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506 A. Ram Mohan et al. / Energy 57 (2013) 505e512 drilled so far [3]. These wells are considered as shallow hydro- thermal wells where the thermal gradient may be as high as 50 C/ km [3]. There are three advanced wellbore drilling technologies that will have potential applications in the construction and exploration of geothermal wells. Deep inside the wells, the pressure of the fluid (oil or gas) occupying the pores of the rock and the density of the rocks increase with depth. To avoid the blow out of these fluids from the well during the drilling process, the density of the drilling fluid has to be heavy enough to suppress the pressur- ized fluids within the pores of the rock and not light enough to fracture the rocks. In a certain range of depths, there is a narrow margin for the density of the drilling fluids within which the wells can be drilled safely. The drilling is done in stages where the diameter is largest at the top and smallest at the bottom of the well [6]. The reduction in diameter can be minimized by the expandable tubular casing process invented by Shell Oil, where an expandable device whose outer diameter is larger than the inner diameter of the casing is hydraulically pressurized to increase the outer diam- eter of the tube by 20% without compromising the strength of the tube [7e9]. The reliability of the process is yet to be proven in geothermal wells even though it has a potential to reduce the drilling cost of the wells. Another technique referred to as drilling with casing is also promising as it uses fewer and longer casings reducing the cost of well formation. These technologies have the potential to reduce the cost of the well formation by as high as $ 3 million per well [3]. Around 11.2 GWe of electricity is generated worldwide from geothermal energy [10]. As the temperature of the working fluid utilizing geothermal heat energy is much lower than that used in the combustion of fossil fuels, the Carnot efficiency of electricity generation from ORC is also lower. When water is used as a working fluid, the energy available for power generation from a supercritical fluid is significantly larger than in hydrothermal water at 200 C. Utilization efficiency, defined as the ratio of actual power generated to the maximum possible power output, is between 25% and 50% for the current geothermal systems used in power generation [3]. When water is used as a geothermal fluid, the installed capital cost for power generation is approximately $2.3/MWe for the geothermal fluid temperature of 100 C and $1.5/MWe when the geothermal fluid temperature is 200 C [11]. The cycle thermal ef- ficiency is estimated to be 22% at a resource temperature of 300 C and 14% at a geothermal source temperature of 200 C [12]. When water is used as a geothermal fluid for the extraction of geothermal heat energy, depending upon the available thermal energy in the geothermal fluid, there are four configurations possible for the conversion of geothermal energy into electricity. They are dry steam plants, single flash steam plants, double flash steam plants and binary steam plants. In dry steam plants, water injected into the geothermal well is recovered through the pro- duction well as dry steam. The production fluid will also contain non-condensable gases that typically account for 2% to 10% by wt of steam [13]. A cyclone separator removes all the rock debris and dust particles entrained in the steam. Expansion of the dry steam through an impulse/reaction type turbine produces power. As opposed to direct contact type condenser, a surface-type condenser is used for the condensation of steam so that the non-condensable gases can be treated for the removal of hydrogen sulfide [12]. As air- cooled condensers are uneconomical for small power plants, water- cooled condensers are used to condense the geothermal fluid. It is cooled in a cross-flow or counter-flow cooling tower and circulated back into the injection well to form a closed loop. The Geysers in northern California is an example where dry steam plant is used for the conversion of geothermal energy into electricity [12,13]. Predominantly, the geothermal fluid leaving the production well is a two phase mixture. The steam quality, indexed by the weight percentage of the steam in the mixture, is determined by the reservoir fluid conditions, well dimensions and well head pressure. The well head pressure is typically 0.5e1.0 MPa. In a single flash steam plant, the two phase mixture is fed to the cylindrical pressure vessel cyclone separator to separate the primary high pressure steam from the water. The high pressure steam is fed to the turbine for power generation. The hot water is circulated through heat exchangers for direct heat applications. In a double flash steam plant, the high pressure hot water is flashed through a control valve for the generation of steam that is subsequently expanded in a low pressure steam turbine for the generation of additional power. The amount of liquid wasted without the utilization of geothermal heat is 30 times more in a single flash power plant compared to that in a dry steam power plant [13]. The amount of power generated by a double flash power plant is 20%e30% greater than that recovered from a single flash power plant [13]. Binary cycle plants use an organic Rankine cycle (ORC) where the geothermal heat is transferred from the geothermal fluid (water in most cases) to a working fluid. The direct contact between the geothermal fluid and the turbine, a feature typical in both single and double flash cycles, is avoided and prevent damage to the turbine vanes caused by small particles and non-condensable gases. Extensive studies have been conducted on the properties of working fluid that are suitable for the organic Rankine cycle [14e 29]. The working fluids used in the ORC can typically be R134a for geothermal fluid temperatures as low as 100 C [14,15]. For geothermal fluid temperatures greater than 200 C, isobutane, isopentane, and a combination of mixture of fluids can be used [14,18]. 2. Approach to the utilization of carbon dioxide for the extraction of geothermal heat In arid regions, for example in the southwest part of the United States where subsurface temperatures are elevated, it is not feasible to use water as a geothermal heat transfer fluid due to its scarcity. An alternative geothermal heat transfer fluid that is cheap and abundant is necessary for the absorption of geothermal heat in these regions. In the year 2010, the total amount of CO2 emitted from the energy and the industry sector in the United States is 5.6 gigatons [30]. Almost 34% of the total amount of CO2 is emitted from coal combustion for electricity generation and coal utilization in the industrial sector [30]. Capture and sequestration of CO2 emitted from power plants is necessary to mitigate climate change [31]. The objective of the paper is to explore the possibility of uti- lizing carbon dioxide as an alternative geothermal fluid for the extraction of geothermal heat in arid regions and to simultaneously sequester CO2. Air-blown combustion, oxycoal combustion and gasification are the three coal-based technologies that can be utilized for power generation [32e34]. The CO2 stream produced from oxycoal com- bustion is concentrated compared to that obtained from air-blown combustion maximizing the storage space if CO2 is sequestered. However, oxy-combustion requires that the supply air is pre- separated in the upstream portion of the boiler with attendant parasitic loads [33]. In both cases, compression of CO2 to high pressures is necessary before sequestration. Post combustion car- bon capture is suitable for air-blown and oxycoal combustion [32]. In Integrated gasification combined cycle (IGCC), the concentrated stream of carbon dioxide is separated from the synthesis gas by pre-combustion carbon capture methods at high pressures suitable for sequestration. Pre-combustion carbon capture is more cost effective compared to post combustion carbon capture [35]. The higher efficiency of power generation for IGCC (42% based on HHV) [32,35] combined with the economic method of separation of CO2 Author's personal copyPDF Image | Energy Technology ORC
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