugsand limits the surge volume to less than the slug catcher capacity.it also limits the topside pressure to less than the set value of thehigh integrity pressure protection system (hipps). gas lift, as a

method of slug mitigation, could not be recommended becauseof lower arrival temperature and erosional concerns due toadding gas to the production fluid. also, the erosional problemswould still persist if the flow were combined into a single line.

overall, the Bc-10 system had three operational constraints:inlet pressure, slugging, and erosion. through the range of produc-tion scenarios that were considered, safe operating windowswere identified that address both the operational constraints andslugging issues seen through the expected operating regions, thushelping to ensure the system operates with the highest efficiency. n

Ensuring highly EfficiEntsystEm opErations

Multiphase Solutions

15115 Park Row, Suite 201Houston, Texas 77084Tel: (281) 646-1515Fax: (281) 646-8700www.multiphase.com

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SBM Offshore continued


Baker Hughes customizes pumping solutionsto solve development’s challenges.

baker hughes brought a totally different subsea solution fordeepwater applications to Shell’s parque das conchas fielddevelopment by installing electrical submersible pumping (eSp)systems in caisson on the seabed to boost several produc-tion wells in commingle with a single unit. Traditionally,eSps are installed in well bores. The project, located in bc-10 block offshore brazil, encompasses three separate fields – ostra, abalone, and argonauta b-west – each with different challenges. baker hughes’ technical capability todevelop a fit-for-purpose solution as well as the company’sdemonstrated commitment to investment in new technologiesresulted in a collaborative approach to solving the develop-ment’s challenges with Shell.

Two of the fields in bc-10 – ostra and argonauta b-west– which Shell operates in a joint venture with petrobras andongc, are equipped with eSp systems located inside a caisson below the seabed. Several production wells can feedthe eSp. however, due to different operating philosophies,both fields have different configurations.

“The ostra field is composed of two connected productionmanifolds that bring the production from several wells to the artifi-cial lift manifold (alM),” said ignacio Martinez, artificial lift andFlow assurance Technical Manager for baker hughes. “The alMis 9 km (approximately 5.6 miles) from the floating production storage and offloading [FpSo] unit and contains four caisson electrical submersible pumping systems.”

each eSp is enclosed in a 32-in. caisson and there is a gas linethat connects the four caissons to the FpSo. The gas is separatedfrom the liquid and vented through the gas line to the FpSo. “Thisconfiguration, also called a separator caisson, allows the liquid tofall to the bottom of the caisson where it will then be pumpedthrough a flowline by the eSp equipment to the FpSo,” Martinezexplained. The eSp operates as a fluid level control dispositive inthe caisson. The pressure on the gas line controls the intakepressure on the eSp equipment and that pressure can be adjustedfrom the FpSo.

production from abalone, the third field, is commingled with theostra field. abalone has a low flowrate and high gas/oil ratio.

“That high gas rate allows pressure to be kept on the gas line.without that extra gas from abalone, there would not be enoughgas on the gas line to flow through, complicating operationalissues and not making it possible to use the gas line on the separator caisson,” Martinez said.

in the second field, argonauta b-west, the caisson is also fedwith several production wells, but there is no gas separation. TheeSp systems are designed to handle more than 40% gas entrainedin the fluids. in this case, the intake pressure is controlled by the eSp. “argonauta b-west with 17 api is a heavier fluid thanostra at 28 api, which also affects the operational procedures,”he said.

“The objective was to supply an enhanced run life eSp systemsbased on proven technology to meet both scenarios where rapidgas decompression, temperature cycles, high-power and high-vol-ume eSp systems are compatible with the subsea infrastructure andShell’s operational philosophy,” Martinez said.

critical to the baker hughes solution was the fact that the eSpsystems were planned as an integral component of the entire

Baker Hughes

Through collaboraTionwiTh Shell, innovaTiveanSwerS developed


Baker Hughes installed ESPs in caisson on the seabed to boost several production wells in commingle with a single unit. (Photo courtesy of Baker Hughes)


hardware configuration. “This differs from the approaches wherethe ESP is considered as a separate item instead of being pre-planned as part of the final configuration,” Martinez said.

Baker Hughes’ dedication to delivering reliable and techni-cally innovative products and services was applied to the fullscale of the process, from the initial research and design effortsthrough describing the application, qualifying the manufacturing,transporting, and installing the solutions through to commissioningand operation of the equipment.

“This project presented unique challenges and demanded innovative approaches to meet Parque das Conchas’ needs,” Mar-tinez noted. “Although we have a demonstrated track record insubsea applications, the complexity of this subsea infrastructureand associated procedures for BC-10 called upon many of ourresources. Many hours were dedicated to workshops, internalmeetings and meetings with Shell’s experts. Testing of new solu-tions was required for hardware and new procedures were devel-oped to operate and control the ESP equipment. Many of thehardware solutions on the BC-10 ESP equipment are unique.”

Specifically, the motor used for the ESPs in the BC-10 develop-ment was designed and manufactured with new high-end technol-ogy seals. “Vanguard™ has been proven to enhance reliabilitywhen compared with standard motor construction,” said Martinez.“The extreme performance motor with Vanguard technology is aprecision design, manufactured to the highest industry standards.The motors are assembled in a specially designated facility underthe close scrutiny of design engineers from Centrilift, a BakerHughes subsidiary.”

The main hardware improvements were made to the seal section and were required because of expected rapid gasdecompression during some transient periods of operation.“Baker Hughes developed solutions to hold up to 1,000 psi per minute of gas decompression from 3,000 to 1,000 psi and 350 psi per minute from 1,000 to 300 psi,” he said.

Rapid decompression is detrimental to all elastomers, necessitating evaluation of composition and change to metalconfigurations. Components, such as the o-rings on the motorand pump and the power cable were evaluated.

“The BC-10 operational procedures are unique and involve a new philosophy of how to operate ESP equipment,” Martineznoted. “Commissioning of the system and startup has been flawlessand the system is in continual operation. To date, there is no subsea boosting system that has the high-volume and highboosting pressure capabilities of this Baker Hughes ESP system,which is considered the most cost-effective solution to the type of operations present in the BC-10 development.”

Martinez said the main objective of all the research was to bring the lessons learned to the design stage, thereby reducing the learning curve during the operational phase. “The applied technology and research enhances the run life of the ESP system and, ultimately, will result in a reduction in the number of interventions.”

Early research and development also improved the quality andoutcome of a project which is often influenced by the process andrelationship between the operator and the contractor. “In manycases, the operator focuses on the ESP as hardware only, neglect-ing the importance of the process in the conceptual phase of theproject,” Martinez noted. “Our work with Shell demonstrates thebenefits gained with collaborating to solve unique challenges.”

Many Baker Hughes personnel contributed to the success of the project, especially those located in Brazil. “The entire system has been installed and operated by Brazilian people,demonstrating the expertise available in the region for delivery of this type of high-end project,” said Martinez. “Rui Pessoa, amember of the Brazil team, was the dedicated desk engineerlocated in Houston who committed more than 18 months to project details. Other key personnel included Howard Thompsonand his team as technical support; Carl Grotzinger and BenGould as project managers and Bill Largess and his team whomanaged all processing and manufacturing in Claremore, Okla.All advance qualification testing for every piece of the systemwas performed using the test wells in the Claremore facility. Our management dedicated its best resources from the region as well as from headquarters.”

Research and development was used in installations in Claremore for several studies. The most important was the development of a new high viscosity loop to determine pump operating performance and motor temperature profile in high viscosity scenarios. “This was the first time ever that high volume pumps (10,000 b/d to more than 40,000 b/d)were tested under those conditions and the results were exciting– demonstrating that high volume ESP pumps can be much more efficient than expected,” said Martinez.

“This was a dedicated, successful partnership with Shellwhich led to further improvements in our processes, productsand quality of our services,” Martinez noted. “Our collabora-tion with Shell resulted in a mutual understanding of critical interfaces and delivery of innovative solutions.” n


Baker Hughes2929 Allen Parkway

Houston, Texas 77019Tel: (713) 439-8135Fax: (713) 439-8135

www.bakerhughes.comkathy.shirley@bakerhughes

s)

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Oceaneering and Shell collaborate onadvances in umbilical technology.

oceaneering provided one of the key solutions for shell’s par-que das conchas project located in the Bc-10 block offshoreBrazil – an umbilical whose cross-section design includes multi-ple power transmission circuits as well as electro-hydraulic con-trol and chemical service elements. shell operates this project asa joint venture with partners petrobras and ongc.

“We collaborated with shell to develop a technical solutionthat allowed for subsea power transmission and subsea controlsdistribution to be optimized at Bc-10 through the use of a sin-gle cross section for each of the three umbilical risers,” saidnick Wood, oceaneering senior project Manager. “each riserincorporates three Mv power circuits and standard electro-hydraulic control elements.”

david emery, senior project Manager, noted, “the three-phase power cables were built as trefoils before being incorpo-rated into the umbilical, resulting in superior power transmissionquality, which, in turn, improves the reliability of the subsea pro-cessing equipment. Additionally, the trefoil design significantlyreduced interference between the power circuits and the lowvoltage communication system.”

“We had to develop a complex multicable splicing techniquedue to the need to provide three trefoil medium voltage (Mv) cir-cuits within the umbilical,” added Andre chartier, engineeringManager at the time of the Bc-10 project and currently part of theAdvanced technologies group. “the splicing technique that wedeveloped maintained the electrical characteristics of the cable

while minimizing any impact to its tensile and mechanical capa-bilities. Additionally, the splicing did not change the cross-sectionalprofile of the cable, maintaining the overall umbilical diameter.”

With the aggressive manufacturing program schedule,oceaneering developed a multicable splicing regime where theslimline Mv splices were made on the three trefoils concurrently,minimizing the impact to the cabling schedule. the slimline electrical abandonment cap design is suitable for one-year subsea storage and 9,843 ft (3,000 m) water depth.

While the biggest challenge was providing the compositeumbilical in a continuous length, other major challenges includedcoordinating the large total scope of the umbilical and termina-tions design and manufacture. this included a comprehensive setof analysis activities including power transmission, thermal per-formance, and dynamic and fatigue modeling including vortex-induced vibration (viv) analysis. in addition, an extensive designand manufacturing verification program was undertaken to proveup the design. Finally, the scope involved a large number of subsupply vendors located in multiple locations around the world,requiring a comprehensive vendor management program.

specifically, oceaneering’s scope of work on the parquedas conchas project included:

n three Medium voltage/electro Hydraulic (Mv/eH) controlumbilicals with a total length of 99,407 ft (30,298 m);

n three static control umbilicals with a total length of70,213 ft (21,400 m); and

n steel tube flying lead umbilical with a total length of16,733 ft (5,100 m).

in addition, the following components were manufactured inorder to assemble the umbilicals:

n 1.6 million ft (492 km) of oversheathed steel tube; n 705,000 ft (225 km) of low voltage controls system

cables that included electrostatic and electromagneticshielding to minimize crosstalk between the Mv and lowvoltage (lv) circuits;

n 29 each of 10,500 ft (3,200 m) Mv trefoils, includingtwo manufacturing contingency spares; and

n 1.6 million ft (492 km) of extruded profiled filler.oceaneering’s Umbilical termination Hardware includes its

own list of impressive accomplishments:n three each, 15 ft (5 m) long pull heads, manufactured in

multiple sections to facilitate installation monitoring. thepull heads also incorporated a secondary hang-offgroove to ease installation activities;

Oceaneering

UniqUe cross-sectiondesign developed


The 30-ton bobbins on the cabling machine resulted in fewersplices in the power triads. (Photos courtesy of Oceaneering)


n Three each, 18 ft (5.4 m) dynamic bend stiffeners (BSR) witha remotely operated vehicle (ROV) operable latching system;

n Two thousand feet (600 m) of VIV suppression devices(strakes);

n Two hundred distributed buoyancy modules; andn Multiple repair splice kits and subsea Umbilical Termina-

tion Head (UTH) interface assemblies with vertebraebend restrictors (VBR).

Extensive experience in the design and manufacturing ofumbilicals combining power transmission with production controlfunctions allowed Oceaneering to address the design challengesspecific to this type of umbilical, such as internal heat generation,electrical interference, and increased mechanical loads.

“Oceaneering developed and enhanced existing techniquesto study the interaction of the MV and LV electrical circuits, includ-ing their impact on the operating temperature of the umbilical inthe upper section of the dynamic umbilicals,” Emery noted. “Wealso performed 3-D thermal analysis to evaluate the effect of theinsulating properties of the unusually large polyurethane bendstiffener on the operating temperature of the umbilical.”

Other specific testing included:n Tension/torsion testing;n Crush and installation simulation;n Reverse bend and flex fatigue;n Qualification of splicing techniques and abandonment caps;n Verification of electromagnetic interference (EMI); andn Multiple mechanical tests of hardware components.Two of Oceaneering’s accomplishments on the project will

likely make an impact on the BC-10 project’s life cycle operatingcosts. “Improved power transmission quality results in lower volt-age imbalances on the subsea pump motors, thus improving theirreliability,” said Matt Smith, Oceaneering’s Commercial Opera-tions Manager. “Additionally, use of a single umbilical riser crosssection reduced the costs of the qualification program.”

As with all umbilical projects of this size and complexity,Oceaneering put in place a dedicated project team to ensuresuccessful completion of the project scope. “Oceaneering dedi-cated five full-time team members at our facility in Panama City,Florida, during the execution of the BC-10 project,” said Wood.“Three full-time team members in Brazil contributed to the projectalong with multiple other team members who joined during spe-cific phases of the work. Cumulatively, more than 200 Oceaneer-ing employees played a role in the successful completion of theumbilical scope for the Parque das Conchas project.”

Oceaneering utilized a variety of its facilities around the worldto bring their part of the project to fruition. “The BC-10 umbilicalsupply was an example of successful cross-regional project execu-tion,” said Smith. “Each of Oceaneering Multiflex’ three umbilicalfactories (in Panama City; Rosyth, Scotland; and Niterói, Rio deJaneiro, Brazil) are capable of supplying a full range of productsand services. In the case of BC-10, Oceaneering was able tobring this global capacity to bear, supplying the long-length

umbilicals from Panama City while supplying the flying leads andperforming qualification testing in Brazil.”

A comprehensive list of “lessons learned” from the BC-10 proj-ect will be incorporated into future practices. “We made significant advancements in our technical capabilities withrespect to the electrical, thermal, and dynamic analysis activitiesrequired to support this type of major project,” said Chartier. “Wedeveloped and implemented new splicing techniques for the MVpower conductor trefoils and we applied updated processes toimprove the safety and quality of oversheathing steel tubes.”

With the successful completion of the Parque das Conchas umbil-ical, Oceaneering is looking forward to the next challenging project.

“Due to the compelling economic impact of subsea pumping,umbilicals for this type of application are among the fastest-growing sectors of the umbilical market,” said Charles (Chuck)Davison, vice president of Oceaneering Multiflex. “Oceaneering’ssuccessful execution of the BC-10 umbilical project is the resultof ongoing investments in people, processes, and facilities dedicated to maintaining market leadership in this technology.The umbilicals that Oceaneering designed, manufactured, andtested for the Parque das Conchas project demonstrate our commitment to provide superior technical solutions for the mostchallenging deepwater developments.” n


Oceaneering Multiflex – USACorporate/Sales Office

11911 FM 529Houston, Texas 77041Tel: (713) 329-4500Fax: (713) 329-4603

Loadout of the umbilicals at Oceaneering’s deep-draft quayside.

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Mooring contractor provides wide range ofservices as well as driven conductor and pipeinstallation.

interMoor is a full-service mooring contractor whose broadrepertoire of services includes engineering design, innovativetechnique development, installation, and testing of deep-seamooring systems. the company’s role has recently expanded to include driven conductor and pipe installation.

a good case in point is the recent Bc-10 project offshoreBrazil. there, interMoor was challenged to design and installthe mooring system for the 327,000-ton FpSo Espirito Santo in 5,800 ft (1,780 m) of water, as well as position and drive conductors for the development wells and for the artificial liftcaissons on the seabed. the sea off the coast of Brazil is characterized by very long period deep-ocean swells. theseconditions had to be taken into account in both the design andthe installation of the mooring system and the installation of theconductors and caissons.

Mooring designed to lastUnlike a temporary mooring for a drilling rig that will be movingon after a few weeks, the system for the FpSo must be capableof performing its task for 30 years or more. accordingly, inter-Moor closely collaborated with the operator, Shell, and its geo-mechanics contractor to select the optimum location on theseabed to install the nine anchors. installed in groups of three at120-degree intervals, the anchors were to be pre-set inadvance of the arrival of the Espirito Santo from its conversionsite in Singapore.

the seabed in the vicinity was characterized by turbiditic depo-sition caused by massive sloughing of sediments off the continentalshelf. not only was the seabed extremely heterogeneous, but italso contained large buried mass-transport deposits (MtD). Hittingone of these MtDs while setting an anchor could prevent it fromreaching its designed penetration depth.

installation of the anchors was straightforward. interMoorhas designed and installed hundreds of similar systems. eachcylindrical anchor was 16.4 ft (5 m) in diameter and wastargeted to penetrate between 53 ft and 57 ft (16 and 7.5 m)below the seabed. the open-bottom cylinders were loweredinto position by the OCV Normand Installer and achieved initial self-weight penetration of the seabed. Final penetrationwas achieved by pumping water out of the anchor via a valveon its top. the resulting suction allowed hydrostatic pressure to

set the anchors firmly in the seabed at which time the valve is closed and the anchor is ready for rigging.

on the Bc-10 project, the anchors were riggedchain/poly/chain with both the upper and lower ends of eachmooring line made of steel chain and the center (longest) spanmade of polyester rope. polyester rope is almost neutrally buoyantin water so it provides the required tensile strength without addingweight to the vessel. anchor lines were pre-laid on the seabed, sowhen the Espirito Santo arrived all that was required to moor herwas to pull in the nine anchor lines, tension them properly, andmake them fast to the cleats in the turret.

Conductor placement challengesinterMoor was also challenged to pre-install conductor casingfor the Bc-10 development wells and for the production caissonsthat housed the artificial lift systems. For the 36-in.-diameter wellconductors, the main challenge was timing. they had to be pre-installed off the critical path for the Arctic 1 drilling rig so asnot to delay drilling. For the 48-in.-diameter artificial lift conduc-tors, the challenge was precision. they had to all be driven to the same level (within a 2-in. tolerance of each other) and within1 degree of verticality. in all, 17 conductors were installed.

InterMoor

Setting DeepwaterrecorDS in Brazil


A 55-ton, 4-tube, ALM template is hung off vertically in the stern of the AHV prior to launch. (Photo courtesy of InterMoor)


InterMoor managed this project from conception throughdevelopment and finally execution. These conductors were thefirst pre-installed driven conductors in deep water, and duringthe project development and execution there were several otherindustry firsts, as could be expected when operating in watersranging in depth from 5,412 to 6,298 ft (1,650 to 1,920 m).Among these were:

n Vertical transportation and insertion of massive artificiallift module (ALM) templates into the water followed byhorizontal lowering to the seabed;

n Deepwater hydraulic hammer spread deployed and operated from an anchor-handling vessel (AHV); and

n A new deepwater hammering depth record (6,298 ft).

In addition, as a direct result of the learnings from Phase Iof the BC-10 project, InterMoor engineers have designed andtested a prototype 15-ton enhanced passive heave compen-sator. It is specifically intended for metocean conditions onlong-period deep ocean swells as found offshore Brazil andWest Africa. As a result of the successful prototype testing, acommercial version rated to 60-tons is being built and design iscomplete for a 75-ton unit. The new design, which is unique inthe industry, is currently planned for BC-10 Phase II conductorand ALM template installations. This helps enhance perform-ance and helps retain the commercial advantage of performingthe installation from a smaller vessel without the need for largeconstruction vessels.

Although conductors typically are installed using a jettingtechnique, for the BC-10 project a hydraulic hammer wasplanned. This was largely to ensure that the required verticalprecision and setting depth accuracy could be achieved. This isbecause a driven product is better understood than a jettedproduct from a geotechnical perspective; therefore, the finalcapacity, penetration requirements, conductor length, and setupare easy to calculate. Driven installations have traditionallybeen conducted using very large crane barges or constructionvessels. However, these vessels command a very high day rateand are of limited availability.

Accordingly, InterMoor developed a technique to effectivelylaunch conductors off a flat barge and install them using theoperator’s own AHV.

ALM templates set preciselyThe massive ALM templates were transported to location verticallyon the back of the AHV. The large four-conductor ALM templatesweighed 55 tons and the small two-conductor ones weighed 35tons. They were carefully lowered into the water and only turnedto the horizontal position after they were below the level of surfacedisturbance (waves and ocean swells). The ALMs were preciselypositioned on the seabed within 20-in. horizontal and 1.5-degreeheading tolerances. Fine-tuning was accomplished with the helpof the ship’s remotely operated vehicle (ROV). All of the 48-in.-

diameter conductors were to be installed through alignment tubesin the templates. There was only ½-in. tolerance between thealignment tube ID and the conductor OD.

Novel technique usedAfter attaching the work wire from the AHV to the top of a con-ductor on the barge, the conductor was positioned on a slopingramp and rolled off the barge into the sea. The conductor han-dling system was also designed and fabricated by InterMoorspecifically for this project, and allowed for the safe movement ofsingle conductors on the barge to the launching ramp. Whenentering the sea, the conductor filled instantly with water andswung in a pendulum motion through the water column until it stabilized in the vertical position under the stern roller of the AHV.Once in the vertical position, and hanging on the passive heavecompensator, the rigging was checked by an ROV and the con-ductor was lowered to the seabed. On the seabed the conductorself-weight penetrated enough to ensure stability (both structuraland geotechnical), at which point the ROV connected to a suctionport on the suction to stability (STS) head and pumped out waterfrom the conductor and gained additional penetration and furtherstability before landing the 80-ton hammer on the conductor fordriving. The STS head was designed and fabricated by InterMoorto provide additional contingency in the case that the conductorstopped short during the self weight penetration phase. With theSTS head removed, the subsea hydraulic hammer could belanded and the conductor driven to final penetration. Tolerancewas met on all conductors the first time, with no re-drivingrequired, mainly due to the hammer being able to reduce energyand to single blow counts during the final blows. This allows it tobe a very controlled driving process, even at such depths.

AdvantagesThe single biggest advantage of this novel approach was that itremoved the installation of 17 conductors from the rig’s criticalpath; however, there is also an argument that this reduces riskbecause it reduces multiple handling of many large pipe sec-tions offshore. It also delivers a well-understood product (drivenconductor) with a known capacity, which is not the case withtraditional jetted conductors. n


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Bredero Shaw meets clients’ needs with network that spans the globe

Bredero Shaw has been known for its specialized pipe coatingsprotecting oil and gas pipelines worldwide for more than 80years. as oil and gas resources become harder to reach, BrederoShaw continually works with its clients in developing new tech-nologies. with the introduction of Syntactic polypropylene and 4-layer polypropylene coatings at Bredero Shaw’s facility in Belohorizonte, Brazil, the company continues to serve the growingSouth american market with their leading pipe coating solutions.

Shell’s parque das conchas project, located in the Bc-10block offshore Brazil, is a key milestone in the commercializationof heavy oil offshore Brazil. to protect this pipeline, BrederoShaw coated 50 miles (81 km) of 6-in., 8-in.,10-in., and 12-in.diameter pipe with Syntactic polypropylene thermal insulationcoating and 39.8 miles (64 km) of 6-in. and 8-in. diameter pipewith 3-layer polyethylene (3lpe) and fusion Bond epoxy (fBe)anti-corrosion coatings.

in offshore oil fields, the flow of oil contains many types ofhydrocarbons that can turn to solids when cooled to certaintemperatures. as the oil flows from the wellhead to the process-ing facilities on offshore platforms, the temperature can dropbelow the point where certain hydrocarbons can turn to solids;effectively plugging the pipeline. “Syntactic polypropylene is acoating designed to ensure that the temperature remains above

where these hydrocarbons solidify, both in full operation andduring shutdown,” explained Sergio ferreira, Managing directorfor Bredero Shaw Brazil.

Bredero Shaw also provided field joint coating services forBc-10. when a pipeline is being constructed, pipe is weldedtogether end-to-end. this welded area requires the same coatingas the pipe and must be applied in the field or where the pipeis welded.

ferreira noted that Bc-10 was a strategically important projectfor Bredero Shaw. “although this was the second project utilizingSyntactic polypropylene for Bredero Shaw Brazil, it was by far themost significant,” he said. “the mobilization and construction of anew coating production line at our facility was completed as aresult of the contract award from Shell. our latest coating technol-ogy was installed in three months and required Bredero Shaw tomobilize engineers and coating experts from all over the world.”

the Belo horizonte facility is adjacent to the Valourec andMannesman’s seamless pipe mill. “Most of our facilities aroundthe world have similar product capabilities and the majority ofthe projects we participate in are determined by where the pipeis manufactured or where it is consumed by our customers,” saidferreira. Many of the coating systems can be designed andmanufactured to client specification in a single plant or in multiplecoating plants to improve project logistics. “high capacitywithin the Bredero Shaw plant network allows the client to benefitfrom single source advantages, ultimately providing more cost-effective management of pipe coating needs,” he noted.

“with the experience we gained on the parque das conchasproject, we expect our business relationship to grow,” said ferreira.“in other areas of the world, we have been providing coatingservices for Shell for many years. we have successfully completedprojects in Malaysia, the north Sea, and north america.” n

Bredero Shaw

Specialized pipe coatingSkeep the oil flowing

AV. Olinto Meireles65 – Barreiro (Usina V&M)

Belo Horizonte – Minas Gerais, BrasilCEP: 30640-010

+55-31-3029-6933www.brederoshaw.com

Pipes protected with Syntactic Polypropylene for the Parquedas Conchas pipeline project. (Photo courtesy of Bredero Shaw)


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Parque Das ConChas

June 2010


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Parque Das Conchas - Special Edition