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Use of hot supercritical CO2 produced from a geothermal reservoir to generate electric power in a gas turbine power generation system
Journal of CO₂ Utilization 23 (2018) 20–28
Contents lists available at ScienceDirect
Journal of CO2 Utilization journal homepage: www.elsevier.com/locate/jcou
Use of hot supercritical CO2 produced from a geothermal reservoir to generate electric power in a gas turbine power generation system
T
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Edward K. Levya, Xingchao Wanga, , Chunjian Pana, Carlos E. Romeroa, Carlos Rubio Mayab a b
Energy Research Center, Lehigh University, 117 ATLSS Drive, Bethlehem, PA 18015, USA Universidad Michoacana de San Nicolás de Hidalgo, Morelia, Michoacán, Mexico
A R T I C L E I N F O
A B S T R A C T
Keywords: Supercritical carbon dioxide Geothermal heat mining Power generation
CO2 capture and sequestration in deep saline aquifers is widely considered to be a leading option for controlling greenhouse gas emissions. One such possibility involves injection of supercritical carbon dioxide into a highpermeability geothermal reservoir. In addition to the benefit of sequestering the CO2 in the reservoir, the CO2 can be used to mine geothermal heat for utilization above ground. This paper describes one of the options for generating power from hot supercritical CO2 obtained from CO2 production wells connected to a geothermal reservoir, where the original source of the CO2 is CO2 captured from fossil-fired power plants or industrial processes. The cost of power generated using CO2 produced from a geothermal reservoir with a gas turbine generation system is compared to the cost of generating power from a conventional geothermal steam power plant.
1. Introduction Carbon capture and sequestration is widely recognized as one of the more promising methods for preventing CO2 formed in fossil-fired power plants or industrial processes from being released into the atmosphere. Fig. 1 shows a fossil-fired power plant with a post combustion carbon capture system, with the captured CO2 compressed to supercritical pressures and then injected into a porous geologic reservoir for long term storage. Over the last few decades, numerous investigators have been developing a variation of the CCS approach shown in Fig. 1, in which compressed CO2 from a carbon capture process is injected into a hot geothermal reservoir. The heated high pressure CO2 flows through production well(s) to the surface of the earth. It then flows into a CO2-water separator and from there into a power generation system and it is then reinjected into the reservoir for ultimate sequestration (Fig. 2). These investigations have resulted in publications describing studies of the fluid flow and heat transfer processes in injection and production wells and through the porous material in the reservoir [1–9], papers describing the importance of CO2 thermosiphons which occur due to injection of cold supercritical CO2 into geothermal reservoirs and production of hot pressurized CO2 from the reservoirs to the earth’s surface [10–13], and papers dealing with the use of either Organic Rankine Cycle power systems or power systems which rely on expansion of hot pressurized CO2 through turbines to generate electric power from the hot produced CO2 [14–16].
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Also pertinent are publications dealing with production of water from geologic reservoirs to control reservoir pressure during CO2 injection, to recover water from the reservoir for subsequent use in water scarce areas, and/or to control the CO2 production process [17–20]. The present paper describes analyses which link the pressure and flow rate of the CO2 injected into a geologic reservoir, the arrangement of the injection and production wells, and the pressure, temperature and flow rate of the produced CO2 to the power generated from Direct Turbine Expansion Power Generation Systems. In addition, results from thermoeconomic analyses are presented to compare the cost of power generated from CO2-based geothermal power systems to the cost of power generated by a steam cycle geothermal power plant. 2. Reservoir and well modeling of CO2 flow rate, temperature and pressure The inputs needed for the type of power plant performance and cost analyses described in this paper include information on the temperature, pressure and flow rate of the hot CO2 at the production well head and pressure and temperature at the injection well head. Simulations, using an analytic expression for the Darcy Law for CO2 pressure drop in the reservoir in combination with the T2Well/ECO2N code [21], were performed for a system of five wells arranged as shown in Fig. 3. It was assumed that the top and bottom of the reservoir were 2000 m and 2500 m below the surface of the earth, the horizontal distance between
Corresponding author. E-mail address: [email protected] (X. Wang).
https://doi.org/10.1016/j.jcou.2017.11.001 Received 9 June 2017; Received in revised form 11 October 2017; Accepted 8 November 2017 Available online 20 November 2017 2212-9820/ © 2017 Elsevier Ltd. All rights reserved.
Journal of CO₂ Utilization 23 (2018) 20–28
E.K. Levy et al.
Nomenclature
prod
Roman symbols
Greek letters
R T P h s m Wnet Qin mVG
ηth
Radial distance from injection well to production well [m] Temperature [°C] Pressure [MPa] Specific enthalpy [kJ/kg] Specific entropy [kJ/kg K] Mass flow rate [kg/s] Plant net power output [MWe] Heat from geothermal reservoir [MWth] Van Genuchten parameter
Production well
Thermal efficiency [%]
Acronyms O&M COE LCOE HP LP
Operation and maintenance Cost of electricity Levelized cost of electricity High pressure Low pressure
Subscripts inj
Injection well
Fig. 1. Steam Power Plant with Post-Combustion CO2 Capture and Sequestration in Geologic Reservoir.
Γfρm um um ∂ ∂P 1 ∂ − − ρm g cos θ (ρ um) + [A (ρm um2 + γ )] = − ∂t m A ∂z ∂z 2A
the injection well and each of the four production wells was 425 m, the bottom of the injection well was at the bottom of the reservoir (see Fig. 3) and the radial velocity of the injected CO2 flowing from the injection well was uniform from the top of the reservoir to the bottom. It was also assumed the reservoir has a single porosity with a value of 0.1 and a permeability of 30 mD and the specific heat and thermal conductivity of the cap rock equals are 920 J/(kg K) and 2.51 W/(m K) (see Table 1). The temperature of the injected CO2 was assumed to be 30 °C, the initial temperature in the reservoir was 225 °C, the reservoir was initially filled with water, and the pressure at the top of the reservoir at the location of the injection well at the beginning of the injection process was 8.77 MPa. The phase velocities in the wellbore were calculated using the DriftFlux-Model (DMF) and obtained by salving the momentum equation for the DFM [22]:
2 )[(C0 − 1) um + ud]2 is caused by whereγ = (SG /1 − SG )((ρG ρL ρm )/ ρ* m slip between the two phases. The terms ρm , um , ρm* and ud are the mixture velocity, the profile-adjusted average density of the mixture and the drift velocity, respectively. It was assumed the injection flow rate was 120 kg/s, with the four production wells each receiving equal flow rates of CO2. In addition, all five wells had 0.32 m wellbore diameters. In the flow model used here, the injected CO2 flows radially outward from the injection well, with part of it being captured by the four production wells (Fig. 4). The remainder bypasses the production wells and forms a plume of CO2 in the region beyond the production wells where it is ultimately permanently sequestered. This is illustrated by the results in Figs. 5–8 for an injection flow rate of 120 kg/s. Fig. 5 shows the flow rates of CO2 and water at one of the
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Fig. 2. Direct Turbine Expansion System, Including CO2 Pre-cooler, Compressor and Post Cooler with CO2 injection and Production in Geothermal Reservoir.
production wells as a function of time, where the initiation of CO2 injection occurred at zero time and full CO2 production was initiated after 5 years of injection. The predicted flow rate of CO2 at the production well shows a relatively stable flow rate of 25–27 kg/s after 12 years of injection. With an injection flow rate of 120 kg/s, and in the absence of any reinjection of the produced CO2, a CO2 flow rate at each production well of 27 kg/s would correspond to a CO2 sequestration rate of 10 percent of the injected flow rate. Figs. 6 and 8 show the corresponding predicted transient values of CO2 pressure and temperature. The pressures at the production and injection well heads are of particular importance, and in this case, the predicted production well head pressure is 8–10 MPa greater than the injection well head pressure (Fig. 6). The two temperature graphs are plotted at different time scales with Fig. 7 covering the first 15 h and Fig. 8 covering 30 years of injection. The predicted CO2 temperatures at the production wellhead range from 195 to 175 °C (Fig. 7). Fig. 8 shows
Table 1 Input Parameter and Initial Values for Geothermal Heat Mining Modeling Using CO2. Parameter Reservoir Characteristics Reservoir Porosity Reservoir Permeability Rock Specific Heat Rock Thermal Conductivity Parameters for Relative Permeability Residual Gas Saturation mVG Residual Liquid Saturation Saturated Liquid Saturation Parameters for Capillary Pressure Residual Liquid Saturation mVG Alpha
Unit
Value
– mD J/(kg K) W/(m K)
0.1 30 920 2.51
– – – –
0.01 0.65 0.05 1.00
– – Pa−1
0.03 0.4118
6.08 × 10−5
Maximum Capillary Pressure
Pa
Saturated Liquid Saturation Reservoir and Injection Well Initial Conditions Reservoir Initial Fluid Reservoir Initial Temperature Reservoir Initial Pressure CO2 Temperature at Injection Well Head CO2 Injection Mass Flow Rate
–
6.40 × 107 1.00
– °C MPa °C kg/s
Water 225 20–25 30 120
the temperatures of the CO2 at the injection well bottom and at the top of the reservoir at the location of the injection well decrease from 225 °C to 50 °C over a period of 8 h after the initiation of the injection process. 3. Geothermal CO2-based power plant based on expansion of hot produced CO2 through a gas turbine Results are presented in this paper on a conventional steam cycle geothermal power plant (see Section 4) and a CO2-based power plant (described in Section 3) which utilizes the flow of hot CO2 produced from a geothermal reservoir to provide thermal energy to a power generation system consisting of a turbine, compressor and heat exchangers (Fig. 2). The power generation cycle analyses were performed
Fig. 3. Diagram of Injection and Production Wells in the Cap Rock and Reservoir.
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Fig. 6. Predicted Transient Pressure Variations at Various Locations in the Reservoir and Injection and Production Wells.
Fig. 4. Plan View of the Arrangement of an Injection Well and Four Production Wells.
Fig. 7. Predicted Transient Variations in CO2 Temperatures at Various Locations in the Reservoir and in the Injection and Production Wells Over 30 Years.
Fig. 5. Predicted Values of Produced CO2 Flow Rate vs Time.
using the ASPEN Plus process modelling software [23]. In generating power from the expansion of hot supercritical CO2 in a gas turbine-generator, the CO2 at the turbine inlet would be at the pressure and temperature in the outlet of the production well. The reservoir and well-bore analyses described in this paper show production well head CO2 pressures in the 22.5 MPa range and temperatures from 195 to 175 °C for the particular geothermal saline aquifer modelled in this study. The compression work for CO2 is significantly lower near the critical point, thus to minimize the CO2 compression work and avoid phase change in the CO2 pre-cooler and compressor, the minimum CO2 discharge pressure was set at 7.8 MPa, which is above the critical point (31.1 °C and 7.39 MPa) These values provided the temperature and pressure ranges used in the analyses described in this paper. Fig. 9 shows the temperature-entropy (TS) diagram for the direct turbine expansion system, where it is assumed CO2 from the production well head enters the turbine at 22.5 MPa and 195 °C and expands in the turbine to 8.3 MPa. The CO2 is cooled to the 35 °C compressor inlet temperature, compressed to the injection well-head pressure of 14.5 MPa and then cooled to 30 °C prior to re-injection into the
geothermal reservoir. (Note: The locations of the five state points referred to in Fig. 9 are shown in the process diagram in Fig. 2.) Analyses were performed over a range of turbine exhaust pressures to determine the turbine exhaust pressure which would provide the largest predicted net power (turbine power minus compressor power). This was found to be 8.34 MPa for this system, and it resulted in a predicted net power of 4.61 MWe for a produced CO2 flow rate of 108 kg/s and for the particular geometry of the injection and production wells and the initial reservoir conditions. Fig. 10 shows the turbine power, compressor power and net power as functions of turbine exhaust pressure and Table 2 summarizes the optimal process conditions for the turbine expansion case. The plant thermal efficiency is defined as:
ηth =
Wnet Wnet = Qin mCO2 (hCO2, prod − hCO2, inj )
where hCO2, prod and hCO2, inj are the enthalpies of CO2 at the production well head and injection well head, respectively. Pressure drops through the water cooled heat exchangers used for 23
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E.K. Levy et al.
Fig. 10. Net Power Output and Turbine/Compressor Power for Direct Turbine Expansion System. Fig. 8. Predicted Transient Variations in CO2 Temperatures at Various Locations in the Reservoir and in the Injection and Production Wells Over 15 h. Table 2 Optimal Process Conditions for the Direct Turbine Expansion Case.
cooling the CO2 before it enters the CO2 compressor and before it is reinjected back into the geothermal reservoir have the potential to affect the cycle efficiency and thus they were calculated as part of this study. The heat exchangers were assumed to be of shell and tube design (Fig. 11) and because of high CO2 pressure, the CO2 was assumed to flow on the inside of the tubes and the cooling water on the shell side of the heat exchangers. Analyses were performed to determine required heat exchanger surface area, tube diameter and length, and cooling water flow rate [26]. Using these parameters, estimates were made of both tube side and shell side pressure drops and installed costs of the heat exchangers. The compressor power needed to overcome pressure losses in the CO2 pre and post-coolers is approximately 3 kW for this case and is negligible compared to the power input to the CO2
Net Power Output
MWe
4.61
Plant Thermal Efficiency Compressor Outlet P Hot CO2 Flow Rate Optimal Turbine Outlet P Pre-cooler Outlet T Turbine/Comp Isentropic Eff.
% MPa kg/s MPa °C %
14.3 14.5 108 8.34 35 88.0
Fig. 9. Temperature-Entropy Diagram for Direct Turbine Expansion with Hot Produced CO2.
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(Note: The results shown in Table 3 were generated by the authors from ASPEN Plus simulations of the power generation unit represented in Fig. 12). The thermal efficiency for this conventional steam cycle geothermal power plant was obtained from:
ηth =
Wnet Wnet = Qin m H2 O,1⋅h H2 O,1 − m H2 O,4⋅h H2 O,4 − (m H2 O,1 − m H2 O,4 )⋅h H2 O,9
where h H2 O and m H2 O are the enthalpies and mass flow rate of H2O for different streams shown in Fig. 12. 5. Cost comparisons Cost comparisons were developed for the two geothermal power generation technologies described in this paper. To provide a common basis for comparison, a 30 MWe power generation capacity was assumed for each technology. Costs for a 30 MWe Dual Flash Steam Geothermal Power Plant were taken from Ref. [24] and the costs for a 30 MWe CO2 Direct Turbine Expansion Unit were developed by the authors of the present paper.
Fig. 11. Heat Exchanger Used to Cool CO2 Upstream and Downstream of CO2 Compressor.
compressor [27].
5.1. Dual flash steam geothermal power plant 4. Geothermal steam-based rankine cycle power plant Investigators at the U.S. Department of Energy have developed software, referred to as GETEM, for computing levelized cost of electricity (LCOE) of water and steam type geothermal power plants [24], and one of the cases they modeled is a dual flash steam geothermal power cycle similar in concept to the 100 MWe unit described in Table 2 and illustrated in Fig. 11. They published results for a 30 MWe unit and the cost analysis for the steam hydrothermal flash unit described here is patterned after their findings. The hydrothermal reservoir temperature is listed at 200 °C in Ref. [24], the reservoir is 2 km deep and the well flow is 80 kg/s. A total of 5.8 production wells and 4.3 injection wells were assumed, and a total of 13.9 wells were drilled (Note: Depending on the conditions specified, GETEM may at times predict fractional numbers of wells). Including the costs of exploration and site confirmation, the total cost of developing the geothermal field with wells drilled is listed as $83.813 M. The installed power plant is listed at $71.078 M, and the overnight capital with contingency is $178.826 M. The annual operating cost, including O&M, taxes, insurance and royalties is $5.189 M. Assuming 4 percent annual interest with a 30 year loan, the annual fixed cost is $12.727 M.
One type of power plant currently in use for steam-based geothermal applications involves a dual flash steam cycle. Fig. 12 shows the process diagram for a 100 MWe geothermal steam unit located in Mexico [25]. Wet saturated steam, produced from the geothermal reservoir, enters the high pressure (HP) flash separator, with the vapor phase flowing to the high pressure (HP) turbine. The liquid phase flowing from the HP separator goes from there to a low pressure (LP) flash separator, with the vapor phase from the LP separator flowing to the low pressure (LP) turbine and the liquid phase from the LP separator being discharged back to the geothermal well. The steam flow leaving the HP turbine is mixed with the LP steam leaving the LP Separator, with the combined flow going from there into the LP turbine. Low pressure steam from the LP turbine is condensed in a water cooled direct contact condenser. Table 3 shows the process conditions for the dual flash steam unit. The overall thermodynamic efficiency of this power plant is 18.7 percent and the net rate of heat input to the power plant with the steam from the geothermal reservoir is 534.78 MWe at full load conditions.
Fig. 12. Process Diagram of a 100 MWe Geothermal Heated Steam Cycle Power Plant (Color Printed).
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5.2. CO2 powered direct turbine expansion power plant
Table 3 Design Data of Dual Flash Geothermal Steam Power Plant. Net Power Output
MWe
100
Reservoir Outlet Vapor Fraction Production Well Water Flow Rate (m1) Production Well Outlet Enthalpy (h1) Re-Injection Flow Rate (m4) Re-Injection Inlet Enthalpy (h4) HP Turbine Inlet Temp HP Turbine Inlet Pressure HP Steam Flow Rate LP Turbine Inlet Temp LP Turbine Inlet Pressure LP Steam Flow Rate Turbine Isentropic Eff. Condenser Temp Condenser Pressure Condenser Outlet Enthalpy
– kg/s kJ/kg kg/s kJ/kg °C MPa kg/s °C MPa kg/s % °C MPa kJ/kg
0.34 518.6 1464.4 311.3 596.2 185 1.01 176.46 121 0.206 206.08 71.4 45 0.012 188.4
For a single five-well system with total produced CO2 flow rate of 108 kg/s and with the turbine/compressor/heat exchanger system illustrated in Fig. 2, the net power produced would be 4.6 MWe. To generate 30 MWe of net power, 6.51 five-well systems would be needed (or 7 five-well systems, if we round up to a whole number of wells). If it is assumed each well is 2 km deep at $4 M per well, the cost of 7 fivewell systems and 7 reinjection wells would be $168 M plus $35 M for exploration and site confirmation. (Table 4) The estimates for equipment costs include seven CO2/water separators and turbines ($10.5 M), seven compressors ($7 M), and seven sets of heat exchangers ($2.8 M). Assuming a $4 M contingency, the installed equipment costs come to $48.3 M. (Another option would be to install a central power plant with the capacity to produce 30 MWe from the produced CO2 taken from the 7 five-well systems.) The overnight installed cost including site exploration and confirmation, well drilling and equipment installation plus an additional 15 percent contingency totals $289 M. The annual fixed charge for this case is $20.57 M, and for a 90 percent capacity factor, the cost of the plant comes to $0.087/kW h. With an O&M cost of $0.024/kWh, this yields electrical power at $0.11097/kW h. Using a levelization factor of 1.4, this yields a levelized cost of electricity of $0.155/kWh (Table 4). One of the potential advantages of using hot produced CO2 from a geothermal reservoir to generate power is the benefit of permanently sequestering the CO2 as part of the power generation process. At the present time, CO2 credits are purchased and sold in some parts of the world, and these range widely in price, depending on the country or state. Recent examples include $3.50/t in Mexico, $12–$13/t in California and 5–6 euros/t in the European Union. In the case of the 30 MWe CO2 power plant described above, the total flow rate of injected CO2 would be 782 kg/s or 22.2 t/year. Fig. 13 shows the CO2 credits and the net profit from the CO2 power plant as functions of the price of CO2. The results of the analysis show that at CO2 prices of approximately $0.50/t or higher, the geothermal CO2 power plant would be more profitable than the conventional steam plant steam described in this paper.
Table 4 Cost Comparisons of the Two Geothermal Technologies (30 Year Life).
CO2 Injection Flow Rate per Well, kg/s Power, MWe Number of Wells Cost of Wells, $M Installed Costs of Power Plant, $M Overnight Capital +15% Contingency, $M Annual O&M, $M Annual Fixed Charge, $M Cost of Plant, $/kW h Cost of O&M, $/kW h COE, $/kW h LCOE, $/kW h
Steam Hydrothermal Flash
CO2 Direct Turbine Expansion
0
120
30 10 83.813 71.078
30 42 203 48.3
178.8
289
5.189 12.727 0.0538 0.024 0.0778 0.109
5.189 20.57 0.087 0.024 0.11097 0.155
6. Discussion and conclusions Geothermal reservoir and well-bore simulations were performed for a system of one injection well and four production wells arranged with the injection well in the center of the array and with each of the production wells located 425 m from the injection well. It was assumed the flow in the production wells was initiated five years after initiation of CO2 injection. The predicted flow rate of CO2 at each production well shows a relatively stable flow rate after 12 years of injection. (Note: The actual CO2 flow rate at the production well as a function of time would greatly depend on distance between the injection and production wells, flow rate of injected CO2 and reservoir permeability). The pressures at the production and injection well heads are of particular importance, and in this case, due to the thermosiphon effect caused by the hot CO2, the predicted production well head pressure is 8–10 MPa greater than the injection well head pressure. The predicted CO2 temperatures at the production wellhead range from 195 to 175 °C. Cost of electricity (COE) was tabulated for the two geothermal power generation technologies (Dual Flash Steam Hydrothermal power plant and CO2 powered Direct Turbine Expansion system). To provide a basis for comparison, a 30 MWe power generation capacity was assumed for each system. The seven pairs of wells needed to generate 30 MWe from the geothermal CO2 system, might be arranged as illustrated in Fig. 14. Also shown in this figure are seven individual injection wells which would be used for reinjecting the CO2 leaving the power generation systems back into the reservoir. The installed capital costs for the geothermal CO2 system analyzed here are significantly higher than those for the geothermal steam
Fig. 13. CO2 Credits and Difference in Levelized Costs of Electricity for Geothermal CO2 and Steam Power Plants.
For a 90 percent capacity factor, the cost of the plant comes to $0.0538/ kW h and with an operating cost of $0.024/kWh this yields electrical power at $0.0778/kW h. Using a levelization factor of 1.4, this yields a levelized cost of electricity of $0.1089/kWh (Table 4).
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Fig. 14. Well Field with Seven Five-Well Arrays and Additional Wells for Reinjection of CO2.
[2] K. Pruess, Enhanced geothermal systems (EGS) using CO2 as working fluid – a novel approach for generating renewable energy with simultaneous sequestration of carbon, Geothermics 35 (2006) 351–367. [3] K. Pruess, M. Azaroual, On the feasibility of using supercritical CO2 as heat transmission fluid in an engineered hot dry rock geothermal system, Proceedings ThirtyFirst Workshop on Geothermal Reservoir Engineering, Stanford University, January 30–February 1, 2006. [4] K. Pruess, On production behavior of enhanced geothermal systems with CO2 as working fluid, Energy Convers. Manage. 49 (2008) 1446–1454. [5] J. Randolph, M. Saar, Coupling geothermal energy capture with carbon dioxide sequestration in naturally permeable, porous geologic formations: a comparison with enhanced geothermal systems, GRC Trans. 34 (2010) 433–437. [6] J. Randolph, M. Saar, Coupling carbon dioxide sequestration with geothermal energy capture in naturally permeable, porous geologic formations: implications for CO2 sequestration, Energy Procedia 4 (2011) 2206–2213. [7] A. Eastman, M. Muir, Update of a trial of CO2–based geothermal at the St. Johns dome, Proceedings Thirty-Seventh Workshop on Geothermal Reservoir Engineering, Stanford University, January 30–February 1, 2012. [8] P. Jiang, X. Li, R. Xu, Y. Wang, M. Chen, H. Wang, B. Ruan, Thermal modeling of CO2 in the injection well and reservoir at the ordos CCS demonstration project, China, Int. J. Greenh. Gas Control 23 (April) (2014) 135–146. [9] L. Zhang, J. Ezekiel, D. Li, J. Pei, S. Ren, Potential assessment of CO2 injection for heat mining and geological storage in geothermal reservoirs of China, Appl. Energy 122 (June) (2014) 237–246. [10] A. Atrens, H. Gurgenci, V. Rudolph, Exergy analysis of a CO2 thermosiphon, Proceedings Thirty-Forth Workshop on Geothermal Reservoir Engineering, Stanford University, February 9–11, 2009. [11] A. Atrens, H. Gurgenci, V. Rudolph, CO2 thermosiphon for competitive geothermal power generation, Energy Fuels 23 (2009) 553–557. [12] A. Atrens, H. Gurgenci, V. Rudolph, Electricity generation using a carbon dioxide thermosiphon, Geothermics 39 (2010) 161–169. [13] B.M. Adams, T.H. Kuehn, J.M. Bielicki, J.B. Randolph, M.O. Saar, On the importance of the thermosiphon effect in CPG (CO2 plume geothermal) power systems, Energy 69 (May) (2014) 409–418. [14] A.R. Mohan, U. Turaga, V. Shembekar, D. Elsworth, S.V. Pisupati, Utilization of carbon dioxide from coal-based power plants as a heat transfer fluid for electricity generation in enhanced geothermal systems (EGS), Energy 57 (August) (2013) 505–512. [15] A. Atrens, H. Gurgenci, V. Rudolph, Economic optimization of a CO2-based EGS power plant, Energy Fuels 25 (2011) 3765–3775. [16] A. Atrens, H. Gurgenci, V. Rudolph, Economic analysis of CO2 thermosiphon, Proceedings World Geothermal Congress 2010, Bali, Indonesia 25–29, April 2010, 2010. [17] A. Atrens, H. Gurgenci, V. Rudolph, Removal of water for carbon dioxide- based EGS operation, Proceedings Thirty-Sixth Workshop on Geothermal Reservoir Engineering, Stanford University, January 31–February 2, 2011. [18] P. Ziemkiewicz, P.H. Stauffer, J. Sullivan-Graham, S.P. Chu, W.L. Bourcier, T.A. Buscheck, T. Carr, J. Donovan, Z. Jiao, L. Lin, L. Song, Opportunities for increasing CO 2 storage in deep, saline formations by active reservoir management and treatment of extracted formation water: case study at the GreenGen IGCC facility Tianjin, PR China, Int. J. Greenh. Gas Control 54 (November) (2016) 538–556. [19] T.A. Buscheck, J.M. Bielicki, J.A. White, Y. Sun, Y. Hao, W.L. Bourcier, S.A. Carroll, R.D. Aines, Pre-injection brine production in CO 2 storage reservoirs: an approach to augment the development, operation, and performance of CCS while generating water, Int. J. Greenh. Gas Control 54 (November) (2016) 499–512. [20] T. Buscheck, Active CO2 reservoir management, Proceedings U.S.DOE, NETL,
system, due to the larger number of wells required to inject and produce CO2 compared to steam. However, the number of CO2 wells needed for a specified MW output will depend on the CO2 injection flow rates per well. In addition to the flow rates in the injection wells, the distance between the injection and production wells is another important parameter which should be optimized. Changes such as these would affect the temperature, pressure and flow rate of the produced CO2 and might also impact the CO2 pressure at the head of the injection wells. These parameters would, in turn, affect installed capital costs, rate of power generation and costs of the produced power. The authors are in the process of exploring some of these possibilities in an effort to develop an optimized system. Using hot produced CO2 from a geothermal reservoir to generate power would provide the additional benefit of permanently sequestering the CO2 as part of the power generation process. At the present time, CO2 credits are purchased and sold in some parts of the world, and these range widely in price, depending on the country or state. Recent examples include $3.50 t in Mexico, $12–$13/t in California and 5–6 euros/t in the European Union. The results in this paper show that being able to take advantage of CO2 credits by reinjecting the CO2 leaving the CO2 Direct Turbine Expansion system into the geothermal reservoir, could make the CO2 power generation option described here extremely profitable compared to a conventional geothermal Steam Flash System. Acknowledgments This study was funded by the Mexican National Council of Science and Technology (CONACYT in Spanish), under the Sectorial Fund for Energy Sustainability, CONACYT-Secretary of Energy (No. S0019-201204). The team, formed by the Lehigh University Energy Research Center and the University of Michoacán San Nicolás Hidalgo, involved in this project is grateful to the administrators of the Mexican Center for Innovation in Energy-Geothermal (CEMIE-Geo in Spanish) for their support and administration of the program. Additionally, our thanks to Professor Lehua Pan for providing his research version of the TOUGH2ECO2N v.2 code for high temperature simulations, as well as for the many useful discussions and suggestions. References [1] D. Brown, A hot dry rock geothermal energy concept utilizing supercritical CO2 instead of water, Proceedings Twenty-Fifth Workshop on Geothermal Reservoir Engineering, Stanford University, January 24–26, 2000.
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[24] J. Nathwani, G. Mines, Cost contributors to geothermal power generation, Proceedings World Geothermal Congress Melbourne, Australia, April 2015, 2015. [25] C. Romero, Personal Communication with Mexico’s Federal Commission of Electricity (CFE), (2016). [26] T.L. Bergman, F.P. Incropera, Fundamentals of Heat and Mass Transfer, John Wiley & Sons, 2011. [27] W.S. Janna, Design of Fluid Thermal Systems-SI Version, Cengage learning, 2010.
Carbon Storage R&D Project Review Meeting, Pittsburgh, PA., August 18–20, 2015. [21] L. Pan, C. Oldenburg, Y. Wu, K. Pruess, T2Well/ECO2N Version 1.0: Multiphase and Non-Isothermal Model for Coupled Wellbore-Reservoir Flow of Carbon Dioxide and Variable Salinity Water, Report LBNL-4291E, Lawrence Berkeley National Laboratory, Berkeley, California, 2011. [22] L. Pan, S.W. Webb, C.M. Oldenburg, Analytical solution for two-phase flow in a wellbore using the drift-flux model, Adv. Water Resour. 34 (12) (2011) 1656–1665. [23] Aspen Technology, Aspen Plus V8.1, (2012) Burlington, MA.
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Contents lists available at ScienceDirect
Journal of CO2 Utilization journal homepage: www.elsevier.com/locate/jcou
Use of hot supercritical CO2 produced from a geothermal reservoir to generate electric power in a gas turbine power generation system
T
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Edward K. Levya, Xingchao Wanga, , Chunjian Pana, Carlos E. Romeroa, Carlos Rubio Mayab a b
Energy Research Center, Lehigh University, 117 ATLSS Drive, Bethlehem, PA 18015, USA Universidad Michoacana de San Nicolás de Hidalgo, Morelia, Michoacán, Mexico
A R T I C L E I N F O
A B S T R A C T
Keywords: Supercritical carbon dioxide Geothermal heat mining Power generation
CO2 capture and sequestration in deep saline aquifers is widely considered to be a leading option for controlling greenhouse gas emissions. One such possibility involves injection of supercritical carbon dioxide into a highpermeability geothermal reservoir. In addition to the benefit of sequestering the CO2 in the reservoir, the CO2 can be used to mine geothermal heat for utilization above ground. This paper describes one of the options for generating power from hot supercritical CO2 obtained from CO2 production wells connected to a geothermal reservoir, where the original source of the CO2 is CO2 captured from fossil-fired power plants or industrial processes. The cost of power generated using CO2 produced from a geothermal reservoir with a gas turbine generation system is compared to the cost of generating power from a conventional geothermal steam power plant.
1. Introduction Carbon capture and sequestration is widely recognized as one of the more promising methods for preventing CO2 formed in fossil-fired power plants or industrial processes from being released into the atmosphere. Fig. 1 shows a fossil-fired power plant with a post combustion carbon capture system, with the captured CO2 compressed to supercritical pressures and then injected into a porous geologic reservoir for long term storage. Over the last few decades, numerous investigators have been developing a variation of the CCS approach shown in Fig. 1, in which compressed CO2 from a carbon capture process is injected into a hot geothermal reservoir. The heated high pressure CO2 flows through production well(s) to the surface of the earth. It then flows into a CO2-water separator and from there into a power generation system and it is then reinjected into the reservoir for ultimate sequestration (Fig. 2). These investigations have resulted in publications describing studies of the fluid flow and heat transfer processes in injection and production wells and through the porous material in the reservoir [1–9], papers describing the importance of CO2 thermosiphons which occur due to injection of cold supercritical CO2 into geothermal reservoirs and production of hot pressurized CO2 from the reservoirs to the earth’s surface [10–13], and papers dealing with the use of either Organic Rankine Cycle power systems or power systems which rely on expansion of hot pressurized CO2 through turbines to generate electric power from the hot produced CO2 [14–16].
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Also pertinent are publications dealing with production of water from geologic reservoirs to control reservoir pressure during CO2 injection, to recover water from the reservoir for subsequent use in water scarce areas, and/or to control the CO2 production process [17–20]. The present paper describes analyses which link the pressure and flow rate of the CO2 injected into a geologic reservoir, the arrangement of the injection and production wells, and the pressure, temperature and flow rate of the produced CO2 to the power generated from Direct Turbine Expansion Power Generation Systems. In addition, results from thermoeconomic analyses are presented to compare the cost of power generated from CO2-based geothermal power systems to the cost of power generated by a steam cycle geothermal power plant. 2. Reservoir and well modeling of CO2 flow rate, temperature and pressure The inputs needed for the type of power plant performance and cost analyses described in this paper include information on the temperature, pressure and flow rate of the hot CO2 at the production well head and pressure and temperature at the injection well head. Simulations, using an analytic expression for the Darcy Law for CO2 pressure drop in the reservoir in combination with the T2Well/ECO2N code [21], were performed for a system of five wells arranged as shown in Fig. 3. It was assumed that the top and bottom of the reservoir were 2000 m and 2500 m below the surface of the earth, the horizontal distance between
Corresponding author. E-mail address: [email protected] (X. Wang).
https://doi.org/10.1016/j.jcou.2017.11.001 Received 9 June 2017; Received in revised form 11 October 2017; Accepted 8 November 2017 Available online 20 November 2017 2212-9820/ © 2017 Elsevier Ltd. All rights reserved.
Journal of CO₂ Utilization 23 (2018) 20–28
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Nomenclature
prod
Roman symbols
Greek letters
R T P h s m Wnet Qin mVG
ηth
Radial distance from injection well to production well [m] Temperature [°C] Pressure [MPa] Specific enthalpy [kJ/kg] Specific entropy [kJ/kg K] Mass flow rate [kg/s] Plant net power output [MWe] Heat from geothermal reservoir [MWth] Van Genuchten parameter
Production well
Thermal efficiency [%]
Acronyms O&M COE LCOE HP LP
Operation and maintenance Cost of electricity Levelized cost of electricity High pressure Low pressure
Subscripts inj
Injection well
Fig. 1. Steam Power Plant with Post-Combustion CO2 Capture and Sequestration in Geologic Reservoir.
Γfρm um um ∂ ∂P 1 ∂ − − ρm g cos θ (ρ um) + [A (ρm um2 + γ )] = − ∂t m A ∂z ∂z 2A
the injection well and each of the four production wells was 425 m, the bottom of the injection well was at the bottom of the reservoir (see Fig. 3) and the radial velocity of the injected CO2 flowing from the injection well was uniform from the top of the reservoir to the bottom. It was also assumed the reservoir has a single porosity with a value of 0.1 and a permeability of 30 mD and the specific heat and thermal conductivity of the cap rock equals are 920 J/(kg K) and 2.51 W/(m K) (see Table 1). The temperature of the injected CO2 was assumed to be 30 °C, the initial temperature in the reservoir was 225 °C, the reservoir was initially filled with water, and the pressure at the top of the reservoir at the location of the injection well at the beginning of the injection process was 8.77 MPa. The phase velocities in the wellbore were calculated using the DriftFlux-Model (DMF) and obtained by salving the momentum equation for the DFM [22]:
2 )[(C0 − 1) um + ud]2 is caused by whereγ = (SG /1 − SG )((ρG ρL ρm )/ ρ* m slip between the two phases. The terms ρm , um , ρm* and ud are the mixture velocity, the profile-adjusted average density of the mixture and the drift velocity, respectively. It was assumed the injection flow rate was 120 kg/s, with the four production wells each receiving equal flow rates of CO2. In addition, all five wells had 0.32 m wellbore diameters. In the flow model used here, the injected CO2 flows radially outward from the injection well, with part of it being captured by the four production wells (Fig. 4). The remainder bypasses the production wells and forms a plume of CO2 in the region beyond the production wells where it is ultimately permanently sequestered. This is illustrated by the results in Figs. 5–8 for an injection flow rate of 120 kg/s. Fig. 5 shows the flow rates of CO2 and water at one of the
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Fig. 2. Direct Turbine Expansion System, Including CO2 Pre-cooler, Compressor and Post Cooler with CO2 injection and Production in Geothermal Reservoir.
production wells as a function of time, where the initiation of CO2 injection occurred at zero time and full CO2 production was initiated after 5 years of injection. The predicted flow rate of CO2 at the production well shows a relatively stable flow rate of 25–27 kg/s after 12 years of injection. With an injection flow rate of 120 kg/s, and in the absence of any reinjection of the produced CO2, a CO2 flow rate at each production well of 27 kg/s would correspond to a CO2 sequestration rate of 10 percent of the injected flow rate. Figs. 6 and 8 show the corresponding predicted transient values of CO2 pressure and temperature. The pressures at the production and injection well heads are of particular importance, and in this case, the predicted production well head pressure is 8–10 MPa greater than the injection well head pressure (Fig. 6). The two temperature graphs are plotted at different time scales with Fig. 7 covering the first 15 h and Fig. 8 covering 30 years of injection. The predicted CO2 temperatures at the production wellhead range from 195 to 175 °C (Fig. 7). Fig. 8 shows
Table 1 Input Parameter and Initial Values for Geothermal Heat Mining Modeling Using CO2. Parameter Reservoir Characteristics Reservoir Porosity Reservoir Permeability Rock Specific Heat Rock Thermal Conductivity Parameters for Relative Permeability Residual Gas Saturation mVG Residual Liquid Saturation Saturated Liquid Saturation Parameters for Capillary Pressure Residual Liquid Saturation mVG Alpha
Unit
Value
– mD J/(kg K) W/(m K)
0.1 30 920 2.51
– – – –
0.01 0.65 0.05 1.00
– – Pa−1
0.03 0.4118
6.08 × 10−5
Maximum Capillary Pressure
Pa
Saturated Liquid Saturation Reservoir and Injection Well Initial Conditions Reservoir Initial Fluid Reservoir Initial Temperature Reservoir Initial Pressure CO2 Temperature at Injection Well Head CO2 Injection Mass Flow Rate
–
6.40 × 107 1.00
– °C MPa °C kg/s
Water 225 20–25 30 120
the temperatures of the CO2 at the injection well bottom and at the top of the reservoir at the location of the injection well decrease from 225 °C to 50 °C over a period of 8 h after the initiation of the injection process. 3. Geothermal CO2-based power plant based on expansion of hot produced CO2 through a gas turbine Results are presented in this paper on a conventional steam cycle geothermal power plant (see Section 4) and a CO2-based power plant (described in Section 3) which utilizes the flow of hot CO2 produced from a geothermal reservoir to provide thermal energy to a power generation system consisting of a turbine, compressor and heat exchangers (Fig. 2). The power generation cycle analyses were performed
Fig. 3. Diagram of Injection and Production Wells in the Cap Rock and Reservoir.
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Fig. 6. Predicted Transient Pressure Variations at Various Locations in the Reservoir and Injection and Production Wells.
Fig. 4. Plan View of the Arrangement of an Injection Well and Four Production Wells.
Fig. 7. Predicted Transient Variations in CO2 Temperatures at Various Locations in the Reservoir and in the Injection and Production Wells Over 30 Years.
Fig. 5. Predicted Values of Produced CO2 Flow Rate vs Time.
using the ASPEN Plus process modelling software [23]. In generating power from the expansion of hot supercritical CO2 in a gas turbine-generator, the CO2 at the turbine inlet would be at the pressure and temperature in the outlet of the production well. The reservoir and well-bore analyses described in this paper show production well head CO2 pressures in the 22.5 MPa range and temperatures from 195 to 175 °C for the particular geothermal saline aquifer modelled in this study. The compression work for CO2 is significantly lower near the critical point, thus to minimize the CO2 compression work and avoid phase change in the CO2 pre-cooler and compressor, the minimum CO2 discharge pressure was set at 7.8 MPa, which is above the critical point (31.1 °C and 7.39 MPa) These values provided the temperature and pressure ranges used in the analyses described in this paper. Fig. 9 shows the temperature-entropy (TS) diagram for the direct turbine expansion system, where it is assumed CO2 from the production well head enters the turbine at 22.5 MPa and 195 °C and expands in the turbine to 8.3 MPa. The CO2 is cooled to the 35 °C compressor inlet temperature, compressed to the injection well-head pressure of 14.5 MPa and then cooled to 30 °C prior to re-injection into the
geothermal reservoir. (Note: The locations of the five state points referred to in Fig. 9 are shown in the process diagram in Fig. 2.) Analyses were performed over a range of turbine exhaust pressures to determine the turbine exhaust pressure which would provide the largest predicted net power (turbine power minus compressor power). This was found to be 8.34 MPa for this system, and it resulted in a predicted net power of 4.61 MWe for a produced CO2 flow rate of 108 kg/s and for the particular geometry of the injection and production wells and the initial reservoir conditions. Fig. 10 shows the turbine power, compressor power and net power as functions of turbine exhaust pressure and Table 2 summarizes the optimal process conditions for the turbine expansion case. The plant thermal efficiency is defined as:
ηth =
Wnet Wnet = Qin mCO2 (hCO2, prod − hCO2, inj )
where hCO2, prod and hCO2, inj are the enthalpies of CO2 at the production well head and injection well head, respectively. Pressure drops through the water cooled heat exchangers used for 23
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Fig. 10. Net Power Output and Turbine/Compressor Power for Direct Turbine Expansion System. Fig. 8. Predicted Transient Variations in CO2 Temperatures at Various Locations in the Reservoir and in the Injection and Production Wells Over 15 h. Table 2 Optimal Process Conditions for the Direct Turbine Expansion Case.
cooling the CO2 before it enters the CO2 compressor and before it is reinjected back into the geothermal reservoir have the potential to affect the cycle efficiency and thus they were calculated as part of this study. The heat exchangers were assumed to be of shell and tube design (Fig. 11) and because of high CO2 pressure, the CO2 was assumed to flow on the inside of the tubes and the cooling water on the shell side of the heat exchangers. Analyses were performed to determine required heat exchanger surface area, tube diameter and length, and cooling water flow rate [26]. Using these parameters, estimates were made of both tube side and shell side pressure drops and installed costs of the heat exchangers. The compressor power needed to overcome pressure losses in the CO2 pre and post-coolers is approximately 3 kW for this case and is negligible compared to the power input to the CO2
Net Power Output
MWe
4.61
Plant Thermal Efficiency Compressor Outlet P Hot CO2 Flow Rate Optimal Turbine Outlet P Pre-cooler Outlet T Turbine/Comp Isentropic Eff.
% MPa kg/s MPa °C %
14.3 14.5 108 8.34 35 88.0
Fig. 9. Temperature-Entropy Diagram for Direct Turbine Expansion with Hot Produced CO2.
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(Note: The results shown in Table 3 were generated by the authors from ASPEN Plus simulations of the power generation unit represented in Fig. 12). The thermal efficiency for this conventional steam cycle geothermal power plant was obtained from:
ηth =
Wnet Wnet = Qin m H2 O,1⋅h H2 O,1 − m H2 O,4⋅h H2 O,4 − (m H2 O,1 − m H2 O,4 )⋅h H2 O,9
where h H2 O and m H2 O are the enthalpies and mass flow rate of H2O for different streams shown in Fig. 12. 5. Cost comparisons Cost comparisons were developed for the two geothermal power generation technologies described in this paper. To provide a common basis for comparison, a 30 MWe power generation capacity was assumed for each technology. Costs for a 30 MWe Dual Flash Steam Geothermal Power Plant were taken from Ref. [24] and the costs for a 30 MWe CO2 Direct Turbine Expansion Unit were developed by the authors of the present paper.
Fig. 11. Heat Exchanger Used to Cool CO2 Upstream and Downstream of CO2 Compressor.
compressor [27].
5.1. Dual flash steam geothermal power plant 4. Geothermal steam-based rankine cycle power plant Investigators at the U.S. Department of Energy have developed software, referred to as GETEM, for computing levelized cost of electricity (LCOE) of water and steam type geothermal power plants [24], and one of the cases they modeled is a dual flash steam geothermal power cycle similar in concept to the 100 MWe unit described in Table 2 and illustrated in Fig. 11. They published results for a 30 MWe unit and the cost analysis for the steam hydrothermal flash unit described here is patterned after their findings. The hydrothermal reservoir temperature is listed at 200 °C in Ref. [24], the reservoir is 2 km deep and the well flow is 80 kg/s. A total of 5.8 production wells and 4.3 injection wells were assumed, and a total of 13.9 wells were drilled (Note: Depending on the conditions specified, GETEM may at times predict fractional numbers of wells). Including the costs of exploration and site confirmation, the total cost of developing the geothermal field with wells drilled is listed as $83.813 M. The installed power plant is listed at $71.078 M, and the overnight capital with contingency is $178.826 M. The annual operating cost, including O&M, taxes, insurance and royalties is $5.189 M. Assuming 4 percent annual interest with a 30 year loan, the annual fixed cost is $12.727 M.
One type of power plant currently in use for steam-based geothermal applications involves a dual flash steam cycle. Fig. 12 shows the process diagram for a 100 MWe geothermal steam unit located in Mexico [25]. Wet saturated steam, produced from the geothermal reservoir, enters the high pressure (HP) flash separator, with the vapor phase flowing to the high pressure (HP) turbine. The liquid phase flowing from the HP separator goes from there to a low pressure (LP) flash separator, with the vapor phase from the LP separator flowing to the low pressure (LP) turbine and the liquid phase from the LP separator being discharged back to the geothermal well. The steam flow leaving the HP turbine is mixed with the LP steam leaving the LP Separator, with the combined flow going from there into the LP turbine. Low pressure steam from the LP turbine is condensed in a water cooled direct contact condenser. Table 3 shows the process conditions for the dual flash steam unit. The overall thermodynamic efficiency of this power plant is 18.7 percent and the net rate of heat input to the power plant with the steam from the geothermal reservoir is 534.78 MWe at full load conditions.
Fig. 12. Process Diagram of a 100 MWe Geothermal Heated Steam Cycle Power Plant (Color Printed).
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5.2. CO2 powered direct turbine expansion power plant
Table 3 Design Data of Dual Flash Geothermal Steam Power Plant. Net Power Output
MWe
100
Reservoir Outlet Vapor Fraction Production Well Water Flow Rate (m1) Production Well Outlet Enthalpy (h1) Re-Injection Flow Rate (m4) Re-Injection Inlet Enthalpy (h4) HP Turbine Inlet Temp HP Turbine Inlet Pressure HP Steam Flow Rate LP Turbine Inlet Temp LP Turbine Inlet Pressure LP Steam Flow Rate Turbine Isentropic Eff. Condenser Temp Condenser Pressure Condenser Outlet Enthalpy
– kg/s kJ/kg kg/s kJ/kg °C MPa kg/s °C MPa kg/s % °C MPa kJ/kg
0.34 518.6 1464.4 311.3 596.2 185 1.01 176.46 121 0.206 206.08 71.4 45 0.012 188.4
For a single five-well system with total produced CO2 flow rate of 108 kg/s and with the turbine/compressor/heat exchanger system illustrated in Fig. 2, the net power produced would be 4.6 MWe. To generate 30 MWe of net power, 6.51 five-well systems would be needed (or 7 five-well systems, if we round up to a whole number of wells). If it is assumed each well is 2 km deep at $4 M per well, the cost of 7 fivewell systems and 7 reinjection wells would be $168 M plus $35 M for exploration and site confirmation. (Table 4) The estimates for equipment costs include seven CO2/water separators and turbines ($10.5 M), seven compressors ($7 M), and seven sets of heat exchangers ($2.8 M). Assuming a $4 M contingency, the installed equipment costs come to $48.3 M. (Another option would be to install a central power plant with the capacity to produce 30 MWe from the produced CO2 taken from the 7 five-well systems.) The overnight installed cost including site exploration and confirmation, well drilling and equipment installation plus an additional 15 percent contingency totals $289 M. The annual fixed charge for this case is $20.57 M, and for a 90 percent capacity factor, the cost of the plant comes to $0.087/kW h. With an O&M cost of $0.024/kWh, this yields electrical power at $0.11097/kW h. Using a levelization factor of 1.4, this yields a levelized cost of electricity of $0.155/kWh (Table 4). One of the potential advantages of using hot produced CO2 from a geothermal reservoir to generate power is the benefit of permanently sequestering the CO2 as part of the power generation process. At the present time, CO2 credits are purchased and sold in some parts of the world, and these range widely in price, depending on the country or state. Recent examples include $3.50/t in Mexico, $12–$13/t in California and 5–6 euros/t in the European Union. In the case of the 30 MWe CO2 power plant described above, the total flow rate of injected CO2 would be 782 kg/s or 22.2 t/year. Fig. 13 shows the CO2 credits and the net profit from the CO2 power plant as functions of the price of CO2. The results of the analysis show that at CO2 prices of approximately $0.50/t or higher, the geothermal CO2 power plant would be more profitable than the conventional steam plant steam described in this paper.
Table 4 Cost Comparisons of the Two Geothermal Technologies (30 Year Life).
CO2 Injection Flow Rate per Well, kg/s Power, MWe Number of Wells Cost of Wells, $M Installed Costs of Power Plant, $M Overnight Capital +15% Contingency, $M Annual O&M, $M Annual Fixed Charge, $M Cost of Plant, $/kW h Cost of O&M, $/kW h COE, $/kW h LCOE, $/kW h
Steam Hydrothermal Flash
CO2 Direct Turbine Expansion
0
120
30 10 83.813 71.078
30 42 203 48.3
178.8
289
5.189 12.727 0.0538 0.024 0.0778 0.109
5.189 20.57 0.087 0.024 0.11097 0.155
6. Discussion and conclusions Geothermal reservoir and well-bore simulations were performed for a system of one injection well and four production wells arranged with the injection well in the center of the array and with each of the production wells located 425 m from the injection well. It was assumed the flow in the production wells was initiated five years after initiation of CO2 injection. The predicted flow rate of CO2 at each production well shows a relatively stable flow rate after 12 years of injection. (Note: The actual CO2 flow rate at the production well as a function of time would greatly depend on distance between the injection and production wells, flow rate of injected CO2 and reservoir permeability). The pressures at the production and injection well heads are of particular importance, and in this case, due to the thermosiphon effect caused by the hot CO2, the predicted production well head pressure is 8–10 MPa greater than the injection well head pressure. The predicted CO2 temperatures at the production wellhead range from 195 to 175 °C. Cost of electricity (COE) was tabulated for the two geothermal power generation technologies (Dual Flash Steam Hydrothermal power plant and CO2 powered Direct Turbine Expansion system). To provide a basis for comparison, a 30 MWe power generation capacity was assumed for each system. The seven pairs of wells needed to generate 30 MWe from the geothermal CO2 system, might be arranged as illustrated in Fig. 14. Also shown in this figure are seven individual injection wells which would be used for reinjecting the CO2 leaving the power generation systems back into the reservoir. The installed capital costs for the geothermal CO2 system analyzed here are significantly higher than those for the geothermal steam
Fig. 13. CO2 Credits and Difference in Levelized Costs of Electricity for Geothermal CO2 and Steam Power Plants.
For a 90 percent capacity factor, the cost of the plant comes to $0.0538/ kW h and with an operating cost of $0.024/kWh this yields electrical power at $0.0778/kW h. Using a levelization factor of 1.4, this yields a levelized cost of electricity of $0.1089/kWh (Table 4).
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Fig. 14. Well Field with Seven Five-Well Arrays and Additional Wells for Reinjection of CO2.
[2] K. Pruess, Enhanced geothermal systems (EGS) using CO2 as working fluid – a novel approach for generating renewable energy with simultaneous sequestration of carbon, Geothermics 35 (2006) 351–367. [3] K. Pruess, M. Azaroual, On the feasibility of using supercritical CO2 as heat transmission fluid in an engineered hot dry rock geothermal system, Proceedings ThirtyFirst Workshop on Geothermal Reservoir Engineering, Stanford University, January 30–February 1, 2006. [4] K. Pruess, On production behavior of enhanced geothermal systems with CO2 as working fluid, Energy Convers. Manage. 49 (2008) 1446–1454. [5] J. Randolph, M. Saar, Coupling geothermal energy capture with carbon dioxide sequestration in naturally permeable, porous geologic formations: a comparison with enhanced geothermal systems, GRC Trans. 34 (2010) 433–437. [6] J. Randolph, M. Saar, Coupling carbon dioxide sequestration with geothermal energy capture in naturally permeable, porous geologic formations: implications for CO2 sequestration, Energy Procedia 4 (2011) 2206–2213. [7] A. Eastman, M. Muir, Update of a trial of CO2–based geothermal at the St. Johns dome, Proceedings Thirty-Seventh Workshop on Geothermal Reservoir Engineering, Stanford University, January 30–February 1, 2012. [8] P. Jiang, X. Li, R. Xu, Y. Wang, M. Chen, H. Wang, B. Ruan, Thermal modeling of CO2 in the injection well and reservoir at the ordos CCS demonstration project, China, Int. J. Greenh. Gas Control 23 (April) (2014) 135–146. [9] L. Zhang, J. Ezekiel, D. Li, J. Pei, S. Ren, Potential assessment of CO2 injection for heat mining and geological storage in geothermal reservoirs of China, Appl. Energy 122 (June) (2014) 237–246. [10] A. Atrens, H. Gurgenci, V. Rudolph, Exergy analysis of a CO2 thermosiphon, Proceedings Thirty-Forth Workshop on Geothermal Reservoir Engineering, Stanford University, February 9–11, 2009. [11] A. Atrens, H. Gurgenci, V. Rudolph, CO2 thermosiphon for competitive geothermal power generation, Energy Fuels 23 (2009) 553–557. [12] A. Atrens, H. Gurgenci, V. Rudolph, Electricity generation using a carbon dioxide thermosiphon, Geothermics 39 (2010) 161–169. [13] B.M. Adams, T.H. Kuehn, J.M. Bielicki, J.B. Randolph, M.O. Saar, On the importance of the thermosiphon effect in CPG (CO2 plume geothermal) power systems, Energy 69 (May) (2014) 409–418. [14] A.R. Mohan, U. Turaga, V. Shembekar, D. Elsworth, S.V. Pisupati, Utilization of carbon dioxide from coal-based power plants as a heat transfer fluid for electricity generation in enhanced geothermal systems (EGS), Energy 57 (August) (2013) 505–512. [15] A. Atrens, H. Gurgenci, V. Rudolph, Economic optimization of a CO2-based EGS power plant, Energy Fuels 25 (2011) 3765–3775. [16] A. Atrens, H. Gurgenci, V. Rudolph, Economic analysis of CO2 thermosiphon, Proceedings World Geothermal Congress 2010, Bali, Indonesia 25–29, April 2010, 2010. [17] A. Atrens, H. Gurgenci, V. Rudolph, Removal of water for carbon dioxide- based EGS operation, Proceedings Thirty-Sixth Workshop on Geothermal Reservoir Engineering, Stanford University, January 31–February 2, 2011. [18] P. Ziemkiewicz, P.H. Stauffer, J. Sullivan-Graham, S.P. Chu, W.L. Bourcier, T.A. Buscheck, T. Carr, J. Donovan, Z. Jiao, L. Lin, L. Song, Opportunities for increasing CO 2 storage in deep, saline formations by active reservoir management and treatment of extracted formation water: case study at the GreenGen IGCC facility Tianjin, PR China, Int. J. Greenh. Gas Control 54 (November) (2016) 538–556. [19] T.A. Buscheck, J.M. Bielicki, J.A. White, Y. Sun, Y. Hao, W.L. Bourcier, S.A. Carroll, R.D. Aines, Pre-injection brine production in CO 2 storage reservoirs: an approach to augment the development, operation, and performance of CCS while generating water, Int. J. Greenh. Gas Control 54 (November) (2016) 499–512. [20] T. Buscheck, Active CO2 reservoir management, Proceedings U.S.DOE, NETL,
system, due to the larger number of wells required to inject and produce CO2 compared to steam. However, the number of CO2 wells needed for a specified MW output will depend on the CO2 injection flow rates per well. In addition to the flow rates in the injection wells, the distance between the injection and production wells is another important parameter which should be optimized. Changes such as these would affect the temperature, pressure and flow rate of the produced CO2 and might also impact the CO2 pressure at the head of the injection wells. These parameters would, in turn, affect installed capital costs, rate of power generation and costs of the produced power. The authors are in the process of exploring some of these possibilities in an effort to develop an optimized system. Using hot produced CO2 from a geothermal reservoir to generate power would provide the additional benefit of permanently sequestering the CO2 as part of the power generation process. At the present time, CO2 credits are purchased and sold in some parts of the world, and these range widely in price, depending on the country or state. Recent examples include $3.50 t in Mexico, $12–$13/t in California and 5–6 euros/t in the European Union. The results in this paper show that being able to take advantage of CO2 credits by reinjecting the CO2 leaving the CO2 Direct Turbine Expansion system into the geothermal reservoir, could make the CO2 power generation option described here extremely profitable compared to a conventional geothermal Steam Flash System. Acknowledgments This study was funded by the Mexican National Council of Science and Technology (CONACYT in Spanish), under the Sectorial Fund for Energy Sustainability, CONACYT-Secretary of Energy (No. S0019-201204). The team, formed by the Lehigh University Energy Research Center and the University of Michoacán San Nicolás Hidalgo, involved in this project is grateful to the administrators of the Mexican Center for Innovation in Energy-Geothermal (CEMIE-Geo in Spanish) for their support and administration of the program. Additionally, our thanks to Professor Lehua Pan for providing his research version of the TOUGH2ECO2N v.2 code for high temperature simulations, as well as for the many useful discussions and suggestions. References [1] D. Brown, A hot dry rock geothermal energy concept utilizing supercritical CO2 instead of water, Proceedings Twenty-Fifth Workshop on Geothermal Reservoir Engineering, Stanford University, January 24–26, 2000.
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[24] J. Nathwani, G. Mines, Cost contributors to geothermal power generation, Proceedings World Geothermal Congress Melbourne, Australia, April 2015, 2015. [25] C. Romero, Personal Communication with Mexico’s Federal Commission of Electricity (CFE), (2016). [26] T.L. Bergman, F.P. Incropera, Fundamentals of Heat and Mass Transfer, John Wiley & Sons, 2011. [27] W.S. Janna, Design of Fluid Thermal Systems-SI Version, Cengage learning, 2010.
Carbon Storage R&D Project Review Meeting, Pittsburgh, PA., August 18–20, 2015. [21] L. Pan, C. Oldenburg, Y. Wu, K. Pruess, T2Well/ECO2N Version 1.0: Multiphase and Non-Isothermal Model for Coupled Wellbore-Reservoir Flow of Carbon Dioxide and Variable Salinity Water, Report LBNL-4291E, Lawrence Berkeley National Laboratory, Berkeley, California, 2011. [22] L. Pan, S.W. Webb, C.M. Oldenburg, Analytical solution for two-phase flow in a wellbore using the drift-flux model, Adv. Water Resour. 34 (12) (2011) 1656–1665. [23] Aspen Technology, Aspen Plus V8.1, (2012) Burlington, MA.
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