The Kyoto protocol demands major reductions in emissions of greenhouse gases such as CO2, and the technology exists to achieve full compliance, but electricity generators and traders protest that competition has already driven prices too low for them survive even without the additional costs of separation and sequestration.
Under the massive inertia of their political administrations and energy industry megapowers, the energy regulation institutions of North America, the European Union, Japan and a few other industrial giants are beginning to heave into motion on the issue of separation and disposal of CO2 from power plant emissions around the world. There is even hard evidence now of co-operation between the European Community and the US government on this front.
Even so, there is little recognition that the need for action is immediate, that tried and tested technology is available, and that the consummate research and development into the whole range of esoteric advanced technology solutions now being mooted is not necessary before any concrete progress can be made in the field. This is a little surprising considering the proposed EU Climate Change programme threatens to impose a r*50/t tax on excess CO2 emissions from 2005 rising to r100/t in 2010. The Norwegians, who hardly produce any CO2 emissions themselves, still levy a tax off around $32/t on offshore production.
On the other hand, power generators, fuel suppliers, energy traders and even transmission undertakings are crying wolf under the stringencies of the real world of commercial competition. The additional costs of reducing CO2 emissions, or even energy storage for that matter, not only change their competitive environment before they have fully learned to manipulate the market, they even predict that their national economies will not be to survive the impact. Even the oil production companies are protesting that they could not afford to pay for CO2 supplies for enhanced oil recovery (EOR) in offshore resources.
Nevertheless, governments have ambitious targets for CO2 reduction. The UK government, or example, following its PIU Energy Review and input from learned bodies, such as the Royal Society, is producing a White Paper (due spring 2003) to provide a framework upon which future energy decisions can be based. This will include a path to achieve a 60 per cent reduction in CO2 emissions by 2050.
A clean coal demonstrator had been considered in the UK, but it was decided that cleaner coal technology was now sufficiently mature to no longer justify government support. Some R&D support continues, but the UK government wants to stimulate a market for cleaner coal technology, and is said to see IGCC’s coupled with CO2 removal and sequestration as playing an important role in this.
To facilitate the exploitation of UK storage assets, work is in hand to resolve the legal and technical issues relating to CO2 storage. There also now seems to be some appreciation that IGCCs could provide hydrogen to supply a future low carbon economy.
A new investigation into reducing greenhouse gas emissions from fossil fuelled power stations was launched by UK Energy Minister Brian Wilson on 17 September 2002 following the PIU’s conclusions that CO2 capture and storage could reduce a coal fired power stations discharge by 80 to 90 per cent.
Market forces oppose
One thing is quite clear: little of this can be achieved under the present regimes of competitive market forces. One key factor – large scale installation of energy storage systems – is widely expected to further reduce margins on energy trading prices to a degree which would put most independent traders out of business. Electricity prices in most industrial countries have now been reduced to such depths since the inception of open competition, mainly due to the diminishing price of natural gas, that once mighty electricity generating concerns are tending to crumble, but national economies have been reaping great benefits as a result. Even so, the political trends now seem to be moving in favour of reviving the old hard pressed coal industries.
Conferences, symposia, government committees and international co-ordination groups are beginning to proliferate, but it has to be recognised that the subject of CO2 separation and sequestration is complex and impinges on many aspects of the energy and other environmentally suspect industries. As in the case of emerging gasification technologies, which could make a huge impact on the problem, the subject requires a bringing together of the electricity, oil and gas, petrochemicals, chemical process, transport, coal mining and even the iron and steel industries.
It is all too obvious that by far the greatest emissions of greenhouse gas CO2 currently derive from the exhaust stacks of fossil fuelled electricity generating stations along with other nasties like SOx, NOx, poisonous LCH and heavy metals, whereas nuclear power plants and other so called renewable energies emit very little of anything.
On the other hand, while electricity generating stations are said to be responsible for 60 per cent of the world’s CO2 emissions today, by 2020 it is predicted that transport will account for 60 per cent and power generation only 30 per cent.
The amount of conventional fossil fuelled generation capacity to be replaced by wind, wave and solar power does not look likely to make a massive impact on the CO2 problem over the next few decades, so what other emerging systems are available for consideration?
An energy conversion infrastructure based on hydrogen is often mooted, and it is claimed in some circles that the existing natural gas pipeline network can be readily adapted for transport of this almost ideal fuel without excessive leakage in spite of its very small molecule dimensions and its propensity to diffuse through the atomic lattice of most containing metals. Gas turbines are not ideally suited to this gas however. There may not be a need to invest in developing new compressors and power turbines, but modified combustion systems would be necessary and the hydrogen gas would have to be diluted with large amounts of nitrogen, CO2 or steam to avoid excessively high combustion temperatures and to maintain a viable surge margin.
Fuel cells seem to be coming close to commercial application, and the Siemens Westinghouse solid oxide fuel cell development programme is now being very actively geared up for very large scale mass production following installation of the first commercial prototype in Hannover. For the expected high efficiencies that would be necessary for major market penetration, however, they would need to be built in combined cycle arrangement with high speed microturbines which are still some way from meeting their reliability and service life requirements.
Even then, the fuel cell concepts that are likely to be most viable – those running on natural gas, tend to emit very substantial quantities of CO2 themselves. A typical SOFC generating unit would generally emit over half the CO2 of an equivalent fossil fuelled boiler.
Nonetheless, Norske Shell announced in April 2000 a project to install a 250 kWe Siemens Westinghouse SOFC unit aimed at demonstrating that “Carbon dioxide normally emitted in exhaust gases can be successfully recovered at low additional cost and with the highest efficiency of any fuel cell type in the industry.” The CO2 would apparently be used to enhance the growth of algae in fish farms and to enhance the growth of crops in greenhouses.
One of the early applications was thought to be the offshore oil industry, which accounts for some 20 per cent of the CO2 emitted in Norway. Now Shell is committed to a $125 million pilot study with Åker Kvaerner and Statkraft to develop multi-MW fuel cell technology running on natural gas with a view to their use on Norway’s oil and gas platforms by 2010.
Oxyfuels and chemical looping
Chemical looping and the so called oxyfuels systems sound simple, elegant and very promising but they are at an early stage of development. In the days of joint research centres and national laboratories this technology would no doubt have been vigorously pursued, but in the regime of commercial competition this just does not happen.
The oxyfuel approach to CO2 capture, which was well described at the EU NGO Workshop in Amsterdam, 12 – 13 June 2001, by BP technical programme manager Dr Helen Kerr, is primarily seen as a retrofit for existing fossil fuelled boilers. It focuses on producing a fuel gas of high CO2 concentration by using oxygen rather than combustion air as the fuel oxidant. The key to economic viability would be reduction in the cost of oxygen separation – a topic which is already under intensive investigation for gasification processes. The solution may lead to the use of oxygen separation membranes to form the walls of the combustion chambers.
Chemical looping is more appropriate for gas turbine combined cycle CHP plants. In this a metal/metal oxide chemical cycle separates oxygen from air and oxidises the fuel in separate reactors. This is still at the laboratory phase but it looks promising.
There are a number of other techniques which also depend on a degree of flue gas recycling, which offer additional benefits such as higher cycle efficiency and very low NOx emissions.
In this context we should not forget the ZECA process, being developed by some 18 companies, including RAG Coal International from Germany, on the basis of research work performed at the Los Alamos National Laboratory in the USA. The concept employs a number of well known technical processes in which electricity is generated from coal without release of CO2.
A carbon-water emulsion is gasified under hydrogenation resulting in the release of hydrogen and CO2. The CO2 is converted to limestone – CaCO3 with calcium oxide. The hydrogen is delivered to a fuel cell, thus generating electrical energy and heat. The limestone is then broken down by a subsequent process to CaO and CO2 using the waste heat from the fuel cell. The calcium oxide is then fed back into the process. In a later process the CO2 reacts with magnesium- and calcium silicate (serpentine and olivine) to form carbonates and silicon oxide which are chemically stable and can be readily disposed off. Simulated calculations indicate a process efficiency of around 68 per cent, but it is a system of some complexity.
Easy with gasification
With the US government’s new regulatory controls and fiscal incentives to reduce greenhouse gas emissions, coal gasification combined cycle power plants with mature, well demonstrated technology are arguably now cheaper to build and finance than traditional pulverised coal fired power plants. Some such plants around the world have been operating with very high reliability, with high efficiencies and greatly reduced emissions, for decades. At the same time, removing CO2 from the process can be an almost absurdly simple operation. In the USA, however, the emphasis today seems to be on removing mercury.
The mature gasification technology now used can not only run on a wide variety of fuels including poisonous oil refinery wastes, petroleum coke, orimulsion, domestic and industrial refuse and biomass fuels, it can remove most of the important environmental pollutants better than conventional technology including heavy metals and greenhouse gases. It can also produce high value byproducts including a wide range of chemical production plant feedstocks, produce pure hydrogen for some future hydrogen economy, or synthesise Fischer Tropsch liquids in the form of diesel fuel or motor spirits should political problems stifle the traditional sources of petroleum products.
Better still, it can be used to produce syngas to replace natural gas fuel for the ever proliferating population of combined cycle power plants if and when the predicted imminent ramp in natural gas prices occurs. For some nations, gasification could be the salvation of key coal mining industries, especially those with the lowest grade coal deposits. Great strides have been made with underground coal gasification technology, which is particularly suitable for deep vertical seams which are very expensive to mine.
Many refinery residue gasification and petcoke gasification combined cycle power plants located in oil refineries already produce large amounts of hydrogen for extending the output of higher value top cuts, but CO2 is not generally captured as yet.
A good example is the Shell Pernis gasification power plant in the Netherlands. Modifications are now being made to the GE Frame 6 gas turbines to accommodate new licensing requirements to collect the CO2 from the exhaust and dispose of it beneficially. Negotiations are already underway with very large greenhouse farming concerns, which proliferate in Holland, to exploit this valuable resource. The Netherlands is also reported to be planning demonstration projects for CO2 sequestration in a dry natural gas field.
Another useful concept which is already being used is that of “natural gas gasification”. This simply means feeding natural gas into a gasification vessel to split off the hydrogen as a fuel or commercial commodity and run off the CO2 and higher hydrocarbons as valuable byproducts.
The syngas emerging from the gasifier consists simply of CO and H2. A very simple shift reactor can be used to convert the CO in the syngas to CO2 as it exits the gasifier, to be equally simply separated off prior to combustion. The shift reaction, which can use a relatively cheap catalyst, is exothermic and provides a valuable amount of extra heat to increase the thermal efficiency of the cycle. The higher pressure entrained flow quench type gasifiers are particularly suitable for this approach.
In 2000, ChevronTexaco commissioned the Jacobs Consultancy to investigate what the comparative penalties would be if the same flow scheme, incorporating a shift reactor, were used for both non-capture and capture modes of operation. The results of this study were reported at the 2001 Gasification Technologies Conference in San Francisco last October, and again at the IChemE conference “Gasification – the clean choice for carbon management”, held in the Netherlands this April. The reduction in plant efficiency when capturing CO2 was found to be two percentage points with the capital cost increasing by less than 10 per cent.
The advantages of using a shift reactor in an IGCC go beyond that of making it possible to capture CO2. The shift also promotes:
• more efficient waste heat recovery (less low-grade heat to recover);
• COS hydrolysis with the same catalyst;
• simplified hydrogen extraction;
• easier NOx control; and
• the possibility of independent gasification combined cycle.
Initially, the plant can be operated to advantage by continuing to pass the CO2, along with the rest of the syngas, to the gas turbine as in the case of scheme proposed for UK Coal’s Hatfield Energy Park, for which planning permission is now being considered.
Here we have a solution which could provide invaluable fuel flexibility in the event of a serious ramp in natural gas prices, using the existing huge complement of clean, high efficiency gas turbine combined cycle plants.
Another technique which is being considered is to use oxygen as the combustion gas instead of air which will result in an exhaust gas mixture containing only CO2 and H2O which again can be easily separated.
Removal after combustion
Competing interests maintain it is better and cheaper to remove CO2 from the exhaust stream after combustion using a simple amine scrubbing system such as the Fluor Econamine process, which has already been tested in the field at the North East Energy Associates Bellingham facility in Massachusetts. It must be said that this plant is processing gas turbine exhaust gas with a 3 vol per cent concentration of CO2. However the plant has yielded over ten years of operational experience producing some 320 TPD of food grade CO2.
The process can be used with conventional coal fired stations, NGCC plants or IGCC plants. For this process, dehydration and compression of the CO2 is required if it is destined for sequestration or enhanced oil recovery (EOR) and some stack reheating may be required. A minor consideration is that SOx reacts irreversibly with the amines, but this also yields the benefit that SOx should become reduced to below 10 ppmv at the absorber inlet. The amine scrubbing technology status today includes:
• Fluor Econamine FG – 30 wt% MEA with inhibitor;
• Lummus Crest; Kerr McGee technology – 15 to 20 wt% MEA;
• MHI/KEPCO KS-1 hindered amine solvent;
• Maximum capacity 1000 t/d for EOR;
• Numerous smaller examples operating on both coal and GT flue gases.
Table 1 gives a cost impact analysis quoted by Fluor in conference papers, and Table 2 shows the impact on plant efficiency. This represents an increase in electricity price of 0.5 to 1.0 UK pence/kWh, or about 0.75 to 1.5 ¢/kWh. This was reckoned to be equivalent to $10 to 20 per tonne of avoided CO2 for a coal fired power plant. A carbon tax at this level would cover the cost penalty, ie 10 to 20 $/tonne paid to the producer by a government for each tonne of avoided CO2. This would then allow the establishment of a market price for CO2 which would make EOR schemes economically attractive. Fluor points out that, based on supercritical cycles, about a 10 per cent reduction in efficiency has been achieved in studies of retrofits to high efficiency plant.
On reflection, amine scrubbing might seem the most obvious and simple solution for the bulk of coal fired power plants around the world until one considers that most of the vast number of coal fired generating in plants, in places such as the USA in particular, are well over 30 years old and hardly capable of economic refurbishment and upgrading except by gasification or GTCC repowering. In either case, the high pressure marketing and promotion are now on a roll for what could be a huge volume of business in power plant CO2 removal.
One utility particularly active in the field is Elsam of Denmark. Elsam is reputed to have the most efficient and environmentally friendly coal fired stations in the world, including Skærbæckværket and Nordjyllandsværket 3 as well having more than its fair share of onshore and offshore wind power and biomass generation. The potential savings in CO2 emissions from Elsam’s 3000 MWe of central CHP plants could be a drop from over 12 000 Mt/a in 1990 to some 21.8 with CO2 removal (see Table 3).
CO2 capture project
The CO2 capture project is a joint venture formed in 2000 by a consortium of eight major international energy companies to research and develop technologies aimed at reducing the cost of CO2 separation, capture and geologic storage.
Members of the consortium include: BP, ChevronTexaco, ENI, Norsk Hydro, PanCanadian, the Royal Dutch Shell Group of Companies, Statoil and Suncor Energy.
Its programme structure represents a major international development with distinct regional programmes in the USA, Norway and the EU with “sharing among programmes to leverage results and reduce duplication.”
In London in March, 2002 the CO2 Capture Project announced it had entered into a r2.1 million (US$1.8 million) agreement with the European Union’s Research Directorate (DGRES) to study novel technology for reducing CO2 emissions. The project, titled Grangemouth Advanced Capture (GRACE), started in January 2002 and will run for two years. The total programme cost will be r3.2 million (US$2.8 million), with research work carried out by a number of leading European universities and scientific institutions.
The GRACE project will address two generic areas of research:
• The development of chemical looping combustion technology.
• New materials for hydrogen membrane reactors.
Table 4 lists other contracts in place, of end April 2002.
While the symbiosis between the need for enhanced oil recovery using CO2 and the requirements for fossil fuelled power stations to dispose of greenhouse gas emissions may seem obvious, the commercial offshore oil and gas producers do not seem to think that they should pay for the necessary supplies of CO2 – they would rather prefer the power generators to pay for the privilege of having their environmental problems solved – and this is likely to be a major negotiation platform.
One project which appears to call the oil producer’s bluff is the purpose built bulk nitrogen facility installed by Pemex in Mexico for EOR in its Cantarell field, 93 km offshore, in the Gulf of Mexico. The company clearly found it economically attractive to invest in a gargantuan 40 000 ton/day nitrogen separation plant, costing some $1 billion, built by British Oxygen Company in addition to four GE combined cycle cogeneration units to provide the required power. This one project costs more than the projected investment in the entire CO2 transport pipeline network required for North Sea.
The usual government response to major global environmental problems is to prevaricate by means of successions of “essential” further studies by politically contrived authorities until the embarrassing issues hopefully go away.
Of one thing we may be sure : nothing much will happen on the carbon dioxide disposal front under the pressures of fiscal incentives, carbon taxes or market forces alone. Even the Kyoto protocol will not directly instigate the required activity.
If anything ever did need the combined forces of national governments, international agencies, global industrial interests and financial institutions around the world, this is it, and it has to be repeatedly re-emphasized – the time window is small.
TablesTable 1. Cost impact analyses of amine scrubbing in terms of electricity price Table 2. Efficiency impact for power plants of CO2 capture/compression (IEA greenhouse gas R&D programme reports) Table 3. Elsam’s actual and potential CO2 emissions Table 4. Research projects planned by the Carbon Capture Project (contracts in place at end April 2002)