It is important for power plants to be able to operate flexibly to respond to changes in consumer demand for electricity. Flexibility is also becoming increasingly important due to the greater use of other low carbon generation technologies, particularly variable renewable generators. The issue of operating flexibility of power plants with carbon capture and storage (CCS) has been the subject of a previous technical study by IEAGHG (“Operating flexibility of power plants with CCS, IEAGHG report 2012/6, June 2012”, see here: http://www.ieaghg.org/docs/General_Docs/Reports/2012-06%20Reduced.pdf). The new report contributes to the knowledge base on flexible operation of power plants with CO2 capture by focusing on process control issues.
A team from Imperial College London and Process Systems Enterprise has undertaken this work for IEAGHG.
The study focuses on performing an evaluation of process control strategies for normal, flexible and upset operation conditions of CO2 post-combustion capture (PCC) processes based on solvent scrubbing. PCC is currently the leading near-term technology for large-scale deployment of CO2 capture in the power generation sector. The aim of this study was to develop process control strategies PCC, to select appropriate control variables, and to design efficient control structures for operation with minimum energy requirements and costs for both pulverised coal (PCPP) and combined cycle gas turbine (CCGT) power plants.
The key messages from the report are:
- Electricity market models suggest power plants with CCS will need to adopt flexible operation in the future. Appropriate control strategies will be necessary to ensure their ability to operate in such a market and their profitability.
- An evaluation of process control strategies for normal, flexible and upset conditions of PCC processes (considered the leading technology for deployment in the power sector) based on amine scrubbing has been undertaken.
- This work used a high-fidelity modelling tool that can describe the dynamic operation of the CCS chain to investigate 3 different process control strategies for both PCPP and CCGT, each with PCC.
- The power plant modelling showed the performance of the CO2 capture unit can be maintained even during periods of significant load fluctuation, using industry standard control techniques, thus avoiding other more expensive solutions.
- Manipulating the solvent flow rate generally provided better control of the CO2 capture rate than varying the solvent lean loading, as it results in less oscillation, i.e. more constant hydraulic conditions in the CO2 capture plant.
- For the PCPP, a control strategy that manipulates the CO2 capture rate by varying the solvent flowrate is the more profitable option. For the CCGT, all strategies provided the same benefit, due to the dilute nature of the CCGT flue gas.
- The CO2 capture plant was able to continue operation for a limited amount of time, i.e. 3.5-5 hours, in case of hazardous events, such as injection shutdown or loss of compression.
- In conclusion, this study has shown that simple and well-tuned control strategies can maintain critical operational parameters of a CO2 capture plant.
The UK has funded a research network of universities focused on research on CCS, called the UK Carbon Capture and Storage Research Consortia (UKCCSRC). IEAGHG are not directly involved in the UKCCSRC activities and research but we do interact on a regular basis. One such interaction involves feeding in the results from our recent Capture Cost Reduction study (funded directly from the UK Department of Energy and Climate Change) into a workshop organised by UKCCSRC on PCC (post combustion capture) cost reduction. The UK has a commercial development plan for CCS that involves a first phase of demonstration projects (two projects are in the current competition; White Rose and Peterhead), a second phase building on Phase 2 with more limited Government support is then planned, with a fully self-supported Phase 3 programme envisioned for 2025 -2030 onwards.
A pre-meeting seminar was organised that involved IEAGHG, SaskPower, SSE and EoN to look at cost reduction opportunities for PCC. The discussion focused first on what a Phase 2 project might involve in both the UK and Saskatchewan. It was agreed that a Phase 2 project would build upon experience from Phase 1. IEAGHG’s study was then considered which reduced the technology options for Phase 2 to new solvents that would be compatible with existing amine based capture technologies. More radical new technologies that involved major engineering work were not considered as these would slow the delivery of the Phase 2 projects. The companies involved considered that risk minimisation was a priority so nothing that had not been tested at a TCM type scale would be considered in Phase 2 & 3. For the UK it was considered that the next phase of projects would likely focus on NGCC with CCS. There was concern that, based on the experience from Kingsnorth, that a coal fired CCS project might face opposition and face delays, if not cancellation. In the UK any new CCS plants would need to be cost competitive with offshore wind.
For Saskatchewan the situation looks different to that of the UK. The decision on Boundary Dam 4 & 5 will focus around the need to meet current regulations, i.e. 420 CO2/kwh, then <90% capture would be needed. SaskPower have a proven business model for a coal fired CCS plant which they will follow for future projects. The competitor in Saskatchewan for coal/CCS is wind, balanced by natural gas. There is some consideration that wind alone is suitable but Max Ball (of SaskPower) stressed that the public need better informing that to balance the variability of wind you will need gas fired generation to smooth out production and demand.
Max Ball indicated that in their estimates new solvents that use less steam and smaller absorbers will reduce costs but not as significantly as could be expected. Cost reduction at Boundary Dam in Phase 2 will come from reducing equipment redundancy, reducing over engineering within the BD3 design and reducing ancillary costs like water treatment. He felt that after several years of monitoring at BD3 they will be able to categorically prove that the gold plated water treatment system at BD3 will prove superfluous.
The outcomes on the options for PCC cost reduction for phase 2 and 3 power generation based CCS projects were:
- Better compatible solvents
- Waste steam treatment
- Flue gas treatment requirements (coal/gas different)
- Solvent management
- Water management
- Automation of analytics
- Automation of control
- Sale of products
- Making money in the market by appropriate plant operation
This outcome might surprise people but they do focus the mind that a fast trajectory path to CCS deployment without Government support does lock you into the capture technologies that are already tested scale otherwise project developers will consider the project as too risky.
1Test Centre Mongstad, Norway
Post combustion CO2 capture technology is one of the potential technologies which will most likely to be applied at large scale CO2 capture facilities in power plants. One of the main concerns for the solvent based CO2 post combustion capture (PCC) technology for power plant is the relatively large energy penalty. A reduction in energy penalty for solvent based CO2 post combustion capture process can be achieved by improving solvent properties, better integration with power plant as well as by improving process design. Regarding to the improvement in process design, different process flow sheet modifications have been reported in various literature and patents for chemical solvent based CO2 absorption processes. These process modifications reduce the energy penalty imposed by the CO2 post combustion capture plant.
The proposed process flow sheet modifications are multi-component column, inter-stage temperature control, heat integrated stripping column, split flow process, vapour recompression, matrix stripping and various heat integration options. Comparison of these reported modifications was difficult as these were evaluated based on different solvent properties and process conditions. Also there are some process modifications more suitable for particular solvent than the others. In order to identify the suitable process modification for full scale PCC application it was necessary to evaluate further in detail these modifications on the same process condition for their energy savings, additional unit required and additional cost.
Therefore, there was a requirement to evaluate these process modifications on similar solvent and process conditions with a state of the art rate-based CO2 absorption model. This IEAGHG study evaluate the feasibility of these different amine-based CO2 post combustion capture process modifications for coal and natural gas based power plants.
In this study post combustion capture process improvements that are already well established such as intercooling in the absorber and improved heat integration with power plant, combined with improved solvents typical of those that are expected to become available by 2020, is implemented for the coal and natural gas power plant base case. These improvements should substantially reduce the efficiency penalty on power plant. Further in this study various process modifications were investigated for coal and natural gas power plants.
Overall it can be noticed from this study that once all current improvements have been implemented in the solvent based post combustion capture process, different process modifications for coal and natural gas power plant, only bring slight improvements in the power plant efficiency penalty.
The performance and cost of different post combustion capture process modifications depend on the type of solvent used. Therefore, for new solvents further evaluation for all process modifications will be required.
We recently published an article on biomass with CCS (bio-CCS or BECCS) in the journal of the Institution of Environmental Scientists (IES). The February issue “The Energy Trilemma” provides a detailed look at the energy mix in the UK and how legal reform and international policies will affect energy production in the future, with case studies on renewable energy generation initiatives across the UK.
In our article, we summarise the findings of IEAGHG’s recent studies on the global potential of bio-CCS and the accounting of negative emissions. Bio-CCS is one of the few negative emissions technologies because capture and long-term storage of the CO2 emissions from biomass combustion and decay effectively result in net removal of atmospheric CO2. Potential benefits include compensation for historical emissions and the ability to reduce the overall costs of climate change mitigation.
Bio- CCS shows significant potential to reduce GHG emissions by 2050. The main drivers, or barriers, are the price of CO2 and the price and availability of sustainable biomass. Setting an incentive or a reward for bio-CCS remains a task for policy-makers, and it will be a complex and challenging one. If policy-makers and regulators do not accurately address sustainability concerns, like land use change, the credibility of negative emissions claims could suffer, especially as bioenergy crops are competing for land with food production and for storage resources with other CCS technologies.
Download the journal on the IES website
The dehydration step is a small part within the full CO2 capture and storage chain yet this unit plays an important role in maintaining the integrity of the system. In the past, this step usually appeared as a black box process, with little information available on its detailed design. However, the conventional drying technologies face a number of challenges that need consideration before full-scale deployment.
IEAGHG commissioned AMEC to carry out this study in order to examine the characteristics of the various drying processes and their integration into the CCS system. This work evaluates dehydration processes that are able to reach water contents ranging from 600ppmv down to <10ppmv. It considers a range of flow rates, constraints on the dehydration pressure and the range of other substances in the CO2 gas.
Key messages from the report:
- A number of suitable technologies for CO2 dehydration exist. This study focusses on a comparison of molecular sieve and triethylene glycol (TEG) systems.
- Consideration of multiple dehydration technologies in series can be beneficial, e.g. a more basic technique can offload the main dehydration unit resulting in cost reduction.
- It is possible to protect dehydration systems that are sensitive towards certain impurities against degradation by using guard beds or additional upstream treatment.
- The minimum CAPEX and OPEX for both molecular sieve and TEG systems depend mainly on operating pressure and type of regeneration.
- In case of high inerts, the CAPEX will increase for both molecular sieve and TEG systems.
- Presence of NOx, SOx and H2S leads to a 7% higher CAPEX but no significant difference in OPEX for molecular sieve systems. Currently, it is not possible to evaluate the effect of impurities on the costs of TEG systems.
- Due to commercial confidentiality, the information on costs and operation is somewhat preliminary, fragmentary and uncertain. Re-engagement of dehydration vendors will be a priority for future projects and studies.
Areas requiring further work include the effects of inerts and impurities on physical properties and the development of acid resistant solid desiccants to cater for the impurities present in feed gases. IEAGHG will continue to track research and project activities in these areas.
The deployment of CCS in the energy intensive industries like steel manufacture has been a major talking point since the publication of the first IEA CCS Roadmap. The iron and steel industry is one of the largest industrial sources of CO2. Globally, it accounts for about 6% of anthropogenic CO2 emissions (approx. 1.2 Gt CO2/year). Currently, two main processes dominate global steel production:
- the integrated steel mill in which steel is made by reducing iron ore in a blast furnace and subsequent processing in a primary steelmaking plant (BF-BOF Route); and
- the mini-mill in which steel is made by melting scrap steel or scrap substitutes in an electric arc furnace (EAF Route).
The global steel industry has made significant investment in reducing CO2 emissions mostly by raising their energy efficiency. However, to achieve a reduction of the direct CO2 emissions per tonne of steel produced from BF-BOF route by greater than 50%, CO2 capture and storage is required.
The steel industry through the ULCOS project in Europe is researching a new technological development for iron and steel manufacture. One such technology is the oxy-blast furnace (OBF) which is close to the point of being ready for demonstration. Large scale demonstration is necessary to validate the engineering design and help optimisation of the process.
IEAGHG has now completed a detailed technical and economic analysis of one option for integrating CCS into an integrated steel mill with the next generation an oxy blast furnace technology. The option considered involves the capture of CO2 from the top gas of the oxy-fired blast furnace using MDEA/Pz solvent. This comprehensive analysis is the first publicly available study providing plant level bottom up cost analysis and it is hoped that the framework developed as part of this study can also be used to assess other CCS integration options in the future.
One of the key outcomes of the study is that the deployment of oxy-blast furnace with CO2 capture provides an option where CO2 is centrally captured from the most carbon intensive process of the steel mill. This option could potentially reduce the cost of CO2 capture and could benefit from high coking coal price.
On the other hand, post-combustion capture technology, capturing CO2 from various sources of flue gases within the integrated steel mill is technically possible and could be readily retrofitted to an existing steel mill. However, this study has demonstrated that this option could have significant costs implications on steel production which could affect the commercial viability of the steel plants fitted with CCS.
The steel industry is a globally competitive industry and hence they will be reluctant to introduce cost disadvantages like adding CCS without some global agreement on emissions reduction.
Tuesday 6th May 2013 and as part of our 43rd Executive Meeting we are visiting the Boundary Dam power plant in southern Saskatchewan , Canada. Boundary dams unit 3 is undergoing a major refit with a new boiler and steam turbines being added plus the worlds first full flow post combustion capture unit. Whilst currently under construction they will begin capturing CO2 in October 2013, well ahead of any other CCS demonstration plant in the world.
I guess what struck me the most was the sheer size of the capture facility with its SO2 and CO2 amine scrubbing units using Cansolv technology and the gas compressors unit by Mann Turbo. I remember visiting the University of Reginas pilot at Boundary Dam many years ago and thought that was a piece of kit. Recently I visted Technology Centre Mongstad on its opening and was impressed by the size of the scrubbing tower on the Aker 10MW pilot at Mongstad. However nothing prepared me for Boundary Dam and this is only a 115Mwe unit . The FGD unit is actually slightly smaller than the CO2 absorber tower with the Desorber tower of similar stature all poking out above the building cladding into the sunny skies they are an impressive sight. The single Mann gas compressor was enormous I recall the gas compressors at Dakota gasification there I think they had two to do a much smaller duty. It is a feat of German engineering that Mann Turbo can design with such confidence a single CO2 compressor train for this unit.
I look forward to hearing this plant is operational in October and hope to come back and see it operating in the future. With some trepidation I also look forward to seeing the next scale up of a PCC unit on a 500mw or 660 mew boiler.
From 15th to 18th April 2013 I visited EnBW's amine scrubbing pilot plant at Heilbronn in Germany. After a warm welcome from Dr Sven Unterberger and his team who are operating the pilot plant I was invited to tour the facilities. The Heilbronn Combined Heat and Power Plant has a total electric output of 1010 MWel and also supplies 320 MWth for district heating. The boilers are equipped with state-of-the-art flue gas treatment systems such as DeNOx, ESP and wet FGD.
A flue gas slip stream of 1500 Nm3/h (representing about 0.05 % of the total flue gas volume of Unit 7) is taken downstream of the FGD and passed on to the CO2 capture plant, which is designed to capture 300 kg CO2/h (or 7.2 t CO2/d) at a capture rate of 90 %. The pilot plant was constructed by German engineering company atea Anlagentechnik GmbH as an "IP-free" design and started operation on 1st March 2011. The layout includes a pre-scrubber that cools the flue gas to about
30 °C and reduces the SO2 concentration to a minimum by adding NaOH. Both the pre-scrubber and absorber are made of polypropylene and contain random packing of polypropylene. Due to structural requirements the absorber, which has a total height of about 40 m, is reinforced with glass-fibre plastics. The desorber in contrast is made of stainless steel with a random packing of stainless steel as well.
During my stay there was a test campaign with 30 % MEA as a solvent in order to investigate the performance of the capture plant under different loads and dynamic load change conditions of the power plant. Another important issue that has been examined in parallel is the degradation of the solvent. In a preceding test campaign a sudden increase in inorganic and organic acid anions as well as dissolved metals after about 900 hours of operations was observed. This was accompanied by a typical discoloration of the solvent that is frequently reported for MEA in the literature. In order to address the solvent degradation issue and minimise the concentration of degradation products EnBW is currently testing different reclaiming technologies at the pilot plant. From this, a solvent management system will be developed and approved.
Results of the first year's testing programme were presented at GHGT-11 and will be soon published in the conference proceedings Energy Procedia.
For further information on the pilot plant please contact:
Dr Sven Unterberger
Jasmin and I from the IEAGHG Capture and Integration team attended a course on 'An Introduction to the options for Power Generation' at E.ON Engineering Academy, Ratcliffe-on-Soar Power Station on 8-12 April 2013. This course focuses on developing understanding of various power generation options available in the current economic and environmentally conscious climate. The course was given by very experienced and knowledgeable Mr G. Tonge, who has worked several decades at E.ON in different areas of coal, gas and nuclear power generation. The course covers technical and operation details of different type of power generation technologies such as coal, gas, nuclear, combined heat and power, wind, hydro, biomass, solar, geothermal, wave and tide. Moreover during this course topics related to UK electricity market, environmental considerations, economics and plant choice were also covered. I have personally found this course very useful in developing in depth understanding on power plant operation and the electricity market.