4 Oilfield Review

Subsea Development from Pore to Process

Amin AminMark RidingRandy SheplerEric SmedstadRosharon, Texas, USA

John RatulowskiShell Global Solutions (US Inc.)Houston, Texas

For help in preparation of this article, thanks to HusseinAlboudwarej, Moin Muhammad and Shawn Taylor, Edmonton, Alberta, Canada; Kunal Dutta-Roy, James Garnerand John Kerr, Rosharon, Texas; and Lorne Simmons, Sugar Land, Texas.CHDT (Cased Hole Dynamics Tester), FloWatcher, LFA (Live Fluid Analyzer for MDT tool), MDT (Modular Formation Dynamics Tester), MultiSensor, OCM (Oil-BaseContamination Monitor), OFA (Optical Fluid Analyzer), Oilphase-DBR, PhaseWatcher, PIPESIM, Sensa, Vx, WellWatcher and XLift are marks of Schlumberger.

As oil companies step out into deeper waters, operators may discover that finding

oil and gas is the easy part—the real challenge lies in moving produced fluids from

the reservoir to the processing facility.

To replace reserves from their fields on the continental shelf, exploration and productioncompanies around the world are turning todeepwater prospects. These prospects oftenrequire an operator to fabricate a floating pro-cessing facility and move it onto the concessionbefore starting production. Some reservoirs,however, are simply not large enough to justifythe expense of a dedicated processing facility.Rather than let such fields lie fallow, operatorscan take advantage of existing infrastructure bytying marginal-field production back to plat-forms that serve other fields. Operators whosefields have matured beyond peak productiontake a similar approach. With excess productioncapacity available at their platforms, these operators may seek to host production fromother fields—even from other companies.

To reach a processing facility, productionfrom remote reservoirs must flow throughjumpers, manifolds, flowlines and risers designedto withstand deep-ocean pressures, temperaturesand currents (next page). However, extendingtieback distances for several miles is not withoutproblems. Hydrocarbons dominated by heavyfractions often have high viscosity; moving suchfluids from deepwater reservoirs can be difficult.Any number of factors, acting singly or in concert, can lead to scale, hydrate, asphaltene orwax deposition in subsea flowlines.1 Thesedeposits can be severe enough to impede flow tosurface processing facilities.

The onset and magnitude of flow-assuranceproblems are largely influenced by the chemicalcompositions of produced fluids and by theirtemperatures and pressures as they travel fromone end of a production system to the other.These problems can be mitigated. Through test-ing, design and monitoring, subsea productionassurance experts are able to anticipate andmanage conditions that affect hydraulic perfor-mance of production systems.

This article discusses production challengesfaced by deepwater operators. It also describesnew technologies and services developed to over-come obstacles to the flow of oil and gas fromsubsea wellhead to platform. A Gulf of Mexicoscenario demonstrates how surveillance isclosely linked to flow-boosting and flow-assurance functions in a subsea completion andflowline tieback.

Setting the StageSubsea production systems do not remain staticover the course of their productive lives—reservoir pressure declines, fluid compositionchanges with depletion, water productionincreases, and corrosion takes its toll. Fromsandface to separator, operators must plan forchange. Facility upgrades and modifications aregenerally more difficult and expensive in subseafields; therefore, operators must anticipate asmany of these changes as possible during theoriginal facilities design, and then manage the rest.

1. Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson Aand King G: “Fighting Scale—Removal and Prevention,”Oilfield Review 11, no. 3 (Autumn 1999): 30–45.

Subsea layout. Generally, oil, gas and water flow from wellbore to subsea tree, thenceto jumper, manifold and flowline, before finally reaching a riser that pipes it to surfacefor processing. Pressurized reservoir fluid samples collected in an openhole wellbore(upper left) will be analyzed at surface to characterize the physical properties of thefluids. An electrical submersible pump in a completed well (foreground, lower left)propels reservoir fluids thousands of feet up to the wellhead and beyond. Subsea treespositioned atop each completed well contain pressure control valves and chemicalinjection ports. A flowline jumper carries produced fluids from each subsea tree to the manifold, which commingles production from the wells before sending it through aflowline to a platform. A subsea booster pump, located downstream of the manifold,pumps produced fluids along the length of the flowline and up the riser to the platform’sproduction deck. Umbilical lines from the platform run back to a subsea umbilicaltermination assembly before branching off to each wellhead and then to the manifold.The umbilicals supply electric and hydraulic power for wellhead or manifold controlfunctions, and chemicals to suppress the formation of scale and hydrates in theproduction stream. The umbilical lines also carry bidirectional communications andcontrol instructions between the platform, wellhead and downhole devices. In thisillustration, production from each well is allocated through a multiphase flowmetermounted on the manifold.

Dynamically positioned semisubmersible drilling rig

Electricalsubmersible pump

Subsea blowoutpreventer stack

Platform

Riser

Flowlines

Electrohydraulicumbilical line

Subseabooster pump

Umbilicaltermination assembly

Subsea trees

Multiphaseflowmeter

Subseamonitoringand control

module

Manifold

Electrohydraulic flying lead to manifold

Electrohydraulic flying lead to subsea tree

Flexibleflowlinejumper

Subsea tree

Openhole fluid sampling

Spring 2005 5

Water depth represents the greatest chal-lenge to subsea production. It dominates allprocess, design and economic considerations. Toexploit deepwater and ultradeepwater reservoirs,operators must drill and complete wells in waterdepths of 1,000 to 10,000 ft [305 m to 3,048 m] orgreater.2 Reservoirs that do not merit a dedicatedplatform often must be produced from as few asone to three wells. This number may also serveadequately in larger reservoirs—the challengeand expense of drilling in such deep waters willoften dictate the minimum number of wells to bedrilled in a reservoir. These water depths willalso dictate that most wells be completed subsea, with wellheads and production-control equipment placed at the seafloor.

From deepwater and ultradeepwater subseacompletions, produced fluids are sent to a pro-duction facility (above). In marginal fields,

operators may seek a nearby facility with capac-ity to handle their production. In some cases,this facility may be miles away, in the shallowerwater depths—200 to 600 ft [61 to 183 m]—ofthe continental shelf.3

Fluid produced from a deepwater reservoirexperiences significant changes in pressure andtemperature as it moves from pore space to pro-duction riser. Reservoir pressure drives fluidsfrom formation pore spaces to the low-pressuresink of a wellbore. Inside the wellbore, someform of artificial lift may be required to producethe fluids to the subsea wellhead, or tree. Inthese cases, a gas lift system or electrical submersible pump (ESP) will be employed.

While artificial lift adds energy to the wellflow, it also imparts changes in heat, pressure ordensity to the produced fluids. For example, gas lift works by injecting natural gas into the

production fluids. The injected gas reduces thefluid density, thus helping reservoir pressure liftthe fluid to the tree. By contrast, impeller vanesinside an ESP subject fluids to centrifugal forceand thereby compress the fluids. Furthermore,an ESP relies on reservoir fluids to cool its electric motor, thrust bearing and pump—theexact amount of heat exchanged depends onsuch variables as the composition of the fluid(especially the volume of gas contained withinthe fluid) and the efficiency of the mechanicalsystem. As it discharges from the ESP, the fluidwill carry this extra heat toward the subsea tree.4

Deep waters are cold; temperatures can dropto around 39°F [4°C] at the seafloor. These temperatures must be accommodated beyondthe subsea tree, where fluids enter a flowlinejumper that connects to a production manifold.The change in fluid temperature between thetree and the jumper will depend on the thermalmanagement strategy of the operator. Some oper-ators use electrically heated flowlines; some usefoam-insulated pipe; some bury the flowlinebeneath the seafloor for insulation; others use noadditional heat or insulation at all (next page, top).

Before reaching the subsea manifold, the produced fluid may pass through a multiphaseflowmeter, used to measure production fromeach well.5 The oil, water and gas phases of the reservoir fluid mix as they pass through theflowmeter’s venturi. Upon entering the manifold,the fluid is commingled with production from other wells before exiting the manifold to a flowline.

Flowlines tie fields back to a production facility—often a fixed production platform inshallower waters—but in some cases a tension

6 Oilfield Review

2. Drillers have long endeavored to reach the 10,000-ftmark. The record was finally broken in October 2003,when the Discoverer Deep Seas, owned by TransoceanInc., drilled an exploration well for ChevronTexaco on itsToledo prospect. This Gulf of Mexico well, located inAlaminos Canyon Block 951, was drilled in 10,011 feet[3,051 m] of water.

3. A prime example is the Canyon Express Project, developedto produce gas from three separate deepwater fields.Production from two wells in the Camden Hills field(developed by Marathon Oil Company), four wells in theAconcagua field (developed by TotalFinaElf, now Total),and four wells in the King’s Peak field (discovered byAmoco, now BP) is tied back to a platform some 55 miles[89 km] north of Camden Hills. Over this distance, theflowline must climb from a water depth of 7,200 ft[2,195 m] at Camden Hills to reach the production platformin 299 ft [91 m] of water at Main Pass Block 261. For areview of Canyon Express operations: Carré G, Pradié E,Christie A, Delabroy L, Greeson B, Watson G, Fett D,Piedras J, Jenkins R, Schmidt D, Kolstad E, Stimatz G and Taylor G: “High Expectations for Deepwater Wells,”Oilfield Review 14, no. 4 (Winter 2002/2003): 36–51.

4. For more on electrical submersible pump applications,problems and monitoring: Bates R, Cosad C, Fielder L,Kosmala A, Hudson S, Romero G and Shanmugam V:“Taking the Pulse of Producing Wells—ESP Surveillance,”Oilfield Review 16, no. 2 (Summer 2004): 16–25.Fleshman R and Lekic HO: “Artificial Lift for High-VolumeProduction,” Oilfield Review 11, no. 1 (Spring 1999): 49–63.

5. Multiphase flowmeters are not used to measure production in all subsea developments. Another way todetermine production from each well in a field is to allo-cate by difference. This technique requires the operatorto shut in production from a well, then measure thedecrease in production at the separator. By shutting inproduction separately from each well in the field, theoperator can determine its contribution to total output.For more on multiphase flowmeters: Atkinson I, Theuveny B, Berard M, Conort G, Groves J, Lowe T,McDiarmid A, Mehdizadeh P, Perciot P, Pinguet B, Smith G and Williamson KJ: “A New Horizon in Multiphase Flow Measurement,” Oilfield Review 16,no. 4 (Winter 2004/2005): 52–63.

6. A hydrate is a crystalline solid consisting of water withgas molecules in an ice-like cage structure. Watermolecules form a lattice structure into which many typesof gas molecules can fit. Under high pressure, gashydrates can form in temperatures well above freezing.Gas hydrates are thermodynamically suppressed byadding antifreeze materials such as salts or glycols. Gashydrates are found in nature, on the bottom of cold seasand in arctic permafrost regions. In such environments,hydrates affect both drilling and production operations.For more on hydrate control while drilling: Ebeltoft H,Yousif M and Soergaard E: “Hydrate Control DuringDeep-water Drilling: Overview and New Drilling FluidsFormulations,” paper SPE 38567, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 5–8, 1997.

7. The bubblepoint marks the pressure and temperatureconditions under which the first bubble of gas breaks out of solution in an oil. Initially, petroleum reservoir oilscontain some natural gas in solution. Often the oil is saturated with gas when discovered, meaning that the oil is holding all the gas that it can at reservoir temper-ature and pressure, and that it is at its bubblepoint.Occasionally, the oil will be undersaturated. In this case,as the pressure is lowered, the pressure at which thefirst gas begins to evolve from the oil is defined as the bubblepoint.

8. Similar flow behaviors are exhibited in deviated or horizontal wells; for more on multiphase flow in deviatedwells: Baldauff J, Runge T, Cadenhead J, Faur M, Marcus R, Mas C, North R and Oddie G: “Profiling andQuantifying Complex Multiphase Flow,” Oilfield Review 16,no. 3 (Autumn 2004): 4–13.

9. The Joule-Thompson effect produces a change in temperature as gas expands. It is often assumed that this change results in lower temperature. The change intemperature, however, depends on the inversion point ofthe gas. Each gas has its own inversion point, defined bytemperature and pressure. Below the inversion point, thegas will cool, and above that point, it will heat up.

> Fighting an uphill battle. Oil, gas and water are sent upslope through miles of flowline and hundredsor thousands of feet of elevation, only to come up against more backpressure at the production riser.To push production up the riser to the platform, a subsea booster pump may be employed.

Sea level

Flowline

Wellhead

100s offeet

1,000s offeet

Spring 2005 7

leg platform, floating production storage andoffloading vessel (FPSO), spar, semisubmersible,caisson or even a shore-based processing facilitycould be used. When tieback distance and pres-sure drop preclude natural production flow,reservoir fluids must pass through a subseabooster pump before being sent through a flow-line and up a production riser.

The flowline might not trace a constantazimuth from wellhead to platform, but maybend slightly to follow the course of a previouslysurveyed right-of-way. As it follows the undulat-ing topography of the seafloor, the flowlineclimbs gradually from the colder, deeper reachesof the field up to relatively warmer, shallowerwaters of the continental shelf, where the hostplatform stands. If not managed properly, a scenario such as this can lead to trouble.

Temperature and Pressure InteractionsChanges in temperature and pressure along thelength of the flowline promote asphaltene precipitation and wax deposition. Cold seafloortemperatures also promote formation ofhydrates.6 Furthermore, as the oil crosses itsbubblepoint pressure, light hydrocarbon frac-tions evolve as a gas phase.7 This, in turn, makesthe oil more viscous, increasing backpressure onthe system and changing flow patterns byincreasing slippage, or differences in flow rates,between produced oil, gas and water phases.

If flow velocity is not sufficient to keep theproduction stream thoroughly mixed along theentire length of flowline, then gravity segregationof oil, gas and water may take place. This condi-tion allows lighter phases to flow along the highside of the flowline, with denser phases flowingalong the bottom.8 Each phase flows at a different speed, depending on the inclination ofthe flowline.

Any vertical undulation in the flowline willallow one phase to slow with respect to the others; as the flowline climbs, the lighter gasphase can slip past the heavier liquid, while indownhill sections, the liquid can overtake the gasphase. The erratic production regime that resultsfrom such slippage between phases is known asslug flow. This terrain-induced slugging canadversely impact downstream processing facili-ties, and must be taken into consideration duringthe design phase of the project. A further conse-quence of gravity segregation is that liquids canaccumulate in low-lying sections of the flowlineand promote long-term corrosion.

Commingling different production streamsfrom separate reservoir compartments can leadto incompatible fluid mixing and subsequent

formation of organic or inorganic solids withinthe flowline. Pressure is released as fluids travelup the riser. As the gas phase of the fluidexpands, Joule-Thompson cooling may lead tothe formation of hydrates within the riser.9

Asphaltene, wax and hydrate precipitationbehaviors are determined in laboratories fromsamples collected downhole. The results indicate

ranges of operation that require mitigation (above). A phase diagram is central to under-standing the challenges faced by deepwateroperators, who must pay special attention tocomponents that fall out of reservoir fluids with changes in pressure and temperature. Particularly troublesome components includeasphaltenes, waxes and hydrates.

> Pipe-in-pipe flowline. Some operators actively heat their flowlines as part of a thermal management strategy. In this example, insulation providesadditional thermal support to electrical heating cables. Optical fiber can bemounted along the length of the flowline as part of a distributed temperaturesensor system.

Flowline Carrier pipe

Centralizer

Heating cablesOptical

fiber Passive insulation

> Oil phase diagram from a deepwater field in the Gulf of Mexico. Dependingon the design and operation of the production system, some or all of thephase boundaries seen in this diagram may be crossed as oil is producedfrom a reservoir. The oil follows a path along a line of steadily decreasingtemperature and pressure as it moves from reservoir, A, to flowline, F.Temperature and pressure drops cause asphaltene to separate from solution,B, when the oil crosses the upper edge of the asphaltene precipitationenvelope (Upper APE). Next, wax begins to form, C, as the oil crosses the waxappearance temperature (WAT) line. It enters the hydrate range, D, beforecrossing its bubblepoint line, E. Beyond this line, lighter hydrocarbons evolveas gas to form a two-phase fluid before the fluid finally reaches the flowline, F.

16,000

ReservoirA

B

CD

E

FFlowline

Bubblepoint line

Upper APE

Hydrateformationline

WAT line

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0500 150

Temperature, °F100 200 300250

Pres

sure

, psi

Asphaltenes are complex molecules occur-ring in many hydrocarbons.10 These organiccompounds become destabilized and precipitateas a result of shear in turbulent flow conditions;they can also precipitate with changes in pressure or temperature, or with changes in composition resulting from blending or commin-gling of incompatible fluids during production.Precipitated asphaltene particles can grow tocreate significant blockages in wellbore tubularsand flowlines.

Asphaltenes begin to precipitate in a pressurerange between the reservoir pressure and the bubblepoint, known as the asphaltene precipita-tion envelope (APE). The APE is bounded on itsupper edge by relatively high pressures at lowtemperatures and drops in pressure as tempera-ture increases. At a given temperature within theAPE, asphaltene precipitation typically increasesas pressure decreases, reaching a maximum at thebubblepoint pressure, at which point precipitationdecreases as pressure continues to decrease. Theoil becomes denser below the bubblepoint pressure, as solution gas evolves from the oil,allowing previously precipitated asphaltenes topartially or completely resolubilize.

Paraffin or wax produced in crude oils canadversely affect production by precipitation anddeposition within flowlines, causing blockages, orby increasing the fluid viscosity through gelling.Wax precipitates over a fairly wide range of pressures, but this phenomenon is temperature-dependent. On a phase diagram, this pressurerange lies to the left of the wax appearance tem-perature (WAT) line. The wax appearancetemperature is that temperature at which a solidwax phase forms within a hydrocarbon fluid, at agiven pressure. Below the wax appearance temperature, significant viscosity increase, deposition and gelling are possible. The WAT fallsslowly with pressure until it reaches the bubble-point of the oil. Below the bubblepoint pressure,the WAT increases with decreasing pressure.

Two other important parameters relate towax in the production stream: pour point and gelstrength. The pour point is the temperature, at agiven pressure, at which the static fluid may forma gel. If a shutdown, blockage or flow interrup-tion allows the fluid in the flowline to gel, it willnot start to flow again until a certain minimumstress is applied. This yield stress is called the“gel strength.”

Hydrates are icy crystalline structures thatcontain gas molecules trapped in the spacesbetween hydrogen-bonded water molecules.11

Hydrates exist at higher temperatures than ice,and can coexist with water or ice depending on

temperature and pressure conditions. Hydratespose a plugging hazard to chokes, pipelines, separators, flowlines and valves. The hydrate-formation line maintains a relatively steady temperature across a wide range of pressuresuntil it intersects the bubblepoint line, belowwhich the hydrate-formation temperaturedecreases with decreasing pressure.

Stacking the DeckDeep water to shallow, high pressure to low, coldtemperature to warm—these are the changes towhich oil, gas and water are subjected as theyare produced to surface. Understanding thephase behaviors that accompany these changesand predicting their timing and magnitude arekeys to developing successful design, operationand remediation strategies that maximize returnon investment. This is the role of a subsea production assurance team.

The realm of the subsea production assur-ance team extends from reservoir to riser,helping offshore operators manage challenges toflow imposed by low temperatures, high pressures and extended tieback distances. Teammembers specialize in flow prediction and modeling, fluid analysis, artificial lift, multiphaseboosting, metering and allocation, measurement,monitoring and control. These experts provide afully integrated multidisciplinary approach tooptimizing production from subsea fields.

Subsea production assurance can be dividedinto three interrelated functions: flow assurance,flow boosting and flow surveillance. Flow assur-ance involves analysis of reservoir fluid samples tocharacterize phase behaviors and anticipate asso-ciated flow problems so that production facilitiescan be designed and operated to prevent or manage these problems. Flow boosting involvesthe integrated design, placement and operation ofartificial lift systems and subsea booster pumps,which are combined to overcome pressuresbetween the reservoir and the surface productionfacility. Flow surveillance is used in a feedbackloop to measure pressure, temperature, flow ratesand a host of other variables that are instrumentalin fine-tuning the operation of pumps, chemicalinjectors and other components to optimize performance of the production system.

Subsea Flow AssuranceTo optimize return on investment, operatorsmust identify and manage any changes thatmight affect reservoir fluids as they movethrough the production system to the processingfacility. Some of these changes are counter-intuitive, and are recognized only through

analysis of reservoir fluid samples and modelingof fluid behaviors between the reservoir and theprocessing facility. Flow-assurance specialistsprovide a multidisciplinary approach to fluidsampling, analysis and modeling. The informa-tion derived from analysis and modeling of fluidbehavior serves as a basis for developing an overall production strategy.

Deposition of paraffin, hydrates, asphaltenes,scales, and other such flow-assurance issuesmust be addressed early in the design stage ofproduction systems. In fact, the flow-assurancework process begins with formation fluid sam-pling during the drilling stage of the explorationand appraisal program (above).12

Analysis of reservoir fluid samples is instru-mental in defining phase behaviors and physicalproperties of oil, gas and water produced in areservoir. More importantly, it will identify andcharacterize the phase behavior of waxes,asphaltenes and hydrates that precipitate fromthe reservoir fluids with changes in temperatureand pressure. Other important components ofthe production stream will be revealed throughsample analysis. For example, some reservoirfluids contain trace amounts of corrosives, such as carbon dioxide, hydrogen sulfide ormercury; others may contain elements such asnickel or vanadium that inhibit downstreamrefining catalysts.

Properties of produced fluids impact thedesign of a production facility—its components,metallurgy, operational plans, contingency plansand remediation programs. However, data collected on poor-quality samples provide equally

8 Oilfield Review

> Typical flow-assurance design process.Downhole pressures and in-situ fluid propertiesare measured, and fluid samples are retrieved fordetailed laboratory analysis. The resultinglaboratory data are downloaded to specializedengineering software to model variations in theproduction system. These models are used toformulate flow-assurance management strategies.

Preventionstrategy

Modeling

Downholemeasurementand sampling

Remediationstrategy

Systemselection

Laboratoryanalysis

Spring 2005 9

poor results, leading to over- or underdesign ofthe production facility or mistaken assumptionsabout operating procedures.

Reservoir fluid properties are best deter-mined with testing of representative samples.Samples can be taken using wireline-conveyedformation testers, such as the openhole MDTModular Formation Dynamics Tester or theCHDT Cased Hole Dynamics Tester, during drill-stem testing (DST) or from a surface separator.Samples taken using wireline formation testersrepresent a value from a point in the wellbore,while samples taken during a well test representan average over a producing interval. Fluid properties, however, can vary across a field oracross a reservoir.13

Whenever possible, samples from multipledepths or multiple wells should be considered toidentify and quantify variations. Understandingthe magnitude and nature of compositional variation is important for system design. Thesesamples should be obtained early in the life of thefield, during the drilling stage, before productiondepletes the reservoir below saturation pressure.

Flow-assurance models highlight the need forrepresentative samples. Ideal fluid samples are

obtained under reservoir conditions, above bubblepoint, with no asphaltene precipitation,and with little or no contamination. At the labo-ratory, such a sample would be virtually identicalto the fluid in the reservoir. Unfortunately, someof the very same solids that come out of solutionduring production also come out of solution during the sampling process.14 As samples arebrought to surface, changes in temperature andpressure may lead to phase changes that alterthe fluid sample. Samples can also be altered bycontamination, frequently caused by drillingfluid filtrate.

Advances in Sampling and AnalysisFortunately, there are strategies for obtaininggood samples that reduce the potential for contamination and phase changes. For example,the MDT tool can take downhole fluid samples atreservoir temperature and pressure. An OFAOptical Fluid Analyzer system within the MDTtool provides a qualitative measure of contamina-tion by mud filtrate entering from the invadedzone of the formation surrounding a wellbore.For oil-base muds, sample contamination can bequantitatively monitored using the OCM Oil-Base

Contamination Monitor.15 A methane detector inthe LFA Live Fluid Analyzer module of the MDTtool provides a measure of gas content in the oilphase and allows calculation of the gas/oil ratio(GOR). This module can verify that the fluidpressure has not dropped below bubblepoint during sampling.16 Dropping below the bubble-point would turn a single-phase fluid diphasicand render the sample unrepresentative.

In the past, downhole samples would invariably drop below bubblepoint as tempera-ture and pressure decreased while the sampletool was brought to surface. Sample chamberscarried by early downhole formation testers weredesigned to withstand pressures downhole, butwere not designed to maintain such pressure onthe fluid sample itself. Oilphase, acquired bySchlumberger in 1993, developed a single-phasemultisample chamber to overcome this problem.

After the downhole MDT pumpout modulefills a single-phase multisample chamber atreservoir pressure, a nitrogen charge providesoverpressure to compensate for any temperature-induced pressure drop as the sample is retrievedto surface. This prevents flashing of the sample to keep the fluid in single phase (left).In many cases, a single-phase multisample

10. Asphaltenes are defined as the n-pentane or n-heptaneinsoluble components of petroleum crudes that are solu-ble in toluene. For further information: Jamaluddin AKM,Joshi N, Joseph D, D’Cruz D, Ross B, Creek J, Kabir CSand McFadden JD: “Laboratory Techniques to Define theAsphaltene Precipitation Envelope,” Petroleum Societyof the Canadian Institute of Mining, Metallurgy &Petroleum, Paper 2000-68, presented at the PetroleumSociety’s Canadian International Petroleum Conference2000, Calgary, June 4–8, 2000.

11. For more on gas hydrates: Collett TS, Lewis R and Uchida T: “Growing Interest in Gas Hydrates,” OilfieldReview 12, no. 2 (Summer 2000): 43–57.

12. Ratulowski J, Amin A, Hammami A, Muhammad M andRiding M: “Flow Assurance and Subsea Productivity:Closing the Loop with Connectivity and Measurements,”paper SPE 90244, presented at the SPE Annual Technical Conference and Exhibition, Houston, September 26–29, 2004.

13. Ratulowski J, Fuex A, Westrich JT and Seiler JJ: “Theoretical and Experimental Investigation of Isothermal Compositional Grading,” paper SPE 84777,SPE Reservoir Evaluation and Engineering 6, no. 3 (June 2003): 168–175. For fluid property variation within a vertical wellbore: Betancourt S, Fujisawa G, Mullins OC, Carnegie A, Dong C, Kurkjian A, Eriksen KO, Haggag M, Jaramillo ARand Terabayashi H: “Analyzing Hydrocarbons in theBorehole,” Oilfield Review 15, no. 3 (Autumn 2003): 54–61.

14. Ratulowski et al, reference 12.15. For more on the measurement of mud contamination in

downhole fluid samples: Andrews JR, Beck G, Chen A,Cribbs M, Fadnes FH, Irvine-Fortescue J, Williams S,Hashem M, Jamaluddin A, Kurkjian A, Sass B, MullinsOC, Rylander E and Van Dusen A: “Quantifying Contamination Using Color of Crude and Condensate,”Oilfield Review 13, no. 3 (Autumn 2001): 24–43.

16. For more on pressure and temperature effects on hydrocarbon samples, and a discussion on downholefluid-property evaluation tools: Betancourt et al, reference 13.

> Pressure-compensated fluid sampling. This phase diagram illustrates the changes in temperatureand pressure to which fluid samples will be subjected as they are drawn from a reservoir to thesurface. Point A shows a single-phase sample taken at reservoir temperature and pressure. As itreaches the surface in a conventional sample container, the reduction in temperature andsubsequent drop in pressure cause asphaltenes to come out of solution and lighter components toflash into a gaseous phase, at Point B. An identical sample drawn into a single-phase bottomholesampler will be pressurized to Point C before being brought to surface. Under pressure, this sampledoes not cross the asphaltene precipitation envelope before reaching ambient temperature at Point D.

Pres

sure

Liquid

fracti

on, %

Temperature

Asphaltene precipitation envelope

Multiphasesample

Multiphase zone

Single-phase bottomhole samplerConventional bottomhole sampler

Fluid at initial reservoirtemperature and pressure

Critical point

Nitrogen-charged fluid

Single-phasesample

Liquid

Asphaltene

Gas

A

B

D

C

100%

Liquid, %

75%

50%

25%

0%

chamber will be run in conjunction with a multi-sample module to allow pressurized reservoirfluid samples to be transported offsite to a pressure-volume-temperature (PVT) fluid analysis laboratory.

These field-proven sampling systems are alsoused in cased-hole applications. The CHDT tool isfully combinable with MDT modules such as thepumpout module, multisample module and theOFA module. Other formation fluid samples maybe obtained with a DST-conveyed sample carrierthat complements existing wireline-conveyedsamplers and surface sampling services. Thesecarriers may be employed to collect samples inwells containing hydrogen sulfide and in high-temperature, high-pressure or heavy-oil wells.

At the surface, fluid samples can be obtainedfrom a separator. In producing wells, recombinedfluid samples from a separator may be the onlyoption available for determining reservoir phasebehavior. Oilphase-DBR fluid sampling and analysis service provides single-phase samplebottles for transporting pressurized fluid samplesand can also provide bottles for transporting pressurized gas samples.

Analysts take an incremental approach tosample testing, allowing initial results to dictatethe course of subsequent tests. First, the compo-sition and basic fluid properties of the sample areanalyzed. Next, samples are subjected to wax,asphaltene and hydrate screening; samples thatscreen positive are subjected to further detailedanalysis. Live fluid samples—those in which solu-tion gas is preserved in oil samples, or in whichheavy ends are maintained in the vapor phase ofgas samples—are tested under special laboratoryconditions. PVT tests, gas chromatography and mass spectrometry help to analyze phasebehavior, fluid composition and flow properties.

The Oilphase-DBR service uses several special technologies to analyze reservoir fluidsand quantify conditions that promote depositionof paraffins, hydrates and asphaltenes in the production system. Hydrate-formation conditionsare measured in both the single-phase and two-phase regions, while precipitation boundaries,growth kinetics, morphology and solubility arecharacterized both visually and quantitatively.

A laser-based solids detection system evaluates changes in pressure, temperature orcomposition to define the point at which solidsprecipitate in a sample. The solids detection system projects near-infrared laser light throughreservoir fluid in a special PVT cell. The intensityof transmitted laser light decreases at the onsetof asphaltene precipitation. A high-pressuremicroscope allows analysts to directly observe the

onset and growth of organic solid precipitates, atpressures to 20,000 psi [138 MPa] and at temper-atures to 392°F [200°C]. This microscope candefine the quantity and morphology of organicsolids as they grow in order to evaluate and optimize the effectiveness of various chemicalsfor solids inhibition or remediation. A controlled-stress high-pressure rheometer operable to6,000 psi [41.3 MPa] and 302°F [150°C] is used todefine the rheology of waxy crudes.

To better understand how paraffin, scale andasphaltene are deposited, analysts use a rotatingshear deposition cell to model turbulent flow andshear under pressure and temperature condi-tions found inside a flowline (right). Becausesurface irregularities such as rust, pitting orporosity influence deposition rates, specialsleeves can be inserted in the cell to simulatethe inner surface of the flowline. After runningthe shear deposition cell, analysts remove thesleeve inserts to measure the thickness and composition of the deposits.

These advanced technologies aid the produc-tion assurance specialists in defining behaviorsof reservoir fluids to reduce uncertainty andpotential overdesign of the production system.

Results from fluid sample tests are fed intomodeling software to address flow-assurancechallenges. PIPESIM production system analysismodeling can be employed to predict liquidholdup and pressure loss, along with simulatingflow regimes and multiphase flow between wells,pipelines and process equipment. Using thismodeling software, subsea production assurancespecialists determine optimal pipeline andequipment size, carry out heat transfer calcula-tions and generate flow models to predictconditions under which hydrates form. Just asimportant, it also models the effects of hydrateinhibitors or remediation systems. These modelsare integrated into the front-end engineeringdesign process to develop optimal productionsystems and operability strategies that are neither over- nor underdesigned.

Flow-assurance management strategies,developed on the basis of fluid sample analysis,generally take the form of thermal management,pressure management, chemical treatments andmechanical remediation.17 Thermal managementtypically consists of circulating hot fluids, electri-cal heating and flowline insulation. Pressuremanagement can be carried out by downholepumps and seafloor booster pumps. Chemicaltreatments are injected into the production system to inhibit corrosion or deposition of wax,scale and hydrates. Mechanical remediation usually involves pigging of flowlines.18

Managing Pressure through Flow BoostingBeyond its critical role in controlling phasechanges of reservoir fluids, pressure is the driving force that moves those fluids from porespaces to processing facilities. To produce subseawells, pressure from the reservoir must workagainst high static backpressures inherent inextended tiebacks and long risers. Backpressurecomprises both frictional resistance to flow andpressure head caused by the elevation changebetween the subsea tree and the surface facility.Backpressure invariably wins out as reservoirpressure declines over time.

Conventional dry-tree wells are routinelydrawn down to wellhead pressures of 100 to200 psi [689 to 1,379 kPa] before being abandoned.19 By contrast, subsea wells with longtiebacks may have to be abandoned much earlierand at higher pressures, sometimes as high as2,000 psi [13.8 MPa] at the subsea, or wet, tree.20

Such high abandonment pressures are dictatedby backpressure at the wet tree, which increasesin proportion to the length of flowline and riser,in addition to the number of constrictions caused by fittings or deposits within the production system.

Increased backpressure requires a higherbottomhole flowing pressure to maintain production. Typically, without some form of artifi-cial lift, this increased backpressure results in adecline in reservoir production. Therefore, tocontinue producing reservoir fluids through the

10 Oilfield Review

> Cross section of a shear deposition cell. Tosimulate conditions within a flowline, shear forcesare generated in the reservoir fluid sample as itspins between a rotating inner cylinder and astationary outer cylinder. Afterward, the thicknessand composition of any deposited materials aremeasured.

Rotatingcylinder

Electricalheatingcartridge

Oil

CoolantStationarycylinder

Deposit

Spring 2005 11

flowline to the processing facility, this back-pressure must be reduced.

Flow boosting helps manage pressures in theproduction system using two complementaryapproaches. First, downhole artificial lift isemployed where needed, especially when lowreservoir drive pressure cannot sustain accept-able production rates, or low gas/oil ratios (GOR)are combined with highly viscous oil. Second,seafloor booster pumps are used to propel produced fluids along the length of the flowlineand up the production riser.

Artificial lift systems are installed to boostenergy downhole or to decrease effective fluiddensity in a wellbore, thereby reducing hydro-static load on the producing formation. Artificiallift improves recovery by lowering the bottom-hole pressure at which a well must beabandoned. Gas lift and electrical submersiblepumps account for the two most common formsof artificial lift in subsea wells.21

Operators routinely use gas lift to maximizedrawdown and increase total production of their

offshore oil wells. A gas lift system draws high-pressure gas from a surface production facilityand injects the gas into a well’s casing annulus.Gas is then injected into the tubing fluidsthrough a gas lift valve housed in a side-pocketmandrel made up in the tubing string. Theinjected gas lowers the density of produced fluidsin the production tubing and lifts the fluids tothe wellhead. By lowering the weight of thehydrostatic column in the tubing, the gasdecreases backpressure on the producing formation, allowing more flow from the reservoirinto the well.

Total recovery will increase with the depth atwhich the gas is injected. This depth is limited bythe operating pressure rating of standard gas liftvalves. Surface compression is required to pushthe lift gas to deeper injection points, but thiscompression pressure must not exceed the maxi-mum operating pressure rating of the gas liftvalve. Standard gas lift valves are typically ratedto inject gas at operating pressures of 2,500 psi[17.2 MPa] at valve depth. Beyond this pressure,

the bellows within the valve gradually fatigue,eventually causing it to fail.

As operators venture into deeper waters,higher operating pressures and greater lift-valvedepths are required to produce their subseawells. These requirements are being addressedby new developments in gas lift technology. UsingSchlumberger XLift high-pressure gas lift systemtechnology, gas lift valves with bellows rated at5,000 psi [34.5 MPa] can handle gas at greatercompression pressures than those allowed bystandard valves. This higher pressure ratingenables the valves to be installed at deeper set-points, allowing increased drawdown, extendedproductive well life and added reserves.

Where heavy crudes, limited access to injection gas, high water cut or low bottomholepressures preclude the gas lift option, an electrical submersible pump (ESP) can be used.ESPs generate centrifugal force to pressurizewellbore fluids and are capable of lifting fluidsfrom depths of 20,000 ft [6,100 m] or more. Withpower ratings up to 1,500 hp [1,119 kW], they can move up to 100,000 B/D [15,890 m3/d]of fluids, depending on casing size and drawdown requirements.22

On the seafloor, multiphase pumps providefurther flow-boosting capabilities that helpextend the life of a field. When backpressurefrom a long tieback and riser prevents a wellfrom flowing naturally, a booster pump installednear the wellhead can help draw down wellheadpressure (left). The effect on the well is a reduc-tion in backpressure, which allows increased

17. Ratulowski et al, reference 12. 18. Pigging allows operators to clean or inspect pipelines by

pumping a spherical or cylindrical device, known as apig, through the pipe. Fluid flowing through the pipe propels the pig along the length of the pipeline. Scraperpigs are fitted with cups, brushes, disks or blades toclean out rust, wax, scale or debris inside the pipe. Other pigs, often called smart pigs, can carry cameras,magnetic or ultrasonic sensors and telemetry devices to detect corrosion, cracks and gouges, or to measuretemperature, pressure or wax deposition.

19. Offshore completions can be loosely classified as “dry-tree” or “wet-tree,” depending on where the wellhead, or “tree” is located. Generally, dry-tree completions are used in shallow to moderately deepwaters, where a wellhead is placed on a platform, above sea level. In moderately deep waters, dry treescan be found on compliant towers, spars and tension legplatforms. Conversely, a wet tree is a subsea completionfor deep and ultradeep water depths. The wellhead is situated on the seafloor, and production from the well ispiped from the subsea tree to the platform.

20. Devegowda D and Scott SL: “An Assessment of SubseaProduction Systems,” paper SPE 84045, presented at SPE Annual Technical Conference and Exhibition, Denver,October 5–8, 2003.

21. Shepler R, White T, Amin A and Shippen S: “Flow Boost-ing Key to Subsea Well Productivity,” presented at the Deepwater Offshore Technology Conference, New Orleans, November 30–December 2, 2004.

22. Shepler et al, reference 21.

> Framo subsea multiphase booster pump. Thispump uses a modular design consisting of anintegrated pumping and drive unit. The drive unitcan be powered by electric motor or waterturbine. All components subject to wear and tearare located in a single, easily retrievable cartridgethat can be serviced from an intervention vessel.

Electricmotor

Inlet

Gas

Liquid Mixingsection

Outlet

Coolingpipes

Helicoaxialpump

flow from the well. Rather than abandon subseawells at higher pressures, sometimes as high as 2,000 psi, operators can use booster pumps to extend production by reducing wellhead pressures, in some cases to as little as 50 psi [345 kPa].

By providing additional pressure for flowboosting, seafloor booster pumps also fill animportant role in flow assurance. Without suffi-cient pressure in the flowline, a productionstream will eventually separate into multiplephases. Gas will evolve out of solution, and gravity will stratify the fluids. Gas, flowing at thehigh side of the pipe, will overtake oil and wateras they flow more slowly along the bottom. Ensuing transient flow conditions can cause process upsets in surface production equipment.

Multiphase booster pumps pressurize produc-tion streams, compressing the gas, andsometimes even driving it back into solution(below). A production stream is expelled from amultiphase booster pump as a homogeneous liq-uid, at elevated temperature and pressure and ina steady-state flow regime. As it exits the boosterpump, the heat imparted by the pump is carriedoff by the production stream, thereby helping toreduce hydrate and wax formation problems. Atthe same time, the pressure increase helps boostflow velocities. The additional heat and pressuresupplied by the pump can have a positive influ-ence on flow assurance.

The multiphase booster pump plays a criticalrole in subsea production when used in conjunc-tion with downhole gas lift. The behavior ofinjected gas in the production stream must befactored into the flowline operability plan whengas lift is used. Whether it is injected or liberated, gas will flow along the high side of aflowline, hampering movement of fluids throughthe flowline.23 However, subsea multiphasebooster pumps are capable of handling a range offluid phases from 100% water to 100% gas, andcan manage transient flows generated in theflowline due to gas separation.

By compressing the gas back into solution,the ensuing reduction in gas volume allows moreliquid to be carried within the same volume ofpipe. Alternatively, the booster pump can be usedto flow the same volume of fluid through asmaller diameter flowline. The subsequentincrease in flow velocity helps reduce heat loss,thus lowering the risk of hydrate formation andwax buildup.

When used in conjunction with an ESP, seabedmultiphase boosting takes up some of the burden carried by the downhole pump. In conventional dry-tree applications, an ESP mustbe powerful enough to lift fluids to the separator.In the case of ultradeep waters, however, the sizeof the ESP must be sufficient to pump fluids to thewet tree, through the tieback, and up the riser tothe topside separator. With extended tiebacks in

ultradeep waters, the capacity of the ESP and thenumber of pump stages must increase, sometimesdoubling the power from that needed to pumpfluid to surface. However, run life drops substan-tially as motor size increases.

With a multiphase seabed booster pump, thesize of an ESP can be decreased, thus extendingESP run life and reducing the number ofrequired interventions.

Flow SurveillanceTo anticipate and manage conditions in subseaproduction systems, operators require the capability to monitor, measure and analyze keyattributes, and they must have some means tocontrol subsea processes. Production systemsrely on instrumentation and control to predictand mitigate flow-assurance and flow-boostingproblems. By taking measurements to character-ize the system in real time, operators may beable to minimize chemical consumption or reduce energy input into the system by decreasing flowline heating requirements or pigging frequency.

Important downhole parameters, such astemperature, pressure, flow rate, fluid densityand water holdup data, can be tracked on a real-time basis by the FloWatcher integratedpermanent production monitor. Subsea flow-meters, such as PhaseWatcher fixed multiphasewell production monitoring equipment, measure

12 Oilfield Review

> Helicoaxial booster pump. This Framo pump has four stages, with each stage comprising an impeller and a diffuser. Thedesign combines the capabilities of a centrifugal impeller with an axial gas compressor, and can operate across a range ofphases, from pure liquid to pure gas.

Impeller Diffuser

1 2 3 4

Spring 2005 13

multiphase flow rate and holdup, but require nophase separation and are insensitive to slugs,foam and emulsions.24 These systems can becombined with other sensors, such as sanddetectors, pressure gauges and fiber-optic distributed temperature sensor (DTS) systems toprovide a constant stream of data for diagnosis of wellbore and flowline performance. This information allows the operator to make proac-tive operational decisions—changing a valvesetting, boosting pump output or starting chemical injection—based on factual analysis of validated data.

Data validation is an important aspect of sub-sea production assurance. Validated data arerequired to ensure that decisions are based onsound, proven information. Data can be validatedby comparing measurements from one sensor tothose from another corroborating sensor. Forexample, DTS data can be compared to tree temperature sensors located in close proximityto the DTS. In many cases, however, much of thevalidation information simply is not availablebecause of low data transmission rates providedby production control systems.

Analysis generally requires comparison witholder data and modeling against expected perfor-mance. A surveillance workflow collects andintegrates data into a closed loop system to optimize production (above).25

The surveillance system utilizes data acquiredby real-time sensors, along with fluid and pres-sure data obtained during the drilling phase, tomonitor the state of the overall system. The sameengineering models used to design the system canthen be used to evaluate its performance.

Though wellbore and seabed monitoring andcontrol systems are installed to improve produc-tivity of subsea wells, the capability of thesesystems can be hampered by transmission band-width. Data transmission systems in the subsearealm have not always kept pace with sensorthroughput. As subsea and downhole devicesbecome more intelligent, providing more dataand greater levels of diagnostics and control,communications may prove to be the weakestlink in the system.

Great volumes of high-speed data must passto the surface to provide an operator with real-time control of the production system.26 However,subsea control commands and production moni-toring data are often bundled into a commontransmission system. All data and commandspass through one of these systems, known as aproduction control system (PCS), designedlargely for subsea valve control. Although mostproduction facilities have topside systems tosecurely transmit large volumes of high-bandwidth data around the world, seafloorinfrastructure can create information bottle-necks that delay timely analysis and action tooptimize production.

One way around the bottleneck is to separatesafety-critical control functions from subseamonitoring processes. Separation can beachieved through an industry-standard surveil-lance system with a high-bandwidth, networkedcommunications link to the surface. This commu-nications link can be implemented by installing asingle low-cost fiber in the same umbilical usedfor tree control. A subsea monitoring and control(SMC) module has been developed as a centralconnectivity hub for downhole and subsea instrumentation that works in conjunction withtraditional PCS wellhead safety-valve control systems. By taking this approach, the operatorcan employ a surveillance and monitoring systemwithout interfering with the subsea safety func-tions of the PCS—in fact, its only impact is toreduce the burden of data transmission on thePCS. At the same time, the SMC permits dataintegration topside through standard links, thusproviding the ability to utilize conventional data-handling and analysis systems similar to thoseused in processing facilities onshore.

23. Shepler et al, reference 21. 24. Atkinson et al, reference 5.25. Ratulowski et al, reference 12.26. Amin A, Smedstad E and Riding M: “Role of Surveillance

in Improving Subsea Productivity,” paper SPE 90209, presented at the SPE Annual Technical Conference andExhibition, Houston, September 26–29, 2004.

> Integrating surveillance into flow assurance. Data such as temperatures, pressures and flow rates are collected from sensors at various points throughoutthe production system. Models used during the design stage are conditioned to process the sensor data. These models can then be used to determine thecurrent state of the system and to optimize the system through a series of “what-if” runs.

Multiphaseflowmeters

Sensorsystems

Acquisitionsystems

Fluid propertymodels

Processmodels

Operations

Dynamic dataacquisition system

Flowlinesimulator Monitoring

Distributedtemperature sensor

Thermodynamicmodels

Changing parameters

Wellboresimulator Optimization

Facilitiessimulator

Pressure andtemperature gauges

Multiphaseflow models

Electricalsubmersible

pump monitors

Static datastorage system

Depositionmodels

Model conditioning

The subsea monitoring and control moduleallows subsea data acquisition and controldevices to communicate directly between thesubsea data hub and the topside data hub, usinga high-speed data link to avoid passing throughslower intermediary devices. The subsea datahub connects sensors to the surveillance system(above). The topside data hub is connected todata recording, analysis and alarm systems.

The SMC is capable of communicating overelectrical or optical cable at rates up to100 megabits/second—essentially creating aseabed local area network. The surveillancepackage mounts on a subsea tree or manifold,and can be expanded or upgraded without affect-ing production. Compliance with the industry’sIntelligent Well Interface Standardisation (IWIS) procedure enables the open, plug-and-play SMCsystem to interact seamlessly at optimal trans-mission rates with any networked combination ofacquisition sensors and control modules fromSchlumberger or third parties.27

Surveillance ScenarioSubsea surveillance scenarios have been devisedto test the capacity of the SMC to monitor anddetect flow-boosting and flow-assurance issues.One laboratory simulation study, based on adeepwater field in the Gulf of Mexico, relied oninput from several real and simulated instru-ments physically connected to an SMC. Thisinput was provided by pressure and temperaturegauges; a FloWatcher integrated production mon-itor for flow rate, fluid density and holdupmeasurements; a Sensa fiber-optic DTS monitor-ing system; a flow-control valve and simulateddevices representing two ESPs, a subsea multi-phase pump and a subsea multiphase flowmeter(next page, top). This example shows how one abnormal event can cascade into another, with potential for adverse impact on the production system.

In this simulation, electrical windings in oneof the ESP motors began to overheat, setting offan alarm at the controller workstation whenpump temperature exceeded its specified setpoint.28 ESP performance curves indicated thatthe pump was operating outside of specifications,so test personnel took corrective action to returnthe pump to original operating conditions beforedamage occurred (next page, bottom).

14 Oilfield Review

27. The Intelligent Well Interface Standardisation (IWIS)Panel formed in 1995 as a joint industry project betweenoil and gas operators and downhole equipment manufac-turers and service companies. Their stated intent is “To assist the integration of downhole power & commu-nication architectures, subsea control systems andtopsides by providing recommended specifications (and standards where appropriate) for the interfacesbetween them, and other associated hardware require-ments.” For more on the IWIS joint industry project:http://www.iwis-panel.com/index.asp (accessed February 4, 2005).

28. Shepler et al, reference 21.

> Subsea data hub component of the subsea monitoring and control (SMC) module. A remotely operated vehicle (ROV)inserts a subsea data hub into a receptacle during qualification testing (upper right). The receptacle, mounted to asubsea tree (lower left), provides wet-connect capability for retrieval or upgrade of the data hub at the seabed. Thesubsea data hub (upper left) handles simultaneous input from numerous sensors along the production system, includingthird-party sensors operating on industry-standard protocols. It accepts input from a wide range of sensor types, such as downhole temperature and pressure gauges, single- and multiphase flowmeters, downhole flow-control valves,distributed temperature sensor systems, electrical submersible pump monitors, subsea multiphase pump monitors andsand detectors.

Spring 2005 15

> Seabed installation with multiphase pump, manifold, subsea trees and flowline leading to a distantFPSO. This typical installation served as a model for a laboratory scenario in which increased waterproduction from one well was detected at a downhole pump and flowline.

Subsea trees Multiphase pump

Flowlines Umbilical

FPSO

Riser

Manifold andmultiphase flowmeter

> ESP performance display. Pump intake pressure, temperature sensors and water cut indicate that pump performance is outside of normal operatingparameters (red boxes).

PhaseWatcher Vx

Flow rate

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sure

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er, h

p

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ESPSTATUS: RUNNING

Density

Flow rate

BHFPDownhole

temp

Reservoirpressure

Motor windingtemperature

Vibration

Current leakage

Water cut

Calculated freegas at intake

DischargepressureDischargetemperature

2,775.45 psia

7.24 bbl/psi/day

318.68 scf/STB

38.33%

0.55 g/cm3

32,652.1 B/D

2,456.84 psia

163.65 °F

292.11 °F

4.39 g

0.42 mA

6,112.4 psia

9.27%

281.46 °F

167.66 °F

2,148.45 psia

288.49 °F

Intakepressure

Wellheadpressure

Intaketemperature

Pump protectortemperature

31,726.87 B/D

384.51 psia

Wellhead

FloWatcher TVD 7,850 ft

TVD 7,850 ftWellWatcher

MultiSensor Motor vibration

DTS

76.26%

Meanwhile, other sensors incorporated in thesystem, particularly a FloWatcher productionmonitor and a simulated seabed multiphaseflowmeter, relayed readings consistent withincreased water cut. An advisory system thatsimultaneously analyzed sensor readings fromthe wellbore and seabed suggested adjusting thepump’s variable speed drive to reduce the ESPmotor speed, and choking back the downholecontrol valve to decrease water production in the well.

In this instance, the rise in pump tempera-ture was attributed to increased waterproduction, which subsequently raised the fluiddensity and caused the pump to work harder tolift heavier fluids. By choking back water produc-tion at the downhole control valve, oil cutincreased, thus lowering fluid density and easingthe load on the pump. These actions led to can-cellation of the alarm and returned pumpoperations to a safe performance level.

Beyond its adverse effect on flow boosting,the increased water cut also raised concernsfrom a flow-assurance standpoint. The Sensa

fiber-optic monitoring system acquired DTS tem-perature traces along the flowline. These traceswere transmitted by the SMC system.29 Alarmswere generated as temperatures fell along alength of flowline near the riser (above). The sys-tem event analyzer indicated that the flowlinetemperature-pressure profile had crossed thehydrate-formation curve (next page). This unex-pected decrease in DTS temperature readingscorresponded to an increase in water cut and adecrease in pipeline boarding pressure at theproduction facility.

Increased water cut would eventually encour-age the formation of hydrates in the presence ofany gas in the line. Based on analysis of SMC output, test personnel took remedial action, simulating an increase in methanol injection intothe pipeline while production was choked back.This remediation caused temperatures to moveoutside the hydrate envelope, forcing disassocia-tion of any hydrates that may have formed in thesystem. The well in the simulator was thenbrought back on production, and methanol injec-tion was adjusted to avoid further problems.

This simulation showed how the SMC surveil-lance system, wellbore and subsea sensors,real-time data, static data and predictive modelscan be integrated to monitor and interpret system performance. Abnormal events were recognized, diagnosed and resolved before theybecame unmanageable. This response optimizedboth the flow-assurance operating strategy and the efficiency and reliability of the flow-boosting systems.

One Step Forward, One Step BackInnovative offshore well-completion technologywill drive advances in subsea production assurance. New power-delivery systems, separators, dehydrators, compressors, single-and multiphase pumps and flowmeters are beingdeveloped for seafloor applications. These technologies are paving the way for processingproduced fluids at the seafloor. Not all subseaprocessing systems will have the same capabili-ties, but the ability to separate water from aproduction stream results in lower lifting costsand improves flow assurance by reducinghydrate and scale formation.

16 Oilfield Review

> An alarming drop in temperature. The unheated flowline in this scenario was buried to insulate it against coldocean temperatures. Fiber-optic DTS readings along the flowline normally show a steadily declining temperaturetrend as the warm production stream decreases from 45°C [113°F] at the manifold, to 38°C [99°F] at the riser.However, a sharp temperature drop, extending some 1,800 m [5,905 ft] from the riser base, was cause for concern. It was attributed to hydrate formation.

Tem

pera

ture

, °C

308,000 7,000 6,000 5,000 4,000

Depth, m

3,000 2,000 1,000 0

35

40

45

50

Hydrate zoneManifold

FPSO

Flowline

Sea level

995 m

29. Amin et al, reference 26.

Spring 2005 17

As subsea completion technology matures,developments such as coiled tubing have spurredoffshore operators and service companies toapply their deepwater experience to marginalfields in shallower waters on the continentalshelf. Continuous lengths of coiled tubing can bemanufactured to withstand pressures required ofsubsea production lines, and require fewer weldsper mile than traditional pipelines.

Some single-well reservoirs on the US Continental Shelf have been tied back to exist-ing platforms, often using coiled tubing forflowlines and umbilicals. For example, an 18-mile [30-km] coiled tubing tieback in the

Gulf of Mexico was commissioned from 1,250-ft[381-m] waters of Garden Banks Block 208 to anexisting platform at Vermillion Block 398 in450 ft [137 m] of water. At Garden BanksBlock 73, 2.7 miles [4.3 km] of coiled tubingwere used to tie a single subsea well to a plat-form in water depths ranging from 500 to 700 ft[152 to 213 m]. A well in 375 ft [114 m] of waterat West Cameron Block 638 was tied by coiledtubing to another operator’s platform in 394 ft[120 m] of water at West Cameron 648.

However, flowline systems in shallow watersare not completely free of subsea productionassurance problems. In some cases, the problems

can be addressed by injecting methanol, corro-sion inhibitors and paraffin suppressants at thesubsea tree. In any event, the reservoir must besampled, the samples must be analyzed, and theanalysis must be incorporated into the designplan to anticipate and prevent production assurance problems.

In deep and shallow waters, reservoir fluid analysis and front-end engineering design,coupled with advances in artificial lift, flowboosting and fast-acting subsea monitoring systems are turning small, sometimes isolated,reservoirs into economically viable assets. —MV

> Event analyzer output. DTS, wellbore pressure and flowline pressure trends are integrated and displayed by thesubsea monitoring and control connectivity platform. Taken together, these trends indicate that the fluid system haddropped into the hydrate formation zone.

Schlumberger Event Analyzer has detected a possibleproduction assurance event.

Pipeline 1A DTS has detected atemperature DROP at the riserin a HYDRATE zone.

Decrease of 3.41 °Cin 2 hours.

Related events

Well 1A Production Pressure FPSO Pipeline 1 Boarding PressureDecrease in well 1A production pressure.Pressure decrease of 996.4 psia in 2 hours.

FPSO Pipeline Water Production

FPSO control system indicates a waterproduction rate alarm for manifold 1.

Decrease in FPSO pipeline 1 boarding pressure.Pressure decrease of 121.23 psia in 2 hours.

Exit

4,000

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EVENT ANALYZER – ANALYSIS

Causes and Probabilities