Counting the cost of Gasification

An NETL project has developed variants of the Wabash IGCC plant design that could be used to supply power, steam and hydrogen to petrochemical plants to minimize capital costs or maximize availability.

Gasification systems can be economically attractive when compared to traditional coal-fired generation, says Gary Stiegel, product manager for Gasification Technologies at the National Energy Technology Laboratory. “On a capital to capital basis I believe that gasification is competitive with coal-fired generation that has advanced flue gas cleaning systems,” he says, “and gasification offers an opportunity to achieve near-zero emissions, not just of NOx and SOx but of particulate and mercury. In future it offers the opportunity of capturing CO2, when sequestration technologies are developed, and abstracting hydrogen. That reduces the cost of compliance with environmental legislation.”

But the US Department of Energy acknowledges in its Vision 21 programme, intended to improve energy production from fossil fuels in the new century, that gasification systems are relatively complex and costly to build and operate, when compared to simple pulverized coal plants. Taking an integrated approach, Vision 21 aims to develop advanced concepts for high-efficiency power generation and pollution control into a new class of fuel-flexible facilities capable of co-producing power, heat, fuels such as hydrogen and chemicals with virtually no emissions or pollutants.

Steigel adds, “On a capital basis, gasification is equivalent in price to building a pulverized coal plant and bringing it down to low emission levels. If you are using coal, the efficiency of gasification is higher, so there are continuing lower fuel costs. And there is the possibility of using low-cost feedstocks, or disposing of hazardous waste.”

Superior performance

“Gasification compares very well with incineration of hazardous material because the emissions are so low – you don’t emit dioxins, for example.”

Environmental performance is a major benefit of gasification, compared to traditional coal-fired plants, and likely to become even more significant as environmental legislation begins to bite. Steigel says, “At the moment about 160 sites worldwide use gasification, and there are about 400 gasifiers in operation. We see growth in the technology of about ten per cent per year, and the real driver for that growth is gasification’s superior environmental performance. It’s a process that can take any carbon-based feedstock and produce energy with minimal emissions. Some plants are co-firing waste but the waste proportion is fairly low – around five to ten per cent on a 300-400 MWe plant. That is really because of the availability of the waste.”

Figure 1. The Wabash repowering project transformed a 33 per cent efficient, 90 MWe unit into a 40 per cent efficient, 262 MWe unit
Click here to enlarge image

In the future, he says, gasification “is well placed for CO2 sequestration. We are looking at new technologies in that area too, using membranes for hydrogen and CO2 separation. In the longer term, we are also looking at using hydrates to separate CO2.”

Long term economic benefits to gasification are not hard to find, and Steigel adds, “There is lots of activity looking at coal-based IGCC as a hedge against increased volatility in the natural gas price.”

Nevertheless, there is work to be done to reduce upfront costs to make them more attractive, especially in deregulated power markets where low capital costs and quick returns are important. A major Vision 21 project operated for NETL by Nexant, Bechtel and Global Energy has therefore focused on improving the profitability of gasification projects by optimizing plant performance, capital cost and operating costs. The project is based on data from the successful Wabash repowering project in which a 1950s steam turbine was re-powered as part of an integrated gasification combined cycle plant.

Wabash project

At Wabash River, Indiana, a 1950s-vintage pulverized coal fired plant was repowered using a two-stage pressurized oxygen-blown entrained-flow IGCC system in a project sponsored by the US Departmemt of Energy and operated by a joint venture of Destec Energy and PSI Energy. Repowering has transformed a 33 per cent efficient 90 MWe unit into a 40 per cent efficient unit with a net rating of 262 MWe, with 104 MWe coming from the repowered steam turbine, and 192 MW from a GE MS7001 FA combustion turbine generator. Although fuelled by local high-sulphur coal or petcoke, the plant has among the lowest emissions of any coal fired plant worldwide.

In the Destec gasification process, coal slurry is mixed with oxygen and undergoes partial oxidation when it is injected into the first stage of the gasifier at 1400à‚°C and 27.6 barg. Fluid ash is quenched to form an inert vitreous slag while the hot syngas passes to the second stage where it pyrolyses more coal slurry in an endothermic reaction. The syngas is then passed through a fire tube steam generator to produce high pressure saturated steam. Particulates are removed in a hot/dry filter and recycled, while the syngas is cooled so that it can be water-scrubbed for chloride removal and passed through a catalyst that hydrolyses carbonyl sulphide to hydrogen sulphide so it can be removed using stripper columns. The syngas is then moisturized and preheated before being pumped to the power block.

The efficiency of the plant is maximized by hot/dry particulate removal, integration of the high temperature heat recovery steam generators at the gasification and gas turbine stages, carbonyl sulphide hydrolysis, recycling of carbon from slag fines and use of 95 per cent pure oxygen. It has demonstrated thermal efficiencies of 39.7 per cent when operating on coal and 40.2 per cent on petcoke.

Wabash illustrates the flexibility of the gasification process. Designed to operate on coal, it is currently fuelled by petcoke. Steigel says, “In the short term petcoke is a good opportunity feedstock. There were very few modifications required to switch Wabash from burning coal to petcoke. The plant was built for coal so it is not optimized for petcoke, and that means parts of the plant are not sized to get the best performance from the feedstock, but nevertheless it is performing very well.” He adds, “There is a huge variety of potential feedstocks for gasification plants and you are likely to see some co-firing but they won’t be completely fuel-flexible. It is more likely that you will see plants with flexibility within a class of fuels.”

An optimized design

The optimization work used the existing Wabash plant as the base case. In the first stage, design and cost engineers adjusted the equipment, materials and process operation to convert the design into a greenfield IGCC. The group first derived a cost database using documented equipment and material costs, adjusted to eliminate unusual circumstances and escalated to 2001 values. It then incorporated the effects of changes to the plant design, for example, after a few years of operation ceramic candle filters at Wabash were removed, and replaced with metallic ones. Bechtel’s Comet estimating tool was used to benchmark base qualities and provide a base to evaluate future changes. Finally, a standard methodology was developed to evaluate different plant configurations.

Refinery application

In step two, the coal plant design was converted to a ‘trigeneration’ facility using petcoke as fuel to produce electricity, hydrogen and industrial-grade steam, and the theoretical site was changed to one on the Gulf Coast assumed to be adjacent to a petroleum refinery. The petrochemicals industry is seen as a likely customer for gasification technology, and Steigel explains, “Polygeneration activities are most likely to be at an existing refinery that means you can take advantage of efficiencies in the system. In the future we do see lots of projects in refinery applications.”

The design was based on the assumption that the steam and hydrogen produced at the IGCC plant can be sold to an adjacent refinery, but must have a very high reliability. A single gasification train can backup natural gas firing, which could satisfy the refinery’s hydrogen and steam requirements by sacrificing power production, redundancy strategy aimed at maximizing the gasification reliability.

The entire gasification area had three duplicate trains, each with 50 per cent of the total plant design capacity. This high degree of reliability and sparing is necessary since the plant would become an integral part of the petroleum refinery. Using two GE 7FA gas turbines and a more efficient steam turbine than the repowered version at Wabash, the plant was calculated to have a cost of $993.2 million at 2000 prices.

In the next phase of the project, the plant design was optimized using Bechtel’s “value improvement practices” (VIP) methodology. Bechtel and Global Energy analysed more than 300 value engineering ideas generated during brainstorming sessions based on experience gained at Wabash during repowering and O&M activities and at Bechtel’s other gasification projects. After analysis, VIP efforts focused on the gasification area as these were shown to be critical to reliable operations.

Enhanced efficiency

Among the optimization processes, Bechtel used its ‘Comet’ plant layout programme to evaluate layouts and minimize piping requirements, and its ‘Powerline’ suite of standard design templates for combined cycle, pulverized coal and fluidized bed power plant designs. The optimized plant consumes 3 per cent more petcoke fuel (5399 t/day) than the earlier version. It exports 17 per cent more electric power (461.5 MW net) while producing the same amount of hydrogen and steam. Among the changes in the optimized design GE 7FA+e 210 MWe combustion turbines replaced the GE 7FA design, because of their higher thermal efficiency and lower emissions, and low-BTU fuel gas was used within the plant to make steam for power generation, instead of being exported to the refinery.

Redundant equipment was removed unless it contributed to higher reliability. In many cases, including the sulphur recovery unit, low temperature heat removal and acid gas removal areas, CO shift and hydrogen production areas meant three 50 per cent trains were reduced to two 50 per cent trains. The efficiency of the hydrogen plant was also improved.

The most significant changes were made in the high temperature heat removal area as each, of the now reduced trains, operated with two 60 per cent rod mills. When it is necessary to replace the refractory in one of the two identical and parallel gasification trains, the train is shut down during a normal maintenance outage and piping is rearranged to place the spare vessel in service and completely disconnect the operating vessel. This is expected to take about two weeks. The train can then be restarted using the spare gasifier while the original gasifier is being serviced.

Optimization has also reduced the amount of scheduled maintenance required, from 20 to 14 days per train annually. Following the optimization procedure, the 2000 installed cost of the plant was estimated at $764 million – about 23 per cent less than the non-optimized plant.

The group also investigated two variants on the optimized plant. In a ‘minimum cost’ version, the spare gasifier was removed from each of the two parallel gasification trains. With one gasifier per train, each would require a 12-week biannual outage for refractory replacement, so there is a penalty to be paid in availability, and hence in annual power, hydrogen and steam sales. However, it reduced the capital cost by some $18 million to $746 million.

Figure 2. Effect of power selling price on the return on investment
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In a second variant, there are three identical and parallel trains containing the slurry feed tank and pumps, gasifier, high temperature heat recovery unit and dry/wet particulate removal systems. This places the capital cost at $812.6 million, but has benefits in availability.

Figure 3. The optimized plant consumes 3 per cent more petcoke fuel than the earlier version, and exports 17 per cent more electric power while producing the same amount of hydrogen and steam
Click here to enlarge image

With capital costs assessed, the group used downtime and availability data from Wabash during the final year of its demonstration, March 1998 to February 1999, to estimate the availability of the greenfield IGCC designs and their variants.

Using this data and variations in the price of financing and gas (all the designs would be likely to need backup firing using natural gas between ten and 40 per cent of the time) and the selling price for steam, hydrogen, fuel gas and power for the four variants. The economic analysis showed that for situations where export power can be sold at an attractive price the spare gasification variant has the highest return on investment although it has the highest costs. It is also the most attractive option when outages in the steam and hydrogen supply incur large penalties. The minimum cost case may be the most attractive where power prices are low and long outages can be tolerated, and it also may be an attractive option where a refinery may expand, as it can then be upgraded to the base or spare train case.

Gary Steigel says that efforts to optimize gasification plants have been very successful. “People have been very excited about work on optimizing the design, bringing down costs and raising the efficiency,” he says, and he points out that: “There is a reduction in costs, and there has also been a reduction in the whole ‘engineer, procure and construct’ schedule. That has a positive effect on financing costs too.”

Continued work is likely to show that gasification can be attractive of pure economic as well as environmental, grounds.

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