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Uday T.,ADI Analytics LLC
SPE Hydrocarbon Economics and Evaluation Symposium | Year: 2014

The discovery and rapid proliferation of shale gas basins has revolutionized the supply of natural gas in North America. Natural gas from shale basins accounted for less than 1% of total natural gas supply in 2005; today shale basins provide approximately one quarter of total natural gas production. Although the supply outlook looks promising, demand for natural gas is growing moderately, if not stagnant. Sustainable growth of the natural gas industry requires that demand keep pace with supply. There are a number of natural gas monetization options including the use of gas to produce electric power; liquefaction to produce LNG for shipping globally; conversion to liquid transportation fuels such as gasoline and diesel as well as chemicals; and use as transport fuel. The relative economics and incremental impact on demand varies for each of these options. ADI Analytics has recently conducted an in-depth assessment of these gas monetization options. Our findings show that cheap North American shale gas will have global industry-wide impacts through development of new LNG supply that can compete with existing supply, moderation of oil demand through substitution and GTL and MTG, a resurgence of the chemical industry driven by new supply of NGLs. Further, there are numerous competitive developments in LNG, GTL, ethylene crackers, NGL pipelines, and cleantech, all of which could alter the industry while providing first movers significant competitive advantage. These and other findings are the subject of this paper. Copyright 2014, Society of Petroleum Engineers.

Mohan A.R.,Pennsylvania State University | Turaga U.,ADI Analytics LLC | Shembekar V.,Omkar Scientific Solutions LLC | Viswanathan S.,SSTD Inc. | And 2 more authors.
30th Annual International Pittsburgh Coal Conference 2013, PCC 2013 | Year: 2013

Utilization of CO2 from fossil fuel power plants is an important aspect to be considered as an alternative to sequestration in mitigating the global climate change. Utilizing the heat energy from the geothermal sites for the production of electricity presents a great opportunity for the simultaneous extraction of geothermal energy and sequestration of CO2 emitted from the fossil fuel power plants. CO2 captured by pre-combustion method is more suitable for heat extraction compared to that captured by post combustion method as it is discharged at high pressure suitable for sequestration. Therefore, after considering air-blown combustion, oxy-combustion and Integrated Gasification Combined Cycle (IGCC), pairing IGCC with Enhanced Geothermal System (EGS) was found to produce a symbiotic combination for the simultaneous extraction of geothermal heat energy and sequestration of CO 2. This paper models the utilization of CO2 as a heat transfer uid for the extraction of geothermal energy and utilizing the heat for the production of electricity from the Organic Rankine Cycle (ORC). The simulations were performed in ASPEN Plus version 7.3. The first part focused on well simulation with CO2 as a heat transfer uid for extraction of geothermal heat energy to predict the temperature profile and pressure profile along the length of the injection well and the production well. The second part focused on the modeling of organic Rankine cycle for the generation of electricity by utilizing the pressure and geothermal heat energy of CO 2. These simulations showed that an additional total power output of 63 MWe and 29MWe for a geothermal source temperature of 300 °C and 200 °C, respectively could be obtained for an IGCC plant output of 315 MWe.

Ram Mohan A.,Pennsylvania State University | Turaga U.,ADI Analytics LLC | Shembekar V.,Speedway | Elsworth D.,Pennsylvania State University | Pisupati S.V.,Pennsylvania State University
Energy | Year: 2013

The feasibility of using carbon dioxide (CO2) as a heat transfer fluid by organic Rankine cycle (ORC) in enhanced geothermal systems (EGS) in arid regions is explored in this paper. As CO2 is available for sequestration at high pressures from an Integrated Gasification Combined Cycle (IGCC) plant, this idea is examined by pairing an IGCC plant with an EGS plant to facilitate both the simultaneous extraction of geothermal heat and sequestration of CO2 as well as power generation from EGS. The ORC portion of EGS was modeled by ASPEN Plus version 7.3. Four different working fluids were chosen for the ORC portion of the EGS to absorb the geothermal energy from the CO2 in a binary heat exchanger. The power generated from the EGS and the lowest possible temperature at which CO2 can be discharged from the binary heat exchanger was evaluated for each working fluid. The addition of a preheater provides an opportunity to add a second cycle so that both CO2 and the working fluid can be discharged at the lowest possible temperature. In all cases, the thermal energy recovered from the EGS reservoir is substantially higher than that required to compress the CO2 stream from the IGCC for sequestration. © 2013 Elsevier Ltd.

Mohan A.R.,Pennsylvania State University | Turaga U.,ADI Analytics LLC | Subbaraman V.,SSTD Inc. | Shembekar V.,Speedway | And 2 more authors.
International Journal of Greenhouse Gas Control | Year: 2015

The global warming potential of carbon dioxide (CO2) emphasizes more the sequestration of CO2 otherwise emitted from coal-fired power plants in the future. This study is focused on pairing a coal-fired integrated gasification combined cycle (IGCC) plant with enhanced geothermal system (EGS) for simultaneous sequestration of CO2 and extraction of geothermal heat energy for subsequent electricity generation by an organic Rankine cycle (ORC) in enhanced geothermal systems (EGS). By assuming the reservoir characteristics for two different geothermal source temperatures 200°C and 300°C, heat transfer calculations show that larger reservoir volume (>1km3) is necessary for the sustained extraction of geothermal heat energy over a period of 25 years. The temperature and pressure profiles of CO2 in the injection well and the production well, the corresponding power output from the ORC for five different working fluids, are simulated by ASPEN Plus Version 7.3. The reservoir conditions and the type of working fluid selected determine the power output in the ORC. The temperature and the pressure of the CO2 at the outlet of the production well are greater than that at the injection well due to the heating of CO2 in the reservoir during the extraction of geothermal heat energy. Therefore, a combination of a high pressure turbine and an organic Rankine cycle is beneficial for the conversion of geothermal energy from CO2 into electricity before its recirculation into the injection well. Among the secondary working fluids used in the modeling of the ORC, the time-averaged net EGS power is highest for isobutane and lowest for isopentane over a period of 25 years. When isobutane is used as a secondary working fluid, the time-averaged power output over a period of 25 years for two geothermal reservoirs at an initial geothermal source temperature of 300°C and 200°C are 46MWe and 21MWe, respectively. When neopentane is used as a secondary working fluid, the time-averaged power output for a period of 25 years is 37MWe for an initial geothermal source temperature of 300°C and 17MWe for an initial geothermal source temperature of 200°C. Pairing IGCC with EGS can considerably recover some of the energy lost during the sequestration of CO2 (50MWe) from a 629MWe IGCC plant. © 2014 Elsevier Ltd.

Shembekar V.,ADI Analytics LLC | Turaga U.,ADI Analytics LLC
Transactions - Geothermal Resources Council | Year: 2011

In order to develop a true understanding of the long-term costsof emerging energy technologies, it is important to assess costs on the basis of both the technology's current status as well as a likely future state based on innovations and technology advancements. We are currently conducting such an assessment for geothermal energy technology with particular emphasis on Enhanced Geothermal Systems (EGS). In this paper, we will report our efforts to forecast the implications of innovation and their impact on future cost of power from EGS. Specifically, we have conducted a detailed assessment of technology advancements and innovations across drilling, well stimulation, and power plants. Leveraging patent data, paper literature, and detailed expert elicitations, we have inventoried a number of innovations and new technologies ranging in maturity from conceptual to commercially proven albeit in complementary industries such as oil and gas. Further, we have developed estimates of improvements along performance and cost metrics for each of these innovations. Finally, we have used a number of analytical models including the U.S. Department of Energy's Geothermal Electric Technologies Evaluation Model (GETEM) to assess the levelized costs of electricity (LCOE) for a series of cases with varying levels of technology improvements. Preliminary results show that cost reductions range from 20%50% for drilling, 5%-30% for well construction, 20%-40% for well stimulation, and 10%-38%forpowerplants. Based on these improvements, the LCOE for an illustrative EGS system can be reduced up to 40% from a reference case. Our paper will report additional details and cases from this on-going work.

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