IGCC Power Generation – Down But Not Out

By Shelley, Suzanne

The proposed use of coal for power generation has come under tremendous fire over the past 18 months or so. For integrated gasification combined cycle1 (IGCC) power generation based on coal or petroleum coke, the road has been particularly rocky. Historically, coal’s popularity for power generation has followed a fairly predictable, boom-or-bust pattern in response to the perceived negative environmental impact of coal, volatility in the price of natural gas (an alternative fuel for baseload power generation), and ongoing breakthroughs in so-called “clean coal” technologies.

In 2006 and early 2007, the growth in the proposed use of coal- based power generation – and IGCC in particular – experienced strong momentum (partly in response to skyrocketing natural gas costs). For instance, during that time, utilities on five continents announced plans for at least two dozen grassroots IGCC facilities. This was particularly significant because a full decade had elapsed since the prevailing fleet of commercial-scale, soud-fuel-based IGCC plants2 came online between 1994 and 1998.

But since late 2007, at least nine proposed commercial-scale IGCC facilities in the U.S. (and another six outside of North America) have been canceled or shelved indefinitely, including units proposed by Tampa Electric, Xcel, NRG, Tondu Corp., Southwestern Power Group, Buffalo Energy Partners, Southern Co., and Energy Northwest. These cancellations were driven by a combination of factors, including intense public and political attention to climate change, the prevailing uncertainty related to the regulation of CO2 emissions, and skyrocketing capital costs that have been impacting all industry sectors worldwide.

“Many of these were not merely newspaper headlines – they were projects that had been in planning for years and already had millions of dollars invested in them,” says Phil Amick, gasification commercialization director for ConocoPhillips (Houston, TX; www.conocophillips.com) and former chairman of the Gasification Technologies Council (GTC; Arlington, VA; www.gasification.org).

Meawhile, the TGCC community was dealt another setback last January, when the U.S. Dept. of Energy (DOE; Washington, DC; www.doe.gov) abruptly announced that it was canceling the flagship “zero-emissions” FutureGen IGCC power plant (see box, p. 11), citing, among other things, rapidly escalating construction costs.

Nonetheless, many industry observers say that, at least for the short term, it’s unrealistic to assume – or to demand – that the U.S. will wean its dependence on coal. Today, nearly 50% of U.S. electricity generation comes from coal, according to the U.S. Energy Information Administration’s 2008 Annual Energy Outlook (www.eia.doe.gov), and an estimated 263 GW of new baseload power generation is expected to be required to meet U.S. demand between now and 2030. Instead, coal advocates say that the best hope for enabling the most environmentally responsible use of coal – still the lowest-cost, most widely abundant fossil fuel in the U.S., with enough estimated reserves to last 300 years – lies within the engineering community.

Moving forward with IGCC

While it’s generally accepted that conventional IGCC facilities (i.e., those not yet equipped with carbon capture and sequestration, or CCS, capabilities) cost roughly 10-20% more than either conventional coalcombustion or natural-gas-fired combined cycle (NGCC) power plants, proponents agree that this cost difference will shrink as more commerciaJscale IGCC facilities are built, allowing advanced technologies to be vetted and economies of scale to result from the broader use of proven, standardized plant designs.

“Although both combined cycle and gasification technologies are wellproven in other industrial applications, there is less operating history for commercial-scale, solid-fuel IGCC plants that integrate these technologies,” says Jeff Phillips, senior program manager, advanced generation for the Electric Power Research Institute (EPRI; Charlotte, NC; www.epri.com).

“When a plant moves forward using a design that’s already been vetted, the whole operating, financial and insurance community can step back and focus on the site-specific design adjustments that are needed, but still take comfort in the fact that this is essentially a 600-MW plant that has already been operating successfully elsewhere,” adds Jim Sorensen, president of consultancy Sorensenergy LLC (Allentown, Pa.), who spent 40 years with Air Products and was the founding chairman of the GTC.

Many power companies remain bullish on the IGCC approach which is arguably the cleanest way to generate electricity from coal or petroleum coke, and more amenable to CCS than coal-combustion facilities. Today, at least 30 commercialscale IGCC facilities and gasification-based pol y generation facilities (producing both power and chemicals) are still under development in the U.S., as well as another 20 outside of North America. “Fortunately, there are a few players with enough foresight to go forward in this contentious environment, says Douglas Todd, president of consultancy Process Power Plants LLC (Galway, NY), who spent 35 years at GE developing the combined-cycle and IGCC business before starting his firm seven years ago.

Phillips also applauds these ongoing efforts, saying: “When it comes to IGCC, many public agency and private funders have become disillusioned, but as long as fundamental technology performance results continue to meet expectations – which they do – and a path to cost reductions is clear – which it is – perseverance by project sponsors is crucial to maintaining momentum.”

Engineers are hard at work on efforts to demonstrate and commercialize a diverse array of technology advances – some evolutionary, some revolutionary – that are aimed at reducing IGCC’s capital and operating costs, minimizing the main reliability and availability issues that have emerged from the first generation of IGCC facilities, and addressing the increasingly urgent question of CO2 capture. In fact, according to EPRl’s Phillips, the most promising nearterm advances-1 have the potential to reduce the capital costs of IGCC by as much as 10% to 35%, “but not without sustained R&D effort and appropriate funding.”

‘Today, we see that most, if not all, proposed coal-based power plants are expected to include CCS – well before any binding regulations are in place or there has been meaningful commercialscale demonstration and acceptance of carbon- sequestration technologies,” says Harry Morehead, manager of IGCC business development for Siemens Power Generation (Orlando, FL) and vice chairman of the GTC. As a result, efforts are also underway to make the IGCC plants of tomorrow “carbon-capture ready” for the inevitable day when federal and/or state regulations related to CCS finally fall into place (see box, p. 12).

Improving the “gasification island”

At the heart of any IGCC facility is the coal gasification system that converts pulverized coal into syngas, which is then used to fire the gas turbine (Figure 1). Pulverized coal can be introduced to the pressurized gasification reactor either in dry form (typically using nitrogen-based pneumatic conveying and a series of lock hoppers), or it can be pumped as a coal-water slurry. Once inside, the coal is reacted with steam and oxygen (or air) at high temperatures (typically 2,500-2,800[degrees]F) to produce a synthesis gas comprised mainly of carbon monoxide and hydrogen, with smaller quantities of methane, carbon dioxide, hydrogen sulfide and water vapor.

Today, several competing gasifier designs are available. In general, they are distinguished by their use of dryfed versus slurry- fed coal, their use of oxygen versus air, the reactor’s flow direction (up-flow, down-flow, or circulating), and the means used to cool the syngas (to enable pollutant removal prior to combustion in the gas turbines).

Improving the feed systems

According to EPRI’s Phillips, slurry-fed gasifiers (such as those offered by ConocoPhillips, GE Energy and others) tend to have a cost advantage over dry-fed systems (which are available from Shell, Siemens, KBR, Mitsubishi, Uhde and others). However, they are not amenable to the use of lower-rank coals, such as lignite, sub- bituminous and Powder River Basin coals, which contain a larger fraction of water and ash (with moisture content ranging from 9% to 40%). And slurry-feed injectors are subject to very severe duty, making them susceptible to frequent maintenance and replacement.

“Efforts aimed at improving dryfeed gasifiers are attracting a lot of attention today, because there’s strong desire in the IGCC community and the market it serves to be able to gasify the lower- cost, lower-rank coals,” says consultant Sorensen.

“Dry-fee gasifiers also have improved efficiency, by avoiding the use of heat in the gasifier to evaporate the moisture, and their capital and operating savings are expected to hold whether the system is equipped with CO2 capture or not,” adds Tetsuya “Terry” Fujino, manager of boiler and IGCC engineering for Mitsubishi Power Systems Americas (Lake Mary, FL; www.mpshq.com).

One promising development is a new dry-coal-pumping system that had been under development (with DOE support) by Stamet, Inc. It can pressurize and feed the dry pulverized coal at a pressure of up to 1,000 psi (70 bar) into the gasifier, thereby reducing the capital and maintenance requirements associated with the existing lockhoppers that are used to do this. In June 2007, Atlanta-based GE Energy (www.ge-energy.com) acquired Stamet, and is now working to integrate Stamet’s proprietary rotary pump technology for dry coal with its existing slurry-fed gasifier technology “to accelerate the expansion of GE’s existing IGCC plant design offering for sub- bituminous coal,” says Keith White, director of GE Energy’s IGCC platform. Prart & Whitney Rocketdyne (East Hartford, CT; www.pw.utc.com), with DOE funding, is also developing an advanced gasifier and rapid-mix, dry-solids injector pump.

Meanwhile, EPRI predicts that another promising development could benefit IGCC plants of tomorrow specifically those equipped with CCS capabilities: the use of a slipstream of recovered liquid CO2 to replace water as the medium for slurry-fed coal gasifiers. “Liquid CO2 has a lower heat of vaporization than water, and is able to carry more coal per unit mass of fluid,” explains Phillips. “As a result, the liquid CO2-coal slurry will flash almost immediately upon entering the gasifier, providing good dispersion of the coal particles and potentially yielding the higher performance of a dry- fed gasifier with the simplicity of a slurry-fed system.”

EPRI identified and piloted the use of CO2-COaI slurrying as a bona fide IGCC innovation concept more than two decades ago. “Early on, the cost of producing liquid CO2 was just too high to justify the improved thermodynamic performance,” explains Phillips. “But today, the anticipated CCS requirements will change that by substantially reducing the incremental cost of producing liquid CO2 at the site.”

Protecting the ga si fie r from slag

Inside a conventional entrainedflow gasifier, coal ash melts into a molten slag, which is both corrosive and erosive. Today, high- temperature entrained-flow gasifiers typically rely on one of two technologies to protect the gasifier vessel from temperaturerelated degradation and loss of strength and damage from the molten slag – either the use of a multi-layer refractory lining (as in the ConocoPhillips and GE Energy gasifiers), or the use of a water- cooled membrane wall design (Shell, Siemens and Mitsubishi use this approach). (A newer gasifier that produces no slag, developed by Southern Co. and KBR, is discussed later).

The membrane wall (also called a cooling screen) combines tubes and fins that are welded together to form a continuous wall around the hot reaction zone inside the gasifier, to protect the pressure vessel. During operation, a layer of chilled slag forms along the tube surfaces. Molten slag then continues to flow down this frozen slag layer and is removed. “This provides a more economical alternative to refractory-lined gasifiers, since outages related to refractory problems have proven to be one of the most common difficulties encountered during IGCC gasification,” explains Fujino.

When refractory linings are used, they are susceptible to corrosive and erosive attack by the molten slag produced inside the gasifier. “Replacing the gasifier refractory is costly and time- consuming, so any chance to increase the time between turnarounds is an important opportunity to increase overall power plant availability,” says consultant Sorensen.

Today, an advanced refractory material, developed by DOE’s Albany Research Center, is being tested at several gasification sites. Based on conventional chromium oxide refractory that has been improved by the addition of aluminum and chrome phosphates, its goal is to extend the replacement interval from the current 12-18 months to 36 months. Typical refractory replacement requires 3-4 weeks of gasifier downtime.

“If a 36-month changeout goal could be achieved, it would not only save the cost of the refractory replacement (typically about $1 million for materials and labor per changeout), but would increase gasifier availability by 2.5 to 5 percentage points, and potentially eliminate the need to maintain a spare gasifier,’ says Phillips of EPRI.

Instrumentation, control and modeling

The IGCC facilities of tomorrow are also expected to benefit from improved systems to monitor key process variables, and to model the complex operations in both the gasification and power islands. For instance, Southern Co. (Atlanta, GA; www.southernco.com) is currently testing real-time particulate monitors to keep track of ash content and particle size. It is also working on advanced devices to enable better in situ temperature measurement in the erosive and corrosive conditions in the gasifier, and to improve the realtime, in situ detection of mercury in the syngas.

Southern Co. has also collaborated extensively with DOE’s National Energy Technology Laboratory (NETL; Pittsburgh, PA; www.netl.doe.gov) to test and validate DOE’s “MFIX” models, which combine computational fluid dynamics (CFD) with real-time chemistry simulations to provide added insight into the gasification process. “We’ve worked with DOE to use these powerful models to fine-tune the gasifier, and others are using them as well,” says Kerry Bowers, director of the Power Systems Development Facility (PSDF; Wilsonville, AL), a semicommercial-scale gasification plant that is co-owned and operated by Southern Co. and DOE.

Meanwhile, Morehead notes that Siemens is working to apply advanced control system architectures (combining advanced instrumentation and artificial intelligence databases) to improve both the gasification and combined-cycle aspects of IGCC. Such systems are already helping NGCC power plants, by monitoring system health and providing condition-based diagnostic information to plant operators, he says. Siemens has also developed a camera-based monitoring system mounted on the gas turbine that allows operators to more easily assess the condition of the first row of turbine blades.

Similarly, the standard GE-Bechtel IGCC plant design incorporates advanced controls that “are intended to recognize and correct minor operability issues to avoid trips and increase plant reliability,” says White of GE Energy. Improved simulation capabilities are also expected to improve overall IGCC operation. “‘With tens of thousands of control points and many more secondary interactions, it is extremely difficult to fully understand the effect of operational decisions on IGCC plant performance,” says White. In addition to validating the plant’s controls and enabling modeling to support decision-making, he notes that “GE’s IGCC plant simulator is a useful training tool, allowing operators to explore the full range of potential plant operations and fault scenarios and to develop a deeper understanding of complex IGCC dynamics.”

Air-blown gasification: The new kid in town

While the prevailing approach to IGCC requires a 95%-pure stream of oxygen (produced onsite via costly airseparation units [ASUs] that rely on capital- and energy-intensive cryogenic distillation columns), a radically different approach to IGCC – one that uses air- blown gasification to convert coal into syngas – is being developed by a partnership of Southern Co. and Houston-based KBR, and by Mitsubishi Heavy Industries (MHI; Yokohama, Japan). The companies claim that air-blown IGCC provides significant economical advantages over the oxygen-blown approach.

“The ASU typically accounts for 15% of the total capital costs and consumes 15% of the gross power output of an IGCC facility, so the ability to eliminate it provides significant cost advantages for air-blown IGCC,” says David McDeed, manager of application engineering for combined cycle for Mitsubishi Power Systems Americas (Lake Mary, FL; www.mpshq.com). Additional savings come from eliminating the slurry-making equipment train, too, since both the Southern/KBR and Mitsubishi air-blown gasifiers rely on dry-coal- feed gasifiers.

While the Mitsubishi and Southern/KBR gasifiers both rely on air instead of oxygen, that’s where the similarities end – they are fundamentally different in both design and operation. For instance, Mitsubishi’s TGCC flowsheet (Figure 2) uses an air-blown entrained- flow gasifier (the most common design used in oxygen-blown IGCC, as well). It reacts the pulverized coal with air in a semicombustion mode at extremely high temperatures (on the order of 2,500- 2,800[degrees]F), producing syngas and byproduct ash, which is melted into slag and continuously removed.

In contrast, the Southern/KBR IGCC flowsheet features the proprietary air-blown transport reactor integrated gasification (TRIG) system, “a non-slagging, circulating, fast-fluidized-bed reactor that represents a completely new approach to gasification,” says Bowers.

Based on a high-velocity, fluidized-bed reactor design (similar to those used by fiuidized catalytic crackers, or FCCs), the TRIG gasifier “has no burners and no burner zones,” says Bowers. Instead, dry pulverized coal and air are injected at high velocity into the reactor, where they co-mingle with a bed of hot (roughly 1,800[degrees]F) circulating solids, driving the conversion of coal to syngas. “We haven’t had to struggle with the slagging issue at all, because by operating 700[degrees]F to 1,000[degrees]F cooler than conventional gasifiers, the TRIG reactor is able to avoid the creation of high-temperature molten slag altogether,” he says. (The TRIG reactor can also be operated in an oxygen-blown mode, and to date, has logged more than 5,000 h of oxygen-blown operation at PSDF.)

To validate its air-blown IGCC design, Mitsubishi has built a commercially sized (250 MW) demonstration plant (owned by a consortium of Japanese utilities and Japan’s Ministry of Economy, Trade and Industry) in Nakoso, Japan. Since last September, the facility has logged more than 1,500 h of service and all systems “are working as expected,” says Fujino. As for the TRIG technology, it was supposed to have had its commercial debut at a 285-MW IGCC facility that was being developed by Southern Co. and the Orlando Utilities Commission. Unfortunately, that facility (which had already broken ground) was part of the wave of IGCC projects that were cancelled in late 2007.

Now, Southern Co. is hoping to debut the TRIG system as part of a 600-MW IGCC plant that is being developed by its subsidiary Mississippi Power. That facility is now undergoing front-end engineering and design and is working its way through the regulatory process.

Debunking the myths. The use of air instead of oxygen as the reactant during coal gasification introduces excess nitrogen into the process. Skeptics have long questioned what the penalties of that excess nitrogen might be, in terms of equipment sizing requirements and related design issues and operational costs.

Advocates of air-blown IGCC say that no real penalties arise. “Because the TRIG gasifier and downstream equipment are operating at high pressure (500 psi), the incremental increase in syngas volume resulting from excess nitrogen moving through the system is minimal,” explains Bowers.

Meanwhile, because combined cycle IGCC power plants already capture waste heat from the gas turbines to produce steam for the steam turbines, the added volume of nitrogen passing through ”helps us to significantly increase the amount of heat captured and steam produced, which increases the overall electrical output from the steam cycle,” says Fujino, adding: “Taken together, the capital cost reductions (by eliminating the air-separation unit and slurry- making equipment), combined with the higher power output, result in lower overall cost per kilowatt.”

Skeptics also wonder whether the added nitrogen content in the airblown syngas might impede gas turbine operation. Not so, say both Southern Co. and Mitsubishi. “Since the combustion of 100% oxygen- blown syngas would result in unacceptable NO^sub X^ emissions, oxygenblown IGCC facilities already routinely blend nitrogen into the syngas (as a diluent ahead of the turbine combustors) to maintain the turbine firing temperature in the optimal range and control peak flame temperatures,” explains Fujino.

As a result, according to Bowers, “the air-blown syngas (with higher nitrogen content) delivered to the combustor nozzles of an IGCC gas turbine has almost identical properties to diluted oxygen- blown syngas, so from a combustion viewpoint, there is little difference between the two approaches for power generation.”

And both say that reliance on nitrogen dilution in IGCC is likely to increase in coming years, as more power plants are forced to convert CO to CO2, leaving behind a shifted syngas stream enriched in hydrogen.

Similarly, when it comes to adding the equipment trains needed to achieve the 90% carbon capture likely to be required in the future, both Southern Co. and Mitsubishi say that their air-blown IGCC+CCS designs have no major disadvantages compared to oxygen-blown IGCC+CCS. Figure 2 shows Mitsubishi’s proposed flowsheet for air- blown IGCC+CCS.

“We have performed extensive engineering analyses of the technologies required for 90% CO2 capture, and DOE has independently validated our conclusions. While some of the process vessels required for the water-gas shift reaction do increase in size a little due to the increased nitrogen throughput, the solvent-based CO2-separation systems are unaffected,” says Bowers. “So overall, the beneficial economic effect of air-blown gasification is sustained, even when adding CO2 capture.” Ongoing experience at Nakoso, and the chance to demonstrate air-blown IGCC at Southern Co.’s proposed commercial-scale facility in Mississippi, may finally help lay to rest some of the prevailing skepticism surrounding the air-based approach.

Restoring IGCC’s luster

Over the past year or so, the headlines proclaiming the cancellation of many proposed IGCC and coal-fired power plants seemed to foreshadow the death of IGCC. However, IGCC proponents are confident that the breadth and depth of the technology advances being pursued today will ultimately put IGCC back in the headlines again – but in a more positive light, as new facilities are able to demonstrate the inherent advantages that IGCC provides for producing power from coal, even in a carbon-constrained world.

“Coal is the largest domestic energy resource, gasification is the biggest opportunity for coal, and coal-to-power is the largest opportunity for gasification,” says Amick of ConocoPhillips.

“IGCC is not dead,” adds Morehead of Siemens. “It’s evolving every day.”

Many technology advances are underway to address cost, CO2 and reliability issues and expand the use of integrated gasification combined cycle (IGCC), a cleaner way to generate electricity from coal.

In addition to the IGCC “gasification island” developments discussed here, parallel advances in the “power island,” to improve the efficiency and power output of the gas turbines used and to develop specialized turbines that can handle high-hydrogen shifted syngas once CCS is routinely used, have occurred. Those will be discussed in the October issue.

1 Combined-cycle power generation involves the use of one or more gas turbines (fired by either natural gas or, in the case of IGCC, coalderived syngas); the waste heat from the gas turbine(s) is used to produce steam, which drives one or more downstream steam turbines, producing additional electricity.

2 The Wabash River facility in Terre Haute, IN, Tampa Electric’s Polk facility in Tampa, FL, Nuon’s facility in Buggenum, The Netherlands, and the Elcogas unit in Puertollano, Spain, all of which are still in operation.

3 A 190-page report from EPRI. entitled “CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants. Technical Update, January 2007,” can be accessed free of charge at www.epri.com. Enter the report number (1013219) in the search box.

Suzanne Shelley

Contributing Editor

Copyright American Institute of Chemical Engineers Sep 2008

(c) 2008 Chemical Engineering Progress. Provided by ProQuest LLC. All rights Reserved.