CREATING ENHANCED GEOTHERMAL SYSTEMS IN DEPLETED OIL RESERVOIRS VIA IN SITU COMBUSTION

Transcription

1 PROCEEDINGS, Thirty-Eighth Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, February 11-13, 2013 SGP-TR-198 CREATING ENHANCED GEOTHERMAL SYSTEMS IN DEPLETED OIL RESERVOIRS VIA IN SITU COMBUSTION Murat Cinar Istanbul Technical University ITU Ayazaga Kampusu Istanbul, 34469, Turkey ABSTRACT While the exact number not known, roughly tens of thousands of abandoned oil fields exist globally. Most of these abandoned oil fields do not have an economic value and possess an environmental risk due to leaks from improperly abandoned wells. These fields contain considerable amounts of oil because an oil field is abandoned not when the oil is depleted but when the economic limit is reached. This study explores the idea; using In situ Combustion (ISC), an enhanced oil recovery method to improve oil production, to create Enhanced Geothermal Systems (EGS) within abandoned reservoirs. In short, by air injection into a reservoir, the oil in place is oxidized to generate energy. The energy is stored within the reservoir matrix. The energy is extracted by injecting water and producing steam and electricity is generated from produced hot fluid likewise EGS. By converting oil fields into EGS, not only energy generation is possible but also potential environmental hazards are prevented as the oil will be combusted within the reservoir. The study is composed of two main parts: First, lab scale simulations were performed with CMG STARS with integration of combustion reactions. The key parameters for the success of the process were identified and criteria for propagating a steam zone behind the combustion front were determined. Second, based on lab scale simulations with kinetic reactions, an up-scaled model was built with pseudo reactions and field scale simulations were performed. Sustainability of high flow rates (at required temperatures) needed to support a commercial-sized power plant seems to be one of the major concerns regarding the process. INTRODUCTION Challenges in meeting energy demand and the need to decrease carbon dioxide emissions caused an awakening of many countries to the need to evaluate and develop alternative energy resources. Consequently, in recent years, research in alternative energy resources has taken a dramatic upswing both in US and throughout the world. This upswing has resulted in new information and greater understanding of resource characteristics. Among alternative energy resources, geothermal energy from EGS represents a large resource that can provide substantial base-load electric power and heat with minimal environmental impacts (MIT 2006). The study intends to combine two known methods; EGS and ISC to extract energy from depleted oil reservoirs. The idea, at its purest form, is to create a geothermal system artificially by in situ combustion of hydrocarbons in an abandoned oil reservoir. Heat is mined likewise EGS. In 2008, Li and Zhang introduced the concept of using abandoned oil reservoirs to generate power by using geothermal power generation technology (Li and Zhang 2008). In their study, using Du84 reservoir in Shuguang oil field as an example, the power and the possible income that might be generated from such an EGS were calculated by using simple energy balance calculations; however, they did not perform any simulations studies so it is not clear if it is possible to sustain the high flow rates required to feed a geothermal power plant with the proposed method. Nevertheless, their results were encouraging. This study intends to explore the technical feasibility of the proposed concept by using laboratory and field scale simulations. Most of the abandoned oil reservoirs do not have an economic value. Some of these reservoirs are suitable for gas storage; however, majority of these fields are potential environmental minefields. Oil and gas wells can develop leaks along the casing years after the production has ceased and the well has been plugged and abandoned (Dusseault et. al. 2000). Well sealing technology relies on cement. Because of improper

2 application (or in time) cement can crank, or shrink resulting in an environmental hazard. The exact number of abandoned wells is unknown; however, within a rough estimate tens of millions of abandoned wells exit globally with likely hundreds of thousands already leaking to a greater or lesser extent. These leaks may accelerate environmental problems such as ecosystem destruction, biodiversity loss, and contamination of aquifers. By converting oil fields into EGS, not only energy production is possible but also a potential environmental hazard could be diminished as the oil would be combusted within the reservoir. If the process is feasible, this would result in re-evaluating fields giving chance to find out and eliminate possible hazardous ones provided that proper governmental regulations are imposed. The proposed concept could be classified as an EGS with major differences. Instead of mining the energy naturally occurring due to heat flux through the crust of the Earth, here the energy is generated within the reservoir from the unrecoverable hydrocarbons. The proposed method is based on two studied and tested concepts: EGS and ISC. Enhanced Geothermal Systems The basic idea of EGS is to recover thermal energy contained in subsurface rocks by creating or accessing a network of connected fractures through which water can be injected towards the production wells. Circulated fluid is heated by contact with hot rocks and returned to the surface via production wells forming a closed loop, shown in Figure 1. In a sense, EGS model is an imitation of naturally occurring hydrothermal systems with addition of missing components artificially. The history of EGS field efforts dates back to early 1970s beginning with the Fenton Hill project in the US. The program was first referred to as the Hot Dry Rock (HDR) project. Later this name was replaced by EGS. The project was terminated at the Fenton Hill site by The project successfully demonstrated the technical feasibility of the concept; however, performance characteristics were not adequate to sustain a commercial-sized system (MIT 2006). Based on the experience and data from Fenton Hill several projects were started; Rosemanowes / UK, Hijiori / Japan, Ogachi / Japan, and Soultz / France. These projects built up a substantial amount of information and experience on EGS. In 2006, Massachusetts Institute of Technology (MIT) published a report providing a comprehensive assessment of EGS. The report (MIT 2006) gives a review of EGS projects initiated summarizing lessons learned and remaining needs. Figure 1: Schematic of a conceptual EGS (MIT 2006). Still there are many challenges to be overcome, sustainability of high flow rates (at required temperatures) needed to support a commercial-sized power plant seems to be one of the major concerns. Based on the production rates of natural hydrothermal systems, flow rates ranging from kg/s, depending on the temperature, needs to be achieved to be able to generate 5 MW electricity per well (MIT 2006). Besides, temperature of the produced fluid needs to be kept high enough to meet the design capacity. This would require a large heatexchange area or long residence time which could result in a high pressure drop. In situ combustion On the other side of the concept resides ISC. Also known as fire-flooding or air injection, is an enhanced oil recovery (EOR) technique mostly applied to heavy oil reservoirs to improve oil recovery. Successful implementation to lighter oil reservoirs has also been presented in the literature (Moore and Mehta, 2002). In situ combustion is the process of injecting air into a reservoir to oxidize a small portion of the hydrocarbons present, to generate heat and pressure. Energy is generated within the reservoir with the combustion of hydrocarbons leading to the name in situ combustion. The burning is sustained by injecting air or oxygen rich gas into the formation. As temperature increases, oil viscosity is reduced, and the oil is driven towards the producing wells by a vigorous gas drive of the combustion gases, a steam drive and a water drive.

3 with and thus upgrade the original crude (Castanier and Brigham 2003). A steam plateau forms next to the coking zone. Depending on the local pressure, the temperature of this zone differs. The steam plateau is succeeded by a hot water bank as the decrease in temperature forces steam to condense. The hot water bank is preceded by an oil bank where the mobilized oil accumulates. The temperature along the oil bank decreases in the direction extending away from the combustion zone. The virgin reservoir lies beyond the oil bank. Figure 2: Schematic of ISC process (Cinar, 2011). Figure 2 is a schematic of a typical in situ combustion process. In this illustration, the air is injected from the well in the middle and the production wells are located on each side. The ignition is initiated by a down-hole heater such as an electrical heater or a gas burner; however, in some cases the ignition is started spontaneously without any igniters (Tadema 1959). Figure 2 is a cross section of the reservoir at some time after the injection started. Similar to steam injection, all the gases in the process tend to go up in the reservoir. This is because of the density difference between air and reservoir fluids. The lighter air tends to override the reservoir fluids. As the combustion front propagates within the reservoir different zones are formed within the reservoir, as shown in Figure 2. These zones differ by their temperature and fluid saturations. The first zone appearing in the illustration shows the burned zones. This is the zone swept by combustion and is saturated with air. The temperature is high in this region. In some applications, water is injected along with air to harvest the energy left behind in the rock. This is referred to as wet combustion. Next to the burned zone is the combustion zone. This is where the reactions take place. Sarathi (1999) describes this zone as a smoldering glow passing through the reservoir. In this zone, formed coke is burned to generate the energy to sustain combustion. Also, combustion products CO, CO 2, and water originate from this region. Just downstream of the combustion zone, comes the coking zone. Exothermic reactions in the combustion zone lead to high temperatures. As the temperature is transferred ahead of the combustion zone ideal conditions for coking exist. Here, the oil is distilled and thermally cracked forming lighter hydrocarbons leaving a carbonaceous residue behind known as coke. Coke is actually the fuel for combustion. The light ends are transported downstream by combustion gases where they mix This study explores the idea of converting abandoned oil reservoirs into EGS by using an old standing oil recovery method ISC. The study is composed of two main parts: First, lab scale simulations were performed with CMG STARS (2012) with integration of combustion reactions. The key parameters for the success of the process were identified and criteria for propagating a steam zone behind the combustion front were determined. Second, based on lab scale simulations with kinetic reactions, an up-scaled model was built with pseudo reactions and field scale simulations were performed. SIMULATIONS Combustion tube simulation runs were performed with CMG STARS (2012). Oil-water and liquid-gas relative permeability curves are shown in Figures 3 and 4 respectively. The oil is 13.5 API dead oil. The viscosity temperature relation is given by Eq. (1) T K cp e (1) Figure 3:Oil-water relative permeability curves.

4 and 2. These reaction parameters are based on isoconversional methods (Cinar et. al. 2009; Cinar et. al. 2011; Cinar et. al. 2011). Please refer to Cinar (2011) for further details of the reaction scheme used. Oil 4O 10Coke H O (2) Coke 1.5O CO CO Coke 2Coke 1 2 Coke O 0.5CO CO Table 1: Reaction parameters for simulations. Reac. A E, J/mol ΔH, J/mol 1 2.0E+12 mol/cm 3 min 9.3E E E+08 mol/cm 3 min 5.2E E E+07 1/min 9.5E E E+12 mol/cm 3 min 1.1E E+05 (3) (4) (5) Figure 4: Liquid-gas relative permeability curves. Physical and thermal properties of oil, rock, and insulation are necessary to run the simulations. These are based on correlations and data available in the literature. In simulation studies, a heavy oil of 13.5 API with a molecular weight of 515 g/ gmol is assumed. Formation properties; porosity and permeability are assumed to be, respectively, 0.25 and 1000 md. The thermal properties, critical properties are estimated based on data in the literature. In addition, the dead oil assumption is used; all equilibrium constants for oil are assumed to be zero. The critical properties of oil are estimated based on the correlations given by Kesler and Lee (1976). Once the molecular weight and the specific gravity are known, critical pressure, critical temperature, acentric factor, and boiling point are estimated based on these correlations. Specific heat capacity of the oil is estimated based on the correlations given by Watson and Nelson (1933). Heat capacity of sand and gas components are based on SiO 2 values from NASA Glenn Coefficients for Calculating Thermodynamic Properties of Individual Species (MacBride et.al 2002). Table 2: Molecular weight of lumped components. Comp. Molecular Weight, g/gmol Oil 515 Coke 1 24 Coke 2 12 First a dry combustion tube run was carried out. The initial temperature for the first 5 grid blocks is assumed to be 800 C for ignition to occur. The rest of the core is at 25 C. The pressure is assumed to be kpa (100 psia). Heat losses are modeled with a proportional heat transfer coefficient, 0.03 J/cm 2 - min- C, used in conjunction with a set temperature value 25 C. Heat is lost through the outer surface of the insulation jacket and at the production end. The simulation starts with air injection from one end of the core and the fluids are produced from the other end. The air injection rate is 3000 cm 3 /min. Once the injection is started combustion is initiated and some portion of the oil is burned. As a result CO 2 and CO is formed. The oxygen utilization is almost 100% and the produced gas is composed of CO, CO 2, N 2. The resulting temperature profiles are given by Figure 5. The temperature measurements are 5 cm apart from each other, profiling all the length of the tube. Laboratory scale simulations The simulations were performed with a one meter long cylindrical core of seven centimeter diameter. The core was modeled with 200 grid-blocks in z direction and 2 grid-blocks in r direction. The first grid-block in r direction represents the porous medium and the second block represents the insulation jacket. Oil and water saturation is assumed to be 0.4 and 0.3 respectively. The reaction scheme used in simulations is given by Eqs. (2) through (5) and the associated parameters are given by Table 1 Figure 5: Temperature profiles for dry combustion run.

5 The combustion temperature is around 690 C. It takes about 11 hours to sweep the entire volume. The average speed of the combustion front (v cf ) is cm/min. Cumulative oil produced (COP) is 175 cm 3. Fuel burned (FB) is cm 3 oil/cm 3 of sand and (~460 Bbl/acre-ft). This value is higher than the experimental values. That s probably because the change of residual oil saturations with temperature was ignored in simulations. Air requirement is 460 cm 3 air / cm 3 of tube (20 MMScf/acre-ft). Next the simulations were repeated with water injection at different rates. Water injection began at about one third of the length of the tube had been swept by the combustion front. Water injection rates (q wi ) used are 1, 2, 3, 4, 4.5, 5, and 5.5 cm 3 /min. Combustion front velocity, fuel burned, and injected water/air ratio for different cases are given by Table 3. As injection rate increases, oil production, combustion front speed increase and amount of oil burned decreases. These observations are in line with experimental results of Burger and Sahuquet (1973). Table 3: q wi, cm 3 /min Calculated values of water/air ratio, combustion front speed, and fuel burned for different cases. Water/Air Ratio v cf, cm/min FB, cm 3 of oil/cm 3 of sand Combustion front was extinguished for runs with water injection rate higher than 4 cm 3 /min. Thus, the maximum water/air ratio should be unit volume of water injected per unit volume of air injected. A typical temperature profile for wet combustion run is shown in Figure 6. Three distinct fronts are clearly indicated by the figure. First, the temperature starts to increase at the condensation front which is preceded by a steam plateau. The combustion front with the highest temperature appears farther left. Finally, the temperature decreases behind the combustion front because of heat losses and break in the temperature profile occurs when the injected water begins to vaporize. Figure 6: Typical temperature profiles q iw = 3 cm 3 /min and t=300 min. Combustion front speed reaches a steady state when vaporization front speed is lower or equal to the combustion front speed. On the other hand, when the vaporization front overruns the combustion front the front temperature starts to decrease and extinction occurs. Another important observation is the decrease in fuel consumption (increase in oil production) with increasing water injection rate. This could be something favorable if the objective was to produce oil; however, the objective of the process proposed is to extract the energy not the oil; thus, the engineering design objective is significantly different. The objective here is to generate as much energy as possible by burning oil in situ. One option is to start injection once all the tube is swept. In such a case the heat losses to the surrounding environment would be maximized. The water injection rate and the time to start injection should be chosen by considering those facts. Filed scale simulations Field scale simulations are performed with Zhu s (Zhu 2011) approach, rather than using full kinetics. ISC field scale simulations are challenged by the fact that the combustion front is very thin (couple of centimeters) compared to grid block sizes (tens of meters) used in a regular reservoir scale simulations. Thin combustion front restricts the size of the gridblocks to be used in ISC simulation to centimeters; however, it is not possible to perform a reservoir scale simulation with grid blocks having dimensions in centimeters. Once the temperature is averaged in a large grid block where combustion front present, some of the reactions does not propagate because of

6 the high activation energy of the reactions. One way around is to use dynamic local grid refinement but this approach is at its development s early stage (Christensen et. al. 2004). On the other hand, Zhu s approach provides a way to be able to perform field scale ISC simulations without using small grid blocks with acceptable outcome. In his approach, it is assumed that constant amounts of the oil in place will be combusted regardless of the local conditions and this amount is known from experimental combustion tube studies. Once oxygen reaches any place in the reservoir, the combustion starts instantly, burning the amount determined a priori. One drawback of this approach is the fact that local conditions, such as local concentration of oxygen, have a profound effect on the amount of oil to be combusted. With all its drawbacks, Zhu s approach is appropriate for this study since this study focuses on the ways to extract the energy left behind a combustion front rather than the kinetics of it. As long as the heat generated within the reservoir is in the range with the real cases the method used will give reliable results. The pseudo reaction scheme for field scale simulations is given by Eqs. (6) and (7). Oil aoil bcoke ch O (6) not reacting 2 2 Coke 1.85O 0.5CO CO 0.7H O (7) The activation energy for both reactions is zero (preexponential factor is assumed to be one); that is reactions occur instantaneously and reaction rate do not depend on temperature. At an instant coke forms leaving behind an oil component not reacting. All the oil converted is produced without any residual left behind. Therefore, the relative permeability curves needs to be adjusted so that there is no residual oil left behind; however, this significantly changes the amount of steam in the steam plateau thus the relative permeability curves left intact and all the oil not reacting is assumed to be produced. As reactions are temperature independent, once the oxygen and coke component meets, the reactions propagate instantaneously producing carbon monoxide, carbon dioxide and water. The stoichiometric coefficients are determined by using lab scale simulations at different air/water ratios. While doing so, the pseudo reactions are integrated in lab scale combustion tube simulation model and pseudo reaction parameters are adjusted so that the same fuel burned, combustion front speed, air requirement, and peak temperatures values are obtained with the full kinetics simulations. Once these parameters are estimated, these pseudo reactions are integrated in field scale simulation model. Thus, the pseudo reaction model is calibrated based on full kinetics model. Field case results were obtained for a 20 acre five spot pattern with an air injection rate of m 3 /day (~10 MMscf/Day) and water injection rate is estimated based on combustion tube runs. The stoichiometric coefficients of Eq. (6) for wet combustion cases are estimated based on combustion tube runs for cases with the same water/air ratio. The stoichiometric coefficients are given along with water injection rates in Table 4. The reservoir pressure at the start of air injection is assumed to be 20.7 bars (300 psia) and the wells are produced at constant bottom hole pressure of 13.8 bars (200 psia). Initial temperature of the reservoir is 32 C. Table 4: water/air ratio Stoichiometric coefficients for different water/air ratio. Water injection rate, a b c m 3 /day Based on combustion tube runs maximum water injection that would allow propagation of combustion front is ; however, field scale simulations performed with this rate indicates that it is not possible to sustain the combustion front with m 3 /day (~2.2 kg/s) water injection rate. Simply the combustion front cannot propagate while heating that much water. Thus, the water injection rate is decreased to m 3 /day with an air/water ratio of Water injection starts after 100 days of air injection. Figure 7 shows total produced fluid temperature with mass rates of produced water, steam, and combustion gases at reservoir conditions of all production wells. Water is saturated at reservoir conditions with changing steam quality. The steam plateau is produced at an average temperature of 160 C for about 440 days with an average total water production rate of 2.5 kg/s. This is higher than the water injection rate due to produced water during combustion. In addition about 5.5 kg/s of gas is produced at the same temperature composed of CO 2, CO, N 2, and O 2 with changing composition in time. Then the combustion front reaches the well and extreme temperatures are observed in these wells. For about another 440 days the produced fluid temperature rises from steam temperature, up to combustion front temperature of 650 C and decreases down to steam temperature at the end. The average water mass production rate during this period is 2.0 kg/s. It takes about 1000 days for the system to cool down to 114 C with similar water production rates. Nevertheless, the produced water rates for a single pattern are far from sufficient to be able to

7 produce electricity. Based on these rates, in order to achieve feasible rates just for electricity production, at least 15 patters should be combusted simultaneously. Water and air is injected together so it is clear that the injection costs would be very high in such a situation. a 20 acre pattern for the given conditions and only 5 months of electricity production is possible. Figure 8: Mass production rate and produced fluid temperature at reservoir conditions for dry combustion case. Figure 7: Mass production rate and produced fluid temperature at reservoir conditions for wet combustion case. Another possibility to consider, in order to achieve high water production rates, is to start injection once the entire pattern is swept by combustion. If the reservoir characteristics are appropriate, high water injection rates could be achieved as the combustion already ended. In such a case, the process is carried out in a dry manner, thus, more oil is combusted in situ, generating more energy. In this scenario, the same model was used with the wet combustion case. In this scenario, 1750 days (~4.8 years) of air injection at a rate of m 3 /day (~10 MMscf/Day) is followed by 41.6 kg/s water injection. The combustion front reaches the production wells at 1750 th day. Produced fluid temperature and fluid production rates are shown in Figures 8 and 9. Produced water temperature cools down from 220 C to 130 C in 150 days of water injection. Mass rate of produced water is about 40 kg/s. Note that there is a transition period prior to achieving aforementioned rates where the produced fluid temperature decreases rapidly from 410 C to 220 C and water mass rate increases from 10 kg/s to 40 kg/s in 15 days. This variety of temperature in produced fluid could be a major problem in power plant design. One way around is to cool down the production wells by injecting water through production wells for some time. The crucial point here is the fact that it takes almost 5 years to combust Figure 9: Mass production rate and produced fluid temperature at reservoir conditions for dry combustion case between 1800 and 2000 days. In this scenario, although high flow rates for electricity production is possible, the system cools down in just 150 days after 1750 days of air injection. Still the process is far from feasible considering injection cost of air and water as well as investment cost for compressors. There are two main reasons behind. First, due to high air injection rates, reservoir behind the combustion front significantly cools down. Second, 40% of the original oil in place is produced. This is significant amount of oil and it is not clear if these oil production

8 rates are realistic or not. In a field application the process would suffer from gravity override resulting in a portion of the reservoir to be bypassed lowering the amount of oil produced. One way to increase fuel burned is to apply reverse combustion. In this process, the oil is ignited in the production wells, so combustion front propagates towards injection wells. Air and combustion front moves in opposite directions. Injected oxygen flushes the reservoir before oil in place is consumed thus, coke formation is favored and amount of oil burned increases. In addition, as the air injected passes through the cold reservoir, injected air does not cool down the system. It is not possible, however; to simulate reverse combustion at field scale with the method described in this study. Instead, final case is built based on the assumption that 90% of the original oil in place is burned within the reservoir. In such a case, stoichiometric coefficients of pseudo reaction (Eq. (6)) becomes, a = 0.1, b = , and c = Again the system is swept by high rates of injected water after air injection. In this case 2936 days (~8 years) of air injection is followed by 41.6 kg/s water injection. The combustion front reaches the production wells at 2936 th day. Produced fluid temperature and fluid production rates are shown in Figures 10 and 11. a water mass production rate of 36 kg/s in average. Then, in the third period the system rapidly cools down from 200 C to 130 C in just 65 days and the average water mass production rate is 40 kg/s. Figure 11: Mass production rate and produced fluid temperature at reservoir conditions for second dry combustion case between 2990 and 3200 days. Based on the simulation results, for the best case scenario where 90% of the original oil in place burns, 36 kg/s water is produced for 160 days with changing fluid temperature from 240 to 150 C. In addition, bbl oil is produced. The temperature range considered is appropriate for a double flash plant. If we assume that 3 patterns are combusted simultaneously, it would require m 3 /day (~30 MMscf/Day) of air injection for about 3000 days in exchange for 160 days of water production with a mass rate of 108 kg/s total. In addition, cumulative oil production is bbl. Based on these numbers total power output is estimated as follows. Double flash plant power output as a function of fluid temperature for the rate of 100 kg/s could be estimated with the following correlation. Figure 10: Mass production rate and produced fluid temperature at reservoir conditions for second dry combustion case. Figure 11 indicates three distinct regions in terms of produced fluid temperature similar to the previous case. In the first period, the produced fluid temperature decreases from 800 C to 240 C in 10 days with an average water production of 32 kg/s. In the second period of 115 days, the produced fluid temperature cools down from 240 C to 200 C with PowerOutput MW T C e (8) Eq. (8) is found by curve fitting data provided by MIT report (MIT 2008, Figure 7-9). Simulation results indicate that the fluid temperature changes with time. Incorporating simulation results with Eq. (8), Figure 12 is plotted. Figure 12 shows that average power output is about 8 MW and total energy production is kw-h from 60 acres. On the other hand, the process requires air injection for almost 8 years with a high injection rate of m 3 /day (~30 MMscf/Day). It takes 8000 HP (~6

9 injection at high rates for a period of 8 years, possible energy production is far from economical. Besides, a 12 MW double flash power plant, 8000 HP air compressor, and water pumps, which would require high initial investment, are needed. The process could be feasible where oil production is significant. In such a case, by using proposed concept additional power could be generated to support air compressors provided that reservoir characteristics allow high rates of water injections. ACKNOWLEDGMENT Figure 12: Power output of double flash plant for the rate of 100 kg/s (second dry combustion case). MW) to inject 30 MMscf/Day of air at 675 psia (Sarathi 1999). The bottom-hole pressure in the scenario considered is about 2200 kpa (~320 psia) for the air injection period. In conclusion, air injection energy requirements itself (also water in injected or 6 months) would be higher than the produced energy. CONCLUSIONS This study explores the idea of converting abandoned oil reservoirs into EGS via ISC. The applicability of the idea is tested with field scale simulations. Mainly two scenarios are considered; wet combustion and dry combustion followed by water injection. Lab scale, high resolution simulations are performed with a set of kinetic equations. Based on lab scale experiments, field scale simulations are performed at 20 acre 5-spot pattern. Field scale simulations are performed with pseudo reactions calibrated with lab scale high resolution simulations. The results show that for the wet combustion case mass production of water is not enough to sustain a commercial sized power plant. High water injection rates are not allowed in the case of wet combustion as combustion is extinguished by high volumes of injected water. Second, 20 acre pattern is swept by combustion and water injection at high rates follows. In this case for about six months high temperature fluids are produced with high mass flow rates of water that are suitable for electricity production. The possible power output is estimated for a double flash plant. For the best case scenario where 90% of the original oil in place burns and gravity override effects are ignored, compared to energy requirements of air I would like to thank Istanbul Technical University for providing financial support for this study and Calgary Modeling Group (CMG) for providing STARS to our department for academic purposes. REFERENCES Burger, G.J., Sahuquet, B.C., Laboratory research on wet combustion, SPE Journal, 1973, 25 (10), Castanier, L. M. and Brigham, W. E. Upgrading of crude oil via in situ combustion. Journal of Petroleum Science and Engineering, 39(1-2): , Special Issue honoring Professor W.E. Brigham. Cinar, M., Castanier, L.M., Kovscek, A.R., Combustion Kinetics of Heavy Oils in Porous Media, Energy & Fuels, 2011, 25 (10), Cinar, M., Hascakir, B., Castanier, L. M., and Kovscek, A. R. Predictability of crude oil in-situ combustion by the isoconversional kinetic approach. SPE Journal 16(3), September 2011, Cinar, M., Castanier, L.M., Kovscek, A.R., Isoconversional Kinetic Analysis of the Combustion of Heavy Hydrocarbons, Energy & Fuels, 2009, 23, Cinar, M.: Kinetics of crude-oil combustion in porous media interpreted using isoconversional methods, Stanford University, Stanford CA, USA, CMG-STARS, Advanced Process and Thermal Reservoir Simulator. Computer Modelling Group Ltd, Alberta, Canada, Christensen, J.R., Dechelette, D. B., Ma, H. Sammon, P.H., Applications of dynamic gridding to thermal simulations., SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield,CA, USA, March 2004.

10 Dusseault, M. B.,Gray, M. N., Nawrocki, P. A. Why Oil wells Leak: Cement Behavior and Long- Term Consequences, International Oil and Gas Conference and Exhibition in China, 7-10 November 2000, Beijing, China. Genter, A. (ed), European geothermal project for the construction of a scientific pilot plant based on Enhanced Geothermal System, Final report April 2004 September 2009, Project co-funded by European Commission within the sixth framework programme. Li, K. and Zhang, L., Exceptional enhanced geothermal systems from oil and gas reservoirs, PROCEEDINGS, Thirty-third Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California, January Kesler, M.G. and Lee, B.I., Improve predictions of enthalpy of fractions. Hydro-carbon Processing, pages , March McBride, B. J., Zehe, M. J., and Gordon, S., NASA glenn coefficients for calculating thermodynamic properties of individual species. Technical Report NASA TP , Misc. Publication No. 97, NASA-Glenn Research Center, Cleveland, OH, Technical Report NASA TP ff Moore, R.G., Mehta, S.A., Ursenbach, M.G. A Guide to High Pressure Air Injection (HPAI) Based Oil Recovery, SPE/DOE Improved Oil Recovery Symposium, April 2002, Tulsa, Oklahoma. Penberthy W.L. and Ramey, Jr. H.J. Design and operation of laboratory combustion tubes, SPE Journal, 2(6): , June Sarathi, P. S. In-situ combustion handbook{principles and practices. Final report: November 1988, doe/pc/ , United States Department of Energy, National Petroleum Technology Office, January Tadema, H. J. Mechanism of oil production by underground combustion. In 5th World Petroleum Congress Proceedings, New York, USA, May 30 - June Tester, J.W., Thee future of geothermal energy, Massachusetts Institute of Technology, 2006, Boston. Watson, K. M. and Nelson, E. F. Improved methods for approximating critical and thermal properties of petroleum fractions. Industrial and Engineering Chemistry, 25(8): , Zhu, Z.: Efficient simulation of thermal enhanced oil recovery processes, Stanford University, Stanford CA, USA, 2011.