Highlighting Heavy Oil

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34 Oilfield Review Highlighting Heavy Oil Hussein Alboudwarej Joao (John) Felix Shawn Taylor Edmonton, Alberta, Canada Rob Badry Chad Bremner Brent Brough Craig Skeates Calgary, Alberta Andy Baker Daniel Palmer Katherine Pattison Anchorage, Alaska, USA Mohamed Beshry Paul Krawchuk Total E&P Canada Calgary, Alberta George Brown Southampton, England Rodrigo Calvo Jesús Alberto Cañas Triana Macaé, Brazil Roy Hathcock Kyle Koerner Devon Energy Houston, Texas, USA Trevor Hughes Cambridge, England Dibyatanu Kundu Bombay, India Jorge López de Cárdenas Houston, Texas Chris West BP Exploration (Alaska) Inc. Anchorage, Alaska For help in preparation of this article, thanks to Cosan Ayan, Jakarta, Indonesia; Hany Banna, Bombay, India; Teresa Barron, Syncrude Canada Ltd., Fort McMurray, Alberta, Canada; Celine Bellehumeur, Jonathan Bryan and Apostolos Kantzas, University of Calgary, Alberta; Sheila Dubey, Shell Global Solutions (US), Houston; Maurice Dusseault, University of Waterloo, Ontario, Canada; Joelle Fay, Gatwick, England; Abul Jamaluddin, Rosharon, Texas; Robert Kleinberg, Ridgefield, Connecticut, USA; David Law and Allan Peats, Calgary; Trey Lowe, Devon Energy Internatlional, Houston; David Morrissey and Oliver Mullins, Houston; and Tribor Rakela and Ricardo Vasques, Sugar Land, Texas. AIT (Array Induction Imager Tool), CMR-200 (Combinable Magnetic Resonance), DSI (Dipole Shear Sonic Imager), Hotline, LFA (Live Fluid Analyzer), MDT (Modular Formation Dynamics Tester), PhaseTester, Platform Express, Quicksilver Probe, REDA, VDA (Viscoelastic Diverting Acid) and Vx are marks of Schlumberger. THAI (Toe-to-Heel Air Injection) is a trademark of Archon Technologies Ltd. Dwindling oil supply, high energy prices and the need to replenish reserves are encouraging oil companies to invest in heavy-oil reservoirs. Heavy and viscous oils present challenges in fluid analysis and obstacles to recovery that are being surmounted by new technology and modifications of methods developed for conventional oils.

Transcript of Highlighting Heavy Oil

Page 1: Highlighting Heavy Oil

34 Oilfield Review

Highlighting Heavy OilHussein AlboudwarejJoao (John) FelixShawn TaylorEdmonton, Alberta, Canada

Rob BadryChad BremnerBrent BroughCraig SkeatesCalgary, Alberta

Andy BakerDaniel PalmerKatherine PattisonAnchorage, Alaska, USA

Mohamed BeshryPaul KrawchukTotal E&P CanadaCalgary, Alberta

George BrownSouthampton, England

Rodrigo CalvoJesús Alberto Cañas TrianaMacaé, Brazil

Roy HathcockKyle KoernerDevon EnergyHouston, Texas, USA

Trevor HughesCambridge, England

Dibyatanu KunduBombay, India

Jorge López de CárdenasHouston, Texas

Chris WestBP Exploration (Alaska) Inc.Anchorage, Alaska

For help in preparation of this article, thanks to CosanAyan, Jakarta, Indonesia; Hany Banna, Bombay, India;Teresa Barron, Syncrude Canada Ltd., Fort McMurray,Alberta, Canada; Celine Bellehumeur, Jonathan Bryan andApostolos Kantzas, University of Calgary, Alberta; SheilaDubey, Shell Global Solutions (US), Houston; MauriceDusseault, University of Waterloo, Ontario, Canada; Joelle Fay, Gatwick, England; Abul Jamaluddin, Rosharon,Texas; Robert Kleinberg, Ridgefield, Connecticut, USA;David Law and Allan Peats, Calgary; Trey Lowe, DevonEnergy Internatlional, Houston; David Morrissey and OliverMullins, Houston; and Tribor Rakela and Ricardo Vasques,Sugar Land, Texas.AIT (Array Induction Imager Tool), CMR-200 (CombinableMagnetic Resonance), DSI (Dipole Shear Sonic Imager),Hotline, LFA (Live Fluid Analyzer), MDT (Modular FormationDynamics Tester), PhaseTester, Platform Express, Quicksilver Probe, REDA, VDA (Viscoelastic Diverting Acid)and Vx are marks of Schlumberger.THAI (Toe-to-Heel Air Injection) is a trademark of ArchonTechnologies Ltd.

Dwindling oil supply, high energy prices and the need to replenish reserves are

encouraging oil companies to invest in heavy-oil reservoirs. Heavy and viscous

oils present challenges in fluid analysis and obstacles to recovery that are being

surmounted by new technology and modifications of methods developed for

conventional oils.

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Most of the world’s oil resources are heavy,viscous hydrocarbons that are difficult and costlyto produce and refine. As a general rule, theheavier, or denser, the crude oil, the lower itseconomic value. Less dense, lighter ends of crudeoil derived from simple refining distillation arethe most valuable. Heavy crude oils tend to havehigher concentrations of metals and otherelements, requiring more effort and expense toextract useable products and dispose of waste.

With high oil demand and prices, andproduction of most conventional-oil reservoirs indecline, industry focus in many parts of the worldis shifting to exploitation of heavy oil. Heavy oil isdefined as having 22.3°API or less.1 Oils of10°API or less are known as extraheavy,ultraheavy or superheavy because they aredenser than water. In comparison, conventionaloils such as Brent or West Texas Intermediatecrudes have densities from 38° to 40°API.

While oil density is important for evaluatingresource value and estimating refining outputand costs, the fluid property that most affectsproducibility and recovery is oil viscosity. Themore viscous the oil, the more difficult it is toproduce. There is no standard relationshipbetween density and viscosity, but “heavy” and“viscous” tend to be used interchangeably todescribe heavy oils, because heavy oils tend to be more viscous than conventional oils.Conventional-oil viscosity may range from1 centipoise (cP) [0.001 Pa.s], the viscosity ofwater, to about 10 cP [0.01 Pa.s]. Viscosity ofheavy and extraheavy oils may range from lessthan 20 cP [0.02 Pa.s] to more than 1,000,000 cP[1,000 Pa.s]. The most viscous hydrocarbon,bitumen, is a solid at room temperature, andsoftens readily when heated.

Since heavy oil is less valuable, more difficultto produce and more difficult to refine thanconventional oils, the question arises as to whyoil companies are interested in devotingresources to extract it. The first part of the two-part answer is that under today’s economicconditions, many heavy-oil reservoirs can now beexploited profitably. The second part of theanswer is that these resources are abundant. Theworld’s total oil resources amount to roughly 9 to13 x 1012 (trillion) barrels [1.4 to 2.1 trillion m3].Conventional oil makes up only about 30% of thatamount, with the remainder in heavy oil,extraheavy oil and bitumen (top right).

Heavy oil promises to play a major role in thefuture of the oil industry, and many countries aremoving now to increase their production, revisereserves estimates, test new technologies andinvest in infrastructure to ensure that their heavy-oil resources are not left behind. This articledescribes how heavy-hydrocarbon deposits areformed and how they are being produced.Important steps along the way are the selection ofrecovery method, downhole and laboratoryanalysis of fluid samples, well testing andcompletion, and monitoring of the heavy-oilrecovery process.

Formation of Vast ResourcesOf the world’s 6 to 9 trillion barrels [0.9 to1.4 trillion m3] of heavy and extraheavy oil andbitumen, the largest accumulations occur insimilar geological settings. These are supergiant,shallow deposits trapped on the flanks offoreland basins. Foreland basins are hugedepressions formed by downwarping of theEarth’s crust during mountain building. Marinesediments in the basin become source rock forhydrocarbons that migrate updip into sedimentseroded from the newly built mountains (above).The new sediments often lack sealing caprocks.In these shallow, cool sediments, thehydrocarbon is biodegraded.

> Total world oil reserves. Heavy oil, extraheavy oil and bitumen, makeup about 70% of the world’s total oil resources of 9 to 13 trillion bbl.

Conventional oil30%

Heavy oil15%

Oil sands and bitumen30%

Extraheavy oil25%

Total World Oil Reserves

> Geological setting of one of the world’s largest deposits of heavy oil. During mountain-buildingevents, foreland basins are formed in front of the mountain range by bending of the Earth’s crust.Marine sediments in the basin (purple) become source rock for hydrocarbons (dark brown) thatmigrate updip into sediments (orange) eroded from the newly built mountains. Microbes in theserelatively cool sediments biodegrade the oil, forming heavy oil and bitumen. Where the overburden is less than 50 m [164 ft], the bitumen can be surface-mined.

3,000

2,000

1,000

–3,000

–4,000

–2,000

–1,000

Height, m

Sea level 0Oil

and gasOil

and gasNo oilor gas

2,800 mbelow sea level

No oil or gas

Precambrian“basement”

Oil sandsand heavy-oil

deposits

Fort McMurrayCalgaryBanff

British Columbia Alberta Saskatchewan

Oiland gas

Younger clastic sediments (sandstones and shales)

Older carbonate sediments (limestones and dolomites)

Ancient crystalline rocks (granites)

Western Canada Sedimentary Basin

1. Calculation of API gravity uses surface measurement ofspecific gravity of degassed oil. The formula relatingspecific gravity (S.G.) at 60°F to API gravity is API gravity = (141.5/S.G.)-131.5. Conaway C: The PetroleumIndustry: A Nontechnical Guide. Tulsa: PennwellPublishing Co., 1999.

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Biodegradation is the main cause of theformation of heavy oil.2 Over geologic time scales,microorganisms degrade light and mediumhydrocarbons, producing methane and enrichedheavy hydrocarbons. The effect of biodegradationis to cause oxidation of oil, decreasing gas/oilratio (GOR) and increasing density, acidity,viscosity and sulfur and other metal content.Through biodegradation, oils also lose asignificant fraction of their original mass. Othermechanisms, such as water washing and phasefractionation, contribute to the formation ofheavy oil, separating light ends from heavy oil byphysical rather than biological means. Optimalconditions for microbial degradation ofhydrocarbons occur in petroleum reservoirs attemperatures less than 80°C [176°F]; theprocess is therefore restricted to shallowreservoirs, down to about 4 km [2.5 miles].

The largest known individual petroleumaccumu lation is the Orinoco heavy-oil belt inVenezuela with 1.2 trillion barrels [190 bil -lion m3] of extraheavy, 6 to 12°API oil. Thecombined extraheavy oil accumulations in thewestern Canada basin in Alberta total 1.7 tril -lion bbl [270 billion m3]. The sources of theseoils are not completely understood, but it isagreed in both cases that they derive fromseverely biodegraded marine oils. The 5.3 trillionbarrels [842 billion m3] in all the deposits ofwestern Canada and eastern Venezuelarepresent the degraded remains of what wasprobably once 18 trillion barrels [2.9 trillion m3]of lighter oils.3

In any depositional environment, the rightcombination of water, temperature and microbescan cause degradation and formation of heavyoil. Tar mats occur in many reservoirs near the

oil/water contact, where conditions are condu -cive to microbial activity. The depositionalenvironment, the original oil composition, thedegree to which it has been degraded, the influxof, or charging with, lighter oils and the finalpressure and temperature conditions make everyheavy-oil reservoir unique, and all of themrequire different methods of recovery.

Recovery MethodsHeavy-oil recovery methods are divided into twomain types according to temperature. This isbecause the key fluid property, viscosity, is highlytemperature-dependent; when warmed, heavyoils become less viscous (left). Cold productionmethods—those that do not require addition ofheat—can be used when heavy-oil viscosity atreservoir conditions is low enough to allow the oilto flow at economic rates. Thermally assistedmethods are used when the oil must be heatedbefore it will flow.

The original cold method of heavy-oil recoveryis mining. Most heavy-oil mining occurs in open-pit mines in Canada, but heavy oil has also beenrecovered by subsurface mining in Russia.4 Theopen-pit method is practical only in Canada wherethe surface access and volume of the shallow oil-sand deposits—estimated at 28 billion m3

[176 billion barrels]—make it economic.5

Canadian oil sands are recovered by truckand shovel operations, then transported toprocessing plants where warm water separatesbitumen from sand (right). The bitumen isdiluted with lighter hydrocarbons and upgradedto form synthetic crude oil. After mining, the land is refilled and reclaimed. An advantageof the method is that it recovers about 80% of the hydrocarbon. However, only approximately20% of the reserves, or those down to about 75 m[246 ft], can be accessed from the surface. In2005, Canadian bitumen production was175,000 m3/d [1.1 million bbl/d]. This is expectedto grow to 472,000 m3/d [3 million bbl/d] by 2015.6

Some heavy oils can be produced fromboreholes by primary cold production. Much ofthe oil in the Orinoco heavy-oil belt in Venezuelais currently being recovered by cold production,as are reservoirs offshore Brazil.7 Horizontal andmultilateral wells are drilled to contact as muchof the reservoir as possible.8 Diluents, such asnaphtha, are injected to decrease fluid viscosity,and artificial lift technology, such as electricalsubmersible pumps (ESPs) and progressingcavity pumps (PCPs) lift the hydrocarbons to thesurface for transport to an upgrader.9 Anadvantage of the method is lower capital

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> Relationship between viscosity and temperatureof heavy oils. Every heavy oil, extraheavy oil andbitumen has its own temperature-viscosityrelationship, but they all follow this trend, withviscosity decreasing as temperature increases.

Visc

osity

, cP

10,000,000

1,000,000

100,000

10,000

1,000

100

10

1

Temperature, °C

0 50 100 150 200 250 300

> Bitumen recovery from oil sands. When over-burden is less than 50 m, bitumen can be minedfrom the surface. The process, depicted inphotographs oriented from top to bottom, startsby recovering oil sands by truck and shoveloperations. The sands are transported toprocessing plants where warm water separatesbitumen from sand. The bitumen is diluted withlighter hydrocarbons and upgraded to formsynthetic crude oil. Finally, the land is refilledand reclaimed. (Images courtesy of SyncrudeCanada Ltd.)

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expenditure relative to thermally assistedtechniques, but the recovery factor is also low—6 to 12%. An additional challenge is the increasein fluid viscosity that arises with the formation ofoil-water emulsions, caused by mixing andshearing in pumps and tubulars.

Cold heavy-oil production with sand (CHOPS)is another primary production method that hasapplicability in many heavy-oil reservoirs. Inhundreds of fields in Canada, sand—up to 10%“sand cut” by volume—is produced along withthe oil (right). Gas exsolving from thedepressurized oil helps destabilize and movesand grains. Sand movement increases fluidmobility and forms channels, called wormholes,which create a growing zone of high permeabilityaround the well. The overburden weight helpsextrude sand and liquids. Sand and oil areseparated by gravity at surface, and the sand isdisposed of into permeable strata. The methodrequires multiphase pumps that can handlesand, oil, water and gas, and has been applied inreservoirs with oil viscosity from 50 to 15,000 cP[0.05 to 15 Pa.s].10 In Canada, annual productionof heavy oil by the CHOPS method was700,000 bbl/d [111,230 m3/d] as of 2003.

Waterflooding is a cold enhanced oil-recovery(EOR) method that has been successful in someheavy-oil fields. For example, offshore fields onthe UK continental shelf use waterflooding toproduce 10- to 100-cP oil from long, screen-supported horizontal wells to a floatingproduction, storage and offloading (FPSO)system.11 The method is being considered fornearby fields with higher viscosity fluids, but therecovery factor decreases with increasing oilviscosity. High-viscosity oils cause viscousfingering in waterflood fronts, resulting in poorsweep efficiency.

Vapor-assisted petroleum extraction (VAPEX)is a relatively new process being tested inCanada. It involves the injection of a misciblesolvent, which reduces the viscosity of heavy oil.The method can be applied one well at a time orin well pairs. In the single-well approach, thesolvent is injected from the toe of a horizontalwell. In the double-well case, solvent is injectedinto the upper well of a pair of parallel horizontalwells. Valuable gases are scavenged after theprocess by inert gas injection. VAPEX has

been studied extensively in the laboratory and in simulations, and is undergoing pilot testing,but has not yet been deployed in large-scale field operations.

Thermal methods, like their coldcounterparts, have advantages and limitations.Recovery factors are higher than for coldproduction methods—with the exception ofmining—but so are costs associated with heatgeneration and water treatment. Cyclic steamstimulation (CSS), also known as steam soak, or

2. Head IM, Jones DM and Larter SR: “Biological Activity inthe Deep Subsurface and the Origin of Heavy Oil,”Nature 426, no. 6964 (November 20, 2003): 344–352.

3. Meyer RF: “Natural Bitumen and Extra-Heavy Oil,” World Energy Council Survey of Energy Resources,www.worldenergy.org/wec-geis/publications/reports/ser/bitumen/bitumen.asp (accessed June 1, 2006).

4. Alberta Chamber of Resources: “Oil Sands TechnologyRoadmap: Unlocking the Potential,” http://www.acr-alberta.com/Projects/Oil_Sands_Technology_Roadmap/OSTR_report.pdf (accessed June 24, 2006).Meyerhoff AA and Meyer RF: “Geology of Heavy CrudeOil and Natural Bitumen in the USSR, Mongolia andChina: Section I: Regional Resources,” in Meyer RF (ed):Exploration for Heavy Crude Oil and Natural Bitumen.AAPG Studies in Geology no. 25. Tulsa: AAPG (1987):31–101.

> Slurry produced by cold heavy-oil production with sand (CHOPS). This tank-bottom sample wasrecovered from a tank farm at an oil-cleaning battery near Lloydminster, Saskatchewan, Canada, andis composed of approximately 10 to 20% fine-grained clay and silica, 20 to 30% viscous oil and 50 to60% water. (Photograph courtesy of Maurice Dusseault.)

5. National Energy Board of Canada: “Energy MarketAssessment, Canada’s Oil Sands: Opportunities andChallenges to 2015: An Update,” http://www.neb-one.gc.ca/energy/EnergyReports/EMAOilSandsOpportunitiesChallenges2015_2006/EMAOilSandsOpportunities2015QA2006_e.htm (accessed June 3, 2006).

6. National Energy Board of Canada, reference 5.7. Capeleiro Pinto AC, Branco CC, de Matos JS, Vieira PM,

da Silva Guedes S, Pedroso CJ, Decnop Coelho AC andCeciliano MM: “Offshore Heavy Oil in Campos Basin: The Petrobras Experience,” paper OTC 15283, presentedat the Offshore Technology Conference, Houston, May 5–8, 2003.

8. Stalder JL, York GD, Kopper RJ, Curtis CM, Cole TL and Copley JH: “Multilateral-Horizontal Wells IncreaseRate and Lower Cost Per Barrel in the Zuata Field, Faja, Venezuela,” paper SPE 69700, presented at the SPE International Thermal Operations and Heavy OilSymposium, Porlamar, Marguerita Island, Venezuela,March 12–14, 2001.

9. Robles J: “Application of Advanced Heavy OilProduction Technologies in the Orinoco Heavy-Oil-Belt,Venezuela,” paper SPE 69848, presented at the SPEInternational Thermal Operations and Heavy OilSymposium, Porlamar, Marguerita Island, Venezuela,March 12–14, 2001.Upgrading is the hydrogenation of heavy crudes by theaddition of hydrogen. The product of upgrading issynthetic crude oil.

10. Course notes from Professor Maurice Dusseault,University of Waterloo, Ontario, Canada.

11. Etebar S: “Captain Innovative Development Approach,”paper SPE 30369, presented at the SPE Offshore EuropeConference, Aberdeen, September 5–8, 1995.Rae G, Hampson J, Hiscox I, Rennie M, Morrison A andRamsay D: “A Case Study in the Design and Execution ofSubsea Production Development Wells in the CaptainField,” paper SPE 88837, SPE Drilling & Completion 19,no. 2 (June 2004 ): 82–93.

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huff and puff, is a single-well method applied instages (below). First, steam is injected. Then,during the soaking, or waiting, period, the oilheats up. Finally, the heated oil and water areproduced and separated, and the processrepeats. The method obtains recovery factors upto 30%, has high initial production rates andworks well in stacked or layered reservoirs. TheCold Lake field in Alberta, Canada, is an exampleof CSS application.

Steamflooding, another thermal method, is amultiwell process. Steam is injected into injectorwells in a variety of spacing and locationpatterns, and oil is produced from producerwells. Steamflooding can achieve up to a 40%recovery factor, but requires good interwellmobility to inject steam at effective rates.Challenges with this method are gravity overrideof the low-density steam, reservoir hetero -geneities and monitoring the steam front.Examples are Duri field in Indonesia, Kern Riverfield in California, and Pikes Peak Lloydminsterin Canada.

Steam-assisted gravity drainage (SAGD)works for extraheavy oils. A pair of parallelhorizontal wells is drilled, one well about 5 to 7 m[16 to 23 ft] above the other (next page, top).Steam injected into the upper well heats theheavy oil, reducing its viscosity. Gravity causesthe mobilized oil to flow down toward the lowerhorizontal producer. Initial communication isestablished between the injector and producerby steam, cyclic steam or solvent injection. Theestimated recovery factor for this method isbetween 50 and 70%.12 However, formationlayering can significantly influence SAGDrecovery.13 SAGD is used in many fields in Canada,including Christina Lake and MacKay River.

In-situ combustion, also known asfireflooding, is a method for mobilizing highlyviscous oils. It is a multiwell process in which acombustion front initiated at an air-injectionwell propagates to a producing well. The in-situcombustion burns some of the oil, and the heatsufficiently reduces the viscosity of the rest to

allow production. The burnt oil, or combustionresidue, is left behind. The combustion upgradesthe crude oil by cracking, or separating smallmolecules from large ones. Most attempts at fieldapplication have found the process to beunstable. However, in Romania, the large-scalefireflooding operation in the Suplacu de Barcaufield has been operating since 1964.14

New technologies are being developed tostabilize the combustion front in the in-situcombustion process. For example, the THAI Toe-to-Heel Air Injection method, a trademark ofArchon Technologies Ltd., uses a combination ofvertical injector and horizontal producer. Themethod is currently in field pilot test in theMcMurray formation near Conklin, Alberta.15

Selecting a Recovery MethodWith various recovery methods available,selecting the best one for a particular reservoirrequires a comprehensive study that incorpo ratesmany factors, such as fluid properties, formationcontinuity, rock mechanics, drilling technology,completion options, production simulation andsurface facilities. This multi disciplinary teameffort must also consider trade-offs betweenfactors such as reserves, expected recovery ratesand production rates. Also required isconsideration of the cost of energy generationand the environmental sensitivity of thesurroundings. An example of the type ofscreening study that can help companies decidehow to produce heavy-oil resources comes fromthe North Slope in Alaska, where BP Exploration(Alaska) Inc. is assessing methods for producingthe high-viscosity oil in the Ugnu sands (nextpage, bottom).

The Ugnu sands and their deeper neighbor,the Schrader Bluff formation, were firstencountered in 1969, when operators drilled andtested the deeper Kuparuk formation.16 At thetime, there was no viable technology to developthe highly viscous oils in the Ugnu and SchraderBluff sands, so the companies concentrated onthe prolific Kuparuk formation. The SchraderBluff formation is a stratigraphically deeperformation and contains relatively lighter viscousoil than the Ugnu. Sections of the Schrader Bluffformation are on waterflood and have beenproducing since the early 1990s. Over the years,several companies conducted simulations andpilot studies to assess the feasibility ofwaterflooding and other enhanced oil-recovery(EOR) methods for producing the Ugnu, butfailed to find economic means to exploit theheavy-oil resources.17

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> Cyclic steam stimulation (CSS), a single-well method applied in stages.First, steam is injected (left). Next, the steam and condensed water heatthe viscous oil (center). Finally, the heated oil and water are pumped to thesurface (right). The process is then repeated.

Stage 1:Steam Injection

Stage 2:Soak Phase

Stage 3:Production

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BP is currently evaluating development of theheavy-oil reserves in the Milne Point unit of theNorth Slope. The total prize is estimated to bebillions of barrels of oil originally in place in theLower Ugnu formation, with a significantpercentage positioned in BP’s Milne Point unit.The reservoir and fluid properties vary across thefield, and are generally represented by high oildensity and viscosity and a low reservoirtemperature of 75°F [24°C]. This means thereservoir clearly requires nonprimary recoverymethods such as some form of enhanced cold production, cyclic steam stimulation,steamflooding, SAGD or hybrid process.

To determine the best approach, a 30-member team comprising BP and Schlumbergerspecialists conducted a screening study. Theobjective of the study was to identify thedevelopment technique that would economicallymaximize oil production rates and recoveryfactor, while ensuring minimal and acceptableheat loss to permafrost and minimal effect onnaturally occurring gas hydrates. The screeningstudy emphasized CO2 and greenhouse-gashandling and usage, and enforced the higheststandards of HSE. A joint BP/Schlumbergertechnology study is currently under way toexamine options to bring heavy-oil developmentsin line with BP’s Green Agenda. The study resultswill be input to the BP Appraise Stage Plan forfinal decision making on Ugnu development.

The screening study reviewed previousstudies and reports issued during the last25 years. With these studies and available data,

> Steam-assisted gravity drainage (SAGD, pronounced sag-dee). A pair of parallel horizontal wells isdrilled, one above the other. Steam is injected into the upper well to heat the heavy oil, reducing itsviscosity. Gravity causes the oil to flow down toward the producer.

Oil

Steam

Caprock

Sand

Shale

SteaminjectionHeatedheavy oilflows towell

km

miles0

0 100

100

Kupa

ruk R

iver

MilnePoint Prudhoe

BayHarrison

Bay

B E A U F O R T S E A

Alaska USA CANADA

L-sand

M-sand

N-sand

O-sands

Ugnu

SchraderBluff

Gamma Ray0 gAPI 150

Deep Resistivity,Induction

0.2 200ohm.m

12. Course notes from Professor Maurice Dusseault,University of Waterloo, Ontario, Canada.

13. Contreras C, Gamero H, Drinkwater N, Geel CR, Luthi S,Hodgetts D, Hu YG, Johannessen E, Johansson M,Mizobe A, Montaggioni P, Pestman P, Ray S, Shang Rand Saltmarsh A: “Investigating Clastic ReservoirSedimentology,” Oilfield Review 15, no. 1 (Spring 2003):54–77.

14. Panait-Patica A, Serban D and Ilie N: “Suplacu deBarcau Field—A Case History of a Successful In-SituCombustion Exploitation,” paper SPE 100346, presentedat the SPE Europec/EAGE Annual Conference andExhibition, Vienna, Austria, June 12–15, 2006.Paduraru R and Pantazi I: “IOR/EOR—Over Six Decadesof Romanian Experience,” paper SPE 65169, presented at the SPE European Petroleum Conference, Paris,October 24–25, 2000.

15. “WHITESANDS Experimental Project,” http://www.petrobank.com/ops/html/cnt_white_project.html(accessed July 3, 2006).

16. Bidinger CR and Dillon JF: “Milne Point Schrader Bluff:Finding the Keys to Two Billion Barrels,” paper SPE 30289, presented at the SPE International Heavy Oil Symposium, Calgary, June 19–21, 1995.

17. Bidinger and Dillon, reference 16. Werner MR: “Tertiary and Upper Cretaceous Heavy-OilSands, Kuparuk River Unit Area, Alaskan North Slope:Section V: Exploration Histories,” in Meyer RF (ed):Exploration for Heavy Crude Oil and Natural Bitumen.AAPG Studies in Geology no. 25. Tulsa: AAPG (1987):537–547.

> The Milne Point unit near the Kuparuk River inAlaska. BP Exploration (Alaska) Inc. is studyingthe best way to produce the high-viscosity oil inthe Ugnu sands.

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three representative wells in the Milne Pointarea were selected for a detailed review. Thewells penetrated intervals of varying reservoirquality. To determine the best recovery method,several were simulated, including steamflooding,CSS, SAGD, hot waterflooding and primaryproduction. The effects of vertical, deviated andhorizontal wells were also tested in thesimulation runs.

The results of the study were compiled in aninteractive matrix that quantified the sensitivityof each recovery method to production,subsurface, surface and cost factors (above).Each matrix block was colored according tofactor sensitivity and acted as a link to reports,analysis and presentations that supported thesensitivity rating. For example, of the subsurfacefactors, improved fluid characterization androck-mechanical properties are rated of criticalknowledge importance for every EOR methodassessed. A brief look at the availableinformation shows why.

Reservoir fluid PVT properties, in particularfluid viscosity and its variation with temperature,are crucial factors in selection of a recoverytechnique.18 These were inadequately known forthe fluids in the Ugnu formation. Measured oil-viscosity data were limited to two productionsamples with dead-oil viscosities of 200 and2,500 cP at 80°F [0.2 Pa.s and 2.5 Pa.s at 27°C].These samples are not thought to be represen -tative of the entire range of viscosities present inthe Ugnu sands. Geochemical transforms wereused to predict oil viscosity from sidewall coresamples. However, this technique relied onextrapolation beyond the range of measuredviscosities and made the assumption that Ugnuoils have the same controls on oil quality as theSchrader Bluff oils. Although the model served asa good starting point, fine-tuning this model forpredicting oil viscosity and collection ofadditional samples was one of the recommen -dations made in the study.

Another critical factor, rock-mechanicalproperties, was assessed by examination of coreand analysis of DSI Dipole Shear Sonic Imagerlogs from the MPS-15 well. Ugnu sand hasextremely low strength, less than 200 psi[1.4 MPa] in estimated unconfined compressivestrength; the core is soil-like and easily crushedby hand, foreshadowing potential wellbore-stability and completion challenges. Additionally,two distinct peaks were noted on the sand sizedistribution. These indicate that a considerableamount of silt, 5- to 60-micron sized, may beproduced along with fine- to very-fine-grain sand of 60 to 250 microns. These fines will have to be either controlled or managed withUgnu oil production.

To determine suitable drawdown pressuresand a depth-stability envelope for production,estimates of mechanical-property data andcompletion options, such as perforation size andorientation, were input to the Sand ManagementAdvisor software. These initial calculations

40 Oilfield Review

> Sensitivity matrix from the Ugnu screening study, quantifying the sensitivity of each recoverymethod to production, subsurface, surface and cost factors. Each matrix block was coloredaccording to factor sensitivity to performance or knowledge importance. In terms of performance,green means excellent, yellow means fair and red means poor. In terms of knowledge importance,green means less important, yellow means important and red means critical. For example, in theproduction categories, CSS was rated excellent performance for production rate per well, reservesper well and reserves recovery. Of the subsurface factors, for example, fluid characterization androck-mechanical properties are rated of critical knowledge importance for every EOR methodassessed. In the interactive version of the matrix, clicking on a box accesses the reports and studiesbehind the evaluation.

Continuous steamflood injection

Cyclic steam stimulation (CSS)

Steam-assisted gravity drainage (SAGD)

Hot waterflood injection

Cold oil production (CHOPS)

Viable EOR Techniques

Key

Perf

orm

ance

Indi

cato

rs

Prod

uctio

n ra

te p

er w

ell

Rese

rves

per

wel

l

Rese

rvoi

r rec

over

y

Petro

phys

ics

Geol

ogy

Flui

d ch

arac

teriz

atio

n

Rock

-mec

hani

cal p

rope

rties

Gas

hydr

ates

Artif

icia

l lift

con

figur

atio

n

Perm

afro

st c

hara

cter

istic

s

CO2 e

mis

sion

s

Fuel

requ

irem

ents

Faci

lity

cost

s

Drill

ing

cost

s

Com

plet

ion

cost

s

Tech

nolo

gy a

vaila

bilit

y

Production Subsurface Surface Costs

Excellent/ less important

Fair/important

Poor/critical

Performance/Knowledge

18. PVT stands for pressure, volume and temperature. PVTproperties are equations for the density of a fluid as afunction of temperature and pressure, the pressure-temperature coordinates of the phase lines, and relatedthermodynamic properties.

19. Freedman R, Heaton N, Flaum M, Hirasaki GJ, Flaum Cand Hurlimann M: “Wettability, Saturation, and Viscosityfrom NMR Measurements,” paper SPE 87340, presentedat the SPE Annual Technical Conference and Exhibition,

San Antonio, Texas, September 29–October 2, 2002; alsoin SPE Journal 8, no. 4 (December 2003): 317–327.

20. Bryan J, Kantzas A and Bellehumeur C: “ViscosityPredictions from Low-Field NMR Measurements,” paperSPE 89070, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas,September 29–October 2, 2002; also in SPE ReservoirEvaluation & Engineering 8, no. 1 (February 2005): 44–52.

Mirotchnik KD, Allsopp K, Kantzas A, Curwen D andBadry R: “Low-Field NMR Method for Bitumen SandsCharacterization: A New Approach,” paper SPE 71208,presented at the SPE Annual Technical Conference andExhibition, San Antonio, Texas, September 29–October 2,2002; also in SPE Reservoir Evaluation & Engineering 4,no. 2 (April 2001): 88–96.

21. Relative hydrogen index (RHI) is defined as a ratio ofamplitude indexes (AI): RHI = AIoil/ AIwater, where AI =amplitude of fluid signal/mass of fluid.

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determined that any drawdown greater than1 psi [6.9 kPa] would cause complete sandfailure. The recommendation was to anticipatesand production during drilling and completion,and to develop creative sand-managementstrategies, such as microslotted liners.

Of the five recovery methods assessed, cyclicsteam stimulation gave the best recovery andproduction rates. If this method is selected, carewill have to be taken not to overheat thepermafrost. This should be possible since thereservoir is isolated from permafrost layers by athick, impermeable shale. Other methods, suchas primary cold production, would have minimalimpact on permafrost, but may have difficultyyielding economic recovery or production rates.SAGD, while having a similar environmentalimpact as CSS, would not be as effective in thestudy location, because it requires a high ratio ofvertical to horizontal permeability for develop -ment of a steam chamber. Continuity of the Ugnuformation will significantly influence the finalrecovery factor, and reservoir description will bea critical component of ongoing work.

Ultimately, the screening study recom -mended cyclic steam stimulation as the optimalrecovery method for the area of study in theMilne Point unit, and outlined well spacing,orientation and patterns. Also, additionalsimulation was recommended to assess theeffects of varying steam-injection rates andvolumes and to investigate the feasibility ofconverting to steamflooding.

Characterizing Heavy Oils DownholeA critical step in determining the best heavy-oilrecovery method is to characterize reservoir fluidproperties. For the purposes of grading reservesand selecting sampling intervals, companies turnto downhole measurements of fluid properties,especially viscosity.

Knowledge of viscosity throughout thereservoir is vital for modeling production andpredicting reserves recovery. However, heavy-oilviscosity can exhibit large variations, even withinthe same formation. Building a viscosity maprequires adequate sampling and logging-derivedinformation of in-situ viscosity.

Nuclear magnetic resonance (NMR) logginghas been used successfully to determine in-situviscosity of conventional oils, but currentcommercial methods have limitations in heavyand viscous oils.19 This is because as fluidviscosity increases, NMR relaxation time, T2,decreases. When relaxation times are extremelyshort, NMR logging tools cannot detect them.

When viscosity is greater than about 100,000 cP[100 Pa.s], NMR tools see most of the heavy oil orbitumen as part of the rock matrix.

To improve understanding of the correlationbetween viscosity and NMR response,researchers at the University of Calgary and itsaffiliate institute, the Tomographic Imaging andPorous Media (TIPM) Laboratory, acquired andinterpreted laboratory NMR measurements on alarge selection of Canadian heavy oils.20 Oils inthe database have viscosities ranging from lessthan 1 cP to 3,000,000 cP [0.001 to 3,000 Pa.s].

Measured viscosities showed a correlationwith two NMR parameters, but with differingsensitivities. With increasing viscosity, T2

decreased and, at high viscosities, became lesssensitive to changes in viscosity. However,increasing viscosity caused the decreasing

relative hydrogen index (RHI) to become moresensitive to viscosity change at high viscosities(above).21 On the basis of these findings, theresearchers developed a new empiricalrelationship between the NMR parameters andfluid viscosity. The relationship was adjusted toprovide the best possible fit for the five oils in thedatabase for which viscosity data were availableover a range of temperatures (below).

Translating this laboratory NMR-viscosityrelationship to one that works for NMR loggingtools is not straightforward. Heavy oils in rocksare mixed with other fluids and exhibit behaviorsthat differ from bulk fluids in the laboratory.However, the right combination of laboratory and logging measurements can provide theinformation necessary to fine-tune the viscosityrelationship and produce a continuous viscosity

> Correlation between laboratory-measured viscosities and two laboratory-measured nuclearmagnetic resonance (NMR) parameters. NMR relaxation time, T2, decreases as viscosity increases(left). However, at extremely high viscosities, there is little change in T2. Relative hydrogen index(RHI) also decreases with increasing viscosity (right), but is more sensitive to viscosity change athigh viscosities. (Adapted from Bryan et al, reference 20.)

10,000,000

1,000,000

100,000

10,000

1,000

100

10

1

0.110.1 10 100 1,000 10,000

Oil T2, ms

Mea

sure

d vi

scos

ity, c

P

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1,000,000

100,000

10,000

1,000

100

10

1

0.110.1

Mea

sure

d vi

scos

ity, c

P

Oil RHI

> Correlation between measured viscosity and viscosity calculated using an empirical relationshipbased on NMR parameters T2 and RHI. The correlation between measured and calculated viscosities(left) is good, but improves when tuned to fit viscosity data acquired over a range of temperatures(right). (Adapted from Bryan et al, reference 20.)

10,000,000

100,000

1,000

10

0.10.1 10 1,000 100,000 10,000,000

Mea

sure

d vi

scos

ity, c

P

NMR viscosity, cP

10,000,000

100,000

1,000

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0.1

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d vi

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NMR viscosity, cP

GeneralTuned

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log (above). In this heavy-oil example fromWestern Canada, data from the Platform Expressintegrated wireline logging tool and CMR-200Combinable Magnetic Resonance measurements

were used to produce an oil-viscosity log thatshowed good agreement with laboratory oil-viscosity measurements in a range from 30,000 to300,000 cP [30 to 300 Pa.s].

Viscosity measurements in this well show notonly variation, but also a gradient of increasingviscosity with depth in the interval from X64 toX80 m. While this type of gradient is common inthis area, other regions show the opposite effect,

42 Oilfield Review

> A continuous oil-viscosity log produced from Platform Express data and CMR-200 measurements, calibrated to laboratory oil-viscosityvalues. From X64 to X80 m, the continuous viscosity log (Track 5) shows a viscosity gradient, with oil viscosity increasing from 30,000 to300,000 cP.

X60

Mea

sure

d de

pth,

m

X70

X80

X90

Bit Size125 375mm

125 375mm

Caliper

0 150gAPI

Gamma Ray

1 1,000ohm.m

AIT 90-in.Investigation

1 1,000ohm.m

Invaded-ZoneResistivity

0.6 0m3/m3

Total CMR Porosity

0.6 0m3/m3

CMR 3-ms Porosity

0.6 0m3/m3

Free Fluid

0.6 0m3/m3

Neutron Porosity

PEF

-50 950kg/m3

Density Difference

0.6 0m3/m3

Density Porosity

Capillary-Bound Fluid

Small-Pore Porosity

0.3 3,000

T2 Cutoff

T2 Distribution

ms 1,000 1,000,000cP

Oil Viscosity (Laboratory)

1,000 1,000,000cP

Oil Viscosity (NMR)

1 0vol/vol

Sw

0.3 3,000msShale

VolumeFraction

0 10

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with viscosity decreasing with depth. The abilityto estimate heavy-oil viscosity will helpcompanies map viscosity changes throughouttheir heavy-oil reservoirs and ultimately aid indetermining the appropriate completion andrecovery strategies.

Sampling Heavy, High-Viscosity FluidsEvaluating the productivity potential of heavy-oilreservoirs has been difficult because high fluidviscosity and unconsolidated formations make itdifficult to acquire representative fluid samplesand test reservoir dynamics (right). There is nounique solution to the problem of collectingheavy-oil samples in unconsolidated sands, butbest practices and sampling techniquesdeveloped for the MDT Modular FormationDynamics Tester are allowing improvedcharacterization of many heavy-oil reservoirs.

Some of the new technology includes an extra-large-diameter probe, a focused probe, dualpackers with customized gravel-pack screens, anextra-high-pressure displacement pump for lowflow rates, advanced downhole fluid analysis andspecialized sampling methodology.

A methodology that has successfully collectedsamples of high-viscosity oil starts by simulatingthe multiphase flow around the wellbore tomodel the decrease in drilling-fluid contamina -tion with time as fluid is pumped into thewellbore. By varying oil viscosity, permeabilityanisotropy, drilling-fluid invasion, flow rate andMDT position, it is possible to estimate thepumping time required to collect a sample ofsufficiently low contamination.22 The cleanuptime is highly dependent on the effective radiusof invasion. Fortunately, oil of extremely highviscosity restricts invasion, reducing the volumeof fluid that needs to be pumped beforeuncontaminated fluid is pulled into the toolflowline. In one case in South America, atechnique using the MDT dual-packer moduleand a flow rate less than 1 cm3/s successfullysampled oil of viscosity greater than 3,200 cP[3.2 Pa.s] (right).23

In another case, exploring in the northweststate of Rajasthan, India, Cairn Energy discoveredthe Bhagyam field in 2004. The Bhagyam field isone of 17 fields in the Barmer basin, andproduces from the high-permeability Fatehgarhsandstone. Oil reserves in the basin are currentlyestimated at 650 million bbl [103 million m3].

> High-viscosity South American heavy oil acquired by wireline sampling.

> Fluid-sampling log from South America, using the MDT dual-packer module and the spectroscopicLFA Live Fluid Analyzer. The optical channels of the LFA measurement (top) are color-coded by opticaldensity, which corresponds to hydrocarbon-component chain length. Channel 1 (black) correspondsto methane. Channel numbers increase upward. In this example, all optical channels show highamplitudes, indicating an opaque heavy oil. For comparison, LFA results for a light oil are shown tothe right, with low amplitudes in most channels. In the water, water-base mud (WBM) and oil-fractiontrack, blue corresponds to mass fraction of water, green represents mass fraction of oil, and reddishbrown corresponds to slugs of WBM. The absence of gas readings in the gas-fraction track isanother characteristic of heavy oil.

Gas Fraction

Oil FractionsWater

Water-Base Mud

Time, s0 50,000

Pressure

Temperature

PumpoutVolume

Optical Channels

LFA results for alight oil

22. Cañas JA, Low S, Adur N and Teixeira V: “Viscous OilDynamics Evaluation for Better Fluid Sampling,” paperSPE/PS-CIM/CHOA 97767, presented at the SPEInternational Thermal Operations and Heavy OilSymposium, Calgary, November 1–3, 2005.

23. Cañas et al, reference 22.

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Crude-oil properties vary widely in the basin,from 15°API in the north to 52°API farther south(above). In the Bhagyam field, oil density rangesfrom 21°API at the bottom to 30°API at the top.Although they are not as dense as other heavyoils, Bhagyam oils have high wax and asphaltenecontent, giving them high pour point and highviscosity at reservoir temperature.24

Acquiring representative, PVT-qualitysamples of these viscous oils has been a

challenge.25 Reservoir sections are drilled withoil-base mud (OBM) to avoid shale collapse.During sample collection, OBM filtrate iscollected along with reservoir fluid, contami -nating the oil sample. Of the more than30 samples acquired by Schlumberger andanother service company using traditionalformation testers, all have been deemednonrepresentative—too contaminated to yieldcorrect PVT properties during laboratoryanalysis. Filtrate contamination can be assessed

downhole by the LFA Live Fluid Analyzer in realtime before fluid samples are collected. Forexample, at one sampling station in theBhagyam-4, LFA analysis quantified volume-percent contamination at 43% even after105 minutes of pumping (above).

Using a new sampling module on the MDTtool, it is now possible to achieve zero filtratecontamination. The Quicksilver Probe wirelinesampling tool uses a focused sampling approachwhereby contaminated fluid is pumped into oneflowline, completely isolated from pure reservoirfluid collected in a second sampling flowline.

This focused sampling approach was used intwo Bhagyam wells with excellent results. InBhagyam-5, after 27 minutes pumping time, theQuicksilver Probe sampler drew in fluid thatregistered 0% OBM contamination on the LFAdetector. Later, independent laboratory analysisconfirmed a contamination level of 0%. InBhagyam-6, the Quicksilver Probe-LFA combina -tion sampled fluid that averaged 2.2%contamination after 52 minutes of pumping.Subsequent laboratory analysis determined acontamination level of 0%. Of the 18 samplescollected from the two wells, 15 were of PVTquality and 6 samples showed zero contamination(next page, top).

44 Oilfield Review

> Bhagyam field in the Barmer basin in Rajasthan, India, where Cairn Energyproduces crude oils with widely varying API gravities.

Barmer Basin

Shakti,API 15 to 19°

Mangala,API 22 to 29°

Vijaya, API 28 to 35°

Vandana, API 28 to 35°

Saraswati,API 40 to 42°

Raageshwari oil,API 32 to 36°

Guda,API 40 to 42°

Bhagyam,API 21 to 30°

Aishwariya,API 29 to 32°

Kameshwari, API 45 to 52°

Raageshwari gas

I N D I A

RajasthanP A

K I S T A

N

NEPAL

C H I N A

BANGLADESH

SRI LANKAkm

miles0

0 500

500

> Oil-base mud (OBM) contamination levels forsamples acquired in Well Bhagyam-4 usingconventional sampling techniques. The heavy-oilsamples had so much OBM contamination, theycould not be used for PVT analysis.

Oil-Base Mud Contamination Levels

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Laboratory Analysis of Heavy OilsCompared with conventional oils, viscous heavy-oil samples not only are more difficult to acquire,they also present several challenges in laboratoryfluid analysis. Traditional techniques foranalyzing key fluid properties can fail to fullycharacterize heavy-crude samples. To solve thisproblem, researchers and engineers at theSchlumberger Reservoir Fluids Center (SRFC) inEdmonton, Alberta, Canada, have developed newmethodologies for determining phase andviscosity behavior of heavy oils (bottom right). Inaddition, compositional analysis techniquescurrently used on conventional oils have beenapplied to heavy oils, with a view tounderstanding the limitations and identifyingpotential improvements.

Of the several laboratory techniques thathave been developed to describe the chemicalcomposition of oils, the most common is gaschromatography (GC).26 This type of analysisdescribes the chemical nature of the oil insufficient detail to capture differences betweenoils without significantly increasing simulationtime. Standard GC analysis can determinechemical composition of a conventional oil up toC36+.27 Its strength is in detecting the lightcomponents of conventional oils. However,standard GC cannot differentiate the highnumber of large compounds in heavy oils withsufficient detail to use in simulation.

For compositional characterization of heavyoils, SRFC engineers perform additional analysistechniques that more fully examine these high-density, high-viscosity fluids. The techniquesinclude analysis of saturate, aromatic, resin andasphaltene (SARA) fractions and simulateddistillation.28 Each of the techniques hasadvantages and inherent limitations.

> Laboratory contamination analysis. Low contamination levels wereachieved in fluid samples acquired with the Quicksilver Probe focusedsampling tool. Laboratory analysis corroborated downhole fluid-analysisresults. Of the 18 samples collected, 15 were of PVT quality, and 6 ofthese showed no contamination. The dashed pink line indicates thecontamination level, 7%, below which samples are considered to be ofPVT quality.

> The Schlumberger Reservoir Fluids Center (SRFC), in Edmonton, Alberta. At SRFC, experts carry outboth research and engineering activities, focusing on areas of phase behavior, flow assurance,enhanced oil recovery and heavy-oil production.

Laboratory Contamination Analysis

0

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Sample number

24. Pour point is the minimum temperature at which oilpours or flows.

25. PVT-quality samples are those that have sufficiently lowcontamination, such that PVT properties measured in thelaboratory correspond to those of an uncontaminatedsample. The maximum allowable contamination variesby company and laboratory. A common standard is 7%contamination for this basin.

26. In GC, a sample is vaporized, then carried by an inert gas through a column that separates components. Each component produces a separate peak in thedetector output.

27. The phrase “composition to C36+” indicates thatcompounds of up to 35 carbon atoms are separatelydiscriminated, with the remainder combined into afraction indicated as C36+.

28. Crude oil is a complex mix of components of differentmolecular structures and properties. Saturates, alsoknown as alkanes or paraffins, are long hydrocarbonchains of the form CnH2n+2. Aromatics incorporate one ormore benzene [C6H6] rings. Resins are nonvolatileconstituents that are soluble in n-pentane [C5H12] or n-heptane [C7H16]. Asphaltenes are nonvolatile constituentsthat are insoluble in n-pentane or in n-heptane.

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SARA analysis fractionates stock-tank oil intoweight percent saturate, aromatic, resin andasphaltene by solubility and chromatography.29

Although SARA analysis resolves only fourcomponents and seems low-resolution comparedwith the thousands of components resolvable byGC techniques, the strength of the method isthat it analyzes the entire sample, from light toheavy compounds, and so allows all oils to becompared on a consistent standard. For example,SARA analysis confirms the expected increase inresin and asphaltene content with decreasingAPI gravity (above).30 In addition, forconventional oils, SARA analysis gives anindication of fluid stability with respect toasphaltene precipitation, an importantconsideration when designing productionschemes and facilities.31 In the case of heavy oils,SARA analysis is less useful as an indicator ofasphaltene precipitation, which typically occurswhen the heavy oil is diluted with certain gasesor solvents. Also, SARA-analysis practices canvary, making it difficult to compare measure -ments made at different laboratories.

Simulated distillation is a GC technique thatidentifies hydrocarbon components in the orderof their boiling points.32 It is used to simulate thetime-intensive, true-boiling-point laboratoryprocedure. When performed at high tempera -tures, 36 to 750°C [97 to 1,382°F], the techniquecan resolve components up to C120. The resultsare valuable for modeling downstream refiningprocesses and can help refiners select crude oilsthat will produce favorable economic returns. Inheavy oils, simulated distillation has limitedapplication, since the larger compounds thatmake up a significant portion of the heavy oil willundergo chemical degradation at elevatedtemperatures; cracking begins to occur above350°C [662°F].

Another important measurement required of an oil sample is its phase behavior, known asPVT behavior. These measurements describe howthe properties of an oil are affected by changes in pressure, temperature or composition thatmay occur during a production process. In thecase of heavy oils, new techniques andmodifications of existing techniques have beendeveloped to accurately determine heavy-oil fluidproperties as functions of pressure, temperatureand composition.

Standard laboratory techniques measure PVTproperties such as bubblepoint, compressibility,composition of fumes—known as off-gas—density and gas/oil ratio (GOR). Although it isnot precisely a phase property, viscosity also mayvary dramatically with pressure, temperatureand composition, and so it is included in this setof measurements. For heavy oils, characterizingviscosity behavior is especially important, sinceeven small changes can have large effects onproduction rates and recoverable oil volumes. Insome heavy-oil reservoirs, the apparent viscosityof the oil may change as the oil mixes with gas orwater. Gas that evolves from heavy oil duringproduction can form a foam. Mixing heavy oilwith water can create an emulsion. The resultingviscosities are markedly different from that ofthe heavy oil alone.

Some heavy-oil recovery techniques call forinjection of steam, gas or viscosity-reducingsolvents, such as naphtha, for assistingproduction or artificial lift. To confirm theviability of these recovery techniques, laboratorymeasurements quantify the changes in bubble -point, density, compressibility, composi tion andnumber of liquid hydrocarbon phases caused bythe addition of gases and solvents. The additionof gases and solvents can further modify heavy-oilproperties by causing precipitation of asphaltenes.

To avoid unwanted changes in viscosity andthe precipitation of solids, laboratory measure -ments monitor rheology and solubility changeson live oil with changes in pressure andtemperature. Solids screening by titration withpotential diluents or injection gases looks for the concentration at which asphalteneprecipitation may be induced for a giventemperature or pressure.

46 Oilfield Review

29. Alboudwarej H, Beck J, Svrcek WY, Yarranton HW andAkbarzedeh K: “Sensitivity of Asphaltene Properties toSeparation Techniques,” Energy & Fuels 16, no. 2 (2002):462–469.

30. “Asphaltene Deposition and Its Control,” http://tigger.uic.edu/~mansoori/Asphaltene.Deposition.and.Its.Control_html (accessed June 26, 2006).

31. De Boer RB, Leerlooyer K, Eigner MRP and van Bergen ARD: “Screening of Crude Oils for AsphaltPrecipitation: Theory, Practice, and the Selection ofInhibitors,” paper SPE 24987, presented at the SPEEuropean Petroleum Conference, Cannes, France,November 16–18, 1992; also in SPE Production &Facilities 10, no. 1 (February 1995): 55–61.

32. Villalanti DC, Raia JC and Maynard JB: “High-Temperature Simulated Distillation Applications inPetroleum Characterization,” in Meyers RA (ed):Encyclopedia of Analytical Chemistry. Chichester,England: John Wiley & Sons Ltd. (2000): 6726–6741.http://home.earthlink.net/~villalanti/HTSD.pdf (accessedMay 25, 2006).

> Correlation between API gravity and resin and asphaltene content from SARA analysis (bottom).The heavier the oil, the greater the content of resin and asphaltene. In the photograph (top), the flaskcontains the heated heavy-oil sample. The standing tube contains resin, the Petri dish containsasphaltene, and the other tubes contain saturates and aromatics. (Data taken from Table 1 inreference 30.)

API gravity

Com

posit

ion,

% b

y wei

ght

0 10 20 30 40 50

25

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5

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ResinAsphaltene

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A fluid property of particular interest inheavy-oil reservoirs is bubblepoint pressure—the pressure at which dissolved gas comes out ofsolution. In the laboratory, bubblepoint istraditionally determined by depressurizing asample in what is called a constant compositionexpansion (CCE) test. The bubblepoint is thepressure at which a large increase in samplevolume occurs.

The traditional CCE method does not givereliable bubblepoint measurements for heavyoils. To obtain the true bubblepoint when thetraditional CCE method fails, SRFC analysts usea CCE test designed for heavy oils (above). Thetrue bubblepoint is obtained by allowing time forthe gas to separate slowly from the oil and bycontrolled mixing of the fluid. Performing the

test in the short time allowed for conventionaloils can result in a bubblepoint that is hundredsof psi lower than the true value.

Similarly, procedures developed for measur -ing viscosity of conventional oils can lead to largeerrors when applied to viscous oil. Rheometers orhigh-pressure capillary viscometers with accu -rate temperature control are capable ofobtaining viscosity values with a measurementerror on the order of 5% (above right).

As mentioned earlier, the quality of datadepends on obtaining representative samples ofthe reservoir fluids. In some cases, it is difficult toobtain representative bottomhole and wellheadsamples for some of the fluids of interest.Therefore, a procedure was developed to generaterecombined heavy-oil samples from liquid samples

collected at the surface (above). As with thebubblepoint measure ment, recombination mustallow time for the gas to diffuse and become fullydissolved in the heavy oil.

> A PVT-analysis apparatus at SRFC, used to measure bubblepoint pressureby depressurizing a sample in a constant composition expansion (CCE) test.The bubblepoint is the pressure at which the sample volume increasessignificantly. A CCE test that mixes the heavy-oil sample yields a bubblepointthat matches ideal calculations, while the traditional CCE method produces abubblepoint that is too low.

>Measuring viscous-oil viscocity with a rheometer.Rheometers measure changes in viscosity withvariation in flow rate. This is important for character-izing viscous oils that exhibit non-Newtonianbehavior, meaning their viscosity is a function ofshear rate.

> Sample-recombination equipment at SRFC forobtaining representative fluid samples from fluidsextracted at the wellhead.

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To test the effectiveness of the fluid-recombination technique, the fluid derived fromthe recombination procedure can be testedagainst wellhead samples for bubblepoint andviscosity. When PVT and viscosity measurementson recombined fluids give comparable results tothe wellhead samples, engineers are able togenerate an accurate field-specific model forpredicting the properties of the heavy oil.

In one case, an oil company was concernedabout the presence of emulsified water in someSouth American live heavy oils.33 Most heavy oilsare produced along with water, whether thewater occurs naturally in the reservoir or hasbeen injected in the form of water or steam.During the production process, shear forcesstemming from high flow rate through pumps orflow constrictions may be great enough to causethe water to become emulsified in the heavy oil,leading to a rise in viscosity. This, in turn, willaffect the efficiency of artificial lift, dramaticallyincrease the energy required to transport theheavy oils and, in some cases, impact the choiceof production equipment.

The viscosity and stability of oil-wateremulsions depend on water cut and on whichphase is continuous. The viscosity of oil-continuous, or water-in-oil, emulsions mayincrease by more than an order of magnitude overthe dry-oil viscosity. The viscosity of a water-in-oilemulsion increases with water cut up to theemulsion inversion point, beyond which thecontinuous phase changes to water, producing anoil-in-water emulsion. In oil-in-water emulsions,viscosity decreases with water cut.

Characterizing the stability and viscosity ofthe South American heavy-oil emulsion requireddevelopment of new experimental techniques atSRFC. Most experimental work on emulsions isperformed on stock-tank oil samples. However,live oils contain dissolved gases that may affectthe viscosity of the oil and emulsion. SRFCengineers developed a technique to generateemulsions in live oils by recombining stock-tankoil samples with gas to create a live oil. The liveoil was then blended with water at various watercuts in a high-pressure, high-temperature(HPHT) shear cell. The shear cell generatedemulsions with an average droplet size of 2 to 5microns. Visual inspection and drop-size analysisconfirmed that the live-oil emulsions remainedrelatively stable up to the inversion point.

The apparent viscosity of the resultingemulsions was measured at two pressures usingan HPHT capillary viscometer (top right). Theviscosity of the emulsified live heavy oil is clearlyhigher than the water-free heavy oil, up to five

times greater at 50% volume water cut. The lowerviscosity at 60% volume water cut indicates aninversion point, where the system convertedfrom a water-in-oil emulsion at or below 50% toan oil-in-water emulsion at 60% volume. Themaximum live-oil viscosity in the system occurs,as expected, just prior to the inversion point.Similar to water-free heavy-oil systems, theemulsion viscosity is reduced by an increase intemperature or by an increase in the amount ofsaturated gas. Clients can use these results todetermine pump sizes, estimate the energyrequired to pump fluids from the reservoir tosurface facilities, and design surface separators.

Drillstem Testing in Heavy-Oil ReservoirsTo confirm the economic potential of a discoverywell, companies perform drillstem tests (DSTs).DSTs provide short-term production to estimatereservoir deliverability, and also to characterizepermeability, completion damage and reservoirheterogeneities under dynamic conditions.Drillstem testing typically involves producing awell with a temporary completion, recordingpressure, temperature and multiphase flow rates,and acquiring representative fluid samples.

Drillstem testing is especially challenging inreservoirs with high fluid viscosity, low reservoirstrength and the presence of emulsions. To

48 Oilfield Review

> Surface equipment for testing a heavy-oil well in Brazil. By including the PhaseTester Vx multiphasewell testing technology, accurate three-phase flow measurements are possible. In conventionalsystems, flow is measured only after being separated by the separator. The orange line representsthree-phase flow, with oil, water and gas. The separator outputs three individual phases.

Chokemanifold Steam exchanger PhaseTester Vx 29 Separator 1440

Burner and flareSurge

tank

> The apparent viscosity of oil-water emulsions created by samplerecombination, measured at two pressures and temperatures using anHPHT capillary viscometer. The viscosity of the emulsified live heavy oilincreases with water cut. At 50% volume water cut, viscosity reaches up tofive times its water-free value. The system converted from a water-in-oilemulsion at or below 50% volume to an oil-in-water emulsion at 60% volume.

100 psia, 40°F100 psia, 70°F2,000 psia, 40°F2,000 psia, 70°F

Visc

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, mPa

.s

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overcome these challenges, Schlumbergerengineers devised and implemented a testingscheme that integrates high-resolution pressureand temperature sensors for monitoring fluidphase behavior, ESPs for fluid lifting, multiphaseflowmeters for flow-rate measurements andseparators for phase separation and sampling.Test efficiency has been enhanced by real-timedata transmission, allowing faster and betterdecision making.

Using this combination of hardware and bestpractices, Schlumberger engineers haveperformed DSTs in more than 20 heavy-oilexploration wells offshore Brazil, with successesin extraheavy oil of 9°API and viscosity as high as4,000 cP [4 Pa.s].

In one case, Devon Energy wanted tocharacterize a heavy-oil reservoir in the Macaéformation, a loosely consolidated carbonategrainstone in the Campos basin offshore Brazil.The Macaé formation was a potential candidatefor acid stimulation, but core analysis indicatedthat deconsolidation following acid stimulationcould lead to borehole instability.34 The variablepermeability, with higher values in the upperportion of the completion interval—in somezones exceeding 1 darcy—could make it difficultto adequately divert acid throughout the entirecompletion interval. The heavy crude oil of 17 to21°API, with viscosity ranging from 50 to 90 cP[0.05 to 0.09 Pa.s], also raised concerns aboutcompatibility with stimulation fluids. The wellwas perforated, and then, to ensure optimal fluidplacement, was stimulated with VDA ViscoelasticDiverting Acid.35 The acidizing results werepositive and the well exhibited good diversionand cleanup after treatment.

Following acid treatment, the well was testedusing Schlumberger heavy-oil DST bestpractices. This included real-time monitoringand PhaseTester portable multiphase periodicwell testing equipment (previous page, bottom).The compact PhaseTester system combines aventuri mass-flow measurement withmeasurements of dual-energy gamma rayattenuation and fluid pressure and temperatureto calculate gas, oil and water fractions.36

PhaseTester oil flow-rate results have proved tobe more accurate and more stable than flow-ratemeasurements made by traditional phaseseparators (top right).

Increased accuracy and stability result inmore confident interpretation of DST data. Inthis Devon well, interpretation of pressure-transient data from the test separator results ina discrepancy between modeled and observedpressures and derivatives (bottom right).However, interpretation of the PhaseTester

> PhaseTester oil flow-rate measurements (blue) for Devon Energy in Brazil, showing more stabilitythan flow-rate measurements made by traditional phase separators (red). Flow rates are in barrelsper day at stock-tank conditions.

Liqu

id fl

ow ra

te, b

bl/d

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0 24 48 72 96 120Time, h

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1stbuildup

Variousrates

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PhaseTester dataSeparator data

33. Alboudwarej H, Muhammad M, Dubey S, Vreengoor Land Saleh J: “Rheology of Heavy-Oil Emulsions,” paper SPE/PS-CIM/CHOA 97886, presented at the SPE International Thermal Operations and Heavy OilSymposium, Calgary, November 1–3, 2005.

34. Lungwitz BR, Hathcock RL, Koerner KR, Byrd DM,Gresko MJ, Skopec RA, Martin JW, Fredd CN andCavazzoli GD: “Optimization of Acid Stimulation for aLoosely Consolidated Brazilian Carbonate Formation—Multidisciplinary Laboratory Assessment and FieldImplementation,” paper SPE 98357, presented at the SPE International Symposium and Exhibition onFormation Damage and Control, Lafayette, Louisiana,USA, February 15–17, 2006.

35. Al-Anzi E, Al-Mutwa M, Al-Habib N, Al-Mumen, Nasr-El-Din H, Alvarado O, Brady M, Davies S, Fredd C,Fu D, Lungwitz B, Chang F, Huidobro E, Jemmali M,Samuel M and Sandhu D: “Positive Reactions inCarbonate Reservoir Stimulation,” Oilfield Review 15, no. 4 (Winter 2003/2004): 28–45.Lungwitz et al, reference 34.

36. Atkinson I, Theuveny B, Berard M, Conort G, Lowe T,McDiarmid A, Mehdizadeh P, Pinguet B, Smith G andWilliamson KJ: “A New Horizon in Multiphase FlowMeasurement,” Oilfield Review 16, no. 4 (Winter2004/2005): 52–63.

> Interpretation of pressure-transient data using production rates from theseparator. The well-test history plot (top) shows discrepancies betweenobserved pressures (green) and the modeled curve (red). In the log-logdiagnostic plot (bottom) of the pressure and its derivative for the secondbuildup period (blue) and the third buildup period (red), the modeled curvesfor the pressure (solid curves) and the derivative (dashed curves) showlarge differences from the observed data.

Buildup 1 Buildup 22,900

2,500

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sure

, psi

a

3/12/2005 3/13/2005 3/14/2005 3/15/2005 3/16/2005 3/17/2005Date

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rent

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ress

ure

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pressure-transient data results in a good matchbetween observed and modeled pressures andderivatives (left). The models underlying the twointerpretations have permeabilities that differ by16%. The permeability inferred from thePhaseTester data also agrees well with perme -ability from scaled-up core measurements.

Constructing and Completing Heavy-Oil WellsWells in heavy-oil reservoirs present a variety ofwell-construction and completion complexities.These include drilling stable boreholes in weakformations, accurately landing horizontal wells,designing tubular systems and durable cementsfor wells that undergo temperature extremes, andinstalling sand-control, completion and artificiallift equipment that must operate efficiently underthe harshest conditions. All these operationsbenefit from an integrated engineering approachthat can draw on global experience to providesolutions to new heavy-oil problems.

Wells that experience extreme variations intemperature, such as in CSS and SAGD projects,require specialized, high-performance comple -tion equipment. High temperatures and tempera -ture variation can cause common elasto mers tofail. This results in broken seals, allowingpressure and fluids to escape up the casing,increasing the potential for casing corrosion andreducing effectiveness of steam injection.

Recently, Schlumberger engineers developednonelastomeric systems capable of operating atcycled temperatures up to 650°F [343°C] andpressures up to 21 MPa [3,046 psi]. Thesesystems maintain pressure integrity whileallowing deployment of reservoir monitoring andcontrol equipment (left).

Schlumberger high-temperature thermalliner hangers have been used in the Cold Lakefield, where a major operator in Canada has beenpiloting a horizontal-well CSS program.37 Withcustomized liners and pressure-tight seals at thetop of the liner, the operator has been able toachieve good steam conformance—steam intakespread evenly over the length of the horizontalwell—verified by time-lapse seismic surveys overthe pilot area.

SAGD wells also need downhole equipmentwith high temperature ratings. These wellsrequire high build rates, proximity controlbetween injector and producer, flexible cement,sand control, and liner hangers, packers andartificial lift equipment capable of operating attemperatures that may exceed 280°C [536°F].

50 Oilfield Review

37. Smith RJ and Perepelecta KR: “Steam ConformanceAlong Horizontal Wells at Cold Lake,” paper SPE/PS-CIM/CHOA 79009, presented at the SPE InternationalThermal Operations and Heavy Oil Symposium andInternational Horizontal Well Technology Conference,Calgary, November 4–7, 2002.

38. Curtis C, Kopper R, Decoster E, Guzmán-Garcia A,Huggins C, Knauer L, Minner M, Kupsch N, Linares LM,Rough H and Waite M: “Heavy-Oil Reservoirs,” OilfieldReview 14, no. 3 (Autumn 2002): 30–51.

39. Krawchuk P, Beshry MA, Brown GA and Brough B:“Predicting the Flow Distribution on Total E&P Canada’sJoslyn Project Horizontal SAGD Producing Wells UsingPermanently Installed Fiber Optic Monitoring,” paperSPE 102159, prepared for presentation at the SPE AnnualTechnical Conference and Exhibition, San Antonio,Texas, September 24–27, 2006.

> A proposed completion for a horizontal CSS or SAGD well. Thermal liner hangers provide pressure-tight seals to increase effectiveness of steam injection. The REDA Hotline 550 artificial lift systemoperates continuously at up to 550°F internal motor temperature. Distributed temperature sensing(DTS) systems monitor temperature changes during steam injection and oil production.

Artificial liftCompletion equipment,liner packers and tools

Reservoir monitoringand control

Productiontubing

> Interpretation of pressure-transient data using production rates from thePhaseTester system. The well-test history plot (top) shows a good matchbetween observed pressures (green) and the modeled curve (red). In thelog-log diagnostic plot (bottom) of the pressure and its derivative for thesecond buildup period (blue) and the third buildup period (red), the modeledcurves for the pressure (solid curves) and the derivative (dashed curves)show good matches with the observed data.

2,900

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Steam generation is approximately 75% of theoperating expense of a SAGD well. Reducing thesteam/oil ratio (SOR) while maintainingproduction rate is key to improving operationprofitability (right). Reducing steam input savesenergy costs, decreases produced-water volumeand treatment expenses and cuts down on CO2 emissions.

An important component in the effort toreduce SOR is the REDA Hotline 550 high-temperature electrical submersible pumpsystem, rated to run continuously at up to 550°F[288°C] internal motor temperature, or 420°F[216°C] bottomhole temperature. Its high-temperature thermoplastic motor-windinginsulation was initially developed and patentedfor geothermal and steamflood wells. Thecomplete system is designed to compensate forvariable expansion and contraction rates of thedifferent materials used in the pump design.

Use of an ESP allows the reservoir to beproduced at a pressure that is independent ofwellhead pressure or separator pressure,increasing the quality of steam that can beinjected. This can decrease the SOR by 10 to 25%,saving about US$ 1.00 per barrel of oil produced. Inaddition, the Hotline 550 ESP has excellentreliability statistics; the longest running instal -lation has been operating for 844 days. The Hotline550 ESP is used by a number of Canadian operators,including Encana, Suncor, ConocoPhillips, Nexen,Total, Husky and Blackrock.

Monitoring Heavy-Oil RecoveryUnderstanding fluid flow in heavy-oil reservoirsis important for optimizing recovery methods,especially when heat is required to reduceviscosity and mobilize fluids. Several techniqueshave been developed, including distributedtemperature sensing (DTS) systems, permanentpressure gauges, crosswell seismic and electro -magnetic surveys, microseismic techniques andtime-lapse seismic monitoring.38

In 2004, Total E&P Canada installed an optical-fiber DTS system along a pilot SAGD productionwell to monitor temperature during productionstartup in the Joslyn field in Alberta, Canada.39 Thereservoir produces from the McMurray formation,which is mined for bitumen in the eastern part ofthe lease. In the western part, bitumen in the 50-minterval is heated by injection of steam andpumped to surface.

Correlating temperature change with viscosityand flow rate, especially when the injector-producer region is first warming up, helpsreservoir engineers modify steam injection toensure that enough heat reaches the entireintrawell region. In addition to the fiber-optictemperature-sensing system in the producing

well, the pilot project included three observationwells that penetrated the injector-producerregion within 1 to 2 m [3 to 7 ft] of the SAGDwells (above). Observation-well temperaturemeasurements were recorded by thermocouplesover a 45-m [148-ft] interval.

> Decreasing the steam/oil ratio (SOR) while maintaining or building production rate. Reducing theSOR decreases the energy required to heat heavy oil, lowers the volume of water produced and also reduces water-treatment expenses. [Data are from Encana Investor Day, November 7, 2005http://events.onlinebroadcasting.com/encana/110705/pdfs/oilsands.pdf (accessed July 28, 2006.)]

Steam/oil ratioProduction rate

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Date

> Total E&P Canada SAGD pilot project, with producer-injector SAGD pair of horizontal wells and threemonitor wells to record temperatures in the injector-producer region.

ProducerWell

SteamInjector Well

Monitor WellOB1AA

Monitor WellOB1B

Monitor WellOB1C

Guide string Injectiontubing

Slottedliner

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Guide string

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hangerLiner

Instrument string

Slottedliner

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To initiate the SAGD process, steam wasinjected into both wells for several months toreduce bitumen viscosity. In September 2004, apump and DTS instrumentation string wereplaced in the producer, and production beganwhile steam injection continued in the injectorwith a bias toward the toe. DTS data acquiredfrom October through December show a generalwarming of the injector-producer region, but onezone near the heel of the well did not follow thetrend (right).

In January 2005, the pump was replaced withan ESP. During the workover, steam injectionhalted and the DTS string was temporarilyremoved. A liner was also installed, and the DTSstring was reinserted. Then steam injectionresumed, concentrating on the heel of theinjector. The new DTS data reveal rewarming ofthe injector-producer region (below right).

Closer inspection of the DTS data acquiredafter the workover shows an unexpectedoscillation of up to 20C° [36F°] (next page, top).In comparison, DTS data prior to the workovershow little such fluctuation. It is believed thatthe temperature oscillation in the postworkoverdata is caused by spiraling of the coiled tubingstring that contains the DTS instrumentation.Before workover, the DTS string was probablylying along the bottom of the slotted liner.However, during workover, the string wasreinserted, and buckled inside the slotted liner.

The observed temperature oscillationcorresponds to temperature values seen at thetop and bottom of the producing well. The heatedbitumen is up to 20C° hotter along the top of thehorizontal producer than at the bottom. Theobservation-well temperature data acquired inWell OB1C before and after the workover alsoindicate that a significant temperature gradientcan exist across the cross section of theproducing well (next page, bottom). Interpretingtempera ture data therefore requires knowledgeof the position of the temperature sensors in thewellbore. The continuous set of measurementsprovided by DTS instrumentation helped clarifythe well’s performance.

52 Oilfield Review

40. Belani A: “It’s Time for an Industry Initiative on HeavyOil,” Journal of Petroleum Technology 58, no. 6 (June 2006): 40, 42.

41. Alberta Chamber of Resources, reference 4.

42. Freed DE, Burcaw L and Song Y-Q: “Scaling Laws forDiffusion Coefficients in Mixtures of Alkanes,” PhysicalReview Letters 94, no. 6 (February 17, 2005): 067602.Freed DE, Lisitza NV, Sen P and Song Y-Q: “MolecularComposition and Dynamics of Diffusion Measurements,”in Mullins OC, Sheu EY, Hammami A and Marshall AG(eds): Asphaltenes, Heavy Oils and Petroleomics.New York City: Springer (in press).

43. Mullins OC: “Petroleomics and Structure-FunctionRelations of Crude Oils and Asphaltenes,” in Mullins OC,Sheu EY, Hammami A and Marshall AG (eds): Asphaltenes,Heavy Oils and Petroleomics. New York City: Springer (in press).

> DTS data acquired after the workover, showing rewarming of the injector-producer region.

03/31/2005 18:39

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> DTS data acquired for three months starting in October 2004, showing warming ofthe injector-producer region. Depth increases from the heel to the toe. One zone nearthe heel of the well did not warm as much as the rest of the intrawell region.

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Moving Ahead in Heavy Oil With heavy-oil reserves so abundant, companiesthat currently concentrate on production ofconventional oils are entering the heavy-oil arena,joining companies that have produced heavy oilfor decades.40 These newcomers may bring newtechnologies, helping to fill technology gaps thathave been identified by long-time producers andother organizations. For example, the AlbertaChamber of Resources has compiled a list ofadvances necessary to allow production from oil

sands to reach 5 million bbl/d [800,000 m3/d], or16% of North American demand by 2030.41

Achieving this vision will require investment intechnology improvements for mining, in-siturecovery methods and upgrading.

For every advance made toward enhancingheavy-oil recovery methods, numerous newavenues point to directions needing more work.In the area of fluid characterization, scientistsare trying to extract more information about oilchemistry and component structure from logging

and laboratory measurements. For example,progress is being made in linking NMR diffusiondistributions with molecular chain lengths ofcrude oils.42 Researchers are working to addfluorescence measurements to current downholefluid-analysis practices based on spectrometry,allowing more accurate fluid characterizationand acquisition of continuous downhole fluidlogs. Efforts are being made to standardizelaboratory techniques, such as SARA analysis, sothat results from different laboratories may becompared. Advances in understanding crude-oil’sheaviest components—asphaltenes—have thepotential to not only improve heavy-oil recovery,but also help solve flow-assurance problems inlighter oils.43

Heavy-oil experts agree that there is nouniversal solution for evaluation and recovery ofheavy oil. Some improvements, such as in loginterpretation, may need to be customized for aparticular region. In other cases—for example,the development of new materials that raise theoperating temperatures of downhole completionequipment—successes may have widespreadapplication. Still other developments, includingadvances in real-time monitoring, may comefrom the combination of methods already proveneffective separately.

Another point of agreement is the need tocontinue to factor environmental concerns intothe development of heavy-oil resources. Inbitumen mining and current in-situ recoveryprojects, environmental and cultural consider a -tions form important parts of the business model,including reclamation of mined areas, mineralrecovery to make use of waste materials,minimization of water usage, issues related toindigenous peoples and reduction of greenhouse-gas emissions. New projects will have to besensitive to these and other factors, includingCO2 emissions, preservation of permafrost andother fragile ecosystems and reduction of theenergy expended to heat heavy oil.

If heavy-oil reservoirs have one advantageover their lighter counterparts, it is theirlongevity. Heavy-oil fields can produce for100 years or more, as do the ones discovered inCalifornia in the late 1800s. By some estimates,the oil sands in Canada can produce for severalhundred years. Investments made now will payoff long into the future. —LS

> Temperature data recorded in an observation well, showing the hightemperature at the level of the injector and the large temperature gradientat the level of the producer.

Elev

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December 29, 2004March 20, 2005

> Close-up of DTS data acquired after the workover, showing an high-frequency oscilation of up to 20C° (red curve). In comparison, DTS datafrom before the workover are much smoother (blue curve). The temperatureoscillation in the data acquired after the workover is caused by spiraling ofthe DTS instrumentation. The temperature oscillation represents thedifference in temperature between the top and bottom of the borehole.

Linerinstalled

in January2005

February2005 spiraltubing effect

February2005 top ofwell flowingtemperature

October 2004bottom of well

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