# Dr. Benjamin M. Adams, P.E.

not published

Contact
not published

## Publications

Underlined names are links to current or past GEG members

### REFEREED PUBLICATIONS IN JOURNALS

16.
van Brummen, A.C., B.M. Adams, R. Wu, J.D. Ogland-Hand, and M.O. Saar, Using CO2-Plume Geothermal (CPG) Energy Technologies to Support Wind and Solar Power in Renewable-Heavy Electricity Systems , Renewable and Sustainable Energy Transition, (in press). [View Abstract]CO2-Plume Geothermal (CPG) technologies are geothermal power systems that use geologically stored CO2 as the subsurface heat extraction fluid to generate renewable energy. CPG technologies can support variable wind and solar energy technologies by providing dispatchable power, while Flexible CPG (CPG- F) facilities can provide dispatchable power, energy storage, or both simultaneously. We present the first study investigating how CPG power plants and CPG-F facilities may operate as part of a renewable- heavy electricity system by integrating plant-level power plant models with systems-level optimization models. We use North Dakota, USA as a case study to demonstrate the potential of CPG to expand the geothermal resource base to locations not typically considered for geothermal power. We find that optimal system capacity for a solar-wind-CPG model can be up to 20 times greater than peak- demand. CPG-F facilities can reduce this modeled system capacity to just over 2 times peak demand by providing energy storage over both seasonal and short-term timescales. The operational flexibility of CPG-F facilities is further leveraged to bypass the ambient air temperature constraint of CPG power plants by storing energy at critical temperatures. Across all scenarios, a tax on CO2 emissions, on the order of hundreds of dollars per tonne, is required to financially justify using renewable energy over natural-gas power plants. Our findings suggest that CPG and CPG-F technologies may play a valuable role in future renewable-heavy electricity systems, and we propose a few recommendations to further study its integration potential.

15.
Malek, A.E., B.M. Adams, E. Rossi, H.O. Schiegg, and M.O. Saar, Techno-economic analysis of Advanced Geothermal Systems (AGS), Renewable Energy, 2022. [View Abstract]Advanced Geothermal Systems (AGS) generate electric power through a closed-loop circuit, after a working fluid extracts thermal energy from rocks at great depths via conductive heat transfer from the geologic formation to the working fluid through an impermeable wellbore wall. The slow conductive heat transfer rate present in AGS, compared to heat advection, makes AGS uneconomical to this date. To investigate what would be required to render AGS economical, we numerically model an example AGS using the genGEO simulator to obtain its electric power generation and its specific capital cost. Our numerical results show that using CO2 as the working fluid benefits AGS performance. Additionally, we find that there exists a working fluid mass flowrate, a lateral well length, and a wellbore diameter which minimize AGS costs. However, our results also show that AGS remain uneconomical with current, standard drilling technologies. Therefore, significant advancements in drilling technologies, that have the potential to reduce drilling costs by over 50%, are required to enable cost-competitive AGS implementations. Despite these challenges, the economic viability and societal acceptance potential of AGS are significantly raised when considering that negative externalities and their costs, so common for most other power plants, are practically non-existent with AGS.

14.
Ezzat, M., B. M. Adams, M.O. Saar, and D. Vogler, Numerical Modeling of the Effects of Pore Characteristics on the Electric Breakdown of Rock for Plasma Pulse Geo Drilling, Energies, 15/1, 2022. [View Abstract]Drilling costs can be 80% of geothermal project investment, so decreasing these deep drilling costs substantially reduces overall project costs, contributing to less expensive geothermal electricity or heat generation. Plasma Pulse Geo Drilling (PPGD) is a contactless drilling technique that uses high-voltage pulses to fracture the rock without mechanical abrasion, which may reduce drilling costs by up to 90% of conventional mechanical rotary drilling costs. However, further development of PPGD requires a better understanding of the underlying fundamental physics, specifically the dielectric breakdown of rocks with pore fluids subjected to high-voltage pulses. This paper presents a numerical model to investigate the effects of the pore characteristics (i.e., pore fluid, shape, size, and pressure) on the occurrence of the local electric breakdown (i.e., plasma formation in the pore fluid) inside the granite pores and thus on PPGD efficiency. Investigated are: (i) two pore fluids, consisting of air (gas) or liquid water; (ii) three pore shapes, i.e., ellipses, circles, and squares; (iii) pore sizes ranging from 10 to 150 μm; (iv) pore pressures ranging from 0.1 to 2.5 MPa. The study shows how the investigated pore characteristics affect the local electric breakdown and, consequently, the PPGD process.

13.
Fleming, M.R., B.M. Adams, J.D. Ogland-Hand, J.M. Bielicki, T.H. Kuehn, and M.O. Saar, Flexible CO2-Plume Geothermal (CPG-F): Using Geologically Stored CO2 to Provide Dispatchable Power and Energy Storage, Energy Conversion and Management, 253/115082, 2022. [View Abstract]CO2-Plume Geothermal (CPG) power plants can use geologically stored CO2 to generate electricity. In this study, a Flexible CO2 Plume Geothermal (CPG-F) facility is introduced, which can use geologically stored CO2 to provide dispatchable power, energy storage, or both dispatchable power and energy storage simultaneously—providing baseload power with dispatchable storage for demand response. It is found that a CPG-F facility can deliver more power than a CPG power plant, but with less daily energy production. For example, the CPG-F facility produces 7.2 MWe for 8 hours (8h-16h duty cycle), which is 190% greater than power supplied from a CPG power plant, but the daily energy decreased by 61% from 60 MWe-h to 23 MWe-h. A CPG-F facility, designed for varying durations of energy storage, has a 70% higher capital cost than a CPG power plant, but costs 4% to 27% more than most CPG-F facilities, designed for a specific duration, while producing 90% to 310% more power than a CPG power plant. A CPG-F facility, designed to switch from providing 100% dispatchable power to 100% energy storage, only costs 3% more than a CPG-F facility, designed only for energy storage.

12.
Ezekiel, J., B.M. Adams, M.O. Saar, and A. Ebigbo, Numerical analysis and optimization of the performance of CO2-Plume Geothermal (CPG) production wells and implications for electric power generation, Geothermics, 98/102270, 2022. [View Abstract]CO2-Plume Geothermal (CPG) power plants can produce heat and/or electric power. One of the most important parameters for the design of a CPG system is the CO2 mass flowrate. Firstly, the flowrate determines the power generated. Secondly, the flowrate has a significant effect on the fluid pressure drawdown in the geologic reservoir at the production well inlet. This pressure drawdown is important because it can lead to water flow in the reservoir towards and into the borehole. Thirdly, the CO2 flowrate directly affects the two-phase (CO2 and water) flow regime within the production well. An annular flow regime, dominated by the flow of the CO2 phase in the well, is favorable to increase CPG efficiency. Thus, flowrate optimizations of CPG systems need to honor all of the above processes. We investigate the effects of various operational parameters (maximum flowrate, ad- missible reservoir-pressure drawdown, borehole diameter) and reservoir parameters (permeability anisotropy and relative permeability curves) on the CO2 and water flow regime in the production well and on the power generation of a CPG system. We use a numerical modeling approach that couples the reservoir processes with the well and power plant systems. Our results show that water accumulation in the CPG vertical production well can occur. However, with proper CPG system design, it is possible to prevent such water accumulation in the pro- duction well and to maximize CPG electric power output.

11.
Ezekiel, J., D. Kumbhat, A. Ebigbo, B.M. Adams, and M.O. Saar, Sensitivity of Reservoir and Operational Parameters on the Energy Extraction Performance of Combined CO2-EGR–CPG Systems, Energies, 14/6122, 2021. [View Abstract]There is a potential for synergy effects in utilizing CO2 for both enhanced gas recovery (EGR) and geothermal energy extraction (CO2-plume geothermal, CPG) from natural gas reservoirs. In this study, we carried out reservoir simulations using TOUGH2 to evaluate the sensitivity of natural gas recovery, pressure buildup, and geothermal power generation performance of the combined CO2-EGR–CPG system to key reservoir and operational parameters. The reservoir parameters included horizontal permeability, permeability anisotropy, reservoir temperature, and pore-size- distribution index; while the operational parameters included wellbore diameter and ambient surface temperature. Using an example of a natural gas reservoir model, we also investigated the effects of different strategies of transitioning from the CO2-EGR stage to the CPG stage on the energy-recovery performance metrics and on the two-phase fluid-flow regime in the production well. The simulation results showed that overlapping the CO2-EGR and CPG stages, and having a relatively brief period of CO2 injection, but no production (which we called the CO2-plume establishment stage) achieved the best overall energy (natural gas and geothermal) recovery performance. Permeability anisotropy and reservoir temperature were the parameters that the natural gas recovery performance of the combined system was most sensitive to. The geothermal power generation performance was most sensitive to the reservoir temperature and the production wellbore diameter. The results of this study pave the way for future CPG-based geothermal power-generation optimization studies. For a CO2-EGR–CPG project, the results can be a guide in terms of the required accuracy of the reservoir parameters during exploration and data acquisition.

10.
Ezzat, M., D. Vogler, M. O. Saar, and B. M. Adams, Simulating Plasma Formation in Pores under Short Electric Pulses for Plasma Pulse Geo Drilling (PPGD), Energies, 14/16, 2021. [View Abstract]

Plasma Pulse Geo Drilling (PPGD) is a contact-less drilling technique, where an electric discharge across a rock sample causes the rock to fracture. Experimental results have shown PPGD drilling operations are successful if certain electrode spacings, pulse voltages, and pulse rise times are given. However, the underlying physics of the electric breakdown within the rock, which cause damage in the process, are still poorly understood.

This study presents a novel methodology to numerically study plasma generation for electric pulses between 200 to 500 kV in rock pores with a width between 10 and 100 $\mu$m. We further investigate whether the pressure increase, induced by the plasma generation, is sufficient to cause rock fracturing, which is indicative of the onset of drilling success.

We find that rock fracturing occurs in simulations with a 100 $\mu$m. pore size and an imposed pulse voltage of approximately 400 kV. Furthermore, pulses with voltages lower than 400 kV induce damage near the electrodes, which expands from pulse to pulse, and eventually, rock fracturing occurs. Additionally, we find that the likelihood for fracturing increases with increasing pore voltage drop, which increases with pore size, electric pulse voltage, and rock effective relative permittivity while being inversely proportional to the rock porosity and pulse rise time.

9.
Birdsell, D. T., B. M. Adams, and M. O. Saar, Minimum Transmissivity and Optimal Well Spacing and Flow Rate for High-Temperature Aquifer Thermal Energy Storage, Applied Energy, 289/116658, pp. 1-14, 2021. [View Abstract]Aquifer thermal energy storage (ATES) is a time-shifting thermal energy storage technology where waste heat is stored in an aquifer for weeks or months until it may be used at the surface. It can reduce carbon emissions and HVAC costs. Low-temperature ($<25$ \degree C) aquifer thermal energy storage (LT-ATES) is already widely-deployed in central and northern Europe, and there is renewed interest in high-temperature ($>50$ \degree C) aquifer thermal energy storage (HT-ATES). However, it is unclear if LT-ATES guidelines for well spacing, reservoir depth, and transmissivity will apply to HT-ATES. We develop a thermo-hydro-mechanical-economic (THM\$) analytical framework to balance three reservoir-engineering and economic constraints for an HT-ATES doublet connected to a district heating network. We find the optimal well spacing and flow rate are defined by the reservoir constraints'' at shallow depth and low permeability and are defined by the economic constraints'' at great depth and high permeability. We find the optimal well spacing is 1.8 times the thermal radius. We find that the levelized cost of heat is minimized at an intermediate depth. The minimum economically-viable transmissivity (MEVT) is the transmissivity below which HT-ATES is sure to be economically unattractive. We find the MEVT is relatively insensitive to depth, reservoir thickness, and faulting regime. Therefore, it can be approximated as$5\cdot 10^{-13}$m$^3$. The MEVT is useful for HT-ATES pre-assessment and can facilitate global estimates of HT-ATES potential. 8. Ogland-Hand, J., J. Bielicki, B. Adams, E. Nelson, T. Buscheck, M.O. Saar, and R. Sioshansi, The Value of CO2-Bulk Energy Storage with Wind in Transmission-Constrained Electricity Systems, Energy Conversion and Management, 2021. [View Abstract]High-voltage direct current (HVDC) transmission infrastructure can transmit electricity from regions with high-quality variable wind and solar resources to those with high electricity demand. In these situations, bulk energy storage (BES) could beneficially increase the utilization of HVDC transmission capacity. Here, we investigate that benefit for an emerging BES approach that uses geologically stored CO2 and sedimentary basin geothermal resources to time-shift variable electricity production. For a realistic case study of a 1 GW wind farm in Eastern Wyoming selling electricity to Los Angeles, California (U.S.A.), our results suggest that a generic CO2-BES design can increase the utilization of the HVDC transmission capacity, thereby increasing total revenue across combinations of electricity prices, wind conditions, and geothermal heat depletion. The CO2-BES facility could extract geothermal heat, dispatch geothermally generated electricity, and time-shift wind-generated electricity. With CO2-BES, total revenue always increases and the optimal HVDC transmission capacity increases in some combinations. To be profitable, the facility needs a modest$7.78/tCO2 to \$10.20/tCO2, because its cost exceeds the increase in revenue. This last result highlights the need for further research to understand how to design a CO2-BES facility that is tailored to the geologic setting and its intended role in the energy system.

7.
Adams, B.M., D. Vogler, T.H. Kuehn, J.M. Bielicki, N. Garapati, and M.O. Saar, Heat Depletion in Sedimentary Basins and its Effect on the Design and Electric Power Output of CO2 Plume Geothermal (CPG) Systems, Renewable Energy, 172, pp. 1393-1403, 2021. [View Abstract]CO2 Plume Geothermal (CPG) energy systems circulate geologically stored CO2 to extract geothermal heat from naturally permeable sedimentary basins. CPG systems can generate more electricity than brine systems in geologic reservoirs with moderate temperature and permeability. Here, we numerically simulate the temperature depletion of a sedimentary basin and find the corresponding CPG electricity generation variation over time. We find that for a given reservoir depth, temperature, thickness, permeability, and well configuration, an optimal well spacing provides the largest average electric generation over the reservoir lifetime. If wells are spaced closer than optimal, higher peak electricity is generated, but the reservoir heat depletes more quickly. If wells are spaced greater than optimal, reservoirs maintain heat longer but have higher resistance to flow and thus lower peak electricity is generated. Additionally, spacing the wells 10% greater than optimal affects electricity generation less than spacing wells 10% closer than optimal. Our simulations also show that for a 300 m thick reservoir, a 707 m well spacing provides consistent electricity over 50 years, whereas a 300 m well spacing yields large heat and electricity reductions over time. Finally, increasing injection or production well pipe diameters does not necessarily increase average electric generation.

6.
Garapati, N., B.M. Adams, M.R. Fleming, T.H. Kuehn, and M.O. Saar, Combining brine or CO2 geothermal preheating with low-temperature waste heat: A higher-efficiency hybrid geothermal power system, Journal of CO2 Utilization, 42, 2020. [View Abstract]Hybrid geothermal power plants operate by using geothermal fluid to preheat the working fluid of a higher temperature power cycle for electricity generation. This has been shown to yield higher electricity generation than the combination of a stand-alone geothermal power plant and the higher-temperature power cycle. Here, we test both a direct CO2 hybrid geothermal system and an indirect brine hybrid geothermal system. The direct CO2 hybrid geothermal system is a CO2 Plume Geothermal (CPG) system, which uses CO2 as the subsurface working fluid, but with auxiliary heat addition to the geologically produced CO2 at the surface. The indirect brine geothermal system uses the hot geologically produced brine to preheat the secondary working fluid (CO2) within a secondary power cycle. We find that the direct CPG-hybrid system and the indirect brine-hybrid system both can generate 20 % more electric power than the summed power of individual geothermal and auxiliary systems in some cases. Each hybrid system has an optimum turbine inlet temperature which maximizes the electric power generated, and is typically between 100 ◦C and 200 ◦C in the systems examined. The optimum turbine inlet temperature tends to occur where the geothermal heat contribution is between 50 % and 70 % of the total heat addition to the hybrid system. Lastly, the CO2 direct system has lower wellhead temperatures than indirect brine and therefore can utilize lower temperature resources.

5.
Fleming, M.R., B.M. Adams, T.H. Kuehn, J.M. Bielicki, and M.O. Saar, Increased Power Generation due to Exothermic Water Exsolution in CO2 Plume Geothermal (CPG) Power Plants, Geothermics, 88/101865, 2020. [View Abstract]A direct CO2-Plume Geothermal (CPG) system is a novel technology that uses captured and geologically stored CO2 as the subsurface working uid in sedimentary basin reservoirs to extract geothermal energy. In such a CPG system, the CO2 that enters the production well is likely saturated with H2O from the geothermal reser- voir. However, direct CPG models thus far have only considered energy production via pure (i.e. dry) CO2 in the production well and its direct conversion in power generation equipment. Therefore, we analyze here, how the wellhead uid pressure, temperature, liquid water fraction, and the resultant CPG turbine power output are impacted by the production of CO2 saturated with H2O for reservoir depths ranging from 2.5 km to 5.0 km and geothermal temperature gradients between 20 °C/km and 50 °C/km. We demonstrate that the H2O in solution is exothermically exsolved in the vertical well, increasing the uid temperature relative to dry CO2, resulting in the production of liquid H2O at the wellhead. The increased wellhead uid temperature increases the turbine power output on average by 15% to 25% and up to a maximum of 41%, when the water enthalpy of exsolution is considered and the water is (conservatively) removed before the turbine, which decreases the uid mass ow rate through the turbine and thus power output. We show that the enthalpy of exsolution and the CO2-H2O so- lution density are fundamental components in the calculation of CPG power generation and thus should not be neglected or substituted with the properties of dry CO2.

4.
Ezekiel, J., A. Ebigbo, B. M. Adams, and M. O. Saar, Combining natural gas recovery and CO2-based geothermal energy extraction for electric power generation, Applied Energy, 269/115012, 2020. [View Abstract]We investigate the potential for extracting heat from produced natural gas and utilizing supercritical carbon dioxide (CO2) as a working uid for the dual purpose of enhancing gas recovery (EGR) and extracting geo- thermal energy (CO2-Plume Geothermal – CPG) from deep natural gas reservoirs for electric power generation, while ultimately storing all of the subsurface-injected CO2. Thus, the approach constitutes a CO2 capture double- utilization and storage (CCUUS) system. The synergies achieved by the above combinations include shared infrastructure and subsurface working uid. We integrate the reservoir processes with the wellbore and surface power-generation systems such that the combined system’s power output can be optimized. Using the subsurface uid ow and heat transport simulation code TOUGH2, coupled to a wellbore heat-transfer model, we set up an anticlinal natural gas reservoir model and assess the technical feasibility of the proposed system. The simulations show that the injection of CO2 for natural gas recovery and for the establishment of a CO2 plume (necessary for CPG) can be conveniently combined. During the CPG stage, following EGR, a CO2-circulation mass owrate of 110 kg/s results in a maximum net power output of 2 MWe for this initial, conceptual, small system, which is scalable. After a decade, the net power decreases when thermal breakthrough occurs at the production wells. The results con rm that the combined system can improve the gas eld’s overall energy production, enable CO2 sequestration, and extend the useful lifetime of the gas eld. Hence, deep (partially depleted) natural gas re- servoirs appear to constitute ideal sites for the deployment of not only geologic CO2 storage but also CPG.

3.
Ogland-Hand, J.D., J.M. Bielicki, Y. Wang, B.M. Adams, T.A. Buscheck, and M.O. Saar, The value of bulk energy storage for reducing CO2 emissions and water requirements from regional electricity systems., Energy Conversion and Management, 181, pp. 674-685, 2019. [View Abstract]The implementation of bulk energy storage (BES) technologies can help to achieve higher penetration and utilization of variable renewable energy technologies (e.g., wind and solar), but it can also alter the dispatch order in regional electricity systems in other ways. These changes to the dispatch order affect the total amount of carbon dioxide (CO2) that is emitted to the atmosphere and the amount of total water that is required by the electricity generating facilities. In a case study of the Electricity Reliability Council of Texas system, we separately investigated the value that three BES technologies (CO2- Geothermal Bulk Energy Storage, Compressed Air Energy Storage, Pumped Hydro Energy Storage) could have for reducing system-wide CO2 emissions and water requirements. In addition to increasing the utilization of wind power capacity, the dispatch of BES also led to an increase in the utilization of natural gas power capacity and of coal power capacity, and a decrease in the utilization of nuclear power capacity, depending on the character of the net load, the CO2 price, the water price, and the BES technology. These changes to the dispatch order provided positive value (e.g., increase in natural gas generally reduced CO2 emissions; decrease in nuclear utilization always decreased water requirements) or negative value (e.g., increase in coal generally increased CO2 emissions; increase in natural gas sometimes increased water requirements) to the regional electricity system. We also found that these values to the system can be greater than the cost of operating the BES facility. At present, there are mechanisms to compensate BES facilities for ancillary grid services, and our results suggest that similar mechanisms could be enacted to compensate BES facilities for their contribution to the environmental sustainability of the system.

2.
Adams, B.M., T.H. Kuehn, J.M. Bielicki, J.B. Randolph, and M.O. Saar, A comparison of electric power output of CO2 Plume Geothermal (CPG) and brine geothermal systems for varying reservoir conditions, Applied Energy, 140, pp. 365-377, 2015. [View Abstract]In contrast to conventional hydrothermal systems or enhanced geothermal systems, CO2 Plume Geothermal (CPG) systems generate electricity by using CO2 that has been geothermally heated due to sequestration in a sedimentary basin. Four CPG and two brine-based geothermal systems are modeled to estimate their power production for sedimentary basin reservoir depths between 1 and 5km, geothermal temperature gradients from 20 to 50°Ckm-1, reservoir permeabilities from 1×10-15 to 1×10-12m2 and well casing inner diameters from 0.14m to 0.41m. Results show that CPG direct-type systems produce more electricity than brine-based geothermal systems at depths between 2 and 3km, and at permeabilities between 10-14 and 10-13m2, often by a factor of two. This better performance of CPG is due to the low kinematic viscosity of CO2, relative to brine at those depths, and the strong thermosiphon effect generated by CO2. When CO2 is used instead of R245fa as the secondary working fluid in an organic Rankine cycle (ORC), the power production of both the CPG and the brine-reservoir system increases substantially; for example, by 22% and 20% for subsurface brine and CO2 systems, respectively, with a 35°Ckm-1 thermal gradient, 0.27m production and 0.41m injection well diameters, and 5×10-14m2 reservoir permeability.

1.
Adams, B.M., T.H. Kuehn, J.M. Bielicki, J.B. Randolph, and M.O. Saar, On the importance of the thermosiphon effect in CPG (CO2-Plume geothermal) power systems, Energy, 69, pp. 409-418, 2014. [View Abstract]CPG (CO2 Plume Geothermal) energy systems use CO2 to extract thermal energy from naturally permeable geologic formations at depth. CO2 has advantages over brine: high mobility, low solubility of amorphous silica, and higher density sensitivity to temperature. The density of CO2 changes substantially between geothermal reservoir and surface plant, resulting in a buoyancy-driven convective current – a thermosiphon – that reduces or eliminates pumping requirements. We estimated and compared the strength of this thermosiphon for CO2 and for 20 weight percent NaCl brine for reservoir depths up to 5 km and geothermal gradients of 20, 35, and 50 °C/km. We found that through the reservoir, CO2 has a pressure drop approximately 3–12 times less than brine at the same mass flowrate, making the CO2 thermosiphon sufficient to produce power using reservoirs as shallow as 0.5 km. At 2.5 km depth with a 35 °C/km gradient – the approximate western U.S. continental mean – the CO2 thermosiphon converted approximately 10% of the energy extracted from the reservoir to fluid circulation, compared to less than 1% with brine, where additional mechanical pumping is necessary. We found CO2 is a particularly advantageous working fluid at depths between 0.5 km and 3 km.

### PROCEEDINGS REFEREED

2.
Rossi, E., B. Adams, D. Vogler, Ph. Rudolf von Rohr, B. Kammermann, and M.O. Saar, Advanced drilling technologies to improve the economics of deep geo-resource utilization, Proceedings of Applied Energy Symposium: MIT A+B, United States, 2020 , 8, pp. 1-6, 2020. [View Abstract]Access to deep energy resources (geothermal energy, hydrocarbons) from deep reservoirs will play a fundamental role over the next decades. However, drilling of deep wells to extract deep geo-resources is extremely expensive. As a fact, drilling deep wells into hard, crystalline rocks represents a major challenge for conventional rotary drilling systems, featuring high rates of drill bit wear and requiring frequent drill bit replacements, low penetration rates and poor process efficiency. Therefore, with the aim of improving the overall economics to access deep geo-resources in hard rocks, in this work, we focus on two novel drilling methods, namely: the Combined Thermo-Mechanical Drilling (CTMD) and the Plasma-Pulse Geo-Drilling (PPGD) technologies. The goal of this research and development project is the effective reduction of the costs of drilling in general and particularly regarding accessing and using deep geothermal energy, oil or gas resources. In this work, we present these two novel drilling technologies and focus on evaluating the process efficiency and the drilling performance of these methods, compared to conventional rotary drilling.

1.
Garapati, N., B.M. Adams, J.M. Bielicki, P. Schaedle, J.B. Randolph, T.H. Kuehn, and M.O. Saar, A Hybrid Geothermal Energy Conversion Technology - A Potential Solution for Production of Electricity from Shallow Geothermal Resources, Energy Procedia, 114, pp. 7107-7117, 2017. [View Abstract]Geothermal energy has been successfully employed in Switzerland for more than a century for direct use but presently there is no electricity being produced from geothermal sources. After the nuclear power plant catastrophe in Fukushima, Japan, the Swiss Federal Assembly decided to gradually phase out the Swiss nuclear energy program. Deep geothermal energy is a potential resource for clean and nearly CO2-free electricity production that can supplant nuclear power in Switzerland and worldwide. Deep geothermal resources often require enhancement of the permeability of hot-dry rock at significant depths (4-6 km), which can induce seismicity. The geothermal power projects in the Cities of Basel and St. Gallen, Switzerland, were suspended due to earthquakes that occurred during hydraulic stimulation and drilling, respectively. Here we present an alternative unconventional geothermal energy utilization approach that uses shallower, lower-temperature, naturally permeable regions, that drastically reduce drilling costs and induced seismicity. This approach uses geothermal heat to supplement a secondary energy source. Thus this hybrid approach may enable utilization of geothermal energy in many regions in Switzerland and elsewhere, that otherwise could not be used for geothermal electricity generation. In this work, we determine the net power output, energy conversion efficiencies, and economics of these hybrid power plants, where the geothermal power plant is actually a CO2-based plant. Parameters varied include geothermal reservoir depth (2.5-4.5 km) and turbine inlet temperature (100-220 °C) after auxiliary heating. We find that hybrid power plants outperform two individual, i.e., stand-alone geothermal and waste-heat power plants, where moderate geothermal energy is available. Furthermore, such hybrid power plants are more economical than separate power plants.

### PROCEEDINGS NON-REFEREED

14.
Ogland-Hand, J, J Bielicki, B Adams, T Buscheck, and M Saar, Using Sedimentary Basin Geothermal Resources to Provide Long-Duration Energy Storage, Proceedings World Geothermal Congress, 2020.

13.
Adams, B.M., M.O. Saar, J.M. Bielicki, J.D. Ogland-Hand, and M.R. Fleming, Using Geologically Sequestered CO2 to Generate and Store Geothermal Electricity: CO2 Plume Geothermal (CPG), Applied Energy Symposium: MIT A+B August 12-14, 2020, Cambridge, USA, 2020. [View Abstract]CO2 Plume Geothermal (CPG) is a carbon neutral renewable electricity generation technology where geologic CO2 is circulated to the surface to directly generate power and then is reinjected into the deep subsurface. In contrast to traditional water geothermal power generation with an Organic Rankine Cycle (ORC), CPG has fewer system inefficiencies and benefits from the lower viscosity of subsurface CO2 which allows power generation at shallower depths, lower temperatures, and lower reservoir transmissivities.

12.
Ezekiel, J., A. Ebigbo, B. Adams, and M.O. Saar, On the use of supercritical carbon dioxide to exploit the geothermal potential of deep natural gas reservoirs for power generation, European Geothermal Congress (EGC), Hague, Netherlands, 11-14 June 2019, 2019.

11.
Fleming, M.R., B.M. Adams, T.H. Kuehn, J.M. Bielicki, and M.O. Saar, Benefits of using active reservoir management during CO2-plume development for CO2-plume geothermal systems., 44th Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, CA, February 11-13, 2019., 2019.

10.
Adams, B.M., M.R. Fleming, J.M. Bielicki, J. Hansper, S. Glos, M. Langer, M. Wechsung, and M.O. Saar, Grid scale energy storage using CO2 in sedimentary basins: the cost of power flexibility., European Geothermal Congress, The Hague, Netherlands, 11-14 June 2019, 2019.

9.
Ogland-Hand, J.D., J.M. Bielicki, E.S. Nelson, B.M. Adams, T.A. Buscheck, M.O. Saar, and R. Sioshansi, Effects of Bulk Energy Storage in Sedimentary Basin Geothermal Resources on Transmission Constrained Electricity Systems , 43rd Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California, February 12-14, 2018, 2018. [View Abstract]Sedimentary basin geothermal resources and carbon dioxide (CO2) can be used for bulk energy storage (CO2-BES), which could reduce the capacity, and thus cost, of high voltage direct current (HVDC) transmission infrastructure needed to connect high quality wind resources to distant load centers. In this study, we simulated CO2-BES operation in the Minnelusa Aquifer in eastern Wyoming and used those results in an optimization model to determine the impact that CO2-BES could have on the revenue of a wind farm that sells electricity to the California Independent System Operator (CAISO) market under varying HVDC transmission capacity scenarios. We found that the CO2-BES facility can dispatch more electricity than was previously stored because of the geothermal energy input. While CO2-BES performance degrades because of geothermal resource depletion, our results suggest that a CO2-BES facility could increase revenue from electricity sales throughout its lifetime by (1) increasing the utilization of HVDC transmission capacity, and (2) enabling arbitrage of the electricity prices in the CAISO market. In some cases, adding CO2-BES can provide more revenue with less HVDC transmission capacity.

8.
Fleming, M.R., B.M. Adams, J.B. Randolph, J.D. Ogland-Hand, T.H. Kuehn, T.A. Buscheck, J.M. Bielicki, and M.O. Saar, High efficiency and large-scale subsurface energy storage with CO2., 43rd Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, CA, February 12-14, 2018., 2018. [View Abstract]Storing large amounts of intermittently produced solar or wind power for later, when there is a lack of sunlight or wind, is one of society’s biggest challenges when attempting to decarbonize energy systems. Traditional energy storage technologies tend to suffer from relatively low efficiencies, severe environmental concerns, and limited scale both in capacity and time. Subsurface energy storage can solve the drawbacks of many other energy storage approaches, as it can be large scale in capacity and time, environmentally benign, and highly efficient. When CO2 is used as the (pressure) energy storage medium in reservoirs underneath caprocks at depths of at least ~1 km (to ensure the CO2 is in its supercritical state), the energy generated after the energy storage operation can be greater than the energy stored. This is possible if reservoir temperatures and CO2 storage durations combine to result in more geothermal energy input into the CO2 at depth than what the CO2 pumps at the surface (and other machinery) consume. Such subsurface energy storage is typically also large scale in capacity (due to typical reservoir sizes, potentially enabling storing excess power from a substantial portion of the power grid) and in time (even enabling seasonal energy storage). Here, we present subsurface electricity energy storage with supercritical carbon dioxide (CO2) called CO2-Plume Geothermal Energy Storage (CPGES) and discuss the system’s performance, as well as its advantages and disadvantages, compared to other energy storage options. Our investigated system consists of a deep and a shallow reservoir, where excess electricity from the grid is stored by producing CO2 from the shallow reservoir and injecting it into the deep reservoir, storing the energy in the form of pressure and heat. When energy is needed, the geothermally heated CO2 is produced from the deep reservoir and injected into the shallow reservoir, passing through a power generation system along the way. Thus, the shallow reservoir takes the place of a storage tank at the surface. The shallow reservoir well system is a huff-and-puff system to store the CO2 with as few heat and pressure losses as possible, whereas the deep reservoir has an injection and a production well, so the CO2 can extract heat as it passes through. We find that both the diurnal (daily) and seasonal (6 months) CPGES systems generate more electricity to the power grid than they store from it. The diurnal system has a ratio of generated electricity to stored electricity (called the Energy Storage Ratio) between 2.93 and 1.95. Similarly, the seasonal system has an energy storage ratio between 1.55 and 1.05, depending on operational strategy. The energy storage ratio decreases with duration due to the pump power needed to overcome the increasing reservoir pressures as CO2 is stored.

7.
Hansper, J., S. Glos, M. Langer, M. Wechsung, B.M. Adams, and M.O. Saar, Assessment of performance and costs of CO2 plume geothermal (CPG) systems., European Geothermal Congress, Hague, Netherlands, 11-14 June 2019, 2018.

6.
Ezekiel, J., A. Ebigbo, B.M. Adams, and M.O. Saar, On the use of supercritical carbon dioxide to exploit the geothermal potential of deep natural gas reservoirs for power generation., European Geothermal Congress, Hague, Netherlands, 11-14 June 2019, 2018.

5.
Bielicki, J.M., B.M. Adams, H. Choi, B. Jamiyansuren, M.O. Saar, S.J. Taff, T.A. Buscheck, and J.D. Ogland-Hand, Sedimentary basin geothermal resource for cost-effective generation of renewable electricity from sequestered carbon dioxide., 41st Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, CA, February 22-24, 2016., 2016. [View Abstract]We investigated the efficacy of generating electricity using renewable geothermal heat that is extracted by CO2 that is sequestered in sedimentary basins, a process described as CO2 -Plume Geothermal (CPG) energy production. We developed an integrated systems model that combines power plant performance modeling, reservoir modeling, and the economic costs of a CPG power plant and a CO2 storage operation in order to estimate the levelized cost of electricity (LCOE). The integrated systems model is based on inverted fivespot injection patterns that are common in CO2-enhanced oil recovery operations. Our integrated systems model allows for these patterns to be coupled together, so that the CO2 that is extracted by a production well can be composed of portions of the CO2 that was injected in the four neighboring injection wells. We determined the diameter of the individual wells and the size coupled inverted fivespot well patterns that most effectively used the physical and economic economies of scale for the coupled reservoir and power plant. We found that substantial amounts of power, on the order of hundreds of megawatts, can be produced as the size of the injection pattern increases, and that the estimated LCOE decreases as these patterns expand. Given the appropriate combination of depth, geothermal gradient, and permeability, CPG power plants can have LCOEs that are competitive with other unsubsidized sources of electricity.

4.
Buscheck, T.A., J.M. Bielicki, J.B. Randolph, M. Chen, Y. Hao, T.A. Edmunds, B. Adams, and Y. Sun, Multi-fluid geothermal energy systems in stratigraphic reservoirs: Using brine, N2, and CO2 for dispatchable renewable power generation and bulk energy storage., 39th Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, CA, February 24-26, 2014., 2014. [View Abstract]Stratigraphic reservoirs are attractive candidates for geothermal power production due to their high permeability and large areal extent, compared to typical hydrothermal geothermal reservoirs. Because they are often associated with a conductive thermal regime that require greater depths to reach economic temperatures, the commercial viability of stratigraphic reservoir systems will depend on leveraging greater fluid production rates per well and on limiting the parasitic costs associated with fluid recirculation. We present an approach to address these challenges. To increase fluid-recirculation efficiency and fluid production rates, we inject supplemental working fluids (CO2 and/or N2) with advantageous properties to augment reservoir pressure. Because N2 can be readily separated from air, pressure augmentation can occur during periods of low grid power demand, which will reduce parasitic costs and enable bulk energy storage. A well pattern consisting of four concentric rings of horizontal producers and injectors is used to store pressure and supplemental fluids, segregate the supplemental fluid and brine production zones, and generate large artesian flow rates to better leverage the productivity of horizontal wells. We present simulations of this approach for an idealized reservoir model, consisting of a permeable sedimentary formation, vertically confined by two impermeable seal units. Because the parasitic costs associated with compressing and injecting supplemental fluids and brine increase with reservoir overpressure, net power production is found to be more efficient at moderate supplemental-fluid injection rates.

3.
Adams, B.M., T.H. Kuehn, J.B. Randolph, and M.O. Saar, The reduced pumping power requirements from increasing the injection well fluid density, Transactions - Geothermal Resources Council, 37, pp. 667-672, 2013. [View Abstract]The reduction of parasitic loads is a key component to the operational efficiency of geothermal power plants, which include reductions in pump power requirements. Variations in fluid den - sity, as seen in CO 2 -based geothermal plants have resulted in the elimination of pumping requirements, known as a thermosiphon; this effect, while less pronounced, is also found in traditional brine geothermal systems. Therefore, we find the reductions in pumping power requirements for traditional 20 wt% NaCl brine and CO 2 geothermal power systems by increasing the injection fluid density. For a reduction in temperature of 1°C at a 15°C surface condition, a traditional brine system was found to require up to 2kWe less pumping power. A CO 2 system in the same condition was found to require up to 42 kWe less power. When the density of the injected brine was increased by increasing the salinity of the injected fluid to 21 wt% NaCl, the injection pumping requirement decreased as much as 45 kWe. Both distillation and reverse osmosis processes were simulated to increase the salinity while producing 7 kg s -1 fresh water. The pumping power reduction does not account for the increased energy cost of salination; however, this may still be economical in locations of water scarcity

2.
Randolph, J.B., B.M. Adams, T.H. Kuehn, and M.O. Saar, Wellbore heat transfer in CO2-based geothermal systems, Geothermal Resources Council (GRC) Transactions, 36, pp. 549-554, 2012. [View Abstract]Abstract Geothermal systems utilizing carbon dioxide as the subsurface heat exchange fluid in naturally porous, permeable geologic formations have been sho wn to provide improved geothermal heat energy extraction, even at low resource temperature s, compared to conventional hydrothermal and enhanced geothermal systems (EGS). Such systems , termed CO 2 Plume Geothermal (CPG), have the potential to permit expansion of geotherma l energy use while supporting rapid implementation. While most previous analyses have f ocused on heat transfer in the reservoir and surface components of CO 2 -based geothermal operations, here we examine wellb ore heat transfer. In particular, we explore the hypothesis that wellbore flow can be assumed to be adiabatic for the majority of a CPG facility's life span.

1.
Adams, B., and T.H. Kuehn, The complementary nature of CO2-plume geothermal (CPG) energy production and electrical power demand., ASME 2012 International Mechanical Congress & Exposition, Houston, TX, US, November 9-15, 2012., 2012. [View Abstract]CO2 Plume Geothermal (CPG) energy generation is a renewable technology that uses CO2 as the geologic working fluid within naturally permeable, sedimentary thermal reservoirs. In this paper, we compare the ability for CPG geothermal technology to meet electrical demand requirements, compared with other renewable technologies, for a 10MW, northern climate town near Minot, North Dakota. Wind and solar are both supply-driven technologies, capturing energy when it is available; However CPG is demand-driven—the rate at which energy is removed from within the earth is chosen to meet electrical demand. Using meteorological data, we compare estimated system performance with actual 2010 electrical load to gage each system’s ability to meet demand. CPG is found to most closely match system demand during the three-season (fall, winter, spring) year, where solar production is inversely related to demand. At the same time, wind does not track demand during any portion of the year, consistently having a large variability. None of these renewable technologies was found to track demand all year. Ultimately we show that CPG may be used to reliably track hourly demand during 95% of the year—an unattainable result for wind and solar.