CGS – Controlled Wellbore-to-Wellbore Geothermal System Flow

Abstract

CGS – Controlled Wellbore-to-Wellbore Geothermal System Flow JA Pogacnik, PC Leary & PE Malin Institute of Earth Sciences and Engineering, University of Auckland j.pogacnik@auckland.ac.nz Uniquely in the domain of wellbore extraction of crustal fluids Enhanced/Engineered Geothermal System (EGS) fluid flow is predicated on wellbore-to-wellbore pathways. Primary oil/gas production, including tight gas and oil/gas shale fracturing operations, and hydrothermal steam production have country-to-wellbore flow geometries. Secondary/tertiary oil/gas production flow paths are wellbore-to-country loosely coupled to country-to-wellbore. EGS alone assumes detailed conservation of the production fluid. The unique EGS wellbore-to-wellbore flow geometry leads to a second distinction, degree of control. Wells producing from country-to-wellbore and/or wellbore-to-country flow geometries typically have lognormal productivity and/or injectivity distributions. Lognormal distributions are highly skewed to a large population of weak producers and a small population of strong producers. Country-to-wellbore and/or wellbore-to-country flow systems exact large drilling costs for low-productivity/low-performance wells. A major component of reservoir economics centres on attempts to increase the drilling rate of high-productivity wellbores and decrease the drilling rate of low-productivity wellbores. As historically such attempts have had limited success, it may be said that country-to-wellbore and/or wellbore-to-country flow-geometry drilling strategies allow little control of flow system permeability structure. In distinction, EGS wellbore-to-wellbore flow is predicated on a high degree of permeability structure control. The point in question is how to exercise that control. Our wellbore-to-wellbore EGS heat transport simulations indicate that 5 x 1000m long-reach wellbores can provide ~5MW electric power over a ~30 year lifetime if the wellbore offsets are of order 100m (total heat reservoir volume ~10^8m^3). We suggest, however, that EGS permeability stimulation of tight basement rock is nearly impossible to adequately control at the ~100m wellbore-to-wellbore offsets required for long-term heat extraction. While flow control may be possible in substantially smaller rock volumes, the consequent rapid cooling of the hot rock reservoir volume is commercially unviable. Wellbore-to-wellbore permeability structure control has then to be exercised in a different manner. Since most well productivity/injectivity distributions are lognormal, we note three empirical rules of fluid flow in crustal rock that embody the lognormality feature of in situ permeability structures: • Long-range scale-independent spatial correlation of grain-scale fracture defects Well-log data show that spatial fluctuations of rock physical properties occur at all scale lengths according to a specific power-law relationship between scale length given by spatial frequency k and fluctuation power S(k) at that scale, S(k) ~ 1/k, for five decades of spatial frequency ~1/km < k < 1/cm. • Multiplicative nature of percolation flow along grain-scale-defect network pathways Well-core data show that spatial fluctuations in well-core porosity äö are closely tracked by fluctuations in the logarithm of well-core permeability älog(ê), äö ~ älog(ê). • Permeability enhancement by increased fracture-connectivity Fluid-system data show that the integrated form of the äö ~ älog(ê) fluctuation relation, ê ~ ê0 exp(á(ö-ö0)), is closely related to the presence of fracture connectivity; low values of empirical parame