On CO2 as Heat Transmission Fluid for Enhanced Geothermal Systems (EGS) Karsten Pruess and Tianfu Xu Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, California, U.S.A. Pressure and Temperature Profiles after 25 Years ABSTRACT For water, most of the available pressure force is used up to displace the highly viscous fluid around the injection well. For CO2, fluid mobility is much less reduced at lower temperatures, and more of the applied pressurization is available at the production well. Operating enhanced geothermal systems (EGS) with CO2 instead of water as heat transmission fluid is a novel concept that was originally proposed by D.W. Brown (2000). Brown pointed out that CO2 has attractive properties as an operating fluid for EGS, and could provide storage of greenhouse gases as ancillary benefit. We have performed a qualitative evaluation as well as detailed numerical simulations to compare the suitability of CO2 and water as operating fluids for EGS. For comparable conditions, we find that CO2 extracts heat from an EGS reservoir at approximately 50 % larger rates than water. Development of an EGS-CO2 reservoir would entail continuous injection of CO2 to remove the water, and significant water concentrations are predicted to persist in the produced CO2 stream for a long time (years to decades). Fluid losses during operation of an EGS with CO2 are estimated at 1 metric ton per second, per 1000 MWe installed capacity, suggesting that EGS-CO2 can provide a large storage capacity for CO2. producer injector Enhanced Geothermal Systems (EGS) Reservoir Development: Inject CO2, Drive out the Water Artificially create permeability through hydraulic and chemical stimulation. Recover heat at the land surface by circulating water through a system of injection and production boreholes. Experimental projects in the U.S., U.K., France, Japan, Australia, Sweden, Switzerland, Germany. Technical challenges for making EGS economically viable: Several challenges relate to water as heat transmission fluid. water solubility limit at injection conditions improve rates of fluid flow and heat extraction increase reservoir size reduce “parasitic” power requirements for keeping water circulating control dissolution and precipitation of rock minerals (avoid short-circuits, formation plugging) reduce water losses from the circulation system reduce cost of deep boreholes (≈ 5 km) “dry-out” At early time (≤ 0.1 year), produce single-phase water. This is followed by a two-phase water-CO2 mixture (0.1 - 4 yr). Total production rate during two-phase period is low due to phase interference. Subsequently produce a single supercritical CO2-rich phase with dissolved water. Water is removed from fracture network fairly rapidly (about 4.4 % remaining after 5 years). The low-permeability rock matrix provides a long-term source of water, with almost half of initial inventory remaining after 36.5 years. Significant concentrations of dissolved water persist in the produced CO2 stream for many years. fracture network in hot rock How About Using CO2 as Heat Transmission Fluid? (Properties: green - favorable; red - unfavorable) Wellbore Flow: CO2 vs. Water injection production ∆P Pressure difference P between production and injection well: CO2: 288.1 - 57.4 = 230.7 bar Water: 118.6 - 57.4 = 61.2 bar CO2 generates much larger pressures in production well, facilitating fluid circulation. EGS-CO2 Issues Effectiveness of CO2 as a heat transfer medium. Other processes induced by CO2, that may affect feasibility and sustainability of EGS with CO2 (chemical reactions, corrosion). Can we make an EGS-CO2 reservoir? (Circulate CO2 to remove the water.) Energy conversion system (binary plant w/ heat exchanger, vs. directly using CO2 on the turbines). Energy extraction vs. CO2 storage; economics. Fluid lost = fluid stored? EGS with CO2? CO2 Storage and Losses General Makeup of a CO2-Based EGS Reservoir CO2 inventory for the injection-production system considered here is 1.8 Megatonnes. For 1,000 MWe, would need 138.5 Megatonnes of CO2, circulating at a rate of 20 t/s. Expect a fluid loss rate of order 5%, or 1 ton per second of CO2 per 1,000 MWe of installed EGS capacity. This is equivalent to CO2 emissions from 3,000 MWe of coal-fired power generation. The MIT report (2006) projects 100 GWe (100,000 MWe) of EGS electric power in the U.S. by 2050. 100 GW of EGS with CO2 would store 3.2 Gt/yr of CO2, approximately 40 % of total current U.S. emissions. CO2 storage capacity from operating EGS with CO2 appears to be very large. CO2 lost = CO2 stored??? Zone 1 Central zone and core of EGS system, where most of the fluid circulation and heat extraction is taking place. This zone contains supercritical CO2; all water has been removed by dissolution into the flowing CO2 (rock-fluid interactions weak). Zone 2 An intermediate region with weaker fluid circulation and heat extraction, which contains a two-phase mixture of CO2 and water (expect dominant dissolution). Zone 3 The outer region affected by EGS activities. The fluid is a single aqueous phase with dissolved CO2 (expect dominant precipitation). (after Fouillac et al., 2004) Concluding Remarks Comparing Operating Fluids for EGS: CO2 vs. Water Water-based enhanced geothermal systems (EGS) face difficult hurdles to CO2 has attractive properties as a heat transmission fluid for EGS. Operating EGS with CO2 would require and store large amounts of CO2. Use of CO2 as heat transmission fluid for EGS looks promising and deserves more study. We are aiming to develop the scientific basis for a field demonstration. (1) achieve adequate heat extraction rates, and (2) maintain injectivity and heat extraction performance in the face of strong rock-fluid interactions. Heat extraction rates when using CO2 are estimated to be approximately 50 % larger than for water. CO2 is very favorable in terms of wellbore hydraulics. Rock-fluid chemical interactions are expected to be much weaker for dry, anhydrous CO2 than for water. Unavoidable fluid losses are costly for water, but could earn greenhouse gas storage credits when using CO2. * we include some wall rock in the definition of the fracture domain five-spot fractured reservoir References Parameters chosen after the EGS system in Soultz/France Monitor mass flow, heat extraction rates Brown, D.W. A Hot Dry Rock Geothermal Energy Concept Utilizing Supercritical CO2 Instead of Water, Proceedings, Twenty-Fifth Workshop on Geothermal Reservoir Engineering, pp. 233–238, Stanford University, January 2000. MIT (ed.), The Future of Geothermal Energy, Massachusetts Institute of Technology, Cambridge, MA, 2006. Pruess, K. The TOUGH Codes—A Family of Simulation Tools for Multiphase Flow and Transport Processes in Permeable Media, Vadose Zone J., Vol. 3, pp. 738–746, 2004. Pruess, K. Enhanced Geothermal Systems (EGS) Using CO2 as Working Fluid – A Novel Approach for Generating Renewable Energy with Simultaneous Sequestration of Carbon, Geothermics, Vol. 35, No. 4, pp. 351–367, August 2006. Pruess, K. On Production Behavior of Enhanced Geothermal Systems with CO2 as Working Fluid, Energy Conversion and Management, Vol. 49, pp. 1446–1454, doi:10.1016/j.enconman.2007.12.029, 2008. Pruess K. and N. Spycher. ECO2N – A Fluid Property Module for the TOUGH2 Code for Studies of CO2 Storage in Saline Aquifers, Energy Conversion and Management, Vol. 48, No. 6, pp. 1761–1767, doi:10.1016/j.enconman.2007.01.016, 2007. Spycher, N. and K. Pruess. A Phase-Partitioning Model for CO2-Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems, Transport in Porous Media, DOI 10.1007/s11242-009-9425-y, July 2009. Xu, T., K. Pruess and J. Apps. Numerical Studies of Fluid-Rock Interactions in Enhanced Geothermal Systems (EGS) with CO2 as Working Fluid, Proceedings, Thirty-Third Workshop on Geothermal Reservoir Engineering, Report SGP-TR-185, Stanford University, Stanford, California, January 28-30, 2008. heat extraction mass flow ∆M ∆Q ACKNOWLEDGMENTS This work was supported by Contractor Supporting Research (CSR) funding from Berkeley Lab, provided by the Director, Office of Science, and by the Office of Energy Efficiency and Renewable Energy under Contract No. DE-AC02-05CH11231 with the U.S. Department of Energy. Energy extraction rate with CO2 is approximately 50 % larger than with water (75 MW(th) = 13 MWe). Relative advantage of CO2 becomes larger for lower reservoir temperatures.