INVESTIGATION ON THE EFFECT OF THE RESERVOIR VARIABLES AND OPERATIONAL PARAMETERS ON SAGD PERFORMANCE

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1 INVESTIGATION ON THE EFFECT OF THE RESERVOIR VARIABLES AND OPERATIONAL PARAMETERS ON SAGD PERFORMANCE a Hashemi Kiasari, H.; b Sedaee Sola 1, B.; a Naderifar, A. a Petroleum Engineering Department, AmirKabir University of Technology, Tehran, Iran b Institute of Petroleum Engineering, Faculty of Engineering, University of Tehran, Tehran, Iran ABSTRACT Steam injection is the most important thermal enhanced oil recovery method. One typical procedure is Steam- Assisted Gravity Drainage (SAGD), which is a promising recovery process to produce heavy oil and bitumen. The method ensures a stable displacement of steam at economical rates by using gravity as the driving force and a pair of horizontal wells for injection/production. There are numerous studies done on SAGD in conventional reservoirs, but the majority of them focus on the investigation of the process in microscopic scale. In this study, we investigate the SAGD process with a preheating period, using steam circulation in well pair on a field scale. The synthetic homogenous model was constructed by CMG and simulated using the STARS module. The effects of operational parameters, such as preheating period, vertical well spacing, well pair length, steam quality and production pressure, and reservoir variables, such as rock porosity and permeability, vertical-to-horizontal permeability ratio, thermal conductivity of the formation and rock heat capacity, on the SAGD performance were investigated. The results show that the preheating period affects mainly the initial stages of production. Due to preheating, the well pair communication with the higher vertical distances is also established; therefore, there was no considerable difference between oil productions in various well spacing cases. As steam quality increases, the oil production in later production times also increases. At shorter well pair, more steam can be injected per unit length of well, but, on the other hand, the production well recovers less heated oil area; therefore the well pair length should be optimized in all cases. By decreasing the production well bottom-hole pressure, more heated oil in near well region is produced; therefore, the injected steam raises more in the depleted area. The results of the simulations show that very low permeability leads to a fully unsuccessful SAGD process. In the lower permeability range, the effect of vertical permeability is not so considerable. The oil production increases when the formation thermal conductivity and the rock heat capacity decrease. Finally the main parameters affecting the SAGD process in conventional reservoirs are listed as follows: preheating period, production BHP, porosity, permeability, well pair length, rock heat capacity, steam quality, thermal conductivity and vertical permeability. They should be more carefully accounted for in any SAGD process. KEYWORDS SAGD; conventional reservoirs; preheating period; operational parameters; reservoir variables 1 To whom all correspondence should be addressed. Address: Institute of Petroleum Engineering, Faculty of Engineering, University of Tehran, Tehran, Iran Telephone/Fax number: sedaeesola@yahoo.com 59

2 1. INTRODUCTION Heavy oil and tar sands are important energy sources which occur in many countries. Assuming an ultimate recovery of 15% for heavy oil and extreme heavy oil, and 33% for conventional oil, the reserves are nearly the same. However, the ultimate recovery factor for heavy oil could be much higher. This large amount of oil can compensate the reduction of production in conventional oil reserves. The best option to produce heavy oil is to reduce oil viscosity using heat. Thermal enhanced oil recovery (EOR) methods that have been applied in the field include hot water drive, steam injection and in-situ combustion. Steam injection is a more effective method than hot water drive, on account of the latent heat of vaporization that can be harnessed from the steam. For this reason, hot water drive is very rarely used nowadays. Due to wellbore heat loss, steam injection may not be feasible beyond a depth of about 3000 ft. In deep reservoirs, in-situ combustion may be a more suitable thermal EOR method. However, steam injection is currently by far the most widely used thermal EOR method. This method is responsible for 80% of thermal heavy oil production. Among the available steam injection methods, the Steam-Assisted Gravity Drainage (SAGD) is a promising recovery process for producing heavy oils and bitumen, and ensures a stable displacement of steam at economical oil rates, by using gravity as the driving force and a pair of horizontal wells for injection/production (Bagci, 2006). In the SAGD process the heated oil moves approximately parallel to the interface which forms the boundary of a growing, steam-saturated zone known as the steam chamber. Although in other thermal recovery methods the oil bank remains cold when reaching the production well, in the SAGD process heated, reduced-viscosity oil is produced since there is no large distance between the well pair (Butler, 1998). The mechanism of SAGD is illustrated schematically in Figure 1. During the rise of steam chamber (countercurrent flow period), the oil production rate increases steadily until the steam chamber reaches the top of the reservoir. SAGD processes with horizontal wells not only offset the effect of very high viscosity by providing extended contact or by heating, but also maintain the necessary drive needed to move the oil, as the reservoir becomes depleted. However, because of its considerable heat requirement, this process is limited in its economic use to higher quality reservoirs (Joshi, 1991). At later stages of the process, when the chamber reaches the top of the reservoir, the rate of oil production is controlled by the lateral expansion of the steam chamber (co-current flow period). During this phase of the process the production rate declines and the Steam Oil Ratio (SOR) eventually increases because of heat losses to the overburden (Sedaee Sola, 2006; Fatemi and Kharrat, 2009). Figure 1. Essential feature of the SAGD process (Sedaee Sola, 2006; Fatemi and Kharrat, 2009). 2. LITERATURE REVIEW After innovation of the SAGD concepts proposed by Butler (1980), numerous studies were done involving experimental, analytical, simulation and field scale. In the following section the simulation studies are summarized. Kisman and Yeung (1995) showed that operating at low pressure decreases oil production and improves OSR in a simulation model for the Burnt Lake oil sand conditions. Chan et al. (1997) observed through a series of 2D simulations that higher recovery efficiency was achieved for smaller injector/producer well spacing. However, in this case the reservoir was thin (20 m) and the injector was placed 3 meters below the top of the reservoir, therefore such results are expected. 60

3 Edmunds and Chhina (2001) conducted a series of simulation and economic analyses and concluded in favor of LP-SAGD instead of HP-SAGD because the SAGD economics (mainly due to gas price) is sensitive to CSOR and LP-SAGD improves CSOR. 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. Gates et al. (2005) provided images of steam quality and temperature of the steam chamber from a simulation study. In their work, they provided a novel method for visualizing heat transfer within the boundaries of the steam chamber. Bharatha et al. (2005) investigated the dissolved gas effect on the SAGD process using simulation. They concluded that the effect of dissolved gas on SAGD is to reduce the bitumen production rate. The results of their study showed that operating pressure is the most important parameter causing the reduction of the dissolved gas saturation effect. Shin and Polikar (2005) showed that as injection pressure increases, CSOR and CDOR increase. However, the LP-SAGD gives the highest NPV. Das (2005) conducted a simulation study where he examined the effects of lower operating pressure. He reached the following conclusions for low pressure operations: (1) they seem to be energy efficient, and (2) they are more amenable to the application of artificial lift. Shanqiang and Baker (2006) observed that decreasing permeability reduced the initial oil production rate, but, at later time, the oil rate increases dramatically. They also studied the effect of oil gravity on SAGD performance and observed that decreasing oil gravity reduces oil production. 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. Oil production increase was noticed with an increase in oil pay thickness. They also found that the startup period increases with decreasing permeability and increasing well spacing. Their results showed that, by increasing the spacing between the injector and the producer, CSOR decreases due to enhanced thermal efficiency. By reducing the spacing, the bitumen recovery reaches its highest point and then decreases. They suggested that I/P spacing does not affect the ultimate recovery. Chen et al. (2007) conducted a numerical simulation study on the shale distribution in NWR and AWR, and found that the presence of shale in NWR impairs vertical permeability and flow of hot fluids, whilst in AWR it affects the expansion of steam chamber. In summary, the effect of some parameters have been reported in the literature, but there are some other reservoir variables and operational parameters which have more effects on the SAGD performance, such as artificial lift (pumping), well pair length, steam quality, porosity, rock heat capacity and thermal conductivity. These parameters have been investigated in this study. 3. SIMULATION STUDY OF SAGD: MODEL DESCRIPTION In order to study the effect of various parameters on SAGD performance, a base case was defined. In this study, the base case was a rectangular field scale reservoir, with dimensions of ft. To exclude grid sensitivity from the results, the grid sensitivity analysis was done and a cell in X, Y, Z coordinates was selected as the base case grid. The simulator used in this study is a CMG-STARS. PVT properties were calculated using the CMG-Winprop software. Average porosity and permeability, irreducible water saturation and residual oil saturation were set as 10%, 500 md, 0.4 and 0.2, respectively. Formation thermal conductivity and rock heat capacity were calculated assuming dolomite and limestone rocks and the results show the following 61

4 values: 24 Btu/ft 3. F for thermal conductivity and 30 Btu/day.ft. F for rock heat capacity. One horizontal injector/producer well pair with 4800 ft length and 30 ft vertical spacing was located three blocks above the bottom of model. The injection scenario was based on a constant injection rate of 1000 STBD CWE for 10 years and the maximum injection pressure was set as 1500 psi (corresponding maximum temperature was set as 600 F). The minimum pressure of production well was set as 1150 psi (50 psi less than the reference pressure at model bottom) and 0.95 was assigned to the steam quality. Four-month preheating period by steam circulation was designed. The crude oil comprised three pseudo components known as X 2 + (gaseous phase), C 2 + (oil phase) and C 7 + (oil phase). The Peng-Robinson Equation of State and Modified Pederson Equation were used to model fluid properties. The oil viscosity at the reservoir temperature (140 F) is about 2000 cp and its dependence on temperature is shown in Figure 2. The reservoir conditions in terms of oil density and GOR are 61.5 lb m /ft 3 and 67 scf/stb, respectively, and the oil formation volume factor (B o ) is 1.05 at the reservoir pressure (1200 psi). The relative permeability of oil-water is shown in Figure 3 and the variation of the residual oil saturation with temperature is considered in the simulation (Table 1). The fluid data and also the base model parameters are shown in Tables 2 and 3, respectively. Table 1. Residual oil saturation changes versus temperature. Temperature ( F) S or Table 2. Mole fraction and molecular weight of the crude oil used in the simulation. Component MW Composition (%) X 2 + C 2 + C Table 3. The Base Case Properties. Parameters 4. RESULTS AND DISCUSSIONS 4.1 Operational parameters The effect of operational parameters such as preheating period, well pair vertical spacing, steam quality, well pair length and production pressure on the SAGD performance were studied and the results are discussed below. 4.2 Preheating period Value Grid No. in X,Y,Z-direction Porosity (%) 10 Permeability (md) 500 Maximum injection temperature ( F) 600 Maximum injection pressure (psi) 1500 Steam quality (%) 95 Production pressure (psi) 1150 Initial pressure (psi) 1200 Irreducible water saturation 0.4 Residual oil saturation 0.2 Number of injector/producer well 1 Well pair length (ft) 4800 Vertical well spacing (ft) 30 Maximum injection rate (STBD) 1000 Preheating period (month) 4 Formation thermal conductivity (Btu/day.ft. F) To investigate the preheating effect on the SAGD performance, three cases with no preheating, two- and four-month preheating (base case) periods were simulated. The preheating was done by circulation of steam in both injection and production wells. Every preheating period up to a certain time affects the oil production, whereby the effects of longer ones are more durable; however, after a specified period of time, there are no more differences between the results. By increasing the preheating period, the initial communication between well pairs becomes easier and the injection rate quickly reaches its desired 24 Rock heat capacity (Btu/ft 3. F) 30 62

5 value. Therefore, during the initial stages of production, the oil production rate increases as the preheating period increases, but after the initial stages of production there is no difference due to variable preheating duration (Figure 4). It was found that the difference between temperature profiles of the base case and no-preheating models was considerable at the initial periods of production (Figure 5), but at the end of production there was no considerable difference between them. As preheating period decreases, the CSOR increases. In the case with no preheating, at the initial stages of production a quick increase in CSOR is evident, but later this value decreases due to Figure 2. Oil viscosity versus temperature. increasing oil production rates (Figure 6). The results of the simulation showed that water production decreases as preheating period increases due to penetration of steam into more heated areas. However, in the case of no preheat, water production increases slowly with time because of less steam injectivity at the initial stages of production. It was obvious that the preheating period was vital for the success of the SAGD process, especially in processes with shorter lifetimes. 4.3 Vertical well spacing To investigate the effect of vertical well spacing on the SAGD performance, three cases with 30 (base case), 60 and 90 ft vertical well spacing were considered. Because of long preheating period, the initial communication between wells quickly occurs. Depending on the preheating period, the cases of longer vertical distances up to a certain value produce oil as well as the cases with less vertical distances. In addition to preheating period, some other parameters such as permeability, oil viscosity, reservoir thickness and heterogeneity might be governing factors when selecting the optimum well spacing. The breakthrough occurs immediately in all cases mentioned above because of suitable preheating period, therefore there was no difference in water production rates. Also the CSOR increases when the well spacing increases, but the difference is not considerable. 4.4 Steam Quality Figure 3. Oil-water relative permeability. Figure 4. Effect of preheating period on oil rate and cumulative oil production. For investigation of the steam quality effects on the SAGD performance, three cases of steam quality, namely 0.5, 0.7 and 0.95 (base case), were simulated. The higher steam quality involves more associated latent heat, therefore more oil becomes movable. On the other hand, in lower steam quality, the steam could not raise further into upper blocks due to higher water content, and therefore its steam chamber was not as large as in the case of higher steam quality. As steam quality increases, the oil rate increases. At the first stages of production, there was no difference in oil rate due to suitable preheating period, but later the difference increases as the temperature of higher steam quality increases, and therefore the oil production rate increases. 63

6 Figure 5. Temperature distribution of 4 months (left) and no preheating period (right) after 2 years. In summary, the difference was not as expected. Due to the high heat conduction of the rock, a considerable amount of heat from injected steam is distributed throughout the reservoir, and therefore the steam chamber temperature does not differ seriously for various steam qualities. This feature can be seen in the region below the producer, whereby its temperature increases during production lifetime but no steam penetrates there. Therefore, the oil temperature inside the steam chamber in the case of higher steam quality could not be raised much farther than lower steam quality, and resulted in no more movable oil (Figure 7). On the other hand, maximum steam injection is achievable at low pressure (and temperature) and therefore the higher steam quality is injected at low temperature and can not improve the oil production rate in comparison with lower steam quality ones. with more oil being heated and produced up to a certain production time. Later, longer well pairs result in more oil production because of longer producer that compensates less injection flux. In total, the balance of injection and production flux (well pair length) results in the optimum well length. The case of 2400 ft can be selected as the optimum one; therefore, up to a certain value, the longer well pair is more economic (Figure 9). Finally, the CSOR of 2400 ft length is approximately as same as 4800 ft, which confirms that it is the optimum one (Figure 10). By decreasing the well pair length, the water production increases to some extent. By decreasing the steam quality, the CSOR increases with time but the difference is not so considerable. There was no difference in water production due to conduction of heat to farther areas and quick steam condensation. 4.5 Well pair length In order to study the effect of well pair length on the SAGD performance, three cases with lengths of 1200, 2400 and 4800 ft (base case) were selected. The initial oil rate of longer well pair was higher than others due to larger heated area between well pair. Since the injection strategy is based on a constant injection rate, by decreasing the well pair length the steam injection flux increases. Therefore, in shorter well pair, the steam permeated more into the upper blocks, also increasing the reservoir temperature (Figure 8), Figure 6. Effect of preheating period on CSOR. 4.6 Production well bottom-hole pressure For investigation of the producer BHP effects on SAGD performance three cases of 300, 800 and 1150 psi (base case) for production BHP were selected. The center blocks around the injector well were subjected to slightly higher pressure drop than the others; therefore more steam was injected through these blocks. By increasing steam penetration through this region, the oil 64

7 Figure 7. Temperature distribution in the cases with steam quality of 0.5 (left) and 0.95 (right) after 10 years. Figure 8. Temperature distribution in the cases with well length of 1200 ft (left) and 4800 ft (right) after 10 years. temperature and also steam injectivity into the reservoir increases. As a result, this region was able to be permeated by more and more steam, so that approximately all of the steam penetrates through this region and causes an umbrella shape for steam chamber at the end of production (Figure 11). As the production BHP decreases, more heated oil in the NWR could be produced due to viscous flow. Therefore this depleted region causes steam to raise more in the upper layers, thereby increasing its temperature. In lower production BHP, the designed steam injection rate is achievable at lower pressure and temperature, therefore less heat is injected into the reservoir than in the case of higher production BHP. As a result, the oil viscosity could not be reduced to lower value, but pressure drop due to lower production BHP compensates this reduction in productivity and produces the less movable oil. Viscous flow and gravity drainage cause the lower production BHP cases to produce more oil. The cumulative oil production in case of 300 psi was three times of base case one. Because of more oil production at lower production BHP, therefore its CSOR decreases severely and make the SAGD process in this model to be more successful (Figure 12).When BHP decreases, the water production especially in the initial stages of production increases. Figure 9. Effect of well pair length on oil rate and cumulative oil production. 65

8 Permeability 4.7 Reservoir variables The effect of reservoir variables such as porosity, permeability, vertical to horizontal permeability ratio (Kv/Kh), formation thermal conductivity and rock heat capacity on the SAGD performance were studied and the results are discussed below. Porosity Figure 10. Effect of well pair length on CSOR. To study the effect of porosity (or volume of oil subjected to steam injection) three cases with 5%, 10% (base case) and 30% were selected. Trends of oil production rate in all cases are similar and, as the porosity increases, the oil production rate in all production periods also increases. Also the temperature around the steam chamber is more distributed in low porosity models, because higher rock volume contributes to heat conduction. The CSOR decreases severely with increasing rock porosity (Figure 13). The water production also decreases a little with increasing porosity. In total, the higher rock porosity compensates the relatively low permeability effect and renders it successful. The cumulative properties such as porosity, oil saturation and thickness made the SAGD process to be more successful. Using three different permeabilities of 10, 100 and 500 md (base case) the effect of permeability on the SAGD performance was investigated. The tight model (at 10 md) has not produced a considerable volume of oil because there is no steam injected into the model. On the other hand, by increasing permeability the oil rate also increases, except in the initial stages of production, which are similar due to preheating effects (Figure 14). The 10-md CSOR is much lower than the higher permeability cases because at this very low permeability approximately no steam is injected into the model. By increasing permeability the CSOR decreases due to more oil production for the same steam injection. In total, the amount of CSOR is high in all cases due to the low permeability range, which renders the SAGD process less successful. For this reason, the 10-md case produces little water due to its very low permeability (or injectivity) but there is no considerable difference between water productions of higher permeability cases. Vertical-to-Horizontal Permeability Ratio To investigate the effect of vertical permeability on the SAGD performance three values for K v /K h such as 0.1, 0.5 and 1.0 (base case) were selected. By increasing K v /K h the spread of steam into upper layers and also drainage of the heated oil has been encouraged. However, at the initial stages of production, the preheating results in the same oil production for all cases. As permeability increases, the CSOR decreases due to more oil production. Also there was no difference in their water production. Figure 11. Temperature distribution in the cases with production BHP of 300 psi (left) and 1150 psi (right) after 10 years. 66

9 Figure 12. Effect of production BHP on CSOR. Figure 15. Effect of rock heat capacity on oil rate and cumulative oil production. the temperature of the NWR is the highest one among all cases. For this reason, the CSOR of the lower thermal conductivity cases is lower than the higher thermal conductivity ones but the difference is not considerable. The water production in all cases is approximately the same. Figure 13. Effect of porosity on CSOR. Formation Thermal Conductivity In order to study the effect of formation thermal conductivity on the SAGD performance three cases with thermal conductivities of 12, 24 (base case) and 48 Btu/day.ft. F were simulated. Since less heat was conducted into farther distances from steam chamber in the lower thermal conductivity cases, the steam chamber temperature increases more than other cases and as a result, more oil has been produced. In case of 12 Btu/day.ft. F, the development of temperature through reservoir was weaker than other ones but Rock Heat Capacity In order to study the effect of rock heat capacity on the SAGD performance three cases with rock heat capacity of 20, 30 (base case) and 40 Btu/ft 3. F were considered. By decreasing rock heat capacity, less heat of injected steam has been adsorbed by rock and therefore the volume of heated oil increases. In the case of 20 Btu/ft 3. F the injected steam reaches the upper layers rather than the base case due to less absorption of steam heat by the rock. Since more heat is gained by the oil inside the rock in the cases of lower rock heat capacity, its oil rate and cumulative oil production were higher than in the other cases (Figure 15). As the rock heat capacity decreases, the CSOR decreases due to more oil production. The water production was not so different in all cases. 5. CONCLUSIONS Figure 14. Effect of permeability on oil rate and cumulative oil production. SAGD production without preheating period decreases severely especially in shorter lifetime projects. Several reservoir variables and operational parameters affect SAGD. Vertical well spacing has less effect on recovery because of suitable preheating. Due to more heat conduction into farther areas around the steam chamber, the higher steam quality does not produce more oil. Up 67

10 to a certain well pair length, no considerable increase in oil production appears due to injection and production balance. Artificial lift systems can increase oil production rates in SAGD by increasing viscous flow. Porous and permeable rocks increase SAGD performance. Higher porosity and use of artificial lifts (i.e., pumping) severely decrease CSOR in lower permeability models. Oil production increases when the thermal conductivity of the formation decreases. In lower rock heat capacity, more oil is produced due to more heating gained from steam. Finally, the results of this study show that preheating period, production BHP, porosity and permeability are the most important parameters affecting the SAGD process. NOMENCLATURE LP-SAGD: Low Pressure SAGD HP-SAGD: High Pressure SAGD CSOR: Cumulative Steam Oil Ratio NPV: Net Present Value I/P: Injector/Producer Btu: British Thermal Units ft: foot ºF: Fahrenheit NWR: Near Well Region AWR: Above Well Region STBD: Stock Tank Barrel per Day CWE: Cold Water Equivalent psi: pounds per square inch cp: centi-poise GOR: Gas Oil Ratio lbm: Pound Mass scf: standard cubic feet PVT: Pressure-Volume-Temperature SOR: Steam Oil Ratio S or : Residual Oil Saturation BHP: Bottom-Hole Pressure Kv/Kh: Vertical to Horizontal Permeability Ratio 6. REFERENCES Bagci, A. S. Experimental and Simulation Studies of SAGD Process in Fractures Reservoirs, SPE Paper 99920, Tulsa, Oklahoma, U.S.A., April Bharatha, S.; Yee, C-T.; Chan, M.Y. Dissolved gas effects in SAGD, Paper 176, 6 th Canadian Int. Pet. Conf., Calgary, Canada, June Butler, R. M. Thermal Recovery of Oil and Bitumen, GravDrain s Blackbook, Feb Chan Chan, M. Y. S.; Fong, J.; Leshchyshyn, T. Effects of well placement and critical operating conditions on the performance of dual well SAGD pair in heavy oil reservoir: SPE , 5th Latin American and Caribbean Pet. Eng. Conf. and Exh., Rio de Janeiro Brazil. Sept Chen, Q.; Gerristen, M. G.; Kovscek, A. R. Effects of reservoir heterogeneities on the steam-assisted gravity drainage process, SPE Paper , Aniheim, U.S.A., Nov Das, S. Improving the performance of SAGD, SPE/PS-CIM/CHOA 97921, Int. Thml. Opr. and Heavy Oil Sym., Calgary, Canada, Nov Edmunds, N.; Chhina, H. Economic optimum operating pressure for SAGD projects in Alberta. JCPT 40 (12) Dec Fatemi, S. M.; Kharrat, R. Operational and reservoir parameters influencing the efficiency of steamassisted gravity drainage (SAGD) process in fractured reservoirs. Brazilian Journal of Petroleum and Gas, v. 3, n. 4, p , Gates, I. D.; Kenny, J.; Hernandez-Hdez, I. L.; Bunio, G. L. Steam-injection strategy and energetic of steam-assisted gravity drainage, SPE/PS- CIM/CHOA 97742, PS , SPE/PS- CIM/CHOA Int. Ther. Opr. and Heavy Oil Sym., Calgary, Canada, Nov Joshi, S. D. Thermal Oil Recovery with Horizontal Wells, J. Pet. Tech., , Nov Kisman, K. E.; Yeung, K. C. Numerical study of the SAGD process in the Burnt Lake Oil Sands Lease, SPE Paper 30276, Int. Heavy Oil Sym., Calgary, Alberta, Sedaee Sola, B.; Rashidi, F. Application of the SAGD to an Iranian Carbonate Heavy Oil Reservoir, SPE Paper , Alaska, U.S.A., 8-10 May Shanqiang, L.; Baker, A. Optimizing horizontal-well steam-stimulation strategy for heavy oil development, SPE Paper , Canton, U.S.A., October Shin, H.; Polikar, M. Optimizing the SAGD process in three major Canadian oil sands area, SPE Paper 95754, Dallas, U.S.A., October

11 Shin, H.; Polikar, M. Review of reservoir parameters to optimize SAGD and Fast-SAGD operating conditions, JCPT 46 (1), January Vincent, K. D.; MacKinnon, C. J.; Palmgren, C. T. S. Developing SAGD operating strategy using a coupled wellbore thermal reservoir simulator: SPE 86970, SPE Int. Thml. Opr. and Heavy Oil Sym. and West. Reg. Meet., Bakersfield California. Mar