From FGD to CCS

27th February 2015


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IEMA

Peter Brown finds out what lessons carbon capture and storage can learn from the rollout of flue-gas desulphurisation technology

Launching phase two of the government’s plans to develop carbon capture and storage (CCS) technology, energy and climate change secretary Ed Davey referred to the precedent set by flue-gas desulphurisation (FGD). So what, if anything, can CCS developers learn from the development and rollout of FGD?

Like CCS, FGD is an emissions abatement technology with clear environmental benefits and similar applications in that both can be deployed in power stations and other industrial plants. The FGD process removes toxic pollutant sulphur dioxide (SO2) from the flue gases emitted by coal-fired power plants and other industrial facilities. It was developed in the early 20th century after concerns about the health and environmental impact of SO2 emissions and what came to be known as acid rain. It was pioneered in the UK and the world’s first full-scale commercial FGD unit began operating at Battersea A power station in 1933.

Yet it took nearly 80 years for the FGD technology piloted at the south London site to be fitted to a majority of the UK’s coal-fired power stations. As Davey acknowledges in Next steps in CCS: policy scoping, which was published in August 2014, the government cannot afford to wait so long on developing CCS.

Regulatory support

The key factor in the successful deployment of FGD technology around the world has been strong regulatory and policy support. In the US, which along with Japan took the lead in its development after the UK’s initial contribution, there was a rapid expansion in the 1970s in the number of plants fitted with FGD in response to increasingly demanding legislation. In particular, the 1970 Clean Air Act Amendments (CAAA) required the Environmental Protection Agency (EPA) to establish nationwide air quality standards for SO2. This led to an explosion of FGD deployment: the first large-scale US plants came on-stream in 1968, and there were nearly 50 units operating 10 years later.

Strong policy support for SO2 abatement was crucial to the development of large-scale, commercially viable FGD in the US. The CAAA and further standards introduced in 1972 mandated emissions reductions regardless of economic or technical feasibility, in effect creating a market for FGD and related solutions that forced the rapid development and deployment of the technology.

Such forceful policy inevitably met resistance, and a number of US utilities mounted legal challenges to the regulations. Eventually in 1976 the US Supreme Court ruled in favour of the federal government’s right to force the development of previously untested technology. This costly pill was made easier for the utilities to swallow by the structure of the US energy industry, which was regulated as a collection of regional monopolies that could pass on higher costs to their customers.

In the UK, by contrast, FGD development proceeded more slowly in the absence of similarly binding legislation. Come 1981, the early FGD units at Battersea and at Bankside, a few miles downstream, had been decommissioned and the issue of acid rain caused by SO2 emissions was a major international concern. Germany and the Scandinavian countries introduced FGD policies in the early 1980s, but the UK was one of a number of EU member states that resisted European legislation on SO2 emissions.

Not until the 1988 Large Combustion Plant Directive (LCPD) did the UK agree to act, setting reduction targets of 21% by 1993, 45% by 1998 and 60% by 2003. The government estimated that around 12GW of plant would need to be retrofitted with FGD units to meet these goals. Crucially, however, the LCPD did not mandate any particular solution for achieving the required emissions reductions. In the UK, the newly privatised energy firms succeeded in lobbying for a reduction of the government’s FGD target to 8GW of plant. In practice, only 6GW was fitted before the LCPD was revised and strengthened in the early 2000s.

The UK also managed to resist the imposition of emission limit values (ELVs) for individual plants, arguing instead for greater flexibility for operators by allowing them to comply with emissions targets at a company and sector level, known as “bubbles”.

Emissions reductions

Although SO2 emissions from the UK energy sector did fall in the 1990s, the limited installation of FGD units accounted for only part of the reduction. More important was the gradual phasing out of high-sulphur domestic UK coal in favour of cheaper, low-sulphur imported coal and the building of new gas-fired power stations. That “dash for gas” may have been motivated partly by the perceived high cost of installing FGD on new coal-fired plants and the efficiency penalties that such installations would inevitably incur.

In a further blow to the effective deployment of FGD during this period, the lack of ELVs on individual plants proved to be a constraint on incentives for operators that did install FGD to run the abated plants at full capacity. “Because they had these additional costs of fitting the FGD equipment, they were then disadvantaged compared with the unabated plants that weren’t carrying that level of debt. So we had the cleaner plants sitting idle while the dirtier ones ran instead of them,” says Lesley James, acid rain campaigner at Friends of the Earth.

The bubble regime resulted in power station operators hitting their emissions reduction targets across their portfolio of plants even without running FGD-abated plants at full capacity.

Unlike in the US, where stringent regulations had forced the rapid development and deployment of FGD technology, the flexibility negotiated by the UK under the first LCPD allowed its energy sector to avoid the risks of the costly new technology while demonstrating a reduction in emissions.

These loopholes were finally closed by the second, more rigorous, LCPD in 2001. As well as setting higher emissions reduction targets, LCPD2 also set ELVs for all new plants and required existing plants to either to meet those limits by 2008 or opt out and run at a limited number of hours before shutting down by 2015.

These requirements triggered a major wave of FGD investments in the UK. A further 14GW of power plants were fitted with FGD between 2001 and 2009, bringing the UK’s total installations to 20.7GW, or just over 70% of the country’s remaining 28.4 KW coal-fired capacity.

Overall, the UK power sector’s SO2 emissions declined by 94% between 1980 and 2008.

Learning the FGD lessons

As noted in 2008 in a Green Alliance report on the future of CCS, it had taken 20 years since the first LCPD for FGD to fully take hold in the UK, and even then it required binding EU legislation to do so. Moreover, this was a technology that had already been proven effective and commercially viable in other parts of the world. “When it comes to the vital issue of cutting carbon emissions,” the report concluded, “we simply cannot afford a repeat of this sorry tale.” Davey appears to have reached a similar conclusion.

The concern, however, is that, in comparison with FGD, CCS is a more complex and costly technology. The UK is at least ahead of the pack this time, at least in Europe, with two CCS commercialisation pilots under way at Peterhead in Aberdeenshire and White Rose in North Yorkshire, with the latter being the only European CCS project to have received EU funding so far. Meanwhile, the world’s first commercial-scale, coal-fired CCS power station began operating at Boundary Dam in Saskatchewan, Canada, in October 2014.

However, the costs and commercial viability of CCS are harder to predict because of the complex nature of the carbon transport and storage infrastructure needed for the technology to work. For maximum efficiency, this infrastructure will be shared between multiple CCS facilities, which in itself introduces another level of complexity and coordination challenges not faced by FGD.

Until the successful commercial demonstration of some of these first generation integrated CCS projects, policymakers will find it difficult to mandate the use of the technology in the way that FGD was in the US in the 1970s.

James worries that, if the regulatory environment for CCS is as flexible as it was for FGD before the introduction of LCPD2, the technology will struggle to achieve its potential. “If the same regime applies for CCS when it starts operating commercially we’ll see cheaper, dirtier plants that are not fitted with CCS running ahead of the more costly ones that are,” she warns. “Unless systems are put in place to prevent this it will happen again.” James also points to a recent spate of applications by utilities to build new plants of 290-299 megawatt electric (MWe) capacity – thereby just avoiding the EU’s requirement that any new plant above 300 MWe be CCS-ready.

Nils Markusson, lecturer at Lancaster University, agrees that the lesson of FGD is that, without sufficiently stringent regulation, a commercially risky technology such as CCS may struggle to deliver on its environmental promise. “Lots of the wrangling over FGD was not just about whether to deploy or not to deploy, but how to deploy it,” he explains. “There are lots of choices to be made even after you’ve built the kit and that will very much be the case with CCS as well.”

Markusson is concerned that CCS could be introduced with an operating regime as flexible as that which saw some operators running unabated plants in preference to their more costly FGD installations: “What I fear is something half-baked, with [CCS] technology that works at a cost that is not prohibitive but an operating regime that is not particularly stringent, and you end up with quite a lot of emissions anyway. This is why the analogy with FGD is relevant: you can have a technology that works but what you get out of it is also a matter of how you operate it and how you regulate it, which comes down to politics and lobbying.”

A better balance

Markusson believes a balance in CCS regulation needs, therefore, to be struck between flexibility for the operators and environmental stringency. With FGD, the UK energy industry enjoyed so much flexibility that full deployment of the technology was delayed by nearly 20 years. Even though the UK has taken on an arguably more proactive stance on emissions reductions since the 1980s, the upcoming negotiations over CCS will be potentially even more difficult, given the technology’s greater complexity and higher and more unpredictable costs.

“The costs of running a CCS system are so much bigger than FGD compared with the basic costs of the overall power plant, so we can expect those issues to matter much more,” Markusson says. “They mattered a lot for FGD and they’ll be even more important for CCS. The politics of those discussions will be fierce, I would imagine.”

The successful FDG example from the US does provide a potential model for future CCS regulation. In that instance, government set tough standards for the development and deployment of FGD technology. As a result, an untested emissions abatement technology was rapidly and successfully scaled up despite resistance from the energy industry.

Although the regulated US energy market of the 1970s is markedly different from – not to mention much larger than – today’s privatised UK market, Markusson thinks there are parallels: “The case of FGD in the US shows that policy can drive innovation. It shows that, if we really wanted to, we could get things working that way.”

As Davey admitted in his CCS policy document, there is no time to waste.


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