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

Journal of Petroleum Science and Engineering 68 (2009) 135–150

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Journal of Petroleum Science and Engineering j o u r n a l h o m e p a g e : w w w. e l s ev i e r. c o m / l o c a t e / p e t r o l

Review

SAGD laboratory experimental and numerical simulation studies: A review of current status 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

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Article history: Received 9 July 2008 Accepted 7 June 2009 Keywords: review of SAGD process pitfalls in numerical and laboratory models effective parameters operational problems future of SAGD

a b s t r a c t With around 7 trillion-barrel reserves and recent increases in oil demand, there is no doubt that there will be a tremendous demand on the development of heavy oil/bitumen (HO-B) reservoirs in the coming decades. Yet the in-situ recovery of HO-B is still not a simple process and there are many technical challenges accompanying it. Two major techniques, namely thermal and miscible, have been considered in HO-B development, along with several other auxiliary methods (chemical, gas, electromagnetic heating, etc.) for different well configurations, with steam assisted gravity drainage (SAGD) being the most popular. Miscible techniques are not highly recognized as a commercial option, while thermal techniques have by far a more stable foundation in the industry. Despite a remarkable amount of laboratory experiments and computational studies on thermal techniques for HO-B, specifically SAGD, there was no extensive and critical literature review of the knowledge gained over almost three decades. We believe that this kind of review paper on the status of the SAGD process will shed light on the critical aspects, challenges, deficiencies and limitations of the process. This will open doors to further development areas, and new research topics. This paper focuses mainly on laboratory and numerical simulation studies, not field experiences. The attempt is to draw a picture of the developments on the physics and technical aspects of the process and its future needs. Specific 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 countercurrent flow), and (d) operational and technical challenges. © 2009 Elsevier B.V. All rights reserved.

Contents 1. 2. 3. 4.

5.

Introduction . . . . . . . . . . . . . . . . . . . . . . . . Background on SAGD process . . . . . . . . . . . . . . . . Mechanism pitfalls . . . . . . . . . . . . . . . . . . . . . Mechanics of SAGD. . . . . . . . . . . . . . . . . . . . . 4.1. Steam chamber rise . . . . . . . . . . . . . . . . . 4.2. Steam fingering theory. . . . . . . . . . . . . . . . 4.3. Co-current and counter-current displacement . . . . . 4.4. Emulsification . . . . . . . . . . . . . . . . . . . . 4.5. Residual oil saturation in steam chamber . . . . . . . 4.6. Heat transfer and distribution through steam chamber 4.7. Analytical models . . . . . . . . . . . . . . . . . . Effects of reservoir properties on SAGD performance . . . . . 5.1. Porosity. . . . . . . . . . . . . . . . . . . . . . . 5.2. Thickness . . . . . . . . . . . . . . . . . . . . . . 5.3. Gas saturation. . . . . . . . . . . . . . . . . . . . 5.4. Permeability . . . . . . . . . . . . . . . . . . . . 5.5. Viscosity and API . . . . . . . . . . . . . . . . . . 5.6. Wettability . . . . . . . . . . . . . . . . . . . . .

⁎ Corresponding author. E-mail address: [email protected] (T. Babadagli). 0920-4105/$ – see front matter © 2009 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2009.06.011

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5.7. 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 . . . . . . . . . . . . . . . . . . . . . . . . . . .

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1. Introduction Reservoir heating is essential in heavy/ultra heavy oil and bitumen (HO-B) recovery. Steam injection is a proven thermal technique to be used for this purpose and it can be achieved through continuous or cyclic (huff-and-puff) injections. Field experience and simulations studies show that performing these techniques are associated with technical difficulties and usually low recovery factors. The steam assisted gravity drainage (SAGD) method was proposed by Butler more than 30 years ago (Butler, 1994b, 1998, 2004a). Due to increased contact area through two horizontal wells, the process was believed to be successful from a technical point of view although economical standpoints are still sceptical. Over a thirty-year period, this technique has been tested successfully, which led many to think of it as a standard technique in HO-B recovery. Obviously, it has some technical and physical restrictions which will be discussed in this paper. Alternatives to this technique have been proposed for unsuitable reservoirs. Those techniques include miscible flooding (VAPEX) or modified versions of SAGD through different configurations of wells or using additives to steam. Due to its suitability for unconsolidated reservoirs that display high vertical permeability, the SAGD technique has received attention in countries with huge HO-B sand reserves like Canada and Venezuela. Although it is a highly promising technique, many uncertainties and unanswered questions still exist and they should be clarified for expansion of SAGD methods to world wide applications. To achieve this, we believe that there is a need to compile and analyze the published data about SAGD studies at different scales and for different purposes. This analysis will provide not only clarifications for uncertainties faced so far, but also an extensive summary of unclear points that eventually lead to defining further research areas. 2. Background on SAGD process SAGD is an abbreviation for steam assisted gravity drainage. It was first developed by Roger Butler and his colleagues in Imperial Oil in the late 1970s. Its main characteristic is introducing steam into reservoirs and producing heated oil using two horizontal wells. Butler described the technique as when steam is injected, a steam saturated zone, called a steam chamber is formed, in which the temperature is essentially that of the injected steam. The steam flows towards the perimeter of the steam chamber and condenses. The heat from the steam is transferred by thermal conduction into the surrounding reservoir. The steam condensate and heated oil flow by gravity to the production well located below. As the oil flows away and is produced, the steam chamber expands both upwards and sideways (Butler,

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1994b). Two types of flow then exist during this process: One at the ceiling of the steam chamber (ceiling drainage; bitumen is pulled away from the front immediately after mobilization where steam rise usually impedes liquid drainage) and the other one along the slopes of the steam chamber (slope drainage; gravity holds mobilized bitumen against the slope where bitumen mobility is controlled by conduction heating 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 are expected to produce in the range of 600–1500 m3/day of the total fluid under normal operating conditions after the initial ramp up period. The corresponding injector well should have the capacity of 400–1200 m3/day cold water equivalent (CWE) of steam injection. 3. Mechanism pitfalls Although the SAGD process looks simple at first sight, several authors pointed out some pitfalls/concerns on the theories of the mechanism. For example, Farouq-Ali (1997) stated that: 1. the theory pertains to the flow of single fluid, 2. steam pressure is constant in the steam chamber, 3. only steam flows in the steam chamber with oil saturation being residual, and 4. heat transfer ahead of the steam chamber to cold oil is by conduction only. He then raised some critical issues to be considered in the project development and field performance assessment: 1. condensate flow: with so much condensate flowing, convection would be expected to be the dominant heat transfer mechanism, 2. geology: geology of the formation can have a profound influence on steam chamber growth (sideway in underground testing facility (UTF) case), 3. 2D vs. 3D models: two important missing factors are flow in the two horizontal wells, and the effect of wellbore, when the wells are drilled from surface rather than from tunnels (refereeing to UTF — Devor project), 4. geomechanical effects: the effects of SAGD on reservoir geomechanics is not well understood. Singhal et al. (1998) mentioned1 that Farouq-Ali pointed out potential 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 Ali in Calgary Jun 17 1998. Unfortunately we could not obtain any recorded material of this talk.

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Fig. 1. Illustration of the SAGD mechanism.

(2) hot effluent/high water-cut production, (3) frequent changes in operating regime (making management of SAGD projects labour intensive), (4) deterioration of production at late stages, and (5) high operating costs. Butler and Yee (2002) stated that despite its attractiveness, SAGD tends to be wasteful of steam because the entire part of the reservoir that is depleted becomes heated to steam temperature, whereas to avoid steam coning, only the reservoir near the production well has to be heated. Heating the upper part of the reservoir to steam temperature is undesirable because of the resulting high loss of heat to the overburden as well as the high heat requirements for the chamber. The loss to the overburden is also increased by the tendency of the steam chamber to creep laterally beneath the reservoir cap (Butler, 1997). Deng (2005) outlined the disadvantages of SAGD as: (1) intensive energy input and excessive CO2 emission, and (2) costly postproduction water treatment. After reviewing published field data, McCormack (2001) listed several problems faced in the field applications: (1) lower than expected drainage rates from average to poor sands; (2) difficulty with installation of liners into the horizontal section of the well; (3) sand production, wellbore scaling, and (4) fluid removal limitations. Based on these evaluations, one can divide SAGD challenges into micro- and macro-scale. Some of these challenges are not inherent to SAGD; they can also be applied to other steam injection techniques, such as geological effects, upscaling (2D/3D models), high SOR, and overburden heat losses. However, such challenges have a relatively profound effect on SAGD; they need more micro/lab-scale studies to further understand the physics of the process and to use them for better industrial applications. 4. Mechanics of SAGD 4.1. Steam chamber rise The SAGD concept is based on steam chamber development, as production is mainly from the chamber/heated-oil interface. Thus, the development and analysis of the steam chamber growth has received a great deal of attention by scientists studying SAGD. Yet, it seems that the complete picture of the steam chamber development process is not fully represented due to different processes occurring at the same time; namely, counter-current flow, co-current flow, water imbibition, emulsification, steam fingering and dimensional movement (lateral vs. vertical). In other words, the complexity is due to the fact that a lighter fluid (steam) is trying to penetrate into a heavier fluid (HO-B) above it. Ito and Ipek (2005) observed from field data that the steam chamber grew upwards and outwards simultaneously like the expansion of dough during baking. The recent understanding of the SAGD process endorses the idea that steam chamber is not connected to the producer; rather a pool of liquid exists above the production well. Gates

et al. (2005) identified the advantage of having such a pool by preventing the flow of injected steam into the production well. Thus, it is of primary importance to clarify the relative effects of each parameter affecting the movement and the shape of the steam chamber. 4.2. Steam fingering theory From a sand pack lab experiment, Butler (1994b) observed that the rise of the steam chamber does not advance as a flat front, rather as a series of separate and ragged fingers. He referred to the occurrence of these fingers as being due to instability created by rising lighter steam below the heavy oil. Thus, understanding steam finger theory is crucial to understanding steam chamber rise processes. Depicting a rectangular boundary, Butler (1987) hypothesized steam chamber development as follows: Steam flows upward from the lower boundary providing heat to rise the reservoir temperature to steam temperature. Heated material drains through the lower boundary as a number of streams. The velocity at which the residual oil leaves the system is that of the steam chamber rise. The entering steam moves at a higher velocity than the chamber in order to pass through the lower boundary. At the very top of the chamber steam fingers move into the relatively cold reservoir and heat the cold oil through conduction. According to Ito and Ipek (2005), many observations in the UTF Phase A and B, Hanginstone and Surmount projects are now clearly understood through the steam fingers concept. They hypothesized that the specific nature of steam fingering phenomena during SAGD operation may cause steam chamber deviation from usual behaviour (stop and resume, shrinkage or even disappearance). Sasaki et al. (2001) provided images where steam fingering can clearly be seen on their 2D experimental model. They also showed an increase in the ceiling instability, hence fingering, due to intermittent steam stimulation of the lower horizontal producer. These observations imply that it is very important to consider steam fingering as a method of steam movement inside the reservoir. Steam fingering occurs in a vertical manner whereas a buoancy advantage of steam to oil mainly drives the process. However, chamber growth disturbance does not only occur vertically and this triggers a question: can steam fingering occur laterally? This question may be backed up with geomechanical investigation results of increasing water 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 recovery process lies in the salient role of moving condensing boundaries and counter-current flows. Counter-current flow between heated heavy oil

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and bitumen occurs at the top of a rising steam chamber where steam fingers rise and heated heavy oil falls (Chung and Butler, 1987; Butler, 1987, 1994a). Nasr et al. (2000) published a paper highlighting steam oil emulsion counter-current flow and the rate of propagation of the steam chamber. They used a cylindrical experimental model and adiabatic control system, and a numerical model to simulate SAGD counter-current flow and to determine the sensitivities of different parameters. They concluded that for a given permeability, the countercurrent steam front propagation rate is a linear function of time. They observed that the time taken for counter-current steam front to propagate to a specific distance is much more than time taken by a cocurrent front, where drainage condensate was impeding the advance of the counter-current front. After a history matching of the steamwater counter-current and co-current relative permeability curves, they found that there was a significant difference between countercurrent and co-current relative permeabilities. They argued that this may be the result of a coupled flow between the phases. Hence, the following question arises: can the existing formulation of numerical simulation capture this important character? The steam interface advancement seems to be due to a combination of both co-current and counter-current flow, which shows the importance of a clear path presence for clean sand with no buffles, as well as how reservoir heterogeneity would have a profound impact on such processes. Another issue we question is whether or not counter-current movement also happens within a pore. When steam rises up inside the pore, preferentially in the middle portion, does the oil drain down through the sides closer to the grain due to wettability and connate water issues? Or does the process take place in a convective manner? What is the effect of injection pressure/rate on this process? 4.4. Emulsification Chung and Butler (1987) stated that the production of in-situ thermal recovery of heavy oils always occurs in the form of water in oil emulsion. This is much more viscous than the oil itself. They conducted a laboratory study to elucidate the geometrical effect of steam injection on the water/oil emulsion of the produced fluid from a SAGD process. They performed their experiment in two schemes. The first scheme consisted of a steam injector slightly above a producer at the base of the formation. The second scheme consisted of a producer at the base of the formation and a vertical circulating steam injector perforated near the top of the formation. They concluded that “much higher water/oil emulsion content was found in the produced fluid when the steam chamber was rising in the experiment with bottom steam injection than with injection at the top”. The rate of recovery was higher in the operation with top injection. This is probably due to the fact that an increase in water/oil emulsion ratio increases the fluid viscosity, hence a reduction in oil production is expected. However, they also noticed that when the steam chamber spreads sideways, a two phase stratified flow of steam and heated heavy oil occurs at which steam flows sideways to the interface, and heated heavy oil flows down, below and along the interface, which dramatically reduces the water/oil emulsion ratio (Chung and Butler, 1987). They later extended their work to include other factors which may affect water/oil emulsification ratio such as initial connate water (0% and 12.5%), steam quality, and pressure variation (153 kPa–3.55 MPa) (Chung and Butler, 1989). For initial connate water, they noticed a higher water/oil ratio emulsion when Swi = 0% than Swi = 12.5%. They commented that there is less tendency for water to condense as droplets on the surface of oil when enough connate water is available. As the droplets of water condense on oil, they become “buried” because of the spreading characteristics 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 is

because the interfacial activity at the steam front and the heating mechanism of the bitumen are the same for both cases. They observed no major difference as a result of pressure variation. This also applies to the effect of particle size in the porous matrix where no significant variation was found. Sasaki et al. (2001) visualized water/oil emulsion at the boundary of the steam chamber in a 2D laboratory scaled model. They noticed a ±25% fluctuation in the ratio after steam breakthrough and chamber rise. Understanding the water/oil emulsion is crucial not only from a reservoir engineering point of view, but also from a production technology perspective as well. 4.5. Residual oil saturation in steam chamber Butler (1994a) observed that major oil flow happened on the chamber sideways rather than through it. He explained this observation by two hypotheses; (1) residual oil saturation is too low inside the steam chamber to allow for any oil movement, and (2) due to water condensate between steam and oil, water imbibition and interfacial tension support the oil to drain laterally. Walls et al. (2003) studied residual oil saturation in steam chambers using a numerical model. Their work consisted of two main parts: (1) sensitivity tests done on the shapes and the end points of the two phase-relative permeability curves, and (2) krog relative permeability curve adjustment to match theoretically determined residual oil saturation. They concluded that water relative permeability and oil relative permeability in the gas–oil system are the main factors that determine the magnitude and the shape of the oil saturation curve as a function of time. They also concluded that residual oil saturation increases at lower SAGD operating pressures. Many of the numerical simulation models reported failed to show their application of changes in relative permeability curves due to temperature change. This will be discussed further in the “Simulation” section. Pooladi-Darvish and Mattar (2002) stated that some of the reasons for larger residual oil saturation are that steam at higher pressures has less latent heat, more heat will leave the reservoir through the produced fluids at higher temperatures, and more heat will be left in the steam chamber where oil is no longer present. What is critical here is the amount of oil left inside the steam chamber. As the steam/oil interface passes through the reservoir, production occurs mainly by co/counter-current. As the interface progresses, the reduction of residual oil saturation is mainly due to the steam–oil gravity difference, which is a very slow process. Eventually, residual oil saturation will become nil, but the question is, how long will it take to reach that point? 4.6. Heat transfer and distribution through steam chamber Understanding the heat transfer through the steam chamber is also critical. As mentioned earlier, Farouq-Ali (1997) criticized the assumption that only thermal conduction exists in SAGD. In response to that critique, Edmunds (1999) stated that based on the associated change in enthalpy, the liquid water could carry and deposit 18% of the heat of condensation of the same water. Convection due to oil is around 1/5 of this and conduction to carry the remaining 78%. He then evaluated the convection role due to water streamline being almost parallel to isotherms of less than 5%. This was also emphasized by Edmunds (1999) who stated that except for the very near vicinity of the liner or anywhere live steam penetrates, heat transfer in the mobile zone is dominated by conduction, not convection. Gates et al. (2005) provided images of steam quality and temperature of the steam chamber from a simulation study. Comparing these pictures, one can clearly see that temperature is “almost” constant while steam quality varies significantly. This supports the 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

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boundaries of the steam chamber. They stated that the usefulness of this method is that steam quality profiles provide the means to examine 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 comments on the outcome by stating that in general the heat remaining within the steam chamber, per unit production of oil, will be lower if the steam temperature is lower (i.e., the chamber pressure is lower) or if the oil saturation is higher (i.e., there is less reservoir to be heated per m3 of oil). The latter is very important in determining the performance of a reservoir; high (initial) oil saturation is always desirable. Yee and Stroich (2004) showed that, after 5 years of Dover project phase B, the amount of injected heat in the chamber was 32.2%, and outside of the chamber, 34.7%. The rest (33.1%) was reproduced. It can be seen that almost one third of heat injected is reproduced. We believe that this may have a beneficial effect as heat may prevent wax deposition inside the tubing and may maintain a lower oil viscosity for uplifting if no emulsion is created.

reservoir properties such as porosity, thickness and initial oil saturation. Chen et al. (2007) also commented on Butler's theory where they addressed that the theory is based on simplifying assumptions, such as that the steam chamber pressure remains at the original reservoir pressure and the chamber must remain connected to the producer. Birrell (2001), on the other hand, stated that Butler's equation was shown to accurately predict the performance of SAGD in the field. Reis (1992, 1993) stated that the limitation to the Butler's model is its complexity; it requires an iterative solution to a set of equations to calculate the production rate. He provided linear and geometrical models for oil production where he introduced a dimensionless temperature coefficient to the denominator. He showed that Butler's model overpredicts oil production compared to his model. He also provided energy balance and steam oil ratio equations. However, his model does not predict production during the rise of the steam chamber.

4.7. Analytical models

5.1. Porosity

Butler (1987) developed an approximate expression to predict the steam chamber rising rate and the dimensions of the steam fingers. He concluded that the rise rates are proportional to reservoir permeability and are strong functions of steam temperature and oil viscosity. Later work was done by Edmunds et al. (1989). They criticized the dependency of Butler's (1987) approach on certain geometric simplifications which restrict the generalization of the model. They continued their numerical analysis based on the UTF Phase A test. They presented a good analysis of 1-D ceiling drainage and its relation to SAGD cases. Butler (1994a) described the result of their work as a prediction of the drainage rate using Darcy's equation with counter-current flow and the incorporation of relative permeability effects. However, he criticized Edmunds et al.'s (1989) work in terms of geometrical and theoretical aspects. From one of Butler's works (1997) we can identify the evolution of Butler's theory in three stages: (1) the original model, (2) the TanDrain & LinDrain model, and (3) the steam rising model. Despite the extensive theoretical input to evolve these equations, all modifications presented are concerned with the shape, height and growth of the steam chamber. To be more specific, the original Butler theory concentrated on obtaining a relationship between the drainage rate and the drainage height independent of interface shape or its horizontal extension. Later, the dependency on the shape of the interface and boundaries were taken into account. Butler then provided a guideline on how to analytically calculate oil production through the following set of equation which we summarized on the flow chart given in Fig. 3. As seen in Fig. 3, the equations tend to have quite a number of simplifications, some of which mentioned by Farouq-Ali (1997). However, a very important feature can be drawn from Butler's theory evolution: the huge dependency of analytical models to steam chamber growth and shape. These factors — as we have seen earlier — are heavily dependent on reservoir characteristics, especially in heterogeneous reservoirs. Butler's formulation also includes the effect of

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

5. Effects of reservoir properties on SAGD performance

5.2. Thickness Several studies report that an increase in oil production was noticed with an increase in oil pay thickness (Sasaki et al., 2001; Chan et al., 1997; Shin and Polikar, 2007; Singhal et al., 1998; Edmunds and Chhina, 2001; McCormack, 2001). Edmunds and Chhina (2001) stated that zones less than 15 m thick are unlikely to be economic. Most of the work done to draw this conclusion is based on the fact that thin reservoirs increase thermal losses resulting in higher SOR. However, this conclusion is subject to a variable understanding of what is “thick” and what is “thin”. Also, the steam chamber growth behaviour — due to other geological parameters — may have an effect on such conclusions. For example, cupcake like steam chamber growth (laterally and sideways) would not see much effect of reservoir thickness, while hand fan like steam chamber growth (laterally then sideways) in a thick reservoir might take much more time for the steam chamber to grow. Other complicated process such as steam fingering, emulsification, and prevailing counter-current flow may result in the fluctuation/decrease of oil production. Thus, there may be an ultimate thickness for each reservoir which may dictate where the injector is placed from the top of the reservoir. This is governed by the steamchamber growth behaviour which is in turn governed by other reservoir charecterstics such as kv/kh. 5.3. Gas saturation

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

Nasr et al. (2000) studied the effect of initial methane saturation on the advancement of a steam front in an experimental sand packed

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Fig. 3. Flow chart of Butler's analytical model for calculating oil production from a SAGD operation.

model. With the presence of initial methane saturation, they noticed the faster movement of steam front at present temperature values on a given time. However, as the steam front entered the region of methane saturation, the propagation rate declined as the methane mole fraction increased in the gas phase. Canbolat et al. (2002) observed that the initial presence of n-butane had a positive effect on the process. They explained this by the reduction of oil viscosity due to gas presence. Bharatha et al. (2005) conducted a study on dissolved gas in SAGD by means of theory and simulation. They stated in their conclusion that the effect of dissolved gas on SAGD is to reduce the bitumen production rate. They also showed that operating pressure plays a greater role in reducing the effect of dissolved gas saturation presence. 5.4. Permeability McLennan et al. (2006) stated that the predicted flow performance of SAGD well pairs is sensitive to the spatial distribution of per-

meability. After experimental (sand packed core) and numerical model investigations, Nasr et al. (2000) noted that the effect of liquid convection ahead of the steam front can provide better heating for the 10 Darcy permeability case than for the 5 Darcy case. They also observed that there was evidence that steam temperature inside 5 Darcy sand was lowered by about 3 °C than that for the 10 Darcy sand for a given steam injection temperature. They argued that this might be a result of higher capillary pressure for the 5 Darcy case. They also reported that the propagation rate of the steam front is not a linear function of permeability. In a 2D simulation model investigating SAGD in a carbonate reservoir, Das (2007) reported no significant change in production due to matrix permeability at earlier stages and faster decline for low permeability at later stages. He referred this to the possibility of matrix production which occurs primarily by imbibition and thermal expansion. However, by looking at the examination range (10–50 mD) it can be seen that the range is too small to study the effect of permeability. Kisman and Yeung (1995), on the other hand, found

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from a simulation model that decreasing the vertical permeability resulted in a significant decrease in CDOR (calendar day oil rate) and OSR initially. But an increase in both CDOR and OSR was noticed at later stages. It was also shown by Shanqiang and Baker (2006) in a 3D simulation model that decreasing permeability reduced the initial oil production but later increased it dramatically. McLennan et al. (2006) presented a permeability modeling procedure. Their methodology consists of two major steps: (1) debiasing and 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 outlined two key features of their methodology as (1) the integration of missing lower porosities or increased shaliness into measurements from dilated and preferentially sampled core which is also dilated, and (2) the translation of porosity-permeability relationships at the core scale to the SAGD flow simulation scale (McLennan et al., 2006). Nasr et al. (1996) showed a decrease in OSR due to a decrease in permeability through their numerical modeling study. Collins et al. (2002) stated that laboratory tests on specimens of undisturbed oil sands have conclusively proven that absolute permeability increases dramatically with dilation. They also showed that shear dilation of oil sands enhances permeability in the SAGD process. Shin and Polikar (2007) observed that higher permeability resulted in a higher ultimate recovery as well as lower CSOR. They also noticed that fining upward sequence showed better SAGD performance due to lateral steam propagation (cupcake growth). Nasr et al. (1997) reported from a 2D sand packed model that for low permeability reservoirs, the steam zone was localized around the injection well. The low permeability reduced the drainage of oil and growth of the gravity cell. Mukherjee et al. (1994) observed that the presence of a low permeability zone between the injector and producer may cause water hold up between the wells where water is not well drained. Butler (2004b) studied the effects of reservoir layering. He stated that in layered reservoirs with permeability ratios less than about two, the height average permeability should be used in the Lindrain equation. He then suggested that in the situation described above, steam should be injected in the more permeable area. He also stated that if the more permeable layer is at the bottom, a steam swept zone will tend to undermine the upper layer. If the more permeable layer is at the top and the permeability ratio is greater than two, the penetration of the steam into the lower layer will be delayed and oil will move through the lower region driven by the imposed pressure gradient. Effects on oil rate are not very severe at least until the upper layer 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 recovery rate and injectivity improved with lower viscous oil. Shanqiang and Baker (2006) studied the effect of oAPI on SAGD performance and observed that increasing oAPI reduced oil production. Singhal et al. (1998) outlined the effects of viscosity on geometrical and operational parameters in a screening study. They advised that from viscosities less than 35,000 mPa s and thickness more than 15 m, using vertical steam injectors staggered around horizontal producers was a feasible recovery strategy. Also, the relaxation of subcool constrain under certain circumstances may be feasible. For viscosities above 65000 mPa s, the use of horizontal injectors and subcool constrain was determined to be critical. Larter et al. (2008) studied the impact of variation in heavy oil heterogeneity in reservoirs through 3D simulation. They concluded that the impact of dramatic oil viscosity variations in a heavy oil reservoir on reservoir productivity depends on the recovery method. They showed that in terms of productivity and compositional varations of the oil phase, the impact is large on SAGD and CSS when initial viscosity gradient with depth is taken into

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account. They observed a reduction of 30% for the top oil end member and 75% for the bottom oil end member. 5.6. Wettability Few studies were conducted to study this crucial reservoir property. Das (2007) used a 2D numerical simulator and observed that lower oil recovery is obtained with oil-wet-carbonate-reservoirs and with no capillary pressure. However, the role of wettability alteration from water-wet to oil-wet was demonstrated to have a positive impact in thermal recovery around the production wellbore region (Isaacs et al., 2001; Yuan et al., 2002). In their patent document Isaacs et al. (2001) demonstrated that oil-wet sand in the near region of the production well (by treatment with wettability alteration chemicals), when coupled with SAGD, causes an increase in recovery compared to classical SAGD. Following up on that patent, Yuan et al. (2002) studied the potential impacts of altering wettability near a production well on SAGD using a field scale numerical model to clarify the possible key parameters. They concluded that (1) the bigger the region around the production well being oil-wet, the better the oil production was, at least in early stages of the steam chamber, (2) more than near well effect was observed from alternating wettability in a local zone near the production well, (3) SOR was lowered due to constant bottom hole pressure, and (4) it might be beneficial not to keep the oil-wet zone at its wettability status for the entire operation period to reduce the cost of wettability-changing agent. However, they noticed water accumulation between the water-wet and oil-wet zone. This water blockage phenomenon was caused by creation of oil-wet zone. This diagnose is very relevant since water flow through the oilwet region will be impeded due to the absence of phase lubricant which may also be a factor influencing SOR. This water blockage would probably have a negative impact on steam chamber growth and maintenance which may be another reason why oil-wet region may be a temporary solution. These observations lead us to raise a few flags on the role of ESSAGD in oil-wet reservoirs and how solvent addition — with high temperature effect — would cause wettability alteration, and hence affect gravity drainage performance. These observations and thoughts should prompt further effort to understand the effect of wettability and/or wettability alteration on SAGD and potential performance optimization. 5.7. Heterogeneity Yang and Butler (1992) studied the effect of reservoir heterogeneities on heavy oil recovery by SAGD. Their approach was to use a two dimensional sand packed model. They limited their study to two field conditions: (1) a reservoir with thin shale layers, and (2) a reservoir containing horizontal layers of different permeabilities. For the two layer reservoir they studied two cases: (1) a high/low permeability reservoir, and (2) a low/high permeability reservoir. They noticed that the high/low permeability was acting like a whole high permeability reservoir. In the low/high permeability case, they noticed an undermining of steam in the lower (high permeability) layer. This effect decreased with time. They then compared the cumulative oil production from the previous setup to all low permeability setups and noticed little difference. They noted two effects cancelling each other, namely (1) undermining steam enhanced gravity drainage of bitumen above the inter-layer surface, (2) a higher water/oil emulsion was expected above the undermining steam causing an increase in the viscosity of the produced fluid. For reservoirs containing a horizontal barrier, they conducted two cases with: (1) top steam injection, and (2) bottom steam injection. They also studied the reservoir dipping effect for the low/high permeability setup. They controlled the dipping by tilting the model upward and downward by 5°. A reservoir dipping upward gave a higher production than a

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reservoir dipping downward. The reason for this, they commented, is that the production rates are mainly controlled by the total drainage height and placing the production well at the lowest location of a dip reservoir obtained the maximum height. They then studied the effect of barrier length for each case (short horizontal barrier, and long horizontal barrier). With a top steam injection, the presence of a short horizontal barrier had no effect on the general performance. They then conducted several experiments on long barriers by changing the location of the injection and production well relative to the barrier. They concluded that a long horizontal barrier decreases the production rate but not as much as expected in some configurations. They also observed that heated bitumen above the barrier may not be produced even though it is hot because of the steam pressure holding up the oil at the bottlenecks to the flow (Yang and Butler, 1992). This confirms that SAGD is heavily dependent on a good communicating reservoir. Chen et al. (2007) conducted a numerical simulation study on stochastic of shale distribution Near Well Region (NWR) and Above Well region (AWR). They stated that drainage and flow of hot fluid within the NWR has a short characteristic length and is found to be very sensitive to the presence of shale that impairs vertical permeability. The AWR affects the (vertical and horizontal) expansion of the steam chamber. It is of characteristic flow length on the order of half of the formation height. SAGD performance is affected adversely only when the AWR contains long continuous shale or a high fraction of shale. They also studied the potential improvement of SAGD performance by hydraulic fracturing by identifying three cases: horizontal fracture, vertical fracture parallel to, and vertical fracture perpendicular to the well. In some cases, they observed an improvement in the oil steam ratio by a factor of two when a vertical hydraulic fracture was introduced. They also concluded that vertical hydraulic fractures are predicted to enhance SAGD performance more dramatically in comparison to — horizontal — hydraulic fracture. Finally, they stated that a vertical hydraulic fracture along the well direction is superior to one perpendicular to the well direction. Zhang et al. (2005) showed 4D seismic amplitude and crosswell seismic images of steam chamber growth at the Christina Lake SAGD project which identified the effects of reservoir heterogeneity. The SAGD performance in the presence of water leg was studied by Doan et al. (1999). They concluded that the presence of water sands hinders oil recovery. Birrell (2001) advised stepping away from simulation models to achieve an understanding of steam chamber development in a heterogeneous reservoir and applying the actual results from pilot data if available. Yang and Butler (1992) showed that long reservoir barriers such as shales can cause differences in the advancement velocity of the interface above and below the barrier. This difference is reduced by the drainage of heated bitumen through conduction above the barrier. 5.8. SAGD in carbonate reservoir Unlike with clastic reservoirs, very few attempts were made to explore the applicability of SAGD in carbonate reservoirs. Yet, even those existing attempts are extremely simplified to the extent that jumping to “commercial conclusions” would be a fallacy. No study on any laboratory experiments investigating the physics of the SAGD process in carbonate reservoir (tight matrix with fractures or extremely heterogeneous structure with significant permeability change) has been identified in the literature. All presented attempts are of a numerical simulation nature. However, there is no doubt that these 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. His model had an extreme heavy fractured reservoir with fracture spacing of 0.5–4 m. One of his interesting observations was that more steam went into the system with wider fracture spacing. He attributed that

to a higher fracture to matrix steam invasion. Beside this, larger matrix is present with wider spacing which implies the need for more energy to heat up the matrix, hence more steam would be injected. He then reported 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 with higher fracture spacing. It is widely known that production from fractured carbonate reservoirs is mainly due to matrix-fracture drainage. The production mechanism in fractured carbonates would be different from the conventional SAGD process in loose sands. The matrix-fracture interaction could be enhanced by two horizontal wells, the upper one injecting steam and the lower one collecting the oil, if a good vertical communication exists. 5.9. SAGD geomechanics Ito and Suzuki (1996) observed a large amount of oil drains through the steam chamber when geomechanical changes occur in the reservoir. Hence, they flagged the role of geomechanical change of formation during SAGD as very important. Chalaturnyk and Li (2004) hypothesized that, in a SAGD process the combination of pore pressure and temperature effects (resulting from steam injection) creates a complex set of interactions between geomechanics and fluid flow. In their work they studied, using a coupled reservoir simulation, major geomechanical/reservoir factors which include: (1) initial insitu effective stress state, (2) initial pore pressure, (3) steam injection pressure and temperature, and (4) process geometry variables such as well spacing and wellpair spacing. They stated that it was difficult to be conclusive about specific geomechanical process relative to the multiphase characteristics of SAGD from work at that stage. However, they provided some observations including enhancement of absolute permeability occurrence in the zones of shear failure. Ito (2007), referring to Chalaturnyk and Li's observations on the geomechanical effects, mentioned that: (1) steam chambers stop rising or shrinking when injection pressure is reduced, and (2) steam chambers resume rising when pressure is increased. Ito emphasizes that it is critical to study the geomechanical properties of oil sands to understand the SAGD process. Collins et al. (2002) modified a geomechanical/reservoir simulation to incorporate the absolute permeability increase resulting from the progressive shear dilation of oil sands. Li and Chalaturnyk (2006) emphasized the shearing process inducing improvement to absolute permeability. This causes an improvement of effective permeability to water and thereby, the water relative permeability increases due to the isotropic unloading and shearing process (Li and Chalaturnyk, 2006). The movement of fluid ahead of the steam chamber was also reported by Birrell (2001). Although he did not identify the type of fluid, such geomechanical observations (= water relative permeability increase) suggest that this fluid movement is of hot water. Singhal et al. (1998) stated that the application of the sand deformation concept (effect of SAGD geomechanics) to the UTF projects helped explain the shape and location of the steam chamber, and the strong oil rate performance at the central well AP2, which was mainly 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) defined start-up as the period of time between the introduction of steam into both the injection and production well and when the well pair is converted to SAGD operation. Proper initialization procedures are required to bring the entire length of a well pair into active drainage (Nasr et al., 2000). It is also known that a proper start-up procedure (especially

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circulation) will heat up the wellbore ensuring a better steam quality at the sand face. The space between the injection and production well is heated via conduction. This is achieved by circulating steam in the tubing and out of the annulus (Nasr et al., 2000). Another interesting feature of wellbore steam circulation introduced by Grills et al. (2002) was the recovery of drilling mud lost to the formation. Sasaki et al. (2001) reported that increasing vertical well spacing between horizontal wells made the lead time for the gravity drainage to initiate oil production longer. This was also observed by Hamm and Ong (1995). Doan et al. (1999) stated that depending on the reservoir, a blow down phase may be necessary. During the blow down period, the reservoir is depressurized so that the subsequent injection of steam ensures higher latent heat. The SAGD process follows the blow down period where both injection and production wells are operated at constant pressure. In general, the initialization phase is slow and oil rates during this phase are low (Nasr et al., 2000). This may be because of oil being drained through oil expansion only. Chen et al. (2007) showed that start-up time is sensitive to shale presence near the well region. Vincent et al. (2004) conducted a coupled wellbore thermal reservoir simulation study to explore the communication initiation for the MacKay River SAGD project. They investigated different variables for operating strategy development including: steam circulation rate and pressure, the magnitude and timing of pressure differential implementation between the injector and producer, and optimum timing for SAGD conversion. Maxwell et al. (2007) used a combination of microseismic and surface deformation monitoring with an array of tiltmeters to monitor the warm-up phase of a SAGD well pair. For the case studied, they reported the possibility of fracture network creation which is then filled with steam at later stages. Another way to conduct start-up was done in the Cold Lake project where wells were pressurized with a solvent followed by hot water to push the solvent into formation. Then, normal steam circulation was conducted in both wells (Donnelly, 1997). Through their numerical model study, Shin and Polikar (2007) found that the start-up period increased with decreasing permeability and increasing well spacing. By installing a fiber-optic distributed temperature system (DTS), Karwchuk et al. (2006) noticed a significant thermal gradient exists across the producing well's diameter. From a thermal model (Joshi's) they showed that temperature and magnitude of the flow from upstream have an impact on the wellbore recorded temperatures downstream, and that this cooling has an impact on the sub-cool measurements calculated. Thus, the sub-cool temperature may not reflect the true rock temperature surrounding the producing well downstream of an inflow, and thus the inflow performance at that point. They also noticed that flow is greater initially at the toe of the well; however, flow improved as the well was further heated. Nasr et al. (1991, 1998) commented that the steam circulation phase delays oil production. They then proposed two novel methods to accelerate this phase. The first is by linking transversely the paired horizontal wells with vertical channels to improve liquid drainage, and the second is the addition of naphtha as a steam additive to accelerate oil drainage. They reported an increase in oil production and a lower SOR. Showing their experience gained from the Celtic field, Saltuklaroglu et al. (2000) reported expected problems with the steam circulation method for communication achievement. The important one to mention is that production through annulus would result in high pressure (up to 4600 kPa) above the fracture pressure, which would result in excessive heating of the intermediate casing and cement. They thus decided to go for cyclic start-up process. It is noticed that the essence of the start-up procedure is to create a gravity drainage seed which will grow into a chamber. Thus, conducting successful start-up is essential for a successful SAGD application.

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7. Steam quality Gates and Chakrabarty (2005) stated that the quality of the injected steam should be as high as possible at the sandface because any condensate in the injected fluids falls under gravity from the injector towards the producer and does not deliver a significant amount of heat to the oil sand. Gates et al. (2005) provided an image showing variation in steam quality throughout the steam chamber. This may be a good indication of the temperature profile inside the steam chamber. In these images, steam quality drops as steam moves towards the edge of the chamber which supports claims that pressure inside the steam chamber is not constant. In terms of the steam quality effect on emulsification, Chung and Butler (1989) reported from a 2D experimental model no significant difference on emulsification with wet or dry steam. They attributed that to the interfacial activities and the heating mechanism being the same at the steam front. The comparison was done on a low pressure injection, and they did not report any high pressure. 8. Length, spacing and placement of horizontal wells Wellbore flow restriction at field conditions was studied by Ong and Butler (1990). They found that the effect of well length on the gravity head was not as significant as the effect of well size. They also reported that the steam chamber slope may be caused by a wellbore pressure drop. Nasr et al. (2000) stated that pressure drop along the horizontal wellbore causes a slope in the steam chamber along the well. Singhal et al. (1998) suggested that, as the well length in SAGD operations vary between 500–1000 m and because steam chambers in many situations are unlikely to spread more than 50 m lateral to the wells on either side, exploitation by 500 m long well pairs placed 100 m apart may be considered. Sasaki et al. (2001) observed from a laboratory 2D scaled reservoir visualization model that setting larger vertical spacing between injection and production horizontal wells resulted in quicker generation of the steam chamber and increased oil production. However, it also led to longer breakthrough time. They concluded from this that the interwell spacing (L) can be used as a governing factor to evaluate production rate and lead time in the initial stage of the SAGD process. Canbolat et al. (2002) observed through a series of 2D experiments that a larger recovery efficiency was achieved for smaller injector-toproducer well separations. This was also observed by Chan et al (1997) from a numerical simulation model. However, in their case the reservoir was thin (20 m) and the injector was placed 3 meters below the top of the reservoir, thus such results are expected. They also reported that even when oil pay is increased, the injector is preferentially placed above the midpoint of the oil pay section. They concluded that injector offset may capture an incremental 10–15% recovery. Terez (2002) studied the effect of well placement in a 40 ft thick model. He conducted 26.4 ft and 36.6 ft interwell spacing runs and results did not show a noticeable difference. However, Terez's work was not conducted on a classical SAGD basis, rather it was a general study of horizontal wells in thermal application for displacement and gravity drainage where SAGD comes as a tertiary recovery process. Shin and Polikar (2007) found from a 2D simulation model that by increasing the spacing between the injector and the producer, CSOR decreased due to enhanced thermal efficiency. By reducing the spacing, the bitumen recovery reached its highest point and then decreased. They commented that I/P spacing does not affect the ultimate recovery. However, we think that such factors are subjected to time constraints and unfortunately the authors did not provide graphs to make such a comparison. Das (2005a) stated that over 80% of steam is injected at the heel of the well and the remaining steam is injected at the toe, while fluid is produced either from the heel or the toe or from both. This can explain the tilted steam chambers and raises questions about the uniformity

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

gave a good comparison between the effects of steam pressure on steam temperature and hence, its effect on oil production and SOR. They stated that a higher steam pressure leads to higher steam temperature and lower oil viscosities. This in turn, leads to a higher oil flow rate. On the other hand, higher steam pressure leads to lower thermal efficiency and higher steam oil ratio (SOR). Some of the reasons for larger SOR are that steam at higher pressure has less latent heat, more heat will leave the reservoir through the produced fluids at higher temperature, and more heat will be left in the steam chamber where oil is no longer present. They also added that a higher pressure would allow natural lift of the produced fluids. Edmunds and Chhina (2001) analytically showed the relationship between LP-SAGD and low CSOR. They illustrated a six fold increase in oil rate between atmospheric pressure and 10 MPa. They also conducted a series of simulation and economic analyses and concluded in favour of LP-SAGD to HP-SAGD for the following reasons: (1) SAGD economics (mainly due to gas price) is sensitive to CSOR and LP-SAGD improves CSOR, and (2) ESPs capability improves with LP-SAGD. Ito and Ipek (2005) observed that high pressure operation is important for activating steam fingers. Das (2005b) conducted a simulation study where he examined the effects of lower operating pressure. He identified two advantages of LP-SAGD over HP-SAGD due to lower operating temperature: (1) reduced silica content in produced fluids and (2) lower H2S production. He reached the following conclusions: (1) low pressure operations appear to be energy efficient, and (2) low pressure operation is more amenable to the application of artificial lift. He also mentioned that reservoir characteristics may lead to fluid losses which may dictate the operating pressures. These observations by Das are in agreement with Edmunds and Chhina's (2001) conclusions. Butler and Yee (2002) reported for Imperial Oil SAGD pilot HWP1 a gradual decrease in CSOR with time, which is an indicator of an economic SAGD project. Initial operation pressure was of the same order of reservoir pressure (5 MPa). Two years later, chamber pressure was kept at 1–2 MPa using periodic steaming. They expected that this, along with low operating pressure, made sufficient gas available to produce improved steam economy through the SAGP2 effect, even though gas was not added to the steam. Sasaki et al. (2001) studied the effect of steam injection pressure in a 2D laboratory scaled visualization model. They stated that higher steam-injection pressure leads to a shorter breakthrough time — and higher expansion rate of the steam chamber — as the higher pressure drop between the injection and production wells (Δp) results in a larger driving force for oil mobilization. It is worth mentioning that they studied the effect of injection pressure by studying (Δp) since they set production pressure to a constant. Wiltse (2005) introduced a hydraulic gas pump (HGP) as artificial lift system solution for LP-SAGD. After field testing, he reported that HGP had outperformed the reciprocating rod pump system installed earlier in that well. Li et al. (2006) conducted a coupled simulation between EXOTHERM and FLAC to examine favourability between HP and LP-SAGD. They concluded that high pressure SAGD induced higher porosity and permeability with higher oil production. In order to observe the effects of geomechanics variation and hence permeability enhancement due to shear dilation, steam chambers should be operated at or near the minimum total stress, which implies HP-SAGD (Collins et al., 2002; Chalaturnyk and Li 2004; Li and Chalaturnyk 2006; Li et al., 2006). Another study showing favourability of HP-SAGD was conducted by Robinson et al. (2005), who also reported an increase in oil production. Kisman and Yeung (1995) also showed that operating at low pressure decreased oil production and improved OSR in a simulation model for the Burnt Lake oil sand conditions. Shin and Polikar (2005)

One of the controversial issues in SAGD operations is whether to operate at high or low pressures. Pooladi-Darvish and Mattar (2002)

2 SAGP (steam and gas push) an addition of non-condensable gas to steam in order to minimize heat loss from steam chamber.

of steam chamber growth along the horizontal well. This is backed up with another graph presented by Das (2005a) which shows that the pressure difference between the injector/producer heels is higher than between the toes. He comments that this situation may impose a great potential for steam breakthrough around the heel area. His study provided good insight into the crucial role of wellbore design to achieve a successful SAGD. An interesting feature shown in this study was that 45% of injected heat was produced back to the surface in a concentric wellbore design during startup. He commented that without the temperature data inside the wellbore, it is difficult to decide whether the vapour quality at the surface is due to countercurrent heat transfer or due to the excess steam in the horizontal section. Yet there is no optimum well spacing proposed. This is due to the fact that thickness, viscosity, permeability and heterogeneity might be governing factors in choosing an optimum well spacing. However, it seems that common practice is somewhere between 5–15 m apart. 9. Subcool temperature (steam trap control) Doan et al. (1999) stated that steam trap control is used as an operational control to reduce or prevent steam withdrawal from the steam zone in the reservoir. Das (2005b) identified three main advantages of steam breakthrough prevention to the SAGD process: (1) energy conservation and SOR reduction, (2) reduction of high vapour flow which negatively affects the lifting capacity of the well and surface facilities, and (3) reduction of sands and fine movement through the liner which may cause erosion. He then added that due to the uneven nature of the well trajectory in the field, it is very difficult to identify, rest alone, and control steam breakthrough. Ito and Suzuki (1996) reported the optimum temperature for a steam trap control to be between 30 to 40o°C. They referred to fluid drainage ahead of the steam chamber, which is 30 to 40 °C lower than steam saturation temperature. Das (2005b) noticed a positive effect of sub cool temperature after exceeding 20 °C. Chen et al. (2007) showed that when coupling hydraulic fracturing with steam trap control of the producer well, injectivity is dramatically improved and an effective oil production rate in the reservoir with poor vertical communication is achieved. Edmunds (2000) investigated this feature on 2D and 3D numerical models. He found that in a specific case, a steam trap of 20°–30 °C was optimum. However, he reached a very important conclusion, stating that the utility of the (mixed) BHT (Bottom Hole Temperature) as an operating control parameter is doubtful. This conclusion was drawn from field observations where an increasing production rate caused the BHT to drop. This observation — as he states — 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 are better off to be cautious when setting production rates with available handling capacity of the plant. Another 2D and 3D dynamic models were conducted by Ivory et al. (2008) to compare ES-SAGD and SAGD operating at low pressure. They found that an introduction of 10 °C subcool temperature minimised oil production and SOR. When no subcool temperature was introduced into the system, an increase in oil production was observed with a greater SOR. They also showed that an increase in BHP created gas saturation around the production well, which implies the need for a greater subcool temperature setpoint. From screening of Tangleflags type projects, Singhal et al. (1998) advised that steam trap constrain on production could be ignored under certain circumstances, especially during early periods of steam injection, to achieve an optimal performance.

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observed through a 2D simulation model study that high pressure injection gave a better CSOR and CDOR. However, the LP-SAGD gave the highest NPV. Gates et al. (2005) stated that high injection pressure implies a relatively high saturation temperature that leads to favourable bitumen viscosities. This explains the favourability of HPSAGD in models which do not take into consideration geomechanical effects. Bharatha et al. (2005) reported from a simulation and theoretical study that HP-SAGD reduces the effect of dissolved gas saturation in a SAGD operation. Card et al. (2006) suggested changing the operating pressure in two manners: (1) operating at high pressure until steam chamber contacts the overburden, and (2) then operate at low pressure to minimize heat losses. Collins (2007) stated that a major benefit of HP-SAGD is that the produced fluids flow to the surface under reservoir pressure, as long as the pressure differential between the steam chamber and the wellhead exceeds the hydrostatic head of the production fluids. He also discussed the failure of LP-SAGD in the Peace River Shell project where SAGD injection was at 2700 kPa and SOR ranged from 5–10. The performance improved after conversion to CSS with an injection pressure of 11,000 kPa. He identified the effect of well depth as a factor in the higher pressure requirement for deeper projects. He then provided a comparison of LP and HP-SAGD factors such as lift, heat exchange, water treatment, viscosity, wells, heat losses, geomechanical enhancement, and residual oil. Thimm (2005) stated that for the most part, the scaling aspects due to produced water in SAGD tend to favour LP-SAGD. In unusual cases, where naturally occurring radioactive materials are involved with sulphate scales, or where significant amounts of phosphate are present, a higher pressure might be favourable. 9.2. Steam chamber monitor and volume size estimation In a SAGD process, pressure and temperature monitoring indicate a reference of heat transfer process occurring in the reservoir and of steam displacement along the completion to the reservoir (Herrera, 2001). The inflection method (using thermocouples) is considered to be the classical method in determining the top of the SAGD steam chamber (Birrell and Putnam, 2000). Birrell and Putnam identified the drawbacks of this method, where in the field, thermocouple spacing can 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 saturated sands above the steam chamber is hotter than in the steam chamber giving the false impression that the steam chamber has risen. Thus, they applied a graphical method utilizing Inverse Conjugate Error Function (ICEF) incorporated with natural log plots to interpret thermocouple data which allowed for the determination of steam chamber position to the centimetre scale. They corrected for transient temperature effect resulting from steam chamber pressure and temperature variation by simplifying the operating temperature to a finite number of values with step change (Birrell and Putnam, 2000). Zhang et al. (2005) used 4D seismic and crosswell seismic imaging to monitor and understand steam chamber growth. The images obtained showed that less than 100% well length was swept by the steam chamber and a non uniform steam chamber growth occurred. Shamila et al. (2005) conducted a study aimed towards investigating the applicability and subsequent accuracy of the pseudo-steady state method in estimating the swept volume/size (fluid injection chamber) under steam injection conditions, with the application of horizontal wells using a commercial 3D thermal reservoir simulator. Herrera (2001) suggested the use of microseismic measurements for steam chamber monitoring by combining it with 3D visualization technology (Herrera, 2001). An example of a well monitored SAGD project is Phase B at UTF, where eleven temperature observation wells are available with twenty thermocouples in each well spaced throughout the McMurry succession (Birrell, 2001).

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10. Numerical simulation Edmunds (2000) conducted a 2- and 3D numerical simulation study on steam trap control. He reported that 2D simulations were found to be unrealistically optimistic for general SAGD problems. He also flagged a very important fact that well pairs in SAGD are not homogeneous as assumed, for several reasons including geology, spacing, and skin factor. Another comment was made by Collins et al. (2002) about conventional reservoir simulations; they do not account for geomechanical enhancement explicitly, but implicitly include the effects by using permeabilities from highly disturbed core. Li et al. (2006), and Li and Chalaturnyk (2003) worked on a coupled simulation of EXOTHERM and FLAC and showed a higher oil production than in uncoupled simulation. They inferred that this difference took into account the enhancement on both porosity and permeability in coupled simulation. An important feature related to the variation in relative permeability curves due to temperature was not incorporated in most of the numerical 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 the simulation model greatly increases the precision and accuracy of swept volume estimation using the pseudo-steady state method. This shows the sensitivity of grid density on the accuracy of the results, which is not incorporated in some numerical simulations reported. In fact, some simulation studies used huge coarse grids for field simulation. Yet having a fine grid for field scale models will increase the run time and — depending upon CPU capability — may not converge. Thus, dynamic gridding may be a good solution for such cases. Christensen et al. (2004) showed that dynamic gridding reduced the CPU time three folds while keeping good accuracy in the simulation results. However, they also commented on a figure where they observed a finger shape above the steam chamber with dynamic gridding which was not shown with fine gridding. They explained this as being an inaccuracy probably introduced by the simple upscaling technique. However, comparing that shape to Sasaki et al.'s (2001) 2D visualization observations, we wonder if that could actually be a steam finger represented by dynamic gridding, which was not introduced in fine gridding. Another remark we can make is that many simulation models, which tried to draw conclusions for SAGD performance in specific reservoirs, use a simple Cartesian model which does not depict actual reservoir heterogeneity. Thus, one has to ensure to use representative reservoir models in SAGD performance analyses using numerical simulators, as the reservoir heterogeneity may have considerable effects on the accuracy of the process. A good demonstration of such an approach is shown by Robinson et al. (2005). McLennan and Deutsch (2005) stated that flow modeling is a transfer function converting the geological uncertainty to production uncertainty. Thus, the importance of having a good reservoir static model emerges where they further state that the main objective of using geostatistics to characterize a potential SAGD reservoir is to quantify the uncertainty in production performance (Oil Production Rate and SOR) due to geological uncertainty. They conducted a study where they implemented nine different static ranking measures for a potential SAGD reservoir. They concluded that static measures of local connectivity were the most effective; they referred that to their correlation of Oil Production Rate and SOR being the highest. They stated in their conclusion that dynamic ranking measures suffer from simplifying assumptions that mask geological heterogeneity where static ranking measures explicitly account for geological heterogeneity modeled by geostatistics. Nestor et al. (2001) referred the complexity of optimizing the SAGD process to the time consuming and limited number of objective function (performance measure) evaluations, a potentially high

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number of parameters, and a non-linear solution space. They also noted that the performance measures (such as net present value, cumulative oil production, and cumulative steam injection), geometrical parameters (e.g. I/P spacing, well length), and operational parameters (e.g. subcooling, steam injected enthalpy etc.) require expensive numerical simulations beside run time/number consumption. 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 called NEGO (neural network based efficient global optimization) which would optimize geometrical and operational parameters in a SAGD process. They stated that the solution methodology includes the construction of a “fast surrogate” of an objective function whose evaluation involves the execution of a time consuming mathematical model (i.e. reservoir numerical simulator) based on neural networks, DACE modeling (design analysis of computer experiments), and adaptive sampling. Tan et al. (2002) conducted a simulation model to investigate the importance of using a discretized wellbore for SAGD simulation. They concluded that a discretized wellbore model is necessary to predict temperature and saturation profiles for startup and production of SAGD well pairs. The use of discretized wellbore is becoming a common practice. This feature enables steam circulation during the startup period. 11. Experimental pitfalls All experimental works to our knowledge were performed on sandpack (natural sand or glass beads) models with no exception. Therefore, the evaluation of the experimental efforts will be only on this type of model. Ong and Butler (1990) developed a scaling criterion for horizontal wells. They showed that the scaling factor for the radius of the horizontal well is proportional to the one-fourth power of the product of the ratios of their respective heights of formation and fluid viscosity values. This geometrical scaling resulted in an impractical (large) laboratory size well. To determine a smaller size well, they then studied the wellbore flow resistance which resulted in a more practical wellbore size (Ong and Butler 1990). Sasaki et al. (2001) found that for a 2D model, heat loss owing to condensate production had little effect on oil drainage process near the steam-chamber interface. They explained this as due to condensate flow down the side walls in the central region of the steam chamber. They concluded that scaled 2D models are possible to analyze steam chamber behaviour in SAGD process investigation, except for the amount of single-phase water condensate dissipated at heat loss. Chung and Butler (1987) had the same approach with the introduction of the dimensionless number. A scaling method of Pujol and Boberg used by Nasr et al. (1996) for their 2D model where the field and model must be geometrically similar (i.e., width-to-length ratio and height-to-length ratio must be the same). For other parameters containing fluid and rock properties, terms related to the transport of heat and mass, and initial and boundary conditions must be equal in the field and lab model. Unlike Pujol and Boberg's scaling approach, the permeability used in the laboratory experiment was different from that in the field. Nasr et al. (1996) commented on its impact as presenting inadequate scaling of capillary pressure. Using a 2D sand packed model, Nasr et al. (1997) reported that transition from initialization (injection in both wells) to developed SAGD (upper well injection, lower well production) resulted in a temporary cooling of wells and drop in production. This phenomenon is observed more during the laboratory experiments with sand packed models than in what actually happens in the field, since poor model insulation can cause such pitfalls. Although, they reported based on previous observations 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 production well during the classical SAGD laboratory experiment. We add that sand pack models would usually represent, to some extent, sandstones, which are cohesive by capillary forces or interlocked sand grains. This may favour sand beads movement with pressure variation showing false increasing permeability, hence higher production, and lower SOR. 12. SAGD improvement From what we have seen above, it is obvious that a consistent steam chamber growth is indispensable for a successful SAGD operation. Thus, different attempts were made to accelerate and improve the efficiency 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 aims directly for improving heat efficiency and reducing the oil water interfacial tension to achieve higher production. The geometrical approach attempts to alternate pressure differential points related to well placement in order to achieve accelerated chamber growth. 12.1. Geometrical attempts 1. Cross-SAGD or X-SAGD: The main feature of this configuration is to create a mesh of injection and production wells. The operation technique is then to alter the injection and production points according to strategic timing to minimize “steam short circuiting” and hence improve steam trap control and production. The crossing points between wells are either plugged initially or at a later stage in the project life. According to Stalder (2007) there are two “penalties” with X-SAGD: (1) Only the points where the wells cross are effective in establishing the initial steam chamber rather than at the entire length of the wells, (2) the plugging operation requires an additional cost and poses a serious practical challenge to operations. One can add to those points that X-SAGD would require a high initial CAPEX where conducting a pilot would be difficult — if not impossible — with fewer wells. This increases the initial risk. Stalder (2007) conducted a comparison study between X-SAGD and SAGD in a numerical simulation model representing expansive, contiguous, and homogeneous bitumen reservoirs. His results indicated that XSAGD has the advantage of accelerating recovery, achieving higher thermal efficiency by reducing CSOR, and favouring low pressure to high pressure SAGD. 2. Fast-SAGD (F-SAGD): This technique employs an additional horizontal well aimed to accelerate and improve the steam chamber growth rate. The horizontal well is placed alongside the well pair which operates by CSS. Shin and Polikar (2006a,b, 2007) conducted a 2D simulation model and concluded that the F-SAGD had a lower cumulative steam-oil ratio due to thermal efficiency and higher calendar daily oil recovery (CDOR) that was as much as 34% of classical SAGD. They showed figures where higher oil recovery was obtained from the F-SAGD compared to classical SAGD but they did not mention if this was from the SAGD production well or combined with the offset well. It is obvious that two wells would produce more oil than one. The way we look at the F-SAGD is as an attempt to create a pressure sink in the lower part of the reservoir where steam will compromise between its tendency to rise and the physical fact of fluid movement from high to low pressure points. 12.2. Chemical attempts 1. Expanding solvent SAGD (ES-SAGD): This novel approach was developed by Nasr et al (2003). Its main concept is the co-injection of hydrocarbon additive with steam at low concentrations. Another approach was a hybrid injection of steam and solvent. Solvent would condense with steam around the steam chamber interface causing oil

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dilution and viscosity reduction. A reduction was reported in the steam oil ratio by up to 50% and solvent recovery of 95–99% in a 2D experiment. 2D experiments showed an improved oil recovery, enhanced non-condensable gas production, lower residual oil saturation, and faster lateral advancement of heated zones. It was also reported that adding non-condensable gases to live oil did not improve the process because of initial methane presence (Nasr et al., 2001; Nasr et al., 2003; Nasr and Ayodele, 2008; http://www.petrocanada.ca/en/about/636.aspx last visited Jan 12., 2008). From the images provided by Nasr and Ayodele (2008), one may notice that ESSAGD temperature was uniformly centred in the middle of the model compared to the classical SAGD. This adds another point to the process where solvent may operate as insulator reducing heat losses and hence reducing the amount of gas needed. This solvent effect may have a greater role than viscosity reduction since at a higher temperature, further viscosity reduction due to solvent addition may have only a small effect. This observation was also reported by Deng (2005). He pointed out that the viscosity reduction was mainly from steam. He also noticed that a higher addition of propane impedes heat transfer between the steam and the oil zone. Deng (2005) used a 2D model to simulate a steam/propane hybrid process. He observed that propane's role was to maintain the reservoir pressure, which raises some questions about how solvent addition would affect reservoir geomechanics. Images provided from Deng's (2005) simulations showed that the addition of propane converted the steam growth shape from a hand fan shape to a cupcake, where better lateral movement was noticed compared to classical SAGD. Gates (2007) conducted a study to determine a suitable injection strategy for higher ultimate recovery by visualizing the process in a phase diagram. He concluded that the presence of solvent in ES-SAGD yields 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 effect of diffusion and dispersion on the ES-SAGD process. They observed that the diffusion coefficient increased with increasing temperature. They referred this to the decrease in the oil viscosity, which is inversely proportional to the diffusion coefficient. Ayodele et al. (2008) conducted laboratory experiments investigating effect of low pressure ES-SAGD. They compared the single component (propane) case with multi-component systems. They concluded that multicomponent solvent yields better field application for low pressure ES-SAGD with lower energy consumption. This process (ES-SAGD) was tested by Suncor Energy in Burnt Lake and Firebag. Petro-Canada is also planning to pilot solvent SAGD in MacKay River. 2. Non-condensable gas (NCG) or SAGP: As it was pointed out earlier, Butler (1997) and Butler and Yee (2002) mentioned the potential problems associated with wasted heat in a mature SAGD project. Adding non-condensable gas to steam affects both the steam chamber growth rate and shape (Butler and Yee, 2002; Canbolat et al., 2002). For the process of SAGP, Butler (1997) stated that the injection conditions are such that a very high concentration of non-condensible gas accumulates in the steam chamber, particularly near the top. In the process proposed, the concentration of non-condensible gas (typically methane) at the top of the steam chamber is intentionally maintained at a level over 90 mol% and the dewpoint of this gas is much lower than the saturation temperature of steam at reservoir pressure. These high gas concentrations are maintained by the addition of natural gas to the injection steam. The gas addition must be sufficient to supply the fill for the chamber and production losses with allowance for the evolution of dissolved gas as the cold reservoir oil is heated. Jiang et al. (2000) discussed further analysis of well configurations in SAGP (injector at the top of thin reservoir and injector close to producer near reservoir bottom) and results from physical model tests. They reported a lower oil production than in conventional SAGD but a much lower SOR. They also reported that the amount of gas required is less

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than 1% volume of the injected steam. Butler et al. (2000) stated that much of the oil displacement is caused by the flow of fingers of gas/steam rising counter-currently, rather than by a simple advance of the continuous steam chamber in SAGP. The rising gas fingers raise the pressure in the reservoir above and this increase in the pressure towards the top of the reservoir tends to push the oil down. Butler et al. (2001) discussed the effect of reservoir permeability heterogeneity where they show that the counter-current behaviour of SAGP gives an advantage for earlier production from the lower permeability layer through finger rising. All previous works showed a significant reduction in SOR and this is also verified by Yee and Stroich (2004) where the addition of NCG to steam injection proved to be a technically viable method to effectively wind-down a mature SAGD chamber. Aherne and Birrell (2002) stated that the difficulty in matching the performance of SAGP using thermal simulation models comes down to a problem with relative permeability. The flow of gas fingers through bitumen is an immiscible displacement process where the mobility ratio is extremely adverse. Areas in the simulation model where gas fingering is taking place will require gas/liquid relative permeability curves to reflect the adverse mobility ratio (moveable oil or the difference between reservoir saturation endpoints may be as little as 5%). Areas of the reservoir in which gravity drainage is taking place will require curves suited for the gravity drainage (where moveable oil may be greater than 89% OOIP). This was also reported by Butler (2004b), who added two other effects: (1) numerical models have confined boundaries, and (2) gas cap layers may not be represented properly as the gas cap layer is very thin compared to the grid block. Hamm and Ong (1995) described the accumulation of NCG in the SAGD steam chamber as a “serious threat” since its accumulation at the chamber boundary may reduce steam temperature at the location of the highest demand. Thimm (2005) stated that excessive free gas non-condensable gas in the steam zone will cause collapse of the steam zone or a steam saturation reduction. Butler (2004b) stated that if chamber pressure is greater than the surroundings, this gas (gas accumulated at the top of the reservoir) can escape. This situation is prevalent in many of the successful SAGD pilots. Conversely, in operations where the chamber pressure is close to or below that of the surrounding reservoir, gas may accumulate in the chamber reducing its temperature (the SAGP effect) and improving the SOR. Ito et al. (2001) showed through numerical simulation that the addition of non-condensable gas to injected steam gathers at the leading edge of the steam chamber and retards the growth of the steam chamber. A major cause for this delay is a decrease in convective heating by steam condensate. However, the addition of gas to steam injection in the later stage results in an improved SOR. From these comments, we can conclude that presence of NCGs can be either a blessing where it increases thermal efficiency or a curse where it destroys the steam chamber, hence SAGD process. We believe that an optimal value threshold exists to distinguish the area between a successful or a failing NCG project. Although the line is not clear, we expect these thresholds in static and dynamic factors; namely reservoir properties and steam chamber size, respectively. 13. Summary In this paper we looked extensively at various aspects governing the SAGD process. We tried to draw a wide picture of SAGD with a neutral perspective to demonstrate points of strengths, weaknesses and ambiguous areas in the process. We highlight the following critical issues as an extraction of our review study. 1) Different dynamic processes occur during SAGD which needs more exploration to fully understand and optimize. These processes include steam fingering, co-/counter-current flow, conduction vs. convection, emulsification, imbibition, relative

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Table 1 Compilation of laboratory experiments reviewed. Authors

Experiment

Purpose

Oil type

Oil rec., (% OOIP)

Type of sand

Porosity (%)

Permeability

Steam temp.

Steam pressure (kPa)

Chung and Butler 1987

2D sand packed model

Monitor water/oil emulsion content

90

2 mm sand bead

39

2.36E−9 m2

109 °C

153

Yang and Butler 1992

2D sand packed model

Effect of reservoir heterogeniety on HO-recovery

Cold Lake (32 800 cp @ 25 °C) Cold Lake (32 800 cp @ 25 °C)

18.4E−10 m2

109 °C

154

Nasr et al. (1997)

2D sand packed model 2D porous packing model

Visualization study

100−2000 µm2

Controlled by steam trap 106 °C

20

Sasaki et al. 2002

Sasaki et al. (2001)

2D porous packing model

Canbolat et al. (2002)

2D crushed limestone Cylinder model

Nasr et al. (2000)

2)

3)

4) 5)

6)

7)

8)

9)

10)

11)

Visualization study/fluid flow characterization in steam chamber and produced fluid Effect of steam injection press, heat loss estimation 7 prod fluid temp and well spacing Visualization study/NCG

53.2–91.6 0.12 Pa s @ 106 °C

beads

33.9–35.7

glass beads

38

20

Athabasca bitumen

64.9

glassbeads

38

115e−12 m2

2 °C above saturated temp

20–97

12.4 API

80−35

limestone

38

8 µm2

139–144 °C

22–47.3

Silica sand

35

10−5 D

115 °C

80

Counter current aspect of SAGD

permeabilities (i.e., interfacial tension and wettability effects), and geomechanics. Understanding the reservoir characteristics is a key element for any oil production project and SAGD is no exception. Its importance emerges from the huge effect that reservoir heterogeneity may have on the success of the process. Thermal efficiency is a key aspect for an economical SAGD project. Although CSOR may provide a good indicator, thermal efficiency cannot be tied only to it. Further utilization of thermal energy may lead to an economic SAGD project. Good monitoring of SAGD projects is required to maintain and predict a successful SAGD operation. SAGD application in carbonate reservoirs is not well understood, nor extensively studied. Due to its high dependency on vertical permeability, the SAGD process may not be applicable in tight carbonate reservoirs. However, fracture presence may help achieve acceptable rates with SAGD, but the recovery mechanism (based on matrix-fracture interaction) will be totally different from sand reservoirs. Understanding the role of geomechanics during SAGD can further help explain the physical phenomenon occurring during the process. However, further work needs to be done on deep and carbonate reservoirs. Execution of a good startup procedure may be a key element to a successful SAGD project. A good understanding of a reservoir's cumulative and flow properties may help in planning and implementing a good startup procedure. In terms of performance, high pressure (HP) SAGD seems to increase oil production with a penalty of high CSOR. However, the debate on favorability of HP-SAGD vs. LP-SAGD may further extend with developing technology which helps both operating practices to be implemented. A major role of HP-SAGD may occur with geomechanical effects. Thus, the absence of geomechanical effects may favour LP-SAGD. Existing formulations and numerical models seem to be capable of conducting SAGD simulations, yet the simulation studies indicate that — in many cases — more effort is needed to fully capture the complex physics of the process. Experimental laboratory models have limited capability in representing actual field application. However, it seems that they give sufficient data for SAGD physics studies. Thus, it is advised not to draw wide conclusions about economics and field performance from simple 2-/3D models. There are several attempts to improve production/performance of SAGD. They are categorized as geometrical and chemical

attempts. Conceptually, expanding solvent SAGD (ES-SAGD) seems to be a promising technique, however, further research is needed to fully understand the physics of the process and optimal operating conditions. 12) Table 1 gives a compilation of all experimental data, which we hope will be a good and quick reference for SAGD researchers. 13) With such advances in research, chances of successful SAGD are greater. However, Farouq-Ali's (1997)-concerned-comments regarding the over-optimistic attitude towards SAGD are still valid: SAGD is “still” an exception, not the rule “yet”. Acknowledgements The first author (MB) is thankful to Petroleum Development of Oman Co. (PDO) for providing the financial support for his graduate study at the University of Alberta. He also would like to express his gratitude to Ron Hamm, Dr. John Van Wunnik, and David Kemshell of PDO for their encouragement to conduct the research on thermal recovery and for fruitful discussion on the SAGD process. Thanks are also extended to Enhanced Oil and Gas Recovery and Reservoir Characterisation (EOGRRC) research group personnel at the University of Alberta for their extensive support and assistance during the implementation of this study. This paper is the revised and improved version of SPE 113283 presented at the 2008 SPE/AAPG Western Reg. Meet., Bakersfield, CA, 31 March–2 April. References Aherne, A.L., Birrell, G.E., 2002. ‘Observation relating to non-condensable gasses in a vapour chamber: Phase B of the Dover Project’, SPE/PS-CIM/CHOA 79023, SPE/PSCIM/CHOA: Int. Ther. Oper. and Heavy Oil Sym. and Int. Horizontal Well Tech. Conf., Calgary, Canada. Nov. Ayodele, O.R., Naser, T.N., Beaulieu, G., Heck, G., 2008. ‘Laboratory experimental testing and development of an efficient low-pressure ES-SAGD processes’, SPE 2008-184: CIPC/SPE-GTS, Calgary. Jun. Bharatha, S., Yee, C.-T., Chan, M.Y., 2005. ‘Dissolved gas effects in SAGD’, Paper 2005-176: Pet. Soc. 6th Canadian Int. Pet. Conf. (56th Annual Tech. Meet.), Calgary Canada. June. Birrell, G.E., 2001. ‘Heat transfer ahead of a SAGD steam chamber: a study of thermocouple data from Phase B of the underground test facility (Dover Project)’, SPE 71503: SPE Ann. Tech. Conf. and Exhib., New Orleans USA. Oct. Birrell, G.E., Putnam, P.E., 2000. ‘A study of the influence of reservoir architecture on SAGD steam chamber development at the underground test facility, Northeastern Alberta, Canada, using a graphical analysis of temperature profiles’, Paper. 2000104: CIPC., Calgary Canada. June. Butler, R.M., 1987. Rise of interfering steam chambers: JCPT, Paper 87-03-07. June. Butler, R.M., 1994a. Horizontal wells for the recovery of oil, gas and bitumen: Petroleum Society Monograph Number 2, Canadian Institute of Mining Metallurgy & Petroleum. Butler, R.M., 1994b. Steam-assisted gravity drainage: concept, development, performance and future. JCPT 32 (2) Feb.

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