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Workshop on Geothermal Reservoir Engineering Stanford Univ

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Workshop on Geothermal Reservoir Engineering Stanford Univ ( workshop-geothermal-reservoir-engineering-stanford-univ )

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Fracture zone thickness size permeability porosity* rock grain density rock specific heat rock thermal conductivity Initial conditions temperature pressure Production/injection injector-producer distance injection temperature injection pressure (downhole) production pressure (downhole) 0.04 m 50mwideby 700 m long 200x10-12 m2 (200 darcy) 0.5 2650 kg/m3 1000 J/kg/ ̊C 2.1 W/m/ ̊C 200 ̊C 500 bar 650 m 20 ̊C 510 bar - CO2 being less dense, less viscous, and having lower specific heat - nearly cancel out for this problem. CHEMICAL ISSUES Aqueous solutions of CO2 can be quite corrosive, and can dissolve rock minerals, as well as attacking steel liners and casings used in well construction (Xu et al., 2005). However, the flowing CO2 stream would quickly dissolve in situ water and thereby remove the aqueous phase from the central zone of an engineered HDR reservoir. This region would be surrounded by a two-phase halo containing a mixture of supercritical CO2 and aqueous phase, and an outer zone with a single aqueous phase with dissolved CO2. Continuous operation of a CO2-HDR system would be expected to produce a rather dry CO2 stream that would not pose corrosion problems for production wells. Rock-fluid interactions in the absence of water The chemical interaction of supercritical CO2 with in situ rock minerals raises interesting questions. Brown (2000) suggested that CO2 would be a far less effective solvent than water, which would reduce the potential for dissolution and subsequent reprecipitation of minerals, thereby avoiding problems of scaling and formation plugging. Fouillac et al. (2004) pointed out that reactions between minerals and CO2 should be quite rapid at the elevated temperatures in an EGS system. They suggested that CO2 injection into granitic rock should give rise to formation of calcite. A possible example is the carbonation of wairakite, which can be written as (wairakite + CO2 calcite + kaolinite + 2 quartz) Ca(Al2Si4O12):2H2O + CO2(g) CaCO3 + Al2Si2O5(OH)4 + 2 SiO2 (2) At T = 25 ̊C, P = 1 atm, the molar volume of wairakite is 207.55 cm3/mole, while the molar volumes of the reaction products sum to 181.83 cm3/mole. This represents a volume reduction of 12.4 %, indicating that reaction (2) would cause an increase in reservoir porosity and permeability. For other minerals, prolonged exposure to supercritical CO2 may cause dehydration reactions that would remove loosely bound water. Such reactions would tend to reduce the molar volume of the minerals involved, which would increase porosity and permeability of the formations, and may promote reservoir growth. 490 bar * we include some wall rock in the definition of the fracture domain This problem is run in two variations, using either CO2 or H2O as reservoir fluid. The simulations use our TOUGH2 code with a special fluid property module "EOSM" for mixtures of water and CO2 (Pruess, 2004a, 2004b). After a brief initial transient, production flow rates stabilize at approximately FCO2 ≈ 11.5 and Fw ≈ 3 kg/s for CO2 and water, respectively. Net heat extraction rates were calculated as Gi = Fihi -(Fihi)inj (i = CO2, water), where injection enthalpy hi,inj was evaluated at downhole conditions of (T, P) = (20 ̊C, 510 bar). Fig. 8 shows simulated rates of net heat extraction as function of time, along with cumulative net heat extraction. It is 5x106 4 3 2 1 0 0 CO2 H2 O 300x10 12 250 200 150 100 50 0 50 100 150x106 Time (s) Fig. 8. Rate of heat extraction and cumulative heat produced for the fracture injection- production problem. seen that heat extraction with CO2 is somewhat more rapid than with water. The differences are rather small, however, indicating that the favorable and unfavorable differences in thermophysical properties

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