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There are strong arguments for movingwater processing from deepwater plat-forms to the seafloor in many fields.There need to be, given the dauntingchallenges to doing so.

One of the prime targets is older off-

shore fields producing more water thanoil. When the water treatment facilityon the topside reaches its capacity, itputs a cap on oil output. The risingwater cut increases the force needed tolift a production stream holding everless oil, as the pressure in the reser-voir declines.

Ultimately the natural force isntenough to lift the water and oil fromdeepwater fields, which will mean the

end of production if nothing is done.When you cant get it to the surface,you are left with nothing, unless youhave got a way to pump it, said TimDaigle, senior project engineer at FluorOffshore Solutions. There are two ways

to do that: Increase the lift with pumps,or reduce the load by removing thewater on the seafloor and disposing ofit there.

After nearly two decades of devel-opment and testing, the latter optionis beginning to emerge as an alter-native. Oil companies are turning tosubsea processing for projects that arechallenged by the economics, look-ing for ways to make them profitable,

or to improve their results, said MikeRobinson, a sales and marketing man-ager at FMC Technologies, which is aleader in this area.

Statoils Tordis field offshore Norwayshows the upside and downside of

subsea water separation. The companypredicted the combination of subseawater processing and improvementsin the pumping system on its GullfaksC platform would increase ultimateproduction by 35 million BOE, push-ing the fields recovery rate from 49%to 55%. The design is based on whatStatoil learned from its earlier pilottest installed on its Troll C platformin 2001, which is still processing

Growing Offshore Water Production

Pushes Search for Subsea SolutionsStephen Rassenfoss, JPT/JPT Online Staff Writer

SUBSEA PROCESSING

This illustration shows the subsea water processing system built by FMC Technologies that is being installed atPetrobras Marlim field, offshore Brazil. The cutaway shows water injection into the reservoir.

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50,000 bbl a day and reinjecting thewater into an aquifer.

Rune Ramberg, chief engineer of sub-sea technology at Statoil, said there aremany reasons for the Norwegian com-panys push to develop subsea watertreatment systems. It has long relied onsubsea completions. Developing Arcticresources will require alternatives tooffshore platforms, which are vulner-able to ice. And most importantly: Weare not making money transportingwater, Ramberg said.

The Tordis subsea water processingunit built by FMC performed betterthan expected after the startup in 2007,Ramberg said. But the test was endedafter about three months because of

problems with the water disposal well.The company described the issue as asevere injectivity problem because thewell was located in a nonoptimal partof an aquifer.

The processing unit is still doingits job, but the water, oil and sand areflowing up to the platform as Statoillooks for an alternative to its originaldisposal well.

This year, Petrobras is readying atest of FMCs improved version of thatdesign in its Marlim field offshore

Brazil. Like Tordis, it has been in pro-duction since the early 1990s. The proj-ect is designed to add water treatmentcapacity, which is now a bottlenecklimiting production in the field where67% of the output is water, and injectthe treated water into the reservoir toimprove the fields output.

Petrobras has made a large commit-ment to a new technology that couldoffer a substantial reward. With oil inplace estimated at about 9 billion bbl,a small percentage gain in the ultimateproduction at Marlim represents a sig-nificant gain.

Those fields are not unique. Onthe decks of FPSOs (floating produc-tion, storage and offloading vessels), it

is crowded and as they produce morewater they have to shoehorn the pro-cessing unit in, said Hank Rawlins,whose company, eProcess Technologies,advises offshore operators seeking waysto process more water in a limited space.The layout on these facilities didntanticipate the need for water handlingequipment 15 years out, Rawlins said.

Platform designers try to limit thesize of platforms, which is a key costconsideration. The space allotted forwater treatment is based on long-term

projections of water production and theprice of oil, both of which are difficultto predict.

When oil was selling for USD 10 toUSD 20 a bbl, the design might havebeen based on the assumption theycan get the oil you affordably can bythe time the water hits 30% to 40%by volume, said John Byeseda, seniorprincipal engineer of subsea processingat Cameron. Now you are looking atmaking a lot more moneyUSD 80 orUSD 90 per bbland you want to beable to deal with more water.

So far only Statoil and Petrobrashave attempted subsea water process-ing. Suppliers in the field say theyhave spoken to others interested in the

technology and are waiting to see ifMarlim works.

Even a competitor with a rival subseawater processing system said he is hop-ing FMCs system performs well becauseso much is riding on Marlim. If it issuccessful, it will be great for the indus-try, and if it is a failure, it is a setback,said Gary Sams, director of research anddevelopment for oil at Cameron.

Ramberg describes Marlim as part ofa block-by-block building process, andexpects wide use of subsea water pro-

A close-up view of the FMC Technologies water treatment unit for Petrobras Marlim field shows the equipmentseparating water from oil and treating the water using in-line separation and a hydrocyclone.

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cessing in 10 to 15 years in big, deep-water fields because, we want to beproducing hydrocarbons, not water.

Prove It and They Will BuyRobinson said when he talks to clientsabout subsea processing, increasingly:I am seeing the lights going on.

Subsea processing solutions areno longer pie in the sky, or what-ifapproaches to happen someday, hesaid. These are available now, viableand necessary alternatives as they move

further offshore and into deeper waterwith more challenging production.

The use of subsea processing is notlimited to aging fields. It can allowlonger tiebacks to satellite fields toplatforms. Removing water from theproduction stream has a double ben-efit: It limits the size of the pipesneeded, and allows longer tiebacks byreducing the force needed to move theoil long distances.

Going on to the beach is the thing.The vision of future is to have sepa-

ration trains that are now on thetopside, located subsea, said PeterBatho, business development managerat Framo Engineering, the largest sup-plier of pumps for subsea processing.

When it comes to multibillion-dol-lar field developments, vision takes a

back seat to need. To date there havebeen far more projects using subseaseparation to remove natural gas fromliquids, such as Shells Perdido proj-ect. Producing the oil and gas in thethree ultradeep water fields in the USGulf of Mexico (GOM) required anelectrical submersible pump to lift theoil 8,000 feet from the seafloor to thePerdido platform.

The ability to separate the oil andwater from the natural gas allowedShell to use an energy-efficient pump

and a subsea design that maximizes thelife of the five single-phase pumps inthe lift system, and eases interventionsfor maintenance or replacement, saidG.T. Ju, engineering manager of subseahardware and umbilicals at Shell.

Production at Perdido employed anumber of industry firsts. Ju said thetechnologies chosen were limited toessential enabling technologies thatcould be successfully implementedwithin a tight schedule.

Seafloor Quality ControlReliable subsea water treatment requiresautomating a process that has alwaysrequired regular attention by workers.On a topside, if there are upsets in thewater system or the water is off spec,there are people there to adjust it, saidByeseda of Cameron. What happens ifthat happens subsea?

Subsea water processing designersare seeking alternatives for dealing withthe water if the quality does not meetspecifications, and a new generation ofmonitoring systems to detect when that

has occurred.They try to prevent such problems

with designs focused on simplicityand durability. Moving parts are keptto an absolute minimum. Fluids aredriven through processing units bythe pressure exerted by the formation.Designs are built around proven con-cepts such as:

SettlingHeavier elements andlighter elements separate.

HydrocyclonesThe productionstream is injected along the walls of a

SUBSEA PROCESSING

Camerons compact electrostatic separator (CES) removes water fromcrude oil with the help of a high-voltage electrostatic field. The chargecauses the water to coalesce into larger droplets that separate from theoil. Petrobras is testing the prototype for use in subsea water processing.

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cylindrical chamber, which separatessubstances with different masses.

Electrostatic separationElectric-ally charged plates pull droplets ofwater out of oil, which is not a goodconductor of electricity.

The Marlim system uses a 400 met-ric ton pipe separation unit capableof handling a production stream of22,000 b/d to 25,000 b/d. The heartof it is an inline pipe separator that islong enough to allow multiple process-ing steps and strong enough to with-stand the pressure at 2,950 feet deep.The system, which includes hydrocy-clones, removes the sand, natural gasand oil from the water. The first threeare recombined and travel together to

the surface.Petrobras set water quality standards

to ensure it could reinject the treatedwater without damaging the formation.The specifications set for Marlim aretighter than for Tordis. Treated watercan have no more than 100 ppm ofoil10% of what is allowed for Tordis.Sand must be reduced from about1,000 ppm to no more than 10 ppm.The specifications call for a systemthat will work for five years withoutmajor maintenance.

While Petrobras is installing FMCsunit at Marlim, it is testing a secondsubsea water treatment design fromCameron. The Cameron device, whichis built around three parallel pipes, isnow undergoing Petrobras technol-ogy qualification testing. If approved,Cameron plans to build a full-sizedevice with a capacity of 30,000 b/dexpected to go into service in 2015.

Automation: FromTopside to MudlineDoing more on the seafloor requiresa host of other developments to sup-port these subsea factories. Improvedelectrical power systems and controlsthat can provide years of reliable service

over long distances are needed, saidRamberg of Statoil.

We are headed for a major change inthe subsea industry, said Tyler Schilling,chief executive officer of SchillingRobotics, a maker of the remotely oper-ated vehicles (ROVs) used to build andmaintain subsea facilities. Since thebeginning in the 1990s, the focus hasbeen putting trees and manifolds on thebottom. They are largely static devicesafter they are installed. The choke isthe most dynamic piece and it is rarely

adjusted. With the addition of moresubsea processing, a graph showing thecomplexity level will look like a hockeystick, he said.

Shilling Robotics, 45% owned byFMC, is focusing on making it easierand quicker to repair ROVs by switch-ing out modular components. The goalis to repair even the largest componentswithin 30 minutes, because construc-tion time offshore is costly. It is work-ing with FMC on changes in subseaequipment with similar goals in mind.

The need for simple, extremelyrobust designs could lead to improvedproductivity. In a yearlong test, a devicecreated by a Norwegian startup to treatseawater for injection into deep water

wells worked 99.8% of the time. If youcould increase your injection plantsoperating efficiency, you could increaseyour output of oil, said David Pinchin,chief technology officer of Seabox,which recently changed its name from

Well Processing.The device, which looks like a big

yellow helmet, uses settling to removesolids bigger than about 10 micronsand electrolysis to produce chlorineand hydroxyl radicals to kill bacte-ria that could sour a reservoir. The

The unit known as the SWIT, which processes seawater for waterflooding oil fields, is lowered into the waterfor a yearlong test in Oslofjord, south of Oslo, Norway.

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company notes that the self-containedseawater treatment plant, known as theSWIT, could eliminate the cost of tyingin injection wells to platforms, thus giv-ing reservoir engineers greater freedomto optimize water injection systems.

Treat and ReleaseEvery subsea water treatment designso far is a closed system. Oil and gasmove on to the platform. Water andsand either go up to the platform,or down into the earth. While envi-ronmental regulations allow properlytreated water to be disposed on thesurface of the sea, no one is buildinga system that releases treated water orsand on the seafloor.

But there is a study exploring wheth-er it is legally and technically possible

to treat and release water subsea. It isfunded by the Research Partnership toSecure Energy for America (RPSEA),whose mission is to support significantresearch that the industry would not bedoing otherwise.

No one is talking about dischargebut there is a limit to how muchreinjection is possible, said Daigle ofFluor, which is leading the project.At the top of the list of questions: Isthere an environmentally acceptableway to release it in the GOM? The shortanswer is: not under the current rules.

There are no regulations for subseadischarges. There are topside dischargeregulations, but there is a big questionhow discharges at the mudline willcompare, said Savanna Hantz, a Fluorproject engineer who has studied theenvironmental issues.

They are also considering if it wouldbe possible to dispose of treated sand.That would be a significant departurefrom current practice where producedsand must go to an oil waste disposalsite on land.

The Macondo disaster showed theresilience of the GOM in the face of anenormous spill. But it has also createda much tougher regulatory climate foroffshore oil and gas operators.

To better understand the environ-mental deep water, and find a wayto measure the impact of releases ofproduced water, Daigle said the groupspoke to Gilbert Rowe, a professor atthe Texas A&M University at Galvestonwho is an expert in ocean bottom eco-systems. Rowe said the starting point

of such a study would be chemicalprofiles of produced water.

We would have to run a physicaldistribution model to see how big animpact a plus would have relative tothe background, Rowe said. Thenbased on the chemical profile, we couldprobably tell how toxic it is to whatanimals, and what we could do to makeit less toxic.

The second challenge for the projectis creating conceptual designs for asystem capable of reliably releasingwater that consistently meets environ-mental standards. For now, the onlyavailable benchmark for discharges

is the one covering treated water dis-posal from platforms. That requires,among other things, that the watercontains no more than 29 ppm ofoil over a 30-day period. In com-parison, the system used in Marlimis supposed to produce water with nomore than 100 ppm of oil. Complyingwith Petrobras standard represents amajor advance in subsea water treat-ment quality.

Even if regulators set a standardthat subsea water treatment systemscan meet: Daigle asked, How do youprove to regulators that what I amdoing complies? JPT

SUBSEA PROCESSING

A cutaway illustration of the SWIT device shows the still rooms, whichuse settling to remove solids. Biocides are created using electricity andchemicals in seawater inside the treatment cartridge, above. The car-tridge can be replaced without disturbing the unit.

For further reading:

OTC 15172 Experience in Operating Worlds First Subsea Separation andWater Injection Station at Troll Oil Field in the North Sea by Terje Horn,Norsk Hydro ASA

OTC 18914 Subsea Oil/Water Separation of Heavy Oil: Overview ofthe Main Challenges for the Marlim FieldCampos Basin by MauroEuphemio, Petrobras

SPE 123159 Subsea Separation and BoostingAn Overview of OngoingProjects by Henning Gruehagen, FMC Technologies, et al.

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