Umbilicals

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Once again, OTC thrived with projects, new technologies, andpresentations that met the highest standards and expectations.Boosted by oil prices, attendance reached more than 67,000,a 25-year high. Nearly 2,400 companies from more than 30countries participated in the show. It was a great opportunityto exchange expertise in the development of offshore resourcesworldwide. Subsea technology, more than ever, was a key factor

in the huge success of this Engineering Celebration.

Last year I highlighted challenges for subsea processing and boosting. Today, Ibelieve even more that the great technical challenges bring huge opportunitiesfor subsea processing and boosting. Such technologies, when put together, willbe able to overcome the water-production challenge and will enable the produc-tion of increasingly heavier oil discoveries. Also, they will enable developmentof long tiebacks for oil and gas and will play an important role in the subsea-to-shore challenge.

Aligned with these principles, this year I picked papers that describe solutionsadopted for subsea-compression systems (Ormen Lange), and integrated sub-sea separation, boosting, and injection (Tordis). I also picked a classical subseadevelopment (Dalia) with great learning opportunities for all. Another subjectthat has generated much attention is the all-electric subsea tree. It is a greatinnovation with impressive results. I hope that next year we will be able to seeanother paper with the learning experience of the first system.

Therefore, I am especially pleased to invite you to read this impressive collec-

tion of topics for their scope, content, and effect on the industry. I hope youenjoy it.

Jacques B. Salis, SPE, is Drilling and Completion Manager of PetrobrasAmerica for the Gulf of Mexico. His 26-year career at Petrobras has been spentin various engineering and management positions in E&P, including coordina-tion of the Petrobras Technological Program on Ultradeepwater ExploitationSystemsPROCAP 3000. Salis holds a BS degree in mechanical engineering fromthe Military Institute of Engineering, Brazil, an MS degree in petroleum engineer-ing from the Federal University of Ouro Petro, Brazil, and a PhD degree in petro-leum engineering from the University of Tulsa. He has served on the SPE Board ofDirectors for Brazil and authored and coauthored several papers. Salis serves ontheJPT Editorial Committee.

OVERVIEW

SUBSEA TECHNOLOGY

Subsea Technology

additional reading

available at the

OTC Library:

www.otcnet.org

OTC 18749

The Tordis IOR Projectby Ann Christin Gjerdseth,FMC Technologies, et al.

OTC 18969

Ormen Lange SubseaCompression Pilot by BerntBjerkreim, Hydro, et al.

OTC 18819

First Application of the All-Electric Subsea ProductionSystemImplementationof a New Technology byLaurent Bouquier, Total,et al. (See JPT, June 2007,page 52.)

58 JPT AUGUST 2007

JPT


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The Ormen Lange field, in theNorwegian Sea, approximately 100 kmoff Norway, is within the prehistoricStoregga slide area with water depthsreaching 850 m in the main productionarea. The gas will be produced from upto 24 subsea wells. The well fluid willbe transported to the Nyhamna plantthrough two 30-in. multiphase lines.

After processing, the dry export gaswill be transported from the onshoreplant through a new 42-in. pipelineby way of the Sleipner riser platformand further through a new 44-in.pipeline to the gas-receiving terminalin Easington, England.

IntroductionFig. 1 shows the development con-cept selected for Ormen Lange, whichcomprises a subsea tieback to anonshore processing plant at Nyhamna.Conceptual engineering of the subseaproduction system was initiated in2002. The main contracts for subsea-equipment supply, umbilical fabrica-tion, and template installation wereawarded between the autumn of 2003and the summer of 2004. The main partof fabrication and testing took placeduring 200405, with the subsea tem-plates installed offshore in late summer2005. Umbilical A and the remainingsubsea equipment were installed dur-ing the summer of 2006, and the firstsubsea tree was installed on Template

A in December 2006. Completion ofthe first subsea well on Template A wasscheduled for spring 2007, and subseaproduction startup was scheduled forautumn of 2007.

Subsea-System ConfigurationWith the large geographical extent ofthe Ormen Lange reservoir and the riskof reservoir segmentation, the subsea-system design has a high degree offlexibility, with four planned templatelocations. Therefore, a phased-develop-ment scheme was chosen. The phasing

and location of the subsea wells will betimed to maintain plateau productionas the field depletes.

Initial Development. The initial sub-sea development consists of two eight-slot production templates (TemplatesA and B), approximately 4 km apart inthe main production area. Each tem-plate is tied back into the two 30-in.multiphase pipelines to shore. As Fig. 2shows, these lines are interconnected

through a pipeline-end-termination(PLET) system.

Two main control umbilicals link theonshore plant to the subsea productionsystem; one is connected to TemplateA and the other to Template B. A cross-over-control umbilical interconnectsthe two production templates, provid-ing redundant hydraulic supply to allthe subsea wells.

To prevent hydrate formation, all wellsare injected continuously with monoeth-ylene glycol (MEG) through two 6-in.pipelines from the onshore plant. One

line is connected to Template A and theother to Template B. A 6-in. crossover-MEG line interconnects the two produc-tion templates for added flexibility.

Future Development. Extension of thefield may require two additional produc-tion templates (Templates C and D).Each template will produce gas throughdual infield flowlines tied back to the30-in. multiphase pipelines to shore. Anew infield 6-in. MEG line will be con-

This article, written by Technology EditorDennis Denney, contains highlightsof paper OTC 18965, Ormen LangeSubsea Production System, by ThomasBernt, Hydro, and Endre Smedsrud,FMC Technologies, prepared for the2007 Offshore Technology Conference,Houston, 30 April3 May.

Copyright 2007 Offshore TechnologyConference. Reproduced by permission.

Ormen Lange Subsea Production System

SUBSEA TECHNOLOGY

Fig. 1Ormen Lange initial subsea development.

The full-length paper is available for purchase from the OTC Library: www.otcnet.org. The paper has not been peer reviewed.

JPT AUGUST 2007 59


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JPT AUGUST 2007

nected to each of the future templatesas extensions from Templates A and B.Similarly, a new infield-control umbili-cal will be connected to each of the new

templates as extensions from TemplatesA and B. The design has provisions fortie-in to a future precompression plat-form or a subsea compression unit.

Key Technical ChallengesThe seabed in the development area ishighly irregular, with soil conditionsvarying from very stiff clay with boul-ders to soft clay. Also, the environmentalconditions are extremely challengingand the installation season is very short.

Currently, there is no fishing activityin the area where the subsea templatesare installed. In the future, howev-er, trawling activity may commence;therefore, the large subsea installationsare equipped with overtrawlable pro-tection structures.

Hydrate Prevention. Hydrate preven-tion is a main technical challenge for thesystem. With the low seabed tempera-ture (1C), both hydrates and ice mayform, unless the well fluid is sufficientlyinhibited. The overall hydrate-preven-tion strategy is to minimize the risk of

operating within the hydrate region bycontinuous MEG injection at individualsubsea trees. For accurate injection con-trol, each well is equipped with an MEGflowmeter and dosage valve.

Long-Offset Control. Control of thesubsea production system will be fromthe onshore terminal at Nyhamna, adistance of 120 km. Availability of thesubsea control system on Ormen Langeis strongly emphasized because theproduction rate from each well is very

high and interventions will be bothcostly and challenging with the waterdepth and weather conditions. A fiber-optic/electrohydraulic multiplexed con-

trol system was designed, built, andtested. Components include high-volt-age power transformers, low-pressurehydraulic power, and backup commu-nication on high-voltage power.

High Flow Rates. The initial eightdevelopment wells will be 95/8-in.hybrid well completions with dualdownhole safety valves (deep-set) andhorizontal subsea trees. The remainingwell completions for Templates A andB are planned as 7-in. completions. Theaverage flow rate from each well maybe as high as 107 std m3/d. A majorchallenge for the project has been toensure that all equipment is designed toaccommodate this very high flow rate.Erosion and vibration are two impor-tant areas of focus in this respect.

SystemsThe design allows simultaneous produc-tion and drilling/completions/workoveroperations. During deployment of heavyequipment in open water from thedrilling/completion rig, the rig is posi-

tioned at a safe horizontal distance fromany subsea installation, even thoughdropped-object protection is part of thetemplate design. The template systemcomprises a foundation bottom struc-ture with skirt foundations and a mani-fold module. The production manifoldshave dual production headers. For eachwell, two hydraulically actuated valvesdirect gas flow to either of the manifoldheaders. Umbilicals and pipelines/spoolswere tied in by use of horizontal-con-nection systems.

Fig. 2Installation layout of Template B and PLET system.


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Subsea Tree. The subsea-tree systemis a 7-in. horizontal production treeequipped with an annulus bore. Thetree is configured with a separatelyretrievable subsea-control module(SCM) and a choke module, the lattercontaining instrumentation, flow-con-trol, and measurement equipment. Theproduction flow loop and the MEG,

annulus-test, and control lines on thesubsea tree are connected to the chokemodule through a multibore-horizon-tal hub. A remotely operated vehicle(ROV) panel is attached to the sub-sea-tree frame structure, and all valvesoperated by ROV are on this panel.Subsea-tree installation used guideline-less techniques. The tree is configuredwith hydraulics to enable a safe opera-tion and testing of tree/running-toolsystem by use of the workover system.

MEG Distribution. The MEG-distribu-tion system is designed to minimize therisk of hydrate formation. Each wellis equipped with a distribution systemensuring that sufficient MEG is injectedinto each well. The subsea tree sys-tem is equipped with two MEG-injec-tion points. During normal production,MEG is injected between the productionwing valve and the production choke toensure good mixing. During well startupand for barrier testing, MEG is injectedbetween the production master valveand the production wing valve.

Completion and Workover. The com-pletion and workover system comprisesall equipment and associated controlsystems required to install, retrieve,and commission a horizontal tubing-hanger system and to perform wellinterventions and workovers duringthe operational phase over the life ofthe field. The workover-control systemprovides the necessary functionality tocontrol all functions on the comple-tion/workover equipment and subsea

tree. It includes facilities to performnormal and emergency shutdown anddisconnection of specified functions inautomatic sequences upon activationfrom the surface unit.

Production Control. The produc-tion-control system uses a redundantfiber-optic bidirectional point-to-pointcommunication link between land andeach SCM. The control system hasfully redundant hydraulic, electrical,and communication systems and is,

as much as possible, based on provensubsea-control-system components.The subsea-control unit is installed atthe onshore plant at Nyhamna and is anode on the main-control-system net-work. The subsea- and onshore-controlsystems are, therefore, fully integratedwith no requirement for a subsea mas-ter-control station.

PLET. The 30-in. PLET system isinstalled close to Template B. ThePLET-system design comprises a PLETbottom structure, which was installedbefore pipeline lay down. The pro-tection structure protects equipmentfrom dropped objects and fishingactivities. The PLET bottom structurewas designed to function as a landingbase for the pipeline terminations, thePLET modules, and the pig loop. ThePLET system allows for thermal expan-

sion of the 30-in. pipeline. It providesfor tie-in of 16-in. rigid spools fromTemplate B and 12-in. rigid spoolsfrom Template C (future).

AchievementsAs of February 2007, the design, fab-rication, testing, and installation of theOrmen Lange subsea-production systemwere nearly completed. Templates Aand B, the in-line tees, the PLET system,and spools were successfully installedsubsea and all tie-ins completed.

Key Success Factors1. The level of detail and the qual-

ity of the conceptual engineering per-formed before contract award provideda very good basis for project executionin terms of planning cost estimates,specification of installation vessels, andother such details.

2. Active risk management has beenperformed throughout the project,whereby key risks have been systemati-cally and proactively identified, evalu-ated, and acted upon to minimize nega-

tive effects and maximize benefit.3. The project team has executed

effective change management, wherebyall change proposals have been care-fully reviewed and evaluated beforeimplementation or rejection.

4. The project team has performedclose and active monitoring of interfacework between contractors.

5. Qualification and verification tests ofall new components and thorough test-ing onshore have contributed to smoothand effective offshore operations. JPT


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62 JPT AUGUST 2007

In 2002, the Dalia subsea productionsystem was the largest subsea orderplaced with a single contractor in off-shore history. The production systemhad 71 wells, 71 drill-through horizon-tal trees, nine six-slot production mani-folds, two workover systems, flowline-connection systems, and a complexcontrol and chemical-injection system.

Heat conservation and hydrate preven-tion were paramount concerns duringthe subsea-production-system detailed-design and construction phases.

Subsea Production SystemFig. 1 shows the general field layout withthe 71 subsea wells and nine productionmanifolds and the flowlines, risers, andcontrol umbilicals that cover a subseafootprint of approximately 100 km2.

Production-Well-Cluster Layout.Various layouts were examined duringdetailed design to find the optimumsolution. A typical production-wellcluster comprises the manifold withthree wells on one side and three wellson the other, all connected by rigidjumpers between the Christmas treeand the manifold. When the manifoldis in the center of a flow loop, rigidspools connect production flowlines atboth ends of the manifold. If the mani-fold is at the end of a flow loop, a pig-

ging loop is mounted on the open sideof the manifold, permitting roundtrippigging. The control umbilical essen-tially is daisy chained from one mani-fold to the next. The rigid jumpers arenot in contact with the seabed but floatapproximately 2.5 m above it becauseof attached buoyancy aids.

Advances in directional horizontal drill-ing and the use of simplified completionshave enabled the wells to be grouped insix-well clusters, which not only facili-tates batch drilling, where necessary, but

also reduces the number of subsea flow-line and umbilical connections.

Water and Gas Injection. Similar toGirassol, the same single-line headerdesign is used to bring water and gasto the relevant wells. Control umbili-cals are laid adjacent to the flowlineswith subsea distribution units (SDUs)connecting the trees by electrical andhydraulic flying leads deployed by aremotely operated vehicle (ROV).

Wellhead, Christmas Tree, andTubing Hanger. Horizontal-Christmas-tree technology has been selected thatis compatible with a 7-in. full-borecompletion and permits an efficientsequence of operations, giving the pos-sibility of batch drilling with a minimumnumber of rig moves. Additionally, thetrees have the drill-through capabilitythat for a light-architecture-type well,lets the tree be run before the blowoutpreventer (BOP). With the tree andBOP in place, the well then can to be

drilled, cased, and completed.Two architecture types are used, with

the majority of the wells being the light-architecture type, based on a three-casing program, including the 36-in.conductor pipe and 183/4-in. wellheadhousing. In the base-case scenario, 10%of the wells are planned to be heavy-architecture wells, based on a four-cas-ing program, including the conductorpipe. In both designs, the wellheads arestandard 183/4-in. external diameter,

This article, written by Assistant

Technology Editor Karen Bybee, containshighlights of paper OTC 18541, DaliaSubsea Production System, Presentationand Challenges, by J.L. Lafitte, M.Perrot, J. Lesgent, J. Bouville, andS.Le Pennec, Total E&P Angola; P. Dahl,Hydro; and S. Lindseth, AKS, pre-pared for the 2007 Offshore TechnologyConference, Houston, 30 April3 May.


Dalia Subsea Production System

SUBSEA TECHNOLOGY

Fig. 1General field layout with subsea wells, manifolds, and flowlines.

The full-length paper is available for purchase at the OTC Library www.otcnet.org. The paper has not been peer reviewed.


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64 JPT AUGUST 2007

but for the light design, the wall isthicker to connect only the 14-in. andthe 103/4-in. casing hangers. The small-er-bore drill-through 13-in. horizontaltree then is installed on the wellheadand tested before BOP-stack installationand testing.

The conductor housing interfaceswith the guide base that provides the

final guidance for the Christmas tree.Installed together after jetting the 36-in.conductor pipe, the guide-base headingcan be adjusted by an ROV to an accu-racy of 1 and includes a receptacle foran orienting stab in the jumper-spoolconnection to the manifold.

The Christmas tree provides a com-plex subsea valve arrangement to con-trol the flow of produced fluids from orinjected water or gas into the reservoir.It also provides vertical access into thewell for workover intervention. The

tree bores are 51

/2 or 7 in., dependingon specific well requirements. Workingpressure is 5,000 psi, and the tree mea-sures approximately 5.14.23.5 m.Dry weight is 40 tonnes.

Completion and Workover System.One well-established advantage ofusing horizontal Christmas trees indeep water is elimination of the expen-sive, mono- or dual-bore workover-riser system, with its specific controlfacilities. It is usual that these sys-tems are deployed, for safety reasons,through the drilling riser and BOP andoffered on a rental basis for fields witha limited number of wells. However,with potentially as many as 100 wells,the decision was made that Daliawould invest in two workover systemsand maintain them under safe storagebetween interventions.

Production-Manifold System. Eachmanifold assembly consists of a founda-tion bottom structure and manifold. Thefoundation bottom structure comprises

a suction pile and a manifold-supportstructure that is adjustable in level to5. The manifold includes large- andsmall-bore piping, connection hubs,and protective structure. In case of amajor problem with a manifold, afterloop shutdown and full disconnectionof all the lines and umbilicals, the topunit can be recovered to the surface.

Spools, Jumpers, and ConnectionSystems. As opposed to three typesof subsea connection systems used in

Girassol, Dalia uses just one standardfor all field-deployed connections.

The production tree is connectedto the manifold connection hub byway of a 6-in. rigid jumper in a J/Lshape, floating above the seabed. The2-in. methanol and service lines andthe 3/4-in. hydraulic and chemical linesalso are connected at the same time by

use of a multiported horizontal huband clamp connection.

The well jumper, complete with hubsand insulation boxes at both ends, islowered from the surface vessel with alifting frame. The first jumper end entersthe manifold porch and is rotated beforethe second end enters the tree guidebase. A stroking tool deployed by ROVpulls the outboard termination intoplace at both ends. A standard torquetool then closes the clamp connectors.The two connections then are tested by

ROV, and finally, the insulation boxesare fitted and sealed. This same methodis used for the production-spool-to-flowline connection system and con-trol-umbilical connections.

Again, this system is used for the con-nection of the injection wells where thetwo additional electric jumpers then areconnected to each tree control module.

Many special tools have been devel-oped, such as a cleaning tool, a seal-replacement tool, a torque tool, anda stroking tool, and are deployed byROV from a subsea work basket. ThisROV-tooling philosophy optimizes sea-bed-operation timing by limiting thenumber of ROV dives.

Control SystemThe operating control system for theDalia subsea production system is oneof the largest and most complex to date.It has been designed to control as manyas 100 subsea wells (including intelli-gent downhole completions), all associ-ated manifolds, and all chemical-injec-tion requirements needed to manage the

heavy-oil production and low operatingtemperatures. The basis of design is anelectrohydraulic multiplex system thatis industry proven for deepwater opera-tions, with a number of key innovations.

Surface Equipment. The integratedcontrol and safety system (ICSS) wasdesigned to ensure the safe operationof all facilities topside and subsea andto fulfill requirements of the operatingand safety philosophies. The ICSS isoperated from the central control room

and is connected to the subsea controlunit (SCU) through a data highway andseparate workstation dedicated to thesubsea operation as part of the mainstation. Dual-redundancy computersare located in the instrument room.

The SCU controls the hydraulic powerunit (HPU) and all the subsea facilitiesby means of a number of gateways called

operation process control (OPC), allinterconnected by a dual data highway.Each OPC is connected to two sub-sea production-control units (SPCUs)and two umbilicals. All communicationcables are duplicated, and production-control umbilicals are configured in aclosed loop for 100% redundancy. Eachproduction loop is connected by oneOPC gateway and two SPCUs.

The HPU provides control fluids toactuate valves at 270 bar in the treesand the manifolds and at 700 bar for

the 51

/2- and 7-in. flapper-type down-hole safety valves.

Umbilicals and Subsea Equipment.Production umbilicals are connectedsubsea to the manifold by means ofa termination head and a manifoldcontrol module mounted on top of thestructure. From there, each Christmas-tree-mounted subsea control module(SCM) is connected by means of flyingleads for electric power and signals.Hydraulic lines and chemical lines arehard piped and mounted piggyback onthe rigid jumpers of the tree.

The SCM consists of solenoid controlvalves, pressure transducers, flowme-ters, filters, and two (dual-redundan-cy) subsea electronic modules (SEMs)housed in a nitrogen-purged housing.

Additional sensors such as the mul-tiphase meters, sand detectors, chemi-cal-injection throttle valves, downholegauges, and downhole interface unitsare all controlled by means of thesame system.

All subsea process sensors have dual

redundancy and are arbitrated by theOPC with a predefined algorithm. TheOPC simplifies the interface between theSCU and subsea equipment while mini-mizing software implementation efforts.

In addition, considering the fieldoperations, software with the overallcontrol of wells and risers assists thecontrol-room operations staff with man-agement of the subsea control by reduc-ing the number of tasks to be executedand in preventing operational upsetsfrom flowline and riser slugging. JPT


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In 2004, the subsea fields compris-ing the Canyon Express system weredeclining and water-production rateswere increasing. To halt the fast declineand extend the life of the field, flow-lines were reconfigured to separate thedepletion-drive wells from waterdrivewells. A real-time production-manage-ment tool for enhanced production

planning, monitoring, and trouble-shooting was implemented.

IntroductionThe Canyon Express transportationsystem consists of two 12-in. flowlinesrunning parallel from Camden Hillsthrough Aconcagua and Kings Peak toCanyon Station platform. The three sub-sea fieldsCamden Hills, Aconcagua,and Kings Peakare in 6,200 to 7,250 ftof water. The Canyon Express subseatieback, at 56 miles from Camden Hillsto Canyon Station platform, is one ofthe longest subsea tiebacks in the Gulfof Mexico. Production from the fieldsis predominantly gas with condensateand produced water. The wells are tiedtogether by means of a daisy-chainarrangement. Fig. 1 shows a CanyonExpress schematic.

During midlife operations, increas-ing water production from waterdrive

reservoirs (Aconcagua AC1 and AC2,Camden Hills CH1 and CH2, andKings Peak KP1 and KP2) and declin-ing reservoir pressures of depletion-drive reservoirs (Aconcagua AC3 andAC4) led to high liquid rates andlower gas rates. The declining deple-tion-drive wells were restricted byhigher water rates and liquid holdupin the flowlines. To optimize produc-tion during this period of increasingwater rates and declining gas rates,

several production options wereconsidered. Detailed flow-assuranceanalysis was performed for each ofthe proposed options, and a recom-mended solution was reached on thebasis of clearly identified advantagesand disadvantages for each operat-ing scenario. Flow-assurance evalu-ations were used on a continuousbasis for operations planning to opti-mize and maintain production duringthis period.

This article, written by AssistantTechnology Editor Karen Bybee, con-tains highlights of paper OTC 18830,

Innovative Operations Managementand Flow-Assurance Strategies ExtendField Life and Increase Ultimate Reservesof a Long-Distance Subsea Tieback inUltradeep Water, by Aditya Singh,SPE,and Kevin Hannaford, Total E&PUSA, prepared for the 2007 OffshoreTechnology Conference, Houston, 30April3 May.


Operations Management Extends Field Life

of a Long-Distance Subsea Tieback in Ultradeep Water

SUBSEA TECHNOLOGY

Virgo

KingsPeak

CamdenHills Aconcagua

Marlin

Ram-Powell

Neptune

MP 261 Canyon Station

Canyon

Express

Pipeline

Virgo

KingsPeak

CamdenHills Aconcagua

Marlin

Ram-Powell

Neptune

MP 261 Canyon Station

Canyon

Express

Pipeline

Pipeline

Umbilical

SubseaWell

Fig. 1Canyon Express schematic.

The full-length paper is available for purchase at the OTC Library: www.otcnet.org. The paper has not been peer reviewed.

JPT AUGUST 2007 65


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66 JPT AUGUST 2007

Evaluation of Late-Life OptionsScenarios of the operating conditionsto be studied were defined. Sensitivitieson arrival pressures, gas-productionrates, and water-production rates weredeveloped from time points in theproduction forecast for evaluating thepossible late-life operating techniques.

A matrix of cases to be evaluatedwas developed.

The following criteria were used toevaluate each of the technical options.

Minimize backpressure for selectedwells and/or all wells (increase gasrates).

Minimize liquid holdup in the sub-sea flowlines.

Minimize methanol requirements. Address operational issues: slug-

ging, shutdown/restart requirements. Examine cost and delay schedules.

It became apparent quickly that theimplementation of subsea separation orsubsea compression would be econom-ically unrealistic and could not meetthe tight time schedule for implementa-tion. Similarly, flowline burial was notan economical solution. Gas recyclingand looped flow had been considered inearly project phases but did not reducewellhead pressure sufficiently to maxi-mize production.

Key Phases in Canyon ExpressOptimizationProposed late-life techniques wereevaluated for the purpose of maxi-mizing production and increasingrecovery of reserves. The followingtechniques were finally selected tominimize wellhead backpressures,minimize liquid holdup, and reducemethanol requirements.

Reconfiguration of the subseaarchitecture to isolate the dry deple-tion-drive wells from the high-water-production wells.

Restaging and optimization of plat-

form gas-sales compressors.At the same time the various late-

life techniques were being studied, theCanyon Express pipeline managementsystem (PMS) was implemented toimprove flow-assurance and hydrate-management capabilities.

Reconfiguration of SubseaArchitecture. The dry depletion-drivewells on the east flowline (AC3 andAC4) were isolated from the high-water-production wells (CH1 and

CH2) on the east flowline. The water-producing wells were redirected intothe west flowline by closing an exist-ing 12-in. isolation valve and openingthe 12-in. pigging valve on the loopedflowline. Before this operation was per-formed, the depletion-drive wells werebeing affected severely by the high-

water- and gas-production waterdrivewells and were fast approaching theirabandonment pressures. The aban-donment pressures of the depletion-drive wells were reduced, enabling theproduction of 3P reserves from thesewells. The duration of the operation toreconfigure the east and west flowlineswas 12 hours and at no cost becausethe 12-in. isolation and pigging valvesare operated remotely.

Extensive flow-assurance simula-tions were performed to analyze the

effect of the strong waterdrive wellson the existing wells on the westflowline. Most of the wells on the westflowline also were strong waterdrivewells, so the effect of the reconfigura-tion on the west-flowline wells wasminimal. However, the overall effectof this operation in extending thelife of the Canyon Express system asa whole was significant. In October,November, and December 2005, pro-duction from Aconcagua AC3 andAC4 increased from approximately20 MMscf/D before the reconfigura-tion to 80 MMscf/D after it. The gas-total curve shows a fast decline ofthese depletion-drive wells from 80 to60 MMscf/D in 3 months. The produc-tion was maintained by simultaneousproduction of upper and lower zonesin AC3 and by east-flowline compres-sor restaging in December 2005.

Compressor Restaging. The east- andwest-flowline gas-sales compressors onthe Canyon Station platform were opti-mized during the late-life operations.

The compressors were restaged andarranged in series as the productiondeclined. The reduction in the flowlinearrival pressures helped to extend thelife of both the depletion-drive and thewaterdrive wells.The results of maintaining low flow-

line pressures included the following. Reduced subsea wellhead pres-

sures, increasing gas-flow rates andultimate recovery.

Higher pipeline gas velocities andlower liquid holdup in the flowline.

Lower liquid holdup resulted in lowerbackpressures at the wells.

Smoother operations during start-up and ramp-up operations.

Reduced hydrate risk in the flow-lines, enabling wells with high waterrates to be produced for longer dura-tions.

The east-flowline compressor wasrestaged from a four-stage to a seven-stage compressor. Through restaging(at the site-available horsepower of5,757 hp and sales pipeline pressureof 1,364 psi), the east-flowline suc-tion pressure was reduced from 700 to450 psia.

By arranging the west- and therestaged east-flowline compressors inseries, the arrival pressure was reducedfrom 450 to 350 psia. The west-flow-line compressor was restaged from a

four-stage to a six-stage compressor.Restaging the west-flowline compressorand arranging the two restaged units inseries lowered the flowline arrival pres-sures from 350 to 175 psia.

Both restagings were carried outwithin 10 days at a cost of USD 500,000per compressor restaging. By stagger-ing the restaging operations over dif-ferent time periods, field productioncould be maintained by diverting gasto the remaining east- or west-flowlinecompressor. Deferred production wasavoided by careful planning.

East-flowline gas production wasincreased from 40 MMscf/D to approxi-mately 50 MMscf/D by arranging thewest-flowline compressor and east-flow-line restaged unit in series. Productionwas maintained at 40 MMscf/D byrestaging the west-flowline compressorand arranging the two restaged unitsin series.

PMS. The Canyon Express PMS wasdeveloped to provide enhanced capa-bilities for reservoir and production

monitoring, early detection of poten-tial production upsets, and produc-tion planning during the mid- to late-life operations.

PMS provided enhanced capabilitiesin estimating water production fromsubsea wells, monitoring of hydratemargins, optimizing methanol injec-tion, and monitoring liquid holdup inthe flowlines. These capabilities facili-tated extending the production life ofthe wells with high water production.In some cases, previously shut-in high-


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JPT AUGUST 2007 67

water-production wells were restartedand produced using PMS.

During certain production peri-ods, if the flowline pressures in sec-tions of the flowline went into thehydrate region, PMS provided thecapabilities for early detection andresponse. Planning and look-ahead

modes of the system allowed exten-sive planning for challenging opera-tions and a fast response time duringthe operation.

Well AC 2, a high water produceron the west flowline, was able tobe produced because of PMS avail-ability. Gas production on the flow-line increased from a base rate of40 MMscf/D to a maximum rate ofapproximately 110 MMscf/D, and liq-uids production increased from a baserate of 3,000 B/D to a maximum rate

of 5,500 B/D. PMS implementationcosts were USD 750,000.

Results and Ultimate Effect

on Field Life

Neither subsea separation nor sub-sea compression was an economicallyviable option on the basis of the addi-tional reserves that could be recoveredby reducing the abandonment pres-sure of the subsea wells. Both of theoptions were technically challengingat Canyon Express water depths andoperating conditions.

Through careful planning and opti-mization, platform arrival pressureswere reduced from 700 to 175 psia.Lower platform arrival pressures notonly reduced the backpressure onsubsea wells but also allowed betterhydrate protection and pipeline sweepvelocities at lower flow rates.

The combined effect of separatingdepletion-drive from waterdrive wellsand lowering platform arrival pres-sures decreased the abandonmentpressures of the depletion-drive sub-

sea wells from 2,300 to 700 psig.By reducing the arrival pressure,

the flowlines could be operated atmuch lower gas rates with a steady-state liquid holdup. The west flowlinewas produced at a 15-MMscf/D gasrate, with approximately 3,000 B/Dof liquid production. The steady-stateliquid holdup in the flowline duringthis production period was approxi-mately 60%.

Water-production rates were in-creased by 100%, facilitating the start-

up of wells that were previously shutin because of high water production.Reduction in the methanol-injectionratio resulted in the replacement ofmethanol by water in the total liquids-handling capacity. Methanol-injectionratio was not only decreased as a resultof lower pressures but also because of

the reduction of safety factors built intothe injection ratios. PMS was responsi-

ble for this significant reduction in theoverinjection safety factors by providingbetter monitoring and risk-managementfunctionalities.

The overall consequence of all of theabove improvements for Aconcaguaand for the Canyon Express systemwas to extend field life by more than 1

year and increase the ultimate reservesrecovery by more than 18 Bcf. JPT

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