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Development of Heavy-Oil ReservoirsPeter J. Briggs, SPE British Petroleum Co. Ltd.R. Paul Baron, SPE, BP Exploration Co. Ltd.Richard J. Fulleylove, BP Exploration Co. Ltd.Mervyn S. Wright, BP Exploration Co. Ltd.

Summary. Although complex categorizations are in vogue, "heavy oils" can be defined simply in terms of their flow propertiesin the reservoir-e.g., a lOO-cp [l00-mPa's] or greater viscosity. Such heavy oils are a major world hydrocarbon resource that isexploited where indigenous demand exists. Efficient methods of production require enthalpy input to the reservoir by hot-fluidinjection or by creation of heat in the reservoir. Heat losses must be minimized to achieve maximum production efficiency.The widely used cyclic-stearn-injection process is examined analytically to indicate which parameters govern successfulexploitation. Steamflood and in-situ combustion techniques are discussed with reference to recent developments. Heavy-oil recoveryfrom the more difficult carbonate reservoirs, such as those of the Middle East, is reviewed and potential production mechanismsare examined. Production techniques are described together with export handling schemes.IntroductionHeavy-oil recovery is traditionally thought of as thermal stimulation of low-API-gravity oil , which may range from 4 to 20 API[1.04 to 0.93 g/cm 3 ]. Heavy oil is defined 1 as having an APIgravity of 0.93 g/cm3 ]. Standard practice in the U.S.also uses this gravity definition. 2 The API gravity, however, doesnot fully describe the flow properties of the crude; this is betterrepresented by the oil viscosity. 3 For instance, some crudes maybe heavy (low gravity) but have a relatively low viscosity at reservoir temperature compared with some lighter crudes (Table 1).The oil viscosity and its response to increased temperature control the flow rate under thermal stimulation, and because the flowrate is a much more important factor in the economic exploitationof the reserve than the oil gravity, it is proposed that heavy oilsi.e., those requiring stimulation by heat or by other means-be defined as crudes having viscosities> 100 cp [> 100 mPa' s] at reservoir conditions. Normally, pumped cold-oil production rates willbe less than 10 BID [1.6 m3 /d] when the oil viscosity exceeds 100cp [100 mPas].The term "bitumen" is used interchangeably with heavy oil,although its use does tend to signify the heavier end of the heavyoil spectrum. The United Nations Inst. for Training and Research 3proposes that bitumen be defined as having a viscosity > 104 cp[> 104 mPa's] and an API gravity < 10 [> 1 g/cm3 ]. Anotherdefinition of bitumen4 is a naturally occurring viscous mixture consisting mainly of hydrocarbons heavier than pentane that may contain sulfur compounds and that, in its naturally occurring viscousstate, is not recoverable at an economical rate through a well. Theterm "tar sand" is often applied to such deposits found in the Canadian Athabasca sands, which are shallower and accessible by mining. Heavy oil in this paper refers only to those deposits that haveto be exploited in situ and that will normally be located at depthsranging between 1,000 and 4,000 ft [300 and 1200 m].In common with tar-sand oil, heavy oils frequently have highasphaltene, sulfur, and metal contents compared with conventional oils. The nonhydrocarbon content tends to increase with decreasing API gravity, which, in combination with decreasing quantitiesof lighter ends, reduces the market value of the crude. Table 2 compares typical heavy-oil properties with conventional oil.Main Locations of World Heavy OilWe have estimated the total discovered heavy oil in place in theworld to be 4,600 X 10 9 bbl [730 X 10 9 m3 ]. This should be compared with our estimate of remaining proved and probable conventional oil reserves as of Jan. 1, 1986, of some 700 x 10 9 bbl[l1Ox 10 9 m3 ]. As can be seen, an average heavy-oil recovery

Copyright 1988 Society of Petroleum Engineers

206

factor of 15 %would be required to equate heavy-oil reserves withthe remaining conventional reserves. The total world consumptionof oil as of Jan. 1, 1986, was about 537 X 10 9 bbl [85 X 10 9 m3],which shows that the heavy-oil resources are important long-tennsupplies of petroleum.The main known heavy-oil deposits are summarized in Table 3.The largest heavy-oil deposits are located in Canada, Venezuela,and the Soviet Union and represent over 90%of the known heavyoil in place in the world. Of these deposits, sandstone reservoirsare estimated to contain 3,000 X 109 bbl [480 X lO 9 m3], with theremaining 1,600 X 109 bbl [250 X 109 m3 ] contained in carbonatereservoirs. Table 4 shows the distribution of the 1985 world production by thermal techniques, which averaged 923,000 BID[147x103 m3 /d].In the past, economics have dictated that a high oil price is necessary before heavy-oil production becomes attractive on a largescale. In many areas of the world, however, conventional oil reservoirs are becoming increasingly marginal as the giant fields remaining to be discovered become fewer and the exploration risks foroffshore fields and their development costs become large. Thereare risks associated with developing offshore fields because veryfew early appraisal data can be collected and no long-term well performance observations are possible. In most cases, pressure maintenance will be required from the outset and has to be based ontheoretical estimates and not pilot results. Thus, these conventional oil prospects require front-end capital, the majority of which isat risk should the project fail. In addition, the uncertainty of futureoil prices and the currently perceived low-price scenarios reducethe estimate of potential reward. In contrast, large quantities of heavyoil have already been discovered; therefore, no exploration costis required. In addition, these discoveries awaiting development aremainly onshore and are at shallow depth. Development wells arelow cost and the capital expenditure (capex) profile is continuousthroughout the project, rather than being front-end loaded. Suchthermal processes as cyclic steam injection are well understood,and the technical and geologic risks are therefore small. These advantages, even though the heavy-oil price will be discounted, allow potential heavy-oil production to compare favorably with manyhigh-risk conventional oil plays. Typical predicted cash-flow profiles for a marginal North Sea development and a heavy-oil development are compared in Fig. 1. Table 5 summarizes the resourceand development economics of the two fields.Carbonate reservoirs also contain large quantities of heavy oil,but the technology and experience of producing such heavy-oil reservoirs are not well developed. Nevertheless, they are important development targets. The potential production mechanisms that maytake place during the thermal stimulation of these reservoirs arediscussed later.

Journal of Petroleum Technology, February 1988

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TABLE 1-TYPICAL HEAVY-OIL VISCOSITIESAND GRAVITIESGravity Reservoir ViscosityField Location (OAPI) (cp)

Bachaquero Venezuela 13 150Emlichheim Germany 24.5 175Lost Hills California 14 400Cold Lake Canada 10 to 12 10,000 to 100,000

TABLE 2-COMPARISON OF CONVENTIONAL CRUDE AND HEAVY OILAttribute Athabasca

Gravity, APIHydrocarbon type, %SaturatesAromaticsAsphaltenesResinsSulfur, %Metals, ppmVanadiumNickelReservoir oil viscosity, cp

TABLE 3-MAIN KNOWN HEAVY-OIL RESOURCES

CountryCanadaVenezuelaUSSRUSAIraqIranSyriaChinaEcuadorTrinidad and TobagoColombia

OIP(10 9 bbl)1,8601,2001,2005534201410753

7 to 818 to 232917354.7

500,000

In estimating the heavy oil in place, we used the viscosity criterionwhere these measurements were available, and when not, we useda 20 0 API [O.93-g/cm 3] limit. The viscosity threshold of 100 cp[100 mPa s] is somewhat arbitrary, and unstimulated wells withhigh net pay thickness, high drawdown, or high formation perme-ability can produce at commercial rates with oil viscosities this high.

300250200

-150

-200

-250

__ Marginal North SeaDevelopment_

Typical Heavy OilDevelopment

YEAR

Fig. 1-Posttax cash flow for North Sea marginal field andheavy-oil project .Journal of Petroleum Technology, February 1988

Conventional Crude,Cold Lake Alberta10 to 12 35

21 70 to 901916 0.1 to 244 9 to 154.5 0.1 to 21 to 5250 1 to 5100 1 to 5100,000 1

TABLE 4-1985 PRODUCTION BY THERMAL TECHNIQUES

CountryUSACanadaVenezuelaUSSRTrinidad and TobagoIndonesia

Production Rate(10 3 BID)

Italy, Turkey, China, Syria, The Netherlands

364601661207040103Total 923

In the majority of cases, however, heating of the oil to reduce vis-cosity, thereby stimulating flow rate, will be necessary for oils hav-ing viscosities >100 cp [>100 mPas].Thermal Recovery TechniquesAll thermal recovery processes reduce the reservoir flow resistanceby reducing the viscosity of the crude. 5 There are basically twotypes of processes. The first injects heat into the reservoir, and thesecond generates the heat in situ. The processes can be further clas-sified into thermal drive or stimulation. The following sectionsdescribe these thermal recovery processes, with the most empha-sis given to cyclic steam injection, which historically has been themost widely used and successful method.

TABLE 5-COMPARATIVE PROJECT COSTS

Total recovery, 10 6 STBPlateau rate, 10 3 BIDInitial capex, U.S. $1 millionAnnual capex, U.S. $1 millionAnnual opex, U.S. $1 millionCost of oil, $/bbl1986 oil price, $/bblMargin, $/bblNPVat 8%, U.S. $1 millionReal rate of return, %

MarginalNorth SeaDevelopment753069235151836012

TypicalHeavy-OilDevelopment6478519131314110026

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TABLE 6-INPUT DATA FOR FRACTURE:MODEL HISTORY MATCHGross thickness, ftNet-to-gross ratioPorosity, %Initial oil saturation, %Initial reservoir temperature, OFOil gravity, APIReservoir oil viscosity, cp

1120.6731.4645911.7156,000

Cyclic Steam Injection. The stimulation process that is usuallyachieved by steam soak was discovered somewhat accidentally in1959 in the Mene Grande field, Venezuela, when a steam-injectionwell was backflowed to relieve the reservoir pressure. 6 The wellflowed at rates of more than 100 BID [16 m3 /d) and had a lowwater cut compared with unstimulated wells, which had beenpumped at rates from 3 to 10 BID [0.5 to 1.6 m3 /d). This discovery led to the now-well-known cyclic steam or huff 'n ' puff process widely used in thermal recovery.

The effect of heating the reservoir on the stimulated oil production rate is complex. It is not only the reduction in oil viscositythat enhances the production rate, but also many other effects, suchas changes in surface tension, which is manifested by changes incapillary pressure, relative permeability, and wettability. Thesechanges result in an improvement in the fractional flow curve anda reduced residual oil saturation. Other effects are thermal expansion of oil, increased evolution of dissolved gas because of its decreased solubility at elevated temperatures, changes in oilcomposition through thermal cracking at temperatures above 650to 750F [340 to 400C], steam distillation, and flashing of waterto steam at low pressure.

The reservoir is heated by conduction and convection, with therelative contribution of each process depending mainly on the oilviscosity. When oil viscosity is so high that no primary oil flowis possible, then heating is by conduction and the oil in the stimulated area has to be raised above a certain mobilization temperature. Heating by conduction can be described by the standarddiffusivity equation:pC oTV 2T=-- . .................................... 1)A ot

Because the radial rate of heating by conduction will be extremelyslow, reservoirs are fractured to allow greater areal heat contact.The fracture, when full of steam, approximates a constanttemperature source in a semi-infinite solid at a uniform lower temperature, initially T=Tr at t=O. The solution to the diffusivityequation for these boundary conditions, giving temperature as afunction of time and distance x from the fracture, is 7

T(X,t)=Tst( l -er f ~ ) ' . . . . . . . . . . . . . . . . . . . . . . . . . .(2)When direct injection of steam is possible, then heating is mainlyby convection, and conductive heating is less important. In this case,the heat flux term on the left side of Eq. 1 has to be modified anda term included for each fluid:

_ oTvv jP jC j+VAVT=pC- . ........................ 3)otThe problem can be treated analytically by assuming that (1) heatis transferred to the reservoir only by convection, (2) heat is lost

to the overburden by conduction, and (3) oil in the heated zone willbe produced and oil saturation is reduced to residual.

The radius of the heated zone can be obtained from the relation 8

r=

208

5.6146Q,fjnjQi +BlastpCrh(Tst - Tr) ........................ 4)

50

040 Cycle 1 0Cycle 2 ";( 30 Cycle 3a:6 "- 0aa: 20C 00z Cycle 4() Actualto o Predicted

O ' ~ - - - - r - - - ~ - - - - - r - - - - ~ - - - ' - - - - - r - - - - 'o tOO 200 300 400 500 600 700CUMULATIVE PRODUCING TIME (DAYS)

Fig. 2-Fracture model match achieved fo r typical Cold Lakewell.

The temperature of the heated region can be obtained with theBoberg and Lantz9 equation. The oil produced during the production stage is given byrr2h

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90807080504030 Prediction (with pressure support)

2010 Prediction " " " I : ; ~ - \ : V " " ~ + ~ ~ ~ ..._..(without pressure support) - "o + - - - - - ~ ~ - - . _ - - - - . _ - - - - ~ L - - - r _ - - - - r _ - - _ .o 10 20 30 40 50 80 70

TlMEIDAYS)

Fig. 3-011 rate for the Midway-Sunset field compared withmodel predictions (one cycle).

Sufficient field history data were collected to perform comparisons with 18 wells, 6 of which produce by gravity drainage andthe remaining 12 by primary production.The model and actual results can be seen in Figs. 3 and 4 fora well in the Midway-Sunset8,12,13 gravity-drainage reservoir. Theeffect of the supplementary steam pressure drive can be seen bycomparing the predictions for no drawdown (only gravity drainage)with the 250-psi [1. 7-MPa] drawdown case. It can be seen in Fig.3 that the latter is a better match to the observed spiked productionprofile, showing that steam pressure drive is actually occurring inthe reservoirs examined. Fig. 4 shows the match achieved with datafrom the same well for seven consecutive cycles. Cumulative productions are matched to within 10% by the model, which is considered satisfactory and reliable for initial predictions ofperformanceof similar reservoirs.The original model has been modified to account for a component representing primary production. Fig. 5 shows the better matchto the Duri 14,15 data obtained when this primary depletion component is included.

From the analysis performed with the model, it has been foundthat cumulative production can be matched to within 10% by thegravity-drainage model, and its extension to include solution gasdrive matches the real data to within 12.5% accuracy. The modelis probably inappropriate to simulate other reservoir drive mechanisms, such as compaction drive and waterdrive. The importanceof the downhole injection parameters needs to be stressed, and acoupled wellbore heat-loss model with the gravity-drainage modelwould improve the accuracy of predictions.Measures ofCyclic Steam Efficiency. It is obvious that an economical energy balance must be attained during thermal recoveryprocesses. The main performance indicators for monitoring a cyclic steam process are given and explained below.

400350

300250wt;:

II: 200...Ja150tOO

50

............_--" ..... ReportedData" - ......, "" ", . ...............- ......,( e X C I U d i n g P ; ~ ~ ~ ~ ~ r o d U C . : : : t l o : n ) : - - - - - - - -

50 ~ ~ = _ 300 350 400 _ _TIMEIDAYS)

Fig. 5-Reported oil rate from the Ouri field compared withmodel predictions.Journal of Petroleum Technology, February 1988

50

40

" 30wt;:II:...J 20a10

- - - Reported Data........._- Prediction

a _ 300 400 _ _ _ B BTIME (DAYS)

Fig. 4-Match achieved with Midway-Sunset data over sevencycles.

Steam/Oil Ratio. The volume of water required to raise the injected steam divided by the volume of the resultant oil recoveredis the steam/oil ratio. Typically, steam/oil ratios above 6 bbl/STB[6 m3/stock-tank m3] are not economical, with projects approaching 2 bbllSTB [2 m 3 /stock-tank m3] becoming attractive. However, local fuel costs are important in determining the economics.

Producing Day Rate. The total oil produced from a cycle divided by the producing time of the cycle is the producing day rate.Calendar Day Rate. The total oil produced from a cycle dividedby the total cycle time, including injection, soak, and productiontimes, is the calendar day rate.Optimization of Cycle Cutoff and Abandonment Timing. Toperform reservoir simulations, criteria for the time of resteamingand abandonment are required. The timing of well resteaming isgoverned by economics, the objective of the operator being to maximize profit.Well performance depends on many parameters over which theoperator has no control, such as reservoir and fluid properties. Theoperator, however, can greatly influence the well performance, andhence project economics, by varying the production rate at whicha well is shut in for resteaming and the number of cycles to which

a well is subjected. Only one combination of these criteria will maximize the profit for a project.The cutoff time affects the average production rate for a well overits life. This in tum governs the number of wells operating to maintain maximum plant utilization efficiency and consequently the operating cost (opex). The cumulative production per well will also beaffected, thus influencing the total number of wells required andthe overall capital expenditure.Well performance in cyclic steam operations generally declinesfrom cycle to cycle. The decision to abandon a well must consider

6 180", . . - . ....-----------4 / 160

140:0.c 2'! Optimum 120!:: 0 Cut-off ~- Point 1000 -2 wII: !;;:"- 80--' a: -4 --'z 60 (5::E0 -6z 40-8 20-1 0 00 200 400 600 800 1000

TIME (DAYS)

Fig. 6 -Typical production and nominal profi t profiles for thefirst cycle.209

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16 OllPnce >

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Well Location~ Heated Channel

Fig. 9-Communication channels created at the Phase A pilot.

tion heterogeneities, low air injectivity, formation damage, scale,reduction of permeability, erosion, inability of lighter crude oil todeposit sufficient fuel for combustion, and production problemsrelating to corrosion, emulsions, sand, and gas locking in pumps.Thermal Recovery Operations at Marguerite(Wolf) LakeBP Resources Canada Ltd. is the operator of a pilot project usingcyclic steam and in-situ combustion at Marguerite Lake. More recently, the operation has extended to the Wolf Lake commercialcyclic-stearn-injection project on the lease. This paper discusses onlythe Phase A pilot at Marguerite Lake because it presents a muchmore advanced development than Wolf Lake, which is still in itsinitial cycles.The Marguerite Lake pilot was designed to test a combinationof cyclic steam injection followed by in-situ combustion. Theprimary objective of the pilot was to obtain information requiredfor a technical and economic appraisal of the recovery process leading to the commercial development of the lease. Steam was firstinjected into the wells in 1978. After the cyclic steam operation,in-situ combustion started first in the test area in 1979 and in themain pattern in 1983. The experience gained from early steaminjection operations in the Marguerite Lake leases since themid-1960s was used in the design of the pilot. The pilot area comprises two principal areas: a three-well wet-air-combustion test andan infill-drilled, four-5-spot-pattern, wet-oxygen-combustion areaoriginally on a 5-acre [2-ha] spacing.Fig. 8 shows the Marguerite Lake C unit bitumen viscosity asa function of temperature. The reservoir is initially at a temperature of 59F [15C] and has a viscosity in excess of 100,000 cp[100 Pa . s]. The bitumen is therefore immobile at initial reservoirconditions, and because of the difficulty of injecting steam into thereservoir, heat transfer is initially only by conduction. The experience from previous thermal recovery operations in the MargueriteLake area was that fractures have to be created to accelerate theconduction heating phase during the cyclic steam operation. On completion of the cyclic steam operation, communication channels areestablished between wells. These channels are mainly parallel (ontrend) to the fracture planes and have an average temperature of212F [l00C]; a few off-trend channels are also created. Fig. 9shows the heated zone and channels on the Phase A pilot at theend of the cyclic steam stimulation phase. It can be envisaged thatoil recovery is high where the steam has contacted the reservoir.Journal of Petroleum Technology, February 1988

-.L..... " j '( ' t ' ~ ; . . / _ - - - - - ~ ~ ' ( ~ 'IIIIIILIIIIII,..._-------L------- .

Cross-sectIonal area A

IIIIIIIIIIIII ! ~I . . -L /2 . . . . .1

Fig. 10-Model for fractured systems.

TABLE 7-DATA FOR TEMPERATURE-DISTRIBUTIONCALCULATIONDimension, L, of cube, ftInitial reservoir temperature, OfSteam temperature, OfVolumetric heat capacity of rock and fluids, BtuJft3_ofThermal conductivity, BtuJft-D_of

101005454025

Owing to the constraints of conductive heating, however, the volumeheated is small, resulting in a poor overall recovery of 20% OIP.At this stage, the conditions in the reservoir were suitable fora follow-up recovery process to be initiated. Reservoir heterogeneities, such as extensive fractures or channels, have been shown tohave a detrimental effect on the in-situ combustion process as normally applied. 16 BP has developed a variation on wet fireflood thatexploits the heated channel system remaining in the reservoir aftercyclic steam operations. The use of pure oxygen maximizes CO2production, which causes oil swelling as the CO 2 dissolves and solution gas drive as it later evolves. In addition, the combustion process is more thermally efficient and convective heat transfer to thereservoir is more important and effective than conduction heatingin the cyclic steam process.Heavy-Oil Recovery From Fractured CarbonateReservoirsApproximately one-third of the discovered heavy oil in the worldexists in carbonate reservoirs; however, the production experiencefrom such reservoirs is limited. In this section, the possible recovery processes are discussed and the results of numerical experiments that attempt to quantify these processes are presented.In the analysis performed, it was assumed that the reservoir consists of cubes of rock matrix with each cube surrounded by a communicating fracture system. This is the Warren and Root 17 modelfrequently used for analyzing fractured systems. Fig. 10 shows thatheat and fluid flow can be analyzed in a one-dimensional modelby taking a pyramidal volume element in which the cross-sectionalarea varies with distance from the matrix/fracture interface:A=(L-2x)2 . ..................................... (6)When steam in the fractures is held at a constant temperature,

T, and assuming conduction heating only, the spatial distributionof temperature at time t is expressed by the following differentialequation (diffusivity equation). This equation was solved numerically for the system given in Table 7.

1 a aT MaT- -A(x ) -=- - . .......................... (7)A(x) ax ax A atThe results are shown in Fig. 11, where temperature at varioustimes is plotted as a function of the distance, x, from the surface

211

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550

500

E 450wa::::>!;;: 400a:w0-::;;w 350r-300

~ ~ ~ ~ 7 ~ ~ = = ~ ~ - - - - - - - - - - ___________............... ------------------------ '"'-.--------

--- - 200ays--- 15Days-- 10DaysSOays

aDISTANCE FROM CUBE SURFACE (FT)

Fig. 11 -Temperature profile at different times.

TABLE 8-DATA FOR IMBIBITION EXPERIMENTRelative permeabilityCapillary pressurePermeability, mdOil viscosity at 100F, cpOil viscosity at 350o F, cp

Fig. 14Fig. 1456004.6

of the cube. With the concept of proximity functions, the temperature can be read (for a lO-ft [3-m] cube) from the figure at a pointx= 1.0316 ft [0.3144 m]. At this point, the volume of rock and fluidscontained between the cube's surface and 1.0313 ft [0.3143 m] isequal to the volume of rock and fluids contained between l.0313ft [0.3143 m] and the center of the cube. The rate of increase ofthese temperatures is shown in Fig. 12, which shows a rather rapidbuildup of temperature above the initial temperature of lOOF[38C]. Thus, it is shown that the temperature of the system canbe raised significantly in a reasonable time frame, stimulating oilflow from the matrix to the fracture system through lowering theoil viscosity as well as through thermal expansion. The reductionof oil viscosity has three effects: it increases the flow rate by expansion and solution gas drive, increases the rate of countercurrent imbibition (assuming water-wet conditions), and enhances therate of gravity drainage. Other effects have been identified that aidoil recovery from thermally stimulated fractured carbonatereservoirs.1. The hydrothermal reaction on the carbonate rock producesCO2 , This can result in rock dissolution, which in tum can enhance

to~ \ ~ O

50

0.8 40Z

\: P, UJ0.6 30 a::::>U)U) UJw \ / - a:::;; 0-a: >-w 0.4 20 a:Q.> 0:

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two temperatures: 75 and 350F [24 and 177C]. It was furtherassumed that the only effect of temperature was to alter the oil andwater viscosity; Le., thermal changes in relative permeability andcapillary pressure were ignored.The results can be seen in Fig. 14, which shows the recoveryof oil as percent OIP. The much faster imbibition at the higher temperature is clearly seen.Production Facility RequirementsWells. Injection well design and operating conditions are important in obtaining the efficient heat transfer to the reservoir. Thesteam quality, defined as the mass fraction of steam vapor in thesteam/water system, needs to be as high as possible because reduction in steam quality directly reduces the latent heat available. However, the production of steam of quality greater than 80% can causeexcessive boiler scale. The downhole steam quality is dependenton several well and injection factors: steam pressure and qualitydelivered at the wellhead, the steam injection rate, the well depth,and the well completion. Of these factors, the injection rate andthe well completion aspects are worth considering further. As discussed before, the steam injection rate will depend on the oil viscosity, and in the cases where the oil viscosity is above themobilization value, fracturing will be required not only for efficient heat transfer in the reservoir but also for minimizing heat losses.in the well by maintaining a high injection rate. In hot-fluid injection, it is important to reduce wellbore heat losses. This may beachieved by the use of insulated tubing and perhaps, in the future,by the downhole steam generators in which several companies haveinvested considerable R&D effort. 19 I f Arctic heavy-oil reservesare to be developed, then the use of these technologies will be essential to avoid melting the permafrost, which can extend downto depths of 1,500 ft [460 m]. Other factors that can impair injectivity and thereby increase wellbore heat losses are sand production into the injection well and water dropout from the steam whenit occurs across the lower injection intervals.Water Treatment and Steam Generation. Supply water for conventional steam generation needs treatment. This may be an important feature of thermal recovery operations in the Middle East,where freshwater supplies are limited, thus requiring the use of oftenvery saline formation waters. The processes required to producesuitable water for stearn generation are softening, fIltering, and deoxygenation. Water is softened by use of base exchange methods, butin areas where natural gas is readily available, reduced-pressuredistillation methods may be more appropriate. Deoxygenation canbe accomplished by stripping with natural gas, also an efficient andeconomical process when a ready supply of natural gas is available.Oil Production and Crude Oil Treatment. In Marguerite Lakecyclic steaming operations, a well will normally produce naturallyfor the initial part of the production cycle; at later times it is pumpedwith sucker-rod pumps. For extremely viscous oils, production mayhave to be assisted by use of diluents injected into the tubing toreduce the viscous drag on the sucker rods. Hollow sucker rodshave been used for this purpose, although injection of the diluentthrough the tubing/casing annulus is also feasible. Production ofevolved gases in in-situ combustion operations or flashing of waterto steam can cause pumping problems that require the use of gasanchors. For combustion, another important feature of well completions is in monitoring downhole conditions of temperature andpressure. Temperature is monitored in Marguerite Lake wells withpermanently installed thermocouples. These have been very useful in detecting the proximity of fireflood fronts, thereby allowinglocal quenching around the producer by the injection of water orsteam and avoiding the destruction of the well. Downhole pressuresare obtained by measuring the surface pressure of a permanentlyinstalled lA-in. [0. 64-cm] line containing a nitrogen column communicating with the bottomhole pressure.Heavy-Oil TransportationTransportation from production areas to suitable refineries and processing plants is a significantly more difficult problem for heavy oilsthan for conventional oils. Typically, heavy oils have been movedJournal of Petroleum Technology, February 1988

in heated road or rail cars and heated pipelines. However, all thesemethods are expensive and applicable mainly to short distances.For efficient movement of heavy oils over significant distances,the use of conventional pipelines is necessary. Because most pipelines have viscosity specifications of < 100 cp [< 100 mPa' s] andheavy oils by definition must be greater than that figure, it is necessary to reduce the viscosity of the heavy crude in some way, oftenby diluting the oil with a lighter hydrocarbon, such as condensate,to produce a blend of viscosity within the pipeline specification.The problem with this method is that it requires a readily availablecheap source of diluent because large quantities are required, especially when the more viscous oils are handled. For example, Cana

dian Cold Lake bitumen is exported as a 2: 1 crude/condensateblend.In many areas of the world where heavy oil is found, suitablediluent is not easily available. This has undoubtedly been an important factor in contributing to the limited development or nondevelopment of such deposits. Work in recent years, however, hasproduced a method for pipelining heavy oils without the use ofhydrocarbon diluents. 20 The method is based on the emulsification of the heavy oil. A combination of mixing conditions and avery small quantity of a particular surfactant has produced extremelystable oil-in-water emulsions with as little as 35 % water. Oils withviscosities as high as 10 6 cp [106 mPa's] have been treated toform an emulsion with an effective viscosity of < 100 cp [< 100mPa' s]. The emulsions are easily resolved by heating, or may conveniently be used directly as boiler fuel. Large-scale pipeline trialshave been carried out in Venezuela and more are planned in Canada.

This ability to move heavy oil more cheaply and efficiently ismost important if the more remote deposits are to be successfullyexploited.Observations. 1. Heavy oil is better defined by a limiting viscosity value thanby API gravity alone. We suggest that oils with an in-situ viscositygreater than 100 cp [100 mPa' s] be classified as heavy oil.2. With this criterion, the known total world heavy oil in placeis estimated to be 4,600 X 109 bbl [730 x 109 m3], with about onethird of this total located in carbonate reservoirs.3. The present economic climate may favor certain heavy-oil development projects over marginal offshore conventional oil development.4. Cyclic steam injection can be described by two basic analyticmodels. The first describes heat transfer to the reservoir by conduction and the second by convection. The selection of the modeldepends on the initial in-situ oil viscosity and its mobilization temperature.5. A profit-optimization method has been developed for steamstimulation. This procedure shows that there is a unique combination of the main performance indicators-st eam/oi l ratio and calendar day oil rate-at optimum conditions.6. For high-viscosity heavy-oil reservoirs, wet combustion canbe a promising recovery technique to follow cyclic steam injection.7. Heavy oil in carbonate reservoirs represents an important development target. The reservoir production mechanisms identifiedare favorable for efficient oil recovery.8. Heavy-oil transport as an oil-in-water emulsion has muchpromise for cost reduction and efficient pipeline operation.Nomenclature

A = cross-sectional area of symmetric element of rockmatrix cube, ft2 [m2]

C = isobaric specific heat, Btu/(lbm-OF) [kJ/(kg' K)]Cf = isobaric specific heat of fluid, Btu/(lbm-OF)[kJ/(kg' K)]h = formation thickness, ft [m]

H 1ast = heat left at end of previous steam cycle, Btu [kJ]k = permeability, darcies

kro = relative permeability to oilkrw = relative permeability to waterL = length of matrix cube, ft [m]

213

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M = volumetric heat capacity, Btu/ft3_oF [kJ/m3 'K ]Np = cumulative oil production, STB [stock-tank m3]Pc = capillary pressure, psi [kPa]Q; = amount of heat injected per unit mass of steam,

Btullbm [kJ/kg]Qs = steam injection rate, BID [m 3 /d]r = radius of heated zone, ft [m]

S = fluid saturationSw = water saturation

t = time, daystinj = injection time, daysT = temperature, OF [0C]T, = temperature of reservoir, OF [0C]Tst = temperature of steam, OF rOC]Vj = fluid flow vector, ftlD [mid]

x = distance from surface of matrix cube, ft [m]11 = diffusivity (l1=AlpC)A = thermal conductivity, Btu/ft-D-OF [kJ/m' d K]

iJ.o = oil viscosity, cp [Pa' s]iJ.w = water viscosity, cp [Pa' s]p = density, Ibm/ft3 [kg/m3]

PI = fluid density, Ibm/ft3 [kg/m3]4> = porosityy, = function in Eq. 9, darcies-psi/cp [darcies' kPa/Pa' s]

AcknowledgmentsWe thank BP Exploration Ltd. for permission to publish this paperand BP Resources Canada Ltd. for providing many useful reportsand data.References

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214

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18. Marie, C.M.: Multiphase Flow in Porous Media, Gulf PubJishing Co. ,Houston (1981) 39-41.19. Chesters, D.A., Clark, C.J., and Riddiford, S.A.: "Downhole SteamGeneration Using a Pulsed Burner," Proc., European Symposium onEOR, Elsevier Sequoia, Bournemouth, U.K., (1981) 563-72.20. Stockwell, A. et al.: "Viscous Crude Oil Transportation: The Preparation of Bitumen, Heavy and Extra-Heavy Crude Oil-in-Water Emulsions," paper HCTS/CF.3115 presented at the 1985 UNITARConference on Heavy Crude and Tar Sands, Long Beach, CA, July22-31.

51 Metric Conversion FactorsAPI 141.5/(131.5+ API) g/cm3bbl x 1.589873 E-Ol m3cp x 1.0* E-03 Pa's

ft x 3.048* E-Ol mOF (OF-32)/1.8 Cmiles x 1.609344* E+OO kmpsi x 6.894757 E+OO kPa'Conversion factor is exact. JPTOriginal SPE manuscript received for review March 7, 1987. Paper accepted for publica-tion Aug. 31,1987. Revised manuscript received Nov. 19, 1987. Paper (SPE 15748) firstpresented at the 1987 SPE Middle East Oil Show held in Bahrain, March 7-10.

Journal of Petroleum Technology, February 1988