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petroleum systems. There should be some cross-over research applications between HPHT petroleum systems and stratigraphic geothermal systems. Delineating reservoir-seal sequences is a sophisticated process in petroleum exploration and has application to stratigraphic geothermal reservoirs; however, understanding the implications of high temperature fluid-rock interactions on permeability is well known in geothermal geoscience, but may be a cutting-edge area development of HPHT petroleum systems. Permeability With stratigraphic reservoirs, the main permeability is within specific geological formations, which in a basin usually means the permeability is nearly horizontal. In hydrothermal systems, the primary permeability allowing the upflow of hot water is usually fault-controlled and frequently sub-vertical. Numerical modeling of sedimentary reservoir-seal sequences suggests that the transmissivity (permeability-thickness) needs to be in the range of 3 – 10 Darcy-meters to avoid excessive pressure decline around production wells (Deo et al., 2014). This modeling also shows that the heat sweep efficiency, and therefore the long-term geothermal power potential, of the reservoir is much improved if there are multiple, thinner high permeability layers in a reservoir- seal sequence, rather than one thick layer of high permeability with the same overall transmissivity. A single high permeability layer allows a more rapid thermal break-through and leaves stranded heat in the reservoir, analogous to the short-circuiting of water in a fracture within a hydrothermal system. The modeling as- sumed four 25 m thick layers of 30 – 100 mDarcy as the reservoir, sandwiched between 1 mDarcy “seal” layers of variable thickness within a 300 reservoir-seal “sandwich”. Evidence from permeability tests in petroleum reservoirs confirms that permeabilities in the range of 30 – 100 mDarcy are not uncommon at depths greater than 3 km (Figure 3a). Kirby (2012) compiled permeability measurements from the western U.S. and found the mean permeability between 3 and 5 km depth is 75 mDarcy for carbonates, and 30 mDarcy for siliciclastics. There is no evidence in this dataset that permeability decreases with depth between 1 and 6 km depth with these two lithologies. However, there is a strong trend of decreasing permeability with depth in igneous rocks (volcanics and intrusives; most data is less than 2.5 km depth), most likely due to the mixed mineralogy of igneous rock and their sensitivity to al- teration and plugging of permeability. Clean sandstones and carbonates appear to be the lithologies most likely to sustain permeability at depth. Figure 2a. Types of geothermal and petroleum systems based on their temperature-depth characteristics. Figure 2b. Conventional hydrothermal and stratigraphic geothermal reservoirs superimposed on the field of HPHT oil and gas reservoirs in temperature-pressure space (modified from www.schlumberger.com, accessed 4/20/2014). Stratigraphic geothermal reservoirs usually have pressures close to hydrostatic (Allis, 2014; gradient of ~ 0.4 psi/foot), whereas deep petroleum reservoirs tend to be over-pressured, and some reservoirs approach a lithostatic gradient (~ 1 psi/foot). For metric conver- sions, 1 MPa is 10 bars and equal to 145 psi; 200°C is 392°F. There is a question whether the higher temperatures within the target zone for stratigraphic geothermal res- ervoirs compared to petroleum reservoirs at the same depth may increase rock ductility and decrease permeability. Two examples of deep gas plays in the Rockies region suggest that for temperatures of up to 240°C this doesn’t appear to be an issue with carbonate rerservoirs (Wilson et al., 2003; Figure 3b). High permeability Mississippian carbonates (often dolomitic) at hydrostatic pressure were encountered at depths of 5 – 7 km and temperatures of 210 - 240°C despite over-pressured formations at shallower depth. The hydrostatic condition implies pressure connection with the near surface, presumably because of the high lateral permeability within the carbonate formation, and a vertical connection in fault zones near the boundaries of the basins. There is a similar relationship between hydrostatic pressure and the Mississippian carbonate reservoir beneath the Paradox basin (Allis, 2014). The eastern Great Basin is also underlain by lower Paleozoic carbonates which appear to control inter-basin groundwater flow (Masbruch et al., 2012), and Allis (2014) has found that local hydrostatic conditions prevail everywhere. It is possible the inverse situation of over- pressures in prospective reservoirs may be an indicator that the prospective reservoir volume is limited and isolated from regional zones of high permeability by stratigraphy or faults. Allis and Moore Temperature (oC) 0 50 100 150 200 250 300 350 00 geothermal direct use traditional petroleum reservoirs (a) moderate temperature hydrothermal reservoirs (pumped wells) magma- hydrothermal high temperature hydrothermal reservoirs (self-discharging wells) HPHT petroleum reservoirs brittle-ductile transition stratigraphic geothermal reservoirs (sgr) sgr with improved economics 1000 2000 3000 4000 5000 6000 7000 5000 10000 15000 20000 0 100 200 300 400 Temperature (oF) 500 600 1011 Depth (m) Depth (ft)PDF Image | Can Deep Stratigraphic Reservoirs Sustain 100 MW Power Plants
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