Keywords:review of SAGD processpitfalls in numerical and laboratory modelseffective parametersoperational problemsfuture of SAGD

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Journal of Petroleum Science and Engineering 68 (2009) 135150

Contents lists available at ScienceDirect

Journal of Petroleum Science and Engineering4. Mechanics of SAGD. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1374.1. Steam chamber rise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1374.2. Steam ngering theory. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1374.3. Co-current and counter-current displacement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1374.4. Emulsication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1384.5. Residual oil saturation in steam chamber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1384.6. Heat transfer and distribution through steam chamber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1384.7. Analytical models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

5. Effects of reservoir properties on SAGD performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1395.1. Porosity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1395.2. Thickness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

5.3. Gas saturation. . . . . . . . . .5.4. Permeability . . . . . . . . . .5.5. Viscosity and API . . . . . . . .5.6. Wettability . . . . . . . . . . .

Corresponding author.E-mail address: tayfun@ualberta.ca (T. Babadagli).

0920-4105/$ see front matter 2009 Elsevier B.V. Adoi:10.1016/j.petrol.2009.06.011. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

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2. Background on SAGD process . . . . . .3. Mechanism pitfalls . . . . . . . . . . .Contents

1. Introduction . . . . . . . . . .accompanying it.Two major techniques, namely thermal and miscible, have been considered in HO-B development, along withseveral other auxiliary methods (chemical, gas, electromagnetic heating, etc.) for different well congura-tions, with steam assisted gravity drainage (SAGD) being the most popular. Miscible techniques are nothighly recognized as a commercial option, while thermal techniques have by far a more stable foundation inthe industry.Despite a remarkable amount of laboratory experiments and computational studies on thermal techniquesfor HO-B, specically SAGD, there was no extensive and critical literature review of the knowledge gainedover almost three decades. We believe that this kind of review paper on the status of the SAGD process willshed light on the critical aspects, challenges, deciencies and limitations of the process. This will open doorsto further development areas, and new research topics.This paper focuses mainly on laboratory and numerical simulation studies, not eld experiences. The attemptis to draw a picture of the developments on the physics and technical aspects of the process and its futureneeds. Specic attention, was given to (a) the effect of geological environment on the physics of the process,(b) evaluation of the laboratory scale procedure and results, (c) problems faced in numerical modelling(capturing the physics of the process, relative permeability curves, dynamics of gravity controlled counter-current ow), and (d) operational and technical challenges.

2009 Elsevier B.V. All rights reserved.Yet the in-situ recovery of HO-B is still not a simple process and there are many technical challengesReceived 9 July 2008Accepted 7 June 2009

a tremendous demand on tReview

SAGD laboratory experimental and numerical simulation studies: A review of currentstatus and future issues

Al-Muatasim Al-Bahlani, Tayfun Babadagli University of Alberta, Department of Civil and Environmental Engineering, School of Mining and Petroleum, 3-112 Markin CNRL-NREF, Edmonton, AB, Canada T6G 2W2

a b s t r a c ta r t i c l e i n f o

Article history: With around 7 trillion-barrel reserves and recent increases in oil demand, there is no doubt that there will behe development of heavy oil/bitumen (HO-B) reservoirs in the coming decades.

j ourna l homepage: www.e lsev ie r.com/ locate /pet ro l. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

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ll rights reserved.

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expansion of SAGD methods to world wide applications. To achieve

136 A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150this, we believe that there is a need to compile and analyze thepublished data about SAGD studies at different scales and for differentpurposes. This analysis will provide not only clarications foruncertainties faced so far, but also an extensive summary of unclearpoints that eventually lead to dening further research areas.

2. Background on SAGD process

SAGD is an abbreviation for steam assisted gravity drainage. It wasrst developed by Roger Butler and his colleagues in Imperial Oil inthe late 1970s. Its main characteristic is introducing steam intoreservoirs and producing heated oil using two horizontal wells. Butlerdescribed the technique as when steam is injected, a steam saturatedzone, called a steam chamber is formed, in which the temperature isessentially that of the injected steam. The steam ows towards theperimeter of the steam chamber and condenses. The heat from thesteam is transferred by thermal conduction into the surroundingreservoir. The steam condensate and heated oil ow by gravity to theproduction well located below. As the oil ows away and is produced,

He then raised some critical issues to be considered in the projectdevelopment and eld performance assessment:

1. condensate ow: with so much condensate owing, convectionwould be expected to be the dominant heat transfer mechanism,

2. geology: geology of the formation can have a profound inuence onsteam chamber growth (sideway in underground testing facility(UTF) case),

3. 2D vs. 3D models: two important missing factors are ow in thetwo horizontal wells, and the effect of wellbore, when the wells aredrilled from surface rather than from tunnels (refereeing to UTF Devor project),

4. geomechanical effects: the effects of SAGD on reservoir geome-chanics is not well understood.

Singhal et al. (1998) mentioned1 that Farouq-Ali pointed outpotential problems and limitations of SAGD such as: (1) sand control,

1 Singhal et al. (1998) refer these comments to a talk about SAGD given by Farouq Aliin Calgary Jun 17 1998. Unfortunately we could not obtain any recorded material of this5.7. Heterogeneity . . . . . . . . . . . . . . . . . . . . . . .5.8. SAGD in carbonate reservoir . . . . . . . . . . . . . . . .5.9. SAGD geomechanics . . . . . . . . . . . . . . . . . . . .

6. SAGD operation . . . . . . . . . . . . . . . . . . . . . . . . .6.1. The start-up procedure . . . . . . . . . . . . . . . . . . .

7. Steam quality . . . . . . . . . . . . . . . . . . . . . . . . . . .8. Length, spacing and placement of horizontal wells . . . . . . . . .9. Subcool temperature (steam trap control) . . . . . . . . . . . . .

9.1. HP (high pressure) vs. LP (low pressure) SAGD . . . . . . .9.2. Steam chamber monitor and volume size estimation . . . . .

10. Numerical simulation . . . . . . . . . . . . . . . . . . . . . . .11. Experimental pitfalls . . . . . . . . . . . . . . . . . . . . . . .12. SAGD improvement . . . . . . . . . . . . . . . . . . . . . . . .

12.1. Geometrical attempts . . . . . . . . . . . . . . . . . . .12.2. Chemical attempts . . . . . . . . . . . . . . . . . . . . .

13. Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . .Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . .References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1. Introduction

Reservoir heating is essential in heavy/ultra heavy oil and bitumen(HO-B) recovery. Steam injection is a proven thermal technique to beused for this purpose and it can be achieved through continuous orcyclic (huff-and-puff) injections. Field experience and simulationsstudies show that performing these techniques are associated withtechnical difculties and usually low recovery factors. The steamassisted gravity drainage (SAGD) method was proposed by Butlermore than 30 years ago (Butler, 1994b, 1998, 2004a). Due to increasedcontact area through two horizontal wells, the process was believed tobe successful from a technical point of view although economicalstandpoints are still sceptical. Over a thirty-year period, this techniquehas been tested successfully, which led many to think of it as astandard technique in HO-B recovery. Obviously, it has some technicaland physical restrictions which will be discussed in this paper.

Alternatives to this technique have been proposed for unsuitablereservoirs. Those techniques include miscible ooding (VAPEX) ormodied versions of SAGD through different congurations of wells orusing additives to steam.

Due to its suitability for unconsolidated reservoirs that displayhigh vertical permeability, the SAGD technique has received attentionin countries with huge HO-B sand reserves like Canada and Venezuela.Although it is a highly promising technique, many uncertainties andunanswered questions still exist and they should be claried forthe steam chamber expands both upwards and sideways (Butler,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

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1994b). Two types of ow then exist during this process: One at theceiling of the steam chamber (ceiling drainage; bitumen is pulledaway from the front immediately after mobilization where steam riseusually impedes liquid drainage) and the other one along the slopes ofthe steam chamber (slope drainage; gravity holds mobilized bitumenagainst the slope where bitumen mobility is controlled by conductionheating from the steam zone) (Edmunds et al., 1989; Edmunds et al.,1994; Nasr et al., 2000). Fig. 1 illustrates the SAGD mechanism.

Das (2005a) stated that most of commercial SAGD wells areexpected to produce in the range of 6001500 m3/day of the totaluid under normal operating conditions after the initial ramp upperiod. The corresponding injector well should have the capacity of4001200 m3/day cold water equivalent (CWE) of steam injection.

3. Mechanism pitfalls

Although the SAGD process looks simple at rst sight, severalauthors pointed out some pitfalls/concerns on the theories of themechanism. For example, Farouq-Ali (1997) stated that:

1. the theory pertains to the ow of single uid,2. steam pressure is constant in the steam chamber,3. only steam ows in the steam chamber with oil saturation being

residual, and4. heat transfer ahead of the steam chamber to cold oil is by

conduction only.talk.

the

137A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150(2) hot efuent/high water-cut production, (3) frequent changes inoperating regime (making management of SAGD projects labourintensive), (4) deterioration of production at late stages, and (5) highoperating costs. Butler and Yee (2002) stated that despite itsattractiveness, SAGD tends to be wasteful of steam because the entirepart of the reservoir that is depleted becomes heated to steamtemperature, whereas to avoid steam coning, only the reservoir nearthe production well has to be heated. Heating the upper part of thereservoir to steam temperature is undesirable because of the resultinghigh loss of heat to the overburden as well as the high heat require-ments for the chamber. The loss to the overburden is also increased bythe tendency of the steam chamber to creep laterally beneath thereservoir cap (Butler, 1997).

Deng (2005) outlined the disadvantages of SAGD as: (1) intensiveenergy input and excessive CO2 emission, and (2) costly post-production water treatment.

After reviewing published eld data, McCormack (2001) listedseveral problems faced in the eld applications: (1) lower than ex-pected drainage rates from average to poor sands; (2) difculty withinstallation of liners into the horizontal section of the well; (3) sandproduction, wellbore scaling, and (4) uid removal limitations.

Based on these evaluations, one can divide SAGD challenges intomicro- and macro-scale. Some of these challenges are not inherent toSAGD; they can also be applied to other steam injection techniques,such as geological effects, upscaling (2D/3D models), high SOR, andoverburden heat losses. However, such challenges have a relativelyprofound effect on SAGD; they need more micro/lab-scale studies tofurther understand the physics of the process and to use them forbetter industrial applications.

4. Mechanics of SAGD

4.1. Steam chamber rise

Fig. 1. Illustration ofThe SAGD concept is based on steam chamber development, asproduction is mainly from the chamber/heated-oil interface. Thus, thedevelopment and analysis of the steam chamber growth has receiveda great deal of attention by scientists studying SAGD. Yet, it seemsthat the complete picture of the steam chamber development processis not fully represented due to different processes occurring at thesame time; namely, counter-current ow, co-current ow, water im-bibition, emulsication, steam ngering and dimensional movement(lateral vs. vertical).

In other words, the complexity is due to the fact that a lighter uid(steam) is trying to penetrate into a heavier uid (HO-B) above it. Itoand Ipek (2005) observed from eld data that the steam chambergrew upwards and outwards simultaneously like the expansion ofdough during baking. The recent understanding of the SAGD processendorses the idea that steam chamber is not connected to the pro-ducer; rather a pool of liquid exists above the production well. Gateset al. (2005) identied the advantage of having such a pool bypreventing the ow of injected steam into the production well. Thus,it is of primary importance to clarify the relative effects of eachparameter affecting the movement and the shape of the steamchamber.

4.2. Steam ngering theory

From a sand pack lab experiment, Butler (1994b) observed that therise of the steam chamber does not advance as a at front, rather as aseries of separate and ragged ngers. He referred to the occurrence ofthese ngers as being due to instability created by rising lighter steambelow the heavy oil. Thus, understanding steam nger theory iscrucial to understanding steam chamber rise processes. Depicting arectangular boundary, Butler (1987) hypothesized steam chamberdevelopment as follows:

Steam ows upward from the lower boundary providing heat torise the reservoir temperature to steam temperature.

Heatedmaterial drains through the lower boundary as a number ofstreams.

The velocity at which the residual oil leaves the system is that ofthe steam chamber rise.

The entering steammoves at a higher velocity than the chamber inorder to pass through the lower boundary.

At the very top of the chamber steam ngers move into therelatively cold reservoir and heat the cold oil through conduction.

According to Ito and Ipek (2005), many observations in the UTFPhase A and B, Hanginstone and Surmount projects are now clearlyunderstood through the steam ngers concept. They hypothesizedthat the specic nature of steam ngering phenomena during SAGDoperation may cause steam chamber deviation from usual behaviour(stop and resume, shrinkage or even disappearance). Sasaki et al.(2001) provided images where steam ngering can clearly be seen on

SAGD mechanism.their 2D experimental model. They also showed an increase in theceiling instability, hence ngering, due to intermittent steam stimu-lation of the lower horizontal producer.

These observations imply that it is very important to considersteam ngering as a method of steam movement inside the reservoir.Steam ngering occurs in a vertical manner whereas a buoancyadvantage of steam to oilmainly drives the process. However, chambergrowth disturbance does not only occur vertically and this triggers aquestion: can steam ngering occur laterally? This question may bebacked up with geomechanical investigation results of increasingwater relative permeability ahead of the steam chamber.

4.3. Co-current and counter-current displacement

Nasr et al. (2000) stated that the uniqueness of the SAGD recoveryprocess lies in the salient role of moving condensing boundaries andcounter-current ows. Counter-current owbetween heated heavy oil

138 A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150and bitumen occurs at the top of a rising steam chamber where steamngers rise and heated heavy oil falls (Chung and Butler, 1987; Butler,1987, 1994a). Nasr et al. (2000) published a paper highlighting steamoil emulsion counter-current ow and the rate of propagation of thesteam chamber. They used a cylindrical experimental model andadiabatic control system, and a numerical model to simulate SAGDcounter-current ow and to determine the sensitivities of differentparameters. They concluded that for a givenpermeability, the counter-current steam front propagation rate is a linear function of time. Theyobserved that the time taken for counter-current steam front topropagate to a specic distance is muchmore than time taken by a co-current front, where drainage condensate was impeding the advanceof the counter-current front. After a history matching of the steam-water counter-current and co-current relative permeability curves,they found that there was a signicant difference between counter-current and co-current relative permeabilities. They argued that thismay be the result of a coupled ow between the phases. Hence, thefollowing question arises: can the existing formulation of numericalsimulation capture this important character? The steam interfaceadvancement seems to be due to a combination of both co-current andcounter-current ow, which shows the importance of a clear pathpresence for clean sand with no bufes, as well as how reservoirheterogeneity would have a profound impact on such processes.Another issue we question is whether or not counter-current move-ment also happens within a pore. When steam rises up inside thepore, preferentially in the middle portion, does the oil drain downthrough the sides closer to the grain due to wettability and connatewater issues? Or does the process take place in a convective manner?What is the effect of injection pressure/rate on this process?

4.4. Emulsication

Chung and Butler (1987) stated that the production of in-situthermal recovery of heavy oils always occurs in the form of water in oilemulsion. This is much more viscous than the oil itself. Theyconducted a laboratory study to elucidate the geometrical effect ofsteam injection on the water/oil emulsion of the produced uid froma SAGD process. They performed their experiment in two schemes.The rst scheme consisted of a steam injector slightly above aproducer at the base of the formation. The second scheme consisted ofa producer at the base of the formation and a vertical circulating steaminjector perforated near the top of the formation. They concluded thatmuch higher water/oil emulsion content was found in the produceduid when the steam chamber was rising in the experiment withbottom steam injection than with injection at the top. The rate ofrecovery was higher in the operation with top injection. This isprobably due to the fact that an increase in water/oil emulsion ratioincreases the uid viscosity, hence a reduction in oil production isexpected. However, they also noticed that when the steam chamberspreads sideways, a two phase stratied ow of steam and heatedheavy oil occurs at which steam ows sideways to the interface, andheated heavy oil ows down, below and along the interface,which dramatically reduces the water/oil emulsion ratio (Chungand Butler, 1987). They later extended their work to include otherfactors which may affect water/oil emulsication ratio such as initialconnate water (0% and 12.5%), steam quality, and pressure variation(153 kPa3.55 MPa) (Chung and Butler, 1989).

For initial connate water, they noticed a higher water/oil ratioemulsion when Swi=0% than Swi=12.5%. They commented thatthere is less tendency for water to condense as droplets on the surfaceof oil when enough connatewater is available. As the droplets of watercondense on oil, they become buried because of the spreadingcharacteristics of oil. It is worth mentioning that Sasaki et al. (2002)observed this process in a microscopic visualization experiment.For steam quality effect, Chung and Butler (1989) noticed no major

difference in injecting steam wet or dry. They argued that this isbecause the interfacial activity at the steam front and the heatingmechanism of the bitumen are the same for both cases. They observedno major difference as a result of pressure variation. This also appliesto the effect of particle size in the porous matrix where no signicantvariationwas found. Sasaki et al. (2001) visualizedwater/oil emulsionat the boundary of the steam chamber in a 2D laboratory scaledmodel. They noticed a 25% uctuation in the ratio after steambreakthrough and chamber rise. Understanding the water/oil emul-sion is crucial not only from a reservoir engineering point of view, butalso from a production technology perspective as well.

4.5. Residual oil saturation in steam chamber

Butler (1994a) observed that major oil ow happened on thechamber sideways rather than through it. He explained this observa-tion by two hypotheses; (1) residual oil saturation is too low insidethe steam chamber to allow for any oil movement, and (2) due towater condensate between steam and oil, water imbibition andinterfacial tension support the oil to drain laterally.

Walls et al. (2003) studied residual oil saturation in steamchambers using a numerical model. Their work consisted of twomain parts: (1) sensitivity tests done on the shapes and the end pointsof the two phase-relative permeability curves, and (2) krog relativepermeability curve adjustment to match theoretically determinedresidual oil saturation. They concluded that water relative perme-ability and oil relative permeability in the gasoil system are the mainfactors that determine the magnitude and the shape of the oil satura-tion curve as a function of time. They also concluded that residual oilsaturation increases at lower SAGD operating pressures. Many of thenumerical simulationmodels reported failed to show their applicationof changes in relative permeability curves due to temperature change.This will be discussed further in the Simulation section.

Pooladi-Darvish andMattar (2002) stated that some of the reasonsfor larger residual oil saturation are that steam at higher pressures hasless latent heat, more heat will leave the reservoir through theproduced uids at higher temperatures, and more heat will be left inthe steam chamberwhere oil is no longer present.What is critical hereis the amount of oil left inside the steam chamber. As the steam/oilinterface passes through the reservoir, production occurs mainly byco/counter-current. As the interface progresses, the reduction ofresidual oil saturation is mainly due to the steamoil gravity dif-ference, which is a very slow process. Eventually, residual oil satura-tionwill become nil, but the question is, how long will it take to reachthat point?

4.6. Heat transfer and distribution through steam chamber

Understanding the heat transfer through the steam chamber is alsocritical. As mentioned earlier, Farouq-Ali (1997) criticized theassumption that only thermal conduction exists in SAGD. In responseto that critique, Edmunds (1999) stated that based on the associatedchange in enthalpy, the liquid water could carry and deposit 18% of theheat of condensation of the same water. Convection due to oil isaround 1/5 of this and conduction to carry the remaining 78%. He thenevaluated the convection role due to water streamline being almostparallel to isotherms of less than 5%. This was also emphasized byEdmunds (1999) who stated that except for the very near vicinity ofthe liner or anywhere live steam penetrates, heat transfer in themobile zone is dominated by conduction, not convection.

Gates et al. (2005) provided images of steam quality andtemperature of the steam chamber from a simulation study. Compar-ing these pictures, one can clearly see that temperature is almostconstant while steam quality varies signicantly. This supportsthe claims of varying steam pressure throughout the steam chamber,i.e., that steam chamber pressure is not constant. In their work, they

provided a novel method for visualizing heat transfer within the

boundaries of the steam chamber. They stated that the usefulness ofthis method is that steam quality proles provide the means toexamine convective heat transfer in the reservoir.

Using a hypothetical example of hotwell analysis, Butler (1987)provides a heat distribution table for a typical Athabasca SAGD project.We reproduced it into a pie chart as shown in Fig. 2. Butler commentson the outcome by stating that in general the heat remaining withinthe steam chamber, per unit production of oil, will be lower if thesteam temperature is lower (i.e., the chamber pressure is lower) or ifthe oil saturation is higher (i.e., there is less reservoir to be heated per

139A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150m3 of oil). The latter is very important in determining the performanceof a reservoir; high (initial) oil saturation is always desirable.

Yee and Stroich (2004) showed that, after 5 years of Dover projectphase B, the amount of injected heat in the chamber was 32.2%, andoutside of the chamber, 34.7%. The rest (33.1%) was reproduced. It canbe seen that almost one third of heat injected is reproduced. Webelieve that this may have a benecial effect as heat may prevent waxdeposition inside the tubing andmaymaintain a lower oil viscosity foruplifting if no emulsion is created.

4.7. Analytical models

Butler (1987) developed an approximate expression to predict thesteam chamber rising rate and the dimensions of the steam ngers.He concluded that the rise rates are proportional to reservoir per-meability and are strong functions of steam temperature and oilviscosity. Later work was done by Edmunds et al. (1989). They cri-ticized the dependency of Butler's (1987) approach on certaingeometric simplications which restrict the generalization of themodel. They continued their numerical analysis based on the UTFPhase A test. They presented a good analysis of 1-D ceiling drainageand its relation to SAGD cases.

Butler (1994a) described the result of their work as a prediction ofthe drainage rate using Darcy's equationwith counter-current ow andthe incorporation of relative permeability effects. However, he criticizedEdmunds et al.'s (1989) work in terms of geometrical and theoreticalaspects. Fromone of Butler'sworks (1997)we can identify the evolutionof Butler's theory in three stages: (1) the original model, (2) theTanDrain & LinDrainmodel, and (3) the steam risingmodel. Despite theextensive theoretical input to evolve these equations, all modicationspresentedare concernedwith the shape, height and growthof the steamchamber. To bemore specic, the original Butler theory concentrated onobtaining a relationship between the drainage rate and the drainageheight independent of interface shape or its horizontal extension. Later,the dependency on the shape of the interface and boundaries weretaken into account. Butler then provided a guideline on how toanalytically calculate oil production through the following set ofequation which we summarized on the ow chart given in Fig. 3.

As seen in Fig. 3, the equations tend to have quite a number ofsimplications, some of which mentioned by Farouq-Ali (1997).However, a very important feature can be drawn from Butler's theoryevolution: the huge dependency of analytical models to steam cham-ber growth and shape. These factors as we have seen earlier areheavily dependent on reservoir characteristics, especially in hetero-geneous reservoirs. Butler's formulation also includes the effect of

Fig. 2. Reproduction of Butler's (2001) heat distribution for a typical Athabasca oil SAGD

project.reservoir properties such as porosity, thickness and initial oilsaturation.

Chen et al. (2007) also commented on Butler's theory where theyaddressed that the theory is based on simplifying assumptions, suchas that the steam chamber pressure remains at the original reservoirpressure and the chamber must remain connected to the producer.

Birrell (2001), on the other hand, stated that Butler's equationwasshown to accurately predict the performance of SAGD in the eld.

Reis (1992, 1993) stated that the limitation to the Butler's model isits complexity; it requires an iterative solution to a set of equations tocalculate the production rate. He provided linear and geometricalmodels for oil production where he introduced a dimensionless tem-perature coefcient to the denominator. He showed that Butler'smodel overpredicts oil production compared to his model. He alsoprovided energy balance and steam oil ratio equations. However, hismodel does not predict production during the rise of the steamchamber.

5. Effects of reservoir properties on SAGD performance

5.1. Porosity

Few studies were presented to show the effect of porosity on SAGDperformance. By reviewing the analytical models provided, however,one can observe that they all have cumulative production and dailyproduction proportional to porosity whichmeans that higher porositywould analytically promote SAGD performance. This was observedin the analytical study by Llaguno et al. (2002) where they reportedthat accumulation properties (thickness, porosity and oil saturation)have a greater effect on SAGD performance than ow properties(permeability, viscosity, API, and reservoir pressure). The micro-scalepore structure could be considered as a critical issue if the assumptionof counter-current displacement occurs within in a single pore,(i.e., steam rises through the center of the pore while heated oil drainsthrough its edge closer to the grain), is valid. In this case, one has tounderstand what impact the pore characterstics (shape, pore andthroat size) have on the counter-current gravity drainage process.

5.2. Thickness

Several studies report that an increase in oil production wasnoticed with an increase in oil pay thickness (Sasaki et al., 2001; Chanet al., 1997; Shin and Polikar, 2007; Singhal et al., 1998; Edmunds andChhina, 2001; McCormack, 2001). Edmunds and Chhina (2001) statedthat zones less than 15 m thick are unlikely to be economic. Most ofthe work done to draw this conclusion is based on the fact that thinreservoirs increase thermal losses resulting in higher SOR. However,this conclusion is subject to a variable understanding of what is thickand what is thin. Also, the steam chamber growth behaviour dueto other geological parameters may have an effect on such con-clusions. For example, cupcake like steam chamber growth (laterallyand sideways) would not see much effect of reservoir thickness, whilehand fan like steam chamber growth (laterally then sideways) in athick reservoir might take much more time for the steam chamberto grow. Other complicated process such as steam ngering, emul-sication, and prevailing counter-current ow may result in theuctuation/decrease of oil production. Thus, there may be an ultimatethickness for each reservoir which may dictate where the injector isplaced from the top of the reservoir. This is governed by thesteamchamber growth behaviour which is in turn governed by otherreservoir charecterstics such as kv/kh.

5.3. Gas saturation

Nasr et al. (2000) studied the effect of initial methane saturation

on the advancement of a steam front in an experimental sand packed

140 A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150model. With the presence of initial methane saturation, they noticedthe faster movement of steam front at present temperature valueson a given time. However, as the steam front entered the region ofmethane saturation, the propagation rate declined as the methanemole fraction increased in the gas phase. Canbolat et al. (2002)observed that the initial presence of n-butane had a positive effect onthe process. They explained this by the reduction of oil viscosity due togas presence. Bharatha et al. (2005) conducted a study on dissolvedgas in SAGD by means of theory and simulation. They stated in theirconclusion that the effect of dissolved gas on SAGD is to reduce thebitumen production rate. They also showed that operating pressureplays a greater role in reducing the effect of dissolved gas saturationpresence.

5.4. Permeability

McLennan et al. (2006) stated that the predicted ow performanceof SAGD well pairs is sensitive to the spatial distribution of per-

Fig. 3. Flow chart of Butler's analytical model for calmeability. After experimental (sand packed core) and numericalmodel investigations, Nasr et al. (2000) noted that the effect of liquidconvection ahead of the steam front can provide better heating for the10 Darcy permeability case than for the 5 Darcy case. They also ob-served that there was evidence that steam temperature inside 5 Darcysand was lowered by about 3 C than that for the 10 Darcy sand for agiven steam injection temperature. They argued that this might be aresult of higher capillary pressure for the 5 Darcy case. They alsoreported that the propagation rate of the steam front is not a linearfunction of permeability.

In a 2D simulation model investigating SAGD in a carbonatereservoir, Das (2007) reported no signicant change in productiondue to matrix permeability at earlier stages and faster decline for lowpermeability at later stages. He referred this to the possibility ofmatrix production which occurs primarily by imbibition and thermalexpansion. However, by looking at the examination range (1050 mD)it can be seen that the range is too small to study the effect ofpermeability. Kisman and Yeung (1995), on the other hand, found

culating oil production from a SAGD operation.

141A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150from a simulation model that decreasing the vertical permeabilityresulted in a signicant decrease in CDOR (calendar day oil rate) andOSR initially. But an increase in both CDOR and OSR was noticed atlater stages. It was also shown by Shanqiang and Baker (2006) in a 3Dsimulation model that decreasing permeability reduced the initial oilproduction but later increased it dramatically.

McLennan et al. (2006) presented a permeability modeling pro-cedure. Their methodology consists of two major steps: (1) debiasingand re-scaling the by-facies core horizontal permeability, kH vs.porosity relationships using mini-models (seven working phases),and (2) assigning permeability to the geological grid. They outlinedtwo key features of their methodology as (1) the integration ofmissing lower porosities or increased shaliness into measurementsfrom dilated and preferentially sampled corewhich is also dilated, and(2) the translation of porosity-permeability relationships at the corescale to the SAGD ow simulation scale (McLennan et al., 2006).

Nasr et al. (1996) showed a decrease in OSR due to a decrease inpermeability through their numerical modeling study. Collins et al.(2002) stated that laboratory tests on specimens of undisturbed oilsands have conclusively proven that absolute permeability increasesdramatically with dilation. They also showed that shear dilation of oilsands enhances permeability in the SAGD process. Shin and Polikar(2007) observed that higher permeability resulted in a higherultimate recovery as well as lower CSOR. They also noticed that ningupward sequence showed better SAGD performance due to lateralsteam propagation (cupcake growth). Nasr et al. (1997) reported froma 2D sand packed model that for low permeability reservoirs, thesteam zone was localized around the injection well. The low per-meability reduced the drainage of oil and growth of the gravity cell.Mukherjee et al. (1994) observed that the presence of a low per-meability zone between the injector and producer may cause waterhold up between the wells where water is not well drained.

Butler (2004b) studied the effects of reservoir layering. He statedthat in layered reservoirs with permeability ratios less than about two,the height average permeability should be used in the Lindrainequation. He then suggested that in the situation described above,steam should be injected in the more permeable area. He also statedthat if the more permeable layer is at the bottom, a steam swept zonewill tend to undermine the upper layer. If the more permeable layer isat the top and the permeability ratio is greater than two, thepenetration of the steam into the lower layer will be delayed and oilwill move through the lower region driven by the imposed pressuregradient. Effects on oil rate are not very severe at least until the upperlayer is exhausted.

5.5. Viscosity and API

Das (2007) studied the effect of oil viscosity in a 2D model,investigating SAGD in a carbonate reservoir. He found that recoveryrate and injectivity improved with lower viscous oil. Shanqiang andBaker (2006) studied the effect of oAPI on SAGD performance andobserved that increasing oAPI reduced oil production. Singhal et al.(1998) outlined the effects of viscosity on geometrical and opera-tional parameters in a screening study. They advised that fromviscosities less than 35,000 mPa s and thickness more than 15 m,using vertical steam injectors staggered around horizontal producerswas a feasible recovery strategy. Also, the relaxation of subcool con-strain under certain circumstances may be feasible. For viscositiesabove 65000 mPa s, the use of horizontal injectors and subcoolconstrainwas determined to be critical. Larter et al. (2008) studied theimpact of variation in heavy oil heterogeneity in reservoirs through 3Dsimulation. They concluded that the impact of dramatic oil viscosityvariations in a heavy oil reservoir on reservoir productivity dependson the recovery method. They showed that in terms of productivityand compositional varations of the oil phase, the impact is large on

SAGD and CSS when initial viscosity gradient with depth is taken intoaccount. They observed a reduction of 30% for the top oil end memberand 75% for the bottom oil end member.

5.6. Wettability

Few studies were conducted to study this crucial reservoirproperty. Das (2007) used a 2D numerical simulator and observedthat lower oil recovery is obtained with oil-wet-carbonate-reservoirsand with no capillary pressure. However, the role of wettabilityalteration from water-wet to oil-wet was demonstrated to have apositive impact in thermal recovery around the production wellboreregion (Isaacs et al., 2001; Yuan et al., 2002). In their patent documentIsaacs et al. (2001) demonstrated that oil-wet sand in the near regionof the production well (by treatment with wettability alterationchemicals), when coupled with SAGD, causes an increase in recoverycompared to classical SAGD. Following up on that patent, Yuan et al.(2002) studied the potential impacts of altering wettability near aproductionwell on SAGD using a eld scale numerical model to clarifythe possible key parameters. They concluded that (1) the bigger theregion around the production well being oil-wet, the better the oilproductionwas, at least in early stages of the steam chamber, (2)morethan near well effect was observed from alternating wettability in alocal zone near the production well, (3) SOR was lowered due toconstant bottom hole pressure, and (4) it might be benecial not tokeep the oil-wet zone at its wettability status for the entire operationperiod to reduce the cost of wettability-changing agent. However, theynoticed water accumulation between the water-wet and oil-wet zone.This water blockage phenomenon was caused by creation of oil-wetzone. This diagnose is very relevant since water ow through the oil-wet region will be impeded due to the absence of phase lubricantwhich may also be a factor inuencing SOR. This water blockagewould probably have a negative impact on steam chamber growth andmaintenancewhichmay be another reasonwhy oil-wet regionmay bea temporary solution.

These observations lead us to raise a few ags on the role of ES-SAGD in oil-wet reservoirs and how solvent addition with hightemperature effect would cause wettability alteration, and henceaffect gravity drainage performance. These observations and thoughtsshould prompt further effort to understand the effect of wettabilityand/or wettability alteration on SAGD and potential performanceoptimization.

5.7. Heterogeneity

Yang and Butler (1992) studied the effect of reservoir hetero-geneities on heavy oil recovery by SAGD. Their approach was to use atwo dimensional sand packed model. They limited their study to twoeld conditions: (1) a reservoir with thin shale layers, and (2) areservoir containing horizontal layers of different permeabilities. Forthe two layer reservoir they studied two cases: (1) a high/low per-meability reservoir, and (2) a low/high permeability reservoir. Theynoticed that the high/low permeability was acting like a whole highpermeability reservoir. In the low/high permeability case, theynoticed an undermining of steam in the lower (high permeability)layer. This effect decreased with time. They then compared the cumu-lative oil production from the previous setup to all low permeabilitysetups and noticed little difference. They noted two effects cancellingeach other, namely (1) undermining steam enhanced gravity drainageof bitumen above the inter-layer surface, (2) a higher water/oil emul-sion was expected above the undermining steam causing an increasein the viscosity of the produced uid. For reservoirs containing ahorizontal barrier, they conducted two cases with: (1) top steaminjection, and (2) bottom steam injection. They also studied thereservoir dipping effect for the low/high permeability setup. Theycontrolled the dipping by tilting the model upward and downward

by 5 . A reservoir dipping upward gave a higher production than a

142 A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150reservoir dipping downward. The reason for this, they commented, isthat the production rates are mainly controlled by the total drainageheight and placing the production well at the lowest location of a dipreservoir obtained the maximum height. They then studied the effectof barrier length for each case (short horizontal barrier, and longhorizontal barrier). With a top steam injection, the presence of a shorthorizontal barrier had no effect on the general performance. They thenconducted several experiments on long barriers by changing thelocation of the injection and production well relative to the barrier.They concluded that a long horizontal barrier decreases the produc-tion rate but not as much as expected in some congurations. Theyalso observed that heated bitumen above the barrier may not beproduced even though it is hot because of the steam pressure holdingup the oil at the bottlenecks to the ow (Yang and Butler, 1992). Thisconrms that SAGD is heavily dependent on a good communicatingreservoir.

Chen et al. (2007) conducted a numerical simulation study onstochastic of shale distribution Near Well Region (NWR) and AboveWell region (AWR). They stated that drainage and ow of hot uidwithin the NWR has a short characteristic length and is found tobe very sensitive to the presence of shale that impairs vertical per-meability. The AWR affects the (vertical and horizontal) expansion ofthe steam chamber. It is of characteristic ow length on the order ofhalf of the formation height. SAGD performance is affected adverselyonly when the AWR contains long continuous shale or a high fractionof shale. They also studied the potential improvement of SAGDperformance by hydraulic fracturing by identifying three cases:horizontal fracture, vertical fracture parallel to, and vertical fractureperpendicular to the well. In some cases, they observed an improve-ment in the oil steam ratio by a factor of twowhen a vertical hydraulicfracture was introduced. They also concluded that vertical hydraulicfractures are predicted to enhance SAGD performance more drama-tically in comparison to horizontal hydraulic fracture. Finally, theystated that a vertical hydraulic fracture along the well direction issuperior to one perpendicular to the well direction.

Zhang et al. (2005) showed 4D seismic amplitude and crosswellseismic images of steam chamber growth at the Christina Lake SAGDproject which identied the effects of reservoir heterogeneity.

The SAGD performance in the presence of water leg was studied byDoan et al. (1999). They concluded that the presence of water sandshinders oil recovery. Birrell (2001) advised stepping away fromsimulation models to achieve an understanding of steam chamberdevelopment in a heterogeneous reservoir and applying the actualresults from pilot data if available.

Yang and Butler (1992) showed that long reservoir barriers such asshales can cause differences in the advancement velocity of theinterface above and below the barrier. This difference is reduced bythe drainage of heated bitumen through conduction above the barrier.

5.8. SAGD in carbonate reservoir

Unlike with clastic reservoirs, very few attempts were made toexplore the applicability of SAGD in carbonate reservoirs. Yet, eventhose existing attempts are extremely simplied to the extent thatjumping to commercial conclusions would be a fallacy. No studyon any laboratory experiments investigating the physics of theSAGD process in carbonate reservoir (tight matrix with fractures orextremely heterogeneous structure with signicant permeabilitychange) has been identied in the literature. All presented attemptsare of a numerical simulation nature. However, there is no doubt thatthese attempts open a wide window for further investigation.

Das (2007) conducted a 2D simulation model investigating CSS,conventional SAGD and Staggered SAGD in carbonate reservoirs. Hismodel had an extreme heavy fractured reservoir with fracture spacingof 0.54 m. One of his interesting observations was that more steam

went into the system with wider fracture spacing. He attributed thatto a higher fracture tomatrix steam invasion. Beside this, largermatrixis present with wider spacing which implies the need for more energyto heat up the matrix, hence more steam would be injected. He thenreported an average oil rate of 400 bbl/d and 34% recovery in 8 years,which is very optimistic. He also reported an increase in SOR withhigher fracture spacing.

It is widely known that production from fractured carbonatereservoirs is mainly due to matrix-fracture drainage. The productionmechanism in fractured carbonates would be different from the con-ventional SAGD process in loose sands. The matrix-fracture inter-action could be enhanced by two horizontal wells, the upper oneinjecting steam and the lower one collecting the oil, if a good verticalcommunication exists.

5.9. SAGD geomechanics

Ito and Suzuki (1996) observed a large amount of oil drainsthrough the steam chamber when geomechanical changes occur inthe reservoir. Hence, they agged the role of geomechanical change offormation during SAGD as very important. Chalaturnyk and Li (2004)hypothesized that, in a SAGD process the combination of porepressure and temperature effects (resulting from steam injection)creates a complex set of interactions between geomechanics and uidow. In their work they studied, using a coupled reservoir simulation,major geomechanical/reservoir factors which include: (1) initial in-situ effective stress state, (2) initial pore pressure, (3) steam injectionpressure and temperature, and (4) process geometry variables such aswell spacing and wellpair spacing. They stated that it was difcult tobe conclusive about specic geomechanical process relative to themultiphase characteristics of SAGD fromwork at that stage. However,they provided some observations including enhancement of absolutepermeability occurrence in the zones of shear failure. Ito (2007),referring to Chalaturnyk and Li's observations on the geomechanicaleffects, mentioned that: (1) steam chambers stop rising or shrinkingwhen injection pressure is reduced, and (2) steam chambers resumerising when pressure is increased. Ito emphasizes that it is critical tostudy the geomechanical properties of oil sands to understand theSAGD process.

Collins et al. (2002) modied a geomechanical/reservoir simula-tion to incorporate the absolute permeability increase resulting fromthe progressive shear dilation of oil sands. Li and Chalaturnyk (2006)emphasized the shearing process inducing improvement to absolutepermeability. This causes an improvement of effective permeability towater and thereby, the water relative permeability increases due tothe isotropic unloading and shearing process (Li and Chalaturnyk,2006). The movement of uid ahead of the steam chamber was alsoreported by Birrell (2001). Although he did not identify the type ofuid, such geomechanical observations (= water relative perme-ability increase) suggest that this uid movement is of hot water.Singhal et al. (1998) stated that the application of the sanddeformation concept (effect of SAGD geomechanics) to the UTFprojects helped explain the shape and location of the steam chamber,and the strong oil rate performance at the central well AP2, which wasmainly due to ceiling drainage of oil through the steam chamber,rather than gravity drainage along its sides.

6. SAGD operation

6.1. The start-up procedure

Vincent et al. (2004) dened start-up as the period of timebetween the introduction of steam into both the injection andproduction well and when the well pair is converted to SAGDoperation. Proper initialization procedures are required to bringthe entire length of a well pair into active drainage (Nasr et al.,

2000). It is also known that a proper start-up procedure (especially

143A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150circulation) will heat up the wellbore ensuring a better steam qualityat the sand face. The space between the injection and productionwell is heated via conduction. This is achieved by circulating steamin the tubing and out of the annulus (Nasr et al., 2000). Anotherinteresting feature of wellbore steam circulation introduced by Grillset al. (2002) was the recovery of drilling mud lost to the formation.Sasaki et al. (2001) reported that increasing vertical well spacingbetween horizontal wells made the lead time for the gravitydrainage to initiate oil production longer. This was also observedby Hamm and Ong (1995).

Doan et al. (1999) stated that depending on the reservoir, a blowdown phase may be necessary. During the blow down period, thereservoir is depressurized so that the subsequent injection of steamensures higher latent heat. The SAGD process follows the blow downperiod where both injection and production wells are operated atconstant pressure. In general, the initialization phase is slow and oilrates during this phase are low (Nasr et al., 2000). Thismay be becauseof oil being drained through oil expansion only. Chen et al. (2007)showed that start-up time is sensitive to shale presence near the wellregion.

Vincent et al. (2004) conducted a coupled wellbore thermalreservoir simulation study to explore the communication initia-tion for the MacKay River SAGD project. They investigated differentvariables for operating strategy development including: steamcirculation rate and pressure, the magnitude and timing of pressuredifferential implementation between the injector and producer, andoptimum timing for SAGD conversion. Maxwell et al. (2007) used acombination of microseismic and surface deformation monitoringwith an array of tiltmeters to monitor the warm-up phase of a SAGDwell pair. For the case studied, they reported the possibility offracture network creation which is then lled with steam at laterstages. Another way to conduct start-up was done in the Cold Lakeproject where wells were pressurized with a solvent followed by hotwater to push the solvent into formation. Then, normal steamcirculation was conducted in both wells (Donnelly, 1997). Throughtheir numerical model study, Shin and Polikar (2007) found thatthe start-up period increased with decreasing permeability andincreasing well spacing.

By installing a ber-optic distributed temperature system (DTS),Karwchuk et al. (2006) noticed a signicant thermal gradient existsacross the producing well's diameter. From a thermal model (Joshi's)they showed that temperature and magnitude of the ow fromupstream have an impact on the wellbore recorded temperaturesdownstream, and that this cooling has an impact on the sub-coolmeasurements calculated. Thus, the sub-cool temperature may notreect the true rock temperature surrounding the producing welldownstream of an inow, and thus the inow performance at thatpoint. They also noticed that ow is greater initially at the toe of thewell; however, ow improved as the well was further heated.

Nasr et al. (1991, 1998) commented that the steam circulationphase delays oil production. They then proposed two novel methodsto accelerate this phase. The rst is by linking transversely the pairedhorizontal wells with vertical channels to improve liquid drainage,and the second is the addition of naphtha as a steam additive toaccelerate oil drainage. They reported an increase in oil productionand a lower SOR. Showing their experience gained from the Celticeld, Saltuklaroglu et al. (2000) reported expected problems with thesteam circulation method for communication achievement. Theimportant one to mention is that production through annulus wouldresult in high pressure (up to 4600 kPa) above the fracture pressure,which would result in excessive heating of the intermediate casingand cement. They thus decided to go for cyclic start-up process.

It is noticed that the essence of the start-up procedure is tocreate a gravity drainage seed which will grow into a chamber. Thus,conducting successful start-up is essential for a successful SAGD

application.7. Steam quality

Gates and Chakrabarty (2005) stated that the quality of theinjected steam should be as high as possible at the sandface becauseany condensate in the injected uids falls under gravity from theinjector towards the producer and does not deliver a signicantamount of heat to the oil sand. Gates et al. (2005) provided an imageshowing variation in steam quality throughout the steam chamber.This may be a good indication of the temperature prole inside thesteam chamber. In these images, steam quality drops as steam movestowards the edge of the chamber which supports claims that pressureinside the steam chamber is not constant. In terms of the steamquality effect on emulsication, Chung and Butler (1989) reportedfrom a 2D experimental model no signicant difference on emulsi-cation with wet or dry steam. They attributed that to the interfacialactivities and the heating mechanism being the same at the steamfront. The comparison was done on a low pressure injection, and theydid not report any high pressure.

8. Length, spacing and placement of horizontal wells

Wellbore ow restriction at eld conditions was studied by Ongand Butler (1990). They found that the effect of well length on thegravity head was not as signicant as the effect of well size. They alsoreported that the steam chamber slope may be caused by a wellborepressure drop. Nasr et al. (2000) stated that pressure drop along thehorizontal wellbore causes a slope in the steam chamber along thewell. Singhal et al. (1998) suggested that, as the well length in SAGDoperations vary between 5001000 m and because steam chambers inmany situations are unlikely to spread more than 50 m lateral to thewells on either side, exploitation by 500 m long well pairs placed100 m apart may be considered.

Sasaki et al. (2001) observed from a laboratory 2D scaled reservoirvisualization model that setting larger vertical spacing betweeninjection and production horizontal wells resulted in quicker genera-tion of the steam chamber and increased oil production. However, italso led to longer breakthrough time. They concluded from this thatthe interwell spacing (L) can be used as a governing factor to evaluateproduction rate and lead time in the initial stage of the SAGD process.Canbolat et al. (2002) observed through a series of 2D experimentsthat a larger recovery efciency was achieved for smaller injector-to-producer well separations. This was also observed by Chan et al (1997)from a numerical simulation model. However, in their case the reser-voir was thin (20 m) and the injector was placed 3 meters below thetop of the reservoir, thus such results are expected. They also reportedthat even when oil pay is increased, the injector is preferentiallyplaced above the midpoint of the oil pay section. They concluded thatinjector offset may capture an incremental 1015% recovery.

Terez (2002) studied the effect of well placement in a 40 ft thickmodel. He conducted 26.4 ft and 36.6 ft interwell spacing runs andresults did not show a noticeable difference. However, Terez's workwas not conducted on a classical SAGD basis, rather it was a generalstudy of horizontal wells in thermal application for displacement andgravity drainage where SAGD comes as a tertiary recovery process.Shin and Polikar (2007) found from a 2D simulation model thatby increasing the spacing between the injector and the producer,CSOR decreased due to enhanced thermal efciency. By reducing thespacing, the bitumen recovery reached its highest point and thendecreased. They commented that I/P spacing does not affect theultimate recovery. However, we think that such factors are subjectedto time constraints and unfortunately the authors did not providegraphs to make such a comparison.

Das (2005a) stated that over 80% of steam is injected at the heel ofthe well and the remaining steam is injected at the toe, while uid isproduced either from the heel or the toe or from both. This can explain

the tilted steam chambers and raises questions about the uniformity

gave a good comparison between the effects of steam pressure onsteam temperature and hence, its effect on oil production and SOR.

144 A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150of steam chamber growth along the horizontal well. This is backed upwith another graph presented by Das (2005a) which shows that thepressure difference between the injector/producer heels is higherthan between the toes. He comments that this situation may impose agreat potential for steam breakthrough around the heel area. His studyprovided good insight into the crucial role of wellbore design toachieve a successful SAGD. An interesting feature shown in this studywas that 45% of injected heat was produced back to the surface in aconcentric wellbore design during startup. He commented thatwithout the temperature data inside the wellbore, it is difcult todecide whether the vapour quality at the surface is due to counter-current heat transfer or due to the excess steam in the horizontalsection.

Yet there is no optimum well spacing proposed. This is due to thefact that thickness, viscosity, permeability and heterogeneity might begoverning factors in choosing an optimum well spacing. However, itseems that common practice is somewhere between 515 m apart.

9. Subcool temperature (steam trap control)

Doan et al. (1999) stated that steam trap control is used as anoperational control to reduce or prevent steam withdrawal from thesteam zone in the reservoir. Das (2005b) identied three mainadvantages of steam breakthrough prevention to the SAGD process:(1) energy conservation and SOR reduction, (2) reduction of highvapour ow which negatively affects the lifting capacity of the welland surface facilities, and (3) reduction of sands and ne movementthrough the liner which may cause erosion. He then added that due tothe uneven nature of the well trajectory in the eld, it is very difcultto identify, rest alone, and control steam breakthrough.

Ito and Suzuki (1996) reported the optimum temperature for asteam trap control to be between 30 to 40oC. They referred to uiddrainage ahead of the steam chamber, which is 30 to 40 C lower thansteam saturation temperature. Das (2005b) noticed a positive effect ofsub cool temperature after exceeding 20 C. Chen et al. (2007) showedthat when coupling hydraulic fracturingwith steam trap control of theproducer well, injectivity is dramatically improved and an effective oilproduction rate in the reservoir with poor vertical communication isachieved. Edmunds (2000) investigated this feature on 2D and 3Dnumerical models. He found that in a specic case, a steam trap of2030 C was optimum. However, he reached a very importantconclusion, stating that the utility of the (mixed) BHT (Bottom HoleTemperature) as an operating control parameter is doubtful. Thisconclusion was drawn from eld observations where an increasingproduction rate caused the BHT to drop. This observation as hestates contradicts with a widely known assumption that the(mixed) producing temperature is always a monotonic (increasing)function of the production rate. He then advised that operators arebetter off to be cautious when setting production rates with availablehandling capacity of the plant. Another 2D and 3D dynamic modelswere conducted by Ivory et al. (2008) to compare ES-SAGD and SAGDoperating at low pressure. They found that an introduction of 10 Csubcool temperature minimised oil production and SOR. When nosubcool temperaturewas introduced into the system, an increase in oilproductionwas observedwith a greater SOR. They also showed that anincrease in BHP created gas saturation around the production well,which implies the need for a greater subcool temperature setpoint.From screening of Tangleags type projects, Singhal et al. (1998)advised that steam trap constrain on production could be ignoredunder certain circumstances, especially during early periods of steaminjection, to achieve an optimal performance.

9.1. HP (high pressure) vs. LP (low pressure) SAGD

One of the controversial issues in SAGD operations is whether to

operate at high or low pressures. Pooladi-Darvish and Mattar (2002)They stated that a higher steam pressure leads to higher steam tem-perature and lower oil viscosities. This in turn, leads to a higher oilow rate. On the other hand, higher steam pressure leads to lowerthermal efciency and higher steam oil ratio (SOR). Some of thereasons for larger SOR are that steam at higher pressure has less latentheat, more heat will leave the reservoir through the produced uids athigher temperature, and more heat will be left in the steam chamberwhere oil is no longer present. They also added that a higher pressurewould allow natural lift of the produced uids. Edmunds and Chhina(2001) analytically showed the relationship between LP-SAGDand low CSOR. They illustrated a six fold increase in oil rate be-tween atmospheric pressure and 10 MPa. They also conducted aseries of simulation and economic analyses and concluded in favour ofLP-SAGD to HP-SAGD for the following reasons: (1) SAGD economics(mainly due to gas price) is sensitive to CSOR and LP-SAGD improvesCSOR, and (2) ESPs capability improves with LP-SAGD. Ito and Ipek(2005) observed that high pressure operation is important foractivating steam ngers.

Das (2005b) conducted a simulation study where he examined theeffects of lower operating pressure. He identied two advantagesof LP-SAGD over HP-SAGD due to lower operating temperature:(1) reduced silica content in produced uids and (2) lower H2Sproduction. He reached the following conclusions: (1) low pressureoperations appear to be energy efcient, and (2) low pressure opera-tion is more amenable to the application of articial lift. He alsomentioned that reservoir characteristics may lead to uid losseswhich may dictate the operating pressures. These observations by Dasare in agreement with Edmunds and Chhina's (2001) conclusions.

Butler and Yee (2002) reported for Imperial Oil SAGD pilot HWP1 agradual decrease in CSOR with time, which is an indicator of aneconomic SAGD project. Initial operation pressure was of the sameorder of reservoir pressure (5 MPa). Two years later, chamber pressurewas kept at 12 MPa using periodic steaming. They expected that this,along with low operating pressure, made sufcient gas available toproduce improved steam economy through the SAGP2 effect, eventhough gas was not added to the steam.

Sasaki et al. (2001) studied the effect of steam injection pressure ina 2D laboratory scaled visualization model. They stated that highersteam-injection pressure leads to a shorter breakthrough time andhigher expansion rate of the steam chamber as the higher pressuredrop between the injection and production wells (p) results in alarger driving force for oil mobilization. It is worth mentioning thatthey studied the effect of injection pressure by studying (p) sincethey set production pressure to a constant.

Wiltse (2005) introduced a hydraulic gas pump (HGP) as articiallift system solution for LP-SAGD. After eld testing, he reported thatHGP had outperformed the reciprocating rod pump system installedearlier in that well. Li et al. (2006) conducted a coupled simulationbetween EXOTHERM and FLAC to examine favourability between HPand LP-SAGD. They concluded that high pressure SAGD induced higherporosity and permeability with higher oil production. In order toobserve the effects of geomechanics variation and hence permeabilityenhancement due to shear dilation, steam chambers should be opera-ted at or near the minimum total stress, which implies HP-SAGD(Collins et al., 2002; Chalaturnyk and Li 2004; Li and Chalaturnyk2006; Li et al., 2006).

Another study showing favourability of HP-SAGD was conductedby Robinson et al. (2005), who also reported an increase in oil pro-duction. Kisman and Yeung (1995) also showed that operating at lowpressure decreased oil production and improved OSR in a simulationmodel for the Burnt Lake oil sand conditions. Shin and Polikar (2005)

2 SAGP (steam and gas push) an addition of non-condensable gas to steam in order

to minimize heat loss from steam chamber.

145A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150observed through a 2D simulation model study that high pressureinjection gave a better CSOR and CDOR. However, the LP-SAGD gavethe highest NPV. Gates et al. (2005) stated that high injection pressureimplies a relatively high saturation temperature that leads tofavourable bitumen viscosities. This explains the favourability of HP-SAGD in models which do not take into consideration geomechanicaleffects. Bharatha et al. (2005) reported from a simulation andtheoretical study that HP-SAGD reduces the effect of dissolved gassaturation in a SAGD operation. Card et al. (2006) suggested changingthe operating pressure in twomanners: (1) operating at high pressureuntil steam chamber contacts the overburden, and (2) then operate atlow pressure to minimize heat losses. Collins (2007) stated that amajor benet of HP-SAGD is that the produced uids ow to thesurface under reservoir pressure, as long as the pressure differentialbetween the steam chamber and thewellhead exceeds the hydrostatichead of the production uids. He also discussed the failure of LP-SAGDin the Peace River Shell project where SAGD injectionwas at 2700 kPaand SOR ranged from 510. The performance improved afterconversion to CSS with an injection pressure of 11,000 kPa. Heidentied the effect of well depth as a factor in the higher pressurerequirement for deeper projects. He then provided a comparison ofLP and HP-SAGD factors such as lift, heat exchange, water treat-ment, viscosity, wells, heat losses, geomechanical enhancement, andresidual oil.

Thimm (2005) stated that for the most part, the scaling aspectsdue to produced water in SAGD tend to favour LP-SAGD. In unusualcases, where naturally occurring radioactive materials are involvedwith sulphate scales, or where signicant amounts of phosphate arepresent, a higher pressure might be favourable.

9.2. Steam chamber monitor and volume size estimation

In a SAGD process, pressure and temperature monitoring indicate areference of heat transfer process occurring in the reservoir and ofsteam displacement along the completion to the reservoir (Herrera,2001). The inection method (using thermocouples) is considered tobe the classical method in determining the top of the SAGD steamchamber (Birrell and Putnam, 2000). Birrell and Putnam identied thedrawbacks of this method, where in the eld, thermocouple spacingcan limit the ability to make accurate steam rise rate determinations.Also, drops in steam chamber pressure (and in turn, temperature)may result in a situation where temperature in the bitumen saturatedsands above the steam chamber is hotter than in the steam chambergiving the false impression that the steam chamber has risen. Thus,they applied a graphical method utilizing Inverse Conjugate ErrorFunction (ICEF) incorporated with natural log plots to interpretthermocouple data which allowed for the determination of steamchamber position to the centimetre scale. They corrected for transienttemperature effect resulting from steam chamber pressure andtemperature variation by simplifying the operating temperature to anite number of values with step change (Birrell and Putnam, 2000).

Zhang et al. (2005) used 4D seismic and crosswell seismic imagingto monitor and understand steam chamber growth. The imagesobtained showed that less than 100% well length was swept by thesteam chamber and a non uniform steam chamber growth occurred.Shamila et al. (2005) conducted a study aimed towards investigatingthe applicability and subsequent accuracy of the pseudo-steady statemethod in estimating the swept volume/size (uid injectionchamber) under steam injection conditions, with the application ofhorizontal wells using a commercial 3D thermal reservoir simulator.Herrera (2001) suggested the use of microseismic measurements forsteam chamber monitoring by combining it with 3D visualizationtechnology (Herrera, 2001). An example of a well monitored SAGDproject is Phase B at UTF, where eleven temperature observationwellsare available with twenty thermocouples in each well spaced

throughout the McMurry succession (Birrell, 2001).10. Numerical simulation

Edmunds (2000) conducted a 2- and 3D numerical simulationstudy on steam trap control. He reported that 2D simulations werefound to be unrealistically optimistic for general SAGD problems.He also agged a very important fact that well pairs in SAGD are nothomogeneous as assumed, for several reasons including geology,spacing, and skin factor.

Another comment was made by Collins et al. (2002) aboutconventional reservoir simulations; they do not account for geome-chanical enhancement explicitly, but implicitly include the effects byusing permeabilities from highly disturbed core. Li et al. (2006), and Liand Chalaturnyk (2003) worked on a coupled simulation ofEXOTHERM and FLAC and showed a higher oil production than inuncoupled simulation. They inferred that this difference took intoaccount the enhancement on both porosity and permeability incoupled simulation.

An important feature related to the variation in relative perme-ability curves due to temperature was not incorporated in most of thenumerical simulations presented in the literature.

In their steam chamber volume estimation by well test analysis,Shamila et al. (2005) observed that increasing the grid density of thesimulation model greatly increases the precision and accuracy ofswept volume estimation using the pseudo-steady state method. Thisshows the sensitivity of grid density on the accuracy of the results,which is not incorporated in some numerical simulations reported. Infact, some simulation studies used huge coarse grids for eld simu-lation. Yet having a ne grid for eld scalemodels will increase the runtime and depending upon CPU capabilitymay not converge. Thus,dynamic gridding may be a good solution for such cases. Christensenet al. (2004) showed that dynamic gridding reduced the CPU timethree folds while keeping good accuracy in the simulation results.However, they also commented on a gure where they observed anger shape above the steam chamber with dynamic gridding whichwas not shown with ne gridding. They explained this as being aninaccuracy probably introduced by the simple upscaling technique.However, comparing that shape to Sasaki et al.'s (2001) 2D visualiza-tion observations, we wonder if that could actually be a steam ngerrepresented by dynamic gridding, which was not introduced in negridding.

Another remark we can make is that many simulation models,which tried to draw conclusions for SAGD performance in specicreservoirs, use a simple Cartesian model which does not depict actualreservoir heterogeneity. Thus, one has to ensure to use representativereservoir models in SAGD performance analyses using numericalsimulators, as the reservoir heterogeneity may have considerableeffects on the accuracy of the process. A good demonstration of suchan approach is shown by Robinson et al. (2005). McLennan andDeutsch (2005) stated that ow modeling is a transfer functionconverting the geological uncertainty to production uncertainty. Thus,the importance of having a good reservoir static model emergeswhere they further state that the main objective of using geostatisticsto characterize a potential SAGD reservoir is to quantify the uncer-tainty in production performance (Oil Production Rate and SOR) dueto geological uncertainty. They conducted a study where they imple-mented nine different static ranking measures for a potential SAGDreservoir. They concluded that static measures of local connectivitywere the most effective; they referred that to their correlation of OilProduction Rate and SOR being the highest. They stated in their con-clusion that dynamic ranking measures suffer from simplifyingassumptions that mask geological heterogeneity where static rankingmeasures explicitly account for geological heterogeneity modeled bygeostatistics.

Nestor et al. (2001) referred the complexity of optimizing theSAGD process to the time consuming and limited number of objective

function (performance measure) evaluations, a potentially high

146 A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150number of parameters, and a non-linear solution space. They alsonoted that the performance measures (such as net present value,cumulative oil production, and cumulative steam injection), geome-trical parameters (e.g. I/P spacing, well length), and operational para-meters (e.g. subcooling, steam injected enthalpy etc.) requireexpensive numerical simulations beside run time/number consump-tion. This diagnosis seems to be accurate since Gates et al. (2005)reported executing over 100 runs to achieve a SAGD optimization.Nestor et al. (2001) thus proposed a solution for optimisation calledNEGO (neural network based efcient global optimization) whichwould optimize geometrical and operational parameters in a SAGDprocess. They stated that the solution methodology includes theconstruction of a fast surrogate of an objective function whoseevaluation involves the execution of a time consuming mathematicalmodel (i.e. reservoir numerical simulator) based on neural networks,DACE modeling (design analysis of computer experiments), andadaptive sampling.

Tan et al. (2002) conducted a simulation model to investigate theimportance of using a discretized wellbore for SAGD simulation. Theyconcluded that a discretized wellbore model is necessary to predicttemperature and saturation proles for startup and production ofSAGD well pairs. The use of discretized wellbore is becoming acommon practice. This feature enables steam circulation during thestartup period.

11. Experimental pitfalls

All experimental works to our knowledge were performed onsandpack (natural sand or glass beads) models with no exception.Therefore, the evaluation of the experimental efforts will be only onthis type of model.

Ong and Butler (1990) developed a scaling criterion for horizontalwells. They showed that the scaling factor for the radius of thehorizontal well is proportional to the one-fourth power of the productof the ratios of their respective heights of formation and uid viscosityvalues. This geometrical scaling resulted in an impractical (large)laboratory size well. To determine a smaller size well, they thenstudied the wellbore ow resistance which resulted in a more prac-tical wellbore size (Ong and Butler 1990).

Sasaki et al. (2001) found that for a 2D model, heat loss owing tocondensate production had little effect on oil drainage process nearthe steam-chamber interface. They explained this as due to con-densate ow down the side walls in the central region of the steamchamber. They concluded that scaled 2D models are possible toanalyze steam chamber behaviour in SAGD process investigation,except for the amount of single-phase water condensate dissipated atheat loss. Chung and Butler (1987) had the same approach with theintroduction of the dimensionless number. A scaling method of Pujoland Boberg used by Nasr et al. (1996) for their 2D model where theeld and model must be geometrically similar (i.e., width-to-lengthratio and height-to-length ratio must be the same). For otherparameters containing uid and rock properties, terms related tothe transport of heat and mass, and initial and boundary conditionsmust be equal in the eld and lab model. Unlike Pujol and Boberg'sscaling approach, the permeability used in the laboratory experimentwas different from that in the eld. Nasr et al. (1996) commented onits impact as presenting inadequate scaling of capillary pressure. Usinga 2D sand packed model, Nasr et al. (1997) reported that transitionfrom initialization (injection in both wells) to developed SAGD (upperwell injection, lower well production) resulted in a temporary coolingof wells and drop in production. This phenomenon is observed moreduring the laboratory experiments with sand packed models than inwhat actually happens in the eld, since poor model insulation cancause such pitfalls. Although, they reported based on previousobservations that heat loss was negligible, when they injected a

small amount of steam in the producer, better results were observed.Thus, we recommend a mean of heat maintenance in the productionwell during the classical SAGD laboratory experiment. We add thatsand pack models would usually represent, to some extent, sand-stones, which are cohesive by capillary forces or interlocked sandgrains. This may favour sand beads movement with pressure variationshowing false increasing permeability, hence higher production, andlower SOR.

12. SAGD improvement

From what we have seen above, it is obvious that a consistentsteam chamber growth is indispensable for a successful SAGDoperation. Thus, different attempts were made to accelerate andimprove the efciency of this process. From the above observations,we can classify such attempts under two main categories, namely(1) chemical, and (2) geometrical. The chemical approach aimsdirectly for improving heat efciency and reducing the oil waterinterfacial tension to achieve higher production. The geometricalapproach attempts to alternate pressure differential points related towell placement in order to achieve accelerated chamber growth.

12.1. Geometrical attempts

1. Cross-SAGD or X-SAGD: The main feature of this conguration is tocreate a mesh of injection and production wells. The operationtechnique is then to alter the injection and production pointsaccording to strategic timing to minimize steam short circuitingand hence improve steam trap control and production. The crossingpoints between wells are either plugged initially or at a later stagein the project life. According to Stalder (2007) there are twopenaltieswith X-SAGD: (1) Only the points where the wells crossare effective in establishing the initial steam chamber rather than atthe entire length of the wells, (2) the plugging operation requiresan additional cost and poses a serious practical challenge tooperations. One can add to those points that X-SAGD would requirea high initial CAPEXwhere conducting a pilot would be difcult ifnot impossible with fewer wells. This increases the initial risk.Stalder (2007) conducted a comparison study between X-SAGDand SAGD in a numerical simulation model representing expansive,contiguous, and homogeneous bitumen reservoirs. His resultsindicated that XSAGD has the advantage of accelerating recovery,achieving higher thermal efciency by reducing CSOR, andfavouring low pressure to high pressure SAGD.

2. Fast-SAGD (F-SAGD): This technique employs an additionalhorizontalwell aimed to accelerate and improve the steamchambergrowth rate. The horizontal well is placed alongside the well pairwhich operates by CSS. Shin and Polikar (2006a,b, 2007) conducteda 2D simulation model and concluded that the F-SAGD had a lowercumulative steam-oil ratio due to thermal efciency and highercalendar daily oil recovery (CDOR) that was as much as 34% ofclassical SAGD. They showed gures where higher oil recovery wasobtained from the F-SAGD compared to classical SAGD but they didnotmention if thiswas from the SAGDproductionwell or combinedwith the offset well. It is obvious that two wells would producemore oil than one. Thewaywe look at the F-SAGD is as an attempt tocreate a pressure sink in the lower part of the reservoirwhere steamwill compromise between its tendency to rise and the physical factof uid movement from high to low pressure points.

12.2. Chemical attempts

1. Expanding solvent SAGD (ES-SAGD): This novel approach wasdeveloped by Nasr et al (2003). Its main concept is the co-injection ofhydrocarbon additive with steam at low concentrations. Anotherapproach was a hybrid injection of steam and solvent. Solvent would

condense with steam around the steam chamber interface causing oil

147A.-M. Al-Bahlani, T. Babadagli / Journal of Petroleum Science and Engineering 68 (2009) 135150dilution and viscosity reduction. A reduction was reported in thesteam oil ratio by up to 50% and solvent recovery of 9599% in a 2Dexperiment. 2D experiments showed an improved oil recovery,enhanced non-condensable gas production, lower residual oil satura-tion, and faster lateral advancement of heated zones. It was alsoreported that adding non-condensable gases to live oil did notimprove the process because of initial methane presence (Nasr et al.,2001; Nasr et al., 2003; Nasr and Ayodele, 2008; http://www.petro-canada.ca/en/about/636.aspx last visited Jan 12., 2008). From theimages provided by Nasr and Ayodele (2008), one may notice that ES-SAGD temperature was uniformly centred in the middle of the modelcompared to the classical SAGD. This adds another point to the processwhere solvent may operate as insulator reducing heat losses andhence reducing the amount of gas needed. This solvent effect mayhave a greater role than viscosity reduction since at a highertemperature, further viscosity reduction due to solvent addition mayhave only a small effect. This observation was also reported by Deng(2005). He pointed out that the viscosity reduction was mainly fromsteam. He also noticed that a higher addition of propane impedes heattransfer between the steam and the oil zone. Deng (2005) used a 2Dmodel to simulate a steam/propane hybrid process. He observed thatpropane's role was to maintain the reservoir pressure, which raisessome questions about how solvent addition would affect reservoirgeomechanics. Images provided from Deng's (2005) simulationsshowed that the addition of propane converted the steam growthshape from a hand fan shape to a cupcake, where better lateralmovement was noticed compared to classical SAGD.

Gates (2007) conducted a study to determine a suitable injectionstrategy for higher ultimate recovery by visualizing the process in aphase diagram. He concluded that the presence of solvent in ES-SAGDyields a lower operating temperature due to partial pressure effects.He also showed a solvent recovery of around 80%. Ivory et al. (2008)conducted 2D and 3D simulation runs where they examined the effectof diffusion and dispersion on the ES-SAGD process. They observedthat the diffusion coefcient increased with increasing temperature.They referred this to the decrease in the oil viscosity, which isinversely proportional to the diffusion coefcient. Ayodele et al.(2008) conducted laboratory experiments investigating effect of lowpressure ES-SAGD. They compared the single component (propane)case with multi-component systems. They concluded that multi-component solvent yields better eld application for low pressureES-SAGD with lower energy consumption.

This process (ES-SAGD) was tested by Suncor Energy in Burnt Lakeand Firebag. Petro-Canada is also planning to pilot solvent SAGD inMacKay River.

2. Non-condensable gas (NCG) or SAGP: As it was pointed outearlier, Butler (1997) and Butler and Yee (2002) mentioned thepotential problems associated with wasted heat in a mature SAGDproject. Adding non-condensable gas to steam affects both the steamchamber growth rate and shape (Butler and Yee, 2002; Canbolat et al.,2002). For the process of SAGP, Butler (1997) stated that the injectionconditions are such that a very high concentration of non-condensiblegas accumulates in the steam chamber, particularly near the top. In theprocess proposed, the concentration of non-condensible gas (typicallymethane) at the top of the steam chamber is intentionally maintainedat a level over 90 mol% and the dewpoint of this gas is much lowerthan the saturation temperature of steam at reservoir pressure. Thesehigh gas concentrations are maintained by the addition of natural gasto the injection steam. The gas addition mu