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Table of Contents

Independence:The Project .................................................04

Independence:The Achievement..........................................16

Independence:The Hub ....................................................21

Independence:The Trail Pipeline ........................................28

Independence:The Subsea Infrastructure ..............................38

Independence:The Fields and Reservoirs .............................44

Independence:The Companies ...........................................60

Profile Section:.............................................68

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A supplement to

4 ★ INDEPENDENCE ★ ENTERPRISE ★ SEPTEMBER 2007

The Independence Project began as a“Big Idea.” “Independence is anindustry solution to the problem of

stranded reserves,” said Mike Creel,Enterprise Products Partners LP presidentand chief executive officer. “It’s a veryeconomic and efficient way to buildand invest capital to accelerate resourcedevelopment.”The Big Idea was to develop the infra-

structure necessary to bring previouslyeconomically inaccessible ultra-deep Gulfof Mexico reserves to market.Bringing the Independence Project to

fruition was a “Big Project.”The Independence project is capable

of boosting Gulf of Mexico natural gasproduction by 10% and U.S. gas supply by 2%. It will con-tribute the largest increase in natural gas production in theGulf of Mexico by a single project in decades.“A landmark engineering achievement, the Independence

project represents one of the most innovative and well-coordinated solutions ever for economically developing Gulf

of Mexico natural gas reserves that would otherwise haveremained stranded,” Creel said.GulfTerra Energy Partners LP (predecessor in the Independence

project to Enterprise) came up with a solution attractive to theAtwater Valley Producers Group.“After several discoveries, it was clear to us that there was criti-

cal mass in this region but limited infrastructure,” Creel said.Independence added several levels of complexity to the idea

that collaboration can leverage diverse resources and expertise toachieve the most efficient utilization of resources (capital, facil-ity, capacity and human). Coordinating the Big Project involvedcrafting a unique commercial agreement among multiple par-ties. Forging an agreement among the original producers and amidstream service provider to develop 10 different discoveries,process and transport the gas to market is no small achievement.Independence Subsea wells are completed in record water

depths and connected by subsea pipelines and a state-of-the-artumbilical system to Independence Hub, the central floatingproduction and processing platform. Independence Trail is thehigh-pressure deepwater export gas pipeline that begins in arecord 8,000-ft (2,440-m) water depth at the central facility andends at a platform in shallow water where it connects to theU.S. gas transportation system.

Unique pact and advanced technology lift 10 deepwater fields beyond economic threshold

Mike Creel,

Enterprise Products

Partners LP

President and Chief

Executive Officer

Independence: The Project

SEPTEMBER 2007 ★ INDEPENDENCE ★ ENTERPRISE ★ 5

Independence Hub is the first major platform in the region,and Independence Trail is the first large deepwater gas pipeline.The project also marks the first production from federal watersadjacent to Florida.“The project could not have succeededwithout the collaboration

and cooperation of the whole group to achieve a common goal,”said Ray Cordova, deepwater platformsmanager for Enterprise.Despite the multitude of challenges implied in the record-

setting engineering feats, the complex commercial collaborationand sheer magnitude of scale, Independence was completed onan accelerated schedule, which served to enhance individualstakeholder project economics.

A blueprint for the futureThe Independence project represents the innovative approachof visionary companies to develop aggressive new approaches togain access to ultra-deepwater oil and gas potential rewards. It isa unique, cost-efficient alternative for ultra-deepwater develop-ment. Without this collaboration, the individual discoveriesthat now are part of Independence would have been difficult –perhaps impossible – to develop.Developing deepwater oil and gas reserves takes significant

amounts of capital. Though individual companies may pos-sess impressive resources, risking too much on a single projectof such large magnitude may not be prudent or even possible.As the Independence project proves, access is not limited to a

fewmega-giants with the resources to go it alone. By workingsmart, companies of a less than super size can collaborate toman-age the risks inherent in deepwater development.

By Any Measure,Independence Is A Big Project

World Deep-Sea Record Setting• Pipeline and riser (8,000ft, 2,440m)

• Platform (8,000ft)

• Subsea production (9,000ft, 2,745m)

Record Setting• Largest Gulf of Mexico gas processing facility (1 Bcf/d)

• Longest mooring lines (2.4 miles – 3.9 km – each)

• Deepest suction pile installation

• Largest monoethylene glycol reclamation unit

• Deepest pipeline inline future tie-in subsea structure

• Largest single subsea umbilical order

The natural order“Collaboration yields benefits, not only because it is a $2 billion proj-ect with significant risk and technical challenges, but also becausethere is a natural order of things in theGulf ofMexico,” Creel said.“Producers commit their capital to the development of pro-

ducing properties, midstream companies commit their capital tothe infrastructure required to process that production and bringit ashore,” he continued. “It’s a natural order of investment.”For the industry, the approach helps align interests, increases

utilization of capital employed and results in more efficient useof resources. Eliminating duplicate facilities, especially, has asignificant positive impact on project economics.For producers, leveraging cooperation and combining expert-

ise allows multiple producers to use a single gathering, process-ing and transportation system. Sharing common facilities givesproducers access to dedicated equipment, all with enhancedflexibility and affordability. Independence provides producers ahigher net present value (NPV) on their investment via projectacceleration, lower finding and development costs as well as theopportunity to free up capital for core business.“Independence permits development of significant gas

reserves that would not have been developed without a collab-orative approach,” said Richard Fowler, former vice presidentof deepwater development for Dominion Exploration &Production Inc. “Individually, these fields would not havebeen economic; combined, they are quite lucrative.”For facilities owners, the natural order provides a targeted

investment opportunity supported by significant long-termreserves while simultaneously positioning for the future growthpotential spurred by access to infrastructure.

A mile-high project viewSuperimposed on a map of the Houston metropolitan area withthe Independence Hub positioned over downtown Houston, theproject area would reach from The Woodlands on the north toGalveston on the south (see map).Getting a handle on the magnitude of the Independence

project is easier when grouped into three key systems:• Independence Hub, the 1-Bcf/d-capacity semisubmersibleplatform in about 8,000ft of water in Mississippi CanyonBlock 920 where liquids are removed from the well streamsand gas is compressed to enter the export pipeline.

• Independence Trail, a 134-mile (216-km), 24-in. and 20-in.high-pressure export line transporting gas from the Hub toa new junction platform in shallow water in West DeltaBlock 68 to interconnect with Tennessee Gas Pipeline, thuslinking market access to reserves.

• Independence Subsea, 10 initial fields with 15 subsea wellcompletions in water depths to 9,000ft; 220 miles (354 km)of subsea flowlines connecting subsea wellhead trees to theHub platform. This also includes 97 dedicated blocks.

The Independence Hub facility is owned by IndependenceHub LLC, which is owned 80% by Enterprise Field Services LLCand 20% by Helix Energy Solutions Group.Enterprise owns and operates 100% of Independence Trail.Independence Subsea consists of four producers collec-

tively referred to as the Atwater Valley Producers Group.Originally there were six producers, but corporate changeshave occurred since initial project development. BHP Ltd.left the group when it sold its properties in the region;Anadarko Petroleum Corp. merged with Kerr-McGee Corp.in 2006; Norsk Hydro ASA’s Oil & Energy Division purchasedSpinnaker Exploration Co. in December 2005, then in 2006,Statoil ASA agreed to acquire Norsk Hydro’s Oil and EnergyDivision; and Dominion Exploration & Production Inc. wasrecently sold to ENI Petroleum.

Pushing the water depth limitThe technical challenges of extreme water depths included thelimited supply of deepwater drilling rigs and construction/instal-lation vessels. Few pipeline laying vessels and only a handful ofdrilling rigs are rated for Independence project water depths.For example, most of the export pipeline and some of the

flowlines were installed with the Allseas Group’s Solitaire layvessel, one of only two rated for work in such extreme waterdepths. It still had to be upgraded to withstand the loadsinvolved in laying Independence Trail.Vessel availability may be another area in which Independence

contributes to industry’s deep water capability. It is possible thatthe ultra-deepwater fleet will get a boost with the completion ofIndependence, easing the equipment challenge for future projects.



“We’re showing that development can be done in thesedepths. Success at Independence indicates that the water depthlimit can continue to be pushed. That will help the fleet of deep-water vessels expand,” said Jim Alsup, Anadarko’s general man-ager of operations for Northern Rockies.Highlighting the differences between the approach of a small

company and an oil major, Jim Guion, vice president ofEnterprise, pointed out that a similar project might take a majoroil company 1 to 2 more years and significantly more capital justbecause of the methodology a big corporation applies todevelop, engineer and manage its projects. “One main point atwhich an independent’s project differs from an oil major’s is theattitude toward new technology,” he said. “You can save hugeup-front costs if you don’t have to develop technology.“Oil majors have R&D [research and development] groups

that constantly look into better ways of doing things and devel-oping new technologies. Although that can bring technicaladvantages to their projects, it also adds to both the project time-line and its overall cost. Our approach has been to take existingtechnology andmake it work in the appropriate application.”

Reasonableness prevailsThe commercial arrangements that made Independence possi-ble may be the most impressive accomplishment and key to thefuture of deepwater development.As a concept, the idea of several companies partnering to

optimize financial performance and manage risk is one thatmost would enthusiastically embrace – at least in principle.However, for a project of the size and complexity ofIndependence, distilling that lofty concept into documents allstakeholders put their signature to is another matter.Consider the details of this challenge. Begin with six experi-

enced deepwater operators with 10 ultra-deepwater fields, mostof which are not economical as stand-alone developments, andthen include a variety of well conditions. Add to the mix otherparties that own no production, but tie in the stranded reservesto processing and transportation infrastructure. Then get allthese parties to agree on the best way to spend the necessary $2billion overall investment in a short 4 years.A common goal included moving the project to first produc-

tion as quickly and safely as possible. To that end, facility designand commercial negotiations proceeded simultaneously.Enterprise ordered long lead-time equipment and materialsbefore the final contracts were consummated.During negotiation, “notices to proceed” allowed Enterprise

to begin the project – initial engineering, permitting and otheroperations – before the agreements were finalized. The noticeswere instrumental in fast tracking the project, enhancing thefinal economics to all parties. A “back stop” required the pro-ducers to pay Enterprise its out-of-pocket expenses if the finalagreement were not reached. The original notice to proceed was

revised six times to extend the date and increase the amount ofpay back as negotiation proceeded, because it took longer thanexpected to reach final agreement.From the partnership’s perspective, it is all about project

acceleration, which has a dramatic effect on NPV. Getting 1Bcf/d on stream in 5 years, rather than 7 to 12 years, adds con-siderable value to the project.“That’s when it is important to trust your partners in order

to be able to move the project forward,” said Bob Abendschein,Anadarko vice president of operations.Aggregating reserves of several producers to reach a reserves

threshold is a key to creating a commercial solution, poolingreserves and expertise leverages project economics and lowersindividual risk.

Some Area Discoveries in More Than 7,000ft of Water

Project Name Area/Block Water Depthft

DiscoveryYear

Aconcagua MC 305 7,379 1999

Camden Hills MC 348 7,530 1999

Blind Faith MC 696 7,116 2001

Merganser AT 37 8,064 2001

St. Malo WR 678 7,326 2001

Trident AC 903 9,816 2001

Cascade WR 206 8,143 2002

Great White AC 857 7,425 2002

Vortex AT 261 8,422 2002

Atlas LL 50 9,180 2003

Chinook WR 469 9,104 2003

Jubilee AT 349 8,891 2003

Spiderman/Amazon DC 621 8,100 2003

Atlas NW LL 5 8,810 2004

Cheyenne LL 399 8,987 2004

Mondo Northwest LL 2 8,340 2004

San Jacinto DC 618 7,850 2004

Silvertip AC 815 9,226 2004

Tiger AC 818 9,004 2004

Tobago AC 859 9,627 2004

Jubilee Extension LL 309 8,774 2005

Mondo NW Extension LL 1 8,340 2005

Q MC 961 7,925 2005

Stones WR 508 9,556 2005

Source: U.S. Minerals Management Service. AC = Alaminos Canyon; AT = Atwater Valley;DC = DeSoto Canyon; LL = Lloyd Ridge; MC = Mississippi Canyon; WR = Walker Ridge.

“We view the commercial solution that is Independence asthe first of its kind,” Abendschein said. “It’s important to notethat these companies were not bound to each other by a con-tract. The Atwater Valley Producers Group did not have a char-ter or other document that bound them to work together.”The result of about 4 months of 10- to 12-hour days of

negotiations was a myriad of agreements involving the Hubfacility and Trail pipeline to which producers and Enterprisewere signatories.Including all discoveries in the project optimized the eco-

nomics for each participant. “Even a company with a small per-centage of the Hub capacity could have considerable leverage,”said Brad Boister with Andarko.Operators with large capacity shares needed the smaller

shareholders to enhance project viability.Once the agreements were signed, the integrated project

teams assumed the responsibility to build and install the facility.“Even though it includes Serial No. 1 of the DeepDraft Semi,

a structure in a world record water depth, the most uniqueaspect of Independence Hub is the commercial arrangement,”said Don Vardeman, vice president of Anadarko. “It’s a trend forthe future because in deep water, risk sharing and risk manage-ment are of utmost importance.”“Co-management also sets the Independence project apart

from other projects,” Guion said.

Each operator aboard the Independence Hub shares equallyin the management of the facility, regardless of its interest inthe project. The facility’s steering committee is comprised ofrepresentatives from each producer, each with one vote. Itsdecisions, Guion said, “are truly joint decisions.”“Developing consensus among the partners is part of the

challenge – and I’m happy to say that we’ve managed to do it sofar. There’s a fun part to these jobs, too: taking a small-companymentality and applying it to a major project. It’s amazing howquickly and cost-effectively you can do a major project,” he said.“This is the first deal of its kind by a consortium. But going

forward, this is the kind of deal that will have to be donebetween producing partners and midstream companies tomake these kinds of projects work,” Abendschein said.

Deal highlightsAnadarko’s 2001 Merganser discovery turned out to be thefirst step along the path to the creation of Independence.Merganser, Federal Lease Sale 181 and other Atwater Valleydiscoveries pointed to an accumulating critical mass in theeastern Gulf of Mexico. The location, depth and large geo-graphical footprint of these reserves, however, were significanthurdles to economic development, and further exploration wasseverely hampered by the absence of infrastructure.In early 2001, before the Merganser find was publicized,

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Enterprise approached Kerr-McGee and beganto discuss the type of facility, said DennisJahde, vice president of offshore engineeringfor Enterprise.“Enterprise facilitated the conversation that

drew in other operators and proposed a jointdevelopment,” he said. “It’s the first time thatthis many different operators have beeninvolved with a single facility.”The goal was to structure a deal where the

provider would fund, build and operate thefacility as well as the export system while pro-ducers would dedicate gas throughput from thearea and commit to underwrite the project.Under the agreement, each producer pays a

monthly demand charge to Enterprise for a fewyears on a portion of its front-end investmentand the remainder is recovered through a pro-cessing charge based on actual production.Each producer’s capacity commitment deter-mined its share of the total demand payment.After 5 years, some capacity may become avail-able as the initial wells experience decliningproduction. This capacity then becomes avail-able to new producers.Capacity is allocated to a company, not to a specific project

or discovery. The company has the discretion to use its capac-ity share for its own or non-company use; in effect, it can sub-lease its share of the Hub throughput capacity.

Integrated teamsIt is hard to overemphasize the amount of planning that goesinto a project the size of Independence. The central vehicle forplanning, one that Enterprise had used before with Anadarko,was an integrated project team.

Independence Project Fields

Integrated Project Team. Seated (left to right): BennieTraylor, Anadarko; Dennis

Jahde, Enterprise. Standing (left to right): Mike Stark,Trail Lead, Enterprise; Ray

Cordova, Asset Manager, Enterprise; Jim Guion, Project Manager, Enterprise. Not

Pictured: Pete Stracke, Subsea Lead, Hydro; Mike McEvilly, Helix.

“It was the essential element of the consortium,” Jahde said.The group developed engineering design standards, and man-aged the interface with service providers and contractors thatbuilt the hull in Singapore, fabricated the topsides in Texas andinstalled the export pipeline. Representatives from differentcompanies managed different aspects of the project.“The integrated project team is a unique approach to doing

business in the energy world,” Cordova said. “The Hub conceptprovides benefits for industry, facilities owners and producers.”Independence had three key project teams – one for the Hub

facility, one for the export pipeline and one for the subsea infra-structure. Enterprise led the Hub and Trail teams. The Hubteam was led by Jim Guion, who had also managed the MarcoPolo and Prince projects for GulfTerra. The Hub and Subseainfrastructure involved multiple operators, several of whichsupplied members of the respective teams, which provided abroader experience base.In today’s environment of limited resources – not just capital,

but people, too – the integrated team approach allows all the par-ticipating companies to staff theproject. As a result, each participantalso expands its deepwater experi-ence for future projects that it maydecide to develop on its own.

Other synergiesCollaboration was criticalthroughout the Independenceproject. In addition to the agree-ment to build the Hub as a group,it was crucial to work together onmany other levels. For example,Spiderman and San Jacintohave two different ownerships,but were developed with a common subsea system.“Otherwise we would have had a 20-mile [32-km] piggable

loop and a 24-mile [39-km] piggable loop as opposed to the‘triangle’ that now connects those fields. That alone probablysaved $30 million,” Fowler said.Another innovative approach was to manage design and

installation of the entire subsea infrastructure as one project.All the companies worked together on bidding, contracting andscheduling vessels. It was a significant challenge just to organizework to ensure, for example, an umbilical installation vessel wasnot in the same area as a pipeline installation vessel.As negotiations progressed, front-end engineering design

(FEED) determined the size of the facility. Companies participatingin the FEEDprocess provided a “hard dollar quotation” on build-ing their proposed hull design. Alliance Engineering provided atopsides process design, and two fabricators bid on building thetopsides. Kiewit Offshore Services Ltd. was the successful bidder.

During the course of the FEED, additional discoveries weremade, requiring increases in capacity. And about 2 weeks beforethe FEED was complete, a new discovery caused the nameplaterating to be boosted from 700 MMcf/d to 850 MMcf/d. As theproject proceeded, additional opportunities arose, and thecapacity was increased to its final design rating of 1 Bcf/d. Thehull design had enough space available and a load rating suffi-cient to increase throughput.“It takes a blend of people, collaboration and technical inno-

vation to get to the resource prize in the Gulf of Mexico,”Abendschein said.

Role of the midstream providerBefore Independence, Enterprise had considerable experiencewith the hub and spoke concept, notably from the Marco Poloproject. However, Independence marked the first such project toinvolve multiple producers.For the midstream player, the platform arrangement

provides a solid standalone investment opportunity, andthe vehicle to extend existinginfrastructure and supply aportal to position for futuregrowth.“It gives us the opportunity

to invest in a world class proj-ect with significant reserves,”Creel said. “In this case, wehave contracts with five differ-ent producers in 10 fields withproven reserves estimated atabout 2 Tcf.“We’re well positioned for

the investment we have madeand positioned for future

growth in the eastern Gulf of Mexico.”Bart Heijermans, Helix’s chief operating officer, highlighted

the attraction from Helix’s perspective as 20% Hub owner:• an opportunity to have first mover advantage in a remotelocation with no infrastructure and – at the time – ninestranded fields;

• once the anchor fields begin to decline, the platform willhave excess capacity that will stimulate additional drillingin the area;

• the majority of gas fields are relatively shallow, makinglower dry hole, drilling and completion costs an advantage;

• a lower tie-back cost will reduce the commercial thresholdfor future developments, perhaps from 500 Bcf to 25Bcf (relative shallow fields require lighter flowline pipe,additional pipeline loop is not required for gas production,and future wells can be connected to existing flowlinesor manifolds);


“It takes a blend of people,collaboration and technical

innovation to get to the resourceprize in the Gulf of Mexico.”

Bob Abendschein

Anadarko


• gas poses fewer flow assurance challenges; and• a platform with subsea tie backs will provide a large foot-print, making it possible to tie back discoveries in a supplybasin of more than 8 million acres.“Every time Enterprise has a success like this, where we build

a structure and use it to process production for one or moreproducers, it encourages the industry to believe a little more inthe concept,” Guion said. “Every success shows the independentoperators, the companies that prefer to use their cash to drillmore wells, that they can get into deep water, affordably. We willsee more of these projects, and that’s a very exciting thing forthis industry.”

A critical mass gets infrastructureIn the beginning, the potential of the region that now com-prises the Independence anchor fields and the advisability ofbuilding expensive infrastructure were not entirely clear. Severalproducers had held leases in what became the Independencearea since the late 1990s; the first discovery in the area wasMerganser. Other discoveries followed, but the widely spaceddiscoveries of good – but not elephant – size, in ultra-deepwater, was a situation far from typical.The idea to bring all the resources and experience together

and customize a project to handle the infrastructure require-ments of an entire geographic region had been developing forsome time when the Independence opportunity presented itself.The project provided a chance to implement the idea by assem-bling a consortium of producers and midstream companies to

build a single platform and pipeline in an area that could notsupport multiple platforms and pipelines.The Merganser discovery in 2001 set off exploration activity

in the Atwater Valley that soon accelerated and eventually pro-duced what operators considered a critical mass of discoveries.At that time, GulfTerra (predecessor to Enterprise) firstapproached Kerr-McGee, then the group of producers, and pro-posed the consortium. There was limited midstream infrastruc-ture in the region, and water depth and areal extent posedsignificant technical challenges. Meeting those challenges andmanaging the solutions called for a new approach built on afoundation of collaboration that allowed all participants tocontribute expertise and resources.Before the project was conceived, producers in the area had

their eyes on a number of leases, they had spent money on seis-mic and had a number of drilling prospects. Without an infra-structure in place, however, it was difficult to develop thoseleases economically.“We’ve seen in the past that when we build infrastructure

where there is none, we accelerate development in thoseregions,” Creel said. “We think this area is resource rich, prima-rily in natural gas, but with some oil, too. It will continue to bea significant help in meeting U.S. energy needs.”It was only 15 months after lease Sale 181 that “we began

to work on this project as we made discoveries,” Abendscheinsaid. “It didn’t take long to figure out that we were going toneed to team up with other producers who were also makingdiscoveries.”


That is when the partnership of core producers was formed.Deepwater projects are capital intensive, and even with a

plan, they do not happen quickly. Once the concept forIndependence was outlined, all producers in the area combinedtheir expertise and resources to take the project from proposalto production in about 5 years, compared with a typical deep-water project timeline of 7 to 12 years.Lease Sale 181, in which the industry invested about $350

million, was an important driver of exploration in the area.Independence Hub is in a strategically advantageous positionrelative to other leases the industry hopes will be available infuture lease sales.Eight million acres in the area could hold a resource of 5 Tcf,

Abendschein said.“We hope to bring that gas through the Hub and keep it full

for many years. We’re bringinggas from the new frontier toAmerica,” he said.

Deepwater’s promiseJust what is the extent of theGulf ’s deepwater oil and gasresources?The U.S. Minerals

Management Service (MMS)defines deep water as waterdepths greater than 1,000ft(305m) and ultra-deep wateras depths more than 5,000ft(1,524m).“The deepwater Gulf of

Mexico is an integral part of(U.S.) oil and gas supply and oneof the world’s most importantoil and gas provinces,” accordingto the MMSMay 2006 report,Deepwater Gulf of Mexico 2006:American’s Expanding Frontier.Currently, the U.S. Outer Continental Shelf produces 30% of

the country’s oil and 21% of its natural gas. The Gulf of Mexicois the most prolific offshore region, providing 27% of the oiland 20% of the natural gas produced domestically. The Gulf ’scontribution is expected to rise within the next several years toabout 23% of natural gas and 40% of oil production.The ultra-deep waters of the Gulf are certainly “frontier terri-

tory.” During the past 5 years, there have been 22 industry-announced discoveries in water depths greater than 7,000ft(2,134m); 11 of those were in the past 2 years, according to theMMS. Announced volumes for these discoveries total morethan 1.8 billion boe.One important reason the industry is attracted to deep water

is that the average discovery size is many times larger than theaverage size of discoveries in shallow water. Deepwater fieldsalso are some of the most prolific producers in the area.During the past 10 years, the average shallow-water field

added about 5 million boe of proved and unproved reserves;the average deepwater field added more than 67 million boe ofproved and unproved reserves, according to the MMS report.The presence of pre-Miocene reservoirs, successes in the east-

ern Gulf sale area and significant discoveries in the ultra-deepwater demonstrate the continuing exploration potential in thedeepwater Gulf, the agency said. These new plays are large inareal extent, have multiple opportunities and contain poten-tially huge traps with the possibility of billions of barrels ofhydrocarbons, according to the report.Deepwater activity – and operating depth – has grown

dramatically in the past fewyears, but the groundworkwas laid during the previous twodecades. According to the MMS,in early 2006 there were about8,221 active leases in the Gulf ofMexico outer continental shelf,54% of which were in deep water.This compares with about 5,600active Gulf of Mexico leases in1992, only 27% of which were indeep water.On average, there were 30 rigs

drilling in deep water in 2005,compared with only three in1992, the MMS said. Deepwateroil production increased by morethan 840% between 1992 and2002, and deepwater gas produc-tion increased 1,600%. In 2000,for the first time, more oil wasproduced from deep water in theGulf than from shallow water.

Deepwater production rates rose by more than 100,000 b/dof oil and 400 mmcf/d of gas, respectively, each year from 1997through 2002, according to the MMS. Production rates haveremained flat since 2002, but Independence alone has thepotential to boost Gulf gas production by 10%.The MMS data show there were only six producing deepwa-

ter projects at the end of 1992; by early 1997, there were 17. Atthe end of March 2006, there were 118 producing projects inthe deepwater Gulf of Mexico, up 37% in 2 years.As the number of deepwater projects grew, so did the water

depth of new projects. A major 2006 discovery in the Gulf wasdrilled in 7,000ft of water; other discoveries will be developed indeeper water. Independence is the first to push the water depth

“Producers commit theircapital to the development

of producing properties,midstream companies

commit their capital to theinfrastructure. ... It’s a natural

order of investment.”Mike Creel

Enterprise

envelope for a floating central platform to 8,000ft (2,440m) andthe subsea well completion record to about 9,000ft (2,745m).By setting new water depth records and proving the value

of an innovative business model, Independence will continueto build confidence in the ability to find and develop deep-water reserves. That confidence will fuel investment in thesearch by producers, infrastructure builders, and equipmentand technology providers. In short, there will be more deep-water discoveries, and more tools and new ideas to developthem economically.As the industry’s offshore capability advanced to today’s

impressive level, offshore oil and gas environmental incidentshave dramatically declined.“The offshore technology applied by U.S. companies today

worldwide has a record of environmental compatibility thatwas demonstrated most vividly by there not having been a sin-gle significant offshore exploration and production [E&P]

facility oil spill caused by the otherwise devastating hurricanesKatrina and Rita (in 2005),” said Timothy Parker, senior vicepresident of Dominion, before the Senate Committee onEnergy and Natural Resources hearings on Senate Bill S. 2253in February 2005.

Area impact on supplyThe MMS Sale 181 area in the Gulf may be the best singleprospect in the United States for significant new near-termE&P. The MMS estimated at the time of the sale that the origi-nal Sale 181 area had the potential to produce 7.8 Tcf of gas and1.9 million bbl of oil.Success rates have been good in the area, partially because of

the use of 3-D seismic technology. It is one thing to drillexploratory wells, but developing deepwater discoveries is yetanother challenge.In a statement to a U.S. Senate Committee, R.M. “Johnnie”


Burton, former MMS director, cited estimates that the resourcepotential of the portion of the Sale 181 area east of the area cur-rently available for lease – pro-posed in S. 2253 – has apotential of 930 million bbl ofoil and 6.03 Tcf of gas.The resource potential in the

area contemplated for leasing inS. 2253 may be much bigger,according to the MMS. In partsof the Gulf of Mexico where theindustry has been allowed to buyleases and explore, it has pro-duced three times as much gasas once thought was there.The resource estimate, according to the MMS, is that there is

nearly five times as much remaining to be found. It is yet more

evidence that the more the industry explores, the more it knows.There is an environmental benefit to the search for gas, too.

Non-associated natural gas pro-duction expected in the Sale 181lease area has no potential forcrude oil-related incidents.Even crude oil incidents

related to E&P are now almostnon-existent. There has not beena significant platform spill onthe outer continental shelf dur-ing the past 35 years.The Sale181 area is a gas prone area, andnatural gas production offshorerepresents one of the most envi-

ronmentally sound energy developments this country couldpropose, Burton said in a recent statement. ★


The Delmar subsea connec-tor (DSC) allows opera-tors to change out

mooring components with justone vessel and without havingto unseat the anchor. The DSChas been used with syntheticmooring in permanent moor-ing projects around the globeincluding the Gulf of Mexico,Brazil and Australia. However,the Independence Hub is thedeepest installation for theDSC in water depths thatexceed 8,000ft (2,440m).As the first class society-

approved remote operated vehi-cle (ROV)-actuated connector for mobile offshore drilling unitsand permanent mooring systems, using the DSC results ingreater “setup” time, allowing the anchor to obtain more hold-ing capacity before loading it with the mooring line.

The DSC provides easy connect/disconnect capability withthe use of a standard ROV. During installations, anchors canbe installed separate from the mooring line, which is a break-through not previously used in permanent mooring systems.“We produced our largest third-generation DSC to date,

rated to accept a load of 4,500 kips,” said Brady Como,executive vice president of Delmar systems. “The size of themooring components confirmed our belief that the DSC isas much an installation tool and of benefit to the installationcontractor as it is to the operator since it gives the operatorthe flexibility to change out a mooring line without removingor replacing the anchor.” ★

Paid Sponsorship

Deepest DSC InstallationDelmar Systems Inc.’s innovative permanent subsea mooring connector saw its deepest installation in theGulf of Mexico with the Independence Hub project.

DELMAR SYSTEMS INC.

Delmar Systems Inc.8114W Hwy 90

Broussard, LA 70518Tel: 337-365-0180Fax: 337-365-0037www.delmarus.com

Third-generation Delmar

subsea connector

The MMS Sale 181 area in theGulf may be the best single

prospect in the United States forsignificant new near-term E&P.


In the glow of success thatmarks the days after a difficult projectgoes on stream, when gas – and revenue – are finally flowing, it isoften easy to forget howmany challenges weremet along the

way to the goal and how daunting they seemed at the time.For a project the size of Independence, with each of its three

major components (Hub, Trail, Subsea) requiring cutting-edge tech-nology and innovation in a spectrumof disciplines, it is not possibleto list every achievement. Records set and the implementation ofnew concepts represent some of the triumphs:

• a ground-breaking commercial agreement among an unprece-dented number of operators that leveraged the resources andexpertise toward a common goal;

• water depth records for subsea wells, risers, production facili-ties, pipelines and umbilicals;

• an unprecedented impact on Gulf ofMexico natural gas pro-duction for a single project;

• a fast-track schedule that tested the project management abil-ity of each party; and

• an innovative, collaborative approach to developing strandedoil and gas resources.

Integrated project team conceptThe Independence project’s success is a result of the collaborationamong the owners, producers, operators and contractors involvedand their ability tomeet the challenges of this record-setting project.“Much of the credit for success goes to the integrated project

team [IPT], a concept that was the key tomaking the fast trackpossible,” said Dennis Jahde, vice president of offshore engineeringfor Enterprise Products Partners LP. “The IPT allowed us to takeadvantage of the resources and experience of the other companies.Integratingmanagers into the teammade it possible to put amuchhigher level of expertise on the project.”There was more than one group built around the integrated

team concept. In addition to the overall project team that man-aged the Independence Hub and the Independence Trail ele-ments of the project, the subsea group had its own integratedteam. Representatives from the operators manned the team forthe Hub and Trail but were involved in the subsea integratedproject team only in an interface capacity.Several factors combine to helpmake gas fields with between 30

Bcf and 50 Bcf of reserves tied back subsea to a flowline or mani-fold commercially viable. Compared with oil, gas well tieback costsare relatively low; pipeline loops needed for flow assurance in thecase of oil wells are not required for gas, and handling gas on theplatform requires less equipment and less complexity.Without the joint development concept combination and the

Independence: The AchievementWorld-class project advances deepwaterability, technology and potential


portfolio approach taken by Independence operators,it would take a 500-Bcf gas field to be commercial, saidChief OperatingOfficer BartHeijermans withHelixEnergy SolutionsGroup Inc.Not only does the Independence approachmake

more fields commercial, it opens opportunities tomore companies. Perhaps as important as the techni-cal achievements is the ownership of the Hub’s treat-ing capacity by four producers, an industry first.

Milestones along the pathTo get from a proposal in September 2003 to firstproduction in the second half of this year requiredan all-out effort by the project teams, operators,contractors, suppliers and designers.While ownership arrangements, and processing

and transportation agreements were still being ironed out, front-end engineering design (FEED) and materials procurement gotunder way. This was made possible through the notices to pro-ceed (NTP), whereby Enterprise was authorized to make upfrontpayments with reimbursement assurance from the producers.Without the running start that NTPs allowed, a fast-track

schedule could not have beenmaintained. Making commitmentsto suppliers and contractors before all the “ts” were crossed in theownership agreement required a high level of trust between themidstream provider and anchor producers.

Lessons learnedOn a project the size of Independence, experience and skills areaccumulated that will improve future efficiency, design and oper-ation. Typically, the negative events provide the greatest lessons.For the most part, there were few such events with Independence,partly because the hard lessons and experience from prior proj-ects were brought forward to the Independence project.For example, upsizing the facility midstream in the process

turned out to be an untypical event, yet it was accomplished with-out much impact on the overall schedule.One important lesson for large, complex developments is,

where possible, to avoid operations that can be performed by onlyone heavy-lift vessel. Thoughmating of the hull and topsides wasdone quayside, there still was only one heavy-lift vessel (the Balder)that could install the export line riser and anchors. The Balderwasdelayed by another project late in 2006 when the Hub platformwas ready tomove to its location. The vessel was not available toinstall the Hub, risers and anchors until February. In essence,startup of a facility that would bring 1 Bcf/d of gas production online was held up because of reliance on a specific vessel.“The lesson for future developments is that mooring lines and

export pipeline riser should be designed in such a way that theycan be installed bymultiple vessels,” Heijermans said. “A singlevessel should not be on the critical path.”

Despite the vessel delay, the project team strategicallyrearranged work andmanaged to keep the project on schedule.Initially, to accommodate equipment delivery schedules, much ofthe Hub platform topsides work was planned for after it had beenmoored offshore. However, whenHub installation slipped fromAugust last year to early this year, it was possible to complete thetopsides work at quayside with less expense and difficulty.This strategic work rearrangement avoided the need for a heavy-

lift vessel tomate the topsides at the deepwater location. Bymat-ing topsides to the hull in the controlled environment at Ingleside,Texas, with the port’s heavy-lift crane, weather interruption riskwas reduced, and the expense and difficulty of scheduling the sin-gle capable vessel was avoided.Scheduling was critical in optimizing expensive rig time use,

and much engineering was involved in finding the best way tomake up ultra-long downhole equipment assemblies with thesingle activity rig Deepwater Millennium. Instead of having tomake up each part and connect its piping and control lines onthe critical path of the single rig, the project team devised a pro-cedure for assembling the equipment on the deck. It was alsonecessary to ensure that the long assembly – 80ft to 90ft (24mto 27m) long rather than 30ft to 40ft (9m to 12m) long – couldbe picked up without being damaged.Given the significant day rate of the subsea work with the

Deepwater Millennium, the engineering effort paid off. Instead of4 to 6 hours critical path time to make up the assembly a pieceat a time, pre-assembly off line reduced critical path time toonly 30 minutes.Based on the original schedule, Anadarko thought

completion of all wells it would operate was unlikely beforeIndependence Hub went on stream. However, the combinationof the Hub installation delay and accelerated completion pro-gram allowed the wells to be ready to go on production whenthe Hub started up.It is a credit to planning and design that there were no major

Integrated Project Team, (Left to right) Dennis Jahde, Enterprise; John Weeks,

ENI; Don Vardeman, Anadarko; Ray Cordova, Enterprise; Susan Holley, Anadarko.

Not Pictured: Dave Bozeman, Devon; Arild Haugland, Hydro.


setbacks in building the Independence Trail pipeline. However,there are some lessons to be remembered, said Mike Stark, Trailconstruction manager with Enterprise. Monitoring currents isimportant in the deep water of the Gulf, for example.Early evaluation of materials and material requirements is

also critical. Just the logistics of sourcing 100,000 tons of pipesteel and manufacturing that much pipe is a challenge. “Wespent a lot of time with the steel mills evaluating their steel-

making process to get the highest quality. It is important not totake the steel making process for granted,” Stark said.Valves are another example of the importance of materials.

Though the pipeline is ANSI 1500, valves were ANSI 2500because of the great water depth. That made them very longlead-time items.Welding is also critical. Bevel design and the welding process

are important, especially in the steel catenary riser (SCR). In thecase of Independence, part of the challenge stemmed from the factthat Enterprise was designing the SCR before themotions of thehull were fully known.A special weld treatment was also used on the project.“Weld fatigue life increases when the cap of the weld is

removed,” Stark said. “In several areas of high stress, we groundthe weld cap off the weld, making it smooth with the pipe. Itwas helpful in increasing the fatigue life of the pipe in areas ofconcentrated stress.”It is no small feat tomake five operators and a separate facility

owner happy – each with a different philosophy and its own expe-rience, good and bad, with different contractors.There wasmuch work to be done after the Hub left Ingelside.

Commissioning of the producer flowlines and export line couldnot be performed until the final hookup onto the Hub.

“Even with some hitches, Independence has moved on a prettyfast track,” said Greg Rhodes, Atlantia Offshore’s director of deep-water floater development.

Shifting regulationsNot all the obstacles were technical in nature. In the midst ofthe project, the regulatory environment shifted in response toproblems with another deepwater project and a severe 2005 hur-ricane season.“It changed everyone’s mind about how they ought to look

at these platforms. And unfortunately, we were the next guy inthe queue,” said Chuck Kindel, Atlantia Offshore’s projectmanager for Independence Hub. “Independence Hub got a lotmore questions and a lot more scrutiny than it might otherwisehave received.”While the overall design was not impacted, the biggest change

was in regulations governing the ballast control system. Duringdesign, the decision was made to include the ballast control sys-tem in the integrated marine management system (IMMS) toprovide a single integrated package. The IMMS contains weather,draft, current and other data.“Integrating ballast control in the IMMS sounds good, but it is

muchmore complicated,” Kindel said. “Theoretically, you canoperate the ballast control systemwith just a push-button panel.”Revisions in the regulations, however, required 100% redun-

dancy in all electronic devices. That new rule came in early last yearafter the IMMS system had already been ordered and constructionwas progressing.

TIMELINE—KEY DATES

November 2004 Agreement with anchorproducers was signed

End of 2004 Topsides construction andpiping design began

December 2004 Design of theIndependenceTrailpipeline under way

2005 Construction of the Hubplatform hull had begunin Singapore

2006 Installation of theTrailpipeline began and wascompleted by mid-year.The Hub hull sailed May8 from Jurong Shipyard,headed for KiewitOffshore Services’ facilityin Ingleside,Texas

Mid-2006 Interconnect platform wasinstalled inWest DeltaBlock 68

Late Sept. 2006 Topsides had been matedto the Hub hull

July 2007 First gas begins to flow


The general tenor of regulatory oversight – what does and doesnot need to be done – has becomemore restrictive, a trend to keepinmind in future projects, Kindel said.

Technical highlightsEach main element of Independence – export pipeline, subseainfrastructure and central platform facility – faced significanttechnical challenges. To meet those challenges, project teamsdevised solutions that resulted in world class achievements.Independence subsea wells include the world’s deepest,

for example, the Cheyenne field where a well is in 9,000ft(2,745m) of water. That, in turn, requires the world’s deepestflowline installation.The project’s largest single order for an umbilical systemwas

also the world’s largest single umbilical system tomanage all thesubseamanifolds. Because of the water depth, it is the first use ofcarbon fiber rod in a subsea umbilical system.“It’s impressive that industry cannot only lay subsea pipelines,

but also install umbilicals to control the wells that far from thehost platform,” saidMike Creel, Enterprise president and chiefexecutive officer.That platform is installed in the deepest water of any produc-

tion platform, and because of that, it requires the deepest SCRinstallations to date.The platformmounts the Gulf ofMexico’s largest gas treating

plant. The topsides plant is roughly four times larger than theGulf’s next largest monoethylene glycol (MEG) reclamation unitwith a feed capacity of 7,800 b/d ofMEG and produced water.For amoored structure, record water depths pose other special

technical challenges. The Hub’s 2.4-mile (3.9-km) longmooringlines are longer than the lines for any other structure, and the suc-tion piles to which the lines are attached are the deepest installed.Extreme water depth also called for the use of a newmooring linematerial – polyester rope – that has been tested extensively but notyet widely used.Then there is the export pipeline. Independence Trail, originat-

ing in about 8,000ft (2,440m) of water, is also the world’s deepest.Installed with the S-lay method from a state-of-the-art pipelay ves-sel, installation tension on the lay system reached 550 tons. Eventhough the Allseas Solitaire is the largest lay vessel in the world, ithad to be significantly modified for the project.The 650-ton weight of the Independence Trail SCR is the

heaviest SCR load imposed on a deepwater floating facility.Even one of the pipeline’s tees, installed along the route toWest Delta Block 68 as a tie-in for future development, is theworld’s deepest.

Significance for the future“Independence is a blueprint for the future, largely because of thecapital investment and risk involved in developing wells andinfrastructure in the deepwater trend,” Creel said. “Each elementof Independence represents a significant advance. All threetogether comprise a truly world-class achievement.”“Independence is a world-class project. Including subsea

infrastructure, hull, topsides and pipeline, the investment totalsabout $2 billion spent over a very short time,” Jahde said. “Andproducing 1 Bcf/d from 9,000ft of water is a reasonably impres-sive feat, I think.” ★


Extreme water depth drove the design for theIndependence Hub platform hull and its mooringsystem. Mitigating the risk of hydrate formation in

flowlines that together will supply 1 Bcf/d to the Hub droveits topsides design.Record water depth at the Hub location meant supporting

the longest-yet steel catenary risers (SCRs) that connect flow-lines and an export line to the platform deck. The SCR load wasthe principal criterion for hull size and load capacity. The deep-est water yet for a production platform called for innovation inthe mooring system configuration.As far as hull design is concerned, “water depth drives

what you are able to do,” said Dennis Jahde, vice president ofoffshore engineering for Enterprise Products Partners LP.Even on land, a 1-Bcf/d gas treatment facility is impressive.

To mount it on a floating platform and place it in the deepwa-ter ocean environment is an exceptional achievement. To avoidhydrates in multiple flowlines that carry large gas volumes atlow temperature and high pressure required the largest mono-ethylene glycol (MEG) reclamation unit. Moving 1 Bcf/d of nat-ural gas through a 24-in. export line will take a topsidecompressor station rated at 75,000 hp.Independence Hub is owned 80% by Enterprise Field

Services LLC and 20% by Helix Energy Solutions Group Inc.and is operated by Anadarko Petroleum Corp. on behalf ofthe Atwater Valley Producers Group.Design, construction, assembly and installation of the

Hub facility moved at an accelerated pace and the completedfacility sailed from Ingleside, Texas, in mid-January.

Central hub, subsea wellsAs exploration and development moved into ever deeper waterin the Gulf, several platform designs that could be applicable toinfrastructure needs emerged, said Bart Heijermans, Helix chiefoperating officer. These include tension-leg platforms (TLP),floating structures and spars.As recently as 1996, most of the structures in the Gulf were

fixed platforms. As greater water depths were faced, platformssupported on the ocean floor were not practical or economicand designers turned to TLPs, spars and floaters.Water too deep for fixed platforms also drove development

of the critical technology that is the companion to a deepwatercentral facility: subsea well completion.As the technology advanced, developments built around the

subsea completion/tieback concept grew faster than platform-based development schemes. By 2005, there were more than 90

Steel catenary riser loads drive hull design, water depth requires mooring system innovation

Independence: The Hub


discoveries developed with subsea wells tied back to a central facil-ity, compared with slightly more than 40 discoveries that had beendeveloped using above water platforms, Heijermans said.The bulk of these tiebacks were to platforms on the rela-

tively shallow Outer Continental Shelf, and the producerowned most of those platforms. Late last year, third partiesowned only two out of 38 producing deepwater platforms.Independence Hub is Enterprise’s third deepwater platform

development, seventh hub-type platform and tenth Gulf ofMexico processing platform. Its success is likely to acceleratethe ownership of deepwater infrastructure by third parties.

Making the basic choiceTo determine the best solution for Independence, the projectteam conducted a design competition that included Technip,which proposed a spar structure; and Atlantia Offshore Ltd.and Aker Kvaerner ASA, both of which proposed deep draftsemisubmersibles.The three companies began the front-end engineering design

study (FEED) in the fall of 2003; each was to deliver a designand a lump sum price for a hull and its mooring. The competi-tion excluded the topsides, because Enterprise was still workingwith the operators to finalize the facility’s nameplate capacity.After an engineering analysis of the bid proposals, the evalua-

tion team put the two deep draft semisubmersibles on a shortlist. Then the team selected the Atlantia Offshore proposal.The two designs were similar, said Heijermans; both were

driven by the loads that the SCRs imposed on the hull in theextreme water depths.One key difference between the proposals was in the way bal-

last water would be moved around each platform. Aker Kvaernerproposed a hull with a variable draft that would be de-ballastedto meet the required wave height and deck clearance design crite-ria in case of a storm. Once on location, however, the hull pro-posed by Atlantia Offshore would not require changes in ballast,even under extreme weather conditions.Both spar and semisubmersible structures can be designed for

a range of payloads, so deck space and weight capacity were notprincipal drivers of the decision to choose a semisubmersible.The spar would likely have had a three-level deck, while the semi-submersible design chosen has only a two-level deck.An important advantage of a semisubmersible is that the

topsides can be installed at quayside. A spar must be taken off-shore and upended. Only then can the topsides be installed, andonly with an expensive heavy-lift vessel often at the mercy ofweather conditions.In the 5-month period before the FEED process was due at

the end of March 2004, the Hub’s design capacity changed twiceto accommodate several new discoveries that could be tied backto the Hub, finally reaching 850 MMcf/d. Eventually, through-put capacity was raised to 1 Bcf/d.


“When we initially bid on Independence Hub, the design gasthroughput was to be 450 MMcf/d,” said Greg Rhodes, directorof deepwater floater development for Atlantia Offshore.Because the platform was designed around the SCRs, the

Atlantia Offshore hull design could adapt relatively easily tothe increased topsides payload as design capacity increasedfrom 450 MMcf/d to 1 Bcf/d. Designing for the SCR loadsresulted in a bigger hull than would have been necessary ifdesigning for the topsides weight.

Hub highlightsSemisubmersible production units are suitable for a rangeof water depths, making them an important tool for deep-water development. A number of floating facilities installedin the Gulf before Independence Hub are in water depths ofabout 6,000ft (1,830m). Independence Hub has expanded thewater depth range with installation in close to 8,000ft (2,440m)of water.Moored by 12 chain and polyester rope anchor lines, each

2.4 miles (3.9 km) long, the semisubmersible is a four-col-umn configuration with a ring pontoon. It is attached to theocean floor with 18-ft (6-m) diameter by 90-ft (27-m) longsuction piles, the deepest yet. Anchor chain is 5-in. diameter,and the polyester rope that makes up most of the mooringlines’ length is 95⁄8-in. in diameter.Outside dimensions of the pontoon hull are 232ft x 232ft

x 160ft (71m x 71m x 49m) high. Columns are 46ft x 46ft(14m by 14m); pontoons measure 38ft x 26ft (12m x 8m).The hull displaces 46,160 tons and has a dry weight of14,370 tons. The operating draft is 105ft (32m).Two decks containing the topsides treating and gas com-

pression equipment, each 140ft x 220ft (43m x 67m), alsoinclude quarters for 16 occupants and 12 temporary workers.

Fabricated in Singapore, the hull contains steel from Italy,Ukraine and Belgium.The topsides treating plant is similar to that on other off-

shore facilities, and compared with onshore processingplants, the process is relatively simple. However, IndependenceHub can treat more gas than any other facility in the Gulfof Mexico.“All we want to do is get rid of the water and dry the gas so

it can be compressed and put in the pipeline,” Jahde said.Hydrates are a concern in deep water where pressures are

high and temperatures are low. Water entrained in the gascan form a hydrate plug that will block flow in the pipeline.Hydrate plugs are also a risk in the subsea flowlines from

wells to the platform. The MEG system sends glycol througha tube in the umbilical bundle to the wellhead where it isinjected into the well stream. The glycol is carried back to theplatform in the well stream where the MEG reclamation unitremoves it.The 3,000-b/d capacity reclamation unit on Independence

Hub is designed to recover 97% of the MEG contained in thewell stream, an efficiency critical to making the project eco-nomically viable.Including the MEG reclamation unit and the platform’s

75,000-hp compressor station, the Hub’s topsides weigh in atabout 8,000 tons. With the lifting apparatus, mating thedeck to the hull required a lift of about 9,000 tons.

Designing for SCRsThemajority of deepwater facilities to date have been designedaround payload – the weight of the deck and topsides equipment.Structures in extreme water depths, especially if they are con-

nected tomany pipelines, require special attention to the weightof the SCRs. Minimizing the fatigue of the risers caused by theplatform’s motion is a critical design goal.Atlantia Offshore usedmodeling and tank tests to determine

how the Hub wouldmove then provided the information to thepipeline designers to determine fatigue life for the SCRs. Designfatigue life is 30 years, but a safety factor of roughly 10makes theactual time to failure longer than the expected life of the facility.Atlantia Offshore’s approach to Independence Hub was to

design a floating facility that could adequately manage theextreme weights that 8,000-ft water depths would impose on theplatform through the SCRs.“That is what drives the DeepDraft Semi design,” Rhodes said.

“Typical drilling semisubmersibles have a draft of 60ft to 70ft(18m to 21m). Independence Hub needed a 105-ft draft to takethe load of the SCRs and adequately manage the SCRs over the20-year life of the fields.”“Aside from the deeper draft, Independence Hub resembles a

typical semisubmersible hull design,” said Chuck Kindel, AtlantiaOffshore’s project manager.

Hub Platform Project Team. Seated (left to right): Mike Gann, Hull;

Jim Guion, Project Manager. Standing (left to right): Paul Barnett,

Installation Manager; Rick Lyon,Topsides; Joe Fontenot, Hull Lead;

Steve Davidson,Topsides Lead.


Initially, there is capacity for 19 SCRs to be hung off theplatform, including the 20-in. for the export line, 12 10-in.flowline risers and four 8-in. flowline risers. More SCRs can beadded if new flowlines are required for future discoveries; theplatform has enough excess payload capacity to tie back up to 10additional fields.When another SCR is added, some ballast will be removed

from the hull to maintain the design wave height anddeck clearance.With a design life of 20 years, the platform is classed and

certified by the American Bureau of Shipping as an A1Floating Offshore Installation. Areas of emphasis in the cer-tification process included platform stability, structuralintegrity and buoyancy after damage while also consideringthe unit’s compliance and readiness in terms of fire-fightingcapability and life-saving equipment.While movement is an important consideration in SCR

design, motion of the platform does not have a significanteffect on process operations. Vessels are baffled, and themovement is not severe enough to cause problems.

Schedule, schedule, scheduleWhat did Atlantia Offshore consider a top priority when choos-ing a shipyard?“Schedule,” Kindel said.Two shipyards in Singapore and one in China were consid-

ered at various stages in the selection process. Operators hadreservations about being the first extreme water depth job forthe China yard, and because of the importance of avoidingschedule delays, the choice narrowed to the two Singapore yards.“As it turned out, we chose the shipyard in Singapore that

gave us the best price and schedule,” Kindel said.At 1 Bcf/d, any construction delay translates into deferred

revenue that is quite costly.After being awarded the Independence Hub contract for its

DeepDraft Semi in mid-2004, Atlantia Offshore struck steel forthe hull at Jurong Shipyard in Singapore in early 2005. The hullleft the shipyard for the trip to Kiewit Offshore Service Ltd.’sfacility at Ingleside, Texas, last May.Mating of the hull and topsides was a critical operation per-

formed by Kiewit Offshore Service Ltd. at their Ingleside, Texas,


facility in September of 2006, utilizing their heavy lift device tolift and set the 8,400 ton deck onto the hull.Additional hookup and commissioning activities continued

during the next several months before the Hub was towed toMississippi Canyon Block 920 in the Gulf of Mexico in Januaryand moored. Signet Maritime Corp. transported the Hub, andHeerema Marine Contractors installed the platform and itsmooring system.Once installed, operations began to connect the platform to

the 20-in. export gas line SCR, to the field flowline SCRs and tothe 12 umbilical bundles coming from the 10 anchor fields.

Mooring is trickyMooring a semisubmersible in extreme water depths is a chal-lenge. The anchor footprint grows larger as water depthincreases. In very deep water, an all-steel chain system would beso heavy that the size of the platform needed to support themooring system would be impractical and uneconomic.At the Independence Hub location, the water certainly

qualifies as “very deep,” putting it beyond the practicallimits of an all-chain mooring configuration.The solution is the use of synthetic mooring lines. Though

still a relatively new technology, polyester rope mooring systemshave been tested and proven in service. Earlier, the U.S. MineralsManagement Service (MMS) and Texas A&M University’sOffshore Technology Research Center (OTRC) joined to testand analyze polyester mooring lines to confirm their reliabilityand safety during a design life of 20 to 30 years.Polyester mooring lines offer a cost advantage compared

with steel chain, depending on depth. As water depthsincrease, polyester quickly gains an advantage, according toan OTRC report. In some cases, there can be savings in theplatform design, too; a larger platform is needed to support achain mooring system.Synthetic mooring lines also can be used in taut mooring

systems where the restoring force for the structure is pro-vided by tension in the lines rather than by lifting a largecatenary length of steel mooring chain.For Independence Hub, mooring lines were installed in three

sections of 3,500ft (763m) each. Each line includes about 200ft(61m) of chain on each end; the rest of the roughly 2-mile (3-km)length of each mooring line is polyester rope. On the platformend, chain is necessary to allow the chain jack to haul in the line;on the other end, MMS regulations prohibit polyester rope fromresting on the seafloor, so a length of chain is needed.Whether the synthetic material can safely rest on the bottom is

an open question. In one case, when rope was accidentally laid onthe bottom on another project, when recovered and tested, itshowed no reduction in strength. But time is an important ele-ment, and that accidental event was only temporary.Polyester ropemooring systems had been installed previously in

theGulf ofMexico although not extensively. Nonetheless, this expe-rience was helpful in securing regulatory approval.

It was still necessary, however, to have test inserts in theIndependence Hubmooring lines to meet MMS requirements.“Polyester mooring design is a more complicated design than

a traditional chain mooring system,” said Joe Fontenot, the hullproject manager.Chain is inelastic and rope is elastic, particularly in regard to

stretch during the long term. It also is easier to determine thestiffness of steel.“In the case of polyester, it is necessary to design for a

range of properties and ensure the platform motions arewithin that range,” Fontenot said. “Stretch is a particularlyunique property. Polyester will stretch under load, so it mustbe preloaded during installation to remove this slack beforegoing into service.”On the Hub, stretch is continuously monitored to deter-

mine when tension in the line needs to be changed.Otherwise, mooring line tension is not changed. It wouldnot, for example, be changed in preparation for or in themiddle of a storm.Heerema was awarded the contract for the installation of

the Hub, mooring piles, mooring lines and SCRs in April 2005and began the work last March. The company applied technol-ogy based on using remotely operated vehicles on which suc-tion pile pumps are mounted and the Baldermooring linedeployment winch.The mooring piles for the platform’s 12 mooring lines are

the deepest permanent mooring piles. The 18-ft x 90-ft (6-mx 27-m) suction piles, with a dry weight of 180 metric tons,were installed at a water depth of 8,011ft (2,442m) using thedeepwater crane vessel Balder.Anchor piles are lowered to the seafloor, then air and water are

evacuated, causing the pile to draw itself into the sea bottom.

Elephant on the topsidesAt its natural gas throughput capacity of 1 Bcf/d, the glycolreclamation facility is designed to recover up to 5,000 b/d ofcondensate and 3,000 b/d water. It is the largest monoethyleneglycol (MEG) reclamation unit installed offshore. The largesystem is needed to reclaim the MEG used to prevent hydrateformation in the flowlines.Design pressure of the gas dehydration process is 2,220 psig.Also on the platform are six gas compressors rated at a total of

75,000 hp. The compressor station can be expanded to 90,000 hp.Solar Inc. supplied the six Mars 100 turbine-driven packages (fiveinitially, one in the future). Two stages of compression will boosttreated gas from 600psi to 3,100psi to enter the export pipeline.It is a large compression facility because the export line must

operate at a pressure higher than is typical for gas lines to movethe design volume through the smaller-than-typical line.


Previous large offshore MEG units include Statoil ASA’sÅsgard facility in the North Sea with three 1,800-b/d units;Anadarko’s Red Hawk in the Gulf of Mexico with a 580-b/dunit; and the Mensa platform in the Gulf with a 750-b/d unit.Petreco Process Systems, a division of Cameron Corp.,

supplied a new proprietary glycol reclamation system forIndependence Hub.In an MEG injection and recovery process, the inhibitor must

be present at the point the wet gas is cooled to its hydrate tem-perature, according to Petreco. Wherever possible, it should beinjected upstream of any chokevalves or chillers. Good distributioninto the gas stream is vital.On the platform, recovered liquid

is fed to the regeneration plantthrough a preheat heat exchangerrecovering waste heat from the leanglycol stream. The preheated liquidis then flashed in a flash drum toallow free vapors to be released andany hydrocarbon liquids to be sepa-rated and drained off.The liquid is filtered prior to fur-

ther heat exchange with regeneratedglycol. The hot, rich liquid flows into the still column where itundergoes the necessary distillation to achieve the requiredproduct concentration in the reboiler.Lean glycol in the reboiler flows over a weir into the surge

drum, which provides a buffer to accommodate variations incirculating volumes.Several design features of the Independence unit provide cost

and weight savings, including:• a single train with spared pumps;• high-flux heat exchangers, heaters, condensers;• high-efficiency structured packing;• high mean temperature difference exchangers;• simplified piping scheme; and

• condensation instead ofvacuum duty.Compared with the dry

weight of the Åsgard facility at740 tons, for example, theIndependence unit weighs only375 tons, providing 40% morecapacity at half the weight.Operating weight of the com-

plete gas treating plant and deckatop the platform is 10,250 tons;dry weight is 8,732 tons.Construction of the topsides

unit was “fairly uneventful,” saidJim Walvoord, site manager for

Enterprise. But there was a certain amount of “designing as webuilt.” Those changes did not involve capacity or the basicprocess, but were changes to facilitate the “constructability”of the topsides. ★

“Polyester mooring designis a more complicated

design than a traditionalchain mooring system.”

Joe Fontenot

Hull Project Manager


Independence Trail, the subsea pipeline that brings gasfrom the Independence Hub platform to a shallow-waterconnection, inspires many of the thoughts associated with

other officially-designated “independence trails” throughoutthe United States – thoughts of conquered frontiers, physi-cally challenging achievements and new freedom to developopportunities.In the Texas Independence Trail Region, encompassing 28

counties from Houston to San Antonio, for example, the storiesof this era are retold at historic sites and museums. The SouthYuba Independence Trail in the Gold Country of California, asthe first wilderness trail in the country with wheelchair accessi-bility, represents another kind of independence. Colorado’sIndependence Trail system includes one of Colorado’s toughesthardcore rock crawling trails.These are notable achievements that continue to motivate

others. So, too, does the 134-mile (216-km) long connectionthat links the natural gas resources in the extreme water depthsof the Gulf of Mexico’s Mississippi Canyon to U.S. consumers.Independence Trail pipeline, beginning in a record-setting

water depth, is the first pipeline available to serve those deepwa-ter discoveries. The vision of Trail, however, goes beyond thatmilestone. With the capacity to handle multiple fields and built

with connections spaced along its length for future finds, itpromises to help accelerate deepwater exploration and develop-ment across a broad section of the Gulf.The pipeline’s vital statistics include:• design throughput of 1 Bcf/d at a maximum allowable oper-ating pressure of 3,640psi;

• 134 miles of 24-in. X-65 grade pipe in four-wall thicknessesranging from 1.35 in. at the Hub facility to 0.95 in. at theshallow water end;

• at the Hub, a 20-in. steel catenary riser (SCR) with a wallthickness of 1.21 in. and 8,300ft (2,532m) of strakes toreduce vortex-induced vibration;

• two dual-tee assemblies to provide connections for pipelinesserving future discoveries;

• 31 pipeline crossings;• about 13 miles (21 km) in West Delta Block 68 thatrequired subsea burial; and

• a four-pile junction platform with two decks in 115ft (35m)of water in West Delta Block 68 that connects Trail to theTennessee Gas Pipeline Co. system.Building infrastructure is often a chicken-and-egg challenge

that poses significant economic risk. As deepwater explorationbegan to accelerate in the 1990s, so did the need to create a

Independence: The Trail PipelinePipeline in record water depth serves Independence area and future finds


pipeline infrastructure to serve new discoveries. When waterdepths approached those of the Mississippi Canyon deepwaterdiscoveries, the challenge intensified.Key to meeting that challenge is to tie subsea wells to a host

platform, making it possible to lower the economic thresholdfor developing new fields. Tieback length varies significantly,but according to the U.S. Minerals Management Service (MMS),most subsea wells are within 10 miles (16 km) of the host plat-form. Late last year, the record length for a subsea tieback was62 miles (100 km) from the host platform.Tieback to a central facility is a concept critical to the eco-

nomic viability of many ultra-deepwater discoveries, includingthose that make up the Independence development.A tieback, however, gets the gas only as far as a deepwater

platform. Moving it to shore where it can be connected with thetransmission and distribution network presents another arrayof challenges.

Stretching the envelopeIn November 2004, Enterprise Products Partners LP executedagreements to provide transportation services to operators BPplc, BHP Ltd., Devon Energy Inc., Anadarko Petroleum Corp.,Dominion Exploration & Production Co. and SpinnakerExploration Co. for their gas production from leases in theMississippi Canyon, Atwater Valley, Lloyd Ridge and DeSotoCanyon areas.Like most other elements of the groundbreaking deepwater

development project, the Independence Trail export pipelinedid not require a step change in subsea pipeline technology, butthe extreme water depth did pose new challenges that called fornew capabilities.There is, for example, only one pipelay vessel that could

install the heavy-wall, 24-in. pipe in 8,000ft (2,440m) of water.Even it had to be modified before it could handle the extremeweights that would be encountered during installation.A combination of extreme water depths and high flow rates

also raised unusual pipeline design considerations. At waterdepths and operating conditions encountered by IndependenceTrail, collapse pressure determined pipe wall thickness, notburst pressure.That proved to be an advantage. Designing for collapse

pressure meant that as the design capacity increased duringthe project because of new discoveries, there was no need toincrease the pipe diameter or wall thickness to handle theadditional gas. Operating pressure could be increased to movemore gas without increasing the burst pressure above thatexerted by the deep water.When collapse pressure controls pipe design, it does, however,

bring into question the need for hydrostatic testing required bythe MMS. At least for Independence Trail, the MMS answeredthat question by requiring the line be hydro-statically tested.

Design highlightsPipeline design begins with a capacity requirement. ForIndependence Trail, that meant matching the Hub’s finalnameplate capacity of 1 Bcf/d.In the early stages of the project, when throughput was

expected to be 850 MMcf/d, the design called for operating theline at about 3,250psi. When capacity was upsized to 1 Bcf/d,the maximum allowable operating pressure (MAOP) of the linewas raised to 3,640psi.“Because the design is based on collapse, it was possible to

increase the MAOP by only changing a few valves on the top-sides part of the system,” said Dennis Jahde, vice president ofoffshore engineering with Enterprise.“The capacity increase did not have a significant impact on

the project because the wall thickness for the original designcapacity was thick enough to resist the external pressure ofdeep water,” said Mike Stark, Trail construction managerwith Enterprise.Collapse pressure in 8,000ft of water, for example, is about

3,560psi. At its normal operating pressure of about 3,400psi,the deepwater end of the line experiences almost no burst orcollapse pressure on the pipe wall.As water gets shallower along the route to shore, the external

pressure on the line will decrease. As the distance from theHub’s compressor station increases, however, the internal pres-sure in the line will also decrease.In addition to the role in design that collapse pressure plays

in water depths such as those encountered in the Independencearea, installation stresses also figure into the design.Configuration of the pipe as it is lowered to the seabed and

Independence Trail Export Pipeline Team. Sitting (left to right):

Mike Stark Project Lead and AndyTorstrick, Project Engineer.

Standing (left to right): CT Gore, PipelineTechnical Support; Glenn

Davis, Chief Inspector;Terry Hutzell, Project Manager WD-68.


the capacity of the lay vessel to pick up the pipe are also keyconsiderations in deep water.Then there is the critical steel catenary riser (SCR) connection

between the seabed pipeline and the Hub topsides. In the case ofIndependence Trail, it was a challenge to find a pipe mill thatcould produce the SCRs to a tolerance that would provide thefatigue life needed.The 24-in. pipe of the Trail on the ocean floor transitions

with a flexible joint to the 20-in. SCR at the top of a flex-jointand connects the SCR to the platform’s topsides. At 13,000ft(3,965m) long, it is the deepest SCR installed. The length of sus-pended pipe that hangs off the platform – the arc of the cate-nary from the platform to touchdown – is 10,500ft (3,203m).That one single hang-off point on the Hub must support

about 650 tons.The SCR is fitted with 8,300ft (2,532m) of strakes to reduce

the effect of vortex-induced vibration (VIV) in the riser. Thestrakes wrap around the pipe in a spiral to break up the cur-rents that cause vibration. A similar steel spiral is often used onsmokestacks to break up wind currents.Vortex-induced motion caused by loop currents passing an

SCR, for example, can cause oscillation that fatigues the riser.Effect of these forces usually diminishes near the seafloor, how-ever, so strakes are not required there. Subsea pipelines installedin areas where the bottom is irregular and bottom currents arestrong can still be subjected to vortex-induced motions.

VIVs occur when motion caused by vortex forces creates a res-onance in the structure. Understanding the vibrations causedby these motions is an important key to designing safe, reliablerisers and moorings for deep water. There is a variety of designprocedures – many of them proprietary – to cope with VIV, andthere are still uncertainties about the phenomenon.

Route challengesVarious routes between Independence Hub and West Delta 68were considered during the planning stage, Stark said.The Continental Shelf drops off quickly in the West Delta

area. During the evaluation of the sea bottom topography, therewas some concern about places where the pipe might span a siz-able distance, and about outcrops and existing pipelines. Toavoid these risks, there were some changes in the route near thedeep and shallow ends.The area around the mouth of the Mississippi River in West

Delta and South Pass regions is also prone to mudslides.Underwater mudslides can be big and dangerous. Earlier, apipeline in the Main Pass area, for example, was broken in twoand moved more than a mile underwater by a subsea mudslide.“To be on the safe side, a section of Independence Trail was

moved to the southwest, away from the area where these slideswere known to occur,” Stark said.There are also 31 existing pipelines to cross along the route.

Care had to be taken to minimize the number of crossings and


ensure they were being made at angles that would make possi-ble a well-designed crossing.At each crossing, a protective mattress was laid over the

existing pipeline and supports placed at each end so thenew pipeline could bridge the line. The concrete flexiblemattresses have an abrasive padding on both sides.After the new line was installed, another protective layer

of mattresses was placed over the crossing to complete it,Stark said.Two subsea dual tees, 16 in. and 12 in., were installed in the

line at water depths along the route of about 6,500ft (1,983m)and 4,500ft (1,373m) to accommodate future tie-ins to the sys-tem. The materials and weight of the tees made installing themin those water depths a challenge.The tee in 6,500ft of water is in an area Enterprise has

researched and sees potential for drilling and development.With these tees in place, an operator could avoid the expenseof having to lay a subsea pipeline all the way to another sur-face facility.“These are strategic areas where we see the potential need for

future connections,” Stark said. “As the initial anchor fieldsdeplete, other fields can be brought into the Trail pipeline.”As the pipeline approached West Delta 68, water depth

decreased to less than 200ft (61m) for the last 13 miles (21 km)of the route. That segment had to be buried to comply withMMS regulations that any pipe in less than 200ft of water be

buried with a minimum cover of 3ft (1m). After the pipe waslaid, it was buried to the required depth with another vesseldesigned for pipe burial.

Procurement, manufacturing“Procuring pipe for Independence Trail was not a small chal-lenge, either technically or logistically,” Stark said.The line required more than 100,000 tons of X-65 grade steel.

With its thick wall and large diameter, not many plants couldproduce the pipe.“The procurement phase was a big part of this project,” he said.Welspun Gujarat Stahl Rohren Ltd. in Gujarat, India, manu-

factured the line pipe from steel milled and rolled into plates inEurope and shipped to India. The plate from Ukraine andAustria was used to form the pipe, then it was welded longitudi-nally with the double-submerged arc welding (d-saw) process.Welspun can produce pipe in diameters from half-in.

to 100- in. outer diameter and is accredited with ISO 9001,ISO 14001 and OHSAS 18001 certifications. The companyis the first in India to supply large-diameter line pipe foroffshore U.S. applications; the first to supply 56-in. X-70line pipe to Iran; and the first to produce grade X-80 linepipe. The company’s longitudinal welded pipe divisionhas a capacity of more than 932 miles (1,500 km) annually,and the spiral welded pipe division has a capacity of 621miles (1,000 km) annually.

S-lay installationAllseas Group Inc. installed most of Independence Trail with itsSolitaire, one of the largest pipeline lay vessels in the world. Theline was welded together on board and deployed in an S-shape laymethod, beginning at the Hub inMississippi Canyon Block 920.A J-lay method of laying pipe has also been used in deepwa-

ter; in fact the method was used by another vessel to installsome of the flowlines in the Independence fields. Because of thelength of Independence Trail and Solitaire’s capability of usingthe S-lay method, it was selected for the export line, Stark said.Since 1986, Allseas has completed pipelay and trenching con-

tracts for projects ranging from straightforward pipeline installa-tion jobs to design, installation and engineering; procurement;fabrication; and large subcontracts for diving, dredging androck dumping.As advanced as Solitaire is, however, it had to be modified in

four key areas to handle the installation of Independence Trail:• three new tensioners were installed to support the weight ofthe extra heavy pipe, raising the tension capacity to 1,050 tons;

• a new abandonment and recovery system, also with a 1,050-ton capacity was installed;

• a new radius stinger more than 400ft (122m) long was man-ufactured and installed to support the pipe in an S-lay con-figuration; and

• to absorb some of the increased weight on the stern of thevessel, 4,000 tons of hull buoyancy was added.Solitaire began to lay pipe last April from the Hub end of the

line and completed its part of the job inmid-August. The SCRwaslaid first and tied off to a suction pile on the seafloor to be recov-ered later by HeeremaMarine Contractors’ Balder vessel when theHub was in place.“From the Hub location, the Solitaire began laying away, dou-

ble joint by double joint, beginning with the heaviest wall pipeand moving toward shallower water,” Stark said. The pipe waswelded together in a horizontal position on the ship, then fol-lowed an S-shape path as it left the vessel, first going throughthe over bend, then the sag bend as it reached the seafloor.At the location of the inline tees, the tee assembly had to be



installed during the laying process. Each tee, outfitted with spe-cially designedmudmats opened on the seafloor, as it was laidthrough the stinger.Solitaire laid the line toward shore until it reached a water

depth of about 1,000ft (305m), then the Allseas lay vessel Lorelayreplaced it. To make the exchange, Solitaire installed a valve andlaid the pipe on the bottom; Lorelay picked up the pipe and com-pleted the last 48 miles (77 km) of the line to the platform inWest Delta 68.The primary reason for switching vessels was to facilitate

scheduling of Solitaire’s work elsewhere.After the Hub was on location and all the moorings con-

nected, Heerema hooked onto the attachment point at the endof the Trail SCR, raised it and connected it to the hull in theflex-joint receptacle.

Top-of-the-line vesselsSolitaire, the largest pipelayvessel in the world, has set newstandards for offshore pipelineinstallation. Based on the samedesign principles as Lorelay,Solitaire’s ship shape providesexcellent workability. It has a pipe-carrying capacity of 22,000 metrictons, making it less dependent onoffshore pipe supply in remote andhostile environments.Solitaire has laid numerous deep-

water pipelines and set a series ofdeepwater records. Precise maneu-vering on full dynamic positioningallows Solitaire to work safely incongested areas. Its high cruisingand lay speeds make it competitive.Since the vessel became operational in 1998, it has steadily

improved its performance; a lay speed of more than 6 miles/day(9 km/day) has been achieved operating the in-house-developedPhoenix automatic welding system.The vessel features:• transit speed of 13 knots;• accommodation for 420 people;• dynamic positioning system;• two pipe transfer cranes, each rated at 35 tons at 108ft(33m), a whip hoist rated at 18 tons at 139ft (42m) andother cranes;

• two double-jointing plants, seven welding stations for dou-ble joints, one non-destructive testing station and two coat-ing stations; and

• the capability to lay pipe diameters from 2 in. to 60 in.Lorelay was the first pipelay vessel to be equipped with

dynamic positioning, beginning a new generation of deepwater-capable vessels. Like Solitaire, Lorelay’s ship shape gives it a highcruising speed; a large pipe storage capacity makes it lessdependent on offshore supply. The vessel is able to position pre-cisely and safely.Overall length of the dynamically positioned vessel is 600ft

(183m) and it can accommodate 216 personnel. Transit speed is16 knots. It mounts one heave-compensated mast crane, with acapacity of 300 tons at 46ft (14m) and one pipe-transfer crane,with a capacity of 16 tons at 108ft (33m). The welding lineincludes seven single-joint stations, one X-ray station and onecoating station.Three tensioners are rated at 55 tons each at 66ft/minute

(20m/minute). A fourth tensioner rated at 100 tons is aft of thecoating station. Lorelay can lay pipe with diameters from 2 in.to 36 in.

The West Delta connectionDuring the early stage of the proj-ect, Enterprise considered the pos-sibility of connectingIndependence Trail to an existingplatform to tie into the TennesseeGas Pipeline network.“But there was not a platform in

West Delta that fit our needs, sothe decision was made to build anew junction platform there,”Stark said.The jacket and deck for the

West Delta 68 platform weredesigned by Alliance Engineeringand fabricated at DynamicIndustries Inc. in New Iberia, La.

The 350-ton jacket was placed last June and the 820-ton deckinstalled in early October. Then saturation divers completedthe subsea tie-in from the pipeline to the pre-installed riser onthe platform jacket.Tennessee Gas Pipeline installed two short sections of pipe to

connect the platform subsea to the Tennessee Gas Pipeline linethat brings the gas ashore.Compared with other elements of Independence, the small

four-pile platform in 115ft of water might be called “ordi-nary,” said Terry Hutzell, construction manager for theWest Delta facility.It still, however, is an important component of the

Independence system, adding the final link in the chain thatconnects deepwater gas reservoirs to markets.The 375-ton jacket was placed at its offshore location

while final fabrication of the deck equipment was being com-pleted, as installing the deck equipment was easier to do

“But there was not a platformin West Delta that fit our

needs, so the decision wasmade to build a new junction

platform there.”Mike Stark

Enterprise


onshore than offshore. The jacket was installed in a firstmobilization. Two months later, in late October, after deckmodifications were completed, a second mobilizationinstalled the deck.“The West Delta platform was pretty straightforward,”

Hutzell said. “These, days it would be con-sidered a plain vanilla structure.”West Delta is equipped with a 24-in.

pig receiver that can catch pigs fromIndependence Trail and two launcherscan send pigs through the 20-in. and 24-in.lines to the Tennessee Gas Pipeline mainline. A flowline heater is mounted on theplatform to accommodate the cooling thatoccurs when the pipeline is started up aftera shutdown.There also are quarters for four men.West Delta 68 platform has its own

control system and can communicate withIndependence Hub. In case of a Hub shut-down or a blockage in the Trail pipeline,low pressure in the pipeline will automati-cally shut down West Delta.

Commissioning, startupWith the SCR in place, Independence Trailwas pigged, filled with water and the finalspool that ties the SCR into the Hub pipingwas installed. When that flange-to-flangeconnection was complete, the line washydro-tested. Then water was forced out ofthe pipeline by moving it from the Hub toWest Delta junction with air produced by avessel-mounted dewatering system capableof 10,000 ft3/minute (283 m3/minute) CFMat 5,000psi.“It was a very technical operation,”

Stark said. “The hydrotest was not a prob-lem. The issues were the technical require-ments, time and expense required to get thewater out of the line after testing.”It was necessary to pressure the line to

4,500psi, exceeding the maximum allowableoperating pressure, to pump the water out.Finding compression capacity to produceenough air to move the water out of the linewas also an issue.“It was necessary to have a fairly large ves-

sel alongside the platform for an extendedperiod,” Jahde said.When the line was dewatered, purged

with nitrogen and dried, gas was back flowed from theTennessee Gas Pipeline line to the Independence Hub to powerup and commission the Hub. The pre-commissioning processtook about 3 months, then the project was finally ready todeliver gas to West Delta 68. ★


Throughout the decades since the concept was first devel-oped, subsea completion technology has made spectacularadvances, becoming one of the most important tools for

making smaller deepwater reserves economic.Shallow-water subsea completions are also a significant part

of the Gulf of Mexico well population, according to the U.S.Minerals Management Service (MMS). The agency reports thatthere were fewer than 10 subsea completions per year in theGulf until 1993, but the number increased dramaticallythroughout the rest of the 1990s.Shallow-water subsea completions accounted for 151 of the

348 total subsea wells in the Gulf by year-end 2005. Nearly 70%of the subsea trees are in water depths less than 2,500ft (762m).Operators have found subsea tiebacks to be attractive for

shallow-water marginal fields in the Gulf because of the exten-sive infrastructure of platforms and pipelines.Increasingly, however, the industry relies on subsea technol-

ogy to develop fields in deep water. Early last year, the MMSreported that about 350,000 b/d of oil and 1.7 Bcf/d of gascome from deepwater subsea completions in the Gulf. Theyaccount for about 34% of deepwater oil production and about50% of deepwater gas production.According to MMS data, the deepest subsea completion in

the Gulf was in 350ft (107m) of water until 1988, when thewater depth record jumped to 2,243ft (684m). Successiverecords were set in 1996 at 2,956ft (901m), in 1997 at 5,295ft(1,614m) and later at 7,591ft (2,313m).Now Independence sets a new mark. Its deepest subsea tree,

Independence:The Subsea InfrastructureComplex subsea architecture ties 15 widely spaced wells to central platform


in the Cheyenne field, is in 8,960ft (2,733m) of water; otherproducers are in water depths ranging from 7,925ft (2,417m)to 8,950ft (2,730m).

High techBecause the Hub platform is so visible, it tends to get much ofthe attention focused on the Independence project, but the sub-sea infrastructure is a large, complex, highly technology-drivensystem. Though the gas throughput – and the equipment onthe Hub platform needed to handle it – is the Gulf ’s largest, thesubsea complex arguably contains more advanced technology.The ocean floor network includes miles of flowlines,

sophisticated wellhead trees, a leading-edge umbilical systemand covers an area that spans 75 miles (121 km) between thenorthernmost and the southernmost fields.Key statistics for the system are:• a total of 225 miles (362 km) of flowlines that connect 15subsea wells from 10 fields to the Hub;

• an umbilical package that contains about 1,300 miles(2,092 km) of stainless steel tubing; and

• four manifolds, 26 jumpers and 23 flowline sleds.Front-end engineering for the system began in January 2004,

while discoveries were still being made in the Independencearea. Long lead-time components were ordered in late 2004 andearly 2005. The first flowline started installation in late 2005.System architecture underwent some change as the

process evolved.“The subsea effort began with a FEED [front-end engi-

neering and design], which determined the best seafloor lay-out,” said Pete Stracke, subsea project manager with HydroGulf of Mexico.With the wells spread over a large number of blocks, and

usually not in concentration areas, a variety of system archi-tecture options was studied.

Flexibility and consistency“We ended up with a layout that grouped the wells that were inrelatively close proximity, and then brought them to the Hubwith their own shared flowline and umbilical system. This opti-mized the number of risers that were required,” Stracke said.Wells from different fields with different ownership are con-

nected at various points and commingled in the same flowline.That makes measurement a critical part of the system. There is

a subsea meter on every well that allocates production to eachdevelopment combined in a shared flowline. “That’s one of themain features of the system’s architecture,” Stracke said.It was important to have consistency in the metering – using

the same meter for all wells – because they are the basis for allo-cating each company’s production. Several meters were evalu-ated, and wet gas meters produced by Roxar AS appeared tohave the advantage, he said.

Of the 15 wells to initially be produced back to the Hubthrough 8-in. and 10-in. flowlines, some produce into a singleflowline and some are connected to a dual flowline system,depending on the number of wells in the region. Operatingpressures are similar for all the flowlines, in the range of8,000psi.All the flowlines had been laid by early this year. After the

Hub platform was moored on location, the flowlines and theexport line were hung off.The flowline connection system, M-shaped jumpers with

flowline connectors, is not very different from what has beenused in other developments.“There have been technical challenges because the develop-

ment is in a record water depth,” Stracke said. “But in general, asfar as architecture and major hardware, it was not necessary totake a big leap beyond what had been done. Most of the waterdepth-related challenges have come in the area of installability.”It is not as if the industry just became aware of the needs of

ultra-deep water.“The industry has been preparing for 10,000-ft [3,050-m]

water depths for awhile now,” Stracke said. “For example,when tree manufacturers were building equipment for 6,000-ft[1,830-m] water depths, drilling was already being done indeeper water. Manufacturers took the view that if they weredoing a design for 6,000ft, they might as well design for10,000ft.”As a result, valves and other components for Independence were

already type-rated for the Independence system’s water depths.“But there were a few items that had to be qualified, including

ball valves in the flowlines,” he said.FMCTechnologies Inc. supplied horizontal wellhead trees for

each well, and all the flowline connectors and valves.

Subsea Team. Front (left to right): Paul Beer, Chad Brown, Marcy

Luciani, Carlos Gonzales, Mark Kurtz. Back (left to right): Basim

Mehka, John Anderson, Eric Olson, Bill Clegg, Paul Drake. Not

Pictured: Pete Stracke.


Many of the wells were drilled as exploration wells before therewas an Atwater Valley Producers Group, so wellheads were thechoice of individual operators. Though suppliers varied amongthe operators, the wellheads were all consistent with the FMCtree the project team chose as the standard.Beginning with the tree, the Independence subsea system

becomes basically standard among all the operators, althoughthere are some options. In addition to glycol injection, mainte-nance provisions vary slightly among operators. Though notincluded in every field’s system, there are provisions for wax inhi-bition, corrosion inhibition and anti-scaling.Usingmetering valves onmost wells will reduce the amount of

umbilical tube needed, for example, where five wells are served byone umbilical.“That has saved quite a bit ofmoney,” said Bob Buck, Anadarko

PetroleumCorp. senior staff production engineer.The valves will control monoethylene glycol (MEG) rates at

each well and control injection rates for paraffin inhibitor andscale inhibitor.Since production is a dry gas, flowlines are not insulated.

Each well has a subsea choke. Some of the flowlines are pig-

gable, though it is not expected that pigging will be required.There are no plans for routine operational pigging.Pigging is possible where there is a dual-flowline system,

however. In that case, there was very little added cost in makingsure the turns and curves were of a diameter that will accommo-date a pig.Flowlines were filled with water and hydrotested after being

hung off the Hub platform. Then most of them had to bedewatered and dried. Only a couple of small infield lines onthe outskirts of the system, where the volume of water issmall, had methanol added to the test water and dewateringwas not required. The water flowed to the Hub after startupand was removed.

Carbon fiber: stronger, lighterIndependence wellheads and subsea trees are relatively “standard.”The newest technology in the subsea system is in the umbilical net-work, said Richard Fowler, vice president of deepwater develop-ment withDominion Exploration& Production Inc. The umbilicalbundle includes tubes for hydraulic fluid,MEG, chemical injec-tion, and power and signal wiring.


“Installation of the umbilical in these water depths was achallenge,” he said.Putting steel in 9,000ft (2,745m) of water under its own

weight is problematic. Even more risky is the copper wire usedfor transmitting power and electrical control signals; duringinstallation, copper would break in 9,000ft of water from theweight of the wire beneath it. In addition, copper must go allthe way to the seafloor.Kvaerner ASA’s Kvaerner Oil Products (KOP) division,

which built the umbilical system, applied new technology tothe problem. The KOP contracts to supply about 134 miles(215 km) of steel tube umbilicals, the largest individualumbilical project awarded, had a value of about $100 million.The Independence subsea umbilical system makes a step

change in deepwater umbilical technology by using KOP’scarbon fiber rod design. The carbon fiber rods are roughlythe same strength as steel but lighter, so they can absorbmuch of the tension in the umbilical while reducing weight.Independence umbilicals have between 20 and 64 carbon fiberrods to help cope with the hang off weights involved in suchdeep water.

In 2005, KOP was awarded a Spotlight on New Technologyaward at the Offshore Technology Conference for its design ofthe Carbon Fiber Reinforced Steel Tube Umbilical. The technol-ogy is a spin-off from composite riser and tether technologypreviously developed by Aker Kvaerner and ConocoPhillips.First used in the Independence project, the system was manu-

factured and delivered from KOP’s umbilical plant inMobile, Ala.As part of the scope, KOP delivered 15 control modules to

be mounted on subsea trees and two control modules for sub-sea manifolds. Also included in the contract is a lease agree-ment under which KOP provides an integrated control systemfor well intervention and workover.Previously, the approach to designing umbilicals for deeper

water was to put more armor on the outside for strength. Butdoing this addedmore weight, then still more armor was needed.“Soon you have a diminishing return,” Stracke said.

“But with carbon fiber, the umbilical is not getting heavier.Carbon fiber provides strength in tension without addingsignificant weight.”In addition to the carbon fiber rods, electro-hydraulic

control systems are carried in the umbilical. Tubing provides


low-pressure and high-pressure hydraulic fluid supply, wellannulus access and the ability to inject chemicals. Dependingon the umbilical, there are a variety of electrical cables to supplypower and control signals.Polyvinyl chloride “profiles” run the length of the umbilical to

separate and position all those components within the outersheath. There is no armoring on the outside of the umbilical andno insulation.“In that regard, Independence is kind of standard,”

Stracke said. “The newest thing is the use of the carbon fiberrod technology.”In July last year, subsea engineering and construction con-

tractor SubSea 7 began installing the umbilical system underan installation and commissioning contract with Anadarko

and Dominion. The contract was for the installation of thecontrol system umbilicals, hardware and flying leads for thetie back of seven fields consisting of a total of 11 umbilicalstotaling more than 106 miles (171 km) in length. The scopealso included the ancillary equipment including the installa-tion of three manifolds, 18 jumpers and 17 flying leads.Last year, Hydro Gulf of Mexico LLC awarded Aker

Kvaerner Subsea a $10-million contract to deliver its advancedumbilical system, including engineering and project manage-ment, for the Q field development. Aker Kvaerner Subsea sup-plied a 12-mile (19.5-km) steel-tube, carbon-fiber-enhancedumbilical, including all surface and subsea terminations, to tieQ back to the Hub.In another unique feature of the Independence subsea sys-


tem, Dominion can distribute the MEG at the well location, afirst for the company, though not for industry, Fowler said.One tube runs from the Hub to a location near the wells, thenindividual tubes will run from that point to each well. Theapproach significantly reduces the amount of tube needed.

Wellhead treesFMC was awarded the contract in 2005 to fabricate 11 of itsenhanced horizontal (EXHT) subsea wellhead trees forIndependence wells; the contract allowed for additional wellsto be outfitted with the same tree.In addition to the trees, the scope of work included supply-

ing one two-slot manifold, one four-slot manifold and onefive-slot manifold. Valves and hubs for 26 inline sleds and 26jumpers were also included. FMC also was responsible for sys-tem integration, testing, installation assistance, service andmaintenance.Satellite wells positioned some distance from the central

manifold were tied-in by use of rigid jumper spools, which alsoconnected other subsea structures. The jumper spools have avertical collet connector at each end. Installation of thesespools is done by a simple crane operation assisted by remotelyoperated vehicles (ROVs) when required.FMC’s EXHTwellhead trees are rated for 10,000psi working

pressure and have a 5-in. bore. The trees are available in 10,000psiand 15,000psi pressure ratings, in standard and drill-through con-figurations. The drill-throughmodel allows a 133⁄8-in. casinghanger to be installed and retrieved through the tree. All EHXTtrees are rated for 10,000-ft water depth.Themodular, standardized design and stocking program allow

customized configurations to be produced quickly for a variety ofapplications. By last year, these subsea trees had been installed onmore than 150 wells, according to FMC. At Independence, the10,000-psi tree is installed in a record water depth.Enhancements to the system include the tubing hanger and

tree cap designs. The traditional pressure-containing internaltree cap has been eliminated, and its pressure-containing barri-ers have been moved to the tubing hanger. This enables the treecap to be installed by an ROV off the drilling rig’s critical path,after the blowout preventer (BOP) has been disconnected fromthe tree.Among the benefits of the system, according to FMC, are:• reduction in installation time by 2 days or more;• lower installed cost;• increased safety since the subsea test tree (SSTT) system isrun only once, minimizing rig floor work; and

• simplified interface with the SSTT and BOP stack.

Laying flowlinesThe 15 wells in the Independence project are tied back to theHub initially through seven different flowlines. Two of the

developments will have a dual-flowline system.In late 2004, Anadarko, Dominion and Kerr-McGee Corp.

selected Tenaris S.A. to supply 19,100 metric tons of 8-in. and10-in. pipe and selected Sumitomo to supply 20,100 tons ofpipe for flowlines and risers to connect the group’s wells toIndependence Hub.Strict tolerances were required to minimize the risk of

fatigue in the extreme water depths. Tenaris deliveredthe pipe during a 7-month period from May throughDecember 2005 and supplied bends for the project on anas-needed basis.Beginning with the Spiderman, Jubilee, Vortex and

Cheyenne fields, Allseas Group Inc.’s Solitaire lay vesselinstalled about 55 miles (88 km) of 10-in. flowlines and steelcatenary risers along with two inline pipeline end manifolds.They are the deepest flowlines that have been laid.Solitaire, the largest pipelay vessel, is capable of precise

maneuvering on full dynamic positioning, allowing it towork in congested areas such as that which existed in theIndependence area. It also has a high laying speed; it has laidmore than 6 miles (9 km) a day using Allseas’ Phoenix auto-matic welding system, according to the company.In March last year, the Allseas vessel Lorelay began

installing the 8-in. flowlines in Spiderman, Jubilee Vortex,Cheyenne and Merganser fields. Lorelay was the first pipelayvessel to operate on dynamic positioning. Its ship shapeallows a high cruising speed, and a large pipe storage capacitymakes the vessel less dependent on offshore supply.Heerema Marine Contractor’s Balder vessel was contracted

to install 24 miles (39 km) of 8-in. flowline in Atlas, Mondoand Spiderman fields and 7.5 miles (12 km) of 8-in. in SanJacinto. Three subsea manifolds were installed at Spiderman,Jubilee and Vortex fields to gather production from the fields.

Scheduling the armada“One thing we’re proud of is our scheduling,” Stracke said. “Atone time, we had the Solitaire, Lorelay and Balder doing con-struction activities while theDeepwater Millennium was doingcompletion work.”When theMillennium was at work, the site was not accessible

for work by other vessels.In addition, anchor-handling vessels were in the area, and

subsea trees were being installed. There also are always supportvessels, but no one ever had to step aside for someone else.That’s an impressive achievement, Stracke said.“As long as work is being done on different wells at the same

time, you are OK. The challenge is to create a schedule thatmakes that happen,” he said. “We have been pleased with ourability to schedule so no one had to wait on someone else.”By late last year, 90% of the flowlines and half the umbilicals

had been laid. ★


Independence is what it is because of the nature of the area’sdiscoveries. In most environments, all would be nice bigfinds that would justify a sizable capital investment by each

operator to get its field on stream as fast as possible.But “most environments” do not include 8,000-ft to 9,000-ft

(2,440-m to 2,745-m) water depths far from a pipeline connec-tion. In that extreme situation, an operator needs more than a“nice” discovery to pay for a stand-alone development.In the old model, such frontiers were left to the largest com-

panies because they could afford to bet on finding an elephantfield that would support its own offshore infrastructure.Independence represents a new business model in which

operators with discoveries that might otherwise be marginal –or might be too financially daunting – join to form a criticalmass of reserves and share facilities.Though it still requires a large chunk of capital from compa-

nies with impressive resources, Independence might bedescribed as a project “for independents, by independents.”“Independence is the model that we’ll be looking at increas-

ingly in the future,” said Scott Jenkins, manager of supplyappraisal for Enterprise Products Partners LP. “The portfolioapproach that made these discoveries economically viable willmake more fields commercial and open doors to allow morecompanies to participate.”It is important to approach this type of opportunity on a

portfolio basis, Jenkins said. “Some fields will do better, some

worse, than the estimate. But based on analysis and experience,on average, the portfolio will make money,” he said.Though the commercial agreement that now unites four

operators and a midstream partner is a landmark achievementand a critical first step, such collaboration still poses uniquechallenges, from choosing a “standard” wellhead to accuratelymeasuring individual well output.When 15 wells in record water depths, some separated by as

much as 70 miles (113 km), must be connected to the centralfacility, the subsea infrastructure becomes a massive undertak-ing that requires leading-edge technology.To make the partnership work, each producer assembled

integrated teams of geologists, engineers and geophysicists.“It was very much a team effort within each of the compa-

nies, as well as in the broader integrated project team thatguided the project as a whole,” Jenkins said.One discipline or person cannot possibly know enough

about every technology available. “And people are much better‘cross trained’ than they were 20 years ago,” he said.

Fuel for deepwater growthThe growth of deepwater exploration and development has beendriven by relentless growth in oil and gas demand, and

Independence:The Fields and ReservoirsSteep learning curves boosted exploration success as well as drilling and completion efficiency.


by steadily advancing technology and expanding operating capabil-ities. Deep water has a special allure to tempt explorers and devel-opers: the average deepwater gas completion produces at abouteight times the rate of the average shallow-water gas completion,according to the U.S.MineralsManagement Service (MMS).Independence represents the current state of many offshore

technologies as well as the latest conceptual thinking abouthow to make more discoveries economic.Much of the story of Independence begins with MMS Sale

181, held Dec. 5, 2001. Though regional geological and geo-physical analysis had been done prior to Sale 181 and leases hadbeen awarded much earlier, the sale helped deepwater activitygain momentum.In that sale, a total of 95 tracts received high bids totaling

$340 million and the MMS awarded 95 leases. Average high bidper acre was $622, compared with $93 for Western Sale 180 in2001, and $185 for Central Sale 178, Part 1, in March 2001. All95 tracts receiving bids in Sale 181 were in water depths greaterthan 5,249ft (1,600m). The deepest tract bid on was LloydRidge Block 446 in 9,541ft (2,908m) of water.

Anadarko Petroleum Corp. received 26 leases with total highbids of $136million. Kerr-McGee Corp. received 16 leases withbids totaling $35million.The deepwater Gulf of Mexico became more attractive in part

because of economic incentives to explore there, and the dra-matic increase in the acquisition of 3-D seismic data which nowcovers most of the deepwater Gulf, according to the MMS. And4-D (time-lapse) seismic technology is poised for routine appli-cation in the region to characterize reservoirs, monitor produc-tion efficiency and estimate recovery.

Regional reservesIt is estimated that the 10-anchor fields tied back toIndependence Hub will ultimately produce about 2 Tcf of drynatural gas. Reserves potentially served by Independence Huband Independence Trail, however, could be much more.

“If adjacent areas are opened, well over 2.5 Tcf could come toour project,” Jenkins said. “And there could be more gas,depending on how far east and south leases are offered.”In addition to the fields that will initially anchor

Independence, a significant number of leases in the regionhave not yet been drilled.“We are aware of at least 30 more seismic leads that remain

untested (as of late 2006),” Jenkins said.Legislation passed late last year will significantly expand the

potential of the region, making as much as 8 million acres avail-able for leasing in the area.That potential does not include gas that might be tied into

the Independence Trail pipeline at the subsea taps installed attwo points along the route to theconnection with Tennessee GasPipeline in West Delta Block 68.Fields connected to these taps willlikely have their own platform.Even though some pipeline

projects get off to a slow start, alook back after 25 years of opera-tion often reveals the “most likely”initial resource estimates wereconservative, Jenkins said.“Not all individual fields will

perform equally, but a portfolioapproach can make a projectviable,” he said.

Field highlightsInitially, the first 15 wells con-nected to Independence Hub willtake virtually all of the platform’scapacity. When those wells beginto decline, additional wells drilledin the anchor fields and additional discoveries can be tied backto the Hub to keep it operating near capacity.Fifteen wells have been drilled in the anchor fields, and addi-

tional wells are likely to be drilled, depending on how many areneeded to optimize recovery. Though the wells and the reser-voirs they tap have many similarities, they are all unique.Anadarko is operator of eight of the 10 fields: Atlas, Atlas

NW, Jubilee, Cheyenne, Mondo NW, Merganser, Vortex andSpiderman. Dominion Exploration & Production Inc. operatesSan Jacinto and Hydro Oil and Energy Division operates Q.Anadarko discovered Atlas (Lloyd Ridge Blocks 49/50) in

2003, and Atlas NW (Lloyd Ridge Block 5), a satellite field, in2004. Both are 100% owned. The company also made the Jubileediscovery (Atwater Valley blocks 305/349 and Lloyd Ridgeblocks 265/309) in 2003 and holds a 100% interest in the field.The Mondo NW field was discovbered in 2004 (Lloyd Ridge

blocks 1/2) and Anadarko is operator with 50% ownership andthe remaining interest is owned by Murphy. Anadarko alsoowns a 100% interest in the Cheyenne field (Lloyd Ridge Block399), which was discovered in early 2005.Merganser, the hub’s first discovery (Atwater Valley blocks

36/37), was made by Kerr-McGee in 2001 in a water depth of7,933ft (2,420m). Anadarko is the operator and shares the work-ing interest in this field equally with Devon Energy.Spiderman (DeSoto Canyon blocks 620/621) was discovered

in 2003. Anadarko, as operator, holds a 45% working interest.Dominion holds 37% and Hydro, since its acquisition ofSpinnaker, holds 18%.Anadarko owns 100% of Vortex (Atwater Valley blocks

217/261 and Lloyd Ridge blocks177/221), discovered in late 2002.San Jacinto (DeSoto Canyon

blocks 618/619) was discovered byDominion in April 2004. Dominionhas a 53% working interest, alongwith Hydro’s 27% acquired withSpinnaker and Anadarko’s 20%working interest, acquired with theKerr-McGee merger.Hydro, with a 50% interest, will

operate Q (Mississippi Canyonblocks 960/961/1004/1005), themost recent discovery to be tiedinto Independence Hub. Dominionowns the remaining interest.Some of the discoveries now part

of Independence were made onleases won years earlier. The MondoNW tract, for example, was won inSale 116 in 1988; Vortex in Sale 157in 1996; Jubilee in Sale 166 in 1997;

and Merganser in Sale 175 in 2000.Atlas, AtlasNW, San Jacinto, Spiderman andCheyennewere on

leases won in Sale 181. Qwas discovered on a lease acquired in 2004.The fact that many of these leases were acquired years ago

shows the industry’s vision and eagerness to develop the poten-tial of deep water. It took some time, however, for deepwaterproduction technology and economics to catch up with thevision; the first wells now in the Independence project were notdrilled till 2001.

Atlas and Atlas NWWhen Anadarko discovered the Atlas field in June 2003, itencountered 180ft (55m) of gross pay in nearly 9,000ft of water.Atlas, in Lloyd Ridge Block 50, is about 175 miles (282 km)southeast of New Orleans and about 18 miles (29 km) fromthe company’s Jubilee discovery, made earlier that year.

“The portfolio approach thatmade Independence discoveries

economically viable willmake more fields commercialand open doors to allow more

companies to participate.”Scott Jenkins

Enterprise



The Atlas well was spudded inMay 2003 using Transocean Inc.’sDeepwaterMillennium drillship. It was drilled to the target depth of19,800ft (6,039m) and thin-bedded reservoirsmade upmuch of its180ft (55m) of gross pay. The Atlas well reached total depth in 21days, at a total drilling cost that was well under budget.Anadarko’s Atlas and Jubilee discoveries were made with two

successful wells of three wildcats drilled in its eastern Gulf ofMexico program. It was apparent at the time that both discover-ies would need to be part of a larger development project to becommercial, according to Anadarko.

JubileeAnadarko discovered the Jubilee field in 8,800ft (2,684-m) ofwater. The well encountered 83ft (25m) of net pay and wasdrilled to the target depth of 18,310ft (5,585m). True verticaldepth of the well is 17,800ft (5,429m).When Anadarko announced the discovery, the company

estimated reserves at 250 Bcf to300 Bcf of natural gas. Anadarko’sprospects in the eastern Gulfincluded two different types of plays– structural and stratigraphic traps.“The eastern Gulf of Mexico is

some of the most prospective acreagecurrently available in the UnitedStates,” said Anadarko President andChief Executive Officer Robert J.Allison Jr., at the time. “But it is stillwildcat exploration.”

MerganserKerr-McGee discovered Merganser180 miles (290km) south of Mobile,Ala., in a water depth of 7,933ft (2,420m). The well penetratedfour high-quality Miocene reservoirs, each with excellent flowcharacteristics.The exploratory well was drilled to 21,268ft (6,487m) and

encountered about 150ft (46m) of gas pay, according to Kerr-McGee at the time.Merganser was drilled under the deepwater exploratory drilling

joint venture between Kerr-McGee andOcean Energy Inc. thatcalled for the two companies to jointly explore and develop oil andgas prospects onmore than onemillion undeveloped acres in thedeepwater Gulf. Devon acquired Ocean Energy in 2003.

San JacintoDominion announced the discovery of natural gas at the SanJacinto prospect in DeSoto Canyon Block 618 in April 2004. About140miles (225 km) south ofMobile Bay, the well was drilled to atotal measured depth of 15,829ft (4,829m) and encountered about100ft (31m) of net pay inmultiple reservoir sands. San Jacinto is

only 6miles (10 km) from the Spiderman discovery.In November 2004, Dominion and its partners drilled a suc-

cessful appraisal well at San Jacinto, encountering about 100ftof net pay in the same multiple reservoir sands. The well wasdrilled to a measured depth of 18,075ft (5,513m), cased to totaldepth and temporarily abandoned for use as a producer.

SpidermanThe Spiderman field was discovered in November 2003 with a welldrilled in 8,100ft (2,471m) of water to a total depth of 18,065ft(5,510m). It encounteredmore than 140ft (43m) of net pay.

VortexAnadarko and Kerr-McGee each held a 50% working interest inthe Vortex field, located in a water depth of 8,344ft (2,545m).The exploration well penetrated about 75ft (23m) of high-qual-ity pay in a Miocene-age reservoir.

Combination traps“Geologically, the Independenceregion is an above-the-salt play,”Jenkins said.The discoveries in the Miocene

age rock depended in part on“bright spot” analysis, a technologydeveloped in the 1970s andupdated with experience andtoday’s seismic technology.“The vast majority of what we’ve

seen that has commercial pay hassome sort of seismic amplitudeanomaly, or bright spot. It lightsup on seismic. It’s above the salt,

so it is pretty easy to see,” he said.“The play took a concept from the 1970s, pushed it out into

8,000ft of water, and added the advantage of 3-D over 2-D seismic,as well as other technology enhancements developed over the past25 years,” said Dan Semetko, principal geologist with Enterprise.TheMiocene is one of themain deepwater horizons in the Gulf

ofMexico, but most of the deepwater is oil-prone rather than gasprone. Pays in the Independence fields are in a “combinationtrap,” a blend of stratigraphic and structural trapmechanisms.There are some false positives, Jenkins said. In fact, the

Independence region was originally thought to be an oil play. Ittook six wildcats to make the first commercial discovery, only a17% success rate. After that first discovery, however, 12 of thenext 19 wildcats were successful.“Explorers quickly figured out what worked,” Semetko said.Geology varies in detail among the fields that make up

Independence. Some wells have multiple pay zones, others a sin-gle pay, some cover a relatively large areal extent, and others

“The eastern Gulf of Mexico issome of the most prospectiveacreage currently available

in the United States.”Robert J. Allison Jr.

Anadarko


cover a smaller area. In some cases, zones that cover a smallerarea with a thicker pay have roughly the same reserves as wellsthat cover a larger area.Porosity of the reservoirs ranges from about 25% to 35%, said

Jenkins, with good permeability.“The producing characteristics are good. The real question is

how much area an individual well will drain,” he said.With the good porosity and permeability, a relatively large

drainage area is expected, barring sand “shale-out” or the pres-ence of a fault.“But the seismic is so good that a lot of that can also be

imaged,” Jenkins said.A comparison of Independence wells to theCanyon Express

wells, which produce from the same type of deposition, indicatesthe Independence wells should have good average producing rates.“How much can be produced from each well won’t be known

until they are on production,” Jenkins said. “But wells havetested at more than 60 MMcf/d each. That’s a good sign.”The successes of the Jubilee and Spiderman gas fields helped

lower risk within seismic-amplitude-supported plays whenexploring for deepwater Miocene sands, according to a presen-tation by Todd J. Greene, Peter Gamwell, Todd Butaud, AndrewPink, Michael Golden, David Jones, James Parr and IstvanBarany, all of Anadarko.“Data collected from whole core of the Spiderman (180ft)

and Jubilee (90ft – 27m) wells strongly influenced our interpre-tation of reservoir architecture,” the authors said.At both fields, they inferred a basin-floor setting where strati-

graphic architecture reflects the interplay of a variety of deep-water depositional processes including high-density sandyturbidite flows, suspension deposits, mass transport complexes,low-density turbidites and channelized deposits.The irregular seafloor created by erosional mass transport

complexes along with deeper episodic salt movement alsoplayed an important role in the lithofacies distribution for thesedeposits, according to the authors.In Spiderman, the shallowest interval, theMM9 (Middle

Miocene) Sequence, contains three interconnected stacked sandbodies deposited in a confined, amalgamated, sand-filled, low-reliefchannel complex, the authors wrote. The deepest interval, theMM7 Sequence, also appears interconnected and was deposited asmore unconfined sheets within a frontal splay complex, which isthen overlain by a channel/levee complex, according to the report.In the Jubilee field, three interconnected stacked sand bodies

were deposited as compensatory stacked, amalgamated and lay-ered sheets overlain by erosive mostly mud-filled channels.To optimize reservoir performance, Anadarko developed detailed

facies-basedmodels where petrophysical properties are calibratedto individual facies. Then it could develop a stochastically derived“geobody” volume that predicts reservoir quality and degree ofcompartmentalization over the entire field, the report said.


DRILLING, COMPLETIONDrilling and completing the number of wells that will initiallymake up Independence would not be a challenge if they werelocated in, for example, a typical onshore field developmentwhere producing zones were at depths of 10,000ft to 12,000ft(3,050m to 3,660m).But put them in 8,000ft to 9,000ft of water, spread them over

an area 75 miles (121 km) long, and hire a $ 500,000/day vesselto spend several weeks completing each one and months layingflowlines. Then getting “only” 15 wells ready for production canbe daunting.All the operators in the project have extensive experience

completing subsea wells across the Gulf and applied their ownapproach to completing their Independence wells. Each comple-tion was fitted with a wellhead to which the agreed upon “stan-dard” subsea tree could be mated.Below the wellhead, well design and equipment could con-

form to the individual operator’s taste. From that wellhead up,the rest of the subsea system – trees, flowline layout and design,umbilical system – used components and systems designed bythe subsea integrated project team.Drilling in the area is relatively straightforward, and to date,

most wells have been vertical. Eventually, if the play goes likemany others, there will likely be some wells that are sidetracked.“The wells go down very quickly,” Jenkins said.Wells in the anchor fields are normally pressured. At their

18,000-ft to 22,000-ft (5,490-m to 6,710-m) depth (including8,000ft to 9,000ft of water), that means reservoir pressures inthe range of 9,000psi to 11,000psi.Independence discoveries are analogous to those of the

Canyon Express project about 40 miles (64 km) north ofIndependence, Jenkins said. In that development, eight wells inthree fields in about 6,000ft (1,830m) of water were tied back atdistances up to 40 miles to a platform on the edge of theContinental Shelf.Canyon Express producing sands are also similar to those at

Independence. Canyon Express wells, at peak rates, averaged 50MMcf/d each.“It was a sort of precursor to Independence, with similar

sands and trap types,” Jenkins said. “We’ve learned from thatand other projects.”Independence has been designed with flexibility that will make

it easier to add additional wells. Producers will manage their capac-ity in theHub by drilling extra wells in the existing fields or drillingadditional prospects to have a couple of wells “waiting in thewings” to bring into theHub as capacity becomes available.Of a total of 15 wells for the first phase of the Independence

project, 12 are operated by Anadarko. By spring 2007, the com-pletions were finished on these wells, said Kevin Renfro,Anadarko production/completions engineer. All 12 of thesewells were completed with the Deepwater Millennium.

“The Independence area is drillship territory,” Renfro said.“The obvious way to complete in these depths is with a dynami-cally positioned drillship-type rig.”For Anadarko, the Independence area discoveries have

been its first experience using a dynamically positionedvessel to complete subsea wells; it had previously used onlymoored vessels. Anadarko’s Independence work was also thefirst completions the Deepwater Millennium crew had donewith that rig. The crew had done much of the drilling inIndependence, and some members had performed comple-tions on other rigs.“TheMillennium is an excellent rig, and the crews have been

very good at working in the completion mode,” Renfro said.Reservoirs are also similar in all three of the fields in which

Dominion has an interest; all are seismic amplitude anomalieswith similar horizons and at similar depths subsea.Two San Jacinto wells and the Q well were completed with

Noble Corp.’s semisubmersible rig, Amos Runner. Since it is amoored vessel rather than dynamically positioned like theDeepwater Millennium, Amos Runner’s rig and mooring systemhad to be upgraded for the Independence job. Moored rigsdon’t typically work in 8,000ft of water.Use of this rig was necessary because no other dynamically

positioned rigs were available. The good news is that althoughthe two San Jacinto wells are several thousand feet apart, bothwere completed with one mooring.

Better and betterDrilling the wells in Anadarko-operated anchor fields wouldhave been relatively routine if the wells had not been in 8,000ftto 9,000ft of water.“Even in those water depths, we were able to make them

pretty routine,” said Pat Watson, Anadarko’s lead drilling engi-neer. “On some wells, we drilled at a rate of 1.9 days per 1,000ft[305m] below the mud line from spud to TD [total depth].Average rate for all the wells was about 2.4 days per 1,000ft.“We were very aggressive. Within 2 weeks, we could be at TD,”

Watson said.With a spread rate for the Deepwater Millennium and associ-

ated equipment and services of about $500,000/day, time savedwas money saved.Several efficiencies contributed to the performance. Testing

the blowout preventer (BOP) against casing instead of runningtest plugs is one way time was saved. When the 133⁄8-in. casingwas in place, cement was displaced and the plug bumped withsynthetic mud, avoiding the need to clean the mud pits. Whencementing the production casing on later wells, the cementplug was bumped with the mud that would be left in the holefor temporary abandonment. Surface cement plugs were alsoset about 600ft (183m) below the mud line so the well could betemporarily abandoned without another trip in the hole.


“All those things added up to significant time savings,”Watson said. “We got very efficient at what we did.”The result was the least costly wells drilled in those water

depths.Overall drilling cost for the Anadarko wells was about 22%

under authorization for expenditure (AFE) estimates.“Continuity was a key to helping us get better and better,”

Watson said. “We used the same rig over and over, with thesame foreman and the same mud company. These were some ofthe fastest wells ever drilled in these water depths.”Approving all the wells up front also was an important

advantage. With that inventory, Anadarko was able to minimizeweather downtime. Loop currents and hurricanes caused someweather delays, but weather downtime was not significant. Partof the credit goes to having all wells ready to be drilled so the rigcould move to another well if weather conditions dictated.“If loop currents threatened in Atwater Valley, for example,

we could move to DeSoto Canyon or Lloyd Ridge,” Watson said.In one case, the rig was moved 21 miles (34 km) with

the BOP stack hanging on the riser at a depth of about

8,700ft (2,654m). Typically, 10 riser joints – about 750ft(229m) – would be pulled if the rig were moved withoutpulling the BOP.“That saved several hundred thousand dollars,” he said.In the program, Anadarko drilled 13 wells and two side-

tracks. First wells were spudded in early 2003; the last onedrilled was finished in mid-2005.Anadarko’s wells in the Independence area are very similar,

Watson said. The pressure regime did not require any fancyequipment, but in the first two wells drilled, Anadarko ran a16-in. liner. Pore pressure was not fully known at the time, andthere was the possibility that a debris flow through the areamight indicate the potential to encounter a higher-than-normalpressure. When that higher pressure was not found, the linerwas eliminated from the casing program on subsequent wells.The modified program called for jetting in the 36-in. then

running 20-in. casing. The next string is 133⁄8-in., followed bythe 97⁄8-in. production string to total depth.Running a long string of 97⁄8-in. was a different approach

than that taken by some other operators, but it made it possible


to install trees and go straight to completion without having torun a tie back string for a liner. To mitigate annular pressurebuildup, Anadarko did not cement the 97⁄8-in. into the 133⁄8-in.Anadarko’s first six wells were drilled all the way to the pro-

duction casing interval with a water-based mudM-I Swaco pro-vided. Then the production interval was drilled with a syntheticdrilling fluid system. Later wells, however, were drilled entirelywith a synthetic mud system. Mud weights typically rangedfrom 10.2 lb/gal to 10.5 lb/gal, but were boosted to about 10.9lb/gal in the directional intervals.An extreme water depth can work to advantage when con-

trolling formation pressure during drilling.“It does give you the luxury of being able to kill the well with

the riser in an emergency,” Watson said.Such an emergency did not occur in Anadarko’s

Independence wells.“When a pressure anomaly was encountered in Spiderman,

however, we were able to use the riser to advantage because theriser is at least half the hole,” he said.Except for Spiderman, lost circulation was not a problem in

Anadarko’s program.“We did not have any significant hole problems. In the highly

deviated intervals, we knew we had to raise mud weight byabout 0.3 lb/gal to control sloughing and keep the hole open.

This was especially important during logging,” he said.Anadarko used roller cone bits down through the 133⁄8-in.

interval. A 26-in. bit was used for jetting in and to drill a 26-in.hole to about 3,000ft (915m) below the mud line. After setting20-in., Anadarko drilled the intermediate hole with a 17-in.roller cone bit. Depth of this interval varied among the wells,but ranged from 5,000ft to 6,000ft (1,525m to 1,830m) belowthe mud line. The interval from there to total depth was drilledwith a polycrystalline diamond bit.Rotary steerable systems and steerable mud motors were

used as necessary. The rotary steerable was used in directionalintervals and the steerable mud motor on straight intervals andwhere deviation was minimal. Deviation of some of the direc-tional intervals exceeded 50° and several had deviationsbetween 30° and 50°.“Intervals with deviations above 50° had big turns as well,”

Watson said.Lightweight slurries of “flexible” cement were used on the wells,

an early application of that technology. Halliburton EnergyServices provide cementing services on all of Anadarko’s wells.In these water depths, it often is difficult to determine when

returns reach the seafloor. A typical procedure, to pump 100%excess cement to be on the safe side, increases cementing costs.After trying various techniques, including dyes and black


light, Anadarko settled on a new product, hollow polymer“tracer” beads, to monitor returns. Looking like fireflies on theremotely operated vehicle camera at the seafloor, the tracerbeads are now being used by other operators.“They saved us a lot of money on cement,” Watson said.

Coordinating completionAnadarko’s completion activity began in the second quarter oflast year on wells that had been pre-drilled and cased, and con-tained a cement plug or bridge plug and a subsea wellheadinstalled at the mud line. Once the tree was installed on thewellhead, the completion rig ran and connected the riser andBOP stack to the wellhead.As Anadarko got into the completion program, subsea con-

struction work was also getting under way. Flowlines were beinglaid early last year, and the umbilical network was beinginstalled beginning in the second half of last year.“Coordination of all those activities and equipment took a lot of

effort, especially during the summer and into the third quarter of2006,” Renfro said. “We did a lot of planning, but we also providedflexibility for those times when things didn’t fit the plan exactly.”Umbilicals were reeled onto large carousels on the installa-

tion vessel and a preferred order for installing the umbilicallines was created. When installing a certain umbilical, whichmight only take 10 days, the completion rig could not be oneither well at the ends of that umbilical.A typical completion might take 25 days, and it was necessary

to determine if a well could be completed before it was necessaryto move the rig. To provide flexibility in the schedule, Anadarko“planted” subsea trees in all the fields. Having at least one tree ineach field provided the option to change on short notice whichjob was done next to avoid a conflict with construction vessels.“That saved the consortium a lot of money,” Renfro said.Loaded rate for the vessel that installed flowlines was in the

order of $500,000/day and the drillship was commanding a sim-ilar rate. At some times, three high-dollar vessels were at work.“It was not a case of the inexpensive vessels accommodating

the movement of an expensive vessel,” Renfro said. “Every vesselthat works in these water depths is expensive.”The other challenge was the significant geographical spread

of the project and loop currents that move through the area.Anadarko had developed a sequence for completion that mini-mized rig travel and the number of times it would be necessaryto pull and redeploy the BOP stack and riser.“We knew the loop currents might change this plan,” Renfro

said. “We did get the first well in the sequence done, but wecould not go to the next well on the list because the loop cur-rents moved in. Current was so high, we could not work in thewhole southern portion of the area.”Completion engineers had to have several different comple-

tion procedures ready at any one time. It is very hard to write up

all the plans in advance, Renfro said, because it is hoped thatexperience on early wells can be used to modify procedures onlater wells to help optimize the process.“We were successful at moving around to different wells as

conditions warranted, in part because we had trees at each loca-tion,” he said.

Off the critical pathSubstantial time was spent during planning to determinewhether the Deepwater Millennium rig needed modifications forthe Independence completion work. Focus of this analysis washow to handle the subsea trees, and what control system wouldbe used to install them.Some modifications were made to the workover umbilical

system, a product of Aker Kvaerner ASA’s Kvaerner Oil Products(KOP) division that controls the tree during completion opera-tions. The system provides access to tree valves, because the treeis installed before the completion vessel arrives on location.A unique feature of the KOP system is that the umbilical is

not strapped to the riser as it is run. Instead, the umbilicalextends from another part of the drillship to a termination unitplaced on the seafloor and connected to the subsea tree to pro-vide control. The termination unit is pulled when the tree isinstalled and redeployed on the next well.The advantage of a system that features the termination unit is

that it can be deployed, recovered and redeployed off line, provid-ing more flexibility in positioning the drillship to respond toweather conditions. In addition, if there is a problem with theumbilical, because it is not strapped to the riser, it can be recov-ered and repaired without interrupting other operations.“If the umbilical is strapped to the riser, the riser must be

pulled to fix a problem with the umbilical,” Renfro said.“Having the umbilical separate is a significant efficiencyimprovement.”Prior to the merger, Kerr-McGee and Anadarko had already

planned to share the same rig. After deciding the separateumbilical termination unit was the way to go, the two compa-nies hired KOP to build a unit that would be put on a long-termcontract for the Independence project.“Though Kerr-McGee had proved the system, Independence

is the deepest water depth in which it has been used,” Renfrosaid. “And it has worked out very well.”Much of the completion technology used on the project is

not dramatically different from a typical completion under lessextreme conditions. Independence, however, posed some uniquecompletion challenges because the water depth is roughly equalto the depth of the producing formations below the mud line.For example, when installing the tubing hanger that sits in thesubsea tree at the mud line, there might be as much landingstring above the tubing hanger as there is below it where theother end of the tubing is attached to the gravel pack packer.


“It’s a little weird,” Renfro said. “Typically, when making upthe tubing hanger equipment, the tubing is in the wellbore.But the deep water and modest depth of the formations belowthe mud line meant the crew could be making up the tubinghanger and making control line connections before tubing isout of the riser.”All the wells are fitted with horizontal subsea trees installed

before the completion rig arrived by an anchor handling vesselequipped with a heave-compensated landing system.“The big advantage of that approach is that for most of the

wells, tree installation can be done off line with a much lessexpensive vessel,” Renfro said. “Then when the completion rigcomes, you’re ready to immediately hook up the BOP stack andriser on top of the tree.”On a couple of wells, because tie back work was being done

on casing liners, the rig was on site and it was necessary toquickly install the tree. On location, the rig disconnected the

BOP stack, then moved over and let the anchor handling vesselinstall the tree.“We could do that in just a few hours,” Renfro said.Some deepwater drillships are dual-activity rigs. With two

derricks, tree makeup and other work can be done with one rigwhile separate operations are performed with the other. TheDeepwater Millennium, however, is a single-activity rig with onemoonpool and one derrick.“You try to do things without using the drillship. If it is nec-

essary to pull the riser, run a tree on pipe, then run the riserback, it takes 4 to 5 days,” Renfro said. “With a dual-activity rig,it might take only a few hours to disconnect and move over todo a job, while keeping the riser and stack deployed.”

High rates, smart wellsAll of Dominion’s Independence project wells are smart wellscompleted in multiple horizons. Like the other smart wells in


the field, Dominion’s can be controlled – and different zonesopened and closed – from Independence Hub, which in the caseof Spiderman is 24 miles (39 km) away.“Basically, we can re-complete a well by pushing some but-

tons,” said Richard Fowler, former vice president of deepwaterdevelopment for Dominion Exploration & Production Inc.As much as possible, Anadarko standardized its downhole

assemblies, but some are fitted with 41⁄2-in. tubing, some 51⁄2-in.Two wells are completed in three zones, four wells have two com-pletion intervals, and the company has four single completionsin its Independence portfolio. Multi-zone completions are com-pleted as “smart wells.”Because they will produce at high flow rates, existing smart well

equipment for themulti-zone wells had to bemodified to increaseflow capacity. Smart well technology was developed primarily forzones withmuch lower flow rates and a shorter expected life.“In Independence, there is the potential to make 60 MMcf/d

to 100 MMcf/d from one zone. That much gas just doesn’twant to go through the complicated geometry of a typical smartwell configuration,” Renfro said.Sliding sleeves and packers also were upgraded to a larger

size, and other equipment in the gravel pack zone was modified.“It was not super complicated, but it was necessary to

build for purpose. It required careful planning to give ven-dors time to build and test the equipment before it wasdeployed,” he said.Because Anadarko has several wells with similar configura-

tions, it was possible to design a few sets of equipment thatcould fairly easily fit more than one well, with, for example, onlyminor modifications to accommodate the length of the intervalin each well. Equipment was pre-built and on location so theoperation was ready to go to multiple sites at any given time.It wasn’t exactly a “choose-one-from-column-A and one-

from-column-B situation,” but it was close to that, Renfro said.Because many wells have similar downhole temperatures andpressures, it was possible to standardize the completions to acertain extent.Anadarko completed all of its wells with a frac pack or high

rate water pack completion that provides sand control.Some Independence wells get some aquifer support. Water

drive does help produce at higher rates, but typically causesabandonment earlier than under a pressure depletion mecha-nism, leaving more gas behind in the reservoir. Closely monitor-ing pressure is a way to determine whether water is becoming aproblem, and to define the shape and size of the drainage area.If a well begins to produce significant amounts of water because

it is coming in from the aquifer, the well is likely near abandonment.“It will not be possible to keep producing at that point,”

Jenkins said.Water vapor entrained in the gas at high pressure while it is in

the reservoir also is an issue. As the gas comes to the surface and

temperature and pressure decrease, the water vapor will condense.This might not be a problem under “normal” operating

conditions, but it becomes an issue in 8,000ft of water,Semetko said.“High pressure and low temperatures are the ideal combina-

tion for hydrate formation,” he said.Hydrates also can cause serious flow restrictions.Avoiding hydrates in the flowlines that tie the subsea wells to

the Hub is the reason for the large monoethylene glycol (MEG)recovery system on the Hub platform. Water entrained in thegas makes it necessary to dehydrate it on the platform to keephydrates from forming in the export pipeline.“The nice thing about having a dry gas province and a hub

like Independence is that gas wells can be tied back subsea forgreat distances,” Jenkins said.An oil well needs to be within 15miles to 20miles (24 km to 32

km) of the surface facility, but a gas well can be tied back to a plat-form from a distance of 50miles to 60miles (80 km to 97 km).

Role of a modelIn addition to a reservoir model, an integrated productionmodel (IPM) was used in the planning and design of theIndependence project.“The IPM is more of a material balance model than a reser-

voir model,” said Bob Buck, Anadarko senior staff productionengineer for the eastern Gulf of Mexico. “It is tied to a nodalanalysis model.”IPMmodels the reservoir, the wellbore, the flowline network,

risers, even compression on the Hub topsides. The model wasused early in the planning process to determine the optimumHub location. Well locations and flowlines were put into themodel and the Hub location moved around to determine thelocation that would give the best recoveries.“That’s how we decided on Mississippi Canyon Block 920,”

Buck said. “The original plan was to put the Hub in AtwaterValley Block 85.”The model, developed by Petroleum Experts Ltd., also

helped design the flowlines, and water-handling capacity wasincreased as a result of what the model indicated. PetroleumExperts’ IPM suite of tools can be run together seamlessly todesign complete field models. It can simultaneously model andoptimize the production and the water or gas injection system.All well configurations, including multilateral, can be modeledtogether. There are several thousand fields worldwide havingtheir production managed and optimized using IPM, accord-ing to the company.For Independence, the model also helped evaluate how to

tie in developments. Dominion-operated San Jacinto, forexample, originally was to be connected directly to the Hubwith its own flowline. But evaluating different scenarioswith the model showed San Jacinto could be tied into the


Spiderman manifold and flow to the Hub through the dual8-in. and 10-in. flowline system.“That saved millions of dollars for the companies involved,”

Buck said.The model will also be important during operations.“We’ll use it real time and history-match the production

data to make decisions on how to best optimize production byrouting wells into the proper flowlines. It really is an optimiza-tion model,” he said.

STARTUP AND OPERATIONTwenty years ago, the prospects that resulted in discoveries thatnow make up the Independence anchor fields might have beenindicated by the seismic technology of the day. The explorationholes likely could have been drilled with the rigs and techniquesavailable at the time.But the technology did not exist to produce from water

depths like those in the Independence area.“At that time, it was often necessary to sit on a deepwater dis-

covery for several years until the production technology caughtup,” Jenkins said.Design of the Independence production systems, though it

sets records for size and water depth, is not unusually complex.

On paper and in conference room discussions, it seems fairlystraightforward.In its full installed size and scope, however, starting up the

Independence complex and operating it will not be simple. Keychallenges include:

•managing the MEG inventory within the constraints of lim-ited storage capacities;

• handling water production;•minimizing the accumulation of liquid slugs and control-ling their movement;

• optimizing the operation of fields with dual flowlines aswell pressures change; and

• keeping temperatures within acceptable ranges.“Based on initial tests, the wells are doing pretty much what

we thought they would do,” Buck said late last year. “They arefantastic wells.”The majority of the wells have tested at rates above 50

MMcf/d and one was tested at about 70 MMcf/d.Despite the largest throughput capacity in the Gulf, the

Independence Hub is not an unusually large platform. It willrequire 16 operators and one foreman to run the facility. “Witheverything that is going on there, including the Gulf ’s largestMEG system, that is not many operators,” Buck said.


Even though Independence is not overly complex, theextreme water depth has an impact on almost every aspectof its operation.“All the subsea operating procedures must take into account

water depth, distance from the Hub, temperatures, liquidholdup in the flowlines and the flowline configuration,” saidJarvis Cooley, Anadarko field superintendent. Cooley overseesIndependence operations.In addition to what might be termed “normal” operations,

comprehensive operating procedures were developed thataddress some special challenges. Flow assurance will always be atop priority, making management of MEG flow and processinga critical part of day-to-day operation.When wells are put on stream, liquids accumulate until the

flow reaches the “sweeping rate,” then a liquid slug will arrive atthe topsides and must be controlled.When a well is brought on stream, it raises the temperature

of the annulus fluid; the resulting increase in annulus pressuremust remain below the allowable pipe pressure. Bleeding off toomuch pressure is not the answer, because you need to maintainsome positive pressure for monitoring capabilities.

Measurement and allocationIn concept, the Independence flow measurement system is notsignificantly different from other systems. What makesIndependence different is the number of wells and differentowners in those wells in addition to the number of shareholdersin the platform operation.Combine multiple wells with multiple zones and multiple

well owners – and all production to be commingled in an exportline – and accurate measurement of each party’s productionbecomes a critical piece of the Independence puzzle.The key job of the wet gas meter at each well is to help allo-

cate production. In one case, three wells produce through a sin-gle flowline. Some wells can produce through either of twoflowlines or have more than one ownership interest.Use of individual well meters is the only way to allocate pro-

duction. High producing rates and high gas prices magnify theimportance of measurement.Roxar supplied the wet gas meters for all the wells in the

project and provided its sand monitoring system for Anadarko’swells. The 15 subsea wells comprise the largest application ofRoxar’s wet gas meters to date in the Gulf of Mexico.Placed in the jumpers downstream of the wells, the meters

measure the volumes of gas, condensate and the aqueous phase(water and MEG) in each well stream. The meters do not differ-entiate between water and MEG, but read the total as “water.”Meters were flow tested on the Deepwater Millennium rig

during recent well tests.Roxar’s subsea wet gas meter is the only available meter with

online direct measurement of water in wet gas flow. In addition

to production allocation, the meter provides information valu-able for reservoir management and flow assurance as well as foroptimizing production.Because the meter can distinguish between condensed

water and saline formation water, it provides important inputfor controlling hydrates, corrosion and scale. This is particu-larly important for the Independence Hub developmentwhere hydrate formation is seen as the largest risk to produc-tion integrity.It also is important to control sand production and predict

erosion rates without having to integrate a separate monitoringdevice subsea, according to Roxar. The company’s new sandmonitoring system that is part of Anadarko’s wells is connectedto the wet gas meters, significantly reducing subsea integrationissues and improving prediction of sand production rates.Another part of the allocation process is the individual sepa-

rator that each flowline enters as it comes on the platform.Each allocation separator measures total gas and total liquidcoming from each field.Because these are two-phase separators, MEG, condensate

and water all go out the same liquid dump valve to a condensateflash separator and coalescer where the condensate is separatedfrom the MEG/water mix. MEG and water go to the glycolreclamation system, and the condensate is re-injected into thesales line with the dry gas.To determine the amount of the total liquid leaving the sepa-

rator that is condensate, each separator is equipped with an oil-cut analyzer used to allocate condensate production back toindividual wells.Samples taken throughout the platform are sent to the lab to

determine the composition of the flow at each metering point.Sample information is used to perform a daily in-house plantbalance and a monthly plant balance that is part of the alloca-tion process, Cooley said.Before entering Independence Trail, total gas and condensate

are metered as part of the allocation process that first allocatesthe sales volume to each separator, then allocates separator vol-umes to individual wells.

Managing MEG“One of the first considerations in designing a production sys-tem for the Independence wells was hydrate inhibition,” Bucksaid. “At the pressures involved – wellhead pressures inthe range of 7,000psi initially – we are highly susceptibleto hydrates.”To economically prevent hydrates in the flowlines that will

handle a total of 1 Bcf/d requires the largest offshore MEGreclamation unit yet built. MEG is the least expensive hydrateprevention option for Independence, but because it costsclose to $5/gal, efficient reclamation is important to the pro-ject’s economics.


Although 97% of the MEG is reclaimed from the well streamswhen it reaches the Hub, a loss of 2% per day means glycol costswill still be significant. It is still more economic, however, than amethanol hydrate prevention system and doesn’t have the safetyconcerns that come with methanol.In addition to being the largest such system installed

offshore, the Independence MEG unit is a new proprietarydesign by Petreco Process Systems that results in a significantlylower weight/capacity ratio.The reclamation system can separate more than 7,000 b/d of

MEG and water from the gas. This results in water-handlingcapacity of 3,500 b/d.“For a facility that handles 1 Bcf/d, that is not very much,”

Buck said.“When everything is up and running in a steady state, there

should be no problem,” Buck said. “But when a line or linesmust be shut in and restarted, managing the MEG on the top-sides with the limited storage available could be a challenge.”It’s important to keep injecting MEG so wells can continue

to be produced. So it is necessary to avoid a situation in whichlines are being re-started and MEG is not yet coming back tothe platform.“It’s a very tricky balancing act,” Buck said.The water volume that can be handled by the Hub’s treating

plant is determined by the capacity of the MEG reclamationunit to process the “wet” MEG coming from the wells in addi-tion to the ability to inject the required amount of dry MEG forthe volume of water the well is producing.“It will hinge on the capacity to process wet MEG, about

7,000 b/d,” Cooley said.If one field is not making water, more gas can come from

other fields without exceeding reclamation capacity. However, ifseveral wells in one field are making water, it may not be possi-ble to get enough dry MEG down the umbilical to treat thatamount of water. Then the amount of MEG that can be putthrough the umbilical is the limit on flow rate.“With so many wells coming to the platform, there are a lot

of possible combinations,” Cooley said.How much water can be accommodated from one well

depends on what other wells in that system are doing, whatother fields are doing and the total volume of water coming tothe platform.Each operator has been guaranteed a share of the Hub’s

capacity, another factor in the calculation.The system is designed to produce a 97% dry MEG to return

to the wells. The goal is to have enough dry MEG to inject untilflowline volume reaches the sweeping volume, then to haveenough processing capacity when the liquid hits the platform toprocess the wet MEG and get it back into the system.Eventually, the system will settle into a relatively steady state.“It’s a challenge to best utilize the MEG processing capacity.


We have to be certain we have enough dry MEG to meet theneeds of all the fields as wells are brought on line and gothrough the liquid holdup phase,” Cooley said.

Sweeping up liquidLiquid slugs are unavoidable in Independence Hub operations.Various models have shown that at the anticipated flow rates,there could be liquid slugs as large as 1,000 bbl in the flowlines.There is no slug-catching equipment on the Hub. Slugs are

handled by a ball valve that continuously throttles the flow tocontrol the liquid. Logic that controls the valve on each alloca-tion separator monitors separator pressure, liquid level and therate of change in liquid level.“Wells are occasionally shut in, and the important goal when

putting a well on stream is to get up to that sweeping rate assoon as possible,” Cooley said.The sweeping rate is the gas flow rate that is high enough to

pick up liquids and sweep them out of the flowline.“With the high flow rates, it should be relatively easy to reach

those required rates,” he said.Care must be taken, however, to avoid bringing a well on too

fast, risking damage to the well.“The system will take some fine tuning,” said Cooley before

the startup.“It is critical to operate the flowlines above ‘sweeping’ rates

to keep liquids moving,” Buck said. “We can’t produce at ratesbelow the sweeping rate in any flowline for any extended periodof time.”A helpful tool in managing liquids is the system’s two flow-

line sizes. In the 8-in. lines, flow must be more than 30 MMcf/dto be above the sweeping rates; for a 10-in. line, flow must bemore than 50 MMcf/d to keep the lines free of liquid slugs.If operating below those rates for some time, fluids drop

out of the gas stream in the flowline and accumulate. Thenwhen flow gets back above the sweeping rate, the slug hitsthe platform.Those wells that are connected to dual flowlines can be

switched from the 10-in. to the 8-in., for example, if flow ratedrops below the sweep rate for the 10-in. line. A well may also beswitched when re-completed in a different zone.“It may be necessary to maintain a high-pressure line and a

low-pressure line,” Buck said. For example, compressor suctionpressure on the Hub will initially be about 1,900psi. In a fewyears, however, suction pressure could be down to 600psi. Atthat time, if a new zone is completed with virgin reservoir pres-sure, the well cannot be produced into a low-pressure line withexisting production.At 600psi suction pressure topsides, if a high-pressure well is

put into the low-pressure flowline, temperatures at the subseachoke can approach -60°F (-51°C) on a cold restart. Jumpersare rated at only -20°F (-29°C). That’s why some of the develop-

ments are equipped with dual flowlines, said Buck, to make itpossible to operate a high-pressure and a low-pressure line.“We have to be very careful how we manage these flowlines.

We can’t predict when the slugs will arrive at the Hub, but wewill have some tools in place to help manage liquids,” he said.The wet gas meters on each well are also a tool for helping

manage liquid slugs that come to the Hub. At the platform, theoperator will know how much fluid is crossing the wellheadmeters and how much is coming out of the separator on theplatform. The difference between these readings tells the opera-tor how much liquid is in the flowline and how large of a slugwill hit the platform process equipment.“It’s all in real time,” Buck said. “We can see things coming.

It’s great technology; I don’t see how we could do without it.”“It’s a balancing act, and it is a challenge during startup and

when flowlines are re-started,” Renfro said. “We did a lot ofmodeling to see what the system would look like dynamically,not just when operating at full rate.”The staged startup began by getting one field and one flow-

line working, unloaded and cleaned up. When that line wasworking well, another flowline was brought on stream.

Temperature limitsMaintaining well stream temperature at the platform withinproper limits is also an operating challenge. There is a signifi-cant pressure drop between the well and the Hub. Even thoughthe gas may be between 70°F and 80°F (21°C and 27°C) at thewellhead downstream of the choke, when the gas reaches theHub the temperature is in the order of 20°F (-7°C). The top-sides process requires that the arrival temperature be above18°F (-8°).That arrival temperature then becomes the limiting con-

straint on the flow rate in each flowline.“A typical flowline design is based on erosional velocities and

compressor suction pressures,” Buck said. “Based on that crite-rion, a 10-in. line might be able to handle 400 MMcf/d and an8-in. line could carry 250 MMcf/d.”But arrival temperature constraints limit throughput at

Independence to about 230 MMcf/d for the 10-in. line and 160MMcf/d for an 8-in. line.“So the 8-in. and 10-in. dual flowline systems that normally

could flow 600 MMcf/d are limited to about 400 MMcf/d,”he said.The 18°F minimum is necessary to allow for the further drop

in temperature as the incoming well streams go through achoke on the Hub, reducing pressure and dropping tempera-ture. Arriving at 18°F or above ensures the temperature will stillbe within process equipment ratings after the pressure isreduced through the choke.“The cooling effect of that pressure drop is very large. These

lines will be coated with ice year-round,” Buck said. ★


Independence:The CompaniesDeepwater veterans focus an array of expertise on innovative project

The Independence project is the result of successful collab-oration among the owners, producers, operators and con-tractors involved and their ability to meet the challenges

of this record-setting project.If multiple parties and the challenges of engineering and

construction frontiers were not enough, participating compa-nies also were involved in merger and other organizationalchanges during the 4-year development process. That meantadapting new operating strategies and cultures to the frame-work beginning to emerge for Independence. Two original pro-ducers – Anadarko Petroleum Corp. and Kerr-McGee Corp. –merged during the process. GulfTerra Energy Partners LP wasacquired by Enterprise Products Partners LP, and BHP BillitonPetroleum (Deepwater) Inc. sold its leases in the region and leftthe group. Norsk Hydro ASA purchased Spinnaker ExplorationCo., then later merged into Statoil ASA at about the time theHub was scheduled to sail from Kiewit Offshore Services Ltd.’sIngleside, Texas, yard.During much of the busiest negotiation period, however, the

core group of companies included five producers and one mid-stream service provider.

Independence Hub ownersEnterprise and Helix Energy Solutions Group own the

Independence Hub semisubmersible facility that is the heartof the Independence development. Enterprise owns 80% andmanages the joint venture company for the partnership withHelix owning 20% of the platform. Enterprise owns 100% ofthe export pipeline, Independence Trail, and is the operatorfor the pipeline.

Midstream partner EnterpriseAs the midstream entity in the Independence project, Enterpriseplays a central role in connecting the deepwater gas resource tomarkets. It is far from new to this role, and for Independence,Enterprise leveraged its extensive experience in the many phasesof two general areas critical to the project’s success – offshoredevelopment and natural gas gathering.Enterprise is one of the largest publicly traded energy part-

nerships in the United States and is a North American providerof midstream energy services to producers and consumers ofnatural gas, natural gas liquids (NGL) and crude oil.The company has the only integrated North American nat-

ural gas and NGL network that includes import and exportservices. The system links gas and NGL producers from thelargest supply basins in the United States, Canada and theGulf of Mexico with the largest domestic consumers and inter-national markets.


Enterprise filed its initial public offering in 1998. InSeptember 2004, it acquired GulfTerra Field Services LLC tocreate one of the largest publicly traded energy midstream com-panies serving oil and gas producers and consumers. With anenterprise value of about $17 billion, the company operatesfrom a large platform of assets across the midstream energyvalue chain, including:

• almost 19,000 miles (30,571 km) of natural gas pipelines;• about 14,000 miles (22,526 km) of NGL and petrochemicalpipelines;

• 863 miles (1,389 km) of Gulf of Mexico crude oil pipelines;• 148 million bbl of NGL storage capacity;• 25 Bcf of natural gas storage capacity;• seven offshore hub platforms;• 16 NGL and propylene fractionation plants and anisomerization complex; and

• 25 natural gas processing/treating plants.In November 2004, Enterprise announced the agreement

with the five independent exploration and production (E&P)companies to construct the Independence Hub and Trailinfrastructure.That move fit well with Enterprise’s growth strategy, which is

centered on development activities in the Rocky Mountainregion and the Gulf of Mexico. A key element of the plan is to

continue to develop and invest in joint venture projects withstrategic partners who will provide the raw materials for theproject or purchase the end products.Independence Hub adds to Enterprise’s 15 platforms and is a

seventh hub-type platform that Enterprise owns.“Among the other platforms Enterprise owns, a number are

hub-type platforms where we welcome third-party tie-backs,”said Ray Cordova, deepwater platforms manager withEnterprise. “Independence raises the bar for the industry bothtechnically and commercially. It represents the industry’s mostinnovative and well coordinated infrastructure and develop-ment solutions to economically develop deepwater natural gasreserves, which otherwise would have remained stranded. At thetime it was installed, our Marco Polo TLP [tension-leg platform]was the deepest platform at just over 4,000ft [1,220m].Independence is now the deepest in the world at just over8,000ft [2,440m].”

Production and contracting partner HelixHelix is an offshore oil and gas production and contractingcompany that invests in mature offshore oil and gas proper-ties, hub production facilities and proven undeveloped reserveplays where it can add value by deploying vessels from its con-tracting fleet.


The company’s two-stranded strategy is to offer the fullbreadth of marine contracting services and operate as an oil andgas producer. A specialty as well as primary area of focus is mar-ginal prospects.Before becoming part of the Independence development,

Helix had demonstrated its ability and willingness to share therisks of deepwater development with other partners. In ad-dition to its 20% ownership of the Independence Hub, Helixowns 20% of the Gunnison central facility, a spar platform in3,150ft (961m) of water installed in2003; and 50% of the Marco PoloTLP, installed in 4,300ft (1,312m)of water in 2004.“So we are familiar with the

platform ownership model, wherecapacity of the platform is leasedto a producer or producer group,”said Bart Heijermans, Helix’s chiefoperating officer. “When theIndependence Hub opportunitycame along, it fit well with outgoal to expand our platformownership business.”A producer and a service pro-

vider, Helix operates one of thelargest fleets of vessels and supportequipment in the industry and hasongoing operations in the Gulf ofMexico, the Caribbean and theNorth Sea as well as in theAsia/Pacific regions.Its deepwater contracting divi-

sion began in 2000 on theDiana development project in the Gulfwith the vessel MSVUncle John. Since then, Helix has added anumber of dynamically positioned deepwater vessels to its fleet.As an operator, Helix’s focus on developing marginal fields

has brought its daily Gulf of Mexico production to about 200MMcfe, and its service lines now include construction, rig-lesswell intervention, drilling, robotics and reservoir engineering,and well technology.“The idea is that those services can be used internally to

lower our own finding and development costs as well as exter-nally,” Heijermans said.In the case of Independence, there were three areas of interest

to Helix, he said:• ownership of the Hub platform is a good investmentin itself;

• Helix has the construction vessels and other equipmentthat can be used in the future to tie back other small fieldsand the well intervention vessels to increase flow ratesthrough downhole maintenance; and

• as a producer, the company has an interest in exploring inthe area where the Hub is to find marginal gas fields thatmay only be commercial because the Independenceinfrastructure is in place.

“The large processing capacity of the Hub and the extensivenetwork of flowlines and manifolds on the seabed make theHub area a very attractive place to drill for prospects,”Heijermans said.Producing from 9, 000ft (2,745m) of water is a challenge. The

good news, he said, is that it is gasproduction with a very small con-densate yield.“From a flow assurance point of

view, it is much easier to deal withdry gas than with oil,” he said.As much as technology, the

unique aspects of Independenceare about the pace of developmentand execution of the project as wellas the collaboration among mul-tiple parties, Heijermans said.“A lot of the work was already

under way before the final defini-tive agreements were signed. Thathelped to accelerate first produc-tion by at least a year, maybe a yearand a half,” he said.Even though they are in up to

9,000ft of water, the Independenceanchor fields are not deep belowthe seabed, which results in a typi-cal reduction of drilling costs for

the fields compared to other areas.“Looking at the overall development of reserves in the

Independence area, the cost perMcf is pretty low,” Heijermans said.

INDEPENDENCE HUB PRODUCERSAnchor producer AnadarkoIndependence Hub is operated for the Atwater Valley ProducersGroup by Anadarko, which now has about 61% of the Hub’s gasprocessing capacity. Anadarko explores for, develops and mar-kets oil and natural gas in regions from the deepwater Gulf ofMexico through the Rockies and in Latin America, Africa andthe Middle East.Anadarko is among the largest independent oil and natural

gas E&P companies in the world, with 3.01 billion boe of provedreserves as of Dec. 31, 2006. The company’s major areas of oper-ation are onshore in the Rocky Mountain and Southern regionsof the United States, the deepwater Gulf of Mexico and Algeria.Anadarko also has production and/or exploration in Alaska,Brazil, China, Indonesia, Mozambique, Qatar and West Africa.

“As more was learned aboutthe prospectivity of the

region, it became apparentthat we were going to need

a joint solution.”Don Vardeman

Anadarko


The company actively markets natural gas, oil and NGLs,and owns and operates gas gathering and processing systems.Anadarko is committed to minimizing the environmentalimpact of exploration and production activities in its world-wide operations through programs such as carbon dioxidesequestration and the reduction of surface area used forproduction facilities.In 2006, the company delivered average daily net prod-

uction of 489,000 boe or about 178 million boe for the full year.North America operations generated about 83% of Anadarko’sproduction.At the end of 2006, Anadarko had more than 17 million net

acres within the most prospective areas onshore in NorthAmerica. It also had one of the largest acreage positions in thedeepwater Gulf of Mexico with 2.7 million net acres. Anadarkohas made 14 discoveries on 23 tests in the deepwater Gulfsince 2005 and has identified more than 150 prospects andleads, the vast majority of which are in the Miocene and LowerTertiary formations.At year-end 2006, about 13% of the company’s proved

reserves were in the Gulf ’s deep water, where Anadarko ownedan average 63% working interest in 777 blocks with access to anadditional 27 blocks through participation agreements.

Anadarko budgeted about $1 billion for capital spending in thedeepwater Gulf for 2007, 30% of which relates to exploration.The company also has been deeply involved in the develop-

ment of spar technology. It installed the first classic spar,Neptune, in the Gulf of Mexico in 1,930ft (589m) of water in1997 and operates the platform. Production from theAnadarko-operated Nansen platform, the first truss spar, beganin 2002 in 3,675ft (1,121m) of water. Another first in spar tech-nology, the Red Hawk cell spar, came on stream in 2004 in5,300ft (1,617m) of water.The company’s list of successes in the Gulf includes

Boomvang in 3,450ft (1,052m) of water, which began produc-tion in 2002;Constitution, which began production last year in4,970ft (1,516m) of water;Gunnison, a development in 3,150ft(961m) that came on line in 2003; and theMarco Polo TLP in4,300ft (1,311m), which began production in 2004. Enterprise andHelix own the TLP. In themiddle of 2006, Anadarko had a sizablerig fleet under contract, and by late in the year, the company hadexpanded that commitment to the largest number of rig-years ofany company. In what is expected to continue to be a tight deep-water rig market, rig availability proved to be a valuable asset. Thecompany has been able to effectively leverage its rig position togain access to additional opportunities in the deepwater Gulf.


Prior tomerging with Anadarko, Kerr-McGee had a workinginterest inMerganser andVortex, and later in San Jacinto.Initially, the company began working with engineering contrac-tors to find the best development solution. After Anadarko had adiscovery in the area, Enterprise began talking to both companies.“As more was learned about the prospectivity of the region, it

became apparent that we were going to need a joint solution,”said Don Vardeman, Anadarko vice president.If it had been able to include Kerr-McGee’s production,

Anadarko could have justified development of the two assets ona stand-alone basis. It was apparent, however, that several opera-tors in the region needed each other. Including more partici-

pants in the project enhanced the economics for all parties.When Kerr-McGee, Anadarko and Dominion began to work

with Enterprise to determine what type of floating productionsystem would be best for the challenging environment anddiverse operating requirements, each company had its favoritetechnology.If it had been up to Kerr-McGee, for example, there might

have been a spar for the Independence Hub facility, because thecompany had extensive design, construction and operatingexperience with spars.With the merger, however, the new company had put

together experience with every type of floating system.


“We now have experience in-house with every type of struc-ture, including design, fabrication, installation and operation.And for Independence, an evaluation of lifecycle economicspointed clearly to a deep draft semi,” Vardeman said.For Anadarko, the Independence area will be a significant part

of the company’s production growth for the period 2007 to2009, said Anadarko’s Jim Alsup, general manager of operationsfor Northern Rockies. With about 60% of the process capacity ofIndependence Hub, Anadarko can produce about 600 MMcf/d.With several hub-and-spoke type developments, Independence

Hub further increases Enterprise’s infrastructure in the Gulf.“This infrastructure allows us to bring on new discoveries

more efficiently and cost effectively, and leverage our econom-ics,” Vardeman said. “The more hubs built, the fewer platformswe have to build.”

Anchor producer DevonDevon is one ofNorth America’s leading independent oil and gasE&P companies. Devon’s operations are focused primarily in theUnited States andCanada; however, the company also explores forand produces oil and natural gas in select international areas suchas Brazil, China and Azerbaijan. Devon also is one of NorthAmerica’s larger processors ofNGLs and owns natural gas pipelinesand treatment facilities inmany of the company’s producing areas.


Devon’s portfolio of oil and gas properties provides stable,environmentally responsible production and a platform forfuture growth. Nearly 90% of Devon’s production is from NorthAmerica. The company’s production mix is about 60% naturalgas and 40% oil and NGLs, such as propane, butane and ethane.Devon produces more than 2 Bcf of natural gas each day, about3% of all the gas consumed in North America.At about $5.3 billion, Devon’s 2007 capital budget represents

the largest exploration and development investment in its history.Last year, the company produced more than 580,000 boe/d. Atyear-end, proved reserves of oil, gas and NGLs totaled 2.4 billionboe. About 10% of Devon’s annual production comes from the

Gulf of Mexico. The company’s operations range from shal-low continental shelf waters to projects in the deep watermore than 150 miles from the Texas and Louisianacoasts. Devon’s deepwater exploration program focuseson high-impact projects with potential to expose thecompany to large reserves with significant productionpotential. Since 2002, Devon has announced theCascade, Jack, St. Malo and Kaskida discoveries inthe Lower Tertiary formation more than 100 miles(161 km) off the Louisiana Coast.

In the Gulf of Mexico’s Miocene trend, Devonis active in a number of projects, including theMerganser discovery acquired through thecompany’s merger with Ocean Energy in 2003.Merganser, offshore Louisiana in 8,100ft(2,471m) of water, will be produced by theIndependence Hub and produce about50 MMcf of natural gas per day net to Devon.The company holds a 50% working interest inthe project, which Anadarko operates.Headquartered in Oklahoma City, Devon has

more than 4,700 employees worldwide. It is aFortune 500 company, is included in the S&P 500

Index and trades on the New York Stock Exchangeunder the ticker symbol DVN.

Anchor producer DominionDominion Exploration & Production Inc., the natural gas and oilE&P subsidiary of Dominion, is one of the largest independentnatural gas and oil operators. It has onshore and offshore reservesin West Texas, the Appalachian and Michigan basins, the Mid-Continent region, the Rocky Mountains, western Canada, on theGulf Coast and in the Gulf of Mexico.Parent Dominion has more than 6 Tcf of proved natural gas

reserves, 7,900 miles (12,711 km) of natural gas pipeline and thenation’s largest natural gas storage system, with about 960 Bcf ofcapacity. The company’s assets also include about 28,100 MW ofpower generation capacity and 6,000 miles (9,654 km) of electrictransmission lines.


Recent Gulf of Mexico discoveries will further solidifyDominion Exploration & Production as one of the largest inde-pendent operators in the deepwater area.The company’s East, West, Canada and Gulf of Mexico busi-

ness units produce nearly 1.2 Bcfe daily in natural gas and oilfrommore than 25,000 onshore and offshore wells. The focus forthe future balances lower risk onshore E&P with successful deep-water programs in the Gulf of Mexico.Of the 1 Bcf/d of capacity at Independence Hub, Dominion

Exploration & Production has about 20% and expects to fill up itsshare of the capacity with production from its three fields thatwill initially flow to the Hub – Spiderman with three wells, SanJacinto with two wells andQ with one well.The company’s total net reserve for the three fields is between

200 Bcf and 300 Bcf, said Richard Fowler, vice president of deep-water development with Dominion Exploration & ProductionInc. “When producing 200 MMcf/d through the Hub, it will bea significant boost in our current offshore production.”

Anchor producer HydroFounded in 1905, Hydro was a Fortune 500 energy andaluminum supplier with 33,000 employees in almost 40countries before the merger of its Oil and Energy Divisioninto Statoil.On Dec. 18, the boards of directors of Hydro and Statoil

announced they had agreed to recommend to their shareholdersa merger of Hydro’s oil and gas activities into Statoil, creatingthe largest offshore operator with a strengthened platform forfuture growth.The new company will have a combined production of 1.9 mil-

lion b/d this year and proven oil and gas reserves of 6.3 billionboe. Hydro’s equity production of oil and gas in 2005 averaged563,000 boe.The proposed merger is subject to approval by the general

meetings of the two companies as well as by regulatory authori-ties. The meetings were to be held during the second quarter thisyear and closing is expected in the third quarter. In the mean-time, Hydro and Statoil will be managed as separate companies.Hydro has a history of finding innovative ways to increase

oil and gas recovery and has been in the forefront in usingvirtual reality and multi-branch wells as well as deepwater andsubsea technology.Hydro entered the Gulf of Mexico in 2001; the 2003 Lorien

discovery, where Hydro has a 30% stake, was the company’s firstexploration success in the Gulf. Hydro’s acquisition of Spinnakerin December 2005 was an important step in expanding its deep-water portfolio.Spinnaker’s activities included exploration, development and

production, predominantly in the Gulf of Mexico. In theIndependence project area, Spinnaker owned 18% of Spiderman;27% of San Jacinto; and 50% of Q. ★

Company Profiles

ABS Offshore ..........................................................................................................69

Heerema Marine Contractors.......................................................................................70

Kiewit Offshore Services Ltd.......................................................................................72

Welspun ..................................................................................................................74

SBM Atlantia Inc. ....................................................................................................76

FMCTechnologies Inc................................................................................................77

Helix Energy Solutions ..............................................................................................78

INTEC Engineering .................................................................................................79

Oil States Industries Inc.............................................................................................80

Pegasus International Inc............................................................................................81

Subsea 7..................................................................................................................82

Roxar......................................................................................................................83

Weatherford ..............................................................................................................84

Describing the project as “massive,” BobMajor, ABS proj-ect manager, said the Independence Hub represents thethird application of polyester/synthetic moorings in the

Gulf of Mexico.ABS has classed the deep-draft semisubmersible hull with

integrated topsides as an A1 Floating Offshore Installation.Classification is part of a life-long process to monitor that aunit is built andmaintained to ABS and industry-acceptedstandards, Major said. Basically, there are four steps to classifi-cation: development of rules, design review, surveys duringconstruction and surveys after construction.In the case of the Independence Hub, Major said, areas of

emphasis included: ballast control redundancy, structuralintegrity and buoyancy after damage while also considering theunit’s compliance and readiness in terms of fire-protection,fire-fighting and life-saving equipment.Mooring system design is one element ABS reviews in the

overall classification or certification process. The IndependenceHub features a 12-line taut polyester/chain mooring systemconnecting to 12 suction pilings.“Our challenge is to help operators find the safest, most effec-

tive and, in this case, lightest mooring system tomatch the rangeof environmental loads the installation will face,” he said.“Syntheticmooring lines are lighterweight than steelmoorings

in seawater, offering the deepwatermarket neutral buoyancy and amuch lighter loadon the overall platform system.As a result,operators candedicatemore space to payload, such as productionequipment, and less to supporting theweight of heavy steel strand.”Environmental loads resulting from wind, waves and cur-

rent are the key considerations in choosing a mooring system.These factors pose increasing risks and technical challenges asactivity moves farther offshore and into more hostile environ-ments. In the case of the Independence Hub, the unit has an8,000-ft (2,440-m) water depth at the platform, making it thedeepest offshore platform as well as the deepest project usingpolyester moorings.For ABS, reviewing this mooring configuration and its

material was not new, having gained the regulatory approvalfrom the U.S. Minerals Management Service and U.S. CoastGuard for the first approval for the permanent use of polyestermoorings in the Gulf of Mexico for BP’sMad Dog truss spar.However, because of the ultra-deepwater depth and in light ofrecent hurricanes, the mooring system received a significantamount of scrutiny. ABS worked closely with the owner anddesigners on acceptance of this in such deep waters.

Prior to bringing acceptance of this technology into the GulfofMexico, ABS worked with offshore pioneer Petrobras in theuse of synthetic rope for its taut-legmooring system installed onthe P-27 semisubmersible offshore Brazil in the Campos Basin in1998. One year later, ABS issued the industry’s first GuidanceNotes on SyntheticMoorings, which address abrasion, wear andother fundamental industry concerns, including non-linear stiff-ness or behavior, minimum tension requirements, creep phe-nomenon and effective handling and storage of rope.The challenge for Major and his team was maintaining the

schedule so plan reviews of the hull, topside, piping, electricaland other concerns were completed on time.“We logged thousands of hours in reviewing plans to see

that they met regulatory and class requirements,” he said. “Itwas a tremendous undertaking, and the commitment by theoperator to have state-of-the-art proven technology work in thedeepest water to date was as equally impressive.” ★

Paid Sponsorship

Classification GuidesInnovative Gas Gathering HubABS, the classification society of record for Independence Hub, has extensive experience in the Gulf of Mexico, an abilityto act on behalf of the U.S. Coast Guard and experience with polyester moorings.

ABS OFFSHORE

A 3-ft (0.9-m) section of the synthetic mooring line used in the

Independence Hub project. ABS project team members left to right

(seated) Bob Major, Project Manager; Carol Newell, Principal

Engineer, Piping & Firefighting Systems; Soheni Haque, Senior

Engineer, Electrical Engineering; Gwo Ang Chang, Principal

Engineer, Global Analysis; Yatendra Rajapaksa, Senior Managing

Principal Engineer, Foundation Design Review; and Liangzi Cong,

Senior Engineer, Global Performance & Mooring System Review.

ABS Offshore16855 Northchase Drive

Houston, TX 77060Tel: (281) 877-6000Fax: (281) 877-6851

www.eagle.orgDownload technical documents from ABS’ Rules & Guides Page


Independence Hub was the first of its kind in the Gulf ofMexico and achieved record-setting water depths andmany other “firsts” for the industry. Heerema Marine

Contractors (HMC) was responsible for the installation of thehub’s semisubmersible hull, its mooring system and steelcatenary risers (SCRs) as well as contributing to the technicalachievements of the project with a series of industry recordsin water depth and installation load.During the course of the project, HMC set records for

the longest mooring lines connected to the deepest suctionpile installations, the deepest flowline installation, thedeepest SCR installation, the heaviest SCR load on a deep-water floating facility and the deepest in-line future tie-insubsea structure.The Independence Hub facility consists of a semi-sub-

mersible hull with integrated topsides and an innovative 12-line taut polyester mooring system, supporting the SCRs.HMC used its deepwater construction vessel Balder in the dif-ferent phases of the project. The Balder is one of the largestcrane vessels in the world and measures 449ft (137m) inlength, 282ft (86m) in width and 138ft (42m) in depth. Itstwo cranes have a joint lift capacity of 6,300 t. The Balder alsohas one of the world’s largest capacity J-lay towers for deepwa-ter pipelaying.Cor Verdult, who managed the project for HMC, said the

Balder was involved for a total of 15 weeks in the installationof the Independence Hub project. The company’s part of theproject was executed in three phases, starting last year withthe installation of the suction piles and ending in July withthe installation of the hub, the polyester mooring ropes andeight SCRs.

Phase I—Suction piles installationThis first phase involved the transportation and installationof 12 mooring assemblies, each consisting of a suction pile,anchor chain, connecting shackles and a subsea connector.The components were assembled onboard the Balder and thenlifted, upended, over-boarded and installed.The suction piles, installed at a water depth of 8,011ft

(2,442m), are the world’s deepest. They were installed withthe help of remotely operated vehicles (ROVs) andtransponders on the suction piles. All piles were installedwithin the required tolerances for positioning, orientationand inclination.It was the first time suction piles, subsea structures and

pipelines were installed at such depths and significant engi-

neering, planning and investment was required to ensureactivities were executed safely and securely.The Balder also performed a challenging installation of two

flowlines from subsea manifolds to subsea satellite wells.What makes this installation significant and unique is thatthe flowlines were shorter than the water was deep. The firstflowline – 3,270ft (997m) long – was installed in theSpiderman field at a water depth of 8,080ft (2,464m). Thesecond one – 6,440ft (1,964m) long – was in the Jubilee field,where the water depth was 8,730ft (2,662m).

Phase II—Semisubmersible hull, moorings installationIn January, HMC installed the Hub and the SCRs using theBalder in the five-thruster mode. (Because of a flooding inci-dent in December, two of the Balder’s seven thrusters were outof service.) The five-thruster mode was sufficient to install themooring wires and the SCRs. For the heaviest 20-in. gas-export SCR, the Balderwas required to use at least sixthrusters. Project Engineer John Bouwman explained that tomeet this challenge, HMC developed an alternative pull-inprocedure that uses a long pull-in wire. This new methodreduced the thrust requirement for the Balder and was astrong factor in getting the client’s approval for the perform-ance of the hang-off of the gas-export SCR with only fivethrusters in operation.In February, the Balder installed the semisubmersible hull,

which is connected to the suction piles with 12 polyester

HMC Sets Series of Industry RecordsThe landmark Independence Hub Project, with its four operators and 10 gas fields, is not only a commercially creativeenterprise, but also a project characterized by significant technical feats.

HEEREMA MARINE CONTRACTORS

HMC’s deepwater construction vessel Balder next to the

Independence hub platform.


mooring lines. The mooring lines are the world’s longest at2.4 miles (3.86 km) each. The vessel attached the mooringlines to the platform and the suction piles through a deploy-ment and hook-up sequence. The three segments of the poly-ester mooring lines were deployed using the Balder’smooringline deployment winch. With the chain connected to the poly-ester segments, the Baldermoved to the semi-submersible hullfor the mooring line hook-up. The installation was performedin record time (19 days) thanks to favorable weather condi-tions and teamwork.

Phase III—SCRs installationHMC was contracted to install five 8-in. SCRs and a 20-in.export SCR to the Hub facility. In April, the Balder completedthe installation of the export SCR, the world’s deepest andheaviest riser installation producing the heaviest SCR loads(800 t) at installation. The SCRs connect a network of flow-lines to the hub facility. Bouwman said the installation of the20-in. export SCR required the use of equipment to its limit,and procedures had to be devised to perform the installationefficiently and safely.The Balder (with all thrusters operational again) returned to

the Independence Hub location at the end of June to finishthe installation of the four remaining SCRs, Verdult said. Thefifth SCR (JVC-West) had to be repaired before it could behung into the porch of the Hub. The Balder’s J-lay tower wasrequired to perform this repair, which involved cutting andremoving the existing flex joint, repositioning and welding anew flex joint to the end of the SCR. The repair occurredmore quickly than anticipated; however, strong currents ham-pered the installation of the last three SCRs. This made thejob challenging for the Balder’s ROVs, so additional ROVs andtugs were used.Strong and unpredictable currents in the area made preci-

sion maneuvering a major challenge, Bouwman said. Since

one of the thrusters of the Balder was temporarily out of serv-ice, procedures had to be modified. Extra tugs were used tokeep the Balder stationary. Bouwman said he is very proud ofthe outcome.“We did it. The last SCR was installed on July 17,” he said.

CooperationBeing the world’s deepest development to date, theIndependence Hub Project was unique. With so many techni-cal and logistic challenges, flexibility proved crucial,Bouwman said. Adverse weather conditions, delays, andchanges in scope and execution meant HMC needed to adaptto new circumstances all the time, often at short notice.The offshore execution of this project during the past 14

months has been a tremendous achievement for HMC,Verdult said. The various departments involved in the projectset a number of new world records in the offshore industry.All personnel demonstrated flexibility and the ability to adaptto various schedule changes.Flexibility on the part of the client, other parties and HMC

characterized the project. This made it possible to achieve ahigh level of cooperation, which, in turn, was a key factor inthe project’s success. ★

Paid Sponsorship

Heerema Marine ContractorsPO Box 9321 2300 PH Leiden

The NetherlandsTel: 31 (0) 71 579-9000Fax: 31 (0) 71 579-9099

[email protected]

The Balder’s J-lay tower in action.

The pipeline and riser are welded together prior to installation.


Due to the ability to accommodate ultra-deep waterconstruction projects, in May of 2004 Kiewit’s newfacility was chosen to construct the largest and deep-

est project – Independence Hub. KOS’ original scope ofwork entailed fabrication of the topsides, lifting and settingthe facility atop the floating hull and integrating all equip-ment and hull systems. Aside from setting industry recordswith the installation of Independence Hub, the job alsoscored a KOS facility-best as its heavy-lifting device (HLD)raised and set the 8,400-ton topsides onto the unit’s hull.This feat saved time and reduced cost for the overall project.Based on reserve estimates at the time, the hub was

designed to process 850 MMcf/d. During the course ofconstruction, three new discoveries by the producers whowere to lease the production platform expanded this origi-nal estimate. The capacity was raised to 1 Bcf/d, and thenecessary modifications expanded KOS’ original scopeof work.Prior to the new discoveries, KOS had set high expecta-

tions early and moved the project ahead of its originalschedule. This gave Kiewit the advantage to play a largerrole in the expansion of the platform’s processing capabili-ties. The company completed all the necessary additionalwork to finish the required expansion and maintain theproject schedule. KOS also assumed responsibility for per-forming additional work to complete the construction ofthe semisubmersible’s hull, which had been delivered froma Singaporean shipyard.From November 2004 through December 2006, KOS

nearly doubled its original man-hours due to scopegrowth. Almost a million man-hours were worked on theproject with no accidents, and the project was completedon time.Kiewit Offshore Services Ltd. (KOS) has become known

for its success in building large, complex offshore oil pro-duction platforms at its 400-acre fabrication facility inIngleside, Texas. KOS is a subsidiary of the large Omaha,Neb.-based Peter Kiewit Sons Inc. (Kiewit). The company isknown for building some of the nation’s largest projectssince 1884. Since 1985, Kiewit has been building state-of-the-art fixed and floating structures in South Texas formost of the world’s major oil companies.In October 1988, Kiewit completed fabrication of the

1,350-ft (412-m) long Bullwinkle jacket. The 36-pile, 60-slot jacket – the world’s tallest production platform –stands 1,736ft (529m) from the sea bottom to the top of

the flare boom. The platform was constructed in Inglesideand shipped to its location in the Gulf of Mexico.Experiences like this provided Kiewit with the foresight tobring on other world record projects.As the search for new resources moved into deeper

waters, Kiewit saw advantages in increasing its offshorefabrication capabilities. After 15 years of experience in thismarket, Kiewit approved the formation of Kiewit OffshoreServices. The goal of this development was to construct a

Powerlifting on the Gulf CoastKiewit Offshore Services Ltd.’s up-to-date facility combined with planning, daily management of costs and schedules, andwell-coordinated working relationships helped complete the Independence Hub project.

KIEWIT OFFSHORE SERVICES LTD.

Independence Hub topsides being lifted by the KOS heavy-lift device.


new world-class fabrication facility in Ingleside to addressthe growing deepwater market in the Gulf of Mexico. Sinceopening the gates of this new facility in 2002, KOS has par-ticipated or is participating in the success of projects suchas Samadan Mari-B topsides and jackets, Matterhorn,Marco Polo topsides, Tarantula topsides and jacket, Elontopsides, Thunder Hawk topsides, Perdido topsides,Devon Polvo topsides and jacket, Shenzi topsides,Benguela-Belize Compliant Tower, Thunder Horse,Atlantis, Nakika and Magnolia Integrations, andPeregrino topsides and jackets.The new KOS facility provides unrestricted access to the

Gulf of Mexico along the La Quinta shipping channel inCorpus Christi Bay. With 2,100ft (641m) of continuouspile-founded bulkhead with varying water depths 25ft to55ft (8m to 17m), it also features a 77-ft (23-m) hole toallow heavy lift transport vessels to load and offload hulls,jack-up rigs and semisubmersibles and is backed by a 400-acre fabrication yard. The predominant feature on the sky-line of the yard is a twin-boomed HLD with a workingcapacity of 13,000 tons. This makes the facility ideal fortopsides installations on major floating offshore projectsand has uniquely positioned the company with heavy lift-ing capacity at the bulkhead – the solution of choice fortopsides fabrication, installation and integration projects.The Ingleside facility also promotes safety and efficiency

with an underground utility system that features a separatebreathable air system and high-pressure pipelines for gas,mixed-gas and fiber optics. The structural assembly build-ing contains more than 170,000 sq ft (15,793 sq m) of cov-ered workspace with four bays, two of which are the largestof their kind in the Gulf of Mexico with a clear span of135ft (41m). In addition, the facility contains an on-siteskills training center, a medical facility, automated fabrica-tion equipment such as CNC plate-cutting, CNC beam-cut-ting and coping, CNC tubular coping, and large-capacityplate-bending and rolling machines.Kiewit’s safety record is consistently better than the

industry average, and KOS is committed to sound con-struction practices and the highest possible standards ofsafety performance. The company develops an organizedand effective safety program for every project to providethe safest work environment possible.KOS defines quality as delivering a project that meets or

exceeds a client’s expectations. In today’s environment,contractors are assuming more responsibility for buildinga quality product. KOS has launched a quality initiative bymirroring the systems, measurements and processes, whichhave been proven so effective in the safety program. TheKOS quality program is AISC certified and complies withISO 9001:2000 standards. ★

Paid Sponsorship

Kiewit Offshore Services Ltd.2440 Kiewit Road

Ingleside, TX 78362Tel: (361) 775-4300Fax: (361) 775-4433

www.kiewit.com

Kiewit Offshore Services fabrication facility

Independence Hub topsides fabrication in process


Driven by engineering excellence, WelspunGujarat Stahl Rohren Ltd. (Welspun) isan evolving and learning company,

which has proved to be a comprehensiveprovider of state-of-the-art pipes and relatedniche products for global transportation of oiland gas.True to its motto of “dare to commit,”

accepting challenges has been a way of lifesince its inception. From high-rise mountainsand deepest darkest oceans, from tropicalforests to blazing deserts, from India to everycorner of the world, Welspun’s products haveproven their mettle across harsh terrains, ful-filling expectations.One such challenging project is Independence

Trail, considered to be the world’s deepest large-diameter pipeline.This Gulf of Mexico project involved a 134-

mile (216-km), 24-in. diameter gas pipelineconnecting 105-ft (32-m) deep draft, semisub-mersible platform in 8,000ft (2,440m) of water in theMississippi Canyon Block 920 to Tennessee Gas Pipeline inthe West Delta area.

The Hub platformIndependence Hub was conceived to handle 850 MMcf/d ofnatural gas. The pipeline’s rated maximum allowable operat-ing pressure (MAOP) of 3,640psi and desired to sustainexternal pressure of 3,516psi necessitated critical D/T ratio.Also at the deepest end, a steel catenary riser (SCR) connectsthe pipeline to the floating production facility. This is prob-ably the first time submerged arc welded pipes ( 20-in. x1.31-in. wt) were used for SCR for such depth and pressure.

Challenging diameter/thickness ratioThe making of the line pipe potentially offered challengesprimarily on account of D/T ratio. While Welspun hadestablished the strength of its mill by producing 56-in. x1.4-in. wall, making pipes with the same wall thickness(1.35-in.) in 24-in. diameter had its own challenges.

Small decision, big projectWhen this business was at a budgetary stage and Welspunwas asked to provide budgetary estimate, it not only pro-vided Enterprise with a budgetary number, but also took uprolling of the 24-in. x 1.4-in. American Petroleum Institute 5L

X70 pipe as a capability and capacity assessment exercise.“While our mill had the theoretical capacity and capabil-

ity to roll these sizes, given Welspun’s philosophy, we wouldnot have made a commitment without actually having madethe pipes. As a result, Welspun could offer even betterdimensional tolerances than the specification itself withutmost confidence, which must have played a very crucialpart in deciding the order in our favor,” said Welspun ChiefExecutive Officer and Executive Director Braja Mishra.

Track recordWelspun’s performance of meeting stringent specificationsand delivery schedules in other offshore projects likeCameron Highway and Salman added to Welspun’s abilityto complete this challenging project.

Special technical parametersThe specific requirements related to chemistry, mechanicalproperties, dimensional tolerances and non-destructivetesting were unique and previously untested. The criteriafor key dimensions like out of roundness, or OOR (0.12-in.maximum), local OOR (0.04-in. maximum) and out ofstraightness (0.37-in. maximum) of pipes were some of themost stringent requirements. The Hydro-test requirementwas between 96% and 100% of SMYS (a pressure of 7,250psimaximum) for 24-in. outer diameter pipe with thickness

Innovation and PerformanceThe world’s deepest large-diameter pipeline takes center stage.

WELSPUN


range of 0.93-in. to 1.35-in. The project specifiedthe steel be low carbon, low sulfur and microalloyed as well as calcium-treated for inclusionshape control. Another crucial requirement wasthat no lamination and/or inclusions be allowedwithin 8 in. of pipe ends as they may interfacewith automatic UT scanning of the girth weldseam. Other testing requirements includedCTODs, compression test and strain-ageing test(5% tensile strain).

SCR pipes: first time pipe weldedUsing an SCR system has gained prominencein flowline and export services. Increased pro-duction rates have resulted in SCRs of up to 20in., which was earlier up to 6 in. to 12 in. for infield flowline and up to 18 in. for export servicefor SCRs. The focus is on stringent criteria suchas controlled strength levels, enhanced straincapacity, improved fit up and fabricationperformance.To withstand the demands of high installation loads,

extreme operating conditions such as loop currents and hur-ricane force winds and waves, seamless & LSAW pipes arebeing manufactured using latest in steel making with chem-istry meeting the sour service application requirements,plate rolling practice (TMCP). Line pipe production technol-ogy for meeting tight mechanical properties (YS, TS,YS/UTS, Charpy impact, CTOD requirements) and dimen-sional tolerance (out of roundness, end diameter, straight-ness and more).

Performance better than promiseThe histograms show the different characteristics achievedon SCR pipe at Welspun’s facility.The company’s performance in terms of quality, timely

delivery has been such that it has been a proud supplier oflarge diameter pipes to Enterprise having supplied pipesworth more than US$350 million – the company’s latestbeing on onshore pipeline, which involved 89 miles (143km) of spiral-welded pipes.

Testimony of job well doneSubsequent to the completion of the Independence TrialProject, Welspun had been responsible for supplying theentire quantity of large-diameter pipe for their next offshoreproject involving supply of 83 miles (134 km) of pipe.Welspun is being considered for most of the deep off-

shore projects as a front-runner in most parts of the worldexcept for North Sea where Welspun is not yet active. It isalready working to enlist itself with potential customers likeStatoil and ConocoPhilips.

Welspun boasts of an elite vendor listing with customers,including Exxon, Chevron, Total, Enterprise, BG, KinderMorgan, TransCanada and Saudi Aramco. It also has proj-ects like Independence Trail, Cameron Highway, Salman andGolden Pass in its portfolio for its 7 years of operation.

The last wordAside from a fast growth in its business (10 times in 6 years),Welspun believes in best corporate governance and corpo-rate social responsibility. The company has taken several ini-tiatives in the fields of education, health and vocationaltraining to empower individuals and contributing to society.Several measures have been undertaken for the preservationof environment by harvesting water, setting up waste dis-posal and treatment plants in all manufacturing facilitiesand ensuring health and safety.As more milestones are crossed, Welspun commits to fur-

ther spread its reach and live the dream of being the best.Welspun cherishes the trust of customers, which gives thecompany courage to face the future. More importantly, itgives the confidence to strive to sustain the growth momen-tum in the coming years. ★

Paid Sponsorship

WelspunTradeWorld, ‘B’ wing, 9th Floor

Kamala Mills CompoundSenapati Bapat MargLower Parel (West)Mumbai – 400013

Tel: +91-22-66136000Fax: +91-22-24908020www.welspun.com


In 2002, in response to a significant trend of discoveries inthe Gulf of Mexico at depths nearly double that of thedeepest installed tension-leg platform, the company (then

Atlantia Offshore Ltd.) reached the strategic decision toexpand its product portfolio with new design capable of eco-nomically developing these new ultra-deepwater reserves. Theresult was the DeepDraft Semi, a four-column semi-sub-mersible production facility whose first application serves asthe centerpiece for the one of the industry’s most significantprojects – Independence Hub.

The DeepDraft SemiDuring the past decade, semisubmersible production facilitieshave become increasingly popular for deepwater developments,particularly on large Gulf of Mexico fields. However, whereasthe design of these previous facilities was driven primarily bythe need to accomodate specific payloads, development of thissemi-submersible concentrated on the critical link between thereservoir and the floater – the steel catenary riser (SCR).Prior to the DeepDraft, it was found that the natural heave

and pitch motions of traditional deepwater semisubmersiblescould cause high compressive loading at the touchdownpoint of the SCR. This in turn led to fatigue issues exacer-bated further in extreme conditions such as the 100-yearstorm design criteria and high currents.SBM Atlantia, in collaboration with sister company

GustoMSC Inc., one of the industry’s leading designers ofsemisubmersible drilling units, solved this problem by length-ening the deck support columns and increasing the draftbeyond the typical 90ft (27m) used on traditional semisub-mersibles, to a total of 105ft (32m). By extending this draftand the pontoon below the wave zone, not only is wave-induced motion reduced, but also additional ballast capacityis available to increase the mass of the hull and therebyincrease the structure’s natural period beyond wave periods.The design also lowers the structure’s center of gravity, fur-ther mitigating pitch and roll motion.In addition to effectively supporting SCRs, the DeepDraft

Semi design is also optimized for quayside integration of thetopsides facility. This capability eliminates the many weatherand economic risks of a costly offshore deck lift and furtherallows for significant hookup and commissioning activities tobe performed with efficient and cost-effective onshoreresources prior to tow-out to the installation site. ★

Paid Sponsorship

TheWorld’s First DeepDraft SemiWith five successfully installed SeaStar tension-leg platform units delivered since 1998, all on time and on budget, thecompany has established itself as a premier provider of deepwater production solutions to the Gulf of Mexico market.

SBM ATLANTIA INC.

SBM Atlantia Inc.1255 Enclave Pkwy.Houston, TX 77077

Tel: (281) 899-DEEP (3337)Fax: (281) 899-4301

www.sbmatlantia.com

The DeepDraft Semi hull under construction in Singapore

The Independence Hub DeepDraft Semi


When it reaches peak capacity, the $2 billionIndependence Hub project is expected to producenatural gas at a rate of 1 Bcf/d, or about 2% of

America’s production. It is gas that might never have beenproduced had Anadarko, ENI, Hydro, Enterprise and Helixnot joined forces to connect 10 discoveries that would havebeen uneconomic to develop individually. As a result of theircooperative efforts, 2 Tcf of reserves will eventually be pro-duced through this deepwater hub.

Setting deepwater recordsThe Independence platform is the deepest set. The platform,however, is just the start. The challenge of producing hydrocar-bons at these depths required subsea production equipmentcapable of withstanding intense pressures, cold temperatures andharsh conditions of the deep-sea environment.FMCTechnologies has extensive experience in providing sub-

sea solutions and overcoming deepwater challenges in the GulfofMexico, so it was selected to participate in this project.In March 2005, Anadarko awarded the initial contract for

the Independence Hub, calling for 10 trees and associatedequipment. Since then, the scope of supply has expanded toinclude 17 enhanced horizontal Christmas trees (EHXT) forall partners. In addition to the trees rated for operating pres-sures of 10,000psi, FMC is also supplying manifolds, valvesand connector hubs for inline sleds, pipeline end terminationsand jumpers. Fifteen trees have been installed in a successionof world record depths ranging from 7,900ft (2,408m) to9,000ft (2,743m).

EHXT becomes the standardThe EHXTwas selected independently by all operators andended being the standard for the Independence Hub. Availablein 10,000- and 15,000-psi models, it is the world’s most techni-cally advanced completion system and is designed tomeet thedemanding requirements for high-pressure, high-temperatureand critical service in deepwater environments. The EHXTdesign offers producers significant advantages in delivery time,installation cost and capital expenditure. Installation of theEHXT is simpler as it can run with a tree-on-wire system elimi-nating the critical path dependence on the drilling rig. Also,completion and well workovers can be handled through thestandardmarine drilling riser, eliminating the need for a specialcompletion riser. Downhole equipment is installed and retrieved

through theEHXTwithouthaving to disturbthe tree or itsexternal connec-tions to flow-lines, servicelines or controlumbilicals.EHXT’s

“enhancements”are primarilybased on thedesign of its tubing hanger and tree cap. Experience has shownthat the traditional internal tree cap (ITC) requires additionalsteps and rig time to install reliably due to debris that can collectin the ITC’s landing profile. The EHXT design eliminates theinternal tree cap and instead uses a lightweight tree cap installedby a remote operated vehicle off the drilling rig’s critical path,after the blowout preventer has been disconnected, allowing for amore cost-effective and reliable horizontal completion.

Modular designThanks to itsmodular, standardized design, the EHXT isextremely flexible. Installed inmore than 150well completions,the EHXT can be customized in numerous configurations andcan be readily produced for a variety of project-specific applica-tions. In addition to flexibility, standardization also helps speeddelivery, an important factor for the Independence project.Six years has elapsed since the first discovery in 2001 and 4

years since the initial Independence agreement to first prod-uction. FMC was awarded the contract for subsea systems inMarch 2005, and by year-end, the first deliveries were complete.Best of all, the entire project was completed safely without asingle lost-time incident. ★

Paid Sponsorship

Setting New Recordswith Independence Hub ProjectFMC Technologies is no stranger to industry firsts or world records. As the supplier of subsea production equipment forthe Independence Hub, the company has joined forces with some of America's leading independent oil and gas compa-nies to set new records for the world's largest and deepest offshore hub project.

FMC TECHNOLOGIES

FMC Technologies1777 Gears Road


www.fmctechnologies.com


Helix Energy Solutions(Helix) is proud to part-ner with Enterprise

Field Services LLC (Enterprise),the owner and developer of theIndependence Hub project.Independence Hub provides aninnovative solution for thejoint development of 10 gasfields in a new promising ultra-deepwater gas basin in the Gulfof Mexico. The owners of thesefields joined forces withEnterprise and Helix to connecttheir individual fields to a cen-tral facility and reduced thefinding and development costand lease operating cost ofthese gas fields.“The strategy of our com-

pany is to enhance the eco-nomics of marginal fields indeepwater,” said BartHeijermans, Helix Energy Solutions chief operating officer.“We endeavor to use our capital and assets to grow servicesthat help to lower the finding and development costs fordeepwater fields. We want to find new and better ways ofmaking marginal fields commercial. Simply stated, wewant to be the leading company in enhancing marginalfield economics.”Helix often manages all aspects of marginal field develop-

ment and has structured its business model to facilitate thisstrategy. The model employs a two-pronged approach inwhich Energy Resource Technology Inc. (ERT) is interrelatedwith and supported by an energy services division, HelixContracting Services, which is comprised of DeepwaterContracting, Canyon Offshore, Cal Dive International, WellOps, Production Facilities and Helix RDS. Working together,these divisions can successfully transform marginal fieldsinto economically viable assets. ERT does prospect genera-tion, acquisition, exploration, development and production.Helix Contracting Services entities offer deepwater construc-tion, pipelaying, robotics, diving services, rig-less subsea wellintervention, production facilities infrastructure leasing serv-ices, and reservoir and well technical engineering expertise.Examples of Helix’s two-prong strategy can be seen on the

company’s Phoenix project in the Gulf of Mexico. OnPhoenix, a redevelopment of the Typhoon field, ERT isemploying the company’s construction services division toredevelop the field. The conversion of a former train ferry ves-sel into the Helix Producer I dynamically positioned minimalfloating production vessel will enable the company to obtaina redeployable floating production facility for a lower costand shorter delivery time than if it had been purpose-built.“There is still a lot of undeveloped marginal oil and gas

fields in the world that require the application of innovativemethodologies and low cost assets in order to attract devel-opment capital,” Heijermans said. “Helix has the methodolo-gies and the tools to make a difference.” ★

Paid Sponsorship

Enhancing Field EconomicsHelix Energy Solutions Group combines the interests of producers and contractor by investing in mature offshore oiland gas properties, hub production facilities and proven undeveloped reserve plays, in partnership with other industry-leading companies.

HELIX ENERGY SOLUTIONS

Helix Energy Solutions400 N. Sam Houston Pkwy E.

Suite 400Houston,TX 77060Tel: (281) 618-0400Fax: (281) 618-0500www.helixesg.com

The Helix Express pipeline construction vessel played an important role in bringing the

Independence Hub project online.


INTEC Engineering has been providing specialized frontierand deepwater engineering services for more than 20 years.“INTEC proposed a team of experienced engineers that

had successfully provided engineering for the Canyon Expressproject that had similar challenges of deepwater gas develop-ment of multiple fields with multiple operators,” said VinceVetter, business manager, offshore field developments forINTEC and the company’s project manager for IndependenceHub. “We started in February 2004 and continue to supportthe Independence Hub team.”Using eight senior engineers as well as support staff,

INTEC provided the core subsea engineering team for thedeepwater developments in the critical project phases ofconceptual engineering and front-end engineering design(FEED). The company also assisted in the execution and con-struction phase, particularly in the areas of flow assuranceand operability.During the concept-engineering phase, INTEC generated

and evaluated several field layout options and proposed thebest technical and cost-effective system solutions for furtherstudy in the subsequent FEED study phase.“Amajor purpose of the study was to highlight any technical

issues relating to the extreme water depth of the developmentand to prequalify equipment vendors and installation contrac-tors andmethods,” Vetter said. “A further purpose of the studywas to highlight any potential cost or operational synergies thatcould be obtained from amulti-operator, multi-field develop-ment. The concept selected was a hub-and-spoke principle witha centrally located host facility as the hub.”The subsea system included major components such as

wellheads, trees, manifolds, jumpers, flowlines, risers, umbili-cals and subsea production controls. Using a systemsapproach, interfaces were managed to produce a coordinateddesign suitable for the seabed topology, available installationoptions and connection to the Independence Hub.In the FEED phase, the concept was developed in greater

detail and validated to be a practical system. Specificationswere generated and scopes of work were developed. “Bid pack-ages were prepared for vendors and contractors,” Vetter said,“and documents were prepared for regulatory filings.”In the execution phase, INTEC continued to provide engi-

neering assistance in the various subsea disciplines. Flowassurance and operability were continued, and operating pro-cedures were outlined in detail.

“Designing thesystem componentsand planning thedetails of operationsfor the fields pre-sented several chal-lenges,” Vetter said.These included flowassurance issues ofmanagement of theliquid surges, man-agement and preven-tion of hydrates andmanagement of lowtemperatures, bothsubsea and topsides.“Independence

Hub highlights thevalue of using a sys-tems engineeringapproach for a complicated development,” Vetter said. “Thesubsea concept accomplished the challenging task of findingthe right technical and economical solution. A major focuswas the challenge to design the subsea architectures to assureflow and operability of all fields for the life of the project, eventhough the non-unitized fields have different owners/opera-tors with varied decision drivers.“Designs, equipment and processes were chosen, or devel-

oped when necessary, that were fit for purpose and that lever-aged the experiences of the stakeholders,” Vetter said.“Interfaces were proactively managed by staffing the projectwith senior experienced engineers that met frequently in a cli-mate that encouraged clear communication. The success ofIndependence Hub is not a surprise to those involved with it; itwas a planned event.” ★

Paid Sponsorship

Experienced Team MeetsMultiple ChallengesWith extensive experience in projects highlighted by many industry “firsts” regarding distances and depths, the AtwaterValley Producers Group selected the company for the Independent Hub developments.

INTEC ENGINEERING

INTEC Engineering15600 JFK Blvd., 9th Floor


www.intec.com


The Independence Trail gas export pipeline begins in about8,000ft (2,440m) of water at the new IndependenceHubfloating facility in theMississippi CanyonBlock 920 and

extends to a new platform inWest DeltaBlock 68.For the Trail, Oil States Industries Inc. provided two 12-in. x

16-in. x 24-in. 1500 ANSI dual-hub tee sled assemblies. One ofthe assemblies was installed in the 24-in. 1.35-in. wt section ofthe pipeline in about 6,500 fsw. The other assembly wasinstalled in the 24-in. 1.22-in. wt section of the pipeline inabout 4,500 fsw.

Each dual-hub tee assembly wasfabricated with a 24-in. mainline, one12-in. x 24-in. x 24-in. tee fitting, one16-in. x 24-in. x 24-in. tee fitting, one12-in. 2500 ANSI Cameron ball valve,one 16-in. 2500 ANSI Cameron ballvalve, one 12-in. male hub and one16-in. male hub.Oil States’ project manager Steve

Ippolito noted that this criticalproject was completed on time andwithin budget largely because of theextraordinary teamwork by all com-panies involved along with imple-mentation of lessons learned fromprevious projects with the client andinstallation contractor.Additional equipment supplied as

part of the connector systems included two 12-in. 1500 ANSIvertical non-integral collect connectors, two 16-in. 1500 ANSIvertical non-integral collect connectors, two 12-in. 1500 ANSIremotely operated vehicle (ROV) operable male end closuresand two 16-in. 1500 ANSI ROV operable male end closures.Both dual-hub tee assemblies also incorporated a dual-

buoyancy yoke system that Allseas designed as well as a newinnovative mudmat assembly designed by Oil States subseaengineering team that included a pin type installation system,which allowed for each mudmat assembly to be installed as asingle unit instead of having to be assembled beyond the ten-sioners as the pipeline hung in the installation vessel’s stinger.The design team said this new design approach substan-

tially reduced the pipeline moment offshore thereby reducingoverall system stresses during installation.The mudmat installation time was reduced by about 3

hours on each unit and could be completed in less than 5minutes with the proper setup.The client’s installation representative commented that the

new mudmat design incor-porated a number ofimprovements learned frompast installations. Theimprovements significantlydecreased offshore runningtime, improved reliabilityand most importantlyreduced personnel exposuretime, enhancing safety.In addition to the

above equipment, OilStates designed andmanufactured FlexJoint®

steel catenary riser (SCR)connections for theIndependence hub’s eightproduction risers and onegas export riser as well ashull receptacle assembliesfor these risers and forfuture SCR installations. A unique challenge for installationof Independence Hubs multiple risers was met by Oil States’design and manufacture of four cross-haul tools, whichhelped solve problems faced by retrieval and hang-off ofmultiple risers pre-laid subsea. ★

Paid Sponsorship

Independence Trail Receives AssembliesOil States attributes the majority of the project’s success to teamwork and cross-company collaboration.

OIL STATES INDUSTRIES INC.

Oil States Industries Inc.7701 S. Cooper St.Arlington, TX 76001Tel: (817) 548-4200Fax: (817) 548-4250www.oilstates.com

Steel catenary FlexJoint with lay-down tool in shipping frame

Deployment of a 24-in. dual-hub,

inline tee sled assembly manufac-

tured by Oil States Industries Inc.

Gas export FlexJoint

prior to final hang-off

to the Independence

Hub platform


Management within Pegasus realizes the value of solv-ing new technological challenges on a regular basisin the emerging subsea/deepwater arena. The com-

pany’s capability to cover all aspects of the mechanical designand flow assurance from front-end engineering and designthrough detailed design to commissioning defined its role inthe Independence project, one of the largest offshore projects.When a consortium of five independent producers and one

energy company came together to develop multiple ultra-deepwater natural discoveries in the eastern and central plan-ning areas of the Gulf of Mexico, Pegasus was asked to supplyengineers to play a role in the Independence project team.Based on the company’s previous experience with more than200 deepwater projects since the early 1990s, this role eventu-ally expanded into the broader spectrum of project manage-ment in the topsides and subsea portions of the project.Throughout the planning, Pegasus provided support to

each company’s efforts by managing necessary tasks such aswriting specifications for each phase of the work and thenreading and reviewing submitted construction procedures toassure all work was carried out in compliance with regulatoryand industry standards. In addition, Pegasus performed con-struction management and inspection tasks, which were vitalto this project located 124 miles (200 km) from land. Pegasusalso provided significant engineering and drafting support formany of the project’s work scopes.Aside from the distance of the hub from land, the

Independence Subsea project offered its own unique chal-lenges. At depths of up to 9,200ft (2,804m), no previous pro-duction facility had surpassed the scope of the currentproject. While Pegasus initially was asked to play a small rolein supporting the installation of pipelines and umbilicals, thistoo was eventually expanded into a broader scope.The company’s scope for the subsea portion included con-

struction management for the installation of about 195 miles(314 km) of flowlines in 11 segments with seven steel catenaryrisers included and 8-in. line sleds as well as 12 pipeline endtermination sled assemblies. In addition, Pegasus also man-aged the installation of more than 140 miles (225 km) of pro-duction control umbilicals in 17 segments with five dynamicriser sections and 29 associated subsea structures. The umbili-cals were the first to use carbon fiber rods for tensile rein-forcement of umbilicals.Because of the immense scale of the Independence project,

some innovations were inevitable. Pegasus worked with TDWilliamson and Allseas to develop a flowline recovery tool

capable of dewatering the flowline on the seabed as a contin-gency plan against the high pressures of the project’s deepwa-ter environment. High currents also proved difficult at thisdistance into the Gulf, so a V-Lay method was developed withHeeremaMarine Contractors to ensure the safety and effi-ciency of the pipelay process. Pegasus also worked with ShellGlobal Services to develop S-Lay vortex-induced vibration sup-pression fairings capable of withstanding high roller loads.These required remotely operated vehicle removable lockingassemblies to maintain fin orientation over the stinger.A high-level management team of independent companies

carried out the Independence project. Pegasus provided thenecessary conglomeration to organize each company’s effortsand maintain focus on the overall goal.

“The benefit of the Independence project was its ability toopen the playing field for deepwater operations,” said D.J.Blockhus, a pipeline engineer with Pegasus. “It proved thatsmall- and medium-sized independent production companiescould accommodate large projects with the proper amount ofmanagement and coordination.” ★

Paid Sponsorship

Management Makes HistoryPegasus International Inc., one of the largest independent subsea and pipeline-engineering consultants, holds an impres-sive project track record that includes involvement with major deepwater developments around the world.

PEGASUS INTERNATIONAL INC.

Straked steel catenary riser installation using S-Lay method from

Allseas’ dynamically positioned pipelay vessel Solitaire


Pegasus International Inc.777 N. Eldridge Pkwy., Suite 300

Houston, TX 77079-4524Tel: (713) 465-5777

www.pegasus-international.com

In addition to modern equipment and expert engineeringand project management teams, the company alsobrought an impressive track record of performing work in

extreme ocean depths. Prior to the company’s involvementwith Independence Hub, it had worked on theNa Kika proj-ect from 2001 to 2003. Installing more than 70 miles (113km) of umbilicals at depths from 5,400ft to 7,598ft (1,647mto 2,317m) provided the company with practical experience inthe deepwater Gulf of Mexico. The company also took part inthe Thunderhorse, Glider and South Diana projects. Theseprojects, combined with the company’s numerous deepwatersubsea installations offshore Brazil, Africa and in the NorthSea, prepared it for its recent role in Independence Hub.As the term “deepwater” is constantly redefined, offshore

technology extends its reach. “When I came to the U.K., wewere working in around 328ft (100m) in the central NorthSea,” said Murray Dick, Subsea 7’s project manager forIndependence Hub. “Then we went West of Shetlands to1,476ft to 1,640ft (450m to 500m). Now here we are in theGulf of Mexico laying umbilicals down to 8,960ft (2,731m),pushing the boundaries yet further again.”Subsea 7’s main scope of work on the Independence Hub

project involved transportation, installation and testing ofmore than 118miles (190 km) of umbilicals in water depthsranging from 7,825ft (2,387m) at San Jacinto to 8,960ft(2,731 m) atCheyenne. Beginning on August 29, 2006, theToisa Perseus embarked fromMobile, Ala. After more than 190days, the company had installed seven main umbilicals, fiveextension umbilicals and three infield umbilicals. The projectalso called for the installation of three manifolds, seven subseadistribution units, 23 SHO receivers/mudmats, 23 rigid flow-line jumpers along with steel flying leads and electrical flyingleads. The company had completed the project by mid-July, butnot before achieving two record-setting installations of its own.

Deepest umbilical and ‘Q’ tree installedThrough its involvement with Independence Hub, Subsea 7achieved the world’s deepest installation of an umbilical andwellhead Christmas tree at Q field using the fiber ropedeployment system from the Toisa Perseus.The company helped develop a fiber rope deployment sys-

tem that assisted both installations in water depths of 8960ft(2,731m) with Toisa Perseus. The system proved fiber rope hassignificant potential for deepwater installation operationswhen compared with steel wire.While fiber rope maintains the same strength as steel, it

has a specific gravity of 1.2 compared with 8 for steel. Itsweight is close to zero in water, so when working at depths of9,843ft (3,000m) this creates quite an advantage. The sub-merged weight of steel wire represents 60% of the allowedhook load, which gives the 1.6% of fiber rope a broader appealfor use in deepwater operations because its capacity is whollyavailable for handling payloads. In addition, its low weightallows more accurate active heave compensation (up to 95%)to be achieved with higher speed and less power consumptionthan with steel wire, reducing cost and improving safety.With records in place, Subsea 7 completed the project and

is active in other areas. The Seven Oceans, Subsea 7’s new deep-water rigid reeled pipelay vessel, is due in the region to workon Blind Faith soon. However, the company continues tolook for new frontiers.

“I am now looking forward to pushing back the deepwa-ter boundaries once again in the Gulf of Mexico — I have afeeling that the Cheyenne record won’t be current for toolong,” Dick said.Subsea 7 provides engineering and construction services

with an approximate 4,000-strong workforce supporting off-shore operations in Asia Pacific, Brazil, Gulf of Mexico,Norway, United Kingdom and West Africa. ★

Paid Sponsorship

Pushing Back Deepwater BoundariesWith a workforce of more than 5,000 people worldwide, a fleet of industry-leading dynamically positioned ships capableof reeled steel and flexible pipe lay, subset construction and saturation diving as well as a portfolio of pipeline construc-tion yards worldwide, Subsea 7 is well suited to take part in the record-setting installation of Independence Hub.

SUBSEA 7

Subsea 715990 N. Barker’s Landing Road

Suite 200Houston, TX 77079Tel: (281) 966-7600Fax: (281) 966-7623www.subsea7.com

Toisa Perseus laying Cheyenne extension umbilical, which is the

deepest to date.


Roxar’s subsea Wetgas meter and subsea Sandmonitorwere chosen as monitoring solutions for the project.The Roxar subsea Wetgas meter, which has a length of

less than 3.2ft (1m), detects the resonant frequency in amicrowave resonance cavity with the frequency depending onthe dielectric properties of the fluid mixture present.Robustness and resilience at such depths are essential.

Externally, the meter, its delta pressure transmitter and pres-sure transmitter are constructed using Duplex stainless steel,which has a combination of mechanical and corrosion resist-ance properties.The meter is qualified to operate at 10,000ft (3,050m) and

within a process temperature range of -42°F to -239°F (-40°Cto 150°C), a process pressure range of 0 bars to 700 bars andmaximum line pressure of 10,000psi.Themeters will be able to integrate different well streams and

accurately detect andmeasure real-time hydrocarbon flow ratesand water production at the Independence Hub development.With long tieback distances at the development, the elapsed

time from the occurrence of water breakthrough in a well todetection at the surface could be days resulting in severe conse-quences. Roxar’s real-time wet gas metering is essential to avoidsubstantial damage of pipeline infrastructure.Production allocation was central to the Independence Hub

development. With 10 field developments – many with differ-ent ownership interests and royalty rates – the wetgas meterswill be deployed to provide accurate, real-time subsea measure-ment and allocation. Accuracy is essential to ensure productionrevenue streams are split evenly among partners.By continuallymeasuring formation-water production, each

well will be operational at the limit of its water production. As aresult, fewer wells will be required in the reservoir with greaterefficiency and increased production from those already there.The Roxar subsea Sandmonitor on the Independence Hub

also plays a crucial role providing an early warning system – animmediate response when sand is present as well as being ableto check the integrity of sand screens set up to avoid sand enter-ing the production tubing.Instead of having to go into the pipe with all the accompany-

ingmaintenance, production and environmental challenges, theRoxar subsea Sandmonitor is compact and can bemounted infixed, pre-installed clamps on the outside of the pipe.The ultra-sensitive acoustics andmonitoring technology in

the sandmonitor determines sand in the well stream and the

acceptable sandproduction ratethe facilities canhandle to a highdegree of accuracy.By having accu-

rate data on theamount of sand inthe pipeline,petroleum engi-neers on theIndependenceHub canminimizeerosion damage,optimize produc-tion flow rates andprevent equip-ment clogging aswell as, if necessary, look to remedial actions, such as sandcleanouts or a sand bailer.One of the challenges in subsea wells is that conventional

sandmonitors cannot be calibrated, thus giving only a qualita-tive measurement of sand production.However, by using the new digital signal processing in sub-

sea retrievable sandmonitors and integrating this with thevelocity measurement from the already-installed wetgas metersin the Independence Hub, the Roxar subsea Sandmonitor canmore accurately determine the sand production rate.Concludes Alexis Houdusse of Roxar: “Whether its produc-

tion well-testing, improved reservoir management, allocation orhydrate and sand erosion prevention, the accurate measure-ment of wetgas flow and sand is crucial to managing one’sfields. Roxar is ensuring Independence Hub operates at the verypeak of its production limits.” ★

Paid Sponsorship

Roxar’s Subsea EquipmentMonitors Flow AssuranceWith long tiebacks and production processing split among 10 natural gas fields in water depths ranging between8,000ft and 8,950ft (2,440m and 2,730m), the success of the Independence project depends on timely and effective flowassurance monitoring.

ROXAR

Roxar subsea Wetgas meter


Roxar ASGamle Forusvei 17

PO Box 1124065 Stavanger, Norway

Tel: +47 51 81 8800Fax: +47 51 81 8801

www.roxar.com

Because of the immensity of scale for these pipelines,Weatherford designed, built and used high capacityequipment that will enable future users to more effi-

ciently test, dewater and dry.The Independence Trail export pipeline consists of a 20-

in./24-in. multi-diameter pipeline with a steel catenary riserfrom the Independence Hub in Mississippi Canyon Block920, covering more than 135 miles (217 km) to a newly con-structed platform in West Delta Block 68. The IndependenceSubsea flowlines are a vast network of 8-in. and 10-in. diame-ter flowlines in water depths of 9,000ft (2,745m).Project teams worked simultaneously throughout the early

planning phase to overcome issues, increase efficiency andminimize costs of the overall projects by coordinating sequen-tial timeframes for similar operations in each project as wellas plan for pivotal use of equipment and personnel.Hydrotesting was a challenge in the pre-commissioning

phase of the subsea and flowlines. Operating pressures of9,100psi to 10,500psi made safety the priority when testsbegan. Weatherford's “Split-System” allowed personnel topressurize the flowlines remotely and monitor data in realtime from a safe standoff distance.The dewatering phase of the projects was also a challenge,

removingmore than 13million gal of water from the exportpipeline. The typical dewatering spread with a pumping capacityof 8,000 scfmwould complete the dewatering process in an esti-mated 43 days. With limited deck space on the IndependenceHub and dynamically positioned (DP) vessel, Weatherfordmod-ified the equipment spread tomaximize pressure and volumeoutput while minimizing its overall footprint.The modified equipment spread contains the largest

spread of equipment offshore with volume output of 13,000scfm of compressed air up to 5,000psi. The additional vol-ume reduced the Trail's dewatering to 18 days. While themodifications to the DP vessel and equipment spread repre-sented an additional expense, it provided an efficient andcost-saving addition to the overall project.Once the Trail's dewatering operations were completed,

some of the air equipment on the DP vessel was replacedwith newly constructed nitrogen membrane units suited forapplications offshore to purge the pipeline.Immediately after the Trail’s project completed purging

operations, the subsea dewatering and drying operations

commenced, ultimatelysaving downtime dur-ing transition.Because of extreme

water depths over thelength of the subseaflowlines, they are dewa-tered and dried withcompressed nitrogenwith a capacity of 4,500scfm at pressures up to5,000psi.A custom-built gas

flow control skid andhigh pressure dryer (of8MMscf/d at 700psi)were used for the com-missioning of the exportpipeline. At press time,Weatherford was sched-uled to complete pre-commissioningoperations on the sub-sea flowlines project inmid-October.Weatherford views its

involvement in the Independence Hub as an endeavor toexpand awareness. As the energy industry is driven further intothe Gulf of Mexico into deeper water than ever before, technol-ogy, innovation and applications are driven to new frontiers.Weatherford's deepwater pre-commissioning and commis-sioning expertise was accelerated into the future by its role inexecuting the Independence Trail and Subsea projects. ★

Paid Sponsorship

Surpassing the Challenges of DeepwaterPipeline Pre-commissioningThe challenges of pre-commissioning and commissioning the subsea and export pipelines connecting the IndependenceHub to the market place were met, in large part because of Weatherford's aggressive planning and coordination of itswide net of global resources.

WEATHERFORD


WeatherfordBridget Mappus, Project ManagerPatrick Hollier, Project Manager

7721 Pinemont DriveHouston,TX 77040Tel: (713) 580-9700Fax: (713) 580-9797

www.weatherford.com/pss

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