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Chapter 4 Geothermal Energy reservoirs, and associated teaching tools to foster competence and capacity amongst the people who will work in the geothermal sector. • Improvement of numerical simulators for production history match- ing and predicting coupled thermal-hydraulic-mechanical-chemical processes during development and exploitation of reservoirs. In order to accurately simulate EGS reservoirs, computer codes must fully couple flow, chemistry, poro-elasticity and temperature. Development of suitable fully coupled reservoir simulators, includ- ing nonlinear deformability of fractures, is a necessity. Modern laboratory facilities capable of testing rock specimens under simu- lated down-hole conditions of pressure and temperature are also needed. • Improvement in assessment methods to enable reliable predictions of chemical interactions between geo-fluids and geothermal reser- voir rocks, geothermal plants and equipment, enabling optimized, well, plant and field lifetimes. • Performance improvement of thermodynamic conversion cycles for a more efficient utilization of the thermal heat sources in district heating and power generation applications. Conforming research priorities for EGS and magmatic resources as determined in Australia (DRET, 2008), the USA, the EU ((ENGINE, 2008), the Joint Programme on Geothermal Energy of the European Energy Research Alliance)15 and the already-mentioned IPGT (see footnote in Section 4.5.3.2) are summarized in Table 4.6. Successful deployment of the associated services and equipment is also relevant to many conven- tional geothermal projects. The required technology development would clearly reflect assessment of environmental impacts including land use and induced micro-seismicity hazards or subsidence risks (see Section 4.5). The possibility of using CO2 as a working fluid in geothermal reservoirs, particularly in EGS, has been under investigation. Recent modelling stud- ies show that CO2 would achieve heat extraction at higher rates than aqueous fluids, and that in fractured reservoirs CO2 arrival at production wells would occur a few weeks after starting CO2 injection. A two- phase water-CO2 mixture could be produced for a few years followed by production of a single phase of supercritical CO2 (Pruess and Spycher, 2010). In addition, it could provide a means for enhancing the effect of geothermal energy deployment for lowering CO2 emissions beyond just generating electricity with a carbon-free renewable resource: a 5 to 10% loss rate of CO2 from the system (‘sequestered’), which is equivalent to the water loss rate observed at the Fenton Hill test in the USA, leads to ‘sequestration’ of 3 MW of coal burning per 1 MW of EGS electricity 15 The Joint Programme on Geothermal Energy (JPGE) is described at: www.eera-set. eu/index.php?index=36. (Pruess, 2006). As of 2010, much remains to be done before such an approach is technically proven. 4.6.4 Technology of submarine geothermal generation Currently no technologies are in use to tap submarine geothermal resources. However, in theory, electric energy could be produced directly from a hydrothermal vent using an encapsulated plant, like a submarine, containing an organic Rankine cycle (ORC) binary plant, as described by Hiriart and Espíndola (2005). The operation would be similar to other binary-cycle power plants using evaporator and condenser heat exchangers, with internal efficiency of the order of 80%. The overall effi- ciency for a submarine vent at 250°C of 4% (electrical power generated/ thermal power) is a reasonable estimate for such an installation (Hiriart et al., 2010). Critical challenges for these resources include the distance from shore, water depth, grid connection costs, the current cable tech- nology that limits ocean depths, and the potential impact on unique marine life around hydrothermal vents. 4.7 Cost trends16 Geothermal projects typically have high upfront investment costs due to the need to drill wells and construct power plants and relatively low operational costs. Operational costs vary depending on plant capacity, make-up and/or injection well requirements, and the chemical compo- sition of the geothermal fluids. Without fuel costs, operating costs for geothermal plants are predictable in comparison to combustion-based power plants that are subject to market fluctuations in fuel prices. This section describes the fundamental factors affecting the levelized cost of electricity (LCOE) from geothermal power plants: upfront investment costs; financing costs (debt interest and equity rates); taxes; operation and maintenance (O&M) costs; decommissioning costs; capacity factor and the economic lifetime of the investment. This section also includes some historic and probable future trends, and presents investment and levelized costs of heat (LCOH) for direct uses of geothermal energy in addition to electric production. Cost estimates for geothermal installations may vary widely (up to 20 to 25% not including subsidies and incentives) between countries (e.g., between Indonesia, the USA and Japan). EGS projects are expected to be more capital intensive than high-grade hydrothermal projects. Because there are no commercial EGS plants in operation, estimated costs are subject to higher uncertainties. 16 Discussion of costs in this section is largely limited to the perspective of private investors. Chapters 1 and 8 to 11 offer complementary perspectives on cost issues covering, for example, costs of integration, external costs and benefits, economy- wide costs and costs of policies. All values are expressed in USD2005. 423PDF Image | Geothermal Energy 4
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