Session 5E: Transition from Oil & Gas

Geothermal electricity co-production is a viable option for oil reservoirs producing large water cuts with elevated wellhead-observed temperatures. Repurposing existing oil wells significantly reduces initial investment costs historically associated with geothermal resource utilization. The National Renewable Energy Laboratory (NREL), partnering with Gradient Geothermal, Inc. (formerly known as Transitional Energy) and Grant Canyon Oil and Gas, has been tasked to evaluate the feasibility of geothermal electricity co-production at the Blackburn Oil Field with Organic Rankine Cycle (ORC) generators. The Devonian steady-state reservoir has historically been producing high water cuts of 240°F (115.6°C) observed at the wellhead without documented pressure drawdown or thermal breakthrough. An estimated initial reservoir temperature of approx. 260°F (126.7°C) has been observed in the field and history-matched in a wellbore production analysis and reservoir simulation. Our objective was to develop a conceptual geological model of the subsurface, simulate a natural-state reservoir, model production scenarios, and complete a technical feasibility analysis to accomplish this task. Through extensive modeling and the use of available proprietary and public data, it was possible simulate three scenarios that indicated minimal thermal decline over the duration of a simulated ten-year production and re-injection scheme.

Flexibility is the capability of the power grid to maintain a balance between electricity generation and variable demand. This study presents preliminary results evaluating the impact of geothermal district heating systems on the flexibility of microgrid in Tuttle, Oklahoma. Heating demand profiles were modeled using EnergyPlus for the district that includes two schools and 250 single-family houses. Then, geothermal energy production was modeled using GEOPHIRES to estimate how much heating demand in the district can be supplied by five different geothermal system scenarios. The results indicated that geothermal energy production varied depending on the resource temperature at different depths, system configurations, and flow rates. For the grid flexibility analysis, electricity consumptions in the five geothermal systems were estimated for pump operations to circulate water from the wells to radiators, while electricity consumption by air-source heat pump in the base case was estimated to supply the same heating load. Electricity consumption in the geothermal systems was significantly lower than those in base cases. The electricity saved by the geothermal system was then incorporated into the microgrid electrical load profiles where variable renewable electricity generation is significantly high. The results visually showed that geothermal district heating system can improve grid flexibility as a baseload during the winter season. The results also highlighted potential opportunities to save energy costs that will be further analyzed in future study.

Bowman County, North Dakota, currently relies heavily on coal power, accounting for over half of its electricity generation and leading to substantial greenhouse gas emissions. This study utilizes advanced MATLAB modeling to evaluate the potential for transitioning the county to a renewable energy system comprising wind, solar photovoltaics (PV), geothermal, and energy storage. The proposed hybrid system is tailored to Bowman County's growing electricity demand, with nameplate capacities of 85.7 MW for wind, 24.4 MW for solar PV, 2.03 MW for geothermal, and 195 MWh for storage. Simulations verify that by 2040, this custom-designed system could supply over 90% of the county's projected daily loads, with an estimated levelized cost of $105.226/MWh over 15 years that is cost-competitive with conventional power. Implementing this plan would reduce Bowman County's daily carbon dioxide output by approximately 97% relative to continued coal usage. More broadly, this hybrid model serves as a versatile template for other communities striving toward clean, locally focused energy self-sufficiency. It provides a sustainable and adaptable roadmap to support the renewable transition while meeting regional electricity needs, demonstrating one pathway toward a greener future.

DeepStor envisions the demonstration of a geologic thermal energy storage system with a return flow temperature of 110°C. The connected district heating network at the North Campus of the Karlsruhe Institute of Technology runs with a base load of 2.1 MWth and reaches up to 50 MWth at peak load.

The subsurface of the campus comprises a series of sandstone horizons with a thickness of a few meters between 800 and 1,300 m depth, which connect to the depleted oil reservoirs of the former Leopoldshafen field. These sandstone layers are embedded in the marly Niederrödern and Froidefontaine formations and have numerically proven contain most of the heat in the reservoir layers when operated as a aquifer thermal energy storage (Stricker et al., 2020). The reservoir temperatures are between 60 and 90°C. At an injection temperature of 140°C and production and injections rates of 2 L/s that were extrapolated from the former oil production, the necessary return temperature is reached after 6 years during the entire production period.

This study investigates what proportion of renewable geothermal heat can be achieved in the district heating network of this campus by adding stored heat from the respective sandstone layers during the six cold months (October to March). In the summer months, the storage system is fed by the excess heat from the deep and fractured reservoir, which is operated in continuous mode.

Geothermal energy production is attractive since it is dispatchable, has low emissions, and low environmental impact. In the advent of scalable next generation geothermal systems, repurposing of depleted oil and gas wells can be a contributor to the energy transition. Wells can be repurposed for closed loop borehole heat exchange (BHE) for direct geothermal use or electricity production in areas with sufficiently high geothermal gradient. Repurposing old wells for BHE cuts capital expenditure on drilling and has little reservoir uncertainty compared to conventional open loop geothermal. In this paper we look at design and operational parameters for wells circulating water injected in the annulus space and the core tube feeding hot water to an organic Rankine cycle for energy production. An integrated asset model consisting of a multiphase flow simulator and a process simulator is used to optimize the produced electrical power. The aim is to show how commercial oil and gas simulators and methodology can generate techno-economic studies that lead to successful geothermal project design and operation.

Existing oil and gas fields are much more widespread than conventional (hydrothermal) geothermal fields. Many oil fields are desirable places to exploit Hot Sedimentary Aquifers (HSAs) for electricity generation and/or direct use, for these, and other, reasons:

• High temperatures are required to mature hydrocarbons, so subsurface temperatures of oil and gas fields are often (but not always) warmer than those of surrounding regions. Also, hydrocarbon-bearing intervals are good insulators that trap heat below them.

• The petroleum industry collects large amounts of high-quality data, much of which is publicly available. Such large, detailed data sets include geophysical logs, fluid chemistry, pressure, stress, core, and seismic reflection data. Such data sets enable rapid, economical exploration and are not available for conventional geothermal exploration.

• Sedimentary basins that host petroleum have porous, permeable strata. Such strata host petroleum deposits in traps, but porous strata are brine filled elsewhere. Consequently, the same rocks that host oil and/or gas commonly host large amounts of brine that can be exploited for geothermal electricity generation and/or direct use. In addition to the oil and gas bearing strata, additional water filled strata are commonly present so that multiple strata may be targets for HSA geothermal.

• HSA geothermal wells rely on porous, permeable strata that may not need stimulation to produce large volumes of brine, which represents a substantial cost savings over stimulated wells.

• HSAs are cooler than hydrothermal geothermal fields because high temperatures over geologic time promote cementation which destroys porosity. However, the large volumes of water available, coupled with new proprietary methods of high-rate extraction, results in long well lives and hence favorable economics.

This talk will describe a workflow for HSA exploration and reservoir simulation that resulted in the first deep geothermal well permits ever granted by the State of Colorado. The project is in the “hot spot” of the prolific Wattenberg oil field in the Denver-Julesburg (DJ) Basin and targets the Permian-age Lyons Sandstone. Brine will be extracted from beneath existing oil and gas production.

Reservoir simulations using the COMSOL™ and FracMan™ software packages were performed to determine prospective drilling targets. COMSOL was used to build simple, rapid, uniform porosity-permeability models. FracMan simulations were based on a detailed, 3D static model developed from representative density-porosity logs from the area. A single producer-injector well pair with a production/injection rate of 100 kg/s was simulated.

Both simulation efforts showed that the produced water temperature is stable for more than 20 years. The similarity between the two models likely results from the high porosity and permeability of the formation and the thickness of the Lyons (~40m) relative to the modeled well spacings (600m and 800m).