The use of gasification for power generation has been waiting in the wings for years – a technology for the future that many utilities feel is complex, too expensive and unproven. Recent experience on both sides of the Atlantic nevertheless reinforces its relevance to power generation – as a means of using coal and low value feedstocks in the cleanest possible way. But to be truly competitive using coal alone, natural gas prices need to rise or bigger turbines need to be used.
The gasification process was developed in Germany some 60 years ago and has been used widely in the chemicals industry for over forty years. The world’s largest gasification complexes are in South Africa where Sasol operates over 90 Lurgi slagging gasifiers to convert coal into a range of products including transport fuels.
The most recent application of gasification has been the generation of electric power (Table 1). The acronym IGCC – Integrated Gasification Combined Cycle – has unfortunately become synonymous with gasification in some circles. The acronym also conjures up an image of a totally bespoke package tailored to the power industry’s needs. It masks the fact that in its simplest terms, it is a gas turbine combined cycle (GTCC) plant with its own gas supply.
There are several types of gasifier – fixed bed, entrained and fluidised bed – options on the use of heat recovery or quench, and several technology suppliers – Lurgi, BG/Lurgi, Shell, Texaco, Destec (now Dynergy), Krupp Uhde (Prenflo) and Noell. The degree of ‘integration’ ie full, partial or minimal – steam side or air side – is also optional.
There are various ways of integrating the gasifier and the gas turbine system dependent, amongst other factors, on the type of turbine being used. The degree of integration and the method adopted are also a trade-off between capital cost and the overall efficiency being sought. This economic balance may even relate to the value of the feedstock being considered ie whether it is a prime energy source such as coal or a waste stream such as petroleum coke (petcoke).
Gasification is a versatile energy conversion technology that can process a wide range of hydrocarbon feedstocks into an energy-rich synthesis gas. The process itself is able to meet the highest environmental standards and the product gas can be cleaned so that its use has minimal emissions impact. The growing relevance of gasification to the oil industry and the fact that this technology would be the front-runner for CO2 sequestration, should that become necessary, explain the increasing industrial interest.
Market penetration There is broad agreement that syngas, a mixture of hydrogen and carbon monoxide, can be used in a number of ways either as a fuel for gas turbines and furnaces, or as a building block for the synthesis of other chemicals such as ammonia, methanol or other alcohols. In other words, it is highly flexible both from the feed input and product output standpoint. A number of cogeneration possibilities also arise because of this flexibility, which creates some interesting commercial opportunities.
The anxiety about IGCC as viewed by the power industry appears to have stemmed from the early experience of demonstration projects such as Buggenum and Puertollano or say Tampa (the latter being developed as part of the US Clean Coal Programme). However, these project start-ups need to be carefully examined for the cause of problems and their solutions.
There are over 350 gasifiers operating commercially around the world while current orders for GTCC systems are running at over 100 units per year from the major makers. These two developments suggest a high level of commercial confidence in the component parts of any IGCC system. So, what are the risks of matching the two technologies and why is there a reluctance to use gasification for power generation? A closer examination of the application of gasification is appropriate.
Three factors need to be considered when assessing these first demonstration plants:
Scale-up of the gasifier to match the fuel capacity of a large gas turbine. (For Buggenum, the scale-up represented a doubling in size of the Shell oil gasifier or an eight-fold scale-up of their largest coal gasifier)
The gas turbine combustor accommodates a three-fold increase in volume flow compared with natural gas
The turbines selected for these early IGCC demonstrations were 1980s models. All the gas turbine manufacturers have introduced larger and more efficient models, which will alter the economics of new IGCC projects substantially .
Coal gasification experience Buggenum: Results from the Buggenum project in the Netherlands have been most encouraging over the past year. The design efficiency of 43 per cent has been consistently demonstrated while the reliability has been high. The Shell gasifier has performed very well and the vibration problems related to the turbine combustors have now been solved. Demkolec has been experimenting successfully with reducing the cost of feedstock by blending lower quality coal and petroleum coke. This has not had any adverse effect on performance and has enabled the plant to generate competitively into the grid.
The target performance for 1999 is an availability of 90 per cent. The environmental performance has been outstanding, with NOx levels on syngas considerably lower than the corresponding levels from natural gas operation and well below the levels specified in the operating licence. This makes Buggenum the cleanest coal based power plant in Europe.
Puertollano: There is insufficient operating experience to make valid observations or comment at this stage. The feedstock is undoubtedly a challenge, being a blend of high ash local coal and high sulphur petcoke. The requirements of the EU’s Thermie support grant also dictated that an unproven and non-commercial gasifier had to be chosen, which must have exacerbated the problems associated with an innovative technology on a fuel blend which had never been used before. The delays associated with operating on synthesis gas have primarily resulted from the gas turbine combustor and it is unfortunate that some of the early Buggenum problems have recurred at Puertollano.
Tampa: In the USA, both the Tampa and Wabash River projects are coming to the end of their second and third year of operation, respectively. At Tampa, recent results have shown that a high availability can be achieved on the combined cycle systems with three of the past four quarters showing availability around 90 per cent or above. The gasifier performance over that period has averaged 70 per cent, with increasing confidence as operating problems have been overcome. The performance would have been better if it had not been for the failure of a clean gas/dirty gas heat exchanger that routed contaminated syngas to the turbine by accident causing some damage and delay. The design has subsequently been modified and good performance has been restored.
On completion of the latest run of 51 days, the operating company reported several important technical and commercial attributes of the plant:
high on-peak gasifier availability
high gasifier hot restart reliability
record continuous combined cycle operation
acceptable process feed injector life.
Like Buggenum, Tampa had been conducting tests with alternative fuels and had found that changing the design blend of coal had minimal impact on the good performance of the plant. In fact, they have been able to improve performance with a lower cost coal on some blends. The 1999 focus will be on tuning the facilities to benefit the long-term profitability and reliability of the plant.
Wabash River: The Wabash River project differs from the Tampa project in that it is a repowering scheme which raised the output of 100 MWe from a steam boiler to that of 265 MWe from a combined cycle system. A stand-alone gasifier owned and operated by Dynergy supplies gas to a GE Frame 7A turbine owned by PSI, the power company, while a heat recovery boiler generates steam that is utilised in the original steam turbine. The gasifier is a two-stage entrained system originally designed by Dow and subsequently marketed by Destec before Dynergy took over the company.
The project is in its third year of demonstration and steady progress has been made to improve its performance. The plant has operated over for half its second year on syngas. Over the first 8 months of 1998, it has already exceeded the performance achieved in 1997. Expressed another way, if the plant continues to operate for the remainder of 1998 as it has for the first eight months, the availability will exceed 65 per cent. The operating company has also been experimenting with other coals and petcoke. Results look very promising which adds to the growing data base of gasifiers demonstrating that the process is very flexible.
In summary, all four plants were designed for solid feedstocks – primarily coal. They all have relatively early model gas turbines. With current gas prices, they may only be marginally economic dependent on the accounting treatment of the asset.
Oil industry applications Although coal is often seen as the prime choice of feedstock to IGCC systems, there are some increasingly compelling reasons for converting heavy oil residues. In Europe, it is useful to distinguish between IGCC investment primarily for power generation, eg as in Italy, and the conversion of heavy oil residues to hydrogen and syngas primarily for refining, as at Shell’s Rotterdam refinery. The latter development reflects the fact that the oil industry is increasingly having to examine market demand for product and in particular, the future quality requirements of transport fuels. Many companies are finding themselves short of hydrogen and with a surplus of heavy fuel oil, so there is a role for gasification to convert heavy oils into hydrogen and a clean syngas.
Italy: There are three oil based IGCC projects in Italy, all of which are due to start up in 1999. The Saras (Sarlux), ISAB Energy and API Energia projects are all commercial developments designed to convert heavy residue streams. The heavy fuel oil output from these refineries has historically been channelled to power generation by conventional combustion. The projects will convert the heavy residues into syngas in Texaco gasifiers with the cleaned syngas generating power. The capacities of these plants are 550, 510 and 280 MWe respectively ie large power plant projects. The environmental benefits derived from the generation of clean power in these plants will enable Italy to meet the emissions targets required by EU legislation.
The Netherlands: Commissioning experience with Shell’s large oil gasification plant at Pernis, Rotterdam, has been reassuring, with minimal problems. The prime purpose of the plant is to convert heavy oil residue, for which there is a declining market, into hydrogen for refinery processes and syngas for refinery fuel and power generation. The hydrogen is needed to meet the quality requirements for gasoline and diesel as specified by EU legislation.
Shell decided to scrap their catalytic cracker and replace it with a hydrocracker. In converting the available heavy residue, the gasifier makes more gas than is required for hydrogen and refinery fuel so the surplus is routed to a combined cycle gas turbine system where over 100 MWe of power is generated and is exported to the Dutch grid. Pernis has now become the cleanest refinery of its size in Europe.
Other European projects: Similar projects have recently been announced by Total at Gonfreville (Normandy) where Texaco has taken a shareholding in the development, and by Repsol near Bilbao. Although the prime purpose of the gasifier will be to generate hydrogen, there is likely to be a surplus of syngas and it will be routed to power generation to create a further revenue stream for the oil companies. Other oil companies are examining the technology in the light of recent EU decisions and the target quality parameters of transport fuels are known to the year 2005.
Other non-European projects Texaco: Texaco has already built and commissioned a 40 MWe co-generation project at their El Dorado refinery operating on petcoke. The plant is operating smoothly.
Exxon: Has announced a 180 MWe co-generation unit with hydrogen at its Singapore refinery fed with petcoke and heavy residue, while a 240 MWe repowering project is under construction at its Baytown refinery for completion in 1999 using a Texaco gasifier to convert petcoke.
GSK – Japan: A 550 MWe IGCC unit for generating power from heavy oil has been announced for start-up in 2001.
Future prospects: A review of the heavy residue, asphalt and coke market by Pace Consultants has highlighted the recent decline in petcoke prices and the reasons for the growing surplus. They indicated that announced additions to coker capacity in the USA alone would yield an extra 23 MT of petcoke into the market by 2003 and a further 5 MT has been announced in Venezuela. BP America is also said to have plans for gasification into power at their Toledo refinery.
Gasification of waste At the large SVZ Schwarze Pumpe plant in eastern Germany three different gasifiers are operating on blends of local coal and a range of waste streams. A preparation facility blends coal with sewage sludge or waste plastic while spent lubricating oil and solvent residues can be simultaneously introduced into the gasifier through separate burners. About 50 000t/year of fluid wastes are processed.
The product syngas is being converted into about 120 000 t methanol per year and 60 MWe of power for the grid. By the spring of 1999, a new gasifier will be operating designed by British Gas/Lurgi. The whole Schwarze Pumpe complex is a fully commercial operation with no subsidy or demonstration funding for support.
Drivers in Europe The prime driver for gasification in Europe is environmental legislation and the commitment to reduce CO2 emissions by improving energy efficiency. A further driver – perhaps pulling rather than pushing – is the advance in large gas turbine technology.
Environmental legislation affects both the power generation and transport sectors with a knock-on impact on the oil industry. Recent revisions to the Large Combustion Plant Directive set tougher standards for new power plants not only in terms of the emissions of SO2, NOx and particulate but also with a reduction in the size of plant to which the limits apply. The toughest limits applied to units over 500 MWth but this has been reduced to 300 MWth. Since the average age of most of Europe’s coal and oil fired capacity is about 25 years and much of that capacity is around 35 per cent efficient, there will be a need for a substantial replacement programme over the next decade when the new emissions limits will apply.
The oil industry faces investment both to improve transport fuels quality and to reduce process emissions from its refining operations. A more recent development is the need to process waste streams. The Waste Packaging Directive requires the recovery and recycling of all forms of packaging waste. Cardboard, paper, glass, steel and aluminium present no major technical challenges but plastics are more difficult to recycle. Other legislation covers the need to dispose of oils and solvents in an environmentally acceptable way.
Yet another Directive addresses the issue of urban waste water disposal. It is the basis of legislation that bans the dumping of sewage sludge at sea from the end of 1998. EU member states therefore have to find alternative ways of processing the waste stream.
Gas turbine development Most of the early development work on gas turbines supported the global growth in the aviation industry. It was not until 1981 that the major manufacturers saw the potential of harnessing the large turbine as a stationary source of power. Major strides in the technology have taken place and today, all the major makers are able to offer larger and more efficient units capable of operating at very low emissions on either natural gas or synthesis gas from a gasifier.
Table 2 indicates the pace of development both in the size of the turbines and improved efficiency on natural gas and synthesis gas. The figures for reduced efficiency when in IGCC mode reflect the internal power consumption and energy conversion efficiency of the facility, not a change in the inherent performance of the gas turbine.
These developments, coupled with corresponding reductions in capital cost, indicate clearly the economic appeal to the power generators. While natural gas is at the price currently being enjoyed in Europe and the USA, the natural gas fired combined cycle gas turbine system has no rival on a cost per kWh basis for new power generating plant.
However, there could be circumstances in which gasification becomes economic, eg
Use of low value feedstocks such as petcoke, low cost coal or wastes
Use of heavy oil residues, especially if a hydrogen credit can be taken
Rise in natural gas price of 20-30 per cent.
Capital cost estimates For many years, IGCC has been considered to be an expensive technology. The capital costs have been compared with steam-based plant using coal as the energy source and estimates have been on the basis of a very few units, all of which could be considered ‘first of a kind’.
Demonstration plants frequently include test facilities that would not necessarily be incorporated into commercial designs and have not had the benefit of modern turbine technology. Buggenum, for example, was based on the earliest of the Siemens turbines because it was the only model available when the decision was made to proceed with the demonstration. Having proved the technology, it is now important to assess the economics in the context of the knowledge and equipment available today. Recent studies have attempted to do this: Krupp Uhde/Siemens study. The prime purpose of this study, commissioned by the EU, was to illustrate that IGCC could now compete with the best available ultra-supercritical designs of boiler. The analysis drew on global IGCC experience and manufacturers’ assessments of costs for the component parts of an IGCC. The study used a Siemens turbine and a Prenflo (Krupp Uhde) gasifier with a net power output of 452 MWe and an LHV efficiency of 51.7 per cent. An IGCC investment cost of $1100/kW emerged from this work based on bids from the manufacturers involved.
The reduction relative to previous assessments results primarily from the additional power output and increased efficiency assumed. Further improvements – leading to breaking of the $1000/kW barrier – could be achieved through the following steps:
Use of the most advanced gas turbines available
Decrease expenditure on overheads such as engineering and project management
Standardise equipment and move to series production
Rationalise measures for construction and installation.
These views are broadly shared by ABB/Texaco, who have suggested ways projects should be managed in future to reduce the overall cost.
Parsons/USDoE study. The Parsons/USDoE study compares IGCC costs with those for PF and GTCC and a summary of main results is give in Table 3. One important point illustrated by these figures is the way it is possible to be selective in showing capital cost data. Three levels of capital cost are shown: bare erected cost; total plant cost; total plant plus capital (ie including interest on capital).
The IGCC figures relate entirely to the use of coal and do not reflect the lower capital cost associated with the use of heavy oil residues, although they would be of the right order of magnitude for petcoke. The figures also assume power as the only product whereas the petcoke or heavy oil cases would frequently be associated with hydrogen co-production or co-generation.
GE/Foster Wheeler. In a joint GE/Foster Wheeler study, four IGCC modules were compared. A range of modules can be made available to the oil industry to match the likely quantities of heavy residues produced. The change in cost with size is illustrated in Table 4.
One key factor in the cost build-up is the trade-off between capital cost and efficiency which centres on the use of a quench system to cool the raw gas from the gasifier or the more sophisticated heat recovery boiler route. The other critical factor is the part of the world in which the construction is to take place. These factors can result in the kinds of difference in cost shown in Table 5, which also illustrates the difference between ‘F’ and ‘H’ technology.
EPRI (Electric Power Research Institute). EPRI has evaluated the Shell, Texaco and Destec (Dynergy) gasifier technologies, including both modes of the Texaco system, ie heat recovery and quench.
Table 6 sets out field and total plant costs for each gasifier option using the GE Frame 9 F gas turbine. Table 7 shows estimates for the GE Frame H, which has completed its first workshop trials and is scheduled for field trials shortly (a range is given as the absolute price of the turbine is not known at present).
These calculations are more conservative than those of Demkolec and of the Krupp Uhde/Siemens study mentioned above where there was a greater degree of integration and the use of either the Shell or the Prenflo heat recovery system. In those projections, 51 per cent efficiency was being projected which is also in line with what would be expected from the GE Frame 9H on syngas.
EPRI makes an important point that its calculations were all made on US coals and that there would be a considerable difference in cold gas efficiency ie the amount of usable energy in the feedstock available for the generation of power. EPRI showed data to indicate that Pittsburgh No. 8 coal would yield 83.4 per cent on a Shell gasifier while Illinois No. 6 would only yield 75-75.5 per cent on the Destec and Texaco gasifiers.
The cold gas efficiency which can reasonably be expected from heavy residues would be about 85 per cent and that offers a considerable economic advantage to oil compared with coal in addition to the capital cost saving in feed handling and preparation.
Texaco/Mitsubishi/BOC. According to this group it is advanced gas turbines – such as the Mitsubishi-developed M501G, which has been operating successfully since April 1997 at Takasago – that transform the economics of IGCC. A scheme has been drawn up by Texaco/Mitsubishi/BOC that offers a net power output of 393 MWe at 46.7 per cent LVH efficiency at $860/kW. The system meets strict environmental standards, eg as imposed in Japan, and they conclude that the use of these advanced gas turbines with gasification can produce power more economically and cleanly than any other system available based on direct combustion of dirty fuels.
Project management issues Historically, the concept of IGCC has been largely left to potential owners who would make all the decisions on design, choice of equipment and contracts. They have been offered the choice of gasifier, gas turbine and ASU supplier. Such freedom of choice may not result in the most cost-effective package. The owner may also fail to secure performance guarantees from any one supplier. This has led to project cost increases, especially where the banks have required capital guarantees.
The process of project management can be substantially improved. ABB and Texaco have conducted an analysis based on a refinery IGCC application. They note that IGCC projects are large, complex and create interface problems, for example, between the refining and power industries.
There could be as many as ten participants in a project (eg, developer/investor, refiner, power off-taker, EPC contractor, gasification technology licensor, power equipment supplier, ASU supplier, banks and advisors (legal, financial, technical)). Hence, they advise picking participants carefully, engaging major contributors in ownership, establishing a clear structure in terms of organisation and responsibilities, and striving for simplicity.
They also elaborate on the financing needs that drive projects and set out some key design considerations. The messages are:
Avoid over-specifying the design feedstock
Pick proven standardised units
Consider quench if low value feedstocks are to be processed
Reduce the layering of design allowances and contingencies.
Recent developments suggest the major players are moving in the directions suggested above. Examples include: the alignment between ABB and Texaco; the Texaco shareholding in Total’s Gonfreville project and the Bechtel/Shell International Gas interest in Intergen. Although the latter is currently focused on gas turbine combined cycle power plants the structure of Intergen would allow expansion into other kinds of technology. Also, most of the oil companies have indicated their intent to move into power generation.
Future technology developments Although gas turbine and gasifier technologies are mature, the combination of the two to form an IGCC power plant could still be considered to be at an early stage of a new IGCC learning curve. There are a number of areas in which simplification and integration, choice of materials and flow details can be fine-tuned to reduce unit capital costs. This can be predicted with some accuracy because the larger, more efficient turbines require less fuel per unit of output that, in turn, means a proportionally smaller contribution from the gasifier.
As has been mentioned in the previous section, it is important to move beyond ‘first of a kind’ towards turnkey packages. First steps in this direction are now being taken. There is also scope for capital cost reduction through the growing understanding of feed systems, performance of these large gasifiers and the materials of construction. Process improvements will also steadily reduce the parasitic power consumption through the whole train. Over-integration has already been identified as a problem at Buggenum and the use of a stand-alone air compressor is likely on future systems, with a proportion of the air possibly coming from the gas turbine air compressor for the ASU.
At present oxygen for gasifiers is produced by cryogenic air separation units. This means refrigeration and distillation – both significant consumers of power. Much research is progressing to develop alternative ways of separating oxygen from air. One of the most promising techniques, using ion transport membranes, has been described by Air Products. The membrane is a very sophisticated ceramic filter made of a blend of rare earths whose combined properties allow oxygen to pass through but hold back all other gases. This development should be commercial within a decade and would have a significant cost advantage over today’s cryogenic method.
The importance of carbon dioxide reduction and sequestration has also led to many recent technical papers being presented on this subject, reflecting an emerging consensus that gasification could play a key role in reducing the growth in man-made CO2 emissions. It not only offers the means of increasing efficiency but also enables the CO2 to be captured. Schemes are already being studied for CO2-free power generation, eg by reforming natural gas to hydrogen for use in GTCCs while the CO2 is absorbed and sequestered. The key question is where can all the CO2 be stored safely and what is the cost? Prospects By the turn of the century, 19 IGCC projects will be operational and the demand for gasification technology is gaining momentum all the time. Its excellent environmental performance is beyond doubt – the Netherlands can now boast the cleanest coal-based power generating capacity and the cleanest oil refinery while Germany is able to demonstrate the way in which waste streams can be converted into power and a liquid fuel.
Gas turbine technology has continued to advance and the major manufacturers all have commercial models that approach 60 per cent efficiency in combined cycle mode. The GE Frame 9H, which is aiming for greater than 60 per cent, is due for field trials on natural gas within months. These turbines are capable of operating on natural gas or syngas when the high efficiencies will enable IGCC to exceed the efficiency of any other system at capital costs fully competitive with ultra-critical steam systems.
Although it may take time for coal to become a feedstock for competitive power generation, IGCC appears set to grow rapidly to absorb heavy oil residues, petcoke and waste streams. This may be exclusively for power or for co-generation. In the latter case, the economics can be enhanced considerably by hydrogen or chemicals production from the syngas especially when there is such a diurnal and seasonal fluctuation in power demand in many parts of the world. The pace of development would appear to be primarily in the hands of the independent power producers that now include the oil companies.
|UK gas moratorium creates window of opportunity for IGCC|
| the-uk-government-s-apparently-open-ended-de-facto-moratorium-on-natural-gas-fired-generation-plant-construction-has-encouraged-renewed-interest-in-a-wide-range-of-advanced-coal-gasification-power-plant-projects-even-the-nuclear-power-industry-in-association-with-jacobs-engineering-is-actively-pursuing-an-innovative-400-mwe-design-close-to-welsh-open-cast-coal-deposits-current-projects-being-pursued-include-li-li-rjb-texaco-national-power-facility-at-rjb-pit-head-kellingby-colliery-west-yorkshTablesTable 1 IGCC power plants – operating, under construction or announced Table 2 Development of large industrial gas turbines Table 3 IGCC costs compared with PF (pulverized fuel (coal) and GTCC (gas turbine combined cycle) Table 4 Comparison of four IGCC modules Table 5 Cost variations for different locations Table 6 EPRI IGCC cost studies for F technology gas turbines Table 7 EPRI IGCC cost studies for H technology gas turbines