Burning question

9 min read

The government wants engineers to catch and trap CO2 emissions from power stations. What are the options and why have ministers backed just one of them? Stuart Nathan reports.

Amid all the debates about alternative energy technologies, renewables and the resurgence of nuclear power, most people in the energy sector agree on one thing: the most crucial technology is carbon capture and storage (CCS). Without that, there is little or no prospect of reducing emissions of carbon dioxide.

The reason for this can be summed up in one word: coal. It is by far the most abundant and cheapest hydrocarbon and it is powering the stunning growth of India and China. They have plenty of it and, with their need to ramp up industrial production and improve the quality of life for their remotest villages and outposts, they will keep burning it. China is building 550 coal-fired power stations, and two new ones open every week.

Even in Britain and North America, where gas-fired power stations have been the norm for 20 years, reserves of coal dwarf those of oil and gas. High oil prices and political volatility have once again made coal an economically attractive fuel and new, efficient designs of furnaces fuelled by powdered coal mean coal-fired power stations are back on the drawing boards of many utility companies.

But coal is also the biggest emitter of carbon dioxide per kilowatt of any hydrocarbon, and all that CO2 has to go somewhere. Whatever new energy mix Europe adopts in the coming decade, the worldwide emissions of CO2 are going to rise unless there is a reliable, efficient and cost-effective method of stripping it out and locking it away somewhere that it cannot get into the atmosphere.

‘Carbon capture and storage is clearly the only way that fossil fuels can be used safely,’ said Jon Gibbins of the Energy Technology for Sustainable Development Group at London’s Imperial College. ‘It has the potential to break the link between fossil fuels and the climate. There’s still no society that can solve the problem on its own but CCS does guarantee that fossil carbon stays in the ground.’

Any study of CCS will always begin by saying that the technique is ‘technically feasible’. There are several ways of achieving the vital first step of carbon capture and all have been demonstrated, at various scales. The storage problem has also been addressed before, with spent gas and oilfields being used as underground reservoirs for the gas. And transporting gases around is a problem that was cracked decades ago; building and operating gas pipelines is a well-established and profitable business.

Yet, these same reports will invariably say that full commercial-scale CCS is unlikely to be available by 2020. So what is causing the delay?

Stuart Haszeldine, of the Scottish Centre for Carbon Storage at Edinburgh University, says the main reason is the scale of the problem and the specific challenges posed by power stations, with their variable fuels and the different species that can be present in them.

‘All the component parts exist, but they’re often fitted onto completely different equipment and processes,’ he said. ‘Separating CO2 from other gases is done by people making urea or fertilisers, or for beverages, but that’s on a smaller scale and the CO2 input is reasonably pure and controlled.’

This is not the case in coal-fired power stations, where the flue gases are about 12 per cent CO2 and the processes are 20 to 50 times smaller than those that would be needed for a power station.

There are three main methods for capturing CO2 from hydrocarbons — pre-combustion, post-combustion and oxyfuel.

In pre-combustion — sometimes known as integrated gasification combined cycle or IGCC — the fuel is processed to transform its hydrocarbon content into hydrogen and carbon dioxide, then the two gases are separated — most likely using a membrane — and the hydrogen burned to produce heat and power.

In post-combustion, the flue gases from normal combustion are purified to remove sulphur-containing impurities, then the CO2 is absorbed by a solvent known as a scrubber, which is usually a class of ammonium-containing compounds called amines. The CO2 is then reclaimed from the scrubber, which is recycled back into the process.

In oxyfuel, the fuel is burned in air that has been enriched with extra oxygen, so the furnace burns hotter and more efficiently and the CO2 content of the flue gases is also boosted.

This brings us to another stumbling block: it is not easy to integrate all the various parts of the CCS train. Capturing the CO2 and recovering from an absorption medium if appropriate; chilling the gas to condense any moisture out; compressing it; pumping it into a transport system then transferring it into whatever storage system is chosen all sound simple but have never been attempted at the scale necessary for commercial CCS.

Gibbins said it is not even known which step in the process would be rate-determining: is the absorption fast enough to burn the coal at whatever rate you choose, or would the rate of coal feed have to be tuned to produce CO2 at the optimum absorption rate?

All these systems are being developed around the world, with several under scrutiny in the UK. And all the developers were heartened when, last year, the government announced it would run a competition to promote CCS and fully fund a commercial-scale demonstration project. The competition is to demonstrate 50MW to 100MW of capture and storage by 2014, then capture on a 400MW plant as soon as possible after — a time limit which, Haszeldine noted, is alarmingly ill-defined.

However, when the full details of the competition were announced, it transpired that only one demonstration project would be funded — and limited to post-combustion technology.

The fallout was immediate: BP, which was developing one of the furthest-advanced pre-combustion projects, an IGCC plant at Peterhead in Scotland which would inject its CO2 into an oilfield to help displace more oil, announced that the project would be put on hold. The company now plans to build a carbon-copy of the Peterhead operation in Abu Dhabi.

Other non-post-combustion projects also went into hiatus. ‘The original indications of the competition — which, to be fair, the government hadn’t finalised — was that it wouldn’t discriminate between technologies,’ said Phil Hare, who runs the CCS practice at Pöyry Energy Consulting, ‘so to a certain extent, this took everyone by surprise.’

However, there are good reasons for concentrating on post-combustion. Hare noted that it is the only technology that can be retrofitted to existing plants, which means a wide-scale redesign of generating capacity would not be necessary. ‘I like the fact that it’s pushing out the boat a bit less, technically, and therefore has a higher probability of success.’

Haszeldine added that because the capture is not integrated into the fuel treatment, operators can separate out a portion of the flue gases and send them to a small-scale experimental plant.

RWE npower plans such a project at its Aberthaw power station near Cardiff, where a £8.4m, 1MW capture system will begin operation this year. This would be the first carbon capture pilot plant at a UK coal-fired station. The company plans a second phase at a 25MW scale, probably at one of its supercritical coal plants at Tilbury, Essex or Blyth, Northumberland.

Many observers are concerned that the competition has stifled innovation in the sector. One reason the UK opted for post-combustion was that the US is running an IGCC project, but this was recently put on hold because of funding concerns. Meanwhile, all the UK-based IGCC projects, and oxyfuel development, have slowed or stopped.

‘So from the UK being in a leading position, maybe three to five years ahead of the rest of the world, we’re now just among everybody else and maybe even third or fourth in terms of development,’ Haszeldine said.

‘The developers of IGCC say they can have it working by 2012 or 2013, if they could see themselves making some money out of it,’ he added, such as by the Treasury allowing them to charge more for the electricity they produce. ‘It’s becoming the technology of choice for countries with a reasonable access to clean coal, and it seems strange to walk away from it entirely if industries want to develop it.’

Much of the research in post-combustion carbon capture is concerned with improving the performance of scrubber solvents. These are generally based on monoethanol amine (MEA), which readily absorbs CO2 and gives it up when heated. However, the presence of sulphur compounds in the flue gases reduces the effectiveness and the longevity of the solvent.

‘The other disadvantage with MEA is that you need to cool it down from the temperature of the flue gas, then to regenerate it you need to heat it again by about 70°C. That takes a lot of energy, and it can add 30 per cent to the cost of capture— and that’s pretty poor engineering,’ Haszeldine said.

To reduce this effect, several companies are working on systems that do not need such a large temperature rise. Alstom, for example, has a chilled ammonia system that regenerates with a 5°C temperature rise; this is going into pilot trials at 1-5MW scales in Norway and the US. Siemens, working with E.ON, is also developing a low-energy generating system using a non-MEA solvent. Siemens says the system is ‘more stable’ and ‘can be optimally integrated into the power plant’. E.ON plans to build a pilot plant at a hard-coal fired power station in 2010 and will decide on its location and size at the end of this year.

Whatever process and solvent are chosen, scale-up is a daunting task. Normally, chemical companies can take a new process from a laboratory to commercial scale within about five years. However, power stations are so enormous that the pilot plants will have to be scaled up by a far larger factor than most chemical operations. This is not a straightforward operation, as enormous plants do not operate under the same parameters as smaller ones — different parameters such as temperature and pressure, turbulence of gases and the way fluids flow can have vastly different effects as volumes increase. This means operators will have to scale up in up to four stages.

‘That means that even 2020 is a very difficult target for getting CCS up and running,’ said Phil Hare. ‘It’s difficult to envisage the first demonstration projects being up and running before 2014. I think it’ll need at least a second stage of full-scale demonstration before the manufacturers can say it’s as commercially available as buying a supercritical coal-fired power station off Siemens, for example.’

The storage aspect of the problem is also uncertain. For the UK, storage offshore in depleted gas or oil wells is likely to be the favoured option, but only in the relatively short term, as Haszeldine explained.

‘Oil and gas fields are generally considered to have 30 or 40 years of capacity,’ he said, ‘but another kind of geological storage — saline aquifers, sandstone bodies which contain salty water but not hydrocarbons — could have 10 times that. CO2 can be pumped into saline aquifers in liquid form, and it will slowly dissolve into the salt water.’

Aquifers are relatively poorly-explored compared with oilwells, which have advantages and disadvantages. ‘Oilwells have been drilled many times to get the oil out, so you’re clear on the geology,’ said Haszeldine.

‘Conversely, you’ve punctured the natural seal with 20 or 30 holes. CO2 is a very low viscosity fluid when it’s in a dense phase, so it can escape far more easily than oil or methane can.’

Oil companies have tended to seal up old oil wells with Portland cement, he added, but this is not particularly resistant to CO2 and might not be adequate.

Aquifers are unpunctured, but also not surveyed. ‘You won’t have good confidence about the continuity of the saline-bearing sandstone and in particular the continuity and the performance of the seal rock at the top.’

However, the abundance of saline aquifers means it is likely they will be relatively close to most power stations that need to store CO2. Proximity is an important cost factor, as pipelines will be needed to transport the gas. ‘It’s a big issue,’ Haszeldine said. ‘If you say that pipelines cost £1m per mile, and you’re operating a plant in Cardiff, you don’t want to have to build a pipeline all the way to the North Sea. You’re much more likely to look for a suitable aquifer off the coast of Wales.’

A fourth option for geological storage is less likely to be used in the UK, but is generating interest. Unmined coal seams could not only hold and lock away CO2 but could also be used as an energy source in their own right. ‘Coal loves CO2; it chemically binds it into its structure,’ said Peter Styles, professor of applied and environmental geophysics at Keele University. ‘And not only that, it displaces methane from the coal.’

Pumping CO2 into coal is known as enhanced coal bed methane (ECBM) and has long been seen as a way of exploiting the vast supplies of coal that are too deep, fractured or otherwise inaccessible to mine — the volumes of which vastly outweigh the minable resources. The coal could even be gasified underground, using a form of controlled combustion to convert it into carbon monoxide, hydrogen and methane, with simultaneous capture of CO2 in the charred areas around the burned coal or in overlying seams.

However, the safety concerns and public worries about the possible risk of such a project make it unlikely that it would ever be tried in the UK.

China, however, is another matter. ‘If they’re building power stations on top of coal fields, then they could try to send the CO2 down far below the level at which they could mine even in the future,’ said Haszeldine. ‘But it’s still at a stage of advanced experimentation — it’s not even at a pre-commercial stage yet.’

Trials of ECBM in Spain, Poland, India and China have so far produced disappointing results, he added; moreover, it raises the problem of polluting drinking water. ‘You have to pump a lot of water around as well, and it’s hard to predict where that water will go underground. Some of the deep salty water, which is rich in heavy metals, could come up into shallower drinking aquifers.’

Back in Europe, however, politics may come into play to change the rules of the game yet again. The European Union has announced its development plan for CCS, and said it wants 12 demonstration plants up and running by 2015, of which the UK’s could be one. However, it has also said that by January 2013, CO2 trading allowances will no longer be given away but will have to be bought at auction, specifically by power generators.

This makes the cost of emitting CO2 part of the economics of electricity generation, and could be a spur to driving down the cost of CCS — CO2 stored underground will not have to be paid for.

Moreover, Haszeldine noted, the EU says it expects each country to recycle 20 per cent of any money raised through CO2emission permits to go towards supporting renewable or clean energy projects.

‘But we’ve seen the Treasury take lots of clean fossil fuel obligation money before and just sit on it, and not hypothecate it to support the sector.’