Nicolas Rangel Jurado Publications

Nicolas Rangel Jurado

PhD Student for Geothermal Energy and Geofluids


Mailing Address
Nicolas Rangel Jurado
Geothermal Energy & Geofluids
Institute of Geophysics
NO F 51.1
Sonneggstrasse 5
CH-8092 Zurich Switzerland

Phone +41 44 632 2558
Email nrangel(at)

Dominique Ballarin Dolfin
Phone +41 44 632 3465
Email ballarin(at)


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Underlined names are links to current or past GEG members


Rangel Jurado, N., A. J. Hawkins, and P. M. Fulton, Influence of extreme fracture flow channels on the thermal performance of open-loop geothermal systems at commercial scale., Geothermal Energy, 2023. [Download] [View Abstract]Adequate stewardship of geothermal resources requires accurate forecasting of long-term thermal performance. In enhanced geothermal systems and other fracture-dominated reservoirs, predictive models commonly assume constant-aperture fractures, although spatial variations in aperture can greatly affect reservoir permeability, fluid flow distribution, and heat transport. Whereas previous authors have investigated the effects of theoretical random aperture distributions on thermal performance, here we further explore the influence of permeability heterogeneity considering field-constrained aperture distributions from a meso-scale field site in northern New York, USA. Using numerical models of coupled fluid flow and heat transport, we conduct thermal–hydraulic simulations for a hypothetical reservoir consisting of a relatively impervious porous matrix and a single, horizontal fracture. Our results indicate that in highly channelized fields, most well design configurations and operating conditions result in extreme rates of thermal drawdown (e.g., 50% drop in production well temperatures in under 2 years). However, some other scenarios that account for the risks of short-circuiting can potentially enhance heat extraction when mass flow rate is not excessively high, and the direction of geothermal extraction is not aligned with the most permeable features in the reservoir. Through a parametric approach, we illustrate that well separation distance and relative positioning play a major role in the long-term performance of highly channelized fields, and both can be used to help mitigate premature thermal breakthrough.

Beckers, K. F. , N. Rangel Jurado, H. Chandrasekar, A. J. Hawkins, P. M. Fulton, and J. W. Tester, Techno-Economic Performance of Closed-Loop Geothermal Systems for Heat Production and Electricity Generation, Geothermics, 2022. [Download] [View Abstract]Closed-loop geothermal systems, recently referred to as advanced geothermal systems (AGS), have received renewed interest for geothermal heat and power production. These systems consist of a co-axial, U-loop, or other configuration in which the heat transfer or working fluid does not permeate the reservoir but remains within a closed-loop subsurface heat exchanger. Advocates indicate its potential for developing geothermal energy anywhere, independent of site-specific geologic uncertainties, and with limited risk of induced seismicity. Here, we present a technical and economic analysis of closed-loop geothermal systems using a Slender-Body Theory (SBT) model, COMSOL Multiphysics simulator, and the GEOPHIRES analysis tool. We consider a number of different scenarios and evaluate the influence of variations in reservoir temperature (100 to 500℃), well termination depth (2 to 4 km), mass flow rate (10 to 40 kg/s), injection temperature (10 to 40℃), fluid type (liquid water vs. supercritical carbon dioxide), design configuration (co-axial vs. U-loop), and degree of reservoir convection (natural, forced or conduction-only). The resulting average heat production rates range from about 2 to 15 GWh per year for cases considering a co-axial design and from 9 to 67 GWh per year for cases with a U-loop design. Assuming generous economic and operating conditions, estimates of levelized cost of heat range from ∼$20 – $110 per MWh (∼$6 – 32/MMBtu) and ∼$10 – $70 per MWh (∼$3 – $20/MMBtu) for greenfield co-axial and U-loop cases, respectively. In the scenarios in which electricity generation is considered, annual electricity production ranged between 0.12 and 7.5 GWh per year at a levelized cost of electricity from roughly $83 to $2,200 per MWh. In all scenarios, the results exhibit a large rapid drop in production temperature after initiation of operations that levels off to a steady value significantly below the initial reservoir temperature. Operating at lower flow rates increases the production temperature but also lowers the total heat production. The consistently low production temperatures hinder efficient electricity generation in most cases considered. Natural or forced convection can increase thermal output but requires sufficiently high reservoir permeability or formation fluid flow. As expected, overall system costs are heavily dependent on drilling costs; hence, repurposing existing wells could significantly lower capital and levelized costs. In comparison with other types of geothermal systems, our results for closed-loop geothermal systems predict long-term production temperatures considerably below the initial reservoir temperature, and relatively high levelized costs for greenfield closed-loop geothermal systems, particularly for electricity production, unless significant reductions in drilling costs are obtained.

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Rangel Jurado, N., M. Cervelli, and F. Games, Storage capacity assessment for CO2/H2S in a depleted gas condensate reservoir, Caprock Integrity & Gas Storage Symposium (CIGSS), 2024. [View Abstract]Acid gas (CO2/H2S) storage has emerged as an attractive solution for managing the undesirable byproducts generated during natural gas sweetening in hydrocarbon fields. The design of an acid gas injection (AGI) scheme requires large amounts of subsurface information, among which the static and dynamic storage capacity of the targeted reservoir are paramount. In this study, we present two different methodologies for calculating the static storage capacity of a depleted gas-condensate Cretaceous (Albian) reservoir in the Middle East region, which has produced more than 100 billion standard cubic feet (Bscf) of gas as of September 2021. Through material balance calculations based solely on historical production data and a volumetric expansion factor, we estimate the theoretical storage capacity of the formation at 13.73 metric tons (MMtons) or 0.97 billion cubic feet (Bcf) under reservoir conditions. In contrast, using established correlations found in literature (e.g., McCabe, 1988; Bachu et al., 2007; Bradshaw et al., 2007), which rely on the expected geometry and petrophysical properties of the reservoir, results in a more conservative estimate for gas storage capacity, ranging from 0.5 to 10.1 MMtons (or 0.036 to 0.710 Bcf). This range encompasses lower and upper bounds based on typical storage efficiency factors of 0.5% to 10%, respectively. Comparison between the capacity estimates derived from historical production data and the literature-based correlations suggests that higher storage efficiency factors can be considered for the Albian reservoir. Furthermore, it is important to note that the reservoir is still in production, meaning that additional volumes available for AGS are continuously increasing. The static storage capacity assessment contained here reveals a significant opportunity for acid gas storage in the Albian reservoir, which warrants further investigation to determine its economic viability. Ongoing dynamic modeling is underway to further refine these storage capacity values, incorporating the latest production data, and to inform the risk for fracture propagation in the reservoir and caprock, fault reactivation and/or rock-fluid chemical interactions.

Rangel Jurado, N., X-Z. Kong, A. Kottsova, F. Games, M. Brehme, and M.O. Saar, Investigating the chemical reactivity of the Gipskeuper and Muschelkalk formations to wet CO2 injection: A case study towards the first CCS pilot, Swiss Geoscience Meeting, 2023. [View Abstract]Carbon capture and storage (CCS) is expected to play a major role in societal attempts to reduce CO2 emissions and mitigate climate change. In parallel, CO2-based geothermal systems have been proposed as an innovative technology to couple CCS with geothermal energy extraction, therefore, increasing renewable energy production and unlocking industry-scale carbon capture, utilization, and storage (CCUS). The safe implementation and sustainability of both these technologies require a comprehensive understanding of how injected CO2 will interact with formation fluids and rocks in situ, especially under elevated pressure and temperature conditions. Whereas the role that CO2-bearing aqueous solutions play in geological reservoirs has been extensively studied, the chemical behavior of non-aqueous CO2-rich mixtures containing water has been vastly overlooked by academics and practitioners alike. In this study, we address this knowledge gap by conducting core-scale laboratory experiments that investigate the chemical reactivity of CO2-H2O mixtures, on both ends of the mutual solubility spectrum, towards reservoir and caprock lithologies. We conducted batch reactions on rock specimens from the Muschelkalk and Gipskeuper formations in Switzerland, subjecting them to interactions with wet CO2 under reservoir conditions (35 MPa, 150 °C) for approximately 500 hours. A wide range of high-resolution techniques, including scanning electron microscopy (SEM), X-ray diffraction (XRD), X-ray computed tomography (XRCT), and stable isotope analysis, were employed to characterize the evolution of petrophysical properties, morphology, and chemical composition of the samples. Furthermore, upon experiment termination, we analyzed fluid effluents using inductively coupled plasma atomic emission spectroscopy (ICP-AES) to gain insights into ion transport processes associated with dissolution reactions caused by both the aqueous and non-aqueous phases. Our results reveal that fluid-mineral interactions involving CO extsubscript{2}-rich supercritical fluids containing water are significantly less severe than those caused by aqueous solutions containing CO extsubscript{2}. Nonetheless, the existence of dissolved ions in the wet CO2 samples is evidence of ion transport processes caused by the gaseous phase that warrants further investigation. The experimental characterization of CO2-H2O mixtures under a wide range of reservoir and operating conditions represents a critical step in ensuring the reliability, long-term security, and technical feasibility of deploying CCS and CO2-based geothermal energy worldwide.

Rangel Jurado, N., S. Kucuk, M. Brehme, R. Lathion, F. Games, and M.O. Saar, Comparative analysis on the techno-economic performance of different geothermal system types for heat generation, European Geothermal Congress, 2022. [View Abstract]Geothermal energy can play a major role in renewable energy transition efforts worldwide by replacing fossil fuels since it provides baseload, firm, and carbon-free energy. Nonetheless, in contrast to its renewable alternatives, which are harnessed on the Earth’s surface, geothermal energy resources exist underground, inherently posing challenges, risks, uncertainties, and opportunities regarding energy exploration and utilization. As a result, multiple concepts to exploit geothermal energy have been proposed over the last century with varying degrees of complexity, technological maturity, and commercial success. This paper presents a first-order comparison of the technoeconomic performance of different types of deep geothermal systems for direct heat production. The system types are Conventional Hydrothermal Systems (CHS), CO2 Plume Geothermal (CPG) systems, and Advanced [or Closed-Loop] Geothermal Systems (AGS and CO2-AGS). In this study, we consider a medium sized, standard geothermal field of intermediate depth (i.e., average continental crust geothermal gradient and petrophysical properties), for which all naturally occurring reservoir conditions remain fixed. Our results show that water-based and open-loop configurations are more favorable in the context of heat production for the reservoir conditions investigated here. However, the value of CO2-based and closed-loop designs is overlooked in direct-use applications. Our work highlights how important the interplay between thermal performance and hydraulic performance is to predict and regulate the techno-economic viability of deep geothermal projects over multiple decades.

Beckers, K. F. , C. R. Galantino, N. Rangel Jurado, N. Kassem, A. J. Hawkins, S. M. Beyers, O. J. Gustafson, T. E. Jordan, P. M. Fulton, and J. W. Tester, Geothermal District Heating Using Centralized Heat Pumps and Biomass Peakers: Case-Study at Cornell University, GRC Transactions, 44, 2020. [View Abstract]As part of the university’s commitment to become carbon-neutral by 2035, Cornell University is researching and developing a geothermal deep direct-use system to provide baseload heating for its main campus in Ithaca, NY. The term Earth-Source Heat (ESH) was adopted to distinguish Cornell’s approach to extract thermal energy from rock formations 2.5 to 5 km deep at low temperatures. Over the last several years, the ESH team has characterized the local and regional subsurface, using well log analysis and bottom hole temperature interpretation of regional wells, and tools such as gravity and aeromagnetic surveys and active and passive seismic campaigns. We investigated optimal integration of ESH into the existing district heating network. Promising sedimentary (Trenton-Black River, Galway and Potsdam) formations have been identified with temperatures in the range 70–90°C, and a fractured basement target (3.0–3.5 km, ~90–100°C) has been considered. Reservoir simulations indicate acceptable thermal drawdown over a 30-year lifetime. Enhanced Geothermal System technology may be applied to increase formation permeability. Techno-economic modeling results show hybridizing the ESH with centralized heat pumps enhances the overall performance and results in an attractive levelized cost of heat (LCOH) on the order of $5/MMBTU. Biomass is considered to produce continuously renewable natural gas that on an annual basis covers the campus peaking heating load. Currently, a borehole is being designed to obtain cores from target formations and in-situ measurements of critical parameters (e.g., temperature, stress field). The ESH project at Cornell — a mid-sized community with 30,000 staff, students and faculty — serves as a regional demonstration site. If successful, demonstrating ESH at Cornell could accelerate the development of geothermal district heating in other communities in the northeastern U.S., where subsurface temperatures in the range 50–100°C are widely available. In the northern tier of the U.S., heating loads are high and dominated by fossil fuel combustion, and contribute significantly to statewide total greenhouse gas emissions. Geothermal district heating could be key to decarbonize heat supplies and meet the enacted greenhouse gas reduction targets in these states.

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Rangel Jurado, N., X-Z. Kong, A. Kottsova, M. Brehme, F. Games, and M.O. Saar, Experimental characterization of the chemical reactivity of wet scCO2 under elevated pressure and temperature conditions, Society of Core Analysts Annual Symposium , 2023. [View Abstract]CO2-Plume Geothermal (CPG) systems have been proposed as an affordable and scalable strategy to deploy Capture, Utilization, and Storage (CCUS) globally. These systems utilize CO2 to extract geothermal energy from the subsurface while ensuring its permanent sequestration in geologic formations. Unlike conventional hydrothermal systems that use water or brine, CPG utilizes pure supercritical CO2 (scCO2) or water-bearing scCO2 as the subsurface working fluid. While the thermal-hydraulic performance of CPG systems has been extensively studied, their chemical behavior remains largely unexplored due to a lack of field and experimental observations. In this study, we address this knowledge gap by investigating the chemical performance of CPG systems through core-scale laboratory experiments. We conducted batch reactions on rock specimens from the Muschelkalk and Gipskeuper formations in Switzerland, subjecting them to interactions with wet scCO2 under reservoir conditions (~35 MPa, 150 °C) for approximately 500 hours. High-resolution techniques, including scanning electron microscopy (SEM), X-ray diffraction (XRD), X-ray computed tomography (XRCT), and stable isotope analysis, were employed to characterize the evolution of petrophysical properties, morphology, and mineralogical composition. Furthermore, we analyzed fluid effluents using inductively coupled plasma optical emission spectroscopy (ICP-OES) to gain insights into ion transport processes associated with dissolution reactions. Our results indicate that fluid-mineral interactions involving CO2-rich supercritical fluids are less severe than those caused by aqueous solutions. Nonetheless, the existence of dissolved ions in the wet CO2 samples is clear evidence of ion dissociation caused by the gaseous phase that warrants further investigation. This experimental investigation provides critical insights into fluid-mineral interactions involving CO2-rich fluids and represents a crucial step in ensuring the long-term security and technical feasibility of deploying global CCS and CO2-based geothermal energy.

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Rangel Jurado, N., Thermal Performance Evaluations of Fractured and Closed-Loop Geothermal Reservoirs. , MSc Thesis, 88 pp., 2021. [View Abstract]Earth’s interior contains an enormous amount of heat that can be exploited for carbon- free direct-use or electricity generation. Even though numerous studies have predicted that geothermal power will become an important contributor to the world’s energy mix, the use of these resources is still growing at a notably slow speed compared to other renewable energy alternatives. This thesis uses computational models to explore the technical challenges that two kinds of geothermal resources face to reach full commercialization. In particular, the temporal evolution of heat production of several fractured and closed-loop geothermal reservoirs is investigated. Thermal-hydraulic simulations are conducted for a fractured meso-scale geothermal reservoir in northern New York, USA. The modeling parameters considered here are constrained by empirical data related to lithology, hydrogeology, and thermal behavior measurements collected on site. This work shows how the addition of realistic complexities, that are well-constrained by field data and often disregarded, can significantly improve the thermal performance predictions compared to overly simplified models. Additionally, the results presented here highlight the importance of characterizing subsurface permeability distributions in order to optimize thermal efficiency and devise appropriate reservoir management strategies that extend the lifespan of geothermal reservoirs. To evaluate how closed-loop or advanced geothermal systems (AGS) compare to alternative ways of extracting geothermal energy, several AGS designs displaying varying reservoir and operating conditions are evaluated to estimate their heat and temperature generating potential. Our findings indicate that the thermal efficiency of AGS is characterized by a considerable exergy loss. Sensitivity analyses show that varying different parameters have slight and moderate improvements on thermal performance, however, AGS designs appear to present multiple technical challenges making them less cost-competitive than both conventional hydrothermal systems and enhanced geothermal systems (EGS). The following key findings summarize the results of these two studies: 1) if well- constrained, computational models are a good tool to assess, manage and intervene geothermal reservoirs to ensure their long-term sustainability, 2) non-uniform permeability can drastically modify fluid flow and heat transport processes in geothermal reservoirs compared to theoretical models that consider homogenous reservoir properties, 3) prospecting adequate subsurface properties is of critical importance to develop geothermal reservoirs, and 4) despite their recent popularity, closed-loop systems are expected to be considerably less productive than other types of geothermal resources at a similar scale.