Hot sedimentary aquifer (HSA) geothermal exploits thick, porous, permeable aquifers for electricity generation, district heating, and direct-use applications. HSA temperatures are typically lower than traditional (hydrothermal) geothermal plays because high temperature over geologic time tends to destroy porosity by cementation. However, HSAs have substantial economic advantages over other geothermal resources. These advantages include long well life, large volumes of water, stable production temperature because water flow through the rock matrix more completely extracts the rock’s heat, and typically there is no need to for expensive stimulation. In contrast, geothermal wells relying on flow in natural or induced fractures in impermeable rock can experience comparatively rapid cool-down because of the low thermal conductivity of rock and may require stimulation to promote sufficient fluid flow. Closed-loop systems have limited potential due to the low thermal conductivity of rock. Existing oil and gas fields are good places to exploit HSAs in part because they are often hotter than surrounding areas (that’s why the oil and gas are there) but especially because abundant, high-quality data has been collected by oil and gas operators. Such data includes log, core, seismic reflection, fluid, and pressure data. This presentation discusses the identification, characterization, and reservoir simulation of an HSA geothermal prospect in the Denver-Julesburg (DJ) Basin of Colorado using such existing data sets. The pilot, production, and injection well permits for this project are the first deep geothermal well permits ever granted by the state of Colorado. The project targets the Permian age Lyons Fm., an eolian sandstone that averages ~40m thick in the area of interest. On the east side of the DJ Basin, the Lyons was deposited in a sabkha environment so that rock was completely cemented with anhydrite shortly after deposition. The anhydrite cement preserved the porosity through a long history of burial and diagenesis. Another diagenetic product was quartz cementation at quartz grain contacts. Subsequent fluid flow from the recharge area along the mountain front on the west to the discharge area in western Kansas removed the cement over large areas of the formation resulting in a strong, porous, and permeable rock. Density-porosity logs and core plug measurements show that the average porosity in the target area is 16%-17%, which is excellent. The horizontal and vertical permeabilities were determined from 71 core plug measurements and average 190-240 mD and 30-60 mD, respectively and a porosity-permeability transform was developed from these data. Elastic moduli, compressive strength, and sanding potential were determined from core testing. A few small, gentle anticlines in areas of porous Lyons trapped oil during regional fluid flow, but the formation is generally wet. Thermal mapping utilized 6,181 corrected bottom hole temperatures from oil/gas wells. The correction procedure was validated with cased-hole temperature logs and a one-dimensional thermal model. Temperature, porosity, the depth to the potentiometric surface, and other quantities were mapped to identify suitable drilling targets. The maps were used to identify a target area with an expected temperature of 130°C. There is little structure in the area resulting in minimal formation dips. Pressure data and literature on DJ Basin hydrodynamics indicate that little or no natural flow is currently occurring in this underpressured reservoir. Fluid samples from a nearby oilfield were evaluated for corrosion and scaling potential. A detailed static reservoir model of the prospect was built from representative well logs. The model included porosity, permeability, rock mechanics data, and other information. A producer-injector horizontal well pair was modeled with different well separations to determine the optimum spacing. Reservoir simulations with the FracMan™ software suite combined discrete fracture network and continuum methods into a hybrid model that captures the complexities of fluid-flow and temperature evolution in the complexly layered eolian sandstone. Pressure, temperature, fluid velocity, and fluid movement were tracked in three dimensions through time. Results show that the temperature of the produced water remains stable for over 20 years at a simultaneous production and injection rate of 100 kg/s. The detailed model was compared to a simple, homogeneous model run in the COMSOL™ software package. The results were similar, likely due to the high porosity and permeability of the rock. Pressure and temperature driven thermoelastic fracturing around the injector was estimated and mapped. Evaluation of sanding risk at the producing well is in progress as of this writing. A detailed static reservoir model of the prospect was built from representative well logs. The model included porosity, permeability, rock mechanics data, and other information. A producer-injector horizontal well pair was modeled with different well separations to determine the optimum spacing. Reservoir simulations with the FracMan™ software suite combined discrete fracture network and continuum methods into a hybrid model that captures the complexities of fluid-flow and temperature evolution in the complexly layered eolian sandstone. Pressure, temperature, fluid velocity, and fluid movement were tracked in three-dimensions through time. Results show that the temperature of the produced water remains stable for 20 years at a production and injection rate of 100 l/s. The detailed model was compared to a simple, homogeneous model run in the Comsol™ software package. The results were similar, likely due to the high porosity and permeability of the rock. Pressure and temperature driven thermoelastic fracturing around the injector was estimated and mapped. Evaluation of sanding risk at the producer is in progress as of this writing.

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