Thermodynamic analysis of power generation and waste heat recovery in CO2-plume geothermal systems in aquifers of varying heterogeneity

ABSTRACTAs a developing country, Turkey’s sustainable development objectives converge on robust and sustainable economic development. The increase in its energy and electricity demand is attributed to the growth of population, urbanization, and industrialization parallel to economic and social growth. Instead of fulfilling the obligation to protect the environment arising from international agreements and achieving desired sustainable development, the dependency on imported fossil fuel in electrical energy production and energy-intensive economic growth results in intensified CO2 emission as well as ironically negative economic output. Therefore, Turkey is forced to exploit its indigenous sources such as coal (which unfortunately increases atmospheric Green House Gas “GHG” emissions) and renewable resources. However, high GHG emission – mainly CO2 – of Turkey’s coal power plants impairs deployment of indigenous sources for power generation. Indeed, there is a necessity of technical approaches for higher heat extraction efficiencies and mitigation of high concentration of energy-related CO2 emission. Admittedly, “Carbon Capture, Utilization, and Storage (CCUS)” employing conventional hydrothermal resources offers highly efficient heat extraction, geological CO2 sequestration, and utilization of CO2 for power generation rather than considering CO2 as an effluent. Although there are research gaps and lack of field scale experiment, the economic and environmental viability of implementing CCUS in Turkey can be improved by pilot or field scale projects whereby the presence of these projects commences technological and experimental advances in capturing CO2 either from geothermal power plants or indigenous coal power plants, transporting it to the proven geothermal geologic site, and generating power. Apart from this, the “CO2 – Plume Geothermal Systems (CPG)” compared to unconventional and conventional geothermal systems would commit vigorous potential for continual improvement in economic feasibility of CCUS without a guaranteed return on power generation investments in Turkey. Hence, legislations concerning incentives in CCUS would foster further improvements in the deployment of geothermal resources to pursue sustainable development in Turkey.

To investigate ways of advancing CO2 plume geothermal (CPG), we have examined key geological, reservoir, geomechanical, and operational considerations. We use a three-dimensional numerical reservoir simulator to model the impact of each parameter studied on the injectivity and productivity indices for CO2 plume geothermal systems. In addition, we use a coupled thermohydromechanical model to understand if the process might induce fracturing or seismicity. The result showed that the top of the reservoir, the formation porosity, and the formation thickness are the top three factors impacting the productivity index and injectivity index of CPG systems. We also note that produced CO2 is less than the injected CO2 due to trapping mechanisms and bypassed CO2. Lower permeability and anisotropy were more favorable for the given reservoir and well configuration. From a geological perspective, sensitivity analyses reveal the influence of dip on CO2 extraction and the need for optimal well placement. Elastic-brittle analysis suggests that reservoir fracturing and microseismicity may not occur during injection. However, microseismicity may occur during production, thus providing some guidance on how operators may want to optimize monitoring strategies. INTRODUCTION The apparent high cost and lack of economic attractiveness of carbon capture utilization and storage (CCUS) projects have been perceived as a challenge for the large-scale deployment of numerous CO2 capture projects (Shen et al. 2022 and Gibbins et al. 2008). Budinis et al. (2018) suggest that the ability to utilize and sequester captured CO2 could enhance the economic viability of CCUS. Researchers such as Brown (2000), Pruess (2006), Luo and Jiang (2014), and Okoroafor et al. (2022) have investigated the thermal performance of an enhanced geothermal system (EGS) using supercritical CO2, which has shown promise for heat mining due to the favorable thermophysical properties of CO2 in its supercritical state. However, unlike the complex fracture system of the EGS model, the CO2 plume geothermal system takes advantage of CO2's greater compressibility, expansibility, and lower viscosity when injected into sedimentary rocks. Fluid loss in the system indirectly serves the purpose of CO2 geological storage, as Randolph et al. (2010, 2011) observed.

The influence of complicated fluid-rock interactions on the geothermal exploitation in the CO2 plume geothermal system

The utilization of geological formations, distinguished by natural porosity and permeability and protected by low-permeability caprock, has emerged as an effective strategy for carbon dioxide (CO2) storage. This method significantly contributes to mitigating anthropogenic greenhouse gas emissions and addressing the challenges of climate change. Recent research has unveiled the potential of CO2 to enhance geothermal heat energy extraction in geothermal reservoirs by acting as a subsurface heat exchange fluid. This review paper explores the viability of CO2 in augmenting geothermal heat energy extraction, comparing it to conventional water-based geothermal systems. Special emphasis is placed on CO2 plume geothermal (CPG) systems, characterized by rapid deployment and long-term utilization of geothermal energy resources. With the overarching objective of establishing net-zero energy communities, the analysis of such systems offers a comprehensive understanding of their features, providing a fresh perspective on extracted energy within the context of energy supply in integrated, sustainable energy in built systems. Notably, these systems demonstrate efficacy in meeting the power requirements of an energy community, spanning both distinct heating and electricity needs. However, the key challenge lies in selecting suitable locations. This scientific review aims to comprehend the characteristics of CPG under specific temperature and pressure conditions while optimizing subsurface permeability. This insight is pivotal for identifying future locations for CPG operations with the intent of powering small energy communities.

Realizing India’s commitment to achieving net-zero emissions by 2070 requires the development and commercialization of Carbon Capture, Utilization and Storage (CCUS) technologies. CCUS is important to decarbonizing hard-to-abate sectors like the oil and gas, cement, steel and chemicals. While CCUS in India is still in the early stages, there have been promising pilot and demonstration projects. Notably, the Indian Oil Corporation operates Koyali refinery through which the facility could capture more than 5000 tons of CO2 daily as part of Enhanced Oil Recovery (EOR) efforts, which establishes this installation as India’s leading CCUS venture. The Jamshedpur plant of Tata Steel enables daily capture of 5 tons of CO2, while NTPC operates a CO2-to-methanol project at their site in Madhya Pradesh. Despite these advancements, the main obstacles to CCUS commercialization are high costs, lack of policy support and technological limitations. The current CCUS initiatives in India are explored and strategic policy innovations to accelerate CCUS deployment are presented in this paper. A phased implementation framework using financial incentives, regulatory changes as well as public private partnerships that help build a robust CCUS ecosystem is the proposed study. Furthermore, international collaboration and knowledge transfer are identified as being important for advancement of technological readiness levels in India and for successful commercialization of CCUS. The study underscored the need for a unified policy framework and multi stakeholder engagement to help ensure the longevity of CCUS in India. To tap on such a huge potential of CCUS in India, it is important to address barriers and align itself with global best practices, as CCUS will greatly help in meeting the country’s climate goals as well as industrial sustainability.

A comparison of electric power output of CO2 Plume Geothermal (CPG) and brine geothermal systems for varying reservoir conditions

Assessment of carbon dioxide storage in the Gulf of Gabes, Tunisia: Analytical and numerical modeling

This paper presents the rational for the selection of fluids for use in a model based study of sub and supercritical Waste Heat Recovery (WHR) Organic Rankine Cycle (ORC). The study focuses on multiple vehicle heat sources and the potential of WHR ORC’s for its conversion into useful work. The work presented on fluid selection is generally applicable to any waste heat recovery system, either stationary or mobile and, with careful consideration, is also applicable to single heat sources. The fluid selection process presented reduces the number of potential fluids from over one hundred to a group of under twenty fluids for further refinement in a model based WHR ORC performance study. The selection process uses engineering judgement, legislation and, where applicable, health and safety as fluid selection or de-selection criteria. This paper also investigates and discusses the properties of specific ORC fluids with regard to their impact on the theoretical potential for delivering efficient WHR ORC work output. The paper concludes by looking at potential temperature and pressure WHR ORC limits with regard to fluid properties thereby assisting with the generation of WHR ORC simulation boundary conditions.

CO2-Plume Geothermal (CPG) is a technology that employs the benefit of CO2 as a geothermal working fluid to turn CCS into CCUS (Carbon Capture, Utilization and Storage), both by producing more power compared to conventional geothermal systems (Randolph and Saar, 2011), as well as improving the performance of the base CO2 storage project. Following a decade of research, a CPG consortium has started in March 2023 to pave the way for de-risking this emerging technology to a Technology Readiness Level (TRL) of 7. This industry-academic initiative unlocks a larger joint portfolio of opportunities, financing options and domain knowledge, thereby enabling a systematic and standardized approach to evaluating candidate CPG field demonstration sites and concepts. A workflow is presented to define several potential field demonstration concepts, leveraging site-specific risk registers, opportunity framing sessions, competitive scoping and multi-scenario modelling. Using a trade-off table, the highest value field demonstration project can be selected for execution in the subsequent phase of the CPG consortium.    

Objective/Scope Many countries are now implementing more detailed regulations on carbon, capture, utilisation and storage (CCUS) projects. Historically CCUS projects have been considered uneconomic, but with introduction of incentives such as CO2 tax and compensation per ton of CO2 injected, many plans for CCUS projects are moving ahead and expected to go in production in the coming years to help achieve 2030 climate targets. This paper examines the economics of CCUS projects, either standalone or in conjunction with large offshore gas projects in Denmark, Indonesia and Australia. Firstly, an analysis of the legislation in these countries reveals to what degree the frameworks are defined to support CCUS projects. Secondly economic robustness analyses of the projects are performed to determine under which circumstances that CCUS strengthens or weakens the business cases for the operators. Method/Procedure/Process Appropriate gas production profiles and costs including DRILLEX, CAPEX and OPEX are determined for large offshore gas projects in Denmark, Indonesia and Australia, and with appropriate CCUS facilities. These countries offer very different settings since offshore projects in Denmark are in harsh environment but shallow water, while Indonesia and Australia offer deeper water and generally more benign weather conditions. The legal analysis is based on existing petroleum fiscal regimes in all three countries and new regulations relevant for CCUS that include depreciating and recovering investments and receiving economic incentives to inject CO2 that may or may not be used for enhanced oil and gas recovery. Economic analyses for typical oil and gas project decisions are performed with alternative development scenarios and robustness evaluations that identify after-tax key metrics and break-even values. These are performed for the offshore gas projects under realistic economic conditions with CCUS facilities. When CCUS facilities are applied this can impact production through enhanced gas recovery or production of alternative fuels. Results/Observations/Conclusions Denmark, Indonesia and Australia are compared from both legal and economic perspectives and conclusions made with respect to how well defined the legal frameworks are for CCUS developments, and the economic viability of CCUS projects when operated standalone or in conjunction with large offshore gas projects. This allows for learning across countries and identifying where improvements in fiscal regimes and incentives for CO2 storages could be made. Novelty/Additive Information CCUS builds on existing technologies but the development of frameworks for incentivizing operators to apply CCUS is still in its early stages and much learning needs to be done. The novelty in this paper is firstly the analysis of how the legal frameworks for CCUS projects compare across three very different locations. Secondly, the novelty is in the development of recommendations for the authorities in Denmark, Indonesia and Australia, for how to make it economically attractive for operators to invest in CCUS, both as standalone projects and in conjunction with large offshore gas projects.

U.S. DOE's R&D Program to Develop Infrastructure for Carbon Storage: Overview of the Regional Carbon Sequestration Partnerships and other R&D Field Projects

The selection of suitable working fluids for use in Organic Rankine Cycles (ORC) is strongly addicted to the intended application of the ORC system. The design of the ORC, the kind of heat source and the ambient condition has an influence on the performance of the Organic Rankine Cycle and on the selection of the working fluid. It can come to a discrepancy between the best candidate from the thermodynamic point of view and the transformation into a real machine design. If an axial turbine design is considered for expansion and energy conversion within the ORC, the vapor volume flow ratios within the expansion path, the pressure ratio and of course the number of stages have to be considered within the fluid selection process and for the design parameters. Furthermore, environmental aspects have to be taken into account, e.g. the global warming potential (GWP) and the flammability of the selected fluid. This paper shows the results of the design and fluid selection process for an Organic Rankine Cycle for application in a combined operation with a 2MW class industrial gas turbine. The gas turbine contains two radial compressor stages with an integrated intercooler. To further increase the thermal cycle efficiency, a recuperator has been implemented to the gas turbine cycle, which uses the exhaust gas waste heat to preheat the compressed air after the second compressor, before it enters the combustion chamber. The shaft power is generated by a three stage axial turbine, whereby the first stage is a convection cooled stage, due to a turbine inlet temperature of 1100°C. To further increase the electrical efficiency and the power output of the energy conversion cycle, a combined operation with an organic Rankine cycle is intended. Therefore the waste heat from the GT compressor intercooler is used as first heat source and the waste heat of the exhaust gas after the recuperator as second heat source for the Organic Rankine Cycle. It is intended that the ORC fluid acts as heat absorption fluid within the compressor intercooler. Due to these specifications for the ORC, a detailed thermodynamic analysis has been performed to determine the optimal design parameter and the best working fluid for the ORC, in order to obtain a maximum power output of the combined cycle. Due to the twice coupling of the ORC to the GT cycle, the heat exchange between the two cycles is bounded by each other and a detailed analysis of the coupled cycles is necessary. E.g. the ambient temperature has an enormous influence on the transferred heat from the intercooler to the ORC cycle, which itself affects the heat transfer and temperatures of the transferable heat from the second heat source. Thus, a detailed analysis by considering the ambient operation conditions has been performed, in order to provide a most efficient energy conversion system over a wide operation range. The performance analysis has shown that by application of an ORC for a combined operation with the intercooled and recuperated gas turbine, the combined cycle efficiency can be increased, for a wide ambient conditions range, by more than 3 %pts. and the electrical power output by more than 10 %, in comparison to the stand alone intercooled and recuperated gas turbine.

Greenhouse gas emissions associated with medical conferences have been associated with climate change, and the effects of climate change have been associated with an increased incidence of ophthalmic diseases. Identifying practical strategies associated with reducing these emissions may be warranted. To assess greenhouse gas emissions associated with in-person and virtual meetings of the American Academy of Ophthalmology (AAO) and to conduct mitigation analyses to suggest strategies to reduce future emissions. Quality improvement study in which attendee and conference data were used to estimate emissions from in-person (October 12 to October 15, 2019, San Francisco, California) and virtual (November 13 to November 15, 2020) AAO annual meetings for 35 104 attendees. The data were also used to perform mitigation analyses to assess whether meeting format alterations could be used to reduce future emissions. Data were analyzed from December 21, 2021, to April 18, 2022. Attendance at a selected meeting. Total attendance was 23 190 participants in 2019 and 11 914 participants in 2020. Greenhouse gas emissions produced by the in-person meeting were estimated by calculating the equivalent metric tons of carbon dioxide (CO2) associated with attendee transportation, attendee accommodations, and the conference venue. Emissions produced by the virtual meeting were estimated by calculating the equivalent metric tons of CO2 associated with attendees' computer use, network data transfer, and video-conferencing server use. Mitigation analyses simulated the association of changing the meeting location and format with reductions in emissions. In this analysis, the 2019 in-person meeting produced 39 910 metric tons of CO2 (1.73 metric tons of CO2 per capita), and the 2020 virtual meeting produced 38.6 metric tons of CO2 (0.003 metric tons of CO2 per capita). Mitigation analyses showed that holding a single in-person meeting in Chicago, Illinois, rather than San Francisco, California, could be associated with transportation-related emissions reductions of 19% (emissions for the San Francisco meeting, 38 993 metric tons of CO2; for the Chicago meeting, 31 616 metric tons of CO2). Holding multiple in-person meetings in separate regions could be associated with transportation-related emissions reductions of as much as 38% (emissions for the San Francisco meeting, 38 993 metric tons of CO2; for multiple meeting scenario 2, 24 165 metric tons of CO2). This study found that the AAO's 2019 in-person meeting was associated with substantially higher greenhouse gas emissions compared with the 2020 virtual meeting, primarily due to transportation-related emissions. Increasing the proportion of virtual participants, holding the meeting in locations chosen to minimize transportation-related emissions, or offering multiple regional meeting locations may reduce the carbon footprint of future meetings.

Since my column in the September 2022 JPT about the regulation of ownership and leasing of pore space, dealmaking has picked up steam, especially by Oxy. Many of the announced deals by Oxy and others are in Texas and in the Gulf Coast region. Oxy Low Carbon Ventures (OLCV) signed an agreement in October with Natural Resource Partners LP for the evaluation of a potential CO2 sequestration hub in Texas. OLCV, a subsidiary of Occidental, would gain rights to about 65,000 acres of pore space for its development, with the potential to store a minimum of 500 million metric tons of CO2. The proposed site is in proximity to industrial greenhouse-gas emitters and a prime location for Oxy’s 1PointFive’s plans to build a carbon capture and sequestration (CCS) hub, possibly connected to direct air capture (DAC) facilities. Also, in October, Occidental and 1PointFive signed a lease agreement with King Ranch, a privately held agricultural production and resource management company, to support large-scale DAC projects on 106,000 acres in Kleberg County, Texas, with the potential to remove up to 30 million metric tons of CO2 per year. The pores space is estimated to store up to 3 billion metric tons of CO2. In addition to DAC emissions capture, the King Ranch acreage is located near industrial emitters in the Gulf Coast region, including Corpus Christi, where emissions can be captured, transported, and sequestered in the pore space. Each DAC plant in the site is expected to be capable of removing up to 1 million metric tons of CO2 per year, yielding a total capacity of up to 30 million metric tons per year when all facilities are operational. Carbon Engineering (CE) began front-end planning and engineering for the DAC facilities in Kleberg County in October. The first 1-megatonne facility is intended to be replicated into multimillion-tonne deployments. The design is being adapted from the first large-scale, commercial facility to use CE’s DAC technology, which is already under construction in the Texas Permian Basin and is expected to start up in 2024. Founded in the 1853, the 825,000-acre King Ranch holds an iconic legacy in Texas. Now, 170 years later, it may build upon that legacy with technological advances not foreseen in its earlier years. In another Oxy deal in 2022, this one with Weyerhaeuser Co., more than 30,000 acres of pore space will be evaluated and potentially developed for CCS in Livingston Parish, Louisiana. Weyerhaeuser will continue to manage the aboveground acreage as a working forest. Also in Louisiana, Lapis Energy, a CCS developer and operator based in Dallas, completed the lease of over 14,000 acres of carbon pore space rights with a private landowner 20 miles west of New Orleans. Lapis believes the pore space in the area has the potential to store more than 500 million tonnes of industrial CO2 and has begun technical studies to progress a Class VI permit for the area. Lapis plans to be ready to begin injection by 2025. San Antonio-based Ozona CCS LLC has reached a definitive agreement in January with Texas Pacific Land Corp. to lease approximately 5,173 contiguous acres of land to drill one of the first commercial CO2 sequestration wells in the Permian Basin. The company will initially focus on the Permian Basin and the Texas Gulf Coast for CCS projects. Initial anchor customers will include natural gas processing plants and oil and gas operators in the region. The acreage has an estimated initial injection rate of up to 25,000 B/D and an estimated total storage capacity of at least 40 million metric tons of CO2. The target in-service date is in the third quarter of 2024. Rystad Energy’s Audun Martinsen, head of supply chain research, forecast a rise in low-carbon investments by $60 billion in 2023, 10% higher than 2022. Hydrogen and CCUS are expected to see the most significant annual increase, growing 149% and 136%, respectively. Total hydrogen spending will approach $7.8 billion in 2023, while CCUS investments will total about $7.4 billion. She wrote, “The new and relatively tiny market of suppliers exposed to low-carbon, well-related services is forecast to climb 33% this year, driven by geothermal drilling and CO2 injection. Despite the significant increase, investments in this market will only total about $3.7 billion.”

Australia’s carbon capture, utilisation and storage (CCUS) sector could be set for fresh boost as oil and gas players are investing heavily in large-scale projects. In 2020, Australia emitted around 499 million tonnes of CO2-equivalent (CO2e). Country-wide, only 2.5 million tonnes of CO2 is captured and stored annually in the Gorgon CCUS project. Starting its CCUS journey on the wrong foot, Australia’s ambitious Gorgon project suffered from cost overruns, delays and much lower capture rates than planned. Nevertheless, 3 years after startup we now see renewed momentum on the back of significant budgetary support from the Federal Government, in addition to inclusion of CCUS projects in the Emissions Reduction Fund and Australian Carbon Credit Units (ACCU), which increased its value ever since. Large players are sizing up opportunities for CCUS in the country and to invest in research and development of next-generation CCUS as well as direct air capture technologies. Considering the vast CO2 storage potential in depleted oil and gas fields and saline aquifers, Rystad Energy have identified three potential storage hotspots in Australia: the northwestern hub, the mid-eastern hub and the southeastern hub. These storage hubs have a cumulative CO2 storage potential of 855 gigatonnes, that is located near to important industrial clusters and is sufficiently large, so it does not pose any barrier for CO2 storage.