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Energy Procedia 63 (2014) 1536 - 1545
GHGT-12
ADA's solid sorbent CO2 capture process: developing solid sorbent technology to provide the necessary flexible CO2 capture solutions
for a wide range of applications
William J. Morrisa*, Sharon Sjostromb, Maryam Sayyaha, Jayson Denneya, Omar Syeda,
Charles Lindseya, and Meghan Lindsaya
aADA-Environmental Solutions, 9135 S. Ridgeline Blvd, Suite 200, Highlands Ranch, CO 80129, USA bAdvanced Emissions Solutions, 9135 S. Ridgeline Blvd, Suite 200, Highlands Ranch, CO 80129, USA
Abstract
Thermal power plant efficiency upgrades and fuel switching from coal to natural gas will not be sufficient for meeting societal needs for decarbonization of the world's electric generating fleet. While coal remains an abundant and more cost effective fuel worldwide than natural gas, recent gas production in North America has driven a significant movement towards fuel switching from coal to gas. However, fuel switching alone will not be a practical method for necessary CO2 emissions reductions. As a result, CO2 capture technologies need to be developed which are scalable from process heaters and small gas plants to 1,000 MWe coal generating units. Retrofit technologies will also be needed because it will take decades to overhaul the entire electric generating infrastructure. Postcombustion CO2 capture will be needed to facilitate progressive CO2 emissions reductions from existing infrastructure as well as being able to flexibly adapt to any new fossil flue gas stream to provide the necessary CO2 emissions reductions for future regulatory compliance.
Carbon mitigation regulations are being discussed in several countries. The United States' Environmental Protection Agency (US EPA) propos ed a new rule, "Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units" in April 2013 for new construction of power plants in the United States, which indicated an emissions limit of 1,100 lbs/MWhr for coal fired power plants. Natural gas combined cycle plants do not require CO2 capture technology for the current EPA proposal.
* Corresponding author. Tel.: +1-720-889-6246; fax: +1-303-734-0330. E-mail address: will.morris@adaes.com
1876-6102 © 2014 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license
(http://creativecommons.Org/licenses/by-nc-nd/3.0/).
Peer-review under responsibility of the Organizing Committee of GHGT-12
doi: 10.1016/j.egypro.2014.11.163
For coal fired power plants, this emissions rate does not require 90% or more CO2 capture, and instead only calls for ~40-50% CO2 capture from a unit depending upon the specific steam cycle and fuel utilized. As a result, high capital cost technologies such as oxy-fuel combustion and integrated gasification combined cycle (IGCC) with pre-combustion CO2 capture for coal fueled applications may not be economically advantageous under this proposed regulation. However, an advantage ofpost-combustion capture, unlike integrated gasification combined cycle or oxy-fuel retrofit, is that it may be implemented as a trim over a broad range of CO2 capture from ~5-90% to meet potential regulatory requirements and industry needs with a potentially significantly lower capital expense necessary for compliance. In addition, post-combustion CO2 capture technology may be adapted to gas fired applications in the future indicating its value as a developmental technology in a time of regulatory uncertainty.
In order to explore the costs and technical challenges associated with providing large scale CO2 capture at coal fired power plants over a wide range of potential capture requirements, ADA has developed a 500 MWe conceptual design for a post-combustion CO2 capture unit that utilizes solid sorbents. ADA has also recently completed construction of a first-in-the-world, 1 MWe scale, CO2 capture pilot facility that utilizes dry solid sorbents and fuidized bed technology to efficiently capture CO2 from power plant flue gas without the energy penalties associated with heating and evaporating water-based liquid amine solvents. This facility will commence operation in 2014 and be used to validate models and assumptions used to scale solid-sorbent CO2 capture technology to necessary levels for industrial compliance. In addition, the design and construction exercise of the 1 MWe pilot plant has aided in performing cost estimates that may be compared to liquid amine-based post-combustion capture systems using methodology based upon the U.S. Department of Energy's National Energy Technology Laboratory's Carbon Capture reports of Cases 10 and 12. ADA has also compared the energy penalties and potential impacts to the levelized costs of electricity associated with a range of partial capture scenarios to assess the relative costs of partial capture compared with 90% CO2 capture.
This study shows how solid-sorbent post-combustion capture technology can provide advantages over aqueous amine technology as well as providing flexible solutions to CO2 capture needs at a wide range of scales and in an environment of regulatory uncertainty.
© 2014TheAuthors.Publishedby ElsevierLtd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/3.0/).
Peer-review under responsibility of the Organizing Committee of GHGT-12 Keywords: CO2 capture; solid sorbents;
1. Introduction
The April 2013 proposed EPA rule, " Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units," requires the use of CO2 capture for any new construction of a coal fired power plant in the United States. As a result, affordable carbon capture technologies are critical for new coal fired construction to take place in the US. Furthermore, this rule proposed an emissions limit of1,100 lbs (499 kg) of CO2/MWhr of electricity. This emissions threshold requires approximately 50% CO2 capture, which favors post-combustion CO2 capture technologies (PCCC) due to the ability to capture a slip stream of the power plant flue gas. Oxy-fuel combustion and integrated gasification combined cycle (IGCC) may not be as flexible in terms of the ability to provide carbon trim at variable capture.
In addition to coal fired utility boilers, processes such as cement kilns, steel mills, refineries, natural gas fired electric generating units, and other industrial point source emissions emit significant amounts of fossil carbon. According to the International Energy Agency, the world's primary energy supply is principally derived from fossil carbon sources such as natural gas, oil, and coal [1]. As a result, technologies are needed that can apply to a wide range of industrial sources including the initial focus of coal fired utility boilers. Fuel switching, plant retirements, and efficiency improvements may not be sufficient to achieve the necessary CO2 emissions reductions required to limit warming to a 2° C increase globally [2]. As a result, flexible technology options that can treat a wide variety of
flue gases for greenfield and retrofit applications are necessary to provide the most robust portfolio of emissions reductions solutions.
Thus the importance of PCCC technology has grown significantly. However, current PCCC technology is not currently cost effective and can pose challenging air and water emissions controls [3]. As a result, ADA-ES has been developing a solid sorbent-based PCCC technology to provide additional options for CO2 capture in postcombustion applications.
One of the primary advantages of PCCC with solid sorbents is that amines may be supported on a solid substrate with covalent bonds to reduce evaporative emissions that may be a concern in an aqueous solvent system. The dry sorbent also reduces the waste water emissions and potential contamination associated with solvent systems' spent sorbent and waste water discharges. The solid substrate also has a lower sensible heat and no latent heat of vaporization, unlike water-based MEA solvents and derivatives.
For these reasons, ADA has constructed a 1 MWe solid sorbent pilot facility as well as conducted initial commercial-scale design exercises. The pilot facility will be operated in the fall of 2014 and provide critical process information for validation and improvement of the commercial-scale design.
Additionally, ADA has conducted preliminary cost sensitivity analyses to focus pilot testing on the areas that may provide the greatest cost savings. In order to perform these analyses, ADA completed initial cost estimates using DOE base case 10 and 12 methodology. Results from this analysis indicated that the most important focus areas should be reduction of energy penalty, sorbent attrition, and capital cost reduction.
Nomenclature
DOE U.S. Department of Energy EPA U.S. Environmental Protection Agency IEA International Energy Agency LCOE Levelized Cost of Electricity PCCC Post-combustion CO2 Capture
2. Pilot Plant Construction and Installation
The pilot facility was fabricated and assembled as much as possible offsite to keep host site activities to a minimum in order to minimize disruption to the power plant. The construction was done in modules capable of being transported by barge to the installation site. Fabrication of the modules began in January 2013 and they were shipped in the third quarter of 2013. Fabrication and assembly was completed by McAbee Construction in their module yard in Tuscaloosa, Alabama. The fabrication of the adsorber is shown in Figure 1.
Site preparation was performed in parallel with the module fabrication. The pilot foundation and utility tie -ins were constructed and a dock for the barge was prepared as the modules were assembled in the module yard of McAbee Construction. Three modules were constructed and loaded onto a barge for delivery to the host site facility. The modules were then transported to the host site for installation, commissioning, and testing. Transportation of the modules is shown in Figure 2.
Figure 2. Module transportation from fabrication site to host site.
Once onsite, the modules were assembled by crane and utility tie-ins were connected. All major installation activities were completed in approximately 4 months. Upon completion of fabrication and installation, commissioning the subsystems began. Commissioning activities are in process as of September 2014. Initial parametric testing of the facility is expected to commence in October 2014. Figure 3 illustrates final installation of the third module at the host site.
Figure 3. Completed installation of capture system modules at the host site.
3. ADAsorb™ Pilot Testing
Slipstream pilot testing is critical to validate the potential of a solid sorbent-based capture technology for the power industry and to collect the data necessary to advance solid sorbent technology toward the commercial stage. The specific test plan is being developed collaboratively by ADA, subcontracted engineers, DOE/NETL, the host site, and cost share participants. A series of parametric tests will be conducted over a period of several weeks in order to derive the target conditions for continual operation. After completing the parametric testing, the pilot system will be continuously operated for a target of 30 days for performance validation.
During parametric and continuous test periods, key gas constituents, temperature, pressure, and periodic moisture measurements will be made at the inlet and outlet of the pilot-scale process. The electrical usage and thermal load (i.e., cooling water and steam inlet and outlet conditions) for the pilot will be monitored continuously.
Approximately two weeks of parametric tests will be conducted to collect pilot-scale data at conditions indicated through process and physical modeling. The heat exchangers responsible for removing heat in the adsorber will be assessed; specifically, the ability of the system to operate isothermally under the design operating conditions will be examined. This step is critical because maintaining isothermal operation in the adsorber is necessary to ensure proper and consistent adsorption rates within the unit. Significant cooling will be required in the adsorber beds due to the highly exothermic reaction between CO2 and the supported amines on the sorbent.
To avoid any condensation, the cooling water will be pumped through the cooling coils after the exothermic CO2 loading of the sorbent has increased the temperature of the system above the flue gas inlet temperature. After the sorbent has been loaded with CO2, the regenerator temperature will be slowly increased via the addition of steam for indirect heating. The temperature of the regenerator will be slowly increased to avoid exposure of the sorbent to high O2 concentration at high temperature, which could lead to oxidation of the amines. The steam usage will be continuously measured and, before increasing the regeneration temperature, the successful performance of the heat exchanger in the fluidized bed regenerator will be confirmed. Once the regenerator temperature is above approximately 70°C the CO2 laden sorbent will begin to regenerate and, therefore release CO2. However, the working CO2 capacity is likely to be unacceptably low at this regeneration temperature as shown in isobars in previous publications [4]. The system will be allowed to achieve steady-state operation; after the CO2 mass balance has been closed, the regeneration temperature will be slowly increased. The system will then be allowed to reach steady-state conditions again at several different regeneration temperatures. The regenerator temperature will be increased until 90% CO2 capture is achieved or 120° C gas temperature has been reached. There are several key operating parameters that can be varied to ensure that 90°% CO2 capture is attained, including:
• Ads orption temperature
• Regeneration temperature
• Sorbent circulation rate
• Bed height in each of the staged fluidized beds - this can be used to control where the CO2 removal is occurring in the system
The optimal operating conditions will be identified prior to initiating the continuous performance-testing period. The continuous testing subtask is designed to obtain sufficient operational data on removal efficiency over 30 days of continuous operation to determine if there is degradation in the CO2 removal performance of the sorbent and to monitor process parameters such as temperatures, pressures, and sorbent attrition rates. The 1 MW pilot will be started at the optimal conditions identified during the parametric testing. Once the condition of 90% CO2 capture has been achieved, the operating conditions will remain unchanged throughout the duration of the test, unless the onsite team decides that another set of conditions would be superior based on heat duty, pressure drop, etc. The quality of the concentrated CO2 stream will be monitored during continuous testing for impurities and moisture content. Potential co-benefits for other pollutants will also be evaluated during the continuous performance phase.
A third party will conduct an independent process evaluation data collection effort. It will consist of a comprehensive gas, solid, and liquid sampling effort to document all of the inputs and outputs of the process. The testing will be conducted at optimum design conditions and last approximately one week. Measurements will include emissions of major and trace constituents, quality of the CO2 produced, composition and quantification of feed and bleed streams, and thermal and electrical energy use. An external contractor will be used for the data collection effort.
Completion of pilot scale testing is necessary to validate the temperature swing process for solid sorbents utilizing fuidized bed technology. While initial cost estimates can be made, they are subject to assumptions that may prove to be invalid.
4. Cost Analysis and Technology Discussion
There are multiple methods to assess the potential cost impacts of post-combustion CO2 capture for coal fired power plants. In order to provide an equitable basis for comparison, it is instructive to use the methodology outlined in DOE base cases 10 and 12 for sub-critical and super-critical boilers. While assumptions and conditions outlined in this model may not be ideal for all processes, they provide a necessary framework to compare multiple technologies on the same basis. As a result, ADA performed a Case 10 and 12 style analysis to determine a general overview of cost sensitivities that may be applied to post-combustion CO2 capture solid-sorbent technology in order to focus on potential process improvement priorities.
4.1 DOE Case 10 Subcritical Pulverized Coal Analysis
Just as with an MEA system in Case 10, in this cost estimate, it is readily apparent that an increase in the levelized cost of electricity (LCOE) will greatly exceed the 35% increase in LCOE that was an initial goal for the DOE CCS programs. In examining the costs associated with the Case 10 analysis, it is clear that variable operating costs, fuel costs, and capital costs dominate the LCOE impact associated with solid-sorbent PCCC technology in Error! Reference source not found.. The fuel costs are a result of increased fuel necessary to provide steam for the temperature-swing process as well as run additional ancillary equipment. The capital costs are dominated by the cost associated with building the PCCC facility and additional gross power capacity required to achieve an equivalent net power output with PCCC. The costs associated with variable operating costs are dominated by sorbent attrition and the need to replace sorbent after it degrades in the process. The degradation rate of the sorbent
Figure 4. Relative contributions to LCOE in a subcritical steam cycle coal fired power plant utilizing solid sorbent PCCC technology
Contributing Cost Factors to CCS
is currently unknown, and clearly has a substantial impact on LCOE. If the sorbent proves to be very resistant to attrition, the LCOE will be reduced and operating costs will no longer be as significant an impact to LCOE.
Due to the significant uncertainties in sorbent attrition prior to testing and the importance of this parameter on LCOE, it is difficult to assess an LCOE for solid sorbent PCCC with a high degree of certainty. Preliminary estimates indicate that costs within 10% of costs typically associated with MEA sorbents in a Case 10 equivalent analysis. This is well within the uncertainty range of these types of preliminary estimates, so it is not possible to draw any conclusion with costs beyond the fact that they are expected to be competing technologies.
4.2 DOE Case 12 Supercritical Pulverized Coal Analysis
As with the Case 10 analysis, the Case 12 analysis also indicated a substantial increase in LCOE as a result of PCCC technology. While the LCOE of electricity is expected to be lower with a supercritical steam cycle boiler, the margins are well within the expected 30+% error range typical of this type of initial assessment. However, notable results were extracted from the exercise. As was the case with the Case 10 analysis, operating costs, capital costs, and fuel costs dominated the relative contributions to increased LCOE compared with a plant without PCCC as shown in Figure 5.
With the increased efficiency of a supercritical steam cycle, the plant increases efficiency, however operating costs and fuel costs and capital costs retain very similar proportions of cost impact associated with the increase in LCOE as a result of PCCC implementation. This suggests that process improvements will have similar impacts for reducing costs associated with a retrofit to a subcritical steam cycle boiler as well as new plant construction with a modern supercritical steam cycle.
Cost Contributing Factors to CCS Case 12
Figure 5. LCOE relative impacts ofsolid sorbent PCCC technology.
4.3 DOE Case 12 Supercritical Pulverized Coal Analysis for Partial Capture
The EPA recently proposed limits for new coal fired power plants capped at 1,100 lbs (499 kg) of CO2/MWhr. This corresponds to a CO2 capture rate of 44%% for a Case 12 analysis, which may not be practical or economical for competing technologies. Unlike an oxy-fuel or integrated gasification combined cycle unit, In practice, additional capability of 50+% CO2 capture would likely be designed into a plant to ensure compliance at all times with the rule. As a result, using a Case 12 style analysis, partial capture with MEA or solid sorbents would still impose a 40-50% increase in LCOE compared with an equivalent plant without capture. As a result, such a plant will need significant public support to be cost competitive with a natural gas combined-cycle plant that is not subject to PCCC requirements.
5. Solid Sorbent and MEA Discussion
Solid sorbents are still a technology that is under development. While there are certainly still opportunities for improvement in MEA systems, the overall technology is much more mature with decades of previous experience. Thus, initial estimates that provide similar cost impacts on an equivalent design basis using DOE Case 10 and 12 methodology, indicates that solid-sorbent PCCC technology should continue to be developed. Process improvements such as a cross heat exchanger to recover sensible heat from the sorbent and reduce the energy associated with solid-sorbent PCCC technology are also currently being investigated.
The uncertainty in cost analysis also highlights the need for rigorous testing at scale with solid sorbents, so that high-confidence cost comparisons can be made with MEA systems that have undergone significantly more scrutiny. The pilot testing of the ADAsorb™ solid sorbent PCCC is a critical step in terms of validating process parameters and increasing confidence in process design.
In addition to potential process improvements to reduce costs, solid-sorbent PCCC technology also has several advantages over an MEA system, which may be difficult to quantify as emissions considerations may vary regionally. However, with solid-sorbent systems the following benefits are expected:
• Eliminate solvent water usage
• Reduced effluent discharge
• Reduced evaporative amine emissions
• Reduced cooling water requirements
6. Conclusions
Overall, ADA continues to develop solid-sorbent technology in order to better understand applicable costs of solid-sorbent and competing PCCC technologies. The initial results of cost estimates indicate that additional process improvements, such as heat integration, will be necessary to reduce costs. Also, the cost assessments have indicated that the pilot testing campaign for the Fall 2014 should focus on ways to make robust estimates on costs concerning capital equipment, operating costs, and efficiency, as these are the most important aspects of LCOE impact.
For these reasons, and the possibility of addressing potential waste water and emissions advantages compared with MEA systems, ADA continues to pursue solid sorbent investigation and development to better characterize the potentials of the technology.
Acknowledgements
Acknowledgements and Reference heading should be le ft justified, bold, with the first letter cap italized but have no numbers. Text below continues as normal.
The work discussed in this manuscript includes work completed under a cooperative agreement (DE-FE0004343) funded by the U.S. Department of Energy National Energy Technology Laboratory's Carbon Capture Program, the Electric Power Research Institute, Southern Company, Luminant, and ADA Environmental Solutions.
References
[1] IEA, Clean Coal Roadmaps to 2030, CCC/152, September 2009.
[2] IPCC, AR5, Working Group III, April, 2014
[3] US DOE NETL, 2010: Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2, DOE/NETL-2010/1397, November 2010
[4] Krutka, et al., Post-Combustion CO2 Capture Using Solid Sorbents: 1 MWe Pilot Evaluation. En. Proc. 2013;37:73 -88.
