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Cryogenic Carbon Capture™ as a Holistic Approach to a Low-Emissions Energy System

By Larry Baxter
Cofounder, Sustainable Energy Solutions (SES)
Professor, Chemical Engineering, Brigham Young University

Reducing global carbon emissions requires a a diverse portfolio of low-emissions technologies, including renewable energy and carbon capture and storage (i.e., CCS and CCUS).1,2 Without using the full portfolio of low-emission options, the costs for reducing global emissions will be higher and the probability of successful climate change mitigation decreases. Each technology, however, faces its own set of challenges. For example, although the deployment of renewables has accelerated in recent years, the issue of intermittency remains a major challenge. Similarly, CCS is lagging behind the projected amount of demonstration projects needed. Sustainable Energy Solutions (SES) has developed a low-cost, integrated energy storage and CO2 capture technology, called Cryogenic Carbon CaptureTM (CCC), that can help address the major challenges faced by renewables and CCS.

THE CCC TECHNOLOGY

The foundation of the CCC process relies on refrigeration to cryogenic temperatures, rather than a chemical reaction, to separate CO2 from flue gas from a power plant or industrial source. Typically, refrigeration cycles consume large amounts of energy, but this is only true if the final products are at lower temperature than the incoming streams, e.g., air conditioning. While the CCC process relies on refrigeration process principles, the products are at nominally the same temperature as the incoming flue gas, and thus the energy efficiency is much higher than for typical refrigeration processes. For comparison, the energy efficiency of an air conditioner could be similarly high if it delivered air at the same temperature as the outdoor air, which, of course, defeats the purpose for that application. However, since the purpose of the CCC process is to separate CO2 from the other constituents in flue gas, with cooling as only an intermediate step, recuperative heat exchange drives most of the temperature change.

There are two possible implementations of the CCC process. Figure 1 illustrates the major process steps of the external cooling loop (CCC-ECLTM) version, which is the implementation that enables large-scale energy storage. Alternatively, the compressed flue gas (CCC-CFGTM) version of the process differs from the ECL version in that it does not include an external refrigeration loop but rather uses the flue gas as its own refrigerant. This article focuses on the ECL process to highlight the opportunity to meet the dual challenge of CCS deployment and energy storage; more information on the CFG process is provided elsewhere.3–5

FIGURE 1. Simplified flow diagram of the CCC-ECL™ process

FIGURE 1. Simplified flow diagram of the CCC-ECL™ process

CO2 Capture

The flue gas enters the capture system and cools in a series of heat exchangers until it reaches a temperature at which the CO2 freezes to form a nearly pure solid that separates easily from the remaining gases. The process pressurizes the solid CO2 to force out all the gases from between the solid particles. Two separate streams exist at this point in the process: the pressurized solid CO2 stream and the CO2-lean flue gas stream at ambient pressure. Both streams warm to ambient temperature by cooling the incoming gases in recuperative heat exchangers. These recuperative heat exchangers are important because they accomplish most of the sensible cooling in the process. As the solid CO2 warms, it melts to form a liquid. The process delivers a liquid stream of nearly pure CO2 at 150 bar and a gas stream at atmospheric pressure, with both streams near ambient temperature. This process can capture more than 99% of CO2 from a large-point source emitter. One substantial advantage of this approach is the ease with which emission sources can be retrofit. Although the process uses electricity, it does not require the extraction of steam or any upstream modifications.

Simultaneous Emissions Control

As the flue gas cools in a series of heat exchangers (for sim-plicity, only one is shown in Figure 1), most gases other than N2 and O2 condense at component-specific temperatures. Thus, as part of the CO2 capture process, the CCC process also captures SOx, NOx, Hg, HCl, particulate, VOCs, etc. In fact, the CCC process removes all gas constituents less volatile than carbon monoxide (CO), which includes nearly all other currently and foreseeably regulated emissions.

Energy Storage

The CCC-ECLTM process stores energy in the form of cold, condensed refrigerant. If there is excess power from renewables on the grid, the extra electricity generates and stores excess refrigerant. The CO2 capture process recovers this energy in periods of high power demand by increasing the net power plant input, using the stored refrigerant, rather than compressor power, to drive the carbon capture and reduce parasitic losses. Refrigerant generation represents over 80% of the energy required in the CCC-ECLTM process (see Table 1). The same approach allows dispatchable power plants to follow dynamic load without changing steam generation rates or temperatures.

Baxter Table 1

SES has completed detailed transient analyses of the energy storage and recovery processes.7 For example, an 800-MWe power plant can stabilize up to a ±400-MWe swing in power demand on a typical U.S. grid with intermittent wind and dispatchable gas and coal power. The estimated economic benefit of the energy storage exceeds $20/MWh, because the system can utilize energy which would otherwise be curtailed or is generated using low-cost baseload resources during off-peak times.1 The process also largely decreases the need for spinning reserve and other high-cost backup systems. The value of the energy storage nearly equals the carbon capture cost in many markets.

PROJECTED PERFORMANCE AND ECONOMIC COMPARISONS

Economic analysis completed by SES, based on application of the technology in the U.S., indicates that, even without considering the economic advantages of energy storage, the CCC process is more efficient and cost effective than leading alternative approaches to CO2 capture.

SES has completed quantitative estimates for the energy consumed by its CCC processes and compared them to that of a post-combustion liquid amine CO2 capture system. The results based on the CFG and ECL systems appear in two forms: a bolt-on version and implementation with some integration. The bolt-on versions consume about 0.71 GJe/tonne of CO2 captured. An integrated system (1) uses a portion of the heat collected in the first condensing heat exchanger to preheat boiler feedwater and (2) reduces the energy demand associated with the control of other emissions (e.g., SOx, NOx, etc.) by capturing them as part of the CCC process. These integration steps reduce the effective energy demand to a little less than 0.6 GJe/tonne of CO2. In both the bolt-on and integrated configurations, CCC is predicted to consume significantly less energy than post-combustion liquid amine-based CO2 capture (see Figure 2).

FIGURE 2. Estimated parasitic load for amine6 and CCC capture processes

FIGURE 2. Estimated parasitic load for amine6 and CCC capture processes

The primary sources of energy savings compared to liquid amine systems come from two factors: (1) the CCC process does not require large thermal swings or recycling materials (e.g., water and amine in the liquid amine CO2 capture process, distillation reflux in oxyfuel systems, etc.) and (2) the CCC process pressurizes the CO2 in a condensed phase, rather than as a gas. Condensed-phase compression requires far less expensive equipment and far less energy than gas compression.

While the parasitic energy is a major component of costs, the economics of all CO2 capture processes also depend strongly on financing and capital costs. To provide some means of comparison with other technology options, SES obtained vendor quotes for major equipment and otherwise made stride-for-stride identical assumptions and used the same software (to the greatest extent possible) as used in detailed cost estimates provided by the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) (see Figure 3).6

FIGURE 3. Incremental increases in the cost of electricity relative to a non-capture supercritical (SC) plant for an amine system6 and for CCC with varying degrees of integration. The bars represent estimated cost of electricity for a new SC coal plant with no carbon capture, a new SC plant with 90% capture via aqueous amines, a new SC plant with 90% capture by CCC, the cost of power for an existing plant with paid-off capital (i.e., most existing plants in the U.S.), and cost of power from an existing SC plant retrofitted with CCC. The first two of these bars are based on results published by NETL6 and the others are SES results using the same assumptions.

FIGURE 3. Incremental increases in the cost of electricity relative to a non-capture supercritical (SC) plant for an amine system6 and for CCC with varying degrees of integration. The bars represent estimated cost of electricity for a new SC coal plant with no carbon capture, a new SC plant with 90% capture via aqueous amines, a new SC plant with 90% capture by CCC, the cost of power for an existing plant with paid-off capital (i.e., most existing plants in the U.S.), and cost of power from an existing SC plant retrofitted with CCC. The first two of these bars are based on results published by NETL6 and the others are SES results using the same assumptions.

In all configurations, the CCC CO2 capture cost estimates per unit of electricity fall well below those of leading alternatives. The CCC processes are predicted to increase electricity costs by about 2.5 ¢/kWh, possibly much less if the processes are fully integrated and/or the energy storage option is used.4 The energy storage, as previously discussed, might provide up to 2 ¢/kWh of additional savings, which is close to the total CO2 capture cost for the fully integrated systems.8 For context, the average U.S. residential retail electricity price is about
13 ¢/kWh.

DEVELOPMENT STATUS AND CHALLENGES

SES has built and successfully tested the CCC-CFGTM and CCC-ECLTM versions of the process at lab, bench, and skid scales up to 7–8 tonnes of flue gas/day (1 tonne of CO2 per day). The largest of these test systems occupies two shipping containers and is mobile. Field tests have included flue gas slipstreams from subbituminous coal, bituminous coal, biomass, natural gas, municipal waste, tires, and blends of these fuels. These field tests occurred at utility-scale power plants, industrial heat plants, cement kilns, and pilot-scale reactors. SES is actively seeking technology partners capable of constructing the equipment for the next two phases of the project: a 5-MWe equivalent (100 tonnes/day of CO2) pilot plant and ultimately a 150–200-MWe demonstration plant.

CCC-ECLTM process test skid

CCC-ECLTM process test skid

Several of the essential components of the CCC processes are in commercial use in the power and other industries. Examples include the condensing heat exchanger, many of the intermediate heat exchangers, slurry and cryogenic liquid pumps, dryers, and water treatment facilities. The primary equipment that is not currently available commercially, and thus the focus of current and future technology development efforts, includes cryogenic solid-fluid separations equipment and desublimating heat exchangers that continuously process solids-forming streams without fouling or plugging.

The remaining challenges in the scale-up of the CCC technology include assessing potential long-term issues with construction materials and engineering details related to solids handling at large scale. Water purification, multi-pollutant handling, and other process steps also still require demonstration, but should be manageable using currently available commercial technologies.

CONCLUSIONS

The CCC-ECL™ process affordably reduces emissions from fossil-fueled power plants while enabling more and better use of renewables on the grid. The CCC process offers major advantages over alternative capture technologies, including lower energy consumption, lower costs, optional energy storage, easier retrofit, lower water use, and optional criteria emission control. Based on its multiple advantages, the CCC process could become one of the most strategically important components of a low-carbon power industry.

REFERENCES

  1. International Energy Agency. (2013). Technology roadmap: Carbon capture and storage 2013, www.iea.org/publications/freepublications/publication/technology-roadmap-carbon-capture-and-storage-2013.html
  2. Intergovernmental Panel on Climate Change. (2014). Climate change 2014: Mitigation of climate change. Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Available at: www.ipcc.ch/report/ar5/wg3/
  3. Safdarnejad, S.M., Hedengren, J.D., & Baxter, L.L. (2015). Plant-level dynamic optimization of Cryogenic Carbon Capture with conventional and renewable power sources. Applied Energy, 149, 354–366.
  4. Jensen, M.J., Russell, C.S., Bergeson, D., Hoeger, C.D., Frankman, D.J., Bence, C.S., & Baxter, L.L. (2015). Prediction and validation of external cooling loop cryogenic carbon capture (CCC-ECL) for full-scale coal-fired power plant retrofit. International Journal of Greenhouse Gas Control, 42, 200–212.
  5. Sustainable Energy Solutions. (2015). Our technology, www.sesinnovation.com
  6. U.S. Department of Energy, National Energy Technology Laboratory. (2013). Cost and performance baseline for fossil energy plants, volume 1: Bituminous coal and natural gas to electricity, www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/OE/BitBase_FinRep_Rev2a-3_20130919_1.pdf
  7. Fazlollahi, F., Bown, A., Ebrahimzadeh, E., & Baxter, L.L. (2015). Design and analysis of the natural gas liquefaction optimization process-CCC-ES (energy storage of cryogenic carbon capture). Energy, 90, 244–257.
  8. Safdarnejad, S.M., Hedengren, J.D., & Baxter, L.L. (2015). Plant-level dynamic optimization of Cryogenic Carbon Capture with conventional and renewable power sources. Applied Energy. 149, 354–366.

The author can be reached at l.baxter@sesinnovation.com and additional technology details can be found at www.sesinnovation.com

 

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Learning From Positive Outcomes on Land Reclamation

By Holly Krutka
Executive Editor, Cornerstone

As this issue of Cornerstone goes to press, world leaders are meeting in Paris, France, for the COP21 negotiations under the United Nations Framework Convention on Climate Change. Momentum for the meetings has long been building, and future issues of Cornerstone will cover the outcomes, as they pertain to the coal industry and the broader energy community. As we have done in the past, we will continue to focus on policy approaches and technologies—including high-efficiency, low-emissions (HELE) coal-fired power plants and carbon capture, utilization, and storage—which enable coal utilization in a carbon-constrained world.

Krutka Headshot

While the significance of reducing emissions is not easily overstated, the environmental footprint of energy production and utilization is far from limited to greenhouse gases. For example, working with local communities and governments to ensure mined land is successfully reclaimed is a process that may not garner the same amount of attention as climate change mitigation, but to those living near mines it can cut at the heart of sustainable energy. Thus, in this issue of Cornerstone, we are highlighting lessons learned and international best practices in reclamation projects—principally from opencast mines. For countries currently growing their coal production, the decades of experience gained in reclamation efforts around the world could help leapfrog standard learning cycle time requirements to enhance reclamation practices.

Reclamation often begins while coal is being actively mined elsewhere at the same site. Such an approach minimizes the footprint of an opencast mine at any given time. Prior to the first excavation shovel, successful reclamation requires soliciting input from local stakeholders and ecology experts. Identifying any plant or animal species at risk, planning for drainage, and defining the optimal end use for the land are key first steps that are site specific. For example, as highlighted in this issue, while the western U.S. may use reclaimed land for livestock grazing, in the Czech Republic, which has recently announced that it is increasing limits on lignite production, nature preserves are a good fit. In cases such as the Czech Republic, spontaneous reclamation—allowing nature to do the work—has demonstrated ecological value.

Positive reclamation projects require an understanding of the local ecology and the risks posed by mining and other associated activities. Protection of the sage grouse in the western U.S. is an important success story of how mining companies have worked with local governments and environmental experts to minimize impact. As this issue of Cornerstone was being prepared, the U.S. Fish and Wildlife Service announced that the sage grouse would not be added to the endangered species list—a positive result for the bird and also the stakeholder groups that have been working to operate mines without affecting it unduly.

As global leaders negotiate on climate change mitigation, there may well be lessons on collaboration and commitment to the environment that can be gleamed by considering decades-long reclamation efforts. On behalf of the editorial team, I hope you enjoy this issue of Cornerstone.

 

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What Will It Take for CCS to Have a Future in the European Union?

By Samuela Bassi
Policy Analyst, Grantham Research Institute
on Climate Change and the Environment,
London School of Economics and Political Science

Carbon capture and storage (CCS) can play a considerable role in tackling global climate change. By capturing CO2 and storing it underground, CCS allows coal- and gas-fired power stations to produce low-emissions electricity. Furthermore, it is the only technology that can reduce carbon emissions from large industrial installations, such as steel and cement plants. If successfully applied to bio-energy generators, CCS technology could also result in “negative emissions”, that is, it could actually remove CO2 from the atmosphere.

For these reasons CCS is included in a wide range of authoritative energy models forecasting future low-carbon energy portfolios, including models developed by the International Energy Agency (IEA)1 and those included in the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (IPCC).2 Most analysts agree that it may be much more expensive, if not infeasible, to limit warming to 2°C without CCS.

The case for CCS is also strong in the European Union. All the scenarios developed in the EU’s Energy Roadmap 2050, which aims to reduce emissions by 80–95% below 1990 levels by 2050, involve using CCS.3 According to these scenarios, CCS should be applied to between 7 and 32% of electricity generation in the EU by 2050.

To achieve the emission reductions outlined in the Energy Roadmap 2050 scenarios, CCS must be deployed in Europe from 2020 onward. However, momentum for CCS on the continent appears to have dwindled, and progress has been painfully slow.

A recently published study by the Grantham Research Institute at the London School of Economics and Political Science and the Grantham Institute at Imperial College investigates the barriers to CCS development in the European Union and recommends a European-wide strategy to speed up investment.4 This article shares key findings from that study.

The full report by the Grantham Institute on Climate Change and the Environment investigates barriers to CCS in the EU.

The full report by the Grantham Institute on Climate Change and the Environment investigates barriers to CCS in the EU.

SLOW DEVELOPMENT OF CCS IN THE EUROPEAN UNION

Although no explicit target has ever been enforced, the European Council did once aspire to have up to 12 CCS demonstration projects operating by 2015.5 Despite this, the pace of CCS development in the European Union has been very slow. Not a single CCS plant is even in construction in the EU. By comparison, North America already has 13 CCS installations in operation and six under construction (see Figure 1).

FIGURE 1. CCS installations in operation by sector and country, 20144,6,7

FIGURE 1. CCS installations in operation by sector and country, 20144,6,7

This does not mean that efforts have not been made by some EU member states. Six CCS plants are now at various stages of planning, five of which are in the UK with the other one being in the Netherlands. It remains unclear how many of these projects will secure enough financing to be fully realized. At the moment only two of them—the White Rose and Peterhead projects in the UK—are relatively close to a final investment decision, but the outcome is not certain. Notably, last September the White Rose project lost the support of one of its three commercial bakers, Drax Group PLC, allegedly due to a recent cut in low-carbon energy subsidies in the UK.

The White Rose project in the UK is one of two CCS projects advancing in the country. (Credit: Capture Power)

The White Rose project in the UK is one of two CCS projects advancing in the country. (Credit: Capture Power)

WHY IS CCS LAGGING BEHIND?

High upfront costs present the biggest barrier to the widespread use of CCS. While the technology is well understood, it is still far too expensive to be commercially competitive with unabated coal- and natural gas-fired power stations.

Based on the current cost of CCS technology, between €18 billion and €35 billion may need to be invested by 2030 in the EU to deliver the 10 GW of CCS power plants with CCS envisaged by the Energy Roadmap 2050. Just €1.3 billion of public European funding, coupled with some private investment, has been allocated to CCS to date—just a fraction of what is needed to make CCS technology commercially viable.

The costs associated with CCS are expected to decrease over time thanks to technological innovation, economies of scale, and increasingly efficient CO2 transport and storage infrastructure. However, realizing these advancements would require investment in fully operational plants as soon as possible.

There is already much being learned from existing projects. The developers of the world’s first operating CCS power plant, the Boundary Dam project in Canada, claim that they could save up to 30% of the costs building an identical CCS plant today, thanks to the knowledge gained in the course of the project. Other, more theoretical, estimates suggest that costs could decrease by 15–40% by 2030, especially through improvements in CO2 transport and reductions in the cost of financing projects.

The financing of CCS projects is particularly important. Currently, perceived risks surrounding first-of-a-kind CCS projects impair access to suitable finance, raising the cost of capital. UK estimates suggest the cost of capital faced by CCS developers could be in the order of 12–17% (mid-point 14.5%).8 By comparison, the cost of capital faced by more established low-emissions technologies, such as solar photovoltaic or offshore wind projects, is between 6 and 9%.

A simple financial model based on publicly available information from the Boundary Dam CCS power plant shows how different costs of capital can affect the average cost of electricity from a CCS power plant, measured in terms of levelized cost of electricity (LCOE). With a cost of capital of 9.5%, the LCOE would be around £180/MWh. For a cost of capital at 14.5%, the LCOE increases to £240/MWh (see Figure 2).

FIGURE 2. Estimated LCOEs based on the Boundary Dam project and different assumptions on cost of capital4

FIGURE 2. Estimated LCOEs based on the Boundary Dam project and different assumptions on cost of capital4

The policies introduced to support CCS in the European Union have so far failed to deliver the expected results. Notably, the price of carbon in the European Union Emissions Trading System (EU ETS) has been very low and is unlikely to increase to the level required to make CCS competitive with unabated fossil fuel installations.

Notably, the carbon price would need to increase from less than €8 to between €35 and €60/tonne CO2-eq if a coal-fired power station fitted with CCS is to be competitive with conventional coal-fired plants. For gas-fired power stations with CCS to be competitive, the carbon price would need to be even higher, between €90 and €105 per tonne. It is very unlikely that the EU ETS will achieve these levels for at least another decade or so.

Public funding programs have also been set up to support CCS development and deployment, such as the European Energy Programme for Recovery (EEPR) and the New Entrant Reserve (NER) 300. These too, however, failed to deliver strong results. This is partly because funds available through the NER 300 depended on the price of 300 million EU ETS allowances earmarked to CCS, and their selling price ended up being lower than expected. In addition, CCS projects were in competition with other low-emissions technologies for funding. Eventually only one of the 39 projects funded by NER 300 actually involved CCS.

In the coming years, additional financial resources are expected to become available through the new Innovation Fund (or NER 400), the Modernisation Fund, the European Fund for Strategic Investment, and the European Structural and Investment Funds. However, the scopes of these programs are much broader than CCS. It is unclear if, and to what extent, CCS projects will be financed through these channels.

Another challenge faced by CCS developers is that existing regulation imposes significant costs and liabilities on CO2 storage site operators, which discourages investment. In particular, site operators are requested to provide financial coverage for the cost of compensation in case of CO2 leakage. This financial liability is linked to the price of allowances in the EU ETS. The uncertainty over the amount of CO2 that could leak and the future EU ETS carbon price make this liability potentially open-ended.

STRONGER, BETTER COORDINATED POLICY IS NEEDED

The European Commission must provide leadership on CCS if it is to keep on course with its Energy Roadmap 2050. Europe needs an overarching strategy to stimulate much needed action to advance CCS. But what would a strategy on CCS involve?

First, such a strategy should encourage member states to assess their potential for CCS and characterize potential storage sites. It should provide policy guidance, set milestones to measure progress, and coordinate transport infrastructure planning.

Second, the strategy should identify additional market-based mechanisms to mobilize investment in the short to medium term. These would complement existing policies like the EU ETS.

These could include more direct funding for research and development, a new funding mechanism to finance early-stage CCS development projects, and financial incentives for electricity generation using CCS.

Furthermore, improvements to the existing European legislation will be required to allow the first demonstration projects to be developed in a timely manner and to create the right conditions for future investment. A key action would be to set an initial cap on long-term liability for CO2 leakage, to be reviewed as risks become better understood and private insurance mechanisms develop. This is not dissimilar to the way risk has been handled in the nuclear industry. A financial mechanism for damage remediation, such as a liability fund or private insurance, would also help spread risk across CCS site operators. Special treatment of early demonstration projects—for example, through a public liability scheme—would also be warranted, given the higher risks faced by first movers.

THE ROLE OF PUBLIC AND PRIVATE SECTORS

If CCS is to be successfully deployed in Europe, the private sector will also need to act. For instance, large, incumbent energy utilities could be well placed to develop the first CCS projects, as they have the size, experience, and capacity to undertake diversified, large-scale, and complex investments while minimizing many of the barriers and inherent risks to CCS projects.

This is not to say that large-scale energy utilities will find it easy to invest in CCS. In the current economic and political environment they are facing significant funding constraints. Furthermore, CCS project financing has a different risk profile compared to traditional capital-intensive energy infrastructure projects. In particular, the risks associated with construction of CCS installations differ considerably from the risks associated with its operation. Investors may be willing to absorb some of the risks, but the long-term nature of CCS means that risks will endure and can only be managed by private investors to a certain degree.

These complexities highlight a need for the involvement of public financial institutions. For instance, the European Investment Bank (EIB) or the European Bank for Reconstruction and Development (EBRD) could contribute convening power and know-how to attract additional private financing sources.

Upstream producers of fossil fuels—whether privately or publicly owned—should also contribute much more strongly to advancing of CCS in the EU. Ultimately CCS will increase the amount of their assets that can be potentially realized in compliance with climate change targets. It is likely that fossil fuel companies may oppose an additional tax to fund CCS development. However, I believe there is a case for encouraging the creation of a private-sector fund for CCS. These companies’ desire to lower the costs of CCS technologies could be fostered by simple agreement between key players to exploit a shared interest in developing CCS.

CONCLUSIONS

The EU and its member states must show much greater urgency and determination to develop and deploy CCS. Without action now, the EU may be unable to meet its targets for reducing greenhouse gas emissions. Evidence indicates that it will be more costly to meet these targets without CCS.

Thus, there is a strong case for stepping up ambition and action on CCS in the EU. The creation of a European Energy Union provides a timely opportunity to revamp European policy on CCS. The European Commission and the Energy Union, in particular, have a strong responsibility to engage and guide member states, helping them meet their emissions reduction targets at the least cost.

The first CCS installations will require significant public and private resources. This will likely be realized through a mix of higher carbon pricing, subsidies, and increased private investment. Further measures, however, need not be monetary in nature—these ought not to be difficult to implement in the short term. For instance, inviting member states to assess their own potential for CCS, and identifying the cost of alternative routes for decarbonization, may be a sensible first step. This could also lead to the identification of a coalition of countries willing to collaborate more closely on CCS.

At the very least, the European Union needs more certainty about which low-emissions energy technologies warrant investment. If the promotion of CCS is considered politically unfeasible, the EU’s stated expectations for CCS would have to be revised in a timely manner and alternative options should be explored immediately.

Ultimately, the public and private sectors both have a role to play. Within the private sector, the burden of investment in CCS has fallen especially on energy suppliers. However, these companies are not often in a position to invest in large multi-billion projects without sufficient public backing. Other players could be well placed to be more involved, such as upstream producers of fossil fuels. It is time to think about how to scale up investment on CCS, by improving public policy as well as further mobilizing private finance from a multiplicity of actors.

REFERENCES

  1. International Energy Agency. (2012). Energy technology perspectives 2012, pathways to a clean energy system, www.iea.org/publications/freepublications/publication/ETP2012_free.pdf
  2. Intergovernmental Panel on Climate Change. (2014). Summary for policymakers. In O. Edenhofer et al. (Eds.), Climate change 2014, Mitigation of climate change. Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Cambridge, UK/New York, NY: Cambridge University Press. Available at: report.mitigation2014.org/spm/ipcc_wg3_ar5_summary-for-policymakers_approved.pdf
  3. European Commission. (2011). Impact assessment, accompanying the document, Communication from the Commission to the Council, the European Parliament, the European Economic and Social Committee and the Committee of the Regions, Energy Roadmap 2050. Commission Staff Working Paper. SEC(2011) 1565/2 Part 1:2, ec.europa.eu/energy/sites/ener/files/documents/sec_2011_1565_part1.pdf
  4. Bassi, S., Boyd, R., Buckle, S., Fennell, P., Mac Dowell, N., Makuch, Z., & Staffell, I. (2015). Bridging the gap: Improving the economic and policy framework for carbon capture and storage in the European Union. London: Centre for Climate Change Economics and Policy, Grantham Research Institute on Climate Change and the Environment at the London School of Economics and Political Science, and Grantham Institute at Imperial College, www.lse.ac.uk/GranthamInstitute/publication/bridging-the-gap-improving-the-economic-and-policy-framework-for-carbon-capture-and-storage-in-the-european-union/
  5. Council of the European Union. (2007). Presidency conclusions, Brussels European Council 8/9. Brussels: Council of the European Union, www.consilium.europa.eu/ueDocs/cms_Data/docs/pressData/en/ec/93135.pdf
  6. Massachusetts Institute of Technology. (2013). Carbon Capture and Sequestration Project database, sequestration.mit.edu/tools/projects/index_capture.html
  7. Global CCS Institute. (2014, 7 October). Status of CCS project database, www.globalccsinstitute.com/projects/status-ccs-project-database
  8. Oxera. (2011). Discount rates for low-carbon and renewable generation technologies, Prepared for the Committee on
    Climate Change, www.oxera.com/Oxera/media/Oxera/downloads/reports/Oxera-report-on-low-carbon-discount-rates.pdf?ext=.pdf

This article is based on a report by the Grantham Research Institute at the London School of Economics and Political Science and the Grantham Institute at Imperial College, “Bridging the gap: Improving the economic and policy framework for carbon capture and storage in the European Union”, by Samuela Bassi, Rodney Boyd, Simon Buckle, Paul Fennell, Niall Mac Dowell, Zen Makuch, and Iain Staffell. The report is available for download from the Grantham Research Institute website: www.lse.ac.uk/GranthamInstitute/publication/bridging
-the-gap-improving-the-economic-and-policy-framework-for-carbon-capture-and-storage-in-the-european-union/
The lead author can be reached at s.bassi@lse.ac.uk

 

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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Finding Opportunities for CCUS in China’s Industrial Clusters

Zhang Jiutian
Director,
Administrative Center for China’s Agenda 21,
Ministry of Science and Technology (MOST)
Zhang Xian
Associate Professor,
Administrative Center for China’s Agenda 21, MOST
Peng Sizhen
Deputy Director General,
Administrative Center for China’s Agenda 21, MOST

The government of China considers addressing climate change to be of the utmost importance. Therefore, the country is exploring how to best approach low-emissions development through innovation and intends to do so even as it pushes ahead with urbanization and industrialization.

Recently China has placed a major emphasis on the research, development, and demonstration of carbon capture, utilization, and storage (CCS and CCUS), while also promoting energy conservation and reducing criteria emissions. Based on geography, economics, technical considerations, and other factors, the Administrative Center for China’s Agenda 21, responsible for carrying out China’s efforts under the United Nations Agenda 21 plans for sustainable development, has found that there are several optimal opportunities for CCUS in China. The best prospects are focused around pairing key industries responsible for 90% of the country’s emissions from coal use (i.e., coal-fired power, coal-to-chemicals, and steel and cement production) with specific CCUS opportunities to advance low-emissions technology deployment in the country.

Industrial clusters, including China’s growing coal conversion industry, could support the development of a CCUS industry.

Industrial clusters, including China’s growing coal conversion industry, could support the development of a CCUS industry.

CHINA’S ENERGY CHALLENGES

In late June 2015, China officially submitted its Intended Nationally Determined Contributions (INDCs) ahead of COP21. The major commitments include peaking carbon emissions by 2030, while striving to do so sooner, and reducing CO2 emissions per unit of GDP by 60–65%, compared to 2005 levels. These ambitious commitments demonstrate the country’s desire to be proactive on climate change mitigation. They also support domestic efforts to expand investigation and innovation of low-emissions development models and pathways.

When making its international commitments on climate and working to advance low-emissions technologies, China must take into account that it is a developing country with a population of more than 1.3 billion people. Thus, the country must balance sustainable economic development, poverty eradication, urbanization, industrialization, the desire to improve standards of living, limited resources and energy supplies, and environmental protection. In terms of reducing carbon emissions from coal, China has opted to focus largely on CCUS in the near term to provide some revenue and/or co-benefits from low-emissions technology deployment.

Addressing emissions from the coal-fired power sector is especially important, considering that China has large coal reserves with relatively small reserves of oil and natural gas. The country is working to expand deployment of many low-emission energy options, but it is not possible for China to fundamentally change its coal-based energy mix in the near future. Any drastic change in the energy consumption structure would inevitably worsen China’s energy security and would directly and negatively impact economic growth. Based on forecasts, the proportion of coal, oil, gas, and other energy sources (e.g., nuclear power and renewables) in China’s primary energy mix are expected to be 55%, 20%, 10%, and 15%, respectively, in 2020.1 Therefore, low-emissions coal utilization must be developed and deployed in China.

CCUS is also of high interest to China because it can increase domestic production of valuable resources, such as minerals, oil, natural gas, uranium, and water. Thus, CCUS presents a key opportunity to enable cross-industry collaboration to form a framework for an emerging low-emissions industrial structure, thereby balancing China’s development and environmental objectives.

THE STATUS OF CCUS IN CHINA

The international community, especially developed countries, has also been increasingly interested in CCUS. In addition to the emissions reduction benefits of CCUS, countries such as the U.S., the UK, Australia, and Canada have set their sights on the considerable market benefits offered by this suite of technologies.

China specifically is actively pursuing research, development, and demonstration of CCUS, which is included in five-year plans and other government documents that cover climate change. For example, the importance of developing CCUS was emphasized in documents and national guidelines such as the Medium- and Long-Term Program for Science and Technology Development (2006–2020), the National Program for Addressing Climate Change in China, the 12th Five-Year Plan for Science and Technology Development, the 12th Five-Year National Plan for Science and Technology Development to Address Climate Change, and the 12th Five-Year Plan for Carbon Capture, Utilization, and Storage Technology Development.

There has been recent progress in advancing CCUS in China. Since the end of the 11th Five-Year Plan, China’s government has supported research and development work carried out by domestic colleges, universities, and research institutes as well as large power, petroleum, and coal companies. This work has laid the foundation for a CCUS industry—and includes launching the country’s largest CCS project in operation to date, Shenhua’s 100,000 tonnes/annum (tpa) full-process demonstration project for CO2 capture, transportation, and storage in saline aquifers. Other major research, development, and demonstrations related to CO2 utilization are listed in Table 1.

Peng Table 1

Today China has developed a pathway for the deployment of CCUS and technologies to use CO2 to produce various resources. However, large-scale full-process demonstration projects over one million tpa in size have yet to be carried out in the country. Thus, to achieve a commercial CCUS industry in the near future the challenges of high costs, lack of maturity of some key technologies, and a lack of complementary facilities and related policies must be addressed. The near-term advancement of the technology is critical.

CCUS CONTRIBUTIONS TO EMISSIONS REDUCTIONS AND INDUSTRIAL TARGETS

In 2013, China’s Ministry of Science and Technology’s Administrative Center for China’s Agenda 21 took the lead in conducting a comprehensive scientific assessment of CCUS technologies in China, and published the results in 2014.1 In this report, the emissions reduction potential and benefits of different CCUS technologies in China were assessed.

Based on the current policies and technology development trends—and as CCUS technology demonstration and industrialization plans are ramping up—enormous potential exists for increased deployment and emissions reductions (see Table 2). If there is expanded policy support and investment for CCUS, greater deployment and the resulting emissions reductions could be achieved sooner, in addition to achieving the broader economic and social benefits.

Considering the large potential revenue and emissions reductions, CCUS should, first and foremost, be applied to reduce emissions from China’s coal-fired power, coal-to-chemicals, and steel and cement production sectors. Integrating CCUS projects could form industrial clusters of emissions reductions across these different industries and reduce net costs.

PRINCIPAL PATHWAYS FOR PROMOTING CCUS IN CHINA

China possesses several characteristics that are important for growing a successful CCUS industry, including CO2 emissions that are largely clustered around industrial centers, diverse geology, proximity of sources and sinks, and commodity prices high enough to help support CCUS projects. Through systematic planning, pathways for CCUS project development in China have been identified.

The first opportunity identified is associated with using CO2 from coal-fired power plants to enhance oil recovery (CO2-EOR) and enhance water recovery (EWR). The water produced in EWR could be further processed to extract valuable minerals, such as lithium salts, potash, and bromine, and also simply to produce usable water (treatment would be required) as many coal-fired power plants are located in regions of the country where water scarcity is higher. There may also be opportunities to use CO2 from some steel and cement production facilities for these purposes.

CO2-EOR is a near-term CO2 utilization opportunity being pursued in China.

CO2-EOR is a near-term CO2 utilization opportunity being pursued in China.

Another potential CCUS opportunity is to use the relatively pure CO2 from coal conversion processes in China, such as the production of synthetic natural gas, for enhanced coalbed methane (ECBM) production. In addition, the captured CO2 and newly produced methane could be combined with coke oven gas (H2 and CH4) to generate a feedstock to produce syngas, liquid fuels, methanol, etc.

Yet another CCUS opportunity is related to using the lower concentrations of CO2 generated during steel and cement production. Such CO2 could be used for the mineralization of bulk solid wastes (such as slag and phosphogypsum), generating value-added materials. In addition, low-concentration CO2 can be used directly for the cultivation of microalgae. The cultivated microalgae can be used for fertilizer—particularly suitable for treating the saline-alkali and desert soils in China. This would have a co-benefit of increasing carbon fixation in soil. Oils from the microalgae could also be used in fuel production and in the chemical production industries, although this work is quite preliminary.

Although some core CCUS technologies are at an early stage of research and development, these technologies hold value for improving China’s energy security, benefitting the environment, reducing emissions, providing new sources of economic growth, growing emerging strategic industries, and improving national competitiveness.

Based solely on the development status of CCUS today, the potential for emissions reductions and the economic benefits of various CCUS options as forecasted in 2030 are shown in Table 3.1 If there is expanded policy support and constraints in the market are reduced, CCUS technologies that are still being researched, developed, and demonstrated could mature more quickly and enter the market sooner, resulting in even greater benefits.

Peng Table 3

CONCLUSIONS AND RECOMMENDATIONS

The development of a CCUS industry is an important way forward for reducing emissions in China. New industrial clusters could potentially develop into foundations for economic growth, promoting sustainable socioeconomic development. To realize this potential, the Administrative Center for China’s Agenda 21 makes several recommendations:

  1. Conduct a systematic assessment of the costs, safety, environmental aspects, and other factors related to CCUS in China, especially in regions with better conditions for early CCUS demonstrations, such as the Ordos Basin, Songliao Basin, Bohai Bay Basin, and Junggar Basin. This will give a more accurate understanding of the potential for CCUS in the country.
  2. Due to the lower capture cost, concentrated sources of CO2, such as from the coal-to-chemicals industry, should be used initially as the source of CO2 for CCUS demonstrations. When considering technologies, attention should be given to increasing energy efficiency through integration of CCUS with existing processes, and thus decreasing coal consumption. For example, efficiency may be achievable through integration of CCUS with the production of synthetic natural gas. Potential opportunities include achieving breakthroughs in the core technologies, such as gasification.
  3. Certainty must be increased around the prospects of the large-scale, commercial application of post-combustion capture, pre-combustion capture, and oxy-fuel combustion technologies. Thus, these three CO2 capture options should be demonstrated and integrated with the demonstration and scale-up of CO2-EOR, CO2-EWR, and onshore saline aquifer storage to achieve several demonstration projects with a scale of more than one million tpa by 2020. In addition, the demonstration of other integrated systems could simultaneously be advanced through knowledge sharing based on these full-process CCUS demonstrations.
  4. In terms of CO2 recycling, the research, development, and demonstration of CO2 mineralization and key technologies for CO2 bio-utilization (i.e., microalgae) should be enhanced. Early demonstrations of such technologies are being carried out today at a relatively small scale, and development of such technologies using CO2 from the steel and cement industries should be considered.
  5. By fully leveraging the common technical features of CO2-EOR and storage of CO2 in saline aquifers, research and development efforts for specialized technologies related to ECBM and the output of water-soluble minerals should be increased. Relevant integrated demonstrations should be identified and supported.

In conclusion, CCUS is an important way forward to reduce CO2 emissions in China. Integration of key technologies can reduce costs and uncertainty, allowing CCUS to play an important first step in reducing the country’s emissions.

NOTES
A. Conversions based on exchange rate of US$1 = 6.4 RMB as of 17 August 2015.

REFERENCES

  1. Administrative Center for China’s Agenda 21. (2014). China’s CO2 utilization technology review. Science Press, www.ccuschina.org.cn/uploadfile/Other/2013112016112758287773.pdf

 

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The Case for Carbon Capture From Air

By Klaus Lackner
Professor,
School of Sustainable Engineering and the Built Environment
Director,
Center for Negative Carbon Emissions, Arizona State University

Stabilizing the atmospheric carbon dioxide (CO2) concentration requires the nearly complete elimination of all anthropogenic CO2 emissions.1 In the popular bathtub analogy that equates atmospheric CO2 concentration with the water level in a tub, the water level is held constant by matching the input from the faucet with the outflow through the drain. Unfortunately—and contrary to the usual explanation—in the case of the atmosphere, the drain clogs as the faucet is turned down. Once the atmospheric concentration stops rising, the surface ocean and the biosphere find their balance with the new CO2 level, and transport into the deep ocean will slow as the top layer of the ocean, which is close to equilibrium with the air, grows in size. Therefore, to meet international climate goals annual global emissions must approach zero. This is a tremendous challenge considering population growth and the existing energy infrastructure. If emissions cannot be fully eliminated or the atmospheric CO2 concentration overshoots the limit considered safe by climate scientists, negative emissions will be required as an additional drain so that the tub does not overflow. In fact, in its latest report, the Intergovernmental Panel on Climate Change (IPCC) suggests that negative emissions (i.e., an anthropogenic drain) will be necessary to meet the international goal of limiting climate change to 2˚C.2

Removing CO2 from the air would likely be required in a zero-emissions future.

Removing CO2 from the air would likely be required in a zero-emissions future.

This poses a challenge for today’s energy engineers: Provide affordable energy for a rapidly growing world economy while eliminating all CO2 emissions. This must also be accomplished without other environmental impacts, without creating energy shortages, and in the most economical way possible. Moreover, the time available for this radical transition is short. Thus, there is an urgency to introduce zero-emissions technologies across all energy sectors. This would include bold negative-emissions technologies for recovering and storing atmospheric CO2 to cancel out residual emissions and, if necessary, actually reduce the CO2 concentration in the atmosphere. Action is necessary, because learning by doing requires doing, and any delay will further increase the difficulty of stabilizing concentrations at a safe level.

NO SMALL FEAT

It is important to consider the scale of the challenge. Fossil fuel consumption could easily quadruple over the course of this century without global per capita energy consumption exceeding that of the U.S. today. With more than 80% of today’s energy derived from fossil fuels, virtually the entire energy system must change. In addition, the world may need to correct an overshoot that could easily be as large as 100 ppm, or 400 Pg of excess carbon. This is more than all emissions of the 20th century. In any overshoot scenario carbon storage becomes unavoidable, and potentially a very large component of carbon management.

LARGE-SCALE LOW-EMISSIONS ENERGY OPTIONS

Solar, nuclear, and fossil energy are the three truly large-scale energy options for the future.3 Sunshine exceeds human energy consumption by four orders of magnitude, nuclear resources could supply thousands of years of power, and fossil carbon, even at increased consumption, could support global energy demand for several hundred years. However, none of the three large options are ready for a future carbon-neutral world. From a business perspective it is entirely rational to back a profitable technology, even if it cannot operate at global scale. From a policy perspective, however, the risk mitigation resulting from developing a global solution is very worthwhile, even if cobbling together a global energy system from many small sources may prove feasible. All energy options need to be pursued, but advances in these three fields are particularly important as each could result in an energy infrastructure that is sufficient to satisfy human needs.

While all large-scale low-emission energy options are critical, each faces unique challenges.

While all large-scale low-emission energy options are critical, each faces unique challenges.

The available options for stabilizing CO2 can broadly be classified into three categories: improved efficiency, increased deployment of renewables and nuclear, and carbon capture and storage.

Acceleration of Efficiency Improvements

The first option is to do more with less energy and increase efficiency throughout the entire energy value chain. There are abundant opportunities on the demand side, from LED lighting to more efficient cars. There are also many opportunities on the supply side, from higher-efficiency power plants to cogeneration of heat and power. Improving efficiency can greatly reduce emissions, but it cannot achieve zero or negative emissions. Since efficiency improvements stem from a myriad of different advances, progress is unlikely to come from a few large projects, but more likely from broad-based economic incentives. It is worth noting that improving efficiency is already built into the IPCC’s business-as-usual scenarios and maintains global energy consumption projections typically one percentage point below the world’s GDP growth. To go beyond business as usual, energy intensity improvements must go much further.4

Increased Deployment of Renewables and Nuclear

The second option is to expand the deployment of carbon-
neutral energy resources, such as renewable and nuclear energy. If all fossil carbon resources were to be replaced with non-fossil energy, anthropogenic CO2 emissions to the atmosphere would drop close to zero, but such a transition would be associated with huge costs, major infrastructure changes, and would likely take too much time to meet international climate goals. In addition, the intermittency issue of solar energy must be resolved in an affordable manner, and nuclear energy is saddled with the risk and legacy of Three Mile Island, Chernobyl, and Fukushima. While not comprehensive in the near term, renewable energy and nuclear energy, including fusion, are an important part of a low-emissions solution and need to be developed to create optionality in the energy sector.

Carbon Capture and Storage

The third major option is to capture and permanently dispose of CO2. For carbon capture and storage (CCS) to be compatible with a zero-emissions world, it must include CO2 capture from the atmosphere, since CCS does not capture 100% of emissions from fossil power plants.

Capture of carbon from the atmosphere, the surface ocean, or the biosphere makes it possible to create negative emissions that could recover past emissions or balance out remaining emissions that are difficult to capture by other means. This includes the fugitive emissions of a coal plant with CCS and its associated CO2 storage as well as the CO2 emitted from the transportation sector.

However, the path forward is challenging. Fossil energy can only contribute to a zero-emissions world if all CO2 and other greenhouse gas emissions can be eliminated. CCS is not yet widely applied and its costs must be reduced.

THE POTENTIAL ROLE OF AIR CAPTURE

If none of these three options for stabilizing CO2 emissions can be made to work, humanity would face the impossible choice between a climate disaster and a collapse of the world’s energy systems. Considering the risks, I believe current efforts and investment are far too lackadaisical.

My own focus has been finding ways of recovering CO2 from the atmosphere by technical means.5,6 Recovering CO2 from the environment by any means can help return the world to lower CO2 levels and it can close the anthropogenic carbon cycle regardless of the original carbon source. This will require the large-scale use of carbon storage technologies. Importantly, use of carbonaceous liquid fuels in the transportation sector can only be sustained if it is fully matched by CO2 recovery. For biofuels grown in open air, the recovery is automatic. For petroleum-based fuels, fuel from algae grown in closed bioreactors, or for synthetic fuels, the CO2 must be recaptured. Ultimately, as long as fossil fuels are used, for every ton of carbon taken from the ground another ton will have to be stored in a net-zero emission world. Even without fossil fuels, for every ton of CO2 injected into the air, another ton will have to be recaptured.

Direct capture of CO2 from air is already practiced today, albeit on a much smaller scale, to purify breathing air on submarines or spacecraft, or the removal of CO2 from air prior to its liquefaction. Thus, there is a foundation on which to build. Through innovation, researchers hope to reduce the costs and find new pathways to enable direct air capture to play a role in a low-emissions future. There are already several start-up companies demonstrating the feasibility of capture from air.

It is necessary to develop cost-effective technologies to store or use CO2 to realize the benefits of air capture.

It is necessary to develop cost-effective technologies to store or use CO2 to realize the benefits of air capture.

It is highly unlikely that the massive changes necessary to stabilize CO2 in the atmosphere could be cost-effectively achieved by deploying a single technology. It is even less likely that scientists, engineers, business people, or policy makers could successfully pick the winner today. With hindsight, it is clear that some technologies have come down in costs by orders of magnitude since their inception and operate at scales initially thought to be impossible. Eventually many processes approach a “frictionless” cost that is dominated by raw materials and energy. However, such reductions in cost are not predictable. Rather than making policies based on current cost, which is meaningless, or hypothetical cost, which is unknowable, a better strategy is to develop technology options and make decisions as advantages and disadvantages emerge. Thus, direct air capture is among the global options that need to be developed.7

Perhaps the strongest motivation for developing direct air capture technologies would be the resultant uniform cost for carbon emissions. Air capture, because it collects CO2 after it has been emitted, can balance out any emission, at any time, and from any location. If there is no better technological option (e.g., as is likely the case for emissions from widespread air travel) air capture combined with storage or fuel synthesis can become viable where no other option is feasible. In most cases, it will be easier or cheaper to collect the CO2 earlier in the energy chain (e.g., CCS at a coal-fired power plant), or it may be preferable to avoid making CO2 in the first place by raising energy efficiency or by deploying near-zero carbon energy sources.

By making emissions reversible, air capture puts a price on CO2 emissions as an option of last resort. If that price proves affordable, comprehensive carbon regulations become more palatable politically. With gradually tightening regulations that enforce a shrinking—and in the future perhaps even negative—annual carbon budget, air capture would provide an economic incentive for other low-emission technologies to reduce emissions at a lower cost. The policy value of air capture is not in the amount of CO2 that it cancels out, but in its ability to set the marginal cost of CO2 remediation. Even if the contribution of air capture to carbon mitigation remains small, its gradual cost reductions will likely spur advances in all other carbon-avoiding technologies.8

Researchers are already working on air capture technologies, such as carpet-like ion exchange resins, that could reduce costs.

Researchers are already working on air capture technologies, such as carpet-like ion exchange resins, that could reduce costs.

HEDGING OUR BETS

How a zero-emissions world will develop is difficult to predict. Different technologies, including air capture technologies, will compete for various sectors of the market. In a zero-emissions world, regulations placing a price on CO2 emissions directly or indirectly would ensure use of unabated fossil fuels is eliminated.

Rather than setting an artificial price for emissions, I propose that all CO2, whether released accidentally or intentionally, must be recovered. This will provide a niche for air capture and it will set the marginal cost of carbon emissions. Whether this niche is large or small will depend on all other technologies
that are under development and which will move forward if zero-emissions becomes an enforceable goal. Rather than prescribing an answer, I propose to set boundary conditions in which markets can find an optimal solution.

REFERENCES

  1. Archer, D. (2010). The global carbon cycle. Princeton: Princeton University Press.
  2. Qin, D., Plattner, G-K., et al. (2014). Climate change 2013: The physical science basis. Cambridge, UK, and New York: Cambridge University Press.
  3. Lackner, K. (2010). Comparative impacts of fossil fuels and alternative energy sources. In R.E. Hester, R.M. Harrison, et al. (Series Eds.), Issues in Environmental Science and Technology, No. 29 (pp. 1–40). Cambridge, UK: The Royal Society of Chemistry.
  4. Lackner, K.S., & Sachs, J. (2005). A robust strategy for sustainable energy. Brookings Papers on Economic Activity 2005, No. 2, 215–284.
  5. Lackner, K. (2010). Washing carbon out of the air. Scientific American, 302(6), 66–71.
  6. Lackner, K. (2014). The use of artificial trees. In R.E. Hester & R.M. Harrison (Eds.), Geoengineering of the climate system (pp. 38, 80). Cambridge, UK: Royal Society of Chemistry.
  7. Lackner, K., Brennan, S., Matter, J.M., Park, A.H.A., Wright, A., & Van Der Zwaan, B. (2012). The urgency of the development of CO2 capture from ambient air. Proceedings of the National Academy of Sciences, 109(33), 13156–13162.
  8. Lackner, K., & Brennan, S., (2009). Envisioning carbon capture and storage: Expanded possibilities due to air capture, leakage insurance, and C-14 monitoring. Climatic Change, 96, 357–378.

The author can be reached at Klaus.Lackner@asu.edu

 

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Reducing Energy’s Footprint by Producing Water and Storing CO2

By Thomas A. Buscheck
Group Leader,
Geochemical, Hydrological, and Environmental Sciences,
Physical and Life Sciences Directorate,
Lawrence Livermore National Laboratory
Jeffrey M. Bielicki
Assistant Professor,
Department of Civil, Environmental, and Geodetic Engineering and John Glenn College of Public Affairs,
The Ohio State University

The global energy sector faces many challenges, perhaps the two most important of which are reducing greenhouse gas emissions from fossil fuels, which made up over 86% of primary energy consumption in 2014,1 and addressing the growing challenge of water scarcity. One key aspect of the landmark U.S.-China Joint Announcement on Climate Change is the consideration of a collaborative effort to engage on both challenges simultaneously through research, development, and demonstration of a CO2 capture and storage (CCS) project that would produce freshwater.2

The U.S.-China Clean Energy Research Center’s (CERC) Advanced Coal Technology Consortium (ACTC) is an opportunity to leverage years of experience and research to investigate an emerging CO2 capture, utilization, and storage (CCUS) technology called enhanced water recovery (EWR). To date, CCUS has been deployed by injecting CO2 into petroleum reservoirs for enhanced oil recovery (CO2-EOR). While CCUS/CO2-EOR can make early contributions to reducing CO2 emissions and raising revenue for first mover CCS demonstrations, the total scope is limited. For example, in the U.S., in the year 2013 alone, emissions were 6.7 billion tonnes of CO2. For comparison, total storage capacity using “next generation” CO2-EOR in the U.S. was estimated to be 45 billion tonnes of CO2, with less than half (20 billion) considered to be economic at an oil price of $85/bbl, which would address the equivalent of three years of CO2 emissions.3,4

Unlike CO2-EOR, which has limited deployment potential in many regions of the world, EWR can be deployed in saline aquifers that are well distributed and close to CO2 sources(e.g., coal-fired power plants). EWR can be synergistically integrated with other emerging CCUS technologies that generate geothermal energy,5,6 as well as provide grid-scale energy storage.7,8 By removing brine from a saline CO2 storage reservoir, EWR can augment the development, operation, and performance of CCS, while producing large quantities of water.9,10 In this article we discuss how EWR can be used to help manage environmental and financial risks during the stages of CCS development.

KEY CCS CHALLENGES

Despite the importance of CCS/CCUS for reducing global emissions, widespread deployment faces some considerable technical challenges. To overcome these, the U.S. Department of Energy (DOE) outlined four major goals for its Carbon Storage Technology Program Plan:11

  1. Develop and validate technologies to ensure 99% storage permanence (i.e., less than 1% of the injected CO2 leaves the storage system due to leakage).
  2. Develop technologies to improve reservoir storage efficiency, while ensuring containment effectiveness.
  3. Support industry’s ability to predict CO2 storage capacity in geologic formations within ±30%.
  4. Develop best practice manuals for monitoring, verification, and accounting; site screening, selection, and initial characterization; public outreach; well management activities, risk analysis, and simulation.

In a CO2 storage reservoir, overpressure is defined as fluid pressure that exceeds the original pressure before CO2 is injected. Overpressure is the limiting metric for CO2 storage capacity because it is the primary factor affecting risks such as induced seismicity, caprock fracture, and CO2 leakage. These risks increase with overpressure. The three most important factors that influence overpressure are

  1. The quantity of CO2 and the rate at which it is injected
  2. The size of the storage reservoir “compartment”, determined by the geology
  3. The permeability (i.e., ability of the CO2 to move) within the storage reservoir

Geologic surveys, geologic logs, and core data from exploration wells provide information that can be used to estimate the size and permeability of the reservoir compartment. However, until injection or production wells are operated, and large quantities of fluid move into and/or out of the storage reservoir, estimates of CO2 storage capacity and permanence may be subject to uncertainty.

Unlike CCUS/CO2-EOR operations conducted at brownfield sites (pre-existing well-fields), CCS in a saline aquifer is typically a greenfield operation. Thus, there may be less geologic information, and little or no production and injection history available to estimate how much CO2 can be safely and securely stored. The ZeroGen project in Australia is one prominent example of a problem resulting from insufficient knowledge about the storage reservoir. The project only advanced to the point of learning that the intended CO2 storage reservoir had too little storage capacity. As a result, a key lesson learned from that project was that storage capacity estimates must be based on long-term, dynamic well testing.12 Thus, uncertainties about CO2 storage capacity and permanence are key reasons why CO2 storage is a primary technical hurdle for the commercialization of CCS, but this hurdle can be addressed through site characterization augmented with brine extraction.

Without adequate site characterization, which can take 5–10 years, CO2 cannot be captured, transported, and stored routinely and reliably at large scale.13 Pore-space ownership and public acceptance are other key challenges. A deployment strategy that extracts brine prior to the injection of any CO2 can address these challenges.

THE MULTIPLE BENEFITS OF BRINE EXTRACTION

Extracting brine from a CO2 storage reservoir provides multiple benefits. First, extracting brine opens more pore space in the reservoir for CO2 storage, resulting in less overpressure and less required post-injection monitoring for a given quantity of stored CO2.14 In addition, more CO2 can be injected without infringing on the pore-ownership rights of neighboring subsurface operations (e.g., other CCS sites).

Producing brine while increasing CO2 storage capacity could address two of the most important challenges facing today’s energy industry.

Producing brine while increasing CO2 storage capacity could address two of the most important challenges facing today’s energy industry.

Second, produced brine can be partially treated for industrial and saline cooling-water applications or desalinated to produce freshwater; it can also be used to extract valuable minerals, such as lithium.10,15 The efficacy of brine use depends on the location, because of differences in the chemical composition of the brine and applicable utilization options.

Third, when brine is extracted before CO2 injection, the resulting pressure drawdown provides direct information about overpressure that will result from CO2 injection.9 Hence, operational experience with removing brine reduces uncertainties about CO2 storage capacity and permanence, compared to when the first major well operation is CO2 injection itself. This third benefit is valuable for both site selection and characterization. Reducing CO2 storage uncertainty could be necessary prior to final commitments on CO2 capture and transportation infrastructure.

Fourth, brine extraction maximizes storage resource utilization. A “one source, one sink” approach is unlikely given the current regulatory climate and cost of CO2 capture. As brine removal increases CO2 storage capacity, it can allow an individual sink to store CO2 from multiple sources; thus, fixed development costs for that site (e.g., permitting, site characterization, monitoring) are leveraged for multiple sources, reducing CO2 storage cost.16–18

Zero net injection—where the volume of the extracted brine is the same as the volume of the injected CO2—minimizes interference with neighboring owners and users of underground pore space, and it also maximizes all of these benefits.

Brine Extraction as a Pressure Management Strategy

Brine extraction can be scheduled both before (Figure 1) and during CO2 injection (Figure 2). It could also be scheduled after CO2 injection (Figure 3), as part of a reservoir pressure management strategy aimed at reducing the required time for post-injection monitoring, while continuing to produce water.

FIGURE 1. Brine extraction before CO2 injection results in pressure drawdown, making room for CO2 storage.9

FIGURE 1. Brine extraction before CO2 injection results in pressure drawdown, making room for CO2 storage.9

For CCS operations, pre-injection brine extraction has three objectives: 1) minimize the total number of wells required for CCS deployment, 2) maximize the magnitude of overpressure reduction per unit of extracted brine, and 3) acquire pre-injection information on the reservoir from measuring pressure drawdown. When the same well is used first to extract brine and then to inject CO2, pressure drawdown and the information gathered are greatest where needed most—the center of CO2 storage.9 Measuring pressure drawdown in an adjoining deep monitoring well (Figure 1) provides additional information about the size of the reservoir compartment and CO2 storage capacity. Measuring drawdown in a shallow monitoring well provides important information about the potential for CO2 leakage through the caprock and, hence, CO2 storage permanence.

CO2 injection begins where pressure drawdown is greatest, which is where the brine was initially extracted (Figure 2). Then a second brine-extraction well can operate until CO2 from the first well reaches the second well, at which time the second well may be repurposed for CO2 injection (Figure 3). Brine extraction may continue at a third deep well, depending on the CO2 storage goals. Brine extraction could continue long after CO2 injection has ceased. This strategy could nullify residual overpressure, limit pore-space competition with neighbors, and reduce the time required for post-injection monitoring to assure storage integrity.

FIGURE 2. The brine-extraction well shown in Figure 1 is repurposed as a CO2 injection well and the deep monitoring well is repurposed for brine extraction.9

FIGURE 2. The brine-extraction well shown in Figure 1 is repurposed as a CO2 injection well and the deep monitoring well is repurposed for brine extraction.9

FIGURE 3. The brine-extraction well shown in Figure 2 is repurposed as a CO2 injection well; brine extraction is moved to a third deep well and could continue post-CO2 injection.9

FIGURE 3. The brine-extraction well shown in Figure 2 is repurposed as a CO2 injection well; brine extraction is moved to a third deep well and could continue post-CO2 injection.9

Based on data from the Snøhvit CO2 storage project that injected 1.09 million tonnes of CO2 over three years,19,20 a retrospective reservoir modeling study evaluated the potential efficacy of extracting brine prior to injecting CO2.21 Hydrogeologic information and CO2 injection-rate and pressure data provided by Statoil were used to calibrate a reservoir model to predict overpressure from CO2 injection. The results of this model agreed closely with measured values during the three years of CO2 injection (see Figure 4).

FIGURE 4. Overpressure history from the Snøhvit CO2 storage project injection well and as modeled for injection only and with pre-injection brine extraction.21

FIGURE 4. Overpressure history from the Snøhvit CO2 storage project injection well and as modeled for injection only and with pre-injection brine extraction.21

The calibrated model was then used to simulate a scenario where a volume of brine equal to the injected CO2 volume (~1.56 million m3) was extracted over the three years prior to CO2 injection. To continue the modeling exercise beyond the end of the actual Snøhvit CO2 injection phase, it was assumed that the three-year CO2 injection-rate schedule was repeated nine times during the 27 years following the end of the phase. It was also assumed that brine was extracted in the same time-varying fashion.21

At the end of injection at Snøhvit, a peak overpressure of 7.63 MPa was reached; a goal of this modeling exercise was to determine how much additional CO2 could be injected before this overpressure was reached if brine had been extracted. It was found that extracting a volume of brine equal to the volume of the injected CO2 nearly doubled the time (and quantity of CO2) required to reach an overpressure of 7.63 MPa.21 On a volume-for-volume basis, brine extraction was found to be 94% effective, the equivalent of not having injected 1.03 of the 1.09 (actual) million tonnes of CO2, which could enable an additional 1.03 million tonnes of CO2 to be injected before the peak measured overpressure was reached.21

This exercise also showed the value of brine extraction for site characterization. Pressure drawdown history is the mirror image of the overpressure history (Figure 4), and thus this technique provides useful information on overpressure that will result from CO2 injection as well as on the CO2 storage capacity. It is worth noting that three years of pre-injection brine extraction falls within the 5–10-year timeframe attributed to site characterization.13

Brine Extraction as a Site Selection and Characterization Strategy

Extracting brine prior to CO2 injection could be applied to several potential CO2 storage sites to help identify the one that has the best combination of storage capacity, permanence, and efficiency. Brine extraction could then continue at the selected site until enough pressure data is collected and analyzed to assure investors, insurers, and, most importantly, the public that risk has been sufficiently reduced.

The Benefit of Producing Water

The inextricable link between water and energy has been termed the water–energy nexus. Every energy source requires water at some point in the supply chain.22,23 Thermal power plants fueled by coal, natural gas, and nuclear energy serve as the backbone of the modern energy infrastructure and such plants require substantial cooling, which is most often served by water.

EWR through brine extraction produces water as part of an integrated strategy to also dispose of CO2 in the deep subsurface. Thus, thermal power plants begin producing water and some plants, such as those that employ low-water demand technologies like pressurized oxy-combustion or chemical looping with CCS (currently pre-commercialization), could become net water producers. However, brine that is produced from the deep aquifers suitable for CO2 storage contains more dissolved solids and impurities than groundwater in shallow aquifers. Brine from saline aquifers is not usable without treatment. Based on preliminary estimates,10 treatment may cost ~0.3 US¢/kWh for zero net injection, possibly attractive in many water-scarce regions. Moreover, that cost can be offset by other savings (fewer wells, less monitoring, lower insurance costs) and the economic and permitting advantages that arise from reducing uncertainty. There may also be opportunities for synergistic integration of thermal power plants and water purification processes.8,24 Still, the net life-cycle benefits of producing water from CO2 injection need to be investigated.25

The CO2 storage site down-selection criteria, discussed in the previous section, can be broadened to include brine treatability (e.g., energy required and costs of treatment depend on the brine composition and intended application), as well as the proximity of a candidate site to arid regions.

A zero net injection strategy for reservoir pressure management can generate substantial quantities of brine (and product water after treatment) on a per MWh basis. A 1000-MW coal-fired power plant operating at 90% capacity and a 90% CO2 capture rate produces 10–14.4 million m3 (8–11.6 thousand acre feet) of water per year while storing seven million tonnes of CO2 each year.14

If low-water CO2 capture options are used, coal-fired power plants with EWR could become net water producers.

If low-water CO2 capture options are used, coal-fired power plants with EWR could become net water producers.

U.S.-CHINA COLLABORATION AS A NEAR-TERM EWR OPPORTUNITY

The potential of EWR was highlighted by its consideration for development in U.S-China collaboration efforts. Under the recent joint climate announcement, the U.S.-China CERC is considering EWR in connection with the GreenGen project in Tianjin, China. The Huaneng Corporation is planning to capture CO2 at a coal integrated gasification combined-cycle (IGCC) power plant.26 The feasibility of injecting this CO2 into a deep saline aquifer for permanent storage, while extracting an equivalent volume of brine to generate freshwater by reverse osmosis desalination, possibly using pre-injection brine extraction, was evaluated with promising results.27

CONCLUSIONS

Overall, challenges facing modern energy systems include reducing both CO2 emissions and water intensity, while providing reliable, affordable, and secure energy. These challenges can be addressed simultaneously by injecting CO2 for storage in deep saline aquifers while producing brine from the same aquifers. Producing brine has a number of operational benefits that enhance the efficacy of CO2 storage, while simultaneously producing water that may help alleviate the stress in the water–energy nexus. CCS is a key tranche in the lowest-cost suite of technologies needed to limit global emissions and EWR could play an important role in advancing CCS.

ACKNOWLEDGMENTS

We gratefully acknowledge the Statoil and the Snøhvit Production License for use of data from the Snøhvit CO2 storage project, and Philip Ringrose for useful discussions. This work was sponsored by the USDOE Fossil Energy, National Energy Technology Laboratory, managed by Traci Rodosta and Andrea McNemar. This work was performed under the auspices of the USDOE by Lawrence Livermore National Laboratory under DOE contract DE-AC52-07NA27344.

REFERENCES

  1. BP. (2015). Statistical review of world energy 2015, www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy.html
  2. The White House, Office of the Press Secretary. (2014, 11 November). U.S.-China joint announcement on climate change, www.whitehouse.gov/the-press-office/2014/11/11/us-china-joint-announcement-climate-change
  3. U.S. Environmental Protection Agency. (2015). Sources of greenhouse gas emissions, www.epa.gov/climatechange/ghgemissions/sources/electricity.html
  4. U.S. Department of Energy National Energy Technology Laboratory. (2011). Improving domestic energy security and lowering CO2 emissions with “next generation” CO2-enhanced oil recovery (CO2-EOR), DOE/NETL-2011/1504, Activity 04001.420.02.03.
  5. Randolph, J.B., & Saar, M.O. (2011). Combining geothermal energy capture with geologic carbon dioxide sequestration. Geophysical Research Letters, 38(10).
  6. Zhang, L., Li, D., Ren, B., Cui, G., Zhuang, Y., & Ren, S. (2014). Potential assessment of CO2 geological storage in geothermal reservoirs associated with heat mining: Case studies from China. Energy Procedia, 63, 7651–7662.
  7. Buscheck, T.A., Bielicki, J.M., Chen, M., Sun, Y., Hao, Y., Edmunds, T.A., . . . Randolph, J.B. (2014). Integrating CO2 storage with geothermal resources for dispatchable renewable electricity. Energy Procedia, 63, 7619–7630.
  8. Buscheck, T.A., Bielicki, J.M., Edmunds, T.A., Hao, Y., Sun, Y., Randolph, J.B., & Saar, M.O. (2015). Multi-fluid geo-energy systems: Using geologic CO2 storage for geothermal energy production and grid-scale energy storage in sedimentary basins. Geosphere, special edition on geothermal systems in sedimentary basins, submitted for review.
  9. Buscheck, T.A., White, J.A., Chen, M., Sun, Y., Hao, Y., Aines, R.D., . . . Bielicki, J.M. (2014). Pre-injection brine production for managing pressure in compartmentalized CO2 storage reservoirs. Energy Procedia, 63, 5333–5340.
  10. Bourcier W.L., Wolery, T.J., Wolfe, T., Haussmann, C., Buscheck, T.A., & Aines, R.D. (2011). A preliminary cost and engineering estimate for desalinating produced formation water associated with carbon dioxide capture and storage. International Journal of Greenhouse Gas Control, 5, 1319–1328.
  11. U.S. Department of Energy (USDOE). (2014). USDOE clean coal research program carbon storage technology program plan, www.netl.doe.gov/File%20Library/Research/Coal/carbon-storage/Program-Plan-Carbon-Storage.pdf
  12. Garnett, A.J., Greig, C.R., & Oettinger, M. (2014). ZeroGen IGCC with CCA: A case history. The University of Queensland, www.uq.edu.au/energy/docs/ZeroGen.pdf
  13. U.S. National Coal Council. (2015). Fossil forward: Revitalizing CCS bringing scale and speed to CCS deployment, www.nationalcoalcouncil.org/studies/2015/Fossil-Forward-Revitalizing-CCS-NCC-Approved-Study.pdf
  14. Buscheck, T.A., Sun, Y., Chen, M., Hao, Y., Wolery, T.J., Bourcier, W.L., . . . Aines, R.D. (2012). Active CO2 reservoir management for carbon storage: Analysis of operational strategies to relive pressure buildup and improve injectivity. International Journal of Greenhouse Gas Control. 6, 230–245.
  15. Surdam, R.C., Quillinan, S.A., & Jiao, Z. (2013). Displaced fluid management—The key to commercial-scale geologic CO2 storage. In R.C. Surdam (Ed.). Geological CO2 storage characterization: The key to deploying clean fossil energy technology (pp. 233–244). New York: Springer. doi:10.1007/978-1-4614-5788-6
  16. Middleton, R., & Bielicki, J.M. (2009). A scalable infrastructure model for carbon capture and storage: SimCCS. Energy Policy, 37, 1052–1060.
  17. Bielicki, J.M. (2009). Integrated systems analysis and technological findings for carbon capture and storage deployment. Ph.D. Thesis, Harvard University.
  18. Middleton, R., Kuby, M., & Bielicki, J.M. (2012). Generating candidate networks for optimization: The CO2 capture and storage optimization problem. Computers, Environment, and Urban Systems. 36, 18–29.
  19. Hansen, O., Gilding, D., Nazarian, B., Osdal, B., Ringrose, P., Kristoffersen, J-B., . . . Hansen, H. (2013). Snøhvit: The history of injecting and storing 1 Mt CO2 in the fluvial Tubåen Formation. Energy Procedia, 37, 3565–3573.
  20. Shi, J-Q., Imrie, C., Sinayuc, C., Durucan, S., Korre, A., & Eiken, O. (2013). Snøhvit CO2 storage project: Assessment of CO2 injection performance through history matching of the injection well pressure over a 32-month period. Energy Procedia, 37, 3267–3274.
  21. Buscheck, T.A., White, J.A., Sun, Y., Hao, Y., & Bielicki, J.M. (2015). Preliminary analysis of pre-injection brine-production CO2 reservoir pressure-management strategy using a calibrated model of the Snøhvit CO2 storage project. LLNL-TR-675402, Livermore, CA, USA.
  22. Fthenakis, V., & Kim, H.C. (2010). Life-cycle uses of water in U.S. electricity generation. Renewable and Sustainable Energy Reviews, 14, 2039–2048. doi:10.1016/j.rser.2010.03.008
  23. Meldrum, J., Nettles-Anderson, S., Heath, G., & Macknick, J. (2013). Life cycle water use for electricity generation: A Rreview and harmonization of literature estimates. Environmental Research Letters, 8, 015031. doi:10.1088/1748-9326/8/1/015031
  24. Chen, Y., & Zhang, J. (2014). Supplying water to power plants with desalination technology. Cornerstone. 2(1), 65–68, cornerstonemag.net/supplying-water-to-power-plants-with-desalination-technology/
  25. Zhang, C., Anadon, L.D., Mo, H., Zhao, Z., & Liu, Z. (2014). Water–carbon trade-off in China’s coal power industry. Environmental Science & Technology, 48, 11082–11089. doi:dx.doi.org/10.1021/es5026454
  26. Shisen, X. (2014). Moving forward with the Huaneng GreenGen IGCC demonstration. Cornerstone. 2(3), 61–65, cornerstonemag.net/moving-forward-with-the-huaneng-greengen-igcc-demonstration/
  27. Ziemkiewicz, P., Carr, T., Donovan, J., Lin, L., Song, L., Bourcier, W.L, Buscheck, T.A., Wagoner, J.L., Chu, S., Sullivan-Graham, J., Stauffer, P., Jiao, Z., Northam, M. & Quilinan, S. 2014. Pre-feasibility study to identify opportunities for increasing CO2 storage in deep, saline aquifers by active aquifer management and treatment of produced water. Presented at the Fourth U.S.-China CO2 Emissions Control Science and Technology Symposium, Hangzhou, PRC.

The authors can be reached at buscheck1@llnl.gov and bielicki.2@osu.edu

 

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Exploring the CCS Roadmap Landscape

By Jiang Wenhua
Chairman, Shenhua Science and Technology Research Institute

In the months leading up to the COP21 international climate negotiations, it is important to consider how potential emissions reductions can be met at the lowest cost. Widespread deployment of high-efficiency, low-emissions (HELE) technologies could reduce emissions immediately. Implementation of HELE technologies can also increase the efficiency of power plants and industrial facilities, which can partially address the energy penalty associated with carbon capture and storage (CCS, including utilization).

CCS has been recognized as an important technology to meet climate goals. Both the International Energy Agency (IEA) and the Intergovernmental Panel on Climate Change (IPCC) have reported that mitigation costs will be considerably higher without CCS (i.e., 70–138% higher using median estimates).1,2 This is because CCS is necessary to drastically reduce emissions from a wide range of industries, including the production of power from coal and natural gas, iron and steel, cement, chemicals, and natural gas processing, and also because negative emissions can be accomplished through the combination of biomass, including co-firing of biomass with coal, and CCS.3 By minimizing the total costs associated with climate change mitigation, the deployment of CCS increases the chances of meeting international climate goals without sacrificing vital development objectives.

Despite its importance as an emission mitigation option, the development and deployment of CCS is lagging behind that of some other low-carbon technologies, both in terms of financial support and level of deployment (i.e., number of CCS demonstrations). A number of roadmaps have been generated by various governments and research institutions that offer insight on approaches to get CCS development and deployment on track. This article focuses on reviewing select roadmap goals to compare how CCS is faring globally and in some key nations.

Various roadmaps provide insight about how and where to advance CCS projects.

Various roadmaps provide insight about how and where to advance CCS projects.

IEA SETS THE STANDARD

In 2009 the IEA published its CCS Technology Roadmap and then followed up with a revised version in 2013.3 The underlying message of the document was well explained by the Agency Executive Director at the time, Maria van der Hoeven: “It is critical that governments, industry, the research community and financiers work together to ensure the broad introduction of CCS by 2020, making it part of a sustainable future that takes economic development, energy security and environmental concerns into account.”

The IEA’s roadmap was consistent with limiting climate change to 2°C, which would require the widespread application of CCS, including 950 GW of coal- and natural gas-fired power generation equipped with CCS as well as widespread implementation in the iron and steel manufacturing sectors. The IEA recognized the need to bring down costs to make this a reality. Thus, the 2013 roadmap called for at least 30 large-scale (defined as at least 800,000 tonnes per year for power plants or 400,000 tonnes per year for other facilities) CCS projects by 2020 (down from 100 in the 2009 roadmap), routine use and storage of over 2000 million tonnes per annum (Mtpa) in 2030, and 7000 Mtpa in 2050 (see Figure 1).

FIGURE 1. CCS technology development pathway from the IEA CCS Technology Roadmap

FIGURE 1. CCS technology development pathway from the IEA CCS Technology Roadmap

Currently 14 large-scale CCS projects are operating and another eight are under construction. The total CO2 capture capacity of these 22 projects will be 40 Mtpa when they are all operating. With another 14 projects in a late stage of development, it is conceivable that the IEA roadmap goal of 30 projects can be met, but several of the projects could be at risk and may require greater financial support to advance to construction and operation.4

THE U.S. AT THE FOREFRONT

The U.S. could be considered a leader in CCS advancement, with seven of the 14 projects operating today occurring in the country (and these seven projects having a CO2 capture capacity of around 20 Mtpa). Although the U.S. government does not have an official roadmap for deployment of CCS, it has set a goal to reduce national emissions by 26–28% in 2025 and 83% in 2050 (both compared to 2005 levels).5 The government has not itemized how the emissions will be reduced, but has clearly supported CCS to date as part of a low-emissions strategy. Recently, the U.S. administration’s key regulatory effort to reduce the country’s emissions from the power sector, the Clean Power Plan (CPP), was released in its final form. The CPP specifically mentions CCS as an emission reduction option. However, considering CCS still is at a demonstration phase, it will be difficult for the technology to play a large role in emission reductions in the U.S. in the near term without strategic support.

To set goals on CCS development and cost reductions, the U.S. Department of Energy’s National Energy Technology Laboratory (DOE NETL) has published various CCS technology development roadmaps. The carbon capture research timeline from the 2013 CCS technology development roadmap is provided in Figure 2.6

FIGURE 2. U.S. DOE NETL carbon capture research timeline and cost goals

FIGURE 2. U.S. DOE NETL carbon capture research timeline and cost goals

CCS progress in the U.S. has been mixed, with many important recent developments in 2014. For example, the DOE’s Illinois Basin-Decatur Project crossed the benchmark of having successfully injected one million tonnes of CO2 into a saline aquifer. In addition, large projects such as the Kemper IGCC facility (582-MW pre-combustion capture) and the Petra Nova Carbon Capture Project (240-MW post-combustion capture) are expected to be operational in 2016. In addition, the Obama administration called for $2 billion in tax credits for carbon capture projects in its budget. At the same time, the DOE suspended federal funding on its $1 billion investment in FutureGen 2.0, which would have been the nation’s first commercial-scale oxy-combustion project. In general, the U.S. appears committed to supporting the development and deployment of CCS nationally and abroad. For example, China and the U.S. have been collaborating on various clean energy technologies through the Clean Energy Research Center, and CCUS collaboration was specifically mentioned in the U.S.-China Joint Announcement on Climate Change.

CANADA: A LEADER ON CCS FOR POWER

Canada has made considerable contributions to the advancement of CCS. Recently all eyes have been on the world’s first commercial-scale post-combustion CCS project, hosted by the Boundary Dam coal-fired power plant in Saskatchewan, which began operation in October 2014 and at full capacity captures around one million tonnes of CO2 each year. That project represents a tremendous step forward in CCS applied at coal-fired power plants and is also serving as a database for how to execute future projects at a lower cost.

Long before the Boundary Dam project was operational, Canada began considering the prospects of CCS. Canada’s CCS Technology Roadmap (CCSTRM) was published in 2006 with the purpose of identifying technologies, strategies, processes, and integration system pathways needed for large-scale deployment of CCS in Canada.7 Importantly, the roadmap highlights Canada’s world-class storage sites as well as clusters of emissions sources that can help to optimize technology deployment. While Canada has not updated its roadmap in recent years, the country’s leadership on CCS and support of the Boundary Dam project demonstrates a clear continued commitment to the technology.

CAN UK CCS BECOME A REALITY?

In 2012 the UK’s Department of Energy and Climate Change (DECC) published a CCS development roadmap and backed this with the potential for financial support.8 While the government made the commitment to “work with industry to make CCS a reality”, and made £1 billion available, among other financial mechanisms, to support the capital expenditure for early CCS projects, it also made it clear that CCS must be made to be cost-effective and competitive with other low-carbon technologies. Thus, the UK CCS roadmap focused on identifying cost reductions through learning-by-doing and knowledge sharing.

UK electricity market reform (EMR) could play a critical role in supporting CCS development in the country. EMR aims to provide investors with a transparent, long-term, and stable investment environment for low-carbon energy technologies, as well as to ensure national energy security. Three policy instruments in the market reform—feed-in tariffs with contracts for difference (CfDs), a carbon price floor, and emission standard performance—have the most direct impact on CCS.9 The basic mechanism of CfDs is a pre-identified strike price to the generator for all eligible electricity generation. This strike price will operate against a reference wholesale market price: If the reference wholesale market price is lower than the strike price, the generator will be paid the difference between the two prices, whereas if the reference price is higher than the strike price the generator will have to pay back the difference. The carbon price floor aims to provide long-term certainty about the cost of carbon in the UK electricity generation sector and send clear pricing signals toward low-carbon generation. An emissions performance standard became law in 2014 at a level of 450 g CO2/kWh—requiring any new coal-fired power plants to use CCS.

The roadmap highlighted several advantages that UK has for advancing CCS: extensive geological storage capacity, especially under the North Sea; already existing clusters of emissions sources, such as power and industrial plants (these facilities could potentially share CCS infrastructure, such as pipelines); expertise in the offshore oil and gas industry that could be transferrable to the area of CO2 storage; and long-standing excellence in academic CCS research. The ultimate goal of this roadmap is to achieve cost-competitive CCS technology to a point that would enable widespread private-sector investment in CCS power stations and industrial facilities in the 2020s without government subsidies.

Potentially, UK commercial-scale CCS deployment could make major advances in the near term. Two projects have been shortlisted under the UK CCS Commercialisation Programme. The Peterhead Project in Aberdeenshire would capture about 1 Mtpa annually from an existing natural gas combined-cycle plant and store it under the floor of the North Sea. The White Rose project would capture about 2 Mtpa from a new 448-MW (gross) oxy-combustion coal-fired power plant. As these projects move forward they represent a major advancement toward deployment of CCS following the recommendations in the country’s technology development roadmap.

CHINA SPRINGS INTO ACTION

In recent years there has been a notable uptick in China’s interest and engagement on reducing emissions (both criteria emissions and CO2). For years the country has been replacing smaller, inefficient boilers with HELE technologies and has actively increased the efficiency of its coal-fired power plant fleet. It has also been working to diversify its energy mix to include more renewables, natural gas, and nuclear. China has made it clear that in the near term it plans to focus on CCUS as some revenue is necessary to move projects forward.

China’s approach to increasing its actions on climate change is supported by roadmaps, national plans, and early projects.

China’s approach to increasing its actions on climate change is supported by roadmaps, national plans, and early projects.

In 2011 the Ministry of Science and Technology (MOST) and the Administrative Center for China’s Agenda 21 published the China CCUS Technology Development Roadmap, which outlined policies and actions necessary to advance CCUS in China. Although not a roadmap by title, in 2013 the National Development and Reform Commission (NDRC) published a notice stating that “all regions and departments should strengthen support and guidance for CCUS pilot and demonstration, based on the climate change program in the national 12th Five-Year Plan….”10 Six primary working tasks were listed in the notice, including:

  1. Develop pilot and demonstration projects along the CCUS technology chain.
  2. Develop CCUS demonstration projects and sites.
  3. Explore and establish financial incentive mechanisms.
  4. Strengthen strategic research and planning for CCUS development.
  5. Promote CCUS standards and regulation.
  6. Strengthen capacity building and international collaboration.

There are many research, pilot, and demonstration-scale projects underway in China. One of the largest such projects is Shenhua’s 0.1-Mtpa CCS demonstration project in Ordos, Inner Mongolia, with 245,000 tonnes of CO2 stored to date.

In terms of large projects, the Global Carbon Capture and Storage Institute (GCCSI) reports that there are 11 such projects at various stages of completion (none are operating yet). Two significant potential projects are the Yanchang Integrated Carbon Capture and Storage Demonstration Project (nearly 0.5 Mtpa potentially operational in 2016–2017) using CO2 from a chemicals-related production plant and post-combustion capture from the Sinopec Shengli power plant (1.0 Mtpa potentially operational in 2017).4 Various industries, including coal conversion facilities, in China offer the ability to use relatively inexpensive CO2 for first-mover CCUS projects. If most of these large-scale projects move forward to operation, China could quickly become a leader in CCUS deployment.

OTHER CCS DEVELOPMENTS

Some countries with large CO2 emissions do not have active CCS roadmaps. For example, while India’s per capita emissions remain much less than those in developed countries, the gross national emissions could grow rather quickly over the next decade as the country attempts to bring electricity to all its people, highlighting the importance of employing HELE technologies. Although India does not have an official CCS roadmap, with assistance from GCCSI, India conducted a CCS scoping studying in 2013.11 The subsequent report concluded that CCS is a viable mitigation option in India, but the lack of reliable storage data leads to uncertainty. In addition, very few studies have quantified the overall cost of capturing and storing CO2 in India. Financial risks and legal liabilities for CCS development are also under-studied. Thus, there is a strong need for capacity building among all links in the CCS industrial chain if India is to consider CCS in the future.

Australia also does not have a current national CCS roadmap but has three large-scale projects in various stages of planning and execution and boasts a strong history of research in the area. The Gorgon CO2 Injection Project, the world’s largest CO2 injection project into a deep saline formation, could begin storing as much as 4 Mtpa after 2016 and be a leader in the field.

GLOBAL PROGRESS

Despite roadmap goals and the progress made in some key projects, the overall development and deployment of CCS is behind schedule, but within reach of IEA’s 2013 roadmap goals. Regulatory drivers and policy and funding parity, under which CCS would be funded on par with its emissions reduction potential compared to other low-carbon technologies, are generally lacking. While roadmaps may show the way to CCS deployment, their recommendations and timelines must be followed if the technology is to reach its full potential.

REFERENCES

  1. International Energy Agency (IEA). (2009). Technology roadmap: Carbon capture and storage, www.iea.org/publications/freepublications/publication/technology-roadmap-carbon-capture-and-storage-2009.html
  2. Intergovernmental Panel on Climate Change (IPCC). (2014). Working Group III, Climate change 2014: Mitigation of climate change, report.mitigation2014.org/drafts/final-draft-postplenary/ipcc_wg3_ar5_final-draft_postplenary_technical-summary.pdf
  3. IEA. (2013). Technology roadmap: Carbon capture and storage, www.iea.org/publications/freepublications/publication/TechnologyRoadmapCarbonCaptureandStorage.pdf
  4. Global Carbon Capture and Storage Institute (GCCSI). (2015). Large scale projects, www.globalccsinstitute.com/projects/large-scale-ccs-projects#overview
  5. The White House, Office of the Press Secretary. (2014, 11 November). U.S.-China Joint Announcement on Climate Change, www.whitehouse.gov/the-press-office/2014/11/11/us-china-joint-announcement-climate-change
  6. DOE/NETL. (2010). DOE/NETL carbon dioxide capture and storage RD&D roadmap, www.netl.doe.gov/File%20Library/Research/Carbon%20Seq/Reference%20Shelf/CCSRoadmap.pdf
  7. Natural Resources Canada. (2006). Canada’s CO2 capture & storage technology roadmap, publications.gc.ca/collections/collection_2014/rncan-nrcan/M154-16-2008-eng.pdf
  8. UK Department of Energy & Climate Change (DECC). (2012). CCS roadmap: Supporting deployment of carbon capture and storage in the UK, www.gov.uk/government/uploads/system/uploads/attachment_data/file/48317/4899-the-ccs-roadmap.pdf
  9. DECC. (2012). Electricity market reform: policy overview, www.gov.uk/government/uploads/system/uploads/attachment_data/file/48371/5349-electricity-market-reform-policy-overview.pdf
  10. National Development and Reform Commission. (2013). Notice of the National Development and Reform Commissions (NDRC) on promoting carbon capture, utilization and storage pilot and demonstration (translated by the GCCSI), hub.globalccsinstitute.com/sites/default/files/publications/102106/notice-national-development-reform-commission-ndrc.pdf
  11. GCCSI. (2013). India CCS scoping study: Final report, www.globalccsinstitute.com/publications/india-ccs-scoping-study-final-report

 

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Don’t Count Coal Out of a Lower-Emission U.S. Energy Mix

By Fredrick Palmer
Principal, Green Coal Solutions, LLC
Frank Clemente
Professor Emeritus of Social Science, Penn State University

The 21st Session of the Conference of the Parties (COP21) to the United Nations Framework Convention on Climate Change (UNFCCC) will be held in Paris in December 2015. The goal of COP21 is to achieve a legally binding and universal agreement on climate, capping anthropogenic greenhouse gas emissions by 2020 and reducing them to near zero toward the end of the century. The U.S. administration has assured its fellow COP21 negotiators that its commitments are achievable and legal and that it is pursuing national-level policies, such as the Clean Power Plan (CPP), to support those commitments. However, policies at the national level have technical challenges based on the current generation mix and transmission grid, face considerable legal opposition, and must withstand the test of time far longer than the current administration will be in office. Under all circumstances, the authors of this article believe the U.S. should increase the role of cleaner coal technologies as a principal component of achieving its international climate goals while ensuring the country and electricity consumers can continue to rely on a diverse, reliable, and cost-effective energy mix in a low-emissions future.

THE EVOLVING U.S. ENERGY MIX

The ability of the U.S. to meet any commitments made at COP21 is largely contingent on its energy sector. While energy demand in the U.S. has been mostly flat in recent years, there is reason to believe that growth will be observed over the long term. For example, the U.S. population continues to grow. The United Nations Population Division projects that there could be nearly 80 million new Americans by 2050.1 In essence, another population “boom” is yet to come. In the past, the U.S. has relied heavily on coal to meet growing demand. For example, when the U.S. added 105 million people to the population during 1970–2010, coal production increased 100%—by over 500 million tons used each year—and coal provided half of the incremental electric power.2 Today the incremental additions will be more diverse—the U.S. Energy Information Administration’s Annual Energy Outlook (AEO) 2015 projected that incremental electricity capacity will be split equally between renewables and natural gas combined cycle.3 However, the same AEO projected that electricity generation from coal will remain largely flat and still provide over 1660 billion kWh in 2040. By comparison, in 2040 renewables and natural gas combined would contribute about 1200 and 805 billion kWh, respectively (projections exclude the relatively small role of combined heat and power in the U.S.).4 These projections are not inclusive of any regulations, including the CPP.

While the U.S. has relied on coal for decades, the country still has extensive proven coal reserves (shaded).

While the U.S. has relied on coal for decades, the country still has extensive proven coal reserves (shaded).

COP21 AND THE CLEAN POWER PLAN

Through its intended nationally determined contribution, the U.S. has committed to reduce emissions 26–28% by 2025, compared to 2005 levels. Under the U.S. Constitution, if COP21 produced a binding treaty that required the U.S. to meet this commitment, ratification by two thirds of the U.S. Senate would be required. Based on the current makeup of the U.S. Senate, ratification of such a climate treaty is extremely unlikely. Thus, the U.S. administration and negotiators have been careful to avoid any use of the word “treaty”, and as a result any agreement reached by the U.S. will not be binding by definition. Instead, national-level regulations are being advanced through the Environmental Protection Agency (EPA).  Namely, the CPP as well as several other measures that are primarily focused on heavy duty vehicles, end user efficiency, and other approaches outside the scope of this article.

The Clean Power Plan faces legal challenges that will likely be decided by the Supreme Court.

The Clean Power Plan faces legal challenges that will likely be decided by the Supreme Court.

The CPP was issued by the executive branch through the EPA under the Clean Air Act and was released on 3 August 2015 after four million comments on the proposed version had been submitted, demonstrating intense societal interest in the U.S. electric sector and coal-based electric generation. The CPP sets a goal to reduce carbon emissions from the power sector 32% below 2005 levels by 2030. To accomplish the emissions reductions the EPA directs the states to compose their own plans to meet compliance based on various low-emission electricity generation technologies, including renewables, energy efficiency, natural gas, nuclear, and carbon capture and storage (CCS)—with CCS requirements being lower compared to the CPP proposal.5 States must submit their initial plans to achieve the emissions reductions to the EPA by September 2016 and two-year extensions can be requested to allow for additional time to finalize the plans. The compliance averaging period begins in 2022.

The U.S. Energy Information Administration previously projected that the proposed CPP would decrease the role of coal in the U.S. electricity mix (no projections were available as this article went to press for the revised CPP).6 Natural gas gains could be displaced by some renewables as the CPP aims to have renewables account for 28% of electricity capacity in 2030.

A robust coal-generation presence in a diverse energy mix helped the U.S. maintain lower electricity rates historically, while reliably meeting demand. Renewables are not able to provide baseload electricity and natural gas has been subject to historical price spikes, will require additional pipeline infrastructure to continue to grow, and cannot easily be stored in the case of a major demand increase (such as the extreme cold snap experienced in early 2014 that sent natural gas prices soaring). Thus, even under the restrictions from the CPP, coal will be maintained in the U.S. energy mix.

Notably, the CPP faces legal challenges and many people are of the view that it will not withstand legal scrutiny, particularly given the constitutional questions that have been raised. With 26 states voicing opposition and both states and organizations set to bring lawsuits against CPP, litigation will begin immediately. Due to the time involved with filing and completing such lawsuits, it is highly unlikely that the CPP will actually be finalized until after President Obama’s tenure in office is over. Phase 1 emissions reductions (20%) are due by 2022 and Phase 2 emissions reductions are due by 2030 (32%). Since the CPP was not passed by Congress and signed into law by the president, it is subject to the will of future presidents. There will be two presidential elections by 2022 and four by 2030. Will all those elected president between now and 2030 fully support the implementation of the CPP? If not, it may not be fully executed and could be reversed. Thus, although the recently released CPP has been termed “final”, considerable challenges remain.

FINDING A ROLE FOR CLEANER COAL TECHNOLOGIES

The U.S. has been a global leader in the development and deployment of cleaner coal technologies. Coal-based electricity in the U.S. has increased 183% since 1970, while regulated criteria emissions decreased about 90% per unit of generation.7 The same level of success can be achieved using low-carbon emission coal technologies.

New pulverized-coal combustion systems utilizing supercritical technology achieve much higher efficiencies than traditional plants. Ultra-supercritical plants offering even higher efficiencies are now considered state of the art, but the U.S. has only one such operating plant. Using such technologies, there is much room to increase the energy efficiency of the U.S. fossil fuel fleet. For example, the overall thermal efficiency of the U.S. fleet of coal-fired power plants is only about 33%, although the best 10% of plants in the country have an efficiency of 37%. Boosting the efficiency of the U.S. fleet to 36% would reduce emissions 175 million tonnes per year.8 Though the current regulatory framework may not fully incentivize it, high-efficiency coal-fired power plants could play an important role in reducing emissions. In addition, improving the efficiency of U.S. coal-fired power plants could serve as a steppingstone to development of CCS (and CCUS with utilization), which is broadly recognized as a prerequisite to meeting global climate policy goals.

U.S. coal-fired plant provide reliable and affordable electricity.

U.S. coal-fired plant provide reliable and affordable electricity.

Seven of the 14 CCS projects operating in the world are on U.S. soil. Although progress on CCS has been slow, the U.S. is a leader in the development of the technology. The country must find a way that CCS on coal and natural gas facilities can contribute to a low-emissions future. This approach would enable reliable, domestically produced, safe baseload generation even under carbon emission constraints much stronger than the U.S. has committed to ahead of COP21.

U.S. COAL IN THE PAST, PRESENT, AND FUTURE

Coal has played a strong role in the U.S. historically for good reason. Reliable and affordable power from coal gave U.S. manufacturers a strong advantage. Indeed, the American Heartland was built and continues to rely on coal. Of the contiguous 48 states, 31 obtain more than 25% of their electricity from coal and 17 states obtain more than 50% of their electricity from coal.9 Thus, large segments of the country will be disproportionally impacted by dramatic decreases in coal power generation. Even the full closure of America’s coal-fired power plant fleet, a scenario not considered feasible by any major energy forecasting organization, would result in only a 1/20th of one-degree temperature change globally.

While the COP21 negotiations are unlikely to deliver specifics in how emissions reduction commitments will be achieved, the regulatory framework in the U.S. is already unfolding as the CPP moves forward. We urge those negotiators, as well as domestic regulators, to consider the important role that coal has and will continue to play in the U.S. and elsewhere. Based on our decades of experience, the authors of this article believe that the U.S., like every other country, is going to put in place policies that are in the best interest of its citizens. In our opinion, that means that the U.S. is going to use more coal in the future than it does today, and minimize the environmental impact with 21st century technologies. Cleaner coal technologies have delivered in the past and can do so again to ensure coal can be a part of a low-emissions future.

REFERENCES

  1. United Nations. (2014). World urbanization prospects: 2014 revision, esa.un.org/unpd/wup/Highlights/WUP2014-Highlights.pdf
  2. U.S. Energy Information Administration (EIA). (2012, 27 September). Total energy: Coal consumption by sector, 1949–2011 (million short tons), www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb0703
  3. EIA. (2015). Annual energy outlook 2015: Electricity generating capacity, www.eia.gov/beta/aeo/#/?id=9-AEO2015
  4. EIA. (2015). Annual energy outlook 2015: Electricity supply, disposition, prices, and emissions, www.eia.gov/beta/aeo/#/?id=8-AEO2015
  5. The White House, Office of the Press Secretary. (2015,
    3 August). Fact sheet: President Obama to announce historic carbon pollution standards for power plants, www.whitehouse.gov/the-press-office/2015/08/03/fact-sheet-president-obama-announce-historic-carbon-pollution-standards
  6. EIA. (2015). Analysis of the impacts of the Clean Power Plan, www.eia.gov/analysis/requests/powerplants/cleanplan/
  7. DOE, Office of Fossil Energy. (2012, June). Fossil energy research benefits: Clean coal technology demonstration program, energy.gov/sites/prod/files/cct_factcard.pdf
  8. U.S. Department of Energy (DOE), National Energy Technology Laboratory. (2010). Improving the thermal efficiency of coal-fired power plants in the United States, www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEfficCoalFiredPowerPlants-TechWorkshopRpt.pdf
  9. EIA. (2015). Electric power monthly, February, Table 1.6.B. Net generation by state, by sector, year-to-date through December 2014 and 2013 (Thousand Megawatthours), Table 1.7.B. Net generation from coal by state, by sector, year-to-date through December 2014 and 2013 (Thousand Megawatthours), www.eia.gov/electricity/monthly/current_year/february2015.pdf

THE NATIONAL COAL COUNCIL OFFERS A WEALTH OF DATA

One of the most significant resources available to understand the importance of coal to the welfare of the American people resides in a series of reports the National Coal Council (NCC) has prepared and submitted to the Secretary of Energy over the last decade. Based in Washington, D.C., the NCC was established in 1984 as a Federal Advisory Committee to the U.S. Secretary of Energy. The NCC provides advice and recommendations to the Secretary on general policy matters relating to coal and the coal industry. The NCC’s Coal Policy Committee develops prospective topics for the Secretary’s consideration. Over the past decade the Council has produced a series of eight extensive empirical studies. These reports, prepared by leading coal and energy researchers, have dealt with the full range of scientific and engineering aspects of coal technologies, including coal utilization, environmental control, and coal conversion.

NCC Cover

Studies of the National Coal Council (2006–2015)
2006: Coal: America’s Energy Future
2007: Technologies to Reduce or Capture and Store Carbon Dioxide Emissions
2008: The Urgency of Sustainable Coal
2009: Low-Carbon Coal
2011: Expedited CCS Development: Challenges & Opportunities
2012: Harnessing Coal’s Carbon Content to Advance the Economy, Environment, and Energy Security
2014: Reliable & Resilient – The Value of Our Existing Coal Fleet
2015: Fossil Forward – Revitalizing CCS: Bringing Scale and Speed to CCS Deployment

The work of the NCC has extensively documented the unique attributes of America’s coal resources: e.g., abundance, accessibility, affordability, security, versatility, sustainability, and amenability to cleaner coal technologies. Much of this information is transferable to the world at large. For more information, visit NCC at
www.nationalcoalcouncil.org/

 

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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Economic Development Status Is a Lingering Challenge for COP Negotiations

By Jeremy Bowden
Contributing Author, Cornerstone

Tensions between rich and poor countries have long been among the key fault lines preventing any significant global agreement on climate change. At the heart of the issue is the perception of relative responsibility and, especially for poorer countries, a strong desire at the national level to find a balance between development and climate goals. Representatives of poorer countries readily point out that more wealthy countries are to blame for nearly all historical emissions. Relatively undeveloped economies have low historic emissions and their current per capita emissions intensities have yet to catch up with those in rich countries. In addition, poverty levels in developing countries are much higher and economic development is therefore a priority. Thus, developing countries claim that richer countries should make the first substantial cuts, as well as pay significant compensation (financial and through technology transfer) to support emissions cuts in developing countries.

Most developing countries assert their right to grow their economies using fossil fuels, a path already taken by most developed countries. Due to its low cost and widespread geographical distribution, the energy source of choice for developing countries is often coal. If developing countries’ emissions are to be curbed, wealthier countries would be required to provide financial support, so that adopting low-emission technologies would not stall much-needed
economic growth.

The argument from developing countries is not unfounded. A recent study in the Environmental Research Letters journal1 showed that, based on per capita calculations, the UK is most responsible on a historic basis for greenhouse gas (GHG)  emissions, followed closely by the U.S., Canada, Russia, and Germany (see Figure 1). China, currently the world’s largest emitter, lies in 19th position for cumulative emissions.

FIGURE 1. Historical GHG emissions per capita (non-dimensionalized by maximum from UK)

FIGURE 1. Historical GHG emissions per capita (non-dimensionalized by maximum from UK)

Juxtaposed to this position is the trend, often highlighted by richer countries, of rapid industrialization and rising emissions in the developing world. They accurately point out that unless action is taken by all, the international goal of limiting a global temperature increase to 2˚C will be unachievable.

A major hurdle is the concern from some richer nations that burdening their economies with heavy environmental regulations might disadvantage them when competing with deregulated markets. Thus, an approach to maintain transparency between Parties, a challenge in and of itself, is a vital component of international collaboration on climate change mitigation. This may be particularly challenging as China, for example, has fought against emissions monitoring as part of the United Nations process.2

India’s position can also provide key insight into the challenge. The country has about 300 million people without any access to electricity. Prime Minister Modi has committed to eliminating energy poverty as quickly as possible and is therefore developing the country’s vast solar and coal resources. While the country’s emissions will certainly grow in the near term, India is looking for help to pay for increased renewables and high-efficiency, low-emissions (HELE) coal-fired power plants. In fact, the Indian Environment Minister recently said that a global deal on climate in 2015 will depend on commitments to finance from developed countries.3

The allocation or transfer of public funds from richer countries must compete with other domestic, shorter term demands. Some corporations—particularly in the U.S. and recently in Japan—have discouraged their governments from signing on to any commitments for fear of damaging established interests and investments. Finding the right political balance at the national level to support international negotiations could be a major concern.

A paramount challenge for the Paris negotiations is that any deal must be adopted by all Parties. The agreement from the last round of climate talks, COP20 at Lima in 2014, highlighted the divide by economic development status. The 2014 talks simply reflected the positions of the two camps, with statements that included calls by developing nations that industrialized nations should take the lead in reducing emissions as well as those from industrialized nations that all parties have a responsibility to reduce emissions. The deal lists a number of policy options reflecting current disputes, on which negotiators will have to compromise to reach a final agreement at COP21. Such an agreement would include specifying national contributions and commitments needed to achieve the global target.

While a divide remains between countries of different development status, the gap may be lessening. It is particularly notable that the U.S. and China, the world’s two largest emitters, held separate talks in the run-up to COP21. Perhaps the U.S.-China commitments can lay the groundwork for a larger agreement in Paris. Although the challenge is daunting, and many critical details remain to be worked out, Parties of different development statuses are taking steps toward the global agreement on climate that has been elusive for so long.

The energy, infrastructure, and development challenges that poorer countries face must be addressed at COP21.

The energy, infrastructure, and development challenges that poorer countries face must be addressed at COP21.

UNDERSTANDING EMISSIONS TRENDS

Some progress is being made in curbing emissions in developed countries already. For example, up to 2013 the U.S. decreased emissions for five consecutive years, before an increase of 2.5% that year. Other OECD countries also mainly show decreases or minor increases below 2%. The EU’s CO2 emissions, which started to decrease in 2006, continued to decrease by 1.4% in 2013, at a faster rate than what was observed in 2012. CO2 emissions in emerging economies mainly increased in 2013. For example, increases were observed in India (4.4%), Brazil (6.2%), and Indonesia (2.3%). Based on commitments made to date, emissions from India and China combined are predicted to account for nearly three times that of the EU and U.S. combined by 2030—well over one third of the world’s total emissions, according to a recent report from the Economic & Social Research Council Centre for Climate Change Economics and Policy.4

However, looking at net emissions and general trends does not tell the entire story. It is also important to consider per capita emissions, which are generally significantly lower in emerging economies. Even in China, the world’s manufacturing center (some of whose emissions could be considered exported as companies have shifted their manufacturing work to the country), in 2013 the emissions per capita level of 7.4 tonnes per person exceeded the mean EU level of 7.3 tonnes for the first time, but still remained under half the U.S. level of 16.6 tonnes. Notably, China has been successfully decreasing the emissions intensity of its economy—by 3.1% in 2013.

Emission trends give yet another example of how the divide is clear. There are many Parties that will not be able to commit to major reductions in emissions in the near term and reducing emissions versus business as usual will require financial support. This is due not to a lack of will or concern about climate change, but rather to a greater concern to eradicate poverty.

INDCS: RAISING THE STAKES

In advance of COP21, countries are indicating publically their intended post-2020 climate action commitments in the form of Intended Nationally Determined Contributions (INDCs). According to the agreement reached in Lima, INDCs must be “fair and ambitious” in light of a country’s historical responsibility, current level of emissions, emissions trajectory, per capita emissions intensity, and financial capability. However, exactly how the INDCs should be worked out remains in dispute. In 2014, calculators aimed at evaluating what level of cuts various countries should make were released by researchers, but have not gained widespread support. Other suggestions to assess how much countries should cut emissions include a concept spearheaded by Brazil, which puts each one in a series of three “concentric circles”, with the poorest on the outside contributing the least in terms of cuts, while at the center are the richest and longest term emitters, which should contribute the most.5 While this approach attempts to blur the lines between Parties’ economic development status, the fundamental barriers remain.

Another fault line revolves around INDC scope. The EU and the U.S. have been unable to agree on what year to compare their emissions reductions against (1990 for the EU and 2005 for the U.S.), but both want the INDCs to be largely focused on tackling their own emissions. However, developing countries are pushing for pledges to include aid for adaptation and mitigation, without which they would have insufficient means to finance low-emission development. In fact, INDCs from poor countries often include two commitments: what could be done with financial support and what they could afford to do without it.

There has been movement to provide support to poorer countries. A Green Climate Fund has been set up providing US$10 billion per year, along with other conduits, such as the Clean Development Mechanism (CDM), which allows industrialized countries to invest in climate-friendly projects in poor countries and earn carbon credits in exchange to help meet their targets. Overall the financial transfer from all sources in the rich world to developing countries is pencilled in to rise to US$100 billion a year by 2020, although such commitments may not be fully backed in the INDCs for COP21. There is also the matter of from where the $100 billion in low-carbon financing will come. National leaders have stressed that contributions from the public sector (i.e., taxpayers) will be minimal, but the question remains as to whether the private sector can and will provide this level of funding and under what mechanisms.

Although their relative magnitude may be difficult to decipher, the INDCs are being submitted—29 submissions representing 57 Parties had been filed at the time this publication went to press. The world’s three largest emitters have all submitted commitments. The EU’s INDC puts forward a legally binding commitment to reduce its overall emissions at least 40% below 1990 levels by 2030. The INDCs of the U.S. and China largely reflect their previous talks—with the U.S. committed to reducing emissions 26–28% by 2025 and China reducing carbon intensity of GDP by 60–65%, both compared to 2005 levels. Other large emitters that had submitted INDCs at the time of publication include Russia, Mexico, and Canada.

THE ROLE OF LOW-EMISSION TECHNOLOGIES

Regardless of their relative economic development status, all Parties will need increased deployment of low-emission technologies to meet commitments made at COP21. The International Energy Agency has outlined six tranches required to limit climate change to 2˚C at the lowest costs. These include renewables, carbon capture and storage (CCS) (including utilization), improved demand and supply side efficiency, end-use fuel switching, and increased nuclear power. While all tranches are important, according to the IPCC, if CCS is not included in the low-emission energy mix, the costs will increase more than if any other tranche is limited—to the tune of a 138% increase in costs (median estimate).6 HELE technologies may also be an important step toward deployment of CCS.

Low-emission technologies, including high-efficiency power plants and CCS, must be important building blocks to achieve emissions reductions.

Low-emission technologies, including high-efficiency power plants and CCS, must be important building blocks to achieve emissions reductions.

The move to deploy low-emission technologies has already begun and, in some cases, emerging economies are leading the way. For example, China is already the world’s largest investor in renewables, with plenty of space to increase renewable utilization. In addition, the country is replacing smaller, inefficient coal-fired power plants with larger, high-efficiency units. The country also looks to transition its economy toward more growth in the less energy-intensive service sector. However, even if China’s coal use is capped by 2020 as has been suggested, it is likely to be capped at an amount over 3.5 billion tonnes per year, highlighting the need to utilize clean coal technologies to meet any climate commitments. China is already working to improve the efficiency of its coal fleet, and has recently increased its involvement in carbon capture, utilization, and storage research.

TOUCH AND GO

COP21 may not deliver the deep, universal commitments hoped for by some. However, if it can provide a framework under which the world can work together to deploy low-emission technologies, reduce emissions over time, and help the poorest countries to grow their economies, then it could be considered a monumental success.

REFERENCES

  1. Matthews, D., Graham, T.L., Keverian, S., Lamontagne, C., Seto, D., & Smith, T.J. (2014). National contributions to observed global warming. Environmental Research Letters, 9, iopscience.iop.org/1748-9326/9/1/014010/pdf/1748-9326_9_1_014010.pdf
  2. Adams, M. (2014, 15 December). China’s double-edged pact. New York Times, www.nytimes.com/2014/12/16/opinion/chinas-double-edged-pact.html
  3. McGregor, I. (2014, 5 November). Global climate change policy: Will Paris succeed where Copenhagen failed?, www.e-ir.info/2014/11/05/global-climate-change-policy-will-paris-succeed-where-copenhagen-failed/
  4. Boyd, R., Stern, N., & Ward, B. (2015). What will global annual emissions of greenhouse gases be in 2030, and will they be consistent with avoiding global warming of more than 2°C?, www.lse.ac.uk/GranthamInstitute/wp-content/uploads/2015/05/Boyd_et_al_policy_paper_May_2015.pdf
  5. Responding to Climate Change. (2015, 6 March). UN climate body needs “automatic” system to split right and poor, www.rtcc.org/2015/03/06/un-climate-body-needs-automatic-system-to-decide-whos-rich-and-poor/
  6. Intergovernmental Panel on Climate Change. (2014). Working Group III, Climate change 2014: Mitigation of climate change, report.mitigation2014.org/drafts/final-draft-postplenary/ipcc_wg3_ar5_final-draft_postplenary_technical-summary.pdf

 

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Deploying Clean Energy in Asia: An Exclusive Interview With Ashok Bhargava of the Asian Development Bank

By Holly Krutka
Executive Editor, Cornerstone

As Director of the Energy Division in the East Asia Department of the Asian Development Bank (ADB), Ashok Bhargava oversees energy-sector operations in the People’s Republic of China (PRC) and Mongolia. He is an electrical engineer with a Master’s Degree in Business Administration and has more than 33 years of energy-sector experience in the Asia-Pacific region and more than 13 years’ experience in the PRC energy sector.

Ashok Bhargava, Director of the Energy Division, East Asia Department, Asian Development Bank

Ashok Bhargava, Director of the Energy Division, East Asia Department, Asian Development Bank

His direct ADB project experience includes innovative, first-of-its-kind, low-carbon technology projects such as integrated gasification combined-cycle (IGCC), concentrated solar power (CSP), carbon capture, utilization, and storage (CCUS), shale gas, and distributed renewable energy. As Team Leader, he processed the PRC’s first multi-tranche financing facility (MFF) in 2006 and its first IGCC power plant in 2010.

Currently, Mr. Bhargava is also Chair, Energy Sector Group, providing leadership and guidance to ADB’s energy-sector operations. He represents ADB in the Carbon Sequestration Leadership Forum, the Global CCS Institute, and the Clean Energy Ministerial CCUS working group.

An Australian national, Mr. Bhargava worked with a large-infra-structure consulting firm, a multinational power company in Australia, and a large public-sector generation utility in India, prior to joining ADB.

Q: What are the objectives of the Asian Development Bank that ultimately drive its investment decisions?

A: The Asian Development Bank (ADB) was founded in 1966. It has 67 member countries of which 48 are regional and 19 are non-regional members. ADB aims for an Asia and Pacific free of poverty. While it has achieved a significant reduction in extreme poverty, approximately 1.4 billion people in the region are still poor.

The ADB aims to reduce poverty through inclusive growth in the region.

The ADB aims to reduce poverty through inclusive growth in the region.

Since its inception, ADB has been dedicated to improving people’s lives in Asia and the Pacific. By targeting its investments wisely, in partnership with its developing member countries and other stakeholders, ADB aims to alleviate poverty and help create a region in which everyone can share in the benefits of sustained and inclusive growth.

ADB assistance is provided through loans, grants, policy dialogue, technical assistance, and equity investments. Our individual investments are rigorously assessed on a set of quality dimensions to check their strategic fit with our country partnership strategies and national programs, their development outcomes and impacts, techno-economic feasibility, social and environmental safeguard compliances, risks, achievability, and sustainability of development outcome and impacts. In 2014, ADB’s operations totaled nearly US$23 billion, including co-financing of US$9 billion.

Q: What percentage of funding from ADB is directed toward energy-related programs? Can you explain how adequate, affordable, and reliable power is important to achieve sustained and inclusive growth?

A: Energy is a core priority area of ADB assistance and operations throughout the region. During the period 2008–2014, about US$28 billion, or a quarter of total ADB financing, were for energy-related programs. In 2014, out of the total ADB financing operations of US$23 billion, about a quarter—US$6.6 billion—were for energy-related projects. Since 2009, ADB has targeted an annual commitment of US$1 billion lending for clean energy, which has since doubled from 2013 to US$2 billion annually.

About 600 million people in the Asia-Pacific region lack access to basic electricity. There are strong correlations between access to electricity and poverty. Under ADB’s Energy for All initiative, we are supporting regional governments’ goals and targets to provide universal access to electricity. So far, ADB assistance under Energy for All has directly brought electricity to more than 10 million homes that did not previously have electricity. A 2010 independent study on rural electrification in Bhutan found that electrification of households (i) increases nonfarm income, allowing families to pursue microenterprises; (ii) improves health conditions by reducing the use of polluting sources of energy, such as fuelwood, kerosene, and candles; and (iii) supports education for children by allowing for safer travel to and from school and the completion of homework at night.

Reliable and adequate electricity supply is essential for the economic growth and well-being of people across the region. Many countries in the Asia-Pacific region face chronic electricity shortages that constrain economic growth. As an illustration, acute electricity shortages in Pakistan of up to 20 hours per day have crippled economic growth, leading to civil strife and factory closures. One estimate suggests that the lack of electricity is causing at least a 2% reduction in Pakistan’s gross domestic product.

A Pakistani shopkeeper rents lanterns to keep his business open during electricity load shedding.

A Pakistani shopkeeper rents lanterns to keep his business open during electricity load shedding.

Q: ADB supports projects for electricity production from diverse sources. Can you describe the benefits of a diverse energy mix in the region?

A: A diverse source of electricity is essential to overcome demand-supply variability during the course of the day and seasons. Hydropower and natural gas plants are commonly used to supply peaking electricity because they can start and generate electricity up to their full load capacity very rapidly. But unlike coal, natural gas and hydropower resources are unevenly distributed across the Asia-Pacific region. Moreover, importing and transporting natural gas are capital intensive. Thus, coal is also used in many countries for peaking power.

Hydropower plants are being deployed, where possible, as part of a diverse energy mix supported by the ADB.

Hydropower plants are being deployed, where possible, as part of a diverse energy mix supported by the ADB.

Diverse sources for electricity production are also an energy security imperative. Since electricity demand is rising rapidly across the region, many large economies with considerable coal reserves have used coal to rapidly build up new capacity. Many countries in the region also rely on fossil fuel imports to produce electricity. Yet, they have substantial indigenous renewable energy sources which they can deploy. Moreover, growing environmental and climate change constraints are also driving investments in new and alternative sources of electricity production. ADB promotes a diversified energy mix with a higher share of renewable and low-carbon sources to meet the goals of reliable electricity supply with minimal environmental and climate change footprints.

Q: In 2013, loans were approved to support the Jamshoro Power Generation Project in Pakistan. Can you describe this project, its benefits, and the reasons to support it?

A: Under its Energy Policy 2009, ADB has been selectively supporting new coal-based power plants in its developing member countries after a careful consideration of alternate scenarios. Project-specific investment decisions for coal-based plants are made when the economic rationale is overwhelming. In 2012, in Pakistan, heavy fuel oil (HFO) was the major source (34%) of electricity in the generation mix followed by hydropower (32%), natural gas (26%), nuclear (5%), high-speed diesel (1.65%), and coal (0.07%) with the balance made up of wind power and power imports. The demand-supply gaps for electricity were continuously increasing and resultant electricity shortages were crippling the economy. In addition, HFO reliance was driving up the cost of electricity and worsening the electricity sector’s financial health. With the dwindling domestic gas supply and much longer gestation period for hydropower, new coal-based capacity was found to be the least-cost option and most suitable economic choice to urgently address the demand-supply gap.

ADB approved financing for a coal-based supercritical plant at Jamshoro with enhanced pollution control measures to reduce emissions. The first of two 660-MW units is entirely financed by ADB in partnership with the Islamic Development Bank with the second unit expected to leverage further co-financing. On completion, the two units will produce 8400 gigawatt hours (GWh) of electricity each year. This will allow fuel cost savings of US$535 million annually due to avoided HFO import. ADB also launched a high-level study to assess the potential for carbon capture and storage (CCS) in Pakistan and sought design provisions in the project for potential CCS retrofit when it is economically feasible. In short, ADB financing not only addressed the core-sector problem of capacity shortages but leveraged introduction of a highly efficient, low-emissions plant, representing the first time such a plant will be installed in Pakistan.

Although there are many HELE coal-fired power plants in the Asia-Pacific region, the Jamshoro power plant will be the first such facility in Pakistan.

Although there are many HELE coal-fired power plants in the Asia-Pacific region, the Jamshoro power plant will be the first such facility in Pakistan.

Q: Can you elaborate further on any other high-efficiency, low-emissions, coal-fueled projects currently being supported by the ADB and the importance of such technologies?

A: Apart from climate change impacts, the prevailing poor air quality in urban areas mainly in coal-dependent large economies such as India and the PRC is a growing concern. Modern high-efficiency, low-emissions (HELE) coal-based electricity generation plants with enhanced pollution control measures can address these twin challenges. On one hand, improved efficiency will reduce carbon footprints; on the other hand, some advanced HELE plants can approach the criteria air pollution levels of a traditional natural gas plant. In the PRC, ADB financed the first 250-MW integrated gasification combined-cycle (IGCC) power plant at Tianjin, which is in successful operation. If coal continues to be a fuel of choice for electricity generation, HELE plants offer a pragmatic policy approach to address the energy trilemma of energy security and access, economic development, and environmental issues. Combined with CCS, these plants can cut carbon dioxide (CO2) emissions significantly. ADB is currently appraising a pilot CCS project at the Tianjin IGCC plant.

Q: The ADB has recently supported several CCS-focused projects in developing countries. Can you explain why the development of CCS is critical for the ADB-covered region? 

A: Fossil fuel dependency in Asia, especially on carbon-intensive coal, is well known and documented. ADB’s developing member countries include some of the largest coal consumers globally, such as the PRC, India, and Indonesia. Thereby these countries are some of the largest CO2 emitters. These countries have prioritized energy efficiency improvement and aggressive renewable energy deployment to reduce growth of their CO2 emissions. The PRC now invests more in renewable energy capacity addition than in coal-based power plants and aims to cap coal use by 2020. However, weaning away from coal has been rather slow. In fact, significant new capacity for coal-based power plants will come online in the next 10–25 years. Since CCS is the only near-commercial technology that can cut up to 90% of CO2 emissions from coal-based plants, CCS becomes essential for meeting anticipated long-term CO2 emission goals in the PRC and other similar large economies of the region.

ADB has set up a CCS-dedicated fund with contributions from the Global CCS Institute and the UK government to support capacity development, undertake strategic analyses to identify a role for CCS in its developing member countries, implement pilot CCS projects to enhance understanding of CCS, and prepare large-scale fully integrated CCS projects. In the PRC, a roadmap for CCS demonstration and deployment was recently finalized which identified significant low-cost (<$25/ton CO2) opportunities to demonstrate CCS. It also highlighted the essential role of CCS in the low-carbon portfolio of technologies to meet an anticipated long-term carbon-constrained world.

 

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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