Gasification & IGCC Forum

2011-09-27T21:09:00.001-04:00

Gasification and IGCC in the news

A bright spot for IGCC:

DOE moves to release funding
for Texas Clean Energy Project

According to today's Fossil Energy Techline, the US DOE issued a Record of Decision (ROD) that – along with a signed cooperative agreement – will allow federal funding to be used to help build the Summit Power Texas Clean Energy Project - an advanced first-of-a-kind clean coal power plant.

The ROD and cooperative agreement between DOE’s Office of Fossil Energy (FE) and Summit sets in motion continued federal cost-shared funds for the project, to be built just west of Midland-Odessa, Texas.

The 400MW facility is a "poly-generation" plant, combining IGCC power generation, urea production, and CO2 capture for use in enhanced oil recovery in nearby oil fields.

The project will be partially funded with $450 million from Fossil Energy's Clean Coal Power Initiative. About half of this will come from the funds allocated by the American Recovery and Reinvestment Act of 2009 for such projects.

DOE’s action to issue the ROD was reached after considering, among other things, the project’s potential environmental impacts and the options for mitigation of the impacts.

"The Texas Clean Energy Project is vitally important...... and a significant step forward that demonstrates the US commitment to developing clean energy technologies and reducing emissions of greenhouse gases," said Chuck McConnell, FE’s Chief Operating Officer.

The plant will convert sub-bituminous coal into hydrogen-rich syngas and CO2. The syngas and high-quality steam will be fed to the combined-cycle plant to produce electricity. The facility will integrate Siemens' IGCC technology and Linde Rectisol® acid-gas removal technology to capture 90 percent of the CO2 from the syngas—about 3 million tons per year.

A portion of the captured CO2 will be used to produce urea for fertilizer while most of it will be used for enhanced oil recovery with monitoring, verification, and accounting to demonstrate the permanence of geologic storage. The CO2 will be transported through existing regional pipelines to the oil fields of the west Texas Permian Basin, the largest CO2-EOR region in the world.

Of the 400MW of electrical power generated by the combined cycle plant, about half will be used on site and the other half will be delivered to the power grid. The plant will also produce sulfuric acid, argon, and inert slag as minor products for sale in commercial markets.

According to Summit, sale of CO2 will generate about one-third of the project's gross revenues.

The project is expected to create an average of 650 jobs during construction, with a peak of 1,500 workers. The project’s operational workforce is expected to be approximately 150 workers.

The current schedule is for TCEP to become operational late in 2014 or early in 2015. This assumes that financial closing will take place early in 2012.

2011-08-29T21:30:00.001-04:00

Gasification & IGCC in the news:

Texas Clean Energy
IGCC Still on Track

Summit close to PRB coal

deal for Texas IGCC plant

Summit Power Group, developer of the Texas Clean Energy Project, is "probably within a month" of closing on Powder River Basin coal supplies for its $2.7 billion Texas Clean Energy Project near Odessa. So said a company official Wednesday, Aug. 24, at the American Coal Council's Coal Market Strategies conference in Colorado Springs, Colorado.

The TCEP involves a 400-MW integrated gasification combined cycle (IGCC) power plant -- scheduled to start construction next year and enter service in 2015. It will use 2 million ton/year of PRB coal, says Barry Cunningham, Summit managing director of project development.

Summit is talking with three PRB producers for supplies and is finalizing a contract with one of them, Cunningham said, declining to disclose names.

The business plan for the "polygen" project relies heavily on revenue from the production of byproducts, what Cunningham termed a "diversified revenue stream."

Revenue will come from 2.7 million ton/year of compressed CO2 to be sold for oil production at nearby wells, he said. The plant will capture 90% of its CO2, making it one of the world's highest CO2-capturing plant projects, Cunningham said.

One ton of CO2 yields 2.5 to 3 barrels of additional oil production, he said.

But urea production for agricultural fertilizer is expected to be the biggest component of the plant's revenue stream at 46%, he said.

All told, the plant will yield 190 MW net for power sales to the grid, Cunningham said, elaborating on the high cost of using self-generated power for the plant's CO2-capture system. This process "cannibalizes about 50% of the electricity" production, one conference participant remarked.

Last month, Gas Turbine World reported that someone close to the project commented that the key issue for TCEP is to keep capital costs in check as it approaches the banking community for project finance. This positive news about a pending coal supply contract should also help move it in the right direction.

2011-07-26T22:13:00.012-04:00

With CCS on back burner what happens to coal-based IGCC ?

AEP pullout from large-scale CCS demo is setback for coal-plant retrofit program, and for hopes of IGCC becoming competitive.

Bloomberg Business Week's July 21 issue features a must-read article entitled "What's Killing Carbon Capture?". It reports on the decision by AEP to cancel plans to demonstrate ammonia-based post-combustion CO2 capture at their 1300MW Mountaineer coal-fired power plant in West Virginia.

Citing the high cost of the project and given the fact that the US government has yet to come up with any policy related to carbon capture and sequestration (or "CCS"), AEP announced that they would not go beyond the current $100 million proof-of-concept pilot project at the plant.

Without the requirement for power plants to employ means of reducing CO2 emissions, what can be said about the future for IGCC technology as the preferred form of coal-based power generation in a carbon-constrained world?

As summarized in past issues of Gas Turbine World magazine, numerous industry and government studies have shown that the cost impact of employing post-combustion CCS on conventional coal plants is so great that IGCC + CCS technology (with pre-combustion CO2 removal) would be elevated to the status of the lowest-cost option for future coal-based power generation.

However, if there is no regulatory requirement, or even some significant cost incentive such as a CO2 tax, to coerce power generators to employ CO2 capture, the apparent 20+ percent cost premium for the use of IGCC vs. conventional PC technology would be very difficult to justify.

To many, the high cost of current coal-based IGCC projects such as Duke's Edwardsport and the Mississippi Power Kemper County plant has already spelled the end of IGCC as we knew it.

For a while it appeared that the concept of a 'hybrid IGCC' plants was a winning idea, where coal-derived SNG would be produced for either power generation or injection into the natural gas pipeline. The associated power plant would be a stand-alone gas-fired combined cycle unit.

But even those projects (for example, Tenaska's Taylorville "IGCC" in Illinois) are proving too expensive, and with the growth of shale gas production and the precipitous fall of natural gas prices, there is no way for SNG from coal to be competitive in the foreseeable future.

Perhaps the answer is "polygneration" - such as being employed at Summit's 400MW Texas Clean Energy Project, where the sale of plant byproducts, including chemicals and CO2 for enhance oil recovery, appears to be making the project economically viable. This is yet to be seen, however, as the project developers pursue bank financing.

To this writer, CCS in any shape or form always seemed to be too expensive - both in capital costs and in its impact on operating costs - for it to be commercially acceptable. If there were going to be constraints on CO2 emissions, alternative cheaper ways to reduce CO2 emissions would have to come along
.

With natural gas combined cycle (NGCC) plants emitting only half the CO2 of coal-based generation, and costing only a fraction to build, they have emerged as the clear winner. This is particularly true in the US under currently depressed natural gas costs, and is making a lot of sense in Europe too, where there is a cost placed on CO2 emissions and shale gas is beginning to come into play.

The Business Week article on the sorry state of CCS does not come as any surprise, especially, as it points out, with the US government putting any specific climate-change regulations on the back burner. Without a clear government policy, industry will only act in its own best interest.

The big question still on the table, however, is whether or not the US EPA will issue CO2-reduction rules for existing and new coal plants.

The agency has already dug a huge hole for itself with its new rules regarding hazardous pollutant emissions and new interstate pollution rules, which together threaten to shut down a large portion of the US coal fleet.

As I see it, any ruling regarding CO2 emissions, effectively mandating either CCS retrofit or plant closure, has been put off for at least several years.

As AEP has pointed out, they have done their share to host a pilot project to demonstrate that the technology works, now they owe it to their stake holders to put CCS on the shelf while the rules of the game are clarified. (Recall that AEP also made a big run at IGCC a few years back, only to cancel efforts on several announced projects due to high costs.)

Yes, the requirement to add CCS to coal-based power generation was supposed to "level the playing field" for IGCC to compete. For now, as long as that requirement doesn't exist, and use of natural gas in a new combined cycle plant is the cheapest way to reduce carbon emissions, IGCC will again have to wait its turn. Whether or not it ever makes another comeback, is not at all clear.

As described in the May-June issue of Gas Turbine World, this is all points to a sustained period of growth for the gas turbine industry. Some of the largest coal-based utilities in the US, including AEP, Xcel, Duke and TVA, are already making plans to shut down their obsolete 50-year old PC plants and replacing them with new high-efficiency NGCC plants.

Even if natural gas prices are to increase by 50% or more from where they are today, studies show that a new combined cycle plant would still make a lot more economic sense than to invest billions in retrofitting those old coal plants to clean them up.

2011-06-29T14:06:00.001-04:00

COAL GASIFICATION NEWS:
Texas Clean Energy IGCC being readied for financing

TCEP reaches major milestone with signing MOU for PPA

The Texas Clean Energy Project (TCEP) is nearing the point of lining up a group of banks to arrange project financing.

So says one industry leader close to the project.

"The key to achieving the next big step will be keeping capital costs in line," he said.

Last week, TCEP took an important step forward with the signing of a memorandum of understanding (MOU) for the purchase of half of the electricity produced by what will be one of the world’s most advanced and cleanest coal-based power plants.

Under the 25-year agreement, CPS Energy – a municipally owned utility serving San Antonio, Texas – will purchase electricity generated by the first-of-a-kind commercial clean coal power plant starting in mid 2014.

TCEP, a 400MW IGCC facility located near Odessa, TX will capture 90% of its CO2 – approximately 3 million tons annually – more than any power plant of commercial scale operating anywhere in the world.

The project was originally proposed as the losing candidate from Texas for the ill-fated FutureGen IGCC project, which was to be built in Matoon, IL.

In January 2010, DOE awarded a cooperative agreement to Summit Texas Clean Energy to design, construct, and demonstrate an IGCC power plant that can co-produce high-value products and capture CO2.

The CO2 captured from TECP will be used for enhanced oil recovery (EOR) in the West Texas Permian Basin. EOR is a way to squeeze additional hard-to-recover oil from older fields, and is an increasingly important contributor to U.S. oil supplies.

Additionally, the plant will produce urea, a high-value chemical, and smaller quantities of commercial-grade sulfuric acid, argon, and inert slag, all of which will also be marketed.

Summit has selected Siemens gasification and combined-cycle technology for the project, and Fluor was awarded the EPC contract.

CPS Energy signed the MOU to purchase 200MW from Summit Energy's TCEP, or half of the plant's electric energy output. In announcing the agreement CPS Energy President and CEO Doyle Beneby stated that the IGCC plant will be cleanest coal-fueled power project ever permitted in Texas.

Ironically, five years ago, the utility decided against building its own IGCC plant and instead invested $1 billion in a new 750MW conventional coal-steam plant that was just completed. At the time, the utility commented that IGCC was "not ready for prime time".

U.S. EPA Administrator Lisa Jackson said in a statement released at the signing ceremonies that “San Antonio is stepping up to lead Texas and our nation into a clean energy future....."

On the same day CPS announced that it plans to shut down its two-unit late-1970s vintage JT Deely coal station to avoid spending as much as $3 billion for environmental equipment needed to upgrade the 871MW plant to comply with pending EPA regulations.

From DOE Fossil Energy TECH LINE and other sources

2011-06-07T14:45:00.003-04:00

Kemper County IGCC plant "on schedule and budget"

GULFPORT, Miss.

Construction of Mississippi Power Co.'s Integrated Gasification Combined Cycle (IGCC) power plant in Kemper County is on schedule and on budget, the company's head says.

Last year, the Mississippi Public Service Commission approved the company's proposal for the project and in December, ground was broken.

As a result of a law the Mississippi Legislature passed in 2008, the cost of the plant will be passed on to ratepayers in stages while the project is being built. In its approval for the project, the PSC set a cap for the cost of the plant at $2.88 billion.

In a recent speech given by Mississippi Power chief executive Ed Day he said the company aims to keep the cost below the cap. The goal is to have the plant operating in 2014.

"Internally, we really only talk about $2.4 billion," Day said.

The plant has been fought by the Mississippi Sierra Club, which has concerns over environmental aspects of the project, along with the company's plans to pass construction costs on to ratepayers. The Sierra Club contends the plant is dirty, expensive and unnecessary and that natural gas would have been a better fuel source.

The company contends that the price of natural gas is much less predictable than that of lignite coal, which the plant will use. The company says lignite is abundant in Mississippi and represents the best option.

Day said there's a chance large fuel cost savings by using the coal could result if natural gas prices rise substantially over the next few years. Typically, about 50 percent of a ratepayer's power bill goes toward fuel costs.

"We know what (price) the coal will be mined at, within a small tight range, it's just now a matter of what will gas do, and how high will it go," Day said. "There's got to be a natural fuel savings to the customer over long periods of time. That's kind of what wins the day."

The increase on a customer's power bill could range from as much as 33 percent, according to the company, to as high as 48 percent, according to the Sierra Club.

Mississippi Power has said those increases could be phased in over 10 years.

Editor's note: At $2.4 billion, the nominal 600MW Kemper County plant will cost $4000/kW to build. A new natural gas fired combined cycle plant would cost less than one-quarter of that amount. For the total cost of energy (covering investment, fuel cost and other operating expenses) to be the same, natural gas price would have to climb from the current $4 per million Btu to about four times that level. Although those high prices are paid for natural gas today in places like Japan, plentiful supplies in the US are expected to keep the price low for the foreseeable future.

2011-04-08T15:13:00.003-04:00

April 7, 2011Amsterdam Nuon postpones implementation of
IGCC technology at Magnum plant

Nuon has decided to postpone its plans for the possible gasification of biomass and coal at its new 1200MW "Nuon Magnum" power plant at Eemshaven. The construction of the gas-fired power station, being built around three Mitsubishi (MHI) M701F4 combined cycle trains, is progressing well. This power station will be ready at the end of 2012 and will supply electricity to two million households.

The company says that commercial reasons, such as the trend in raw material prices, play a significant role in the decision not to make an investment decision at this time about the application of gasification technology. This technology would consist of a coal and biomass gasification element combined with the capture and storage of CO2.

In addition, this decision is the result of a long-running dialogue between Nuon and various environmental organizations, among others. An agreeement has been reached with these organizations under which Nuon states that it will not bring the gasification part of the power plant on stream before 2020.

Other important elements of the agreement relate specifically to CO2 emissions. Once the gasification part is ready, these emissions will not exceed 360g/kWh, or about 800 lb/MWh (equivalent to the emissions from a modern gas-fired power plant). This will require removal of approximately 50% of the CO2 that would otherwise be produced by that type of gasification-based combined cycle plant.

At the same time, the environmental parties involved are withdrawing their legal objections to the gas-fired power station currently under construction.

“As an energy company, Nuon is leading the way with this approach and is setting the bar high for the reduction of CO2 emissions from the coal-fired part of this power plant”, says Ron Wit from the Netherlands Society for Nature and the Environment. “This approach sets a good example for energy companies and should be replicated in the Netherlands and Europe.”

Recent discussions about CO2 capture and storage have shown that there is currently insufficient support for this technology, in particular for onshore storage. The postponement of the investment decision for the expansion is in line with the strategy previously adopted by Vattenfall not to build new coal-fired capacity without the possibility of CO2 capture and storage.

“The use of coal and the capture and storage of CO2 is part of a wider debate in society”, says Huib Morelisse, CEO of N.V. Nuon Energy. “There are many perspectives and opinions involved in this discussion and we do not want to be constrained by the time pressure of permit or subsidy processes. This is why we have entered into this agreement with the parties involved. It is a postponement of the use of gasification technology based on biomass and coal. Because we are also contributing to the reliable supply of energy at an affordable price with Nuon Magnum, it is simply too early to exclude this multi-fuel gasification technology at this point.”

From Nuon website

2011-03-31T20:11:00.000-04:00

2010 GTC Conference Wrap-up:

IGCC on the move
despite obstacles

Five US IGCC power projects under construction or being developed will add almost 2500MW over the next 3-5 years.

Once again, a large and far-reaching turnout was attracted by the annual Gasification Technologies Council/EPRI conference attesting to the continued broad interest in the status of project and technology development connected with gasification of coal and other feedstock.

More than 600 attendees gathered from all over the world attended the 3-day Washington DC event. The range of topics presented over covered the gamut - from the booming commercial coal-to-chemicals industry in China to the emergence of new gasification-based technologies for the conversion of biomass to synthetic natural gas and liquid fuels.

The November-December issue of Gas Turbine World magazine features comprehensive coverage of key presentations made at the conference, with focus on major commercial-scale projects under construction and actively under development. A copy of this convenient wrap-up is now available at this link.

2011-01-13T16:28:00.007-05:00

Gasification & IGCC Industry News

Illinois Senate vote could
derail Taylorville coal project

Yesterday, the Illinois state Senate voted against apporoval of proposed rate subsidies for Tenaska's planned Taylorville power project by a vote of 18 to 33. The proposal had been previously approved by the Illinois state House, which voted (63 to 50) on it last November.

Tenaska planned to commence construction on the $3.5 billion project in mid 2011. Without the Senate approval, Tenaska will need to reconsider its plans.

The project design incorporates Siemens' technology to gasify Illinois coal to produce a synthetic gas ("syngas"), which would be used as fuel to generate electricity in the 602MW combined cycle facility.

Tenaska expects to include pre-combustion processing of the syngas to capture more than 50 percent of the CO2 produced, thereby making the CO2 emissions similar to a natural gas fired power plant. The captured CO2 would then be sequestered, either by storing the CO2 underground in Illinois or transporting the CO2 via pipeline to Gulf Coast states, where it would be injected into oil fields to enhance oil recovery.

Tenaska plans to rely upon federal support for the project, which is sited approximately 200 miles south of Chicago in Christian County. The company has stated that it is waiting for final approval on a $2.579 billion federal loan guarantee and that it plans to use a $417 million federal tax credit.

There has as yet been no statement from Tenaska as to the impact of the state Senate vote to deny the state-subsidized rates for the power to be sold from the project.

2010-12-30T16:14:00.011-05:00

Summit Clean Energy Texas
coal-based IGCC / Polygen
plant gets air-quality permit

First-of-a-kind project passes
major regulatory hurdle

The proposed $2.2 billion "clean coal" plant in West Texas has passed a major regulatory hurdle, receiving approval from the Texas Commission on Environmental Quality for an air-quality permit earlier this week.

Summit Power Group's project is to use Wyoming coal while employing integrated gasification combined cycle (IGCC) technology to convert the coal to a clean "syngas", which will be used to produce electricity and other products, such as urea for fertilizer production. The plant is also designed to capture 90 percent of carbon dioxide emissions from the process and will be a "first-of-a-kind" plant in Texas, Summit said in announcing the permit.

"This is a milestone moment for America's energy economy and this project," said Summit Chairman Donald Hodel, who was energy secretary during the Reagan administration.

"We are delighted to be building this project in Texas, where federal, state and local elected officials have all worked effectively toward the same objective, namely to bring near-zero-emissions coal technology to the world marketplace," Hodel said.

Construction to start 2nd half 2011

The plant is to be built on 600 acres in Penwell, 15 miles southwest of Odessa. Construction is to begin in the second half of 2011 and operations should start in late 2014, said Laura Miller, Texas projects director for Summit and the former Dallas mayor.

The project "will be an economic boon to West Texas, creating more than 1,500 jobs at the peak of construction, 150 high-wage permanent jobs when the plant is operational, and 200 additional jobs in periods of major maintenance," Summit said.

The project has had a high profile because of the advanced technology it will employ. It has received $450 million in federal grants and therefore must undergo an environmental impact assessment, which is under way.

Earlier this year, Summit announced that the West Texas plant will employ technology and equipment for both the gasification process and the combined cycle power generating unit to be supplied by Siemens Corp.

"Overall cleanest" coal plant

Summit said the plant will be "overall the cleanest coal-fueled power project ever permitted in Texas," capturing not only the bulk of CO2 emissions, but also 99 percent of the sulfur, more than 95 percent of the mercury and more than 90 percent of nitrogen oxides.

Chemical processes will convert coal into clean-burning industrial gases used to generate electricity. The process creates a "pure stream" of CO2 that will be captured and sequestered, according to Summit.

The captured CO2 will be diverted to West Texas oil fields to boost oil recovery. This will complement or replace naturally occuring CO2 currently being supplied by pipeline from outside of the area. Reportedly, approximately one-third of the project's operating revenue will be derived from the sale of CO2 for this purpose.

The Summit plant is rated at 400MW gross generating capacity, but that is reduced to 214MW net output as a result of the heavy on-site plant power consumption to support the conversion process and the processing of plant byproducts. That still is enough capacity to power more than 200,000 homes, based on an often-cited yardstick of each megawatt providing enough power for 1,000 homes, Miller said.

Source: Ft. Worth Star Telegram
jzsmith@star-telegram.com

2010-12-17T11:48:00.003-05:00

GTW ANNUAL HANDBOOK
NOW AVAILABLE ONLINE

Includes up-to-date
IGCC reference data

Gas Turbine World's annual Handbook, the Power Industry's standard reference guide for gas turbine pricing data and performance specifications, is now available online from Industrial Info Resources (Sugar Land, Texas).

A feature contained in the Handbook that is of special interest to the Gasification & IGCC community is an up-to-date reference for IGCC plant performance specifications and a listing of currently active IGCC and gasification projects under development.

"Now, for the first time, power project developers, original equipment manufacturers, plant owners, and engineering and construction firms can easily and rapidly access critical performance parameters and prices for gas turbines," said Ed Lewis, president and chief executive at Industrial Info Resources.

"Existing subscribers to Gas Turbine World will be able to access the current annual Handbook for no added cost. And non-subscribers can purchase online access to this vital reference guide," he said.

"Power plant developers, equipment suppliers, and project owners will benefit by having instant access to this widely used reference guide," Lewis added. "Now, subscribers will never have to worry about a colleague accidentally walking off with their copy of this important industry guide."

Gas Turbine World has published an annual Handbook since 1976. This is the first time it will be available in an online version.

"People may be surprised to learn how often we get calls for a copy of the prior year's Handbooks," said Vic deBiasi, founder, editor, and publisher of Gas Turbine World.

"The GTW Handbook is an essential resource for anyone in the power business. The gas turbine pricing information we have is unavailable anywhere else. Our equipment performance specifications are used by firms around the world. We are delighted that our partnership with Industrial Info will make this authoritative, objective Handbook available to anyone in the world when they need it."

This year's GTW Handbook has detailed sections on engineering & operations, turbine inlet cooling, projected equipment prices, equipment performance specifications, Gasification & IGCC power, and global orders and installations. A company directory and list of technical project support resources also are provided for easy reference.

The Online version of the GTW Handbook will also contain quick links to access performance and pricing for simple-cycle generators, combined-cycle generators, and mechanical drives.

Making the GTW Handbook available in a PDF format is Industrial Info's first step toward digitizing the market-critical data contained in that annual publication. In 2011 Industrial Info will introduce a searchable, interactive database of all information contained in previous GTW Handbooks, Lewis noted.

"Bringing this critical information to the market in a digital format will make this industrial project data instantly available to market participants so they can more effectively develop budgets for capital projects," Lewis said. "This is another demonstration of our commitment to providing global market intelligence that constantly moves forward. We have worked closely with Vic deBiasi and his outstanding GTW team and we share a commitment to objective, verified data as the foundation for success in the power business."

Buyers of the current 2010 GTW Handbook can access the current edition of the Handbook at no extra charge, plus previous editions going back to 2006. They also can access the gas turbine design ratings and pricing sections of earlier Handbooks that were published starting in 1982. Subscribers should click here to access their copy of the Handbook.

Non-subscribers can access the 2010 GTW Handbook for $499, which includes a subscription to the GTW magazine, which is published bi-monthly. They, too, will be able to access prior annual Handbooks published since 1982 at no extra charge. Click here to request access to the Gas Turbine World magazine online.

2010-12-16T10:09:00.010-05:00

Miss. Power breaking ground
on Kemper County IGCC plant

Source: WLOX DeKalb, MS

Mississippi Power will break ground today on its next generation of power plants.

The company touts the $2.4 billion Kemper County Integrated Gasification Combined Cycle ("IGCC") Plant as a step toward energy independence in Mississippi.

The company fought a long battle to get to this stage, including questions from the state Public Service Commission and protests from environmental groups. One of the big issues was how Mississippi Power would pay for the plant.

The company had originally proposed that it be allowed to pass along construction costs to customers right away. After hearings with the PSC, the company reached an agreement to delay adding those costs to power bills until 2012.

Mississippi Power selected Kemper County for the plant site because it has huge lignite coal reserves that remain largely untapped. Mississippi Power will take the lignite and turn it into a gas to be used to produce electricity.

Construction of the Kemper County plant will create about 1,000 jobs. Mississippi Power expects to create 260 permanent jobs. The first two stages of construction are scheduled to take all of 2011, with construction of the plant in 2012 and 2013. The Kemper County plant is expected to begin operations in 2014.

Miss. Power's website says "the local lignite will provide decades of low-cost fuel and avoid huge price swings associated with uncontrollable fuel markets. It is the lower cost fuel available - and with a 4 billion ton reserve in Mississippi - we Mississippi Power can secure a stable fuel source while reducing our dependence on foreign fuel for future generations, due to its abundance and affordability."

Ed note: The nominal 600MW (net) IGCC plant will utilize the Southern Co/KBR "TRIG" air-blown gasifier integrated with two Siemens SGT6-5000F gas turbine generators, the hot exhaust of which produces steam to drive a steam turbine generator. Southern Co. is the parent company of Mississippi Power. The project will enjoy a substantial financial boost from Federal tax credit incentives. The South Mississippi Electric Power Association has agreed to take a minor equity stake in the project.

The plant will include capture of 65% of the carbon in the lignite feedstock, giving it a carbon footprint approximately equal to that associated with a natural-gas fired combined cycle plant. The captured CO2 is expected to be fed into a pipeline for use in enhanced oil recovery or other uses.

2010-11-11T13:42:00.002-05:00

2010 Gasification Technologies Council
Annual Conference Papers Now Available On Line

The 2010 GTC conference is now history, and quite an event it was. It took place November 1-3 in Wash DC and there were plenty of important project updates and technology developments that highlighted jam-packed program.

The event attracted more than 600 attendees from all over the world, and from a myriad of industries related to the growing application of gasification technologies as a preferred way to utilize a variety of energy feedstock.

With permission of the GTC, we are providing a copy of the conference program and direct links to all of the presentations.

Look for special coverage of the conference highlights in the upcoming issue of Gas Turbine World Magazine.


Jump to a date:
Monday, November 1	Tuesday, November 2	Wednesday, November 3

Sunday, October 31
1:00 - 3:30 pm	GTC Fall Membership Meeting
4:00 - 7:00	Conference Registration - Registration Desk
5:00 - 7:00	Opening Reception - Exhibit Hall
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Monday, November 1

7:00 am

Conference Registration and Check-In - Registration Desk
Continental Breakfast - Exhibit Hall

8:00 am

Opening Sessions & Introductions - Marriott Ballroom

8:30 am

Keynote Address

Matthew L. Wald
The New York Times

9:00 am

Project & Technology Updates I
Session Chair: Lee Schmoe, Bechtel Corporation

	E-Gas Technology 2010 Outlook Phil Amick, ConocoPhillips
	Updates on Key Projects on Three Continents Keith White, GE Energy - Gasification
	Heavy Residue Gasification in Today's World Michiel Mak, Shell Gasificaion & Clean Coal Energy
	Siemens Technology Advances and Project Development Activities Harry Morehead, Siemens Energy, Inc.
	KBR’s Transport Gasifier - Technology Advancements & Recent Successes Siva Ariyapadi, Kellogg Brown & Root

10:30 am

Break - Exhibit Hall

11:30 am

Project & Technology Updates II
Session Chair: David Denton, Eastman Chemical

	Further Developments and Commercial Progress of the BGL Gasification Technology Hans Hirschfelder, Envirotherm GmbH
	Update on New Projects & Design Development with the Lurgi FBDB Gasifier Max-Michael Weiss, Lurgi GmbH
	Technical Update of the MHI Air Blown and Oxygen Blown Gasifier Hiromi Ishii, Mitsubishi Heavy Industries
	Overview of the Kemper County IGCC Project Using Transport Integrated Gasification Randall Rush, Southern Company Gasification
	OMB Gasification - Industrial Application Updates of Slurry Feeding and Developments of Dry Feeding Prof. Haifeng Liu, Institute of Clean Coal Technology

1:00 pm

Lunch - Exhibit Hall

2:30 pm

Emerging Biomass & Secondary Materials Gasification Opportunities I
Session Chair: R.A. Olliver, Aplethora Energy Services

	PRB Coal and Coal/Biomass Gasification Activities at Emery Energy Company's New Pilot Facility Benjamin Phillips, Emery Energy
	Uhde Biomass and Coal Gasification: Applying Fluidized Bed and Entrained Flow Gasification Karsten Radtke, Uhde Corporation
	Biomass Gasification for the Production of SNG: A Practical Route through Available and New Technologies Rosa Domenichini, Foster Wheeler S.p.A.

4:00 pm

Break - Exhibit Hall

5:00 pm

Emerging Biomass & Secondary Materials Gasification Opportunities II
Session Chair: R.A. Olliver, Aplethora Energy Services

	Plasma Gasification: Integrated Facility Solutions for Multiple Waste Streams Pieter van Nierop, Alter NRG Corp. Poornima Sharma, Technip USA, Inc.
	TPRI Technology and Future Fuels Projects Updates William Douglas, Future Fuels LLC
	Coskata's Syngas-to-Ethanol Platform Ralph Corley, Coskata, Inc.

6:00 pm

Adjourn

6:00 - 8:00 pm

Reception - Exhibit Hall

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Tuesday, November 2

7:00 am

Conference Registration and Check-In - Registration Desk
Continental Breakfast - Exhibit Hall

8:00 am

Keynote Address

Donald Hodel
Chairman and Senior Vice President, Summit Power

8:30 am

Energy Market & Environmental Gasification Drivers
Session Chair: Neville Holt, EPRI

	Coal to SNG via Gasification: Efficiency, Environmental and Economic Benefits Dale Simbeck, SFA Pacific
	Implications of Greater Reliance on Natural Gas for Electricity Generation Catherine M. Elder, Aspen Environmental Group
	POSCO Gwangyang SNG Project Cliff Keeler, ConocoPhillips
	A New Look at Lignite: A Central European Perspective Wojtek Ksiazkiewicz, SNC Lavalin
	A Strategic Fuel Switch From Natural Gas to Local Lignite: Development of the Komsomolsk Gasification Project Marco Kanaar, Gasification Solutions

10:00 am

Break - Exhibit Hall

11:00 am

Gasification's Carbon Management Advantage
Session Chair: Michael DeLallo, WorleyParsons

	Overview of the DOE Industrial Carbon Capture & Storage Program Darren Mollot, U.S. Department of Energy, Fossil Energy
	Pathways to Improved IGCC Performance and Economics with Carbon Capture and Storage Ron Schoff, EPRI
	Advanced Hydrogen and CO₂ Capture Technology for Sour Syngas Jeff Kloosterman, Air Products & Chemicals, Inc.
	CCS Options & Cost Reductions with New SELEXOL^TM Flow Schemes Raj Palla, UOP LLC
	Wandoan IGCC with CCS Project - Development Challenges & Opportunities Chris Walker, Stanwell Corporation

12:30 pm

Lunch - Exhibit Hall

2:00 pm

In Situ Coal Gasification
Session Chair: George Gruber, Black & Veatch

	Update on the Linc Energy Chinchilla UCG Project Don Schofield, Linc Energy
	Swan Hills in Situ Coal Gasification and Power Generation Doug Shaigec, Swan Hills Synfuels

3:00 pm

Break - Exhibit Hall

4:00 pm

Addressing Project Economics
Session Chair: Doug Todd, Process Power Plants LLC

	Coal Gasification: Delivering Performance in Chinese Operations & Developing Technology Deployment Solutions Jim Volk, Shell Gasification & Clean Coal Energy
	The Cost Estimating Process for the Taylorville Energy Center Jim Welniak, Tenaska
	Revving Up Reliability, Availability & Maintainability: Applying Experience to Improve Plant Performance DeLome Fair, GE Energy - Gasification
	New Technologies and Projects Based on Topsoe's Knowledge of Downstream Gasification Technologies Jens Perregaard, Haldor Topsoe A/S
	Cleanly Unlocking the Value of Low Rank Coal Carrie Thompson, Synthesis Energy Systems
	Reduction of CAPEX in Coal Milling and Drying Units Tobias Korz, Loesche GmbH

5:30 pm

Adjourn (evening open)

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Wednesday, November 3

7:00 am

Conference Registration and Check-In - Registration Desk
Continental Breakfast - Exhibit Hall

8:00 am

Advances in Gasification Technologies I
Session Chair: Jenny Tennant, U.S. DOE/NETL

	ConocoPhillips E-STR Technology Development for Lignite Gasification Albert Tsang, ConocoPhillips
	Scale-up of the RTI Warm Syngas Cleanup Process at the Polk Power Station IGCC Raghubir Gupta, RTI International
	Accelerating Commercialization and Deployment of Advanced Gasification Technology Through Multiphase Modeling Chris Guenther, U.S. DOE/NETL
	Ion Transport Membrane (ITM) Technology for Lower-Cost Oxygen Production Robert Steele, EPRI
	Building on History: the Next Generation of Technology Joe Zuiker, GE Energy, Gasification

9:30 am

Break - Exhibit Hall

10:30 am

Advances in Gasification Technologies II
Session Chair: Phil Amick, ConocoPhillips

	Compact Gasification Development & Test Status Alan K. Darby, Pratt & Whitney Rocketdyne
	Results and Evaluations of the 5,000 Hour Durability Test at the Nakoso Air Blown IGCC Plant Tsutomu Watanabe, Clean Coal Power R&D Co., Ltd.
	Low-Swirl Combustion Technology for Advanced IGCC Systems David Littlejohn, U.S. DOE/LBNL
	Rectisol Wash Acid Gas Removal for Polygeneration Concepts Downstream of Gasification Thomas Haberle, Ulvi Kerestcioglu, Linde Engineering

12:00 pm

Conference Adjourns

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2010-08-16T11:10:00.010-04:00

IGCC IN THE NEWS

Gasification Technologies Council
responds to FutureGen changes

As previously posted on this website, the DOE has announced sweeping changes in the FutureGen advance IGCC+CCS project planned for Mattoon, IL. The Gasification Technologies Council (GTC) has formally responded with a letter to DOE Secretary Chu saying that it was "deeply disappointed" and calling the decision to change technology from IGCC to oxy-combustion "a step in the wrong direction".

Meanwhile, Mattoon officials have announced that they have pulled out of the project, where their remaining role would be to provide the storage site for the CO2 captured at the new project site some 150 miles to the west. Other Illinois towns have stepped forward to show interest in replacing Mattoon.

For a view of the GTC response letter, as well as the full text of the DOE announcement, go to this link to the GTC website.

2010-08-15T16:16:00.022-04:00

IGCC in the News

FutureGen and Politics-

Question raised whether
changes in project involved
conflict of interests

Just when it seemed that FutureGen was on track
for a new life, politics raises its ugly head with
questions of DOE integrity, and charges of conflict
of interest, in decision to change technology,
contractors and location.

How ugly is it?

James Wood, DOE Asst. Deputy for Clean Coal,
has become target of suggested impropriety.
He recently came to DOE from Babcock Power.
Yet his past association with Babcock & Wilcox,
where he was president from 1996-2001, is being
cited as possibly having influenced the DOE
decision to tap B&W as new FutureGen lead
contractor.

Although DOE has denied any conflict, issues
raised by those opposed to changes further
tarnish troubled project.

Meanwhile, Mattoon pulls out of project and
DOE is looking for new site for CO2 storage.

(Adapted from AP release)

DOE official once led firm
now redoing FutureGen
By David Mercer (AP)

CHAMPAIGN, Ill. — A top official in the Department of Energy office who oversees the FutureGen clean-coal project is a past CEO of a company newly chosen to retrofit a western Illinois power plant instead of finishing the original project in Mattoon.

Critics of the decision to change FutureGen worry that the official, James F. Wood, could benefit from his past leadership at the company and that he shouldn't have been part of the decision.

James F. Wood, who is deputy assistant secretary for clean coal in the Department of Energy's Office of Fossil Energy, was president of Babcock & Wilcox Company from 1996-2001. (Ed. note: see below for clarification regarding most recent relationship with Babcock Power not B&W.)

North Carolina-based Babcock & Wilcox is one of the companies named last week by the department to retrofit a coal-fired power plant in the western Illinois under the retooled $1.2 billion FutureGen project.

The department announced the changes last week, including a decision to scrap plans to build a new, integrated gasification combined cycle (IGCC) power plant in Mattoon, in eastern Illinois.

The news surprised officials in Mattoon, who this week backed out of the project and its new role as storage site for carbon dioxide from the retrofitted plant in Meredosia, Ill.

The Department of Energy did not make Wood available for an interview, but said its internal vetting process found he had no potential conflicts of interest. (Ed: See update below.)

"Jim Wood worked for Babcock and Wilcox almost a decade ago and has no financial interest in the company," agency spokeswoman Stephanie Mueller wrote in an e-mail.

Details about Wood's role in the decision to change FutureGen aren't clear but, according to the department, he oversees all Office of Fossil Energy coal research and projects, including FutureGen.

It isn't clear how much of the $1.1 billion the federal government plans to contribute to the newly defined project would go to Babcock & Wilcox.

The remainder of the project cost is intended to be covered by the Energy Department's private sector partners in FutureGen - the FutureGen Industrial Alliance - a group of coal companies and other firms who were also surprised the changes and have said little since they were announced.

Wood joined the department from Babcock Power Inc., where he was CEO. That company, in spite of the common name, isn't related to Babcock & Wilcox and actually competes with the latter in some power plant-related work, Babcock Power spokesman Jim Sims said.

Political leaders and others from the Mattoon area angered by the abrupt change in FutureGen plans last week say that at the least the Energy Department should have made clear that Woods had ties, no matter how old, to a key company that was involved.

"I think that's the real issue here"" said state Sen. Dale Righter, a Republican who lives in Mattoon and has been involved in the area's pursuit of a place in the FutureGen project for several years.

A spokesman for Illinois Sen Dick Durbin wasn't aware of Wood's past position or his role in FutureGen but also argued that there's no reason for him not to work on the project for the Department of Energy.

"They (the DOE) hire people with industry experience," Joe Shoemaker said.

The Energy Department and Durbin last week announced that Babcock & Wilcox and another firm, Air Liquide Process & Construction Inc. of Texas, will retrofit a coal-fired plant in Meredosia, Ill., that belongs to Ameren Corp.

The change ended plans to build a new plant in Mattoon intended to prove that coal could produce electricity through a technology called Integrated Gasification Combined Cycle (IGCC), with the carbon dioxide from the fuel removed and safely stored underground.

Durbin and the Department of Energy say delays in Futuregen have allowed several other similar projects to bypass it, leading them to focus instead on another technology, oxy-combustion, that could be used to add life to existing coal plants.

Carbon dioxide from that process would still be stored underground, and would have been piped about 175 miles to Mattoon under the new FutureGen plan. Officials there, though, decided Wednesday to pull out of the project. The Energy Department is now looking for a new carbon storage site.

The Energy Department has said this week that it chose Babcock & Wilcox because the oxy-combustion technology it will use at Meredosia — and, if it works, hopes to use on other, older plants — belongs to the company.

Documents found on the Department of Energy's Web site indicate that the company has done work with the department and Illinois' coal industry on oxy-combustion at least as far back as 2003.

There are, though, a number of other companies working with oxy-combustion, according to the International Energy Agency. At a presentation during an agency conference on oxy-combustion technology earlier this year the agency said there were 15 "large-scale" oxy-combustion power projects in the works worldwide.

UPDATE: DOE officially denies conflict of interest
Kurt Erickson - Springfield, Illinois - August 11, 2010

SPRINGFIELD — The official who oversees federal clean-coal programs had no conflict of interest regarding the awarding of a contract to his former company for the revamped FutureGen project, a senior adviser at the Energy Department said Wednesday.

A day after Mattoon-area officials raised questions about the role James F. Wood played in his former company, Babcock & Wilcox, gaining a stake in the FutureGen project, Matt Rogers said Wood’s relationship had nothing to do with the award.

“That is a non-issue,” Rogers said.

The engineering and industrial retrofitting company was tapped by the department last week to help upgrade a coal-fired power plant in Meredosia as part of a clean coal demonstration project.

Wood, the deputy assistant secretary for clean coal, was president of North Carolina-based Babcock & Wilcox from 1996 to 2001.

“Jim Wood worked Babcock & Wilcox almost a decade ago and has no financial interest in the company,” Rogers said. “Our general counsel has had long looks at this, and there is no conflict of interest issue here at all.”

State Sen. Dale Righter, R-Mattoon, and U.S. Rep. Tim Johnson raised questions about Wood’s role after the bulk of the FutureGen project was moved from Mattoon to Meredosia.

On Wednesday, after hearing Rogers’ explanation of Wood’s role, Johnson spokesman Phil Bloomer had no comment.

2010-08-09T20:53:00.025-04:00

FUTUREGEN IGCC + CCS
ALIVE AND WELL - IN TEXAS
WHILE MATTOON GETS SHAFT

DOE shifts FutureGen technology to oxy-combustion
boiler retrofit and moves plant site to Meridosa IL

On August 5, the news was finally out in the open: the US DOE and the FutureGen Alliance had quietly struck a new deal that totally changes the face of the FutureGen project.

They are calling it "FutureGen2".

Enter oxy-combustion retrofit
Instead of continuing along the rocky path that effectively duplicates Summit Energy's Texas Clean Energy (IGCC) Project - already receiving some $350 million in DOE funding -and other IGCC+CCS projects, FutureGen2 will take the form of an oxy-combustion boiler retrofit of an existing 200 MWe pulverized coal-steam plant in Meridosa, IL – some 150 miles west of Mattoon.

So, what is left for little old Mattoon - the official winner of the original competition for the FutureGen IGCC project?

Well it could be worse. With FutureGen2 they get more than they would have gotten the first time the project was killed back in December, 2007.

But now, rather than providing a site for a new $2 billion state-of-the-art power plant, they get to host the end of a pipeline carrying the CO2 collected at the Meridosa plant, and to supply a place for the long-term storage deep under 400 acres of rural farmland.

The good news
Perhaps Mattoon feels otherwise, but the good news is that the announcement of FutureGen2 is a big step forward.

The announcement actually included the naming of a bona-fide host utility (Ameren Energy), and the major contractors - B&W and Air Liquide - to supply the new oxy-combustion boiler system that will produce steam to power one of the now-idle 200 MWe steam turbine generators at the Meridosa site.

The other good news - to this observer - is that the US DOE - in spite of the expected political fireworks - has shown signs of some real strategic thinking going on behind the scenes.

And for Mattoon, the region will be at the hub of a regional CO2 transportation infrastructure now being given a jump start by the project.

Change was coming
The fact that the Texas Clean Energy (IGCC) Project had received a $350 million award under Round 3 of DOE's Clean Coal Initiative, and is moving ahead nicely with a front-end engineering design (FEED) study being carried out by Siemens and Fluor - made it virtually impossible for the DOE to continue support of FutureGen as a parallel "state-of-the-art" IGCC project.

Other IGCC+CCS projects in Mississippi and California also appear to be moving ahead with DOE funding and/or other forms of government financial support.

Clearly, FutureGen missed it's window of opportunity and the choice was clear - kill it again or have it emerge in a different form. Opting for change has again saved the project.

Oxy-combustion retrofit of existing coal-steam plants is recognized globally as an important option for the future of coal-based power generation in a carbon-restrained world.

In that light, the announcement of FutureGen2, although coming as a surprise, immediately made a lot of sense to anyone keeping an eye on the situation.

US needs oxy-combustion demo
Supporters of IGCC technology (as well as those in and around Mattoon) might bemoan the loss of what might have been substantial government support of another new IGCC+CCS plant.

But, in my opinion, the change in FutureGen's direction is the right way to go.

DOE's own studies have shown the economic benefits of oxy-fuel combustion technology as a means for retrofitting existing coal plants to achieve real reductions in CO2 emissions.

Moreover, there are already a number of significant oxy-combustion demonstration projects underway in Europe, where it is widely accepted that retrofit for CO2 capture is an imperative.

Yes, Mattoon, it may be difficult to swallow yet another disappointment, but the US needs to support the development of its own oxy-combustion technology, and to support a commercial-scale demonstration of the technology.

With so many old coal-steam plants scheduled to be shut down due to their high emissions and huge carbon footprint, it could be that retrofit with new oxy-combustion boilers will prove to be the most cost effective way to keep these old plants online.

Is oxy-combustion ready?
At the very least, the parallel development of the Texas Clean Energy Project and FutureGen2 will provide an excellent way to obtain actual field data from the two main competing clean-coal technologies, operating at commercial scale, thus helping the US map out the future of coal-based power generation.

Is oxy-combustion technology ready for the scale-up to 200 MWe? Some think not - and say that FutureGen2 may be doomed to failure without more R&D. But B&W has already operated a pilot test unit, and the scale-up risk is considered to be manageable.

It looks like we'll all find out before too long - as long as FutureGen2 can get on track and avoid missing this new window of opportunity.

2010-07-23T14:01:00.005-04:00

NETL Launches Reference Site
for Coal Gasification and IGCC
Technologies

The Office of Fossil Energy’s National Energy
Technology Laboratory (NETL) has launched a new
public website called "Gasifipedia," a comprehensive
online collection of resources to promote better
understanding of gasification and IGCC technologies.

For more details about the site, link to the Energy
Department's Fossil Energy website at: TechLine

For a direct link to the new reference site go to Gasifipedia

2010-06-29T20:27:00.020-04:00

Dr. David H. Archer
Father of coal-based IGCC
1928-2010

Dave Archer, IGCC Pioneer - Westinghouse R&D
Adjunct Professor - Carnegie Mellon University

I guess that it's a personal thing with me, but the way I see it was Westinghouse's Dave Archer ("Dr. Dave") who should be considered as the father of the IGCC power plant concept.

And I'm saddened by the passing this past Thursday of an old friend, a nice guy and a technology pioneer.

Coal in gas turbines?
It was fall, 1973, when I joined the Westinghouse Gas Turbine Systems Division, and the Arab Oil Embargo was just taking effect. My first assignment, I soon learned, was to join the marketing effort that was going to save our business.

The days of cheap oil were over, and the buzz was all about "alternative fuels" for gas turbines. I was told to call Dr. David Archer at our R&D Center and learn all about the one idea that was going to save us. I soon learned that he was working on new ways to use coal in gas turbines!

Coal in gas turbines? Of course. What else? Cheap and plentiful domestic coal.

Combined cycles just taking hold
Ironically, the nascent concept of combined cycle power generation using large oil- or gas-fired gas turbines was just beginning to take hold. Record levels of orders were rolling in from all over the country. But almost all of these orders were now being canceled due to uncertainties in the global fuels market.

At the same time, the Clean Air Act of 1972 had just been passed, and the pressure was on the industry to find a way to cleanly use high sulfur coals. The use of scrubbers on exhaust stacks was seen as technically unsound, and much too expensive.

Were these parallel major developments to mean the end for both large coal-fired steam plants and for combined cycle plants at the same time?

Was nuclear power really the only answer? (Anyone remember "Power too Cheap to Meter"?)

Was my career in gas turbines going to be a short one?

Luckily, there were believers
Luckily for Westinghouse gas turbines (and for Siemens some 25 years later?) there were at least a few in upper management who strongly believed in the future of the combined cycle power plant. Even if traditional fuel sources were now in question, they saw ways for the concept to survive and grow. (Remember, this was even before the word "cogeneration" was invented.)

At the same time, these foresighted people saw how the combined cycle power plant could even provide an alternative way - through the use of gasification - to use high sulfur coal and still meet the tough new emission standards that were about to be promulgated under the Clean Air Act.

Enter Dr. David Archer - and IGCC
At the time Dave Archer, a manager at the Westinghouse R&D Center, was heading a group of mostly chemical engineers working on advanced concepts of integrating both fluidized bed coal combustion and air-blown fluidized bed coal gasification with combined cycle power generation.

When I called him to learn about the alternative fuels path for survival I felt that I was talking with the guru - and the creator of a great new concept that was not only going to save Westinghouse gas turbines but also give my new job a whole new meaning.

Although this all happened well before the coining of the term Integrated Gasification Combined Cycle, and the acronym "IGCC" (by EPRI? GE? both?), we were there - almost 40 years ago - at the beginning of a great idea.

Westinghouse was already testing low-BTU syngas fuel in modified W501B combustors, with DOE support, and we really thought that we were onto something very special.

A marketing strategy was developed to convince customers to stick to their plans to install our new PACE combined cycle plants. Our theme (sound familiar, even for today?):

Gas or Oil - Now
Syngas from Coal - Later

An idea that has come and gone - and come again
Well, a lot of water has flowed over the dam since then - and the idea of IGCC has come and gone and come again as the greatest thing since who-knows-what for improving the technology of coal-based power generation.

Entire careers in IGCC development and commercialization have also come and gone since I was first introduced to the idea by Dave Archer.

My own career with Westinghouse gas turbines lasted some 30 years. Unexpectedly, and thanks to Gas Turbine World, it returned to the promotion of IGCC about 5 years ago, shortly after I retired from Siemens-Westinghouse.

Happily, I heard again from Dave Archer when he saw the series of articles that we were publishing in support of gasification and IGCC. He was still working as adjunct professor at CMU teaching advanced power generation to graduate students.

In fact, it was only a few months ago that I last heard from him.

We had just posted the news item on the EPA putting pressure on the developers of the Kemper County (KY) IGCC project to consider natural gas as the primary fuel for their power plant, and their announcement that their IGCC plant was going "hybrid" - that is, separating the coal-to-gas plant from the gas-fired combined cycle plant.

Dave's comment - some 40 years after he fathered the concept as an answer to the Clean Air Act:

"It seems that EPA really wants to strangle IGCC before it takes a real breath.
Keep the faith?"

Fondly remembering Dr. Dave.

Harry Jaeger
Gasification Editor
Gas Turbine World Magazine

The following is reprinted from the Pittsburgh Post-Gazette:

ARCHER DR. DAVID H.
On Thursday, June 24, 2010, age 82 of Ross Township formerly of West View.

Beloved husband of the late Justine (Garnic) Archer. Loving father of Catherine Archer, Miriam (Mac) McCann, Amy Archer & Marsi (Lance) Thrash; brother of Miriam Jeske, proud grandfather of Charles, Andy, Justine & Vivian McCann, and Jordan David, Tim & Bailey Thrash; also survived by 6 great-grandchildren; longtime friend & companion of Myrna Rombach.

Family will welcome friends Monday 2-4 & 6-8 p.m. at the SCHELLHAAS FUNERAL HOME, INC., 388 Center Ave., West View 15229. Service will be in Emanuel's Ev. Lutheran Church, 10 N. Fremont Ave., Bellevue 15202 on Tuesday at 11:00 a.m.

Dr. Archer was retired, Westinghouse Electric Corp.; Adjunct Professor, Carnegie Mellon University; Organist and Music Director, Emanuel's Ev. Lutheran Church; Member, National Academy of Engineers; Member, American Guild of Organists.

If desired memorials may be made in Dr. Archer's name to the Intelligent Workplace Program, Carnegie Mellon University, P.O. Box 371525, Pgh., PA 15251-7525 or Emanuel's Ev. Lutheran Church.

2010-06-12T11:54:00.011-04:00

Memorable Memorial Day for

Kemper County IGCC Project

Mississippi Power announces that it will move forward to construct a 582MW IGCC power plant as Public Service Commission relaxes financial restrictions on the project.

May 28, 2010

Mississippi Power, a wholly owned subsidiary of Southern Company, said that it will formally accept the terms of the revised order of the state regulators allowing for the construction of an advanced design IGCC power plant, which is expected to come online by 2014.

The utility said that the proposed plant would use Mississippi lignite. This locally available and relatively low-cost energy source will be added to its existing fuel mix of natural gas and coal, and will allow the company to mitigate the volatility and growing costs associated with other fuels.

Mississippi Power had asked the Mississippi Public Service Commission to reconsider conditions it had previously placed on the utility's plan to build the 582MW plant, including a recoverable cost cap of $2.4 billion.

The utility had claimed that the $2.4 billion price cap along with other conditions "created unacceptable risks to the company, our customers, our lenders and our investors."

After rehearing the case, the commission voted 2-1 to raise a price cap it placed by nearly $500 million to $2.88 billion and to allow the utility to begin charging customers for some plant costs starting in 2012, at least 2 years before it is expected to begin producing electricity.

Commission Chairman Brandon Presley, who opposed the plant in April as too risky for ratepayers, voted against the revised order. In a dissenting opinion, Presley criticized the action by the other two commissioners in acquiescing to the utility's objections.

Other project critics -- owners of merchant power plants in the region and at least one environmental organization -- said the utility was counting on high natural gas prices to justify the plant's economics at a time when the US natural gas supply is climbing with new production that should keep costs in check.

The Kemper County plant will employ an advanced air-blown circulating fluidized bed "transport" gasifier (the "TRIG" system) developed by Southern Company and KBR, in conjunction with the US Department of Energy. It will be the first commercial-scale application of the technology in the US.

An earlier attempt by Southern, KBR and the DOE to develop a commercial-scale demonstration plant in Orlando, Florida had failed to materialize.

In September 2009, KBR announced that it had been awarded a license and services contract in China with Beijing Guoneng Yinghui Clean Energy Engineering Co., Ltd that is expected to result in the first commercial scale installation of the TRIG system.

2010-03-22T20:32:00.007-04:00

CORRECTION: Kentucky IGCC changed
design to "SNG-NGCC" before EPA order

A comment to our March 21 posting requires that we call attention to a possible misinterpretation of recent news concerning the Cash Creek IGCC project in Kentucky.

According to an anonymous comment received in response to our March 21 posting (see text of comment below), the developers of the Cash Creek project in Kentucky had already decided to change the project design to a hybrid IGCC (or "SNG-NGCC") configuration more than a year before the EPA order of December 2009 was issued.

Moreover, it is claimed that this was done on the basis of "business models" - not due to EPA pressure as suggested by our posting.

After more research into the matter, thanks to a reader who provided a copy of the EPA order, it was learned that the EPA was responding to two petitions filed in Jan/Feb 2008 - one by the Sierra Club and the other by Valley Watch - both objecting to the original air permit issued for the project by the Kentucky Division of Air Quality (KDAQ) at that time.

It took the EPA almost two years to issue its order directing the KDAQ to address certain issues with that permit - the main one being failure to consider use natural gas as the primary fuel instead of coal-derived syngas. Apparently, as pointed out by the comment, this was well after the project developers had already decided to change the project design and applied to the KDQA for modifications to its air permit.

Perhaps, as the comment says, we "missed the point" of the EPA order. Admittedly, we did post our remarks with incomplete information, and should have done more homework.

But the comment raises new issues, and further comment is invited to add clarification.

Since the decision to change the project design supposedly took place around mid-2008, it was done after those petitions were filed. Perhaps, just perhaps, those "business models" included analysis of the cost and risks of continued battles over environmental objections.

Could it be that the decision to change to an "SNG-NGCC" configuration was made to quiet those objections?

How else could those "business models" have justified the extra cost of producing SNG, and the loss of about 10% of the syngas heating value in the process?

If in fact the project design had already been changed, and requests for permit modifications were duly filed, why wasn't that noted in the EPA order of December, 2009 along with other permit history?

As it turned out, due to the long delay in KDQA action on the permit modifications, the EPA order would appear to be totally irrelevant, and a waste of time, since the main objection to the permit (failure to consider natural gas as the primary fuel) was already a moot point.

Why didn't the KDAQ act in a more timely manner instead of waiting until after the EPA order to issue a new permit? Was not the original permit already invalidated by the change in design filed in 2008?

Again, "anonymous" is invited to add further comment to help clarify these issues.

Finally, the comment points out that the EPA order "seemed to go out of its way to praise IGCC" as a cleaner alternative to conventional coal-based power generation.

That may be true. And it may also true that the EPA is now selectively reviewing existing permits for conventional coal plants to decide whether IGCC should be included in the BACT analysis.

True, all of this may be positive for IGCC.

But if IGCC power projects continue to cave under the pressure (be it economical or environmental), and convert to "hybrid IGCC" or "SNG-NGCC", then, as we said at the outset of yesterday's posting, this very well could mean the end of the IGCC concept as we know it.

Text of anonymous comment to original posting:

The developers of Cash Creek made the decision to switch from IGCC to SNG with a co-located NGCC plant in 2008-- some 12 -18 months before the December 2009 EPA objection letter to the original IGCC permit.

The plant's developers filed air permit and water permit modifications to the original IGCC permit in 2008, and hearings on both of the modifications were held months before the EPA objection letter was received.

So I think the article misses the point on the letter. The technology change from IGCC to SNG-NGCC was driven by business models, not by some EPA-imposed permit letter.

KY regulators had 90 days to respond to the December 2009 objection letter. They could have agreed with EPA and voided the permit, modified the existing permit, or issued a new one. Because the developers had long before filed applications for a different technology and the permitting process was so advanced, KY addressed the question by issuing the new air permit.

What EPA intended to say about IGCC in the objection letter is open to some debate. I respect the opinions of those in industry that see it as an attack on coal, but I read the letter differently. The EPA seemed to go out of their way to praise IGCC in the letter, stress this wasn't about coal, and only about documentation in the record.

Time will tell what EPA really intended.

.

2010-03-21T11:39:00.024-04:00

Does Kentucky BACT decision kill
coal-based IGCC as we know it?

EPA order to consider fuel switching to natural gas
drives plant to "hybrid IGCC" configuration.

Based on a story carried by a recent issue of the Washington Energy Report, December 17, 2009 may go down as the date to remember as the death of the integrated gasification combined cycle power plant - or what we have come to know and love as the "IGCC" power plant.

It was on that date that EPA Administrator Lisa Jackson issued a decision requiring the Kentucky Division of Air Quality ("KDAQ") to consider whether the proposed Cash Creek IGCC plant should generate electricity with natural gas rather directly with the syngas produced in the gasification process.

The decision was issued in the context of determining the Best Available Control Technology ("BACT") requirements in Cash Creek’s air permit application. In its order to reconsider the fuel switching, the EPA said that natural gas might be "a lower polluting fuel than syngas".

Without saying it, the inference here is that, in this way the power plant will meet EPA guidelines for CO2 limits, even though there still have been no regulations promulgated to formally set that limit.

Is fuel switch a 'redefinition of the source'
Although the EPA was not specifically ordering the fuel switch, it put the KDAQ, and the Cash Creek project developers, on the spot by requesting a better explanation as to why such an order would constitute a "redefinition of the source". If that were found to be the case, the current rules of the game are such that the EPA cannot order the fuel switch.

So, just when it was hoped by supporters that the EPA might come out in favor of the IGCC as a favored clean coal technology, it appeared that they were putting up another roadblock to a promising IGCC project in an area where other EPA regulations have all but closed down the local coal industry.

Is this actually a serious change in EPA's positive attitude toward IGCC as the preferred form of coal-based power generation?

Even if this negative intervention in the case of the Cash Creek project is not generally considered as an anti-IGCC position, it certainly puts a damper on earlier hopes that the EPA would become an active supporter, and require that the cleaner IGCC technology be considered in the BACT analysis for all new coal-fired power plants.

At least this seemed to be the case as recently as last April, when the EPA decided to pull the plug on the air permit for the 1,500 MW Desert Rock pulverized coal plant in New Mexico. Although the stated reason was that the original PSD application did not consider IGCC technology, it could be that the real impact of the decision, to the glee of the anti-coal activists, will ultimately be to kill the project rather than force it to change its design.

Now Kentucky is going "hybrid"
Meanwhile, back in Kentucky, the "good news" for the Cash Creek IGCC, as reported on March 8, 2010, is that the KDAQ issued its final approval of the air permit for the project, presumably clearing the way for continued PPA negotiations and, ultimately, project financing.

The "bad news", however, is that its developers apparently had to cave under EPA pressure for a "fuel switch", and the plant has been reconfigured to a so-called "hybrid IGCC" - a term used to describe another quasi-IGCC plant in Taylorville, Illinois being developed by Tenaska.

What is a "hybrid IGCC"? And what, if anything, is wrong with it?

A "hybrid IGCC" is actually two separate plants - one that converts the coal to pipeline quality "synthetic natural gas" ("SNG") and another that burns gas from the first plant (or actually from the gas pipeline) in a conventional, high-efficiency, low emissions gas-fired combined cycle plant.

Tenaska claims advantages for the concept that it adopted for Taylorville - probably due to the same environmental gamesmanship now being played out in Kentucky, stating that "hybrid IGCC technology allows coal to be used to generate power as cleanly as natural gas".

They also point out that the "hybrid IGCC" eliminates air-side and nitrogen integration and its "simplicity" leads to expected higher plant availability.

Not mentioned is the substantial reduction in overall plant efficiency, and a significant increase in project cost, due to the lack of integration and the addition of the methanation process. With the cost of true IGCC plants with CO2 capture already approaching $6,000 per net kW, how can the more costly "hybrid" approach pass muster?

Easier to finance and play EPA's game?
Can it be that a "hybrid IGCC" will have an easier time with project financing? This might turn out to be the case, and what has also driven the project developers in that direction, since the power plant portion will be of conventional design, and can be operated like any other gas-fired combined cycle plant? Meanwhile, the coal-to-SNG plant is also an accepted industrial technology that can serve two independent markets, i.e. both for power and for natural gas.

And, perhaps even more important is playing the EPA's game. The combined cycle power plant, now burning natural gas, will meet EPA guidelines for CO2 emissions. This cannot be said of a true IGCC, unless one adds the very high expense of CO2 capture and compression.

Of course that may overlook all of the CO2 given off when the syngas from the coal gasification process is converted to methane. That's another story - and doesn't come into play under EPA rules - since that rule hasn't been written yet.

Currently there seems to be serious planning for CO2 capture and sequestration for the Taylorville and Cash Creek coal-to-SNG facilities, but at least they both have air permits in hand for their power plants while figuring that all out.

The active list of IGCC projects in the US is continuously shrinking. Where will the EPA strike next with their strange way of showing how they prefer IGCC to other forms of coal-based power generation?

2010-01-09T11:10:00.028-05:00

DOE/NETL Defines
Technology Pathways
to Lower IGCC Costs

Final report on benefits of advanced IGCC technologies now available

Back in early October this site reported on a study by the DOE/NETL Office of Analysis and Planning of the potential of advanced technologies currently under development to lower the cost of coal-based IGCC power plants with high levels of carbon capture.

Study results, presented at the 2009 Gasification Technologies Council (GTC) conference held Oct. 4-7 in Colorado Springs, predict that significant improvements are indeed possible. Now the final study report dated, November 2009, is available for downloading at the DOE/NETL website.

Severe economic impact of CCS
A number of studies supported by EPRI and the DOE/NETL (see Jan-Feb 2009 Gas Turbine World), have focused on the severity of the economic impacts of carbon capture and sequestration (CCS) for all forms of coal-based power generation.

For example, the impact of 90% CO2 capture on typical current-technology IGCC plants is to increase HHV heat rate by more than 16 percent (i.e. reducing plant efficiency from around 38% to below 32%). And the additional parasitic plant loads associated with CO2 processing and compression reduce net plant output by more than15 percent.

The combined overall effect is to increase total plant capital cost ($ per net kW) by over 35 percent and add at least 35% to the 20-year levelized cost of electricity (COE).

R&D aims at recouping CCS losses
In a drive to recoup losses in IGCC plant efficiency, and mitigate increases in plant capital costs due to adding CCS, the DOE has several advanced technologies under development with a well defined technology pathway for both near term and longer term improvements.

The NETL report "Current and Future Technologies for Gasification-Based Power Generation" (DOE/NETL- 2009/1384) provides estimates of the benefits of each element of DOE's broad portfolio of advanced power systems technology programs.

Presented roughly in order of expected commercial deployment, these programs are shown to significantly improve process efficiency, cut capital costs and substantially lower the COE for coal-based IGCC plants operating with 90% CCS.

Largest returns are expected of the following R&D efforts which are targeted at specific advances in design and performance:

Advanced hydrogen turbine. Increases in efficiency and power rating will lower emissions and reduce $/kW total plant cost.
Warm gas cleanup. Eliminates thermal penalty of conventional cold cleanup and reduces capital cost. Included is application of high temperature hydrogen transport membranes for CO2 separation.
Ion transport membrane oxygen. "ITM" oxygen production greatly reduces power penalty and cost of cryogenic air separation.
Gasifier technology. Improved gasifier materials, instrumentation and controls improves plant reliability and availability. Increasing plant time on-line goes directly toward lowering energy production cost per kWh.

Starting with a nominal 600 MW current-technology FA-Class IGCC plant with slurry-fed gasification, cold gas cleanup, and 90% CO2 capture and compression, progressive application of these advanced technologies is shown to more than restore plant efficiency to pre-CCS levels (to better than 40%), and to reduce capital cost ($/kW) and COE ($/MWh) by 32% or more.

The Nov-Dec issue of Gas Turbine World magazine features a summary abstract of the DOE/NETL study, highlighting the benefits of the various advanced programs being supported by the DOE.

Additional savings on horizon
Additional savings are on the horizon with progress being made in the development of other advanced IGCC technologies outside of the DOE R&D program.

One example is the revolutionary Pratt & Whitney Rocketdyne (PWR) compact gasification process, which involves the innovative application of rocket-based technology for the production of coal-derived syngas at high pressure and temperature.

Operating conditions result in improved process efficiency and greatly reduced pressure vessel volume (by 90%), leading to an estimated 50% reduction in gasification system cost. This would clearly have a major positive impact on IGCC economics.

In another presentation at the 2009 GTC conference, PWR reported on the status of their program, including their partnership with ExxonMobil and the Alberta Energy Research Institute. As scheduled, the 18 tpd compact gasification pilot test unit started operations at the Gas Technology Institute research facility near Chicago on November 5. Hot-gas testing is now underway, and initial results have reportedly been very satisfactory.

With their process pilot plan now in operation, PWR is said to be close to announcing plans for a commercial-scale demonstration project.

Gas Turbine World is looking forward to presenting an update of the progress of this very promising advanced gasification technology program, including initial test results and design performance data, in our upcoming 2010 IGCC Reference Guide.

2009-11-08T09:36:00.012-05:00

IGCC / Coal Gasification Technologies
GTC Conference Field Report Part 3:
Supplier and R&D Updates

This is the third and final segment of our report on the Gasification Technologies Council (GTC) annual meeting held Oct 4-7 in Colorado Springs.

Earlier postings reported on project status, highlighting the Duke Energy Edwardsport IGCC plant now under construction, and the progress being made with the near-zero emission IGCC projects in the US, Australia and China. All this is happening in the face of continued global uncertainty over low natural gas prices, pending climate change regulations, and a shortage of investment capital.

We now complete our report with summaries of the presentations by major IGCC technology and equipment suppliers, and of selected reports on comparative studies and on R&D programs aimed at improving the performance and cost profile of coal-based IGCC technologies.

Facing head winds
GE’s Monte Atwell, General Manager for Gasification, told the conference that his operation is “investing heavily in customer support” and keeping very busy with the eight new licenses signed in China since 2007, and six plant start-ups in two years, involving 19 gasifiers.

“The China projects are run on a very aggressive schedule, going from contract signing to startup in about 36 months”, says Atwell. “Our commitment of resources there has gotten very large and complex.”

A major project management commitment to the Duke Energy Edwardsport IGCC is high on his list of project activity, including shipment of gas turbines in the spring of 2010, gasifier components and the completion of the IGCC simulator to be used for operator training.

In talking about new-project development, Atwell says that gasification is facing “significant head winds” with the current extended period of cheap natural gas.

“There has been a dramatic reduction in capital flows into gasification-based energy projects,” he says, “and this means that there is serious delay in the experience curve. There is also need for more government incentives and more spending on R&D,” he continues.

GE’s own technology development activity is currently focused on its “Posimetric” dry feed system, which took off with the 2007 acquisition of the Stamet solids pump technology. In 2008, GE entered into an R&D partnership with the University of Wyoming for further development of low-rank coal capabilities. The first new pump has been shipped to GE’s Shanghai R&D center for validation testing.

Other product advances, says Joe Zuiker, GE GM for IGCC and Gasification Engineering, are improved refractories, feed injectors and integrated controls. “The first radiant raw gas cooler, which will soon be shipping to the Edwardsport IGCC project site, is going to cost 30% less than the TECO (radiant/convection) configuration”, he continues, and the design is near complete for the GE “Carbon Island” for bolt-on addition of CO2 capture capability. GE is also launching an advanced 50 Hz syngas product offering, with a Frame 9F-based IGCC design.

GE is participating in the NETL Advanced Hydrogen Turbine development program, which is a part of a portfolio of R&D activities aimed at lowering the cost of coal-based IGCC power generation with carbon capture.

Atwell says that the industry will soon be facing additional challenges in the form of formal legislation to limit greenhouse gas emission and/or EPA regulations that go beyond current controls of criteria pollutants.

Although these new rules will at least provide some clarity to the situation, the addition of CO2 capture and sequestration will add greatly to product cost, implying even higher hurdles to new project activity.

"Doing quite well"
A somewhat more optimistic view of the future for gasification business was painted by Harry Morehead, Siemens’ Manager of IGCC and Gasification Marketing. “Our gasification business is doing quite well, and we see a bright future, both near-term and longer-term”, says Morehead.

As for active business, he reports that Siemens has shipped nine gasifiers, seven to projects in China (of which five are now under construction), and two to Secure Energy’s Decatur SNG project, which signed an off-take agreement with BP and is soon expected to obtain financing and proceed to construction.

As for new projects, Morehead listed the Summit Power Texas IGCC project and (in a new announcement) selection by Tenaska to supply the gasifiers to the Taylorville Energy Center project in Illinois.

He also listed Capital Power Corp’s Genesee Project in Canada, which has since announced an indefinite delay, although the FEED study will be completed. “We have other projects pending that cannot be disclosed just yet”, he says.

The Shenhua plant in China, containing five Siemens gasifiers will start commissioning in late spring 2010. It will be the largest coal-to-polypropylene plant in the world.

“For the future we are now offering the SFG-1200 gasifier, which enables us to supply a single gasifier for the 5000F gas turbine”, says Morehead. Currently two of Siemens SFG-500 gasifiers are required per 232MWe syngas fired gas turbine.

Siemens is also participating in the NETL Advanced Hydrogen Turbine Development program, and is working on advanced materials and low-NOx combustion technology for higher firing temperature machines that would burn high-hydrogen syngas fuel following CO2 removal.

“In the meantime”, says Morehead, “I want to make it clear that our current “F” machines are ready for high hydrogen fuel.” This claim is based on the use of nitrogen dilution for NOx control and, possibly, a reduction in firing temperature to accommodate the effects of high water vapor in turbine expansion gases.

More optimism from Japan
Mitsubishi also boasts of a growing business built around its now-commercial IGCC and gasification offerings.

With the Nikoso 250 MWe air-blown IGCC demonstration plant in its second year of operation, MHI has upped the ante with an aggressive commercial position regarding full IGCC EPC contracts.

“For ZeroGen in Australia, we are planning to sign an EPC contract for a single-train one-on-one IGCC plant based on our M701G2 (1500C) gas turbine and using our air-blown gasification technology,” says Koichi Sakamoto, MHI’s Deputy General Manager, IGCC and Gasification.

The gasifier will process 3,600 tpd coal feedstock, twice the size of the Nikoso demo unit, and expected power rating for the plant is 530MWe, at an LHV efficiency of 48% (before CO2 capture and storage). The plant will be design for up to 90% CO2 capture.

In addition to MHI planning to take on full plant EPC scope and risk – a first in the industry – Mistubishi Corp. is taking an equity stake in the project. At this point MHI is performing feasibility studies ahead of signing a contract for the FEED study about a year from now. Signing of the full EPC contract is planned for the beginning of 2012, and the plant startup is scheduled for mid-2015.

“Besides our air-blown gasification technology, MHI is also offering an oxygen-blown unit for use in the coal-to-chemicals industry”, says Sakamoto. According to his presentation, MHI is currently involved in three new industrial projects, but locations were not disclosed. One is a 3-train plant to produce SNG, another is a 2-train coal-to-liquids plant, and the third is a poly-gen plant which will have both air-blown and oxygen-blown gasifiers (one each). The air-blown system will produce syngas for power, and the oxygen-blown unit will feed a syngas-to-chemicals process.

“We already have two 2,000 tpd oxygen-blown coal gasifiers in operation in China”, Sakamoto told the conference. “Both went into operation this year, and are in continuous operation at near full capacity in a modern fertilizer plant” he says.

Eroding advantage
Results of a number of comparative studies were presented at the conference showing that the once considerable advantage of IGCC technology over pulverized coal when the cost of CO2 capture is taken into account has “considerably eroded” says EPRI’s Neville Holt.

Bob Slettebhaugh of Black & Veatch described their broad-based study: Comparison of CO2 Capture Costs For Coal Power Plants, exploring the scenarios that might favor IGCC.

IGCC is compared with supercritical PC (SCPC) technology, with study variables including gasifier design (slurry; dry feed), coal rank (bituminous; PRB sub-bituminous), site elevation (sea level; 6000 ft.) and percent CO2 capture (60% and 90%). In all, there were 22 cases compared.

As seen in earlier studies, 90% CO2 capture greatly increases SCPC operating cost such that IGCC turns out to be the low-cost alternative. But the advantage indicated in the B&V study is not nearly as large as seen in earlier studies. “At 60% capture (i.e. point of natural-gas equivalence) the comparison is too close to call”, says Slettehaugh.

It was also interesting to see that, with higher levels of CO2 capture, dry-feed gasifiers lead to higher product cost than slurry fed gasifiers, due to higher costs related to the water-gas shift reaction needed for CO2 separation.

High elevation, low-rank hurt
Due to 20% gas turbine power derating at 6000 ft elevation, it is no surprise that SCPC wins over IGCC in that case. Under such an extreme assumption, supposed to represent sites close to western coal mines, study results may wrongly lead one to conclude that IGCC would only be favored in the east.

Similar conclusions are reached by the latest comparative study by NETL: Cost and Performance for Low Rank Coal Power Plants.

Jeff Hoffman, NETL Sr. Analyst, Office of Systems, Analysis and Planning, presented results based on the assumption that Montana PRB sub-bituminous coal is consumed at 3400 ft above sea level – automatically penalizing IGCC cost per kW by more than 10% due to power derate (vs. sea level).

North Dakota lignite-fed IGCC plants are assumed to be located at 1900 ft elevation, penalizing IGCC by about 4%. (Note, however, the assumption of ~40F ambient temperature results in full recovery of penalty in the lignite case, and about half of the derate in the PRB coal case.)
The NETL study looked only at the case of 90% C02 capture, which typically favors IGCC over PC plants. But the derate due to elevation and the inefficiencies and cost adders due to the low-rank feedstock – particularly in the case of lignite – more than erase any of the advantages, shown by the earlier NETL studies, which looked at IGCC+CCS with eastern bituminous coal feedstock (at sea level). (See GTW issue Jan-Feb 2009.))

At 85% capacity factor, the 30-year levelized cost of electricity (COE) for the PRB-fed IGCC at 6000 ft. is around 2% higher than with supercritical PC plants (“too close to call”). The IGCC disadvantage vs. SCPC grows to about 5% in the case of lignite feedstock (at 1900 ft.)

Technology to the rescue
The promise of advanced technology to increase the efficiency and lower the cost of IGCC power plants with carbon capture and storage (CCS) was the message of the presentation delivered by Kristin Gerdes, NETL analyst.

“With today’s technology, CCS (at 90% capture) adds more than 30% to the capital cost and COE for IGCC power plants,” says Gerdes. “The DOE has embarked on a suite of advanced technology development programs to counter those negative impacts.”

The advanced technologies (and prime contractors) being supported by DOE under these programs include a single stage solids feed pump (P&W Rocketdyne), warm gas cleanup and CO2 removal (RTI, Eltron), advanced hydrogen turbine (GE, Siemens), and ITM oxygen (Air Products).

Gerdes shows that the estimated cumulative benefit of progressively introducing these technologies is to lower capital cost and COE to just below the pre-CCS reference case values along with an 8 percentage point improvement in efficiency.

“Advanced technologies offer a pathway to significantly lower cost and better performance than current IGCC plants with CCS”, she concludes.

Technology advances addressing challenges
As has become the custom, the final session of the GTC conference was dedicated to advances in gasification technologies.

Stewart Clayton, Manager of the DOE Office of Fossil Energy Gasification Programs, kicked off the session saying that technology innovations are critical to addressing today’s challenges of cost reduction, efficiency improvement and climate change mitigation.

“This requires a joint commitment by industry and government to meet long term goals of sustainability”, Stewart told the conference.

As described by NETL’s Kristin Gerdes (above), presenting an analysis of DOE’s R&D program benefits, cumulative results are expected to deliver substantial cost reductions and efficiency improvements, better than making up for the negative impacts of carbon capture and sequestration on IGCC plant economics.

Following are highlights of presentations updating status of two key gasification technology programs having the greatest positive impacts. Another key program element, the Advanced Hydrogen Turbine Development program, was not presented at the conference. See GTW May-June issue for details.

Warm gas cleanup Program objective is to lower cost and improve efficiency by replacing current low-temperature commercial syngas cleanup processes with desulfurization and contaminant removal at moderate to high temperatures. RTI International, the main contractor, is also working on a high temperature CO2 capture system, which like the other process elements, uses a regenerable sorbent.

Another option for CO2 capture is to use a high temperature hydrogen transport membrane, operating at full syngas pressure. This is being developed by Eltron Research of Boulder CO, also with DOE support.

”Field testing at the RTI warm gas cleanup pilot unit on real coal-derived syngas at Eastman Chemical, (Kingsport TN), was completed in 2008”, says Raghubar Gupta, Sr. Research Dirctor at RTI. Testing confirmed ability of zinc oxide transport reactor to achieve 99.9% sulfur removal, and effective removal of ammonia, mercury and other contaminants in a multi-contaminant control unit. Work has now started on a 50MWe-scale demo plant to be installed at the TECO IGCC plant near Tampa. Start of testing should begin in 2012.

According to the NETL analysis, warm gas cleanup, incorporating high temperature (membrane) CO2 capture, would contribute more than half of the potential 30% cost savings and 8 percentage point efficiency improvement expected from the overall DOE R&D program.

ITM oxygen “Current commercial cryogenic air separation used to supply gasifier oxygen represents about 15% of total IGCC plant capital cost and consumes about 15% of gross plant power output”, says VanEric Stein, lead development engineer at Air Products & Chemicals. “Ion transport membrane (ITM) technology offers a step change reduction in oxygen cost and power consumption”, he continues.

Air Products has been working on ITM oxygen development for more than 20 years. With DOE support over the past 5 years, development has progressed from lab scale through the successful operation of commercial scale (0.5 tpd) modules in a 5 tpd scaled engineering pilot (SEP) unit.

“Oxygen purity of better than 99% has been demonstrated”, says Stein, “and SEP work continues with testing of 1.0 tpd modules.” Effort also continues to address design challenges related to cycling of the ceramic modules. “The ability to cycle the ITM modules continues to improve”, says Stein.

Meanwhile work has begun on the next step of ITM scale-up. A 150 tpd intermediate-scale test unit (ISTU) is in detailed design and long lead item procurement. Construction activities will begin next year, and operation and testing of ITM modules will start in 2011.

“At that time we expect to begin commercialization of small plants (< style="font-weight: bold;">

Rocket-base gasifier technology
progressing to pilot scale

As impressive as the portfolio of advanced IGCC technologies being supported by DOE is, surprisingly absent from the list is participation in the significant progress being made in the development of new breed of gasification technology.

Alan Darby, Pratt & Whitney Rocketdyne (PWR) gasification program manager provided an update on the development of a high-pressure compact gasifier, which is about to enter pilot-scale testing at Gas Research Institute’s facility near Chicago. (Ed. Note: Formal commissioning of the pilot test unit took place on November 5, 2009.)

Although the DOE had been involved in some earlier R&D support, and continues to fund development of PWR’s advanced single-stage dry feed pump, the GTI pilot plant is moving ahead totally on non-DOE money.

According to Darby, their own corporate commitment to the technology has been joined by the “active partnership” of Exxon-Mobil and the license agreement with Zero Emission Energy Plants (ZEEP). Funding has also been provided by AERI of Alberta, the Illinois Department of Commerce and Economic Activity (DCEO), and the Gas Technology Institute.

Darby described the PWR technology as the result of an innovative application of Rocketdyne’s rocket engine technology. The current progress stems from “proof-of-concept” research-scale testing some 30 years ago, when the DOE’s support of advanced clean-coal technologies was part of “Project Energy Independence”.

Work was recently restarted by PWR with component testing at the University of North Dakota’s Energy & Environmental Research Center (EERC), and the decision was made to go ahead with an18 tpd test unit at GTI.

“The pilot test program is aimed at demonstrating gasifier performance, verifying operating procedures and validating design models”, according to Darby.

Rocket technology means big savings
The PWR gasifier is designed to operate at 1000 psig, at high temperature and extremely high reaction speeds, Darby continues. It is expected to result in a 90% reduction in gasifier size compared to today’s conventional entrained-flow gasifiers, and cut gasifier cost by 50%.

The design features a water-cooled liner, partial-quench and dry-particulate removal, and PWR engineers are predicting extremely high (99%) reliability and availability for their commercial design concept. This includes use of an advanced single-stage solid feed pump, still under development, that is not currently included in the pilot plant.

“The new pump will eliminate the need for any lock hoppers, delivering the pulverized coal directly from atmospheric-pressure storage bins into the gasifier”, says Darby. “Not only does this lead to a simpler and more reliable design, but it means lower oxygen consumption (than slurry feeds) and the ability to handle all ranks of coal.”

Results of a 2006 NETL study comparing a wide spectrum of gasifier technologies showed that a plant incorporating the PWR compact gasifier can reduce syngas product cost by 15-20%, concludes Darby. Test data from the GTI pilot unit should soon be available to help confirm such predictions.

2009-10-20T21:51:00.009-04:00

IGCC and gasification project progress
ZeroGen, GreenGen, Edwardsport, NewGas, more

This is the second of a three-part field report from the 2009 Gasification Technologies Council conference held in Colorado Springs, Oct 4-7

Previous posting reported on insightful Keynote address given by Gov. Freudenthal of Wyoming, a status report by Tenaska on their Taylorville IGCC project, and an update on the status of the "reborn" FutureGen project.

Coverage picks up here with status on the other near-zero IGCC plus CO2 capture projects planned in Australia and China, and other items of interest, including the Duke Energy Edwardsport IGCC and ConocoPhillips/Peabody Coal Kentuck NewGas project.

ZeroGen - MHI taking the wrap
Australia’s “ZeroGen” IGCC project has progressed to the pre-feasibility study phase, and to the point where Mitsubishi has entered the project both as an equity partner and as probable EPC contractor.

The plant will have a net power rating of 530MWe, based on a single-train MHI M701G2 combined cycle integrated with their own air-blown entrained-flow gasifier.

“ZeroGen is a state-owned company with a mission to demonstrate a way to sustain coal-based power generation in Australia, and especially in Queensland”, says Project Director Chris Greig.

“We fully expect the plant to be up and running by 2015, capturing and sequestering 2 million tonne per year of CO2.”

Initially the plant will operate at 60% carbon capture, and it will be cranked up to 90% capture during the demonstration phase, according to Grieg.

“We can’t afford to fail,” he says, and the agreement with Mitsubishi, the first in the industry for an IGCC plant, would appear to be a key factor in the optimism over the project’s success.

“MHI is going to take the full ‘EPC wrap’ – with a make-good warranty on full plant performance, including third party technologies,” Grieg continues.

Actually, the signing of an EPC contract is not scheduled until 2012, after completion of a FEED study.

Currently, along with plant engineering design studies, site selection is underway and CO2 injection testing is being started. Storage in deep saline aquifers is planned, since there are no enhanced oil recovery opportunities for the project.

The project is also competing for Australian government support under a national program that will help fund two clean coal projects with a total of around 1000MWe generating capacity. At the same time, negotiations are underway with local authorities to obtain “must-run” status for the plant, according to Grieg.

GreenGen - Will China be first?
And then there is China’s GreenGen, which, like FutureGen and ZeroGen, is a high-visibility project aimed at demonstrating near-zero emission coal-based IGCC with CO2 capture.

Like FutureGen, GreenGen involves an industrial alliance of China’s largest energy companies. The China Huaneng Power Group, China’s largest coal-based power utility, holds 51% of the equity and is the managing partner; Peabody Coal in the US is the only non-Chinese member of the GreenGen alliance. (Ed. Note: Huaneng is a member of the US FutureGen Industrial Alliance, so is Peabody.)

GreenGen will use a Chinese home-grown gasifier design, developed by the Thermal Power Research Institute (TPRI ~ China’s EPRI).

Dr. Xu Shisen, TPRI Director of New Power Generation Technology, told the conference that, after 15 years of R&D, including operation of a 36 tpd pilot unit through 2005, a 250MWe IGCC demonstration plant is now nearing completion.

“The demonstration plant will start operation in 2010. It features a 2000 tpd TPRI gasifier,” says Xu, “and is the precursor to the actual GreenGen project, which will be a 450MWe IGCC with CO2 capture and storage.”

The TPRI gasifier is a two-stage water-wall design with dry feed. There is no water quench, but a chemical quench instead, according to Xu. “That contributes to a very high cold-gas efficiency of about 83%,” he says.

Depending on economic and technical evaluation, GreenGen may feature a single 3500 tpd gasifier or two 2000 tpd units. Xu says that the larger plant has been approved and is scheduled for completion in 2014. It may also include a demonstration solid oxide fuel cell power generation fueled by hydrogen separated from the coal-derived syngas after CO2 removal.

In addition to the GreenGen project, Xu told the conference that there is another TPRI gasification demonstration project near completion in China, and that the technology has also been selected by Future Fuels LLC for their Future Power project in the US.

The 270MWe IGCC plus carbon capture project, being planned for the anthracite region of central Pennsylvania, is seeking government support under round three of the DOE’s Clean Coal Power Initiative.

Wrestling the 500 lb gorilla
Meanwhile, back in the states, ConocoPhillips’ E-Gas Product Manager Cliff Keeler described the challenges in developing a coal gasification project and getting it permitted in the US these days.

The Kentucky coal-to-gas project, NewGas, appears to be on track despite having to deal with an extensive “CO2 solution” that, says Keeler, is now a prerequisite for project development. ConocoPhillips and Peabody Coal are co-developers in the project.

“CO2 has become the 500 lb gorilla that penalizes all coal projects, and ours is now being designed to be storage ready.” The project includes 90% carbon capture, with plans to have the CO2 vent-gas from the methanation process collected, compressed and transported to a nearby site for geological storage. Enhanced oil recovery is also a potential storage option, says Keeler.

The plant is designed to produce some 60-70 billion cu. ft. per year of pipeline quality SNG, and heat recovered from syngas cooling and the methanation process is used to generate enough steam to drive a 250MWe turbine-generator.

Keeler described the approach being taken to obtain necessary state and federal air permits for the project, giving special emphasis to understanding start-up and shut-down emission issues.

The plan is to start the plant on natural gas, and to execute a “seamless transfer” to coal while minimizing transient plant emissions.

Normal full-load emissions profile for the plant is not at all an issue in the permitting process, according to Keeler. “Our levels of SOx and NOx will be a fraction of those being permitted for a new coal power plant”, he points out.

Keeler also pointed to the complex nature of multi-train coal-to-gas plant, and the importance of utilizing the combined expertise of the various technology suppliers to optimize operations, start-up and shutdown procedures.

SNG vs. IGCC vs. H2
In another presentation by ConocoPhillips, Phil Amick, Gasification Commercialization Manager, described the differences between design requirements for a gasification-based SNG facility and an IGCC plant configured solely for power generation.

“The methanation process and pipeline specifications for SNG puts tighter demands on the process design than when you are making fuel for a gas turbine ”, says Amick, referring to lower sulfur and moisture limits and higher oxygen purity, all of which dictate process design decisions that make SNG more costly.

Amick also told the conference that in-house studies have resulted in a decision to configure their pet-coke gasification project planned for the Sweeney Refinery in Texas as a two-gasifier three-GT IGCC plant with a net power rating (after CCS loads) of almost 700 MW.. Apparently, low natural gas prices have driven the product-mix more toward power and away from hydrogen for use at the refinery.

Just before the conference, the DOE announced that the Sweeney project will be receiving a $3 million cost-share grant to assist in the demonstration of “new advancements that improve conversion efficiency and economies of scale for carbon capture systems”.

The project will feature 85% CO2 capture and is expected to deliver as much as 5 million tons of CO2 a year to depleted oil fields or gas wells, according to the DOE announcement. “We are now in the process of filing papers for air permits,” Amick reports.

Duke well underway at Edwardsport
Last year they were moving dirt, and now they are “moving forward” was the theme of this year’s presentation on the status of the Edwardsport IGCC project.

For me, the highlight of the conference was in seeing a set of recent photos of the construction site showing some real progress after years of planning, permitting and preparation.

What a difference a year makes, said Dennis Zupan, Duke Energy’s General Manager, Projects, as he showed visual evidence of what it means to have achieved 26% completion of construction (as of September 1). Engineering work is now 85% complete, he says, and a FEED study for a 20% CO2 capture project add-on is in the works.

“Almost all of the excavation work is completed; same with the piling and underground piping,” Zupan reports. Photos showed initial components of the coal preparation and gasification area set in place, and foundations in the power block area.

We are building a ‘first-of-a-kind’GE Reference Plant, Zupan says, with “lessons already learned” during the engineering, procurement and construction phases of project development.

“We are happy to note that GE’s project team has matured during this process which will prove to be of benefit to other projects.”

At last year’s GTC conference, Zupan had commented on how the “IGCC alliance” between GE and Bechtel was not working out as expected, and that Duke had to provide major project management resources to fill the gaps.

Referring to a project progress curve showing that the overall project progress is just past the 40% mark, Zupan also noted that September, 2011 is the date scheduled for first-firing of Gas Turbine No. 1 and August 2012 is the expected ‘substantial completion date’ when the plant will enter startup and commissioning activities.

“We are now getting well into planning for operations,” says Zupan. “This includes an operator training program using an IGCC simulator developed by GE. We’re also doing maintenance planning and fine tuning plant manning levels and skills needs,” he concludes.

BP IGCC - California dreamin’?
Craig Skinner, BP Engineering Manager for the Hydrogen Energy California Project, introduced the conference to the latest version of BP’s 250MWe IGCC project planned for southern California. The plant will be designed for both petroleum coke and western bituminous coal.

Rio Tinto is BP’s joint venture partner on the project, along with a list of other participants including GE (gasifier and gas turbine), Fluor (engineering and construction) and Occidental Petroleum (CO2 customer).

Southern California Edison (SCE) would be the off-taker of the plant’s power output, assuring baseload operation. SCE is also granting $30 million to the project under a PUC approved alternative fuels development program.

(Separately, SCE reported on its own $50 million study (with Worley Parsons) on the feasibility of building a coal-based IGCC plant in the area.)

Hydrogen Energy California has replaced BP’s Carson Hydrogen Energy project, which apparently ran into a number of issues that have put it on the back burner. The new project does not co-produce hydrogen for refinery use, as was the case with Carson.

“The new plan has some distinct advantages and we are now making good progress,” says Skinner. “It’s the right project, in the right place, with the right partnership,” he adds, referring to their active nurturing of various private and public relationships.

The project enjoys both state and federal support, according to Skinner. In September, a co-operative agreement was signed worth $308 million under the DOE’s third-round Clean Coal Power Initiative, while the California PUC and Energy Commission are both indicating favorable positions toward the project.

Recently, a licensing agreement was signed with GE for the gasifier technology, releasing the process design package. The full FEED study is scheduled for release early in 2010.

“The GE quench gasifier was selected for its low technical risk,” says Skinner. “We are also impressed with the comprehensive 7FB (gas turbine) hydrogen testing program conducted by GE.”

The plant will meet strict California air quality standards and produce more than 2 million tons per year of byproduct CO2, which will be used for enhanced oil recovery in Oxy’s Elk Hills Reservoir about 5 miles from the project site. Oxy is currently the largest EOR operator in the US. According to current development schedule, construction will begin in 2012, and commercial operation would start in 2015-2016.

To be continued..........Next and final installment will highlight selected presentations by gasification/IGCC technology suppliers and report on results of some of the comparative studies presented at the conference. Key technology advances that address the need to cut IGCC costs are also highlighted.

2009-10-16T12:19:00.013-04:00

Progress reported at 2009 GTC conference in spite of challenging times for coal gasification and IGCC

Construction of Edwardsport IGCC and progress of other key projects and technology improvements overshadow continuing uncertainty over CO2 regulations.

In the face of an extended period of globally cheap natural gas, economic downturn and capital shortages, topped by continuing uncertainty over pending greenhouse gas regulations, this year’s annual Gasification Technologies Council (GTC) conference kicked off in Colorado Springs with a message of a positive future for the industry.

Conference co-hosts Jim Childress, GTC executive director, and EPRI’s venerable Neville Holt each delivered opening remarks with a message of “difficult and challenging times” mixed with optimism over technology developments underway to address both economic and environmental obstacles.

Childress noted that, despite the down economy, registered attendance of almost 750 people demonstrates continued interest and strength in the industry.

The highlights of the conference were indeed positive and forward looking:

Construction of the 630MW Edwardsport IGCC plant is more than 25% complete
China continues to lead in new gasification installations and development
FutureGen, ZeroGen and GreenGen are all progressing
Cost-cutting advanced technologies moving ahead

This is the first of several postings planned to report on the 2009 GTC conference.

Visit the GTC website for access to all conference presentations.

Wyoming strikes sharp keynote
Keynote speaker, Hon. David Freudenthal, Governor of Wyoming, showed extraordinary insight into today’s challenging energy and environmental situation.

Wyoming, US’ leading coal producer, is in a “great position” to meet the energy needs, says the governor, “but we need more from the Federal government to put its words and promises into action.

All that we have gotten so far from Washington is symbolic crumbs – not substance.”

“With the likes of the Sierra Club being supported by the natural gas industry to fight coal utilization, large-scale clean-coal projects – and gasification in particular – need to succeed,” he continues.

For this to happen, he says, there needs to be CO2 legislation passed to provide some clarity to investors. “There is too much money sitting on the sidelines waiting for clarity, and there remains a lot of work to be done by Congress since current bills won’t do the trick.”

There is also a need for the same type of financial commitment for clean coal that the government has made to support wind energy, which is enjoying investment tax credits and other forms of financial support.

“Coal needs a level playing field,” concludes Gov. Freudenthal, “it is still our lowest cost option.”

Illinois on the move
Since gasification-based technology gives new promise to the use of high sulfur eastern coals, states such as Indiana, Illinois and Kentucky are proven to be very favorable locations for projects that will help revive their coal industries.

An upbeat presentation by Bart Ford of Tenaska described how strong state support is helping keep the Taylorville Energy Center project in Illinois on a forward tack.

That project, currently estimated to cost around $3.5 billion, is now configured as a “hybrid IGCC”, says Ford, where the gasification island will be operated to produce pipeline quality SNG, and the stand-alone 730MWe power block can be fired with SNG produced on site or from the natural gas pipeline. Sixty percent of the CO2 normally vented by the methanation process will be captured and delivered to a pipeline for remote geologic storage or for enhanced oil recovery

Ford praised supportive state policies that are enabling the Taylorville project to obtain favorable financing terms. For one thing, the project has qualified under the Illinois Clean Coal Portfolio Standard Law, which establishes a framework for developing coal gasification projects with carbon dioxide (CO2) capture and storage. The law, says Ford, requires emissions from these plants to be as clean as natural gas – and at least 50% CO2 capture.

Importantly, the law mandates 30-year power purchase agreements with qualifying “initial clean coal facilities”, and this has put the Taylorville project on track for financial closing early in 2010, according to Ford.

In a separate announcement, Harry Morehead, Manager of Gasification and IGCC Marketing at Siemens Energy, told the conference that Siemens Fuel Gasification technology has been selected by Tenaska to supply the gasifiers for the project. There was no similar announcement regarding the supply of the power block. Unconfirmed reports are that the owner’s engineer, Burns & McDonnell, is expecting to handle that under their scope.

FutureGen reborn
More optimism was displayed during a conference session dedicated to gasification power projects in development with carbon capture.

FutureGen Industrial Alliance’s David Brown talked about the “rebirth” of the advanced nominally 250MWe IGCC project to be sited in Mattoon, Illinois.

“It’s the right technology, and the right time”, says Brown about the US DOE-supported project that was all but killed at the close of the Bush administration due to its escalating costs. But with a new administration, and a correction in the way that the cost increase was determined, the project seems to be back on track.

Site selection and the environmental impact statement are completed, according to Brown, and a comprehensive cost estimate for a re-configured design will soon be published.

“The plant will initially operate at 60% carbon capture (i.e. natural gas equivalence) and will go to 90% capture in the third year of operation”, explains Brown. “At that level the advanced gas turbine will be operating on high-hydrogen syngas that will push well beyond demonstrated limits.”
The RFP for a turnkey gasification island was issued in September and selection of a contractor is pending further evaluation and budget approval. The new FutureGen project schedule shows startup late in 2013, and commercial operation a year later.

In next installment: ZeroGen (Australia) and GreenGen (China) make progress.

2009-10-03T16:59:00.013-04:00

Bringing down the cost of IGCC
plants with Carbon Capture

By now, industry observers and especially regular readers of Gas Turbine World Magazine and this blog well understand the negative impact on coal-based power plant performance and costs associated with the various technical and regulatory proposals aimed at lowering CO2 emissions and to dispose of the waste CO2.

Several recent studies, notably those supported by EPRI and the DOE/NETL (see Jan-Feb 2009 GTW), have been focused on the severity of the economic impacts of carbon capture and sequestration for all forms of coal-based power generation.

For example, the impact of 90% CO2 capture on typical current-technology slurry-fed IGCC plants is to reduce HHV efficiency by more than 15 percent (from around 38% to below 32%).

And the additional parasitic plant loads reduce net plant output of 15 percent. Combined, the net effect is to increase total plant capital cost ($ per net kW) by over 35 percent and add at least 35% to the 20-year levelized cost of electricity (COE).

IGCC has advantage
NETL estimates that the impact for pulverized coal plants with 90% CCS is even a larger penalty - a whopping 85% increase in COE -- emphasizing a true advantage of IGCC technology in a carbon constrained world.

In a drive to recoup losses in IGCC plant efficiency, and mitigate increases in costs, the DOE has several advanced technologies under development with a well defined technology pathway for both near term and longer term improvements.

Most recent studies published by NETL show that the cumulative impacts of advanced technology programs are expected to improve the efficiency of IGCC+CCS plants by 8 percentage points and reduce capital cost and COE by over 30 percent.

Progress reported
Progress being made on a broad portfolio of DOE/NETL advanced technology development programs promises to significantly improve process efficiency, cut capital costs and substantially lower the cost of energy produced by coal based IGCC plants operating with carbon capture and sequestration.

Largest returns are expected of the following projects which are targeted at specific advances in design and performance:

Warm gas cleanup. Eliminates the thermal penalty of cold cleanup and reduces capital cost of the process.
Ion transport membrane oxygen. "ITM" oxygen production reduces power penalty and cost of cryogenic air separation.
Advanced hydrogen turbine. Advanced gas turbine increases efficiency and power rating, lowers emissions and reduces $/kW total plant cost.
Gasifier technology. Improved gasifier materials, instrumentation and controls improves plant reliability and availability.

At the 9th Greenhouse Gas Technologies Conference held in Washington DC late last year, Julianne Klara, a senior analyst with NETL, Pittsburgh, discussed the potential for these technologies to reduce costs in future IGCC plants.

An updated presentation of study results will be made at the 2009 Gasification Technologies Council conference being held in Colorado Springs, next week Oct 4-7.

Natural gas as the "bridge fuel"
The focus of DOE’s Clean Coal R&D program is on restoring the economic viability of coal-based power generation with carbon capture and sequestration (CCS) by applying advanced technologies to a gasification-based configuration.

Because of the steep environmental challenges currently frustrating new coal-based projects in the US, she maintains, the situation has created a dilemma for coal. Almost all new generating capacity being added is based on using natural gas fuel.

Although the use of this “bridge fuel” by utilities and developers alike is seen as the only viable alternative for reducing CO2 emissions at this time, recent history tells us that this alternative is fraught with risk of fuel cost volatility relative to coal.

The long-term solution for coal, according to the NETL study, is the technology needed to achieve the cost reductions and performance improvements to make coal-based IGCC plants with CCS more competitive with natural gas fired combined cycle plants.

2009-07-02T11:04:00.016-04:00

NY Times Attack on FutureGen Not "Fit to Print"

Op-Ed piece throws FutureGen under the bus in IGCC / Clean Coal Blooper

On June 28, the New York Times carried an Op-Ed piece by "author/journalist/lecturer" Gregg Easterbrook entitled "The Dirty War On Clean Coal" that raises serious questions about the Times' 100+ year-old motto "All The News That's Fit To Print". (In case you can't open the link to the actual piece, I've repeated it at the bottom of this posting.)

Rather than the Times having Easterbrook's work pre-viewed by their energy staff, it would appear that the op-ed page editor had full freedom to publish, and was either totally blind to the issues and/or was just as technically inept as is the author.

The following letter was sent by this writer to the author. Others have sent letters to the Times editor to suggest that they should be embarrassed by the piece.

In the words of one industry executive: I was also appalled at the uninformed inconsistency of Eastbrook's Op Ed. It was an embarrassment to the New York Times for them to publish such a poorly researched work that was so full of factual errors.

Read on and tell us what you think. If you get turned on by the issue the way that we were, write your own letter the the NY Times editor to help set them straight. At least they may try to do a better job researching such technical matters, rather than just exploiting it as the political issue that it has become.

Dear Mr. Easterbrook,

Where shall I begin?

I'm still so upset about your Op-Ed piece "The Dirty War Against Clean Coal" in the June 28 issue of the New York Times that I'm not sure just how to start to tell you.

I've been closely involved with the subject of IGCC and clean coal for many years, and, of late, I have been writing articles in Gas Turbine World Magazine on the subject. Frankly, my readership compared to yours is quite small. Even our blog is visited only a few times a day. But I know that my audience is technically astute and I'm careful to make sure that I'm technically accurate and fundamentally sound in my editorial commentary.

When I read your piece I couldn't believe that something with so many technical errors and mis-statements is being read by so many - not only in print but also by the wide on-line audience enjoyed by NYTimes.com.

First of all, how can you pretend to know what you are talking about when you don't even realize that the FutureGen project, which you condemn, is, in fact, exactly what you are trying to promote?

FutureGen as currently configured will be a state-of-the-art IGCC plant, which you say you favor for immediate deployment. It will be fitted with an added chemical process step to remove CO2.

Moreover, the fact of the matter is that GE will almost certainly be offering to FutureGen essentially the same technologies - gasification and power generation -that they have sold commercially to Duke Energy for Edwardsport.

So, FutureGen will not be an R&D "experiment" as you make it out to be. It will be a working IGCC plant, just as you are suggesting should be built right now.

The CO2 capture technology that would be used to remove at least 60% of the CO2 (and thereby give the plant at minimum the same carbon footprint as a modern natural gas fired combined cycle plant) is very old chemistry that is in use in numerous chemical plants where CO2 has to be removed from gas streams.

It is not new and unproven as you intimate. In fact, it is being used in the Dakota Gasification plant in North Dakota where coal is used to manufacture synthetic natural gas (SNG, which is essentially methane). For more information on that operation you should visit http://www.dakotagas.com/

By the way, that plant was built with Synthetic Fuels Corporation support and was taken over by private operators. So your comment about how the SFC didn't accomplish anything is off base. The predecessor to the successful Wabash (IN) IGCC plant was also supported by the SFC.

At the Dakota plant, the CO2 used to be vented directly into the atmosphere. Since 2005 it has been collected and sent by a 200 mile pipeline to Alberta, Canada for use in pressurizing an old oil field to enhance production. This is the sort of thing being planned for the CO2 collected at the FutureGen project, although they are primarily considering some form of geologic injection or injecting into a deep saline aquifer.

So, contrary the picture that you painted, FutureGen will combine two proven technologies: an IGCC plant using an F-class gas turbine and conventional CO2 removal chemistry. It will not be an R&D project in its initial configuration. It has been carefully planned as a plant that will not - repeat will not - use unproven technology and risk being a white elephant. If they build it - it will work. And it should go forward to provide a useful demonstration of the marriage of these two technologies.

Another issue that I had with your piece is that you seem to be inferring that the new Duke Energy Edwardsport IGCC plant will be the first commercial scale coal-based IGCC plant. Are you not aware that the first successful IGCC plants in the US were operating in California and Louisiana more than 20 years ago?

Are you not aware of the operating plants (since the mid-90s) in Wabash, Indiana and Tampa, Florida?

Are you also not aware of two large coal-based IGCC plants operating in Europe? What about 10 or more IGCC plants that operate on refinery residue in the US and Europe?

You should have taken time to learn about those plants so you could be more accurate when write about these things.

And, by the way, your entire premise about IGCC cutting CO2 emissions by one-third compared to conventional coal plants is way off base. For it to be correct, the heat rate or efficiency of an IGCC plant would have to be one-third better than conventional coal. That just isn't the case.

Unless you are comparing new IGCC plants to very old coal-fired plants, the fact of the matter is that the heat rate or efficiency of modern coal plants (where they burn coal as they have for a hundred year, as you put it) is not that much worse than that of IGCC plants. So the amount of coal used to generate the same amount of electricity in an IGCC plant and a new conventional coal plant is not all that different.

Therefore, the amount of CO2 emitted by the two coal-based power generation technologies per kilowatt hour of electricity is not that different. Please see the attached chart which illustrates this fact. It came from a DOE presentation a few years ago, but is still very valid.

On this basis, your idea of promoting IGCC as a way to cut CO2 emissions by one-third is totally in error - and makes your entire position technically unsound. This sort of erroneous argument does not help the case of IGCC.

What is true - and you do touch on this - is that removing CO2 in a pre-combustion mode from syngas (i.e. using coal gasification and IGCC) is much more practical and economical than removing CO2 from the exhaust of a conventional coal-fired power plant.

This is the main argument in favor of IGCC for new plants, that is, when there is regulatory pressure on the removal of CO2 from coal-based power generators, it will be more economical to build IGCC plants with CO2 removal than to build conventional plants with CO2 removal.

As you could see, although I agree with you that gasification has its advantages over conventional coal burning, I have many issues with your piece and it aggravates me that the New York Times would publish it without first consulting with someone who knows something about the technology and the technical issues before letting it go out to such a wide audience.

Yours very truly,

Harry Jaeger

Gasification Editor

Gas Turbine World Magazine

Following is the Op-Ed piece published on June 28 in the N.Y. Times.

The Dirty War Against Clean Coal
By GREGG EASTERBROOK
Washington

WHILE President Obama’s cap-and-trade proposal to reduce greenhouse gases has been the big topic of recent environmental debate, the White House has also been pushing a futuristic federal project to build a power plant that burns coal without any greenhouse gases.

Sounds great, right? Except the idea is a rehash of a proposal that went bust the first time around. More important, the technology already exists to make huge reductions in greenhouse emissions from coal, allowing power companies to begin cutting the carbon footprint of coal today. Instead, advanced-technology coal power sits on the shelf while regulators wait to see what happens with a project that may be just an expensive boondoggle.

The big project, a public-private partnership called FutureGen, was first announced by George W. Bush in 2003. Dreading facing up to the problem of greenhouse gases from electricity generation, the Bush White House suggested that decisions should wait while FutureGen developed a coal-fired power with no emissions. FutureGen’s administrators spent five years on studies, proposals and studies of studies, but never broke ground for a test installation.

Then, in a fit of integrity, the Department of Energy decided the project should be put in Illinois, a
Democratic state — Midwestern coal is high in carbon, making this a logical choice — rather than in Republican Texas, which the White House preferred. The administration promptly canceled financing for FutureGen. But this month, Energy Secretary Steven Chu announced he was reviving the project, hinting that the ultimate cost may run to billions of dollars.

FutureGen was better off canceled. Government is good at basic research, poor at commercial-scale applied energy technology. The Synthetic Fuels Corporation, a heavily subsidized attempt begun by the Carter administration to manufacture gasoline substitutes, flopped without ever producing a marketable gallon.

The Energy Department has also financed such overpriced, unrealistic projects as the MOD-5B, a wind turbine that weighed 470 tons and stood 20 stories tall: it looked like a gigantic propeller intended to push the earth to a new star system. It ended up being sold for scrap.

The Obama administration’s FutureGen plan calls for yet another year of study before any actual action; test runs may not begin for a decade. No wonder the project’s nickname is “NeverGen".

This is part of a Washington tradition — beginning pie-in-the-sky projects that create an excuse to avoid forms of conservation and greenhouse-gas reduction that are possible immediately. Companies including General Electric have already perfected technology to reduce emissions substantially, called “integrated gasification combined cycle” power. (Yes, it needs a better name.)

Current coal-fired power plants burn pulverized coal using a combustion process that hasn’t changed in a half a century. The new approach turns coal into a gas similar to natural gas, which runs through a device similar to a jet engine. Such plants can achieve near-zero emissions of toxic material and chemicals that form smog, and they require about a third less coal than regular coal-fired power plants to produce an equal amount of energy, which means about a third lower greenhouse gases.

Beyond that, the promising technology of “sequestering” carbon dioxide — pumping it back into the ground to keep it out of atmosphere — appears for technical reasons to be impractical for conventional pulverized-coal power plants. But gasification plants have technical characteristics that should make “sequestration” of carbon feasible. A gasification power plant with sequestration would have around two-thirds lower greenhouse gases than a conventional coal-fired generating station.

The first commercial gasification power plant, designed by General Electric for Duke Energy, is being built in Indiana. Yet, absurdly, most state public-utility commissions have denied requests to construct the seenvironmentally friendly systems. Last year, Virginia denied a major utility’s request to build a coal-fired power plant that would have sequestered nearly all its carbon output.

One reason Virginia gave for the denial was the higher up-front cost of a gasification plant. Yet, once greenhouse gases are regulated (and President Obama’s cap-and-trade plan would in effect tax carbon), the economics of gasification plants may become attractive, with low-emission plants costing less to run.

Another reason for the denials is that utility commissions are waiting for the outcome of the FutureGen experiment. This is a classic instance of the best being enemy of the good. Rather than starting to cut coal-caused carbon emissions right now, we are waiting to see if a hypothetical system could achieve perfection decades from now. Meanwhile, emissions continue willy-nilly.

FutureGen is politically appealing: contractors get subsidies, politicians get to hand out money in their districts and astonishing breakthroughs are promised at unspecified future dates. Why aren’t progressives fighting for an immediate embrace of gasification power?

Much of the environmental movement clings to a fairyland notion that coal combustion can soon be eliminated, and therefore no coal-fired power plant of any kind, even an advanced plant, should be built.

Reflecting this mindset, Senate Majority Leader Harry Reid has said he opposes integrated gasification plants — only new solar, wind and geothermal facilities should be allowed. Environmentalists who correctly point out there can never be absolutely “clean coal” thus end up in the position of opposing coal that’s far cleaner than what we are using.

Yet coal use is a future certainty. Half of our power comes from coal, versus about 2 percent from solar and wind: in the next few decades, green power simply cannot grow quickly enough to eliminate the need for coal.

We have two choices: do nothing and wait for FutureGen while coal-caused carbon emissions continue unabated; or start building improved coal-fired plants that reduce the problem. Which seems moreforward-thinking?

Gregg Easterbrook is the author of “The Progress Paradox” and the forthcoming “Sonic Boom.” Y
http://www.greggeasterbrook.com/

2009-03-11T00:01:00.030-04:00

IGCC Cost Error or Illinoisian Math - You Call it

$500M math error found in FutureGen cost

We all learned in today's headlines that the cost of the FutureGen project did not really double, as claimed by the Bush administration in their Xmas Eve 2007 dumping of the ill-fated US flagship IGCC+CCS project

No, as it turns out, the DOE "erred" by $500 million. The project cost may actually have increased by only 39% above its original $1 billion budget, and should not have been killed after all.

Politics and economics
Apparently, the resurrection of the FutureGen project - in Illinois - was on the new administration's agenda all along.

Thanks to the Government Accountability Office they now have the vehicle to put it back on track - in less than two months after Obama took office!

A GAO report that just brought this to light was prepared for Representative Bart Gordon (D-TN), chairman of the House Science Committee. (Why did it take a year to surface? And, why didn't FutureGen supporters challenge this "mistake" earlier?)

Rep. Gordon, expressed "astonishment" that the top DOE leadership made critical decisions about US energy future and efforts to combat global warming on the basis of "fundamental budget math errors".

He called it "math illiteracy on a grand scale and with global consequences."

To inflate or not to inflate?
What's all the fuss about anyway? What "mistakes" have been uncovered?

According to the GAO report, it all happened back in December, 2007 - just after it was prematurely announced that the selected site for the project would be Mattoon IL, and not in Texas.
After spending some $175 million on the project, the DOE announced that the estimated cost had doubled from the original $950 million estimate, and pulled the plug on the project.

This conclusion, now says the GAO, was reached when DOE inaccurately compared the original estimated project cost in constant 2005 dollars with a new estimate in fully inflated dollars that reflected what would have been spent over the life of the project.

Based on the same constant 2005 dollars, say GAO auditors, an apple-to-apples comparison would have concluded that the plant would cost $1.3 billion, an increase of about $370 million, or "only" about 39 percent, over DOE’s original estimate.

It did not increase by more than $900 million as previously concluded by DOE, a near doubling of the project cost, say GAO auditors.

Could it be?
And why would the DOE be so bold as to make such a blatant apples-to-oranges comparison in broad daylight? Why wasn't this error caught sooner? And why did the GAO report just now surface?

Could it be that the FutureGen Alliance's "premature" announcement of its decision to build the project in Illinois had something to do with a change in the DOE's methods used to estimate project costs?

Could it be that such an "error" was pure politics, and it took a full change in government to get the GAO to issue its report and bring this all to light?

According to the Times article, internal DOE communications were found indicating that key members of DOE management were looking for reasons to kill the project.

As a substitute, the DOE is supporting a number of regional CO2 capture and storage demonstrations, such as the WESTCARB oxy-fuel project in California, but no alternative commercial-scale power project has yet surfaced to replace FutureGen.

This may change soon as the economic stimulus bill just rushed through by the Obama administration and passed by Congress may provide money for the original FutureGen project.

As reported by the Washington Post last week, the bill contains language providing for $1 billion for a "clean coal" research project. Everyone seems to know that this project is FutureGen. President Obama supported the project when he was a senator from Illinois, and new Secretary of Energy Steven Chu "would support it with some modifications" according the the Post.

Chu has been quoted as saying that FutureGen "deserves a fresh look" among potential clean coal projects.

So, stand by IGCC fans.

A year after Matooners awoke to find coal in their stockings, it looks as if a belated Xmas present may be on its way.

Yes, my Illinoisian friends, there is clean-coal Santa Claus in the White House after all!

Don't Forget - Visit www.GTWbooks.com

2009-02-13T22:33:00.004-05:00

Gasification: Redefining Clean Energy

Those of you who are not on the mailing list of the Gasification Technologies Council (GTC) may not have seen their invitation to visit their great website and look at their excellent new video, entitled Gasification: Redefining Clean Energy.

You could either go directly to this link (GTC video) or visit GTC's website www.gasification.org.

I think that you'll find it worth the time.

Also, don't forget to visit Gas Turbine World's website at www.GTWBooks.com

2009-01-25T22:21:00.005-05:00

NETL Video Provides
Basics of Gasification and IGCC

In a departure from our usual objective of using this platform to highlight current issues of interest to the Gasification and IGCC industry, this posting is prepared to help distribute a useful video message prepared by the US Dept. of Energy’s National Energy Technology Laboratory.

The video features Gary Stiegel, Technology Manager, Gasification, at the Office of Coal and Power R&D, in Pittsburgh.

This link will connect you to YouTube.com for access to the informative four-minute presentation and will lead you to additional links to further information on gasification, carbon capture, and other related topics provided by NETL.

We trust that this has been useful in your search for information regarding gasification and IGCC technology.

Gasification Editor
Gas Turbine World Magazine

visit us at www.GTWbooks.com

2008-12-15T16:12:00.035-05:00

Eyes of Texas on IGCC Debate - Again

Once again the opportunity for building a low-emissions IGCC plant on Gulf Coast
is in danger of being missed.

Can polygeneration come to the rescue?

It was only about two years ago when all eyes were on Texas as plans for upwards of 18 new coal plants had environmental groups up in arms.

The pressure was on the utilities to use cleaner IGCC technology, and on the regulators to accept IGCC as "Best Available Control Technology" for all new coal-fired plants - regardless of its higher costs.

That debate over IGCC vs PC technologies went into the history books when TU was bought out by a group of private investors who killed the idea of investing in new generation and made deals instead with IPPs for their surplus, mostly gas-fired, generating capacity.

But now the debate is once again heating up over whether or not IGCC technology should be imposed on a project despite its higher costs.

This time the spotlight is on the 1200 MW Las Brisas Energy Center fueled by high-sulfur petroleum coke slated for construction on the Gulf Coast near Corpus Christi. As currently planned, conventional boiler technology will be used, with stack-gas scrubbers to reduce sulfur and other emissions of the new plant as required by EPA standards.

No provisions are being made for CO2 capture - nor is the plant being required to be "capture ready" in anticipation of pending regulations to curb greenhouse gas emissions.

Once again concerned citizens and others are calling for an IGCC design that would produce much lower emission levels than required by law. As reported by Denise Malan, a journalist for the Caller-Times, gasification is better for the environment than direct burning but adds to the cost of electricity. She points out this is not just a local issue, but one that is shaping the national energy debate.

The question at the heart of the controversy is an old one. It boils down to whether the added cost for IGCC is too much to pay for a cleaner and greener power plant - particularly when the dirtier plant can meet current emissions standards.

The real questions
Taken to the next level, aren't the real questions: a) Is the cost of IGCC really higher when considering all of the long term social, environmental and health costs of the higher emissions generated by directly burning pet coke in a boiler? And, b) Why won't the EPA and state regulators recognize that IGCC is - in fact - the best available control technology for emissions reduction?

Not that the idea of a cleaner pet coke-fueled IGCC plant at Las Brisas has not already been suggested. Tondu Energy had proposed a 600 MW plant at the same site (Tondu IGCC). It was the only one of the 19 proposed coal or pet coke fired plants in Texas that wasn't targeted by environmental protests back in 2006.

As Joe Tondu, president of Tondu Energy, told the Caller-Times “Corpus Christi is a natural location for the application of IGCC, but we were unable to identify a market (for the power) that was willing to pay for an additional costs due to IGCC.” As a result, he says, we are going to build a gas-fired combined cycle plant instead.

It boils down to two issues: 1) should emission standards be stricter? and 2) are consumers willing to pay for the higher cost that comes with cleaner and greener energy?

"If you want gasification", he advises, "go to the state regulators and (get them to) set the emission standards that require IGCC, and boom it will happen."

Clearly, Joe Tondu couldn't hold out for his IGCC project to make it. He threw in the towel in mid-2007 when he announced that he'll take the path of least resistance and go with a natural gas fired plant.

Industrial Polygeneration alive and well
Since gasification per se does make sense for the Gulf Coast, and it could be that the Las Brisas project should revise its business model, and the plant should be redesigned for a different product mix.

At today's $7-$8 per MMBtu price for natural gas, gasification of pet coke to produce synthetic natural gas - with power production as a by-product - seems to have found solid footing at Dow Chemical's massive Freeport (TX) chemicals and cogeneration plant.

The $2.8 billion Hunton Energy Freeport plant, scheduled for completion in 2012 about 180 miles up the coast from Corpus Christi, is touted as a gasification success story.

Hunton plans to gasify petroleum coke to produce methane for sale to the nearby Dow plant, and will also generate a net 400 MW as well as other "process byproducts" including sulfur for fertilizer and carbon dioxide for injection into old oil wells.

The key for IGCC, or more properly, gasification-based polygeneration, is locating the market for the primary product, says Kay Johnson, Hunton Energy Vice President for Project Management.

Johnson told the Caller-Times that gasification plants such as the one in Freeport can only work in certain markets. Such projects are very capital intensive, she explains, which means that project viability depends on the profit you’re trying to make as well as the market conditions.

But it’s not impossible, at least in Freeport. The key was putting together the right combination of technologies in the "perfect location", Johnson says. Hunton is "very proud of the fact that we’re making 400 MW of power with no emissions,” she said. “It proves that you can be green and profitable.”

Which brings us back to Las Brisas. Perhaps they should be compelled to develop a different business model, more like what Hunton Energy adopted at Freeport. If they cannot be moved by tighter environmental standards to use IGCC technology, perhaps the key is to change its primary product, and make electric power a "byproduct" of a more profitable operation.

There should be compelling incentives for project developers to adopt polygeneration in their plant concept - the same way that cogenerators used to be favored under past energy legislation.

If Hunton Energy can profitably produce 400 MW without emissions by making its profit from selling pipeline quality gas to local industry, why can't the developers of the Las Brisas plant do the same?

No doubt the local refineries that are supplying them with pet coke would be good customers for hydrogen, steam and other plant products that could make the overall operation more profitable - and a lot greener.

And, by going with gasification to convert the pet coke into a clean fuel gas, they can more readily incorporate CO2 capture into their plant design. Then, like Hunton, they can then add compressed CO2 to their products for sale -- and and tack on another profit stream.

Don't forget - visit Gas Turbine World at www.GTWbooks.com

2008-08-10T15:53:00.013-04:00

IGCC - "A Promising Technology" for Future Coal Power Plants

The following link appeared on my radar screen recently. Even though the article was published by a competitor, I felt that it merits repetition here just in case it didn't come to you via your own Google Alert, or whatever system you use to bring such items regarding Gasification and IGCC news to your attention.

Link: Coal Gasification - A promising technology

In case you would rather read the article by Kentucky chemical engineering consultant John Colebrook right here, I'm providing you with a copy. It comes with proper credit to author and publisher, but sans advertisement.

Let me know what you thought of it. Although, in my opinion, it doesn't give adequate credit to IGCC as being a commercially proven technology, it does highlight the important benefits of gasification when it comes to resolving permitting issues for new coal-fired power plants.

Posted by:

Harry Jaeger
Gasification Editor
Gas Turbine World Magazine

Don't forget to visit www.GTWBooks.com

Support for IGCC is resolving permitting challenges and enhancing performance.

Electric Light & Power July, 2008
Author: John Colebrook

In 2007, more than 50 percent of the electricity in the U.S. was generated from coal-fired power plants, and according to estimates by the Energy Information Administration, coal-based power generation will continue to be the largest single source of the nation's electricity production through 2030 and beyond. Coal gasification is considered an emerging technology that could replace many of the aging conventional pulverized coal boilers currently used to supply the majority of coal-based electricity in the U.S.

Utility companies, however, have been reluctant to make gasification a major component of their generation portfolios due to high capital costs and the lack of large-scale commercial applications. In an effort to resolve the most pressing challenges preventing the widespread implementation of integrated gasification combined cycle technology (IGCC), the U.S. government, mainly through the Department of Energy, has supported research and development efforts focused on advanced gasification technologies to improve the efficiency and environmental performance of IGCC plants while reducing capital costs.

The current state of IGCC technology already offers significant reductions in emissions of the major criteria air pollutants—nitrogen oxides, sulfur dioxide, particulate matter and carbon monoxide—when compared to pulverized coal plants (see sidebar and chart) but the DOE program seeks to achieve near-zero emissions of these pollutants by 2020 and to simultaneously develop carbon dioxide sequestration technologies that can be readily commercialized.

Click here to enlarge image

The IGCC process. Source: National Energy Technology Laboratory

In a July 2006 EPA report comparing the environmental impacts and capital costs associated with IGCC to pulverized coal technologies, EPA joined the DOE in endorsing IGCC technology, stating "the EPA considers IGCC as one of the most promising technologies in reducing the environmental consequences of generating electricity from coal."

IGCC air permitting challenges

With only two commercialized IGCC facilities in operation (Wabash River, ConocoPhillips E-gas gasifiers, and Polk Station, GE Energy gasifiers) and only a few next-generation high-availability multi-train facilities that have recently received air permits, the air permitting arena for IGCC technology is relatively undeveloped.

However, the DOE's National Energy Technology Laboratory (NETL) identifies more than 30 IGCC projects as of October 2007 that are in various phases of development or that have recently been announced. Consequently, the quantity of air permit applications and air permits available for consideration and comparison when developing the required components of a New Source Review (NSR) permit application for a new IGCC plant is rapidly expanding. (Tracking New Coal Fired Power Plants, Office of Systems Analyses and Planning, DOE National Energy Technology Laboratory, Oct. 10, 2007.)

Further, despite the limited air permitting history for IGCC technology, several key challenges have been identified in the permitting process for a new IGCC plant.

Balancing the pressure to submit air permit applications early in the project against the need to obtain a representative permit on the first submittal of the application. Since state and federal approval processes for IGCC plants can span years, and the participation of environmental groups, the general public and federal land managers in the air permitting process is common in the coal-fired power generation industry, the typical strategy is to submit an air permit application very early in the design process. However, significant design changes after the submittal of an air permit application can lead to multiple revisions of the permit application, the reopening of public comment periods, and substantial delays in obtaining a complete and representative air permit for such a large-scale industrial facility. Successfully striking a balance between securing a timely air permit and ensuring the air permit is representative can alleviate much of the friction between the developer, regulatory agencies, and other interested stakeholders.

Ensuring that the appropriate basis is used for establishing emission limits. The Energy Policy Act of 2005 and New Source Performance Standards (NSPS) Subpart Da require that IGCC emission limits are established on either a power output basis, or a combustion turbine heat input basis. One of these two methodologies needs to be utilized when determining project emission rates and establishing emission limitations; the gasifier heat input should not be used as the basis for emissions calculations.

Representing accurate estimates for the frequency, duration, process flows, and emissions for each type of startup, shutdown, and maintenance (SSM) event in the permit application. Due to gasifier maintenance and the tendency for process upsets, SSM events for IGCC plants are relatively frequent and are often subject to explicit emission limitations in air permits. Therefore, it is important to represent accurate estimates for the frequency, duration, process flows, and emissions for each type of SSM event in the permit application so that acceptable permit limits can be established and accurate air dispersion modeling impacts can be predicted.

Accurately characterizing unique emission sources that require careful consideration in BACT evaluations. Several unique emission sources are associated with IGCC processes that require careful consideration in BACT evaluations under the Prevention of Significant Deterioration (PSD) program. For example, flares can be used during startups, shutdowns, and upsets to combust pure or mixed streams of raw syngas, sweet gas and various other process streams. With such varied inlet exhaust conditions, sources should estimate flare emissions under all scenarios prior to establishing BACT limits to ensure that continuous compliance is attainable. The composition of the vent streams from the acid gas removal system and sulfur recovery unit are often a function of the technology supplier, so selection of a vendor and establishing design specifications is a prerequisite for evaluating BACT for these sources.

Assessing the applicability of Maximum Achievable Control Technology (MACT) standards for Hazardous Air Pollutant (HAP) emissions. Emissions of hazardous air pollutants (HAP) from the acid gas recovery system and combustion by-products at IGCC plants can be above major source thresholds, requiring implementation of MACT for HAP emissions. While certain emission units at IGCC facilities fit into affected MACT source categories under 40 CFR Part 63, the provisions of 40 CFR Part 63 Subpart B can apply to sources not covered by an existing source category. A case-by-case MACT analysis for a new major source must establish an emission limitation that is achieved in practice by the "best-controlled" similar source. Determining the best-controlled similar source for IGCC processes can require technology reviews in a variety of similar industries and can lead to new control installations and increased monitoring, recordkeeping and reporting requirements.

Click here to enlarge image

An increasingly complex regulatory environment for conventional coal-fired power plants bodes well for the future of IGCC technology. IGCC has distinct advantages over conventional coal-fired power plants because of its fuel flexibility and capacity for producing high levels of CO2 capture and sequestration. As with the commercialization of any new type of industrial facility, regulatory challenges will certainly play a key role in the development and implementation process of IGCC technology.

Author

John Colebrook is an air quality consultant for Trinity Consultants, based in the northern Kentucky office, where he helps clients in various industrial sectors successfully navigate the complexities of air quality permitting. Colebrook, a chemical engineer, is in the process of becoming a registered professional engineer to serve clients in Kentucky, Indiana, and Ohio.

A Detailed Look at Emissions from IGCC

In the gasification process, carbon-based feedstocks such as coal, petcoke, biomass or heavy oil residue are converted to synthesis gas, or "syngas," a mixture of primarily carbon monoxide and hydrogen with smaller amounts of CO2, methane and water. Combined with steam and either air or nearly pure oxygen from a cryogenic air separation unit, the preprocessed coal undergoes exothermic gasification reactions in the refractory-lined pressurized gasifier.

With a reduced chemical environment in the gasifier, sulfur compounds in the feedstocks are converted primarily to hydrogen sulfide with smaller amounts of carbonyl sulfide. Nitrogen bound to carbon is liberated primarily as gaseous nitrogen with smaller amounts of ammonia and hydrogen cyanide, and chlorides are converted primarily to gaseous hydrogen chloride. Depending on the gasification technology, ash or slag is recovered from the bottom of the gasifier and can be landfilled or sold.

Syngas leaving the overhead of the gasifier is routed to a filtering and cooling process. High temperature filters and cyclones remove entrained particulate matter while scrubbing systems remove chlorides and ammonia. The cooled raw syngas is then routed to an acid gas removal process where a physical absorption system using an organic solvent separates the raw syngas into a hydrogen sulfide-laden acid-gas stream and a sweetened syngas stream ready for combustion in gas turbines. The acid gas is routed to a sulfur recovery unit that produces salable sulfuric acid or elemental sulfur from the hydrogen sulfide in the acid gas stream.

The acid gas removal system can also produce a nearly pure sequestration-ready CO2 stream. The gas turbines, heat recovery steam generators and steam turbines generate power in the conventional combined cycle arrangement.

The acid gas removal system/sulfur recovery unit is capable of achieving lower SO2 emissions than flue gas desulfurization units at supercritical pulverized coal (PC) plants. Removing particulate matter in the syngas using high temperature filters or cyclones and/or wet scrubbing systems can achieve greater reductions than the use of electrostatic precipitators or baghouses downstream of the boilers at PC plants. Finally, IGCC and PC plants both use activated carbon absorption for mercury removal to achieve comparable emissions rates.

By separating elemental nitrogen from the coal during the gasification process and combining the syngas with diluents prior to combustion in the gas turbine, NOx emissions can be reduced to levels below those achieved at PC plants utilizing low NOx burners and selective catalytic reduction.

Electric Light & Power July, 2008
Author(s) : John Colebrook

2008-02-08T10:04:00.003-05:00

NPR's "On Point" - Way Off Base on View of FutureGen IGCC

If you have a few minutes to spare and still have the stomach for more misinformation on FutureGen, you should tune in to hear the Feb. 7 NPR broadcast of "On Point" which focuses on the DOE "Pulling the Plug on FutureGen".

As one in the know commented about it, "it is incredulous to see how those sound bite spinners could cause such devastation for their own good". It is really something to behold if you could take it.

You could find the "On Point" posting at:
http://www.onpointradio.org/shows/2008/02/20080207_a_main.asp

Or you could launch the broadcast itself at the following by inserting at NPR on FutureGen.

You might also want to look at the WSJ Energy blog coming out of DC at:

http://blogs.wsj.com/environmentalcapital/environmentalcapital@wsj.com

It is amazing how the WSJ energy "expert" totally ignores the fact that the IGCC portion of FutureGen was to be based on available technology. He makes it sound as if making clean gas from coal was still to be proven, and portrays the entire project, including the gasification block, as an R&D experiment in urgent need of Federal support to save the planet.

The other "expert guests" on the broadcast, including MIT's Professor Herzog, aren't much better in the way that they let themselves be used by the NPR reporter to misinform and whip up the public.

Let's hope that some real IGCC projects come along to get a share of the funds that the DOE still intends to put out for the CO2 capture and sequestration part of FutureGen. Maybe it will happen even sooner than the new FutureGen target of 2015.

It should certainly prove to be an interesting summer for DOE watchers, especially with FutureGen now becoming a political football.

Harry Jaeger

Gasification Editor

Gas Turbine World Magazine

visit www.GTWBooks.com

2007-12-23T09:36:00.001-05:00

DOE: The Grinch that stole IGCC Xmas

‘Twas the week before Xmas, and all through the nation
The IGCC world joined Mattoon's great celebration.

For the FutureGen Alliance had picked this central Illinois site
To the chagrin of the Texans who still promised to fight.

Mattoon, now known better for bagels than for its coal,
Was touted as ideal for meeting FutureGen’s “near-zero” goal.

It was picked for its coal feedstock and fine geological accommodation
For advanced IGCC with greenhouse gas sequestration.

All were aglee that the project was on schedule.
For the Alliance had promised the site would be known by the Yule.

But alas! From DC there came an unwelcome clatter.
It seemed that the DOE was rethinking the whole matter

Within hours of news that brought Mattoon so much cheer,
DOE proclaimed: “FutureGen costs too much, we fear”.

With costs rocketing clear out of control
DOE called for “project redesign”, perhaps a new goal?

But have you not read Gas Turbine World, we say?
If not, pick up your copy of the Sep/Oct issue today.

For ultra-clean coal there’s the "40% Solution"
For affordable capture of CO2 pollution.

IGCC with coal could be as clean as gas, I warn ya.
The plant would even be allowed in picky California.

Or should DOE look to Peabody Coal for a clue?
Why not join China’s GreenGen? Let them do that for us too.

If history serves us, they will toe the line.
You can bet they won't waiver; undoubtely break ground in '09.

And the Aussies have their ZeroGen, is it any wonder,
They too have a plan to get it done down under?

And then there is Hatfield for CCS in the UK.
They say this time it’s for real, and that the Russians will pay.

Meanwhile, back home in the US of A,
A few good projects are making their way.

There’s still Edwardsport, Cash Creek, and Eastman Beaumont
Hunton has its Dow, and Mesaba, not yet down for the count.

But FutureGen, Oh FutureGen, where will you go?
Let’s hope that DOE / Alliance deliberations are not too slow.

But while the FutureGen leaders consider its plight,
A Merry Christmas to All, and to all a Good Night.

www.GTWBooks.com

2007-10-30T21:30:00.005-04:00

Natural Gas Equivalence
- the 50% solution for IGCC

It's been two weeks since the 2007 Gasification Technologies Council conference in San Francisco and I am still trying to put a positive spin on what I saw and heard there.

In contrast to the optimistic environment at the past few GTC conferences, the mood this time was clearly more somber, and uncertain.

Impressions that stand out for me are that CO2 has become an “all consuming” issue, we are back to “all talk and no action” for IGCC in the United States, China is where it’s at for the world of gasification, and natural gas fired combined cycle will reign as the bridge technology for power generation while waiting on FutureGen to show the way forward.

Apparently Reuters picked up on the last message with its Oct 22 headline declaring that: “US Gasification Hopes Rest on One Project”. (Reuters 10-22-07)

A scary proposition
To me, that is a scary proposition. I support FutureGen as an R&D platform for the demonstration of advanced gasification with full CO2 capture, and for development of future technologies. My worry is that the project's “near-zero emissions” goal will make it too expensive to build and operate, much less lead the way to the future.

Saying that US gasification hopes rests on FutureGen is not at all reassuring. Granted, the project has political value to show that the US is doing its bit for GHG abatement from coal-based power generation. And it will provide a useful proving ground for worthwhile technologies such as ITM oxygen and the advanced hydrogen-fueled gas turbine being funded by DOE/NETL.

But something else is needed to give more hope to near-term commercial deployment of IGCC . Not only is near-zero emissions commercially impractical – with its penalty of adding nearly 50% to the capital cost and about 40% to the cost of electricity – but it is not needed if the objective is to achieve a low CO2 footprint.

Why not natural-gas equivalence?
Would it not make more sense to limit CO2 emissions for coal-based IGCC to no more than a level of 1100 lb per MWh, which is currently the “power generation standard” that has been set by high efficiency natural-gas fired gas turbines??

The CO2 emissions for coal-based IGCC without capture is about 1800 lb per MWh. This would allow natural gas equivalence to be achieved with less than 50% CO2 capture – a far cry from the 90% capture level specified for FutureGen and currently defining the “with capture” cases in most design studies that we’ve seen.

And CO2 equivalence with a modern high-efficiency natural-gas-fired combined cycle (NGCC) plant, which emits around 850 lb/MWh CO2, can be achieved with a about 55% capture.

Setting a 50-55% capture goal for CO2 is within the reach of current technology and can be achieved for only a fraction of the cost and energy impact. Depending on the gasification process, this may require only a secondary acid gas removal (AGR) unit, and, at most, one stage of water-gas shift reaction (not the two stages, with intercooling, required for 90% capture).

True, this would also make it easier and cheaper to build “compliant” PC plants with carbon capture, but even if this means breaking even with respect to cost of electricity (COE), it would put the focus back on criteria (regulated) emissions, where IGCC outperforms by a mile - and where it belongs.

NGCC - the easy alternative to clean coal
Natural gas fired combined cycles, which produce about half the CO2 of coal plants, are expected to see a global surge in market demand to make up for all of the coal projects being shelved.

Right now, the regulated CO2 capture rate for new coal plants in Japan (“Japan rule”) is set at 45% to match the natural gas emissions rate. California, Florida, Washington and most of Europe have also set natural gas as the as the clean power benchmark for all new generation.

Under the circumstances, it seems reasonable to apply NGCC-equivalence with respect to CO2 footprint as an operational and design target for near-term commercial IGCC with carbon capture.

According to a report by Worley Parsons and ConocoPhillips, presented at the GTC conference, this would cut the capital cost ($/KW) impact for CO2 capture by two-thirds, and the impact on heat rate by three quarters.

As one industry expert put it at the conference (paraphrasing an anonymous poet): “Natural gas is the easy path, but easy paths don’t lead to the future.”

Syngas may end up the winner
Meanwhile, the gas turbine industry is preparing for a very welcome resurgence of NGCC market demand that will inevitably follow as the “rush to coal” hits a regulatory brick wall.

We are already seeing clear signs of this beginning – both in the US and in Europe.

In the long run, gasification suppliers should also welcome this scenario since the expanding fleet of gas-fired power generation will ultimately support a growth in gasification-based SNG production when natural gas and LNG supplies begin to run out.

The almost certain price impact of increasing dependence on imported LNG in the US will go far to creating a solid market for syngas.

With world pricing of around $80 to $90/bbl for crude (about $15/MMBtu), LNG could be expected to set the marginal price of clean “natural gas” at high enough levels to attract new supplies of pipeline quality gas.

No wonder that one gasification technology supplier told the GTC conference that “we love SNG – the customers are already on the ground”. So are the pipelines, and the technology for CO2 capture and storage.

And as another gasifier supplier put it: “Power is still the biggest potential for gasification. Perhaps SNG on its own makes more sense than IGCC.”

What do you think?

Gasification Editor
Gas Turbine World Magazine

2007-07-06T11:20:00.001-04:00

WHAT'S SO HOT (OR NOT) ABOUT CHILLED AMMONIA FOR CO2 CAPTURE?

Our recent article on “What it takes to equip IGCC and PC plants for CO2 capture and storage” (Gas Turbine World, Mar-Apr 2007), attracted an intriguing, if not disturbing, comment that we want to share with our web-based readership in the Gasification & IGCC community.

In preparing the article we took special care to give fair coverage to improved technologies being developed to reduce the almost prohibitive cost and performance impact of post-combustion capture of CO2 from the exhaust of conventional coal plants.

One that seems to hold the most promise, and which is getting at lot of attention, is the so-called “chilled ammonia” process technology.

The PC sector of the industry is touting chilled ammonia as the saving technology development that will preserve the viability of coal-burning steam plants in a carbon-restrained world.

Based on available information from supplier releases and from EPRI, which is supporting a 5-year multi-phase development program, and has helped organize a 16-member group of utilities to help finance it (link to EPRI on CAP), our article includes such positive and optimistic statements as:

The chilled ammonia process is said to dramatically reduce the energy required to capture CO2 at a far lower cost (compared to current commercial amine-solvent technology).

Compared with amines, chilled ammonium carbonate is said to have over twice the CO2 loading capacity and requires less than half the heat for solvent regeneration.

In laboratory testing sponsored by EPRI and others, the chilled ammonium process has demonstrated the potential to capture over 90% of CO2.

In fact, early test data would seem to indicate that chilled ammonia could reduce the impact of post-combustion CO2 capture on levelized cost of electricity (COE) by more than half – perhaps by as much as two-thirds!

Where’s the catch?
So far so good.

Good news on such promising technology developments is always welcome and to be followed with anticipation – especially when it is being used to promote the advantages of “advanced PC plants” over IGCC technology.

But there is a catch.

One of the comments that we received to our article claims that none of this hype about chilled ammonia is true.

It goes on to say that a detailed study carried out by DOE/NETL on chilled ammonia scrubbers for post-combustion CO2 concludes, essentially, that the new technology offers no advantage over currently available amine-based absorption systems in terms of cost or performance.

Although, as claimed by its proponents, chilled ammonia pound-for-pound can absorb substantially more CO2 than amine solvents, the cost and energy penalties associated with the refrigerated process appear to be so high as to negate and overwhelm any such advantage.

Show me the data
Let’s assume these claims have some substance. If such a report was in fact prepared, how is it that it didn’t surface during the research for our article?

Normally, a simple "Google search" would have brought any such NETL report to the top of the list.

As it turns out, the report and its data are still waiting to see the light of day.

The comment that we received indicates that release of the report, which was completed early this year, is being held up pending “management approval”.

The official reason for the hold-up, apparently, is industry objection to proprietary content, which is still in the process of being removed before public release.

But should this be taking 6-7 months, or more? Will the report ever be fully released?

False hope or purposeful smokescreen?
Could it be that the utility industry has inadvertently been putting its bets, and hopes, on a technology with little promise for improvement?

Such placement of false hopes in light of the overwhelming numbers against PC plants with CO2 capture, and the growing success of intervenors, might be understandable but is still questionable, at best.

Or could it be that the parade of utility execs and “expert witnesses” giving testimony for continued construction of PC plants, and for delaying rules on limiting CO2 emissions, have been using the great promise of chilled-ammonia removal as a veil?

Has it been part an industry attempt to fend off the growing resistance to the continued building of conventional coal plants in the face of pressure to lower emissions of greenhouse gases – and to consider IGCC technology as a better alternative?

I leave this for you to ponder and explore. Let us know what you find out pro or con. We think that it is important.

Gasification Editor
Gas Turbine World Magazine
www.GTWBooks.com

2007-05-09T22:51:00.003-04:00

Kerry proposal would ban conventional PC plants and
require CO2 capture and storage

Should this be viewed as pro-IGCC or just another attempt to slow the coal rush?

By late April, legislative activity in Washington related to limitations on greenhouse gases has reached fever pitch. Congressional hearings are being held almost continuously, and it seems that everyone is coming up with a proposal for some form of regulation.

It already seems that a cap-and-trade system for CO2 is inevitable, but legislators are still groping as to how it would work.

Now a growing sense of urgency about climate change is pushing legislators to propose some pretty bold initiatives.

One case in point: a bill, The Clean Coal Act of 2007, introduced last week by Sen. John Kerry (D-Mass.).

Kerry's bill would go so far as placing an immediate ban the building of any new coal plants unless they included provisions for capturing and sequestering CO2 emissions.

To quote our almost president: "This bill is our No. 1 solution to global warming. Unless we can build clean power plants, we should not be building them at all.”

Kerry's proposal is actually an amendment to the Clean Air Act, and would establish a New Source Performance Standard for CO2 emissions for all new coal-fired power plants.

When introducing the bill, Kerry, now the chairman of the Senate subcommittee on Science, Technology and Innovation, made the point that the utility industry is desperately looking for "certainty regarding mandatory greenhouse gas standards" so that planning for new plants can move forward.

He also said that there is need for a uniform national standard as opposed to a patchwork of standards being adopted by a growing number of states.

Some see it as a ban of new coal plants. But if there are to be any new plants built, whether they be gasification-based or PC-based, the proposed requirment is that CO2 emssions be limited to 285 lb/MWh.

Since the typical conventional PC plant emits close to a ton per MWh, this requirement translates to a capture rate of about 85%.

As one industry insider close to the DC scene observed, "this might be viewed by some as favoring IGCC. But even if IGCC offers the low-cost means of meeting the proposed CCS requirements, it may put coal-based power - whether gasification- or PC-based - out of reach.

"Who's going to pay for it?" he asks.

Others are saying that a requirement to include CCS "would kill coal. The only thing that might get built is a natural gas plant", they say.

"Experts" say technology is not here yet
Does the Kerry proposal have a chance of surviving the debate?

Or is it just too far-reaching at this stage of the fledgling US commitment to join the world community in the mission to slow global climate change?

Given the current politically charged situation in Congress, almost anything that would show how the Bush administration has avoided this major environmental issues is possible. But with nearly 200 proposed coal-based power projects in the US affected, and the very growth of the coal industry and the ability to meet future power demands at stake, any serious attempts to bring this bill to a vote will face steep opposition.

For one thing Congress has been hearing a stream of expert comment on how the technology needed to achieve Sen. Kerry's objectives still needs to be demonstrated - and is at least 10 to 15 years away from being commercially available.

Maybe I'm naive. But what baffles me is how all of these "experts" want to ignore what has been going on at the Dakota Gasification operation in North Dakota for almost 7 years now.

Not only are they capturing and sequestering CO2, but they are making money at it - and that is without any kind of trading scheme in effect.

A Google search (CO2 for Sale) would tell them that the equivalent CO2 emissions from a 400 MW power plant is being stripped from syngas used to produce SNG, compressed and piped some 200 miles north into Canada where it is forced deep underground to enhance oil production at an old oil field in Saskatchewan.

The hope is that our Senators and Congressmen can see through this testimony that would have them ignore the facts. They need to be aware that CCS has already been shown in full scale to be technically and commercially sound.

They need to get on with the business of passing a law that would give the utility industry a clear national policy and a path to follow in moving foward.

Others want even quicker action
It will be interesting to see how the power and coal industries come down on Sen. Kerry's proposal, or even if it ever sees the light of day. Meanwhile, others are calling for even quicker and more severe action.

Sen. Barbara Boxer (D-Calif.) suggested that the country should be launching a “Manhattan Project”-type initiative on carbon sequestration. She said that the estimate of 12-15 years for the use of CCS to be widespread is far too long.

"More than 20 percent of carbon dioxide emissions come from coal plants. Advanced cleaner coal can help us solve this great threat that is facing us," she said.

"The most disturbing thing is what could happen if we don't respond to this. We are the Saudi Arabia of coal and if we could figure this out, we'll be well on our way to energy independence in a responsible way."

Sen. Byron Dorgan (D-N.D.), Chairman of the Senate Energy and Natural Resources committee joined Boxer and Kerry in their concern over the lack of urgency in the U.S. on reducing CO2 emissions.

“I hope to move as aggressively as we can persuade Congress to do so” on promoting CCS technology, he said.

Sen. Craig Thomas (R-Wyo) joined committee members calling for quicker deployment of CCS, criticizing an on-going DOE study. “Sometimes we get so caught up in research…….we know how to do this,” he said.

To punctuate the message, Joseph Chaisson, a director of the Clean Air Task Force (CATF), an environmental advocacy group told one Senate committee that the U.S. must act to commercially deploy IGCC technology as soon as possible.

He put forth the CATF action plan for a sound national coal policy as follows:

* Ban the construction of conventional new coal burning power plants.
* Rapidly commercialize the use of IGCC for power generation to benefit from its reduced environmental footprint.
* Urgently demonstrate large-scale geologic storage of CO2, and then require all new plants to include at least 90% carbon capture and sequestration.
* Demonstrate and deploy advancements such as underground coal gasification to further shrink IGCC’s environmental footprint.
* Reform coal mining practices worldwide, imposing effective U.S. regulation of coal plant solid waste disposal.
* Reduce water use and associated impacts of coal mining and coal-based generation to the minimum practical levels.
* Increase the efficiency of IGCC to the maximum practical levels over time.

Chaisson emphasized that IGCC is seen as the key enabling technology for carbon capture and storage.

He said that “while it is possible to retrofit a coal combustion plant with carbon capture technology, it would cost twice as much as capturing carbon from an IGCC plant”.

In either case, there is a very high price to pay in terms of loss of plant thermal efficiency – with the heat rate of a PC plant increasing by some 30-40 percent, and that of an IGCC plant by 20-30 percent.

Based on current technology, said Chaisson, “IGCC power generation is likely to be the most availing path forward If we are to turn the world coal tide to a near-zero carbon footprint in the next 20 years.”

Is cap-and-trade the key?
Regardless of the fate of Sen. Kerry's Clean Coal Act, those close to the scene in DC are saying that a mandatory cap-and-trade regulatory system for regulating greenhouse gases in the general economy seems to be inevitable.

Such a system would set a ceiling on emissions and grant credits to companies that take measures to lower emissions. These credits could be traded (sold) to companies with higher emissions.

In theory, this could be what enables a proposal such as Sen. Kerry's work. If the value of CO2 credits are high enough, they might provide enough incentive for plant developers to include the necessary provisions for CCS.

Some pretty serious players are already lining up to cash in on it. Example: AES and GE joining with a plan to trade "disposal" of methane - which has 20 times the greenhouse effect of CO2 - for emissions of CO2.

An alternative would be a "carbon tax", where the government would set up a trust fund to support investment to reduce emissions.

Energy-related committees in both houses have been holding hearings focused on the pros and cons – and potential pitfalls – of legislating a cutback in CO2 emissions.

Spokesmen from Europe have appeared at hearings to describe how the EU's 2 year-old system has been working (or not working) there.

As for the EPA, and its role in all of this, Stephen Johnson, EPA Administrator, told one of the Senate committees that the Supreme Court ruling was limited to vehicular emissions of CO2, and that a separate determination would have to be made as to whether or not such emissions from stationary sources were to be included in any new standards.

If that were to be the case, he said, one of the remedies available to the EPA would be to set up a cap-and-trade system.

Congressional Budget Office warns of doom and gloom
The Congressional Budget Office (CBO) released a report that focused on how a cap-and-trade scheme to limit CO2 emissions would come at the cost of greatly inflated prices for electricity and other forms of energy.

That should not be surprising, given the substantial impact of CO2 capture on power plant cost and efficiency that has been seen in so many recent studies. (See article in this issue of GTW.)

Additionally, the CBO report warns that any attempt to limit CO2 emissions would cause higher operating costs across the economy and result in job losses. It suggests that the negative impacts would particular hurt the poor.

Predictably, critics of proposed regulations and climate-change skeptics were quick to embrace the CBO report. One ranking Republican senator called the report a “devastating indictment.” He said that CO2 cap-and-trade schemes are doomed to “utter failure”

Back to reality - utility chooses “capture-ready” SPC approach
Roberto Denis, a senior VP of Nevada’s Sierra Pacific Resources, told one Senate committee that in spite of all the new focus on limiting CO2 emissions, and increased efforts to develop renewable energy, his company still needs to build the 2,500 MW Ely Energy Center, which will use super-critical PC technology.

He explained that company engineers and planners decided against IGCC, as it was not shown to be economical when using high moisture, western coal.

He said Sierra Pacific fully supports the conclusions of the MIT “Future of Coal” study that: “new coal units must utilize the best commercially available technologies and must be built to accommodate retrofits when new large scale carbon capture and sequestration (CCS) technologies are demonstrated feasible.”

“The new Ely coal complex will do just that. The first two units are being designed so that when CCS is available we will have a physical facility that can be retrofitted to enable us to capture the CO2 and identified the land for a CO2 storage site.”

According to the MIT report, such a retrofit (without cost of storage) could cost the utility (ratepayers?) upwards of 60 percent of the original plant cost!

Who said that this Mission to Save the Planet was going to come cheap??
|

2007-04-16T23:13:00.001-04:00

Friday the 13th for IGCC....................

Bad news. Just four short months ago in mid-December we were celebrating an early Xmas present for Excelsior Energy.

At that time the US Senate had just passed a correction to the tax credit provisions of EPAct 2005 to cover IGCC projects using low-sulfur coal. Many of us hailed this as a significant ruling that was bound to help “keep the Mesaba Energy Project on track” for approval and financing.

(See that earlier posting at: Gasification & IGCC Forum ).

Fast forward to Friday, April 13th. The morning news from Minneapolis on Friday the 13th was all about a bad luck story for the Mesaba Energy Project.

The first headline that I saw read: “Coal-to-gas plant dealt a setback”. It was followed by news to the effect that “The Mesaba Energy Project could be one unfavorable ruling away from ruin”.

Another headline read: “Hopes for energy project dim” ( Hopes Dim)

The long-awaited decision of the two Administrative Law Judges (ALJ) charged with making a recommendation to the Minnesota PUC on the merits project was out – and it wasn’t good news for supporters of the Mesaba Energy project nor, for that matter, for anyone interested in seeing IGCC technology make some headway and succeed.

The question and the answer
The question before the ALJ was whether or not a proposed PPA between the Mesaba Energy Project and Xcel would likely to be in the public interest.

The answer: No. The judges ruled that the IGCC project failed to meet criteria for a “least-cost resource" when compared to Xcel’s supposed plan for buying more wind power, and gas-fired power from Canada.

Further, they concluded that the project was unnecessary and would cause a significant increase in Xcel customers' electric bills.

Even more significantly, in their opinion, they found that the project failed to meet the criteria of “an innovative energy project,” in accordance with a 2003 law meant to kick-start development of an IGCC power plant in Minnesota.

Based on the air-permit filing for the project, they said that it failed to demonstrate significant environmental advantage over other types of plants - this in the face of promises by Xcel for future CO2 capture and sequestration!

Recommendation to deny project
The ALJ’s recommendation to the PUC — which has the final say — is to deny the proposed PPA, or amend it to address numerous deficiencies.

Excelsior co-CEO Tom Micheletti said that the judges seemed to have ignored most of Excelsior’s testimony, and that of a host of national energy experts who testified in support of the project.

The ruling "flies in the face of everything that’s being discussed about the need to do something about global warming,” he said. “Either they totally ignored our evidence or they just didn’t read it.”

“It was as if we introduced the most obnoxious kind of project you could ever imagine, rather than introducing the cleanest coal plant in the world”, he was quoted as saying in one of the local news articles.

The lesson for all us is that this ruling shows what can happen to any “good project” when it runs into strong grassroots local and legalistic opposition that appeals to emotions and courtroom shenanigans to confuse and obfuscate the technical issues to sway the final decision.

We have been following this case closely. At times it did appear that the developers were over-reaching in what they promised and in their highly political approach. Yet, perhaps they didn't reach far enough with the technology, and what could have been achieved in terms of plant emissions.

To me it is totally incomprehensible that the judges ruled against IGCC as not being sufficiently innovative.

For those of you who are interested in the details, the ALJ's report can be found in its entirety at: ALJ Report

What's next?
Excelsior now has about 20 days in which to submit comment to the PUC in rebuttal to the ALJ's recommendation.

The PUC will hold its own hearings, and a final decision is expected to be issued during this summer.

Project supporters are hoping that the PUC, with its greater experience with energy issues, will see through the sham created by project opponents.

Both sides of the debate noted that the ruling could have far-reaching effects on other IGCC projects. Mesaba is seen as a lead project, with a lot going for it – both financially and politically.

Someone very close to the situation offered this bitter commentary when the ALJ decision hit the newswires:

“Not a good day for gasification. The ALJ detailed review was extremely lopsided, with lots of citations of Xcel and Minnesota Power documents, even generic EIA docs. Yet it ignored the thousands of pages of testimony and reference filed by Excelsior.

“The ALJ apparently couldn't distinguish between what IGCC can do now and what ultra supercritical PC might be able to do someday.

“The battle continues. The unfortunate thing is that this ruling, right or woefully wrong, is going to show up in every other PUC filing by every conventional coal project.”

Excelsior issued a formal statement expressing similar frustration and disappointment over the ALJ hearing procedures. Excelsior Statement

If you just want to read its conclusion, I have copied it here for you:
A national energy policy consensus is emerging that the rapid market adoption of IGCC technology is the most critical measure we can take to stabilize greenhouse gases and avoid dependence on foreign fuel for power generation.

The Mesaba Project provides an opportunity for Minnesota to continue leading the nation towards practical solutions to the difficult issues surrounding climate change and power generation.

Will the Minnesota PUC agree, or will they agree with the claim that the state’s ratepayers can’t afford the cost having the cleanest form of coal-based power?

Carol Overland, the lead lawyer representing local interests opposing the project observed that the PUC typically follows the ALJ’s decisions except for “politically charged issues” or, in many cases, against Xcel Energy.

With many area legislators and businessmen backing the Mesaba Energy Project, the PUC’s hearing should be interesting, she said.

Indeed, everyone will be watching.

2007-02-28T08:11:00.002-05:00

Will the TXU black frog
change into a green prince?

With 85% debt in business structure - Prince might really be a Pauper

It is hard to believe.

It has become national headline news, and everybody is talking about it.

Out of the blue, new “white hat” owners are promising to turn the “wicked” TXU into a defender of the environment.

And they are willing to put up $45 billion* to make it happen, possibly more if forced to fend off other would-be missionary "investors".

Texas shootout turns into a sellout
We started out a few months ago comparing local opposition to TXU’s plan for 11 new coal plants as a good old fashioned Texas Shoot Out. That never happened.

Well the tall cowboys on white horses have just rode into town.

So now, instead, we have the makings of a private deal made behind closed doors with the connivance of two national environmental groups to pull an end-run around pending legislative obstacles that promised to stop TXU dead in its tracks, and effectively put any further environmental objections out of play.

Sounds like a good deal for everyone concerned. TXU shareholders are getting a big wad of cash, and it seems that the old management may be left in place – at least for the time being - to keep the place running. Customers are even being promised better reliability – and lower rates to boot.

In exchange for conceding to cancel 8 of the 11 proposed coal plants that are not needed and not likely to be approved anyway, the new owners get to mute environmental outcry over the three plants that happen to fit their new business model.

(*With a total of $37 billion in debt, as well as a $1 billion "equity bridge" – almost 85% of the “buyout” price – it is doubtful that the pro forma shows any new construction at all - let alone having enough petty cash draw to run the place. Customers will have to pay for whatever the new TXU can get others to build and operate under power purchase agreements.)

Let's play charades
The environmentalist participation in this deal strikes me as a bit of a charade – a play being put on for the benefit of supporting members –already being advertised as a “mission accomplished” by the likes of the NRDC (see, for example, http://www.energycentral.com/centers/news/daily/article.cfm?aid=7889031)

Meanwhile, local groups genuinely concerned about the quality of the air they breathe and their lakes and streams are still opposed to the TXU intent to build the remaining three pulverized coal steam plants.

If the white hat suitors are really as green as they claim, they should withdraw the applications for the remaining three PC plants and refile based on IGCC technology with carbon capture.

But, even for white hats, with their empty pockets, it might be too much to expect them to actually put their scant investment into anything as pricey as CO2 capture and storage operation.

They’ll do well to avoid going the way of that once great Houston-based “Energy Company” that is now a dirty word. Will Texas really be better off with this sort of “solution” to the threatened rush to coal?

2007-02-15T11:17:00.001-05:00

Happy Valentine's Day
for IGCC Technology

Is it "My Funny Valentine" – IGCC style?

Well, it's certainly not the way that Frank Sinatra would do it.

This morning’s news out of Dallas was a bright spot (for me anyway) in the form of a report of a proposal to build the first coal-based IGCC plant in Texas.

Continuing on their theme of vocal support of IGCC technology, this proposal was delivered by NRG Energy at the Valentine’s Day CERA conference currently being held in Houston.

Just more in NRG vs. TXU saga?
At first I saw the story as just another episode in the ongoing saga of TXU vs. NRG and IGCC vs. PC plants. And, in a way, it was certainly had tones of being more of the same story.

NRG is clearly working on the side of those who oppose the TXU plan to build 11 new PC plants, and has become a thorn in the side of its major rival power generator in Texas.

And, of course, there are strings attached to their proposal. NRG admitted that it was not about to commit “commercial suicide” by building a plant that costs at least 20% more than the type of PC plants being proposed by TXU without some form of state financial support to close the “IGCC cost gap” (as it has pending in the case of its New York project).

So far, ho hum, just like my Valentine’s Day turned out to be.

Then the BIG NEWS for IGCC.
As part of it’s announcement, as reported by the Dallas Morning News, NRG will be working with Mitsubishi as their technology partner for their proposed IGCC projects in the east – apparently dropping plans to take up a license for the Shell Gasification Process.

MHI is reportedly stepping up to the challenge of offering “one stop shopping” for IGCC plants using their own newly developed air-blown gasification technology, now undergoing startup at the Clean Coal Power 250 MW demonstration project in Japan. (See MHI website for more http://www.mpshq.com/medialine_index.htm)

NRG’s CEO David Crane announced that the Mitsubishi gasification process, which has been selected for its proposed IGCC plant in New York, would solve several problems that TXU (as well as GE Energy as reported by the Dallas newspapers) claims to prevent building plants using the cleaner coal technology in Texas.

Crane said that the Mitsubishi gasification equipment would be able to use the high moisture sub-bituminous coal from Wyoming. And MHI will provide NRG with the "financial guarantees that the process works” he told interviewers at the CERA conference.

Stepping up to the bar
That MHI has stepped up to the bar to give IGCC technology a major boost should be no surprise to industry watchers.

GTW met with MHI representatives at the December PowerGen conference in Orlando and came away with the impression that they were clearly and aggressively targeting the US market for IGCC plants.

In one of their presentations they show a timetable for commercial introduction of a 600-MW class plant based on M501F gas turbines that would indicate that they were due to identify of a US launch customer at this time.

That the deal is with NRG did come as a surprise, to me at least. We had NRG listed as firmly in the Shell Gasification camp. But they never did identify an equipment supplier or EPC contractor which seemed a bit strange for a project in New York state that was under contract negotiations.

Good news for IGCC
The announcement that MHI will step up to fill the needed role for “one stop shopping” and provide the necessary plant wide performance guarantees is certainly welcome news for those following the struggle for IGCC to claim its niche in the large market for coal-based power plants.

And the fact that the MHI process has been successfully tested on PRB coal, as reported at the 2006 GTC conference, makes this Valentine’s Day present even more important for supporters of IGCC technology. It helps put strength into the argument that the technology can be made to be fuel-flexible and economical on low rank coals.

It also helps take the wind out of the sails of those who say that IGCC can’t work on western coals, and is “not ready for prime time”. TXU has long claimed that it could not get anyone to guarantee such a plant.

Apparently, they have been talking to the wrong supplier of such plants.

Indeed it's time for Texas to put its money where its mouth is - and support the NRG proposal to introduce truly "clean coal" into the Texas power generation market.

As TXU threatens that it will be lights out for Texas if it doesn't get its way with its proposed fleet of new coal-steam plants, perhaps it will be NRG Energy that helps keep the lights on, and helps with lower emissions to pollute the air of central Texas.

2007-01-22T14:49:00.001-05:00

Is It Lights Out For Big Coal/Steam Plants?

Only last weekend we commented on how TXU’s plan for an 11-pack of new coal-fired steam power plants was going to be a matter of “Pay Me Now AND Pay Me More Later”.

The reference was to the near certainty of future environmental regulations - presumably governing CO2 emissions – that would require costly plant modifications for compliance.

By Monday the press was abuzz with reports of proposed legislation being (re)introduced, this time in a Democratic US Congress, that would limit CO2 emissions and set up a market-based trading system, ala the European scheme.

At last count there are four such bills, with one in the Senate having the distinction of bearing the illustrious names of Lieberman and McCain.

Enter the Ecomagination coalition
And then on Friday, the New York Times ran a surprising story (to me anyway) about a new coalition of major US corporations and environmental groups jointly promoting legislation to establish firm limits on emissions of greenhouse gases.

The group is called U.S. Climate Action Partnership – USCAP for short - and who is out there but GE as one of its founders leading the pack.

Then, late Saturday night, to clarify some of the confusion caused by the Times scoop (leak?), USCAP issued a statement of its own declaring that, as part of its set of principles and recommendations, they strongly discourage further construction of stationary sources that cannot easily capture CO2.

So just when GE Energy itself landed perhaps one of its largest ever steam turbine generator orders – probably around $1 billion worth of business with the booking of the 11 units for TXU – they come out helping to lay the groundwork to give it all away.

According to the Times article, the coalition’s platform comes close to "rejection of almost all new coal-fired power plants on the drawing boards, including the 11 plants proposed by TXU."

A full report by the group is expected to be available on Monday, January 22.

For full text of USCAP statement go to: http://www.yubanet.com/artman/publish/article_49708.shtml#

Coalition makes for some strange bedfellows
The coalition representing both major industry and environmental groups is recommending a “Cap and Trade” system that will be “good for everybody”.

Enviros should like it because of the specific hard caps, reduction targets and timetable. And so should industry -- especially those companies in a position to exploit developing technologies that reduce emissions and improve energy efficiency.

The timing is such that it all could be worked out while President Bush is still in office and the Democratic Congress stands ready, willing AND ABLE to endorse such a broadly backed deal.

Who are they and what do they want to do?
The coalition’s current roster contains 10 large US corporations representing manufacturing, energy, electric utility and financial sectors, and four prestigious non-government environmental groups:

Alcoa
BP
Caterpillar
Duke Energy
DuPont
FP&L
GE
Lehman Brothers
PG&E
PNM Resources
Environmental Defense
Natural Resources Defense Council
Pew Center on Global Climate Change
World Resources Institute

Stated legislative objectives:

Mandatory phased reduction in greenhouse gases
Setting pricing structure for greenhouse gas emissions
National program for accelerated technology R&D and deployment
Incentives to encourage actions by other countries, including China and India

Proposed greenhouse emissions cap and reduction timetable:
(Depending on sector)

5 years -- 100-105% of current levels
10 years -- 90-100%
15 years -- 70-90%
2050 -- 60-80%

Too early to celebrate?
Naturally it is far too early to celebrate any sort of victory for IGCC. There are still plenty of hurdles and naysayers.

But the combination of a new attitude in Washington, and the coming together of major industrial players with key elements of the environmental community, has to help pre-empt the rush to coal that is well on its way to put some 150 new PC plants into operation over the next 5 to 10 years.

Even coal-fired plants already permitted will be facing new limitations on emissions (and unplanned operating costs) that will come into play before any new plants can be built.

There can be no grandfathering with a planned phased reduction in emission levels from all major emitters. Either you cut emissions or you pay – that’s how it’s going to work.

Meanwhile, with credits available to those who reduce emissions by phasing out old PC plants and add new plants with designed-in CO2 capture capability, there can be, in effect, a substantial reduction in the high cost of IGCC plants.

With both new and existing PC plants facing high added costs due to their inability to economically capture CO2 emissions, the “IGCC Cost Gap” will likely experience a reversal of direction, eliminating the only valid reason for avoiding the technology.

2007-01-14T20:39:00.000-05:00

TXU’s Rush To Cheap Coal Power - A Matter of "Pay Me Now and Pay Me More Later"

An ugly cyber skirmish between NRG Energy and TXU over something said in a publicly distributed TXU email reminds one of the nonsense going on between The Donald and Rosie O’Donnel.

But this is much more serious business because it can affect the future of IGCC market development, and all interested parties should be paying close attention.

TXU launched an attack on IGCC as a “developing technology” worthy of interest but yet to be proven -- confirmed, they say, by NRG backing out on a proposal to build an IGCC plant in Connecticut.

It is understandable why TXU wants to undermine IGCC, and keep their hurried plan for growth on track.

But in hindsight they should have anticipated that it might back-fire as evidenced by NRG’s strong reaffirmation of its commitment to IGCC and a challenge for a public debate on the issues: http://www.snl.com/irweblinkx/file.aspx?IID=4057436&FID=3283483

Where is all this headed?
Opponents to the proposed new coal plants in Texas (18 in all; 11 by TXU alone) are now calling for a moratorium on permits. What was once considered a “done deal” under a fast-track approval process, is now hitting some very steep speed bumps.

Public challenges are calling for reinstatement of the normal project review process.

And there’s a new state legislature in Austin that will be considering reversal of the Texas governor’s order to expedite permit approval.

Delay should give time for evaluation
Local groups claim that TXU has sidestepped any consideration of cleaner IGCC technology, dismissing it as unproven and unreliable, in favor of building cheaper but dirtier conventional coal plants.

A moratorium will allow time for honestly evaluating alternatives to the TXU plan that would not exclude IGCC technology.

It will also give everyone concerned time to examine the true costs of building the proposed coal steam plants (which TXU puts at only $1100/kW), including the long term impacts on public health.

With most new coal plant projects now costing well over $2000/kW, it is hard to believe that TXU’s initial estimates are still valid.

There is also more time needed to allow for the debate over whether or not IGCC should be treated as BACT under the Clean Air Act.

This is currently the crux of a suit filed in Texas federal court that has been given new life now that the EPA has rescinded its Dec. 2005 letter which, in effect, provided TXU with justification to file for approval of the 11 conventional coal plants.

Challenge and reality check
My understanding is that TXU has already released preliminary engineering and manufacturing for its proposed new fleet of coal plants.

If so, it helps explain its program of misinformation launched against IGCC technology. And also why industry comment has been muted with major suppliers having already booked big equipment and construction orders.

TXU still claims that coal-fired steam plants are absolutely the best solution at present to assure that Texas does not run out of power. That says that they are counting on these plants being readily retrofitted to meet expected and more stringent air quality regulations.

Assuming that is possible, which is questionable, it’s going to be very costly to clean them up (at ratepayers’ or shareholders’ expense?) to meet the inevitable further tightening of emission limits and the requirement for CO2 capture.

Even TXU has publicly stated that they are rushing for approval of conventional coal plants in order to get them grandfathered in before restrictions on CO2 are enacted.

So, it looks like it is a matter of “pay now and pay more later” – and in the meantime living with dirtier air to breathe.

That is the real technology and economical risk facing TXU ratepayers – not whether or not IGCC would work for Texas.

Perhaps the first question that should be raised in the Texas legislature is:

"Would TXU be willing to guarantee that their “low-risk” plan will not result in significant rate increases to meet future environmental requirements? "

Meanwhile, TXU is doing its best to assail IGCC technology and its supporters.
Take a look at what they assembled for their PR people to release to the press last week:

Reality Check: Proposed IGCC Power Plants Face
Cancellation, Cost Recovery Opposition and Delay

AEP: Billion-Dollar Plant's Costs Are Escalating
- Charleston Daily Mail, 12/27/06

The company said earlier this year the plant would probably cost about $1 billion. It promised to provide a more detailed cost estimate by the end of this year.

But in a letter hand- delivered on the day after Christmas to its regulator, the state Public Service Commission, the company's lawyers said it wouldn't be able to provide the estimate at this time.

"...what we've found out is, part of the higher cost is from the construction market -- concrete, steel, labor -- the regular things you have in construction," Matheney said. "It's also the first time a plant of this type has been built to commercial scale."

“...The company has repeatedly said it will only build such plants in states where regulators allow it to recover its costs. That means ratepayers would have to pay increased rates."

...Morris [AEP Chairman and CEO Mike Morris] said the process of getting the regulatory and legal authority to build the integrated gasification plants "is taking longer than we'd like -- at least longer than I'd like. And arguably longer than our customers can really afford and longer than the instate regulators can afford."

NRG: Company Shelves Plan for "Clean Coal" Power Plant
- Associated Press, 11/28/06

"...NRG officials said they decided to drop the coal technology (IGCC) because the company couldn't build the planned 630-megawatt plant in time to receive state incentives.

“...Environmental groups were already fighting the plant, saying the new coal technology still produces carbon dioxide, which, unless captured, contributes to global warming. The technology to capture the gas is still being developed."

AEP: CEO Says Issues Could Delay Clean Coal Build
- Reuters, 11/06/06

"...The company had been hoping to build an integrated gasification combined cycle (IGCC) power plant in Ohio by 2010, "but it's probably more like 2011 or 2012,"

AEP CEO Michael Morris said....The process in Ohio has been slowed because of a lawsuit that alleges that the state public utility commission would overstep its authority by approving cost recovery for the coal plant. Morris said he expects a decision from the state's Supreme Court early in 2007...."

The Bottom Line (according to TXU)

IGCC is still a developing technology that is not yet available at the scale, efficiencies and availabilities needed to meet Texas' near-term power needs.
Cost Recovery Is Not an Option in Texas: Electric utilities developing IGCC plants in other states depend on limiting their technology and operational risk with regulatory cost recovery -- that's not an option in Texas.
IGCC Technology Not Guaranteed for Texas Fuels. No IGCC technology suppliers are currently providing guarantees for IGCC plants using the coals available in Texas.

2006-12-28T16:43:00.002-05:00

In Spite of Showdown in Austin
"Railroad" is Still On a Fast Track

An early Xmas present for TXU?
Once more the technical debate over the benefits of IGCC technology vs. conventional coal-based power generation finds itself making headline news in a major state capital.

This time it’s in Austin, where the news last week must have been like an early Xmas present for Texas Utilities executives and project planners.

TXU has seven air permit applications under review by the Administrative Law Judges as they prepare to make their recommendations to the Texas Commission on Environmental Quality (TCEQ).

On Dec. 14 the Judges issued an initial ruling that these applications are still subject to the fast-track review process ordered in last fall by Gov. Perry.

This came in spite of heavy public objection by a collection of environmental and business groups, as well as the mayors of Dallas and Houston, who oppose the TXU plan to build 11 new coal-fired power plants in central Texas.

In the most recent session, the Judges also moved to consolidate the hearings for six of the TXU permits. This will tend to further streamline the debate that opponents already complain is being rushed.

Coal power is needed
Not that there isn’t widespread agreement that Texas needs to add generating capacity, and to diversify its power generation methods and energy sources. This follows a period of over-building gas-fired combined cycle plants, which resulted in a disproportionate dependence on natural gas in the state.

While some of the greener groups oppose coal outright, those who recognize the need for new coal-based generation want the proposed plants to be as clean as possible.

Enter IGCC technology, and the debate over whether or not it is the right answer for such an ambitious program.

Opponents to TXU's proposals argue that they should not be given fast-track approval to build “obsolete dirty coal plants” and should, instead be required to take more time to consider the use cleaner, albeit more costly IGCC technology.

In coming out in force to the hearings, they were hoping for a moratorium in the permitting of the conventional coal plants (in all there are 16 currently up for approval across the state), and are hoping to swing the Judges opinion as they consider the arguments pro and con.

One bright spot for the opposition was that the Judges did accept the Coalition of Cities, which includes Dallas and Houston, as well as other groups, as a “parties to the case”. This formality will allow opposition spokespeople and expert witnesses to be admitted and heard at the hearings.

”This is clearly a railroad (by the governor’s office), and is simply getting people more angry” one outspoken critic of the fast-track process told me.

Approvals pending
At this point, TXU still has air permit requests for all 11 of the proposed plants pending.

Besides the seven being reviewed by the Judges, two others, Sandow and Oakdale Unit 5 are up before a federal court – where intervenors have filed suit charging that the TCEQ process violates the U.S. Clean Air Act. They argue that that IGCC should be considered as BACT for new coal-based power generation.

Two other applications, for Oak Grove 1 and 2 near Waco, already have negative findings pending before the TCEQ, which, by the way, is not bound by the Administrative Law Judges’ recommendations.

(One late report indicated that these have been officially put on hold after a Waco community group – including business leaders - filed suit. They argued that PC plants are not the cleanest technology available, and they apparently plan to file similar suits against all of TXU's plants.)

Since the Governor's executive order requires the Commission to consider the applications at “its earliest possible opportunity”, these two could very well be decided at the next TCEQ meeting scheduled for Jan. 10.

As for the seven still before the Judges, and possibly being greased for the fast-track process, there is a six-month clock ticking for each of them (from the time that it was referred for review) so they will soon have their “day in court”.

Calling for ‘timeout’ to get it right
Opponents await Gov. Perry's replacement appointment to the three-member TCEQ, and are looking to the incoming state legislature to address the issue.

There are those who are holding out hope for “showdown” between the legislature and the governor’s office that will force a slowing of the TCEQ permitting process, and stop the “stampede” caused by the fast-tracking executive order.

Opponents are calling for a timeout. A group of medical doctors is leading the outcry with questions about the potential danger imposed by coal plants on public health. Although some of the new plants are intended to replace some old ones, the opposition argues that there will be a net increase in the emission of pollutants.

While acknowledging the higher initial cost of IGCC technology, they maintain that the ultimate costs to the public will be much greater due to the impact of conventional coal plants on the already sub-standard air quality in the region.

They say that the state will not have a second chance to consider the consequences. Taking a timeout is the only way to make sure Texas gets this right.

For more up-to-date news on TXU situation in Austin see: http://www.austinchronicle.com/gyrobase/Issue/story?oid=oid%3A432112

2006-12-06T10:03:00.000-05:00

Tax Credit Glitch Gives Wrong Signals and Fuels IGCC vs. PC Debate

Although we just highlighted the problem with the selection process used by DOE to award Phase I tax credits under EPAct 2005, I wanted bring your attention to this news report out of Sioux Falls SD.

The news is on Basin Electric Coop's failure to secure a tax credit for their project, and shows just how something like this can give the wrong signals, and add fuel the debate over whether IGCC is the way to go for clean coal projects.

Just take a look at this article and see how the proponents of the Big Stone II coal plant twists the news around to show how "failure of Basin's tax credit application vindicates the decision to use conventional coal."

Let's hope that the right forces come into play over the next few months so that the 99% sulfur removal rule is modified for low sulfur coals so that good projects using sub-bituminous coal get a chance to get their share of the Phase II awards due out in June.

Harry Jaeger
Gasification Editor

South Dakota coal-gas plant on hold after not getting a tax credit

By Ben Shouse
Argus Leader, Sioux Falls SD
Dec. 6, 2006

Cleaner coal technology hit a speed bump Tuesday in South Dakota, as a major power supplier announced it did not receive a key federal tax credit.

Basin Electric Power Cooperative had proposed a plant near Huron or Mobridge to use integrated gasification combined cycle, or IGCC.

The technology converts coal to a gas before burning, which greatly reduces air pollution and could some day allow the capture of carbon dioxide, the gas most responsible for global warming.

But the project might not be economical without a federal tax credit, said spokesman Daryl Hill in Bismarck, N.D.

"That doesn't mean we're abandoning work on that, but you're right, it does slow that timetable of working with IGCC," Hill said.

Basin sells electricity to rural cooperatives in South Dakota and eight other states. Hill said Basin will decide on a site and a technology in 2007.

A major obstacle to building an IGCC plant in South Dakota is the type of coal it would use. The best source is the Powder River Basin in Wyoming.

The 2005 energy bill, which created the coal tax credit, required plants to reduce sulfur dioxide emissions by 99 percent. But Powder River coal is already low in sulfur. Energy Secretary Samuel Bodman acknowledged that when he announced the credit recipients Thursday and said he is working to resolve it.

Seven power companies are planning to build a separate coal plant near Milbank, to be called Big Stone II. Ward Uggerud, vice president of Otter Tail Power Co., said the failure of Basin's tax credit application vindicates the decision to use conventional coal.

"What this underscores is that IGCC is not necessarily there yet for people to proceed with on a commercial application," he said.

Reach Ben Shouse at bshouse@argusleader.com

2006-12-03T12:07:00.000-05:00

How Did Using Low Sulfur Coal Become a Disadvantage?

It seems that the DOE and IRS can’t even give away a billion dollars to promote clean coal projects without fouling it up.

The long-awaited Phase I awards for IGCC and other qualifying "clean coal" projects were handed out to nine companies under the Energy Policy Act of 2005. (For DOE release, see http://www.fossil.energy.gov/news/techlines/2006/06068-Clean_Coal_Tax_Credits.html)

Seven recipients were identified; another two opted for privacy under IRS rules. (Anyone know who they are? Why would they want to keep the award quiet?)

For coal-based IGCC projects ($400 million):
$133.5 million to Duke Energy for 795 MW (gr.) Edwardsport IN (GE)
$133.5 million to Tampa Electric for 789 MW (gr.) Polk County FL (GE)
$133 million to So. Company/Miss. Power for 700 MW (gr.) Kemper County MS (?)

For other gasification projects (specific $$ awards not published*):
$ ??? million to Carson Hydrogen – for petcoke to hydrogen and 390 MW (GE)
$ ??? million to TX Energy (w/Eastman) – for syngas for industrial chemicals (GE)

For advanced coal-fired steam projects ($250 million):
$125 million to Duke Energy for 1600 MW Cliffside Modernization NC
$125 million to E.oN US et. al. for 1744 MW Bedford KY

(*Since the total announced was $1 billion, that leaves $350 million for the two unidentified recipients and two with award amounts unpublished. Range was from $40 to $130 million. )

Congrats to the winners, but……
Unfortunately though, in spite of the law requiring even allocation among coal types, all of the winning IGCC bids are based on gasifying either high-sulfur bituminous (mid-west?) coals or lignite (Miss. Power).

Applications for IGCC projects using low-sulfur bituminous coal never even got to first base due to quirk in the fine print.

Explanation, says DOE Secretary Samuel Bodman, is that the law stipulates a 99% reduction in sulfur for IGCC proposals.

This is impractical to achieve if you start with a sub-bituminous coal that is already very low in sulfur content, he admits, but that’s the way it is when one has to follow the rules of the game.

So now, with half of the $800 million allotted tax credits for IGCC already awarded, he is saying that the DOE should “work with Congress and industry (aha, blame them!) to address this issue”.

(For Bodman’s speech to the National Coal Council see: http://newsblaze.com/story/20061130105951tsop.nb/newsblaze/TOPSTORY/Top-Stories.html)

Forty proposals rejected
This raises a big question about the proposals that were rejected - or never even submmitted - because of this impractical sulfur-removal rule that the DOE now recognizes was a mistake.

DOE says a total of 49 IGCC applications were received and analyzed “for technical and economic feasibility” and for consistency with energy policy goals.

I wonder how many of those 40 rejected applications might have otherwise been chosen if not for the faulty 99% sulfur-removal hurdle?

Further, how did the technical experts who helped draft the legislation slip up and effectively exclude such a major portion of US coals from being considered?

How did it happen?
Did the 99% requirement just sneak in there undetected? Or was it the work of over-zealous regional lobbyists and deal makers?

How can low-sulfur bituminous coal projects be excluded if DOE’s goal is to “spur rapid deployment” of IGCC power generation plants?

Can the answer be that this was the cost of having other incentives under EPAct specifically earmarked for a project at high elevation using western coals?

How about restitution?
Let’s face it, at this stage whatever the DOE does to address this issue is too late for the first round of tax incentive awards.

Under EPAct there are still $400 million in tax credits to be awarded to coal or lignite-based IGCC projects in June, 2007. At least two-thirds of this is supposed to be earmarked for sub-bituminous projects.

In the interest of promoting good projects rather than regional coal interests, let’s hope that the necessary revisions are made in the law to enable good low-sulfur coal projects to pass the sulfur-removal test.

Maybe sub-bituminous coal should even be given the edge in evaluating competing proposals.

Not much consolation for today’s losers, but it would be one way of compensating for the technicality that had shut them out.

2006-11-16T11:57:00.001-05:00

Texas Shoot-Out May Determine Future of IGCC

The scene that will be playing out during the next few months in Texas courts reminds one of a good old-fashioned shoot-out, reminiscent of High Noon, or The Gunfight at the OK Corral.

But this time the battle lines have been drawn over whether or not enough is being done to limit emissions from a veritable fleet of new coal-fired power plants being proposed by Texas Utilities (TXU) and others – all to be built in central Texas.

As reported recently in the local press, there are pending lawsuits, administrative fights and demands for reform before the Texas state legislature that are challenging the way Texas regulates air pollution.

And caught in the middle of the battle could be the very future of IGCC power generation technology in the US.

Are the rules good enough?
The main issue to be decided in Texas courts is whether the state’s environmental permitting rules are adequately protecting the public health, as is mandated (say the interveners), by the Texas Clean Air Act as well as the federal Clean Air Act.

The Texas Office of Environmental Defense is one of the groups suing the Texas Commission on Environmental Quality (TCEQ), claiming that the commission’s coal-plant permit rules don’t even meet legal minimums set forth by law.

A similar lawsuit is likely in federal district court later this month.

On September 29, another group handed TXU a 60-day advance notice that they plan to sue over one of its proposed plants under the citizen-enforcement provision of the federal Clean Air Act.

On the fast track
Meanwhile, as the judges mull over those suits, permits for 16 new plants (11 proposed by Texas Utilities alone) are moving forward at unprecedented speed under Gov. Perry’s fast-track order for coal plant permits.

Before the end of November, a state administrative law judge will start a 6-month race against the clock to schedule and conduct hearings, and issue recommendations, for a half-dozen of the proposed plants.

That’s the maximum review time now allowed under the October 2005 order, which, the governor says, is simply meant to cut red tape in order to accelerate the building of needed new generation. Environmentalists called it a giveaway to power companies, who are said to be among his biggest campaign donors.

Before that order was imposed, a single plant’s hearing process could typically take a year.

The EPA's green light
To push the coal rush along even faster (not only in Texas but across the entire country) the US EPA issued a controversial decision late last year that gave a boost to power companies in state permit fights over proposed coal burning plants. (Reportedly, about 150 such plants have already been permitted nationwide.)

The EPA’s ruling was related to an industry inquiry for clarification of the Clean Air Act requirement that new sources of pollution must use “best available control technology” (BACT) to limit emissions.

When asked if the BACT provision means that new source applications for PC plants must consider using the cleanest coal technology, namely IGCC, the EPA said “no”.

EPA’s reasoning, apparently, was that IGCC technology would “redefine the proposed project”, which, they said, was not the intent of the BACT analysis.

Not wasting any time, the TCEQ immediately embraced that guidance, ruling that Texas power companies could ignore the cleaner technology and go ahead with higher-polluting coal burning plants.

Then the EPA waffles
Predictably, national environmental groups sued the EPA over their ruling.

Unpredictably, they were successful -- arguing that the agency failed to follow its own procedures, having made the ruling behind closed doors and without public input.

The upshot was that the EPA canceled the guidance in October, and promised to revisit the issue again – this time in public.

But whether the EPA has the power to force states to consider IGCC for new coal plants is still in question, and environmental groups continue their pursuit.

They are claiming that the EPA is ignoring their mandated obligations under the Clean Air Act to foster innovation and to force pollution levels downward whenever possible.

(Last July, the EPA itself had issued a report saying, in essence, that IGCC offers a way to lower emissions across the board, and makes it easier to capture carbon dioxide.)

Setting the stage for the showdown
While about a dozen states now require power companies to consider IGCC for their new plants, Texas still says companies don’t have to consider the cleaner technology.

And while 16 new plants have been proposed (15 burning coal, and one burning petcoke) only Houston-based Tondu Corp. has adopted IGCC for a proposed petcoke-fueled plant on the Corpus Christi ship channel.

Reportedly, TXU’s most recent permit applications, filed in April, still cite the now-invalid EPA guidance as justification for not considering IGCC.

Those permit applications are up for consideration by the courts over the next few months, and, in effect, draw a line in the sand for future projects.

Does almost count for rule making?
As part of its justification of proposing conventional coal-burning plants instead of gasification, TXU says that the emission control measures to be employed will match IGCC on “some emissions”.

The Dallas News reports that a comparison between TXU’s emissions and those of a dozen IGCC plants being permitted across the country shows that the cleanest of the IGCC plants would beat TXU on all eight regulated air pollutants.

However, the comparison did find that TXU’s emissions of NOx, mercury and VOCs were actually lower than at least one of the new IGCC plants. (Ed. Note: One wonders about that IGCC permit application; is anyone familiar with that situation?)

But if IGCC is to be considered BACT, it is what the technology is capable of achieving that is relevant, not how poorly it might perform in one specific case.

Promises, promises
As part of a plan for improving regional air quality, TXU is offering to reduce its overall emissions by 20% -- even as it proposes to add new plants and double its coal use.

This would require an overall 70% reduction in emissions from its existing coal plants, says the Dallas News, but TXU does not specify how or where those reductions will be made.

And there are already signs that their plan is meeting resistance. Recently, for example, an administrative judge panel rejected a proposal for expansion of the Oak Grove plant in Robertson County.

According to the Waco Tribune, the panel doubted TXU’s claims of emissions curbs when using high-sulfur Texas lignite.

“TXU says that their plan to upgrade their old plants is just good environmental stewardship. More likely, it is a response to public outrage,” says the Tribune.

With regard to possible future upgrades to control greenhouse gases, TXU confesses that none of its proposed plants - which can be expected to operate for decades - will have carbon-capturing ability.

However, they say retrofits might be possible if and when any new regulations would require them to limit emissions of greenhouse gases.

Texas precedents don’t favor IGCC
Environmental groups claim that Texas’ failure to press the industry to embrace IGCC is “an abandonment of clean-air progress” as well as a violation of the Clean Air Act.

“We need radically cleaner technology on the coal side,” says John Thompson, director of the Clean Air Task Force’s coal transition project, which encourages cleaner technologies.

But there are already precedents in Texas – not necessarily good ones for the case of IGCC – such as the compromises made by LS Power to get their 800 MW Sandy Creek coal-fired plant approved.

As cited by the Waco Tribune, growing pressure from area residents and environmental groups forced LS Power to make enough concessions on emission levels to get a TCEQ permit for the plant to be located near Riesel, east of Dallas.

There is also the controversial case of the 750 MW CPS (San Antonio) coal plant. After facing concerted objections to the plant, and insistence by environmental groups that IGCC technology be considered, CPS promised a number of concessions, and struck a deal with the interveners.

As part of the deal, they agreed to conduct the “feasibility study” of IGCC technology, issued by EPRI, (that was the subject of our previous posting) and thereby were able to sidestep further action to limit emissions.

Now that the San Antonio and the LS Power projects were approved, can TXU bank on the assumption that the TCEQ cannot deny similar proposals that have already been submitted?

Or will the courts and regulators, now in the national spotlight, rule against TXU in favor of environmental groups who have put IGCC up as the new standard?

As the Waco Tribune put it: "It is outrageous that Central Texans should be chained to a technology that will become obsolete when gasification — IGCC — becomes state-of-the-art. Let’s slow down the race to soon-to-be-obsolete technology and figure out ways to spare our air."

But I wonder if precedent in Texas isn’t telling us that all of this pressure in favor of IGCC is being done only as a means to get project developers to make further concessions to clean up their act.

Tight, crowded schedule
The timetables for resolving legal challenges, permit decisions and a pending revised regional air quality plan -- are about to collide.

As of mid-November, no date has been set for starting hearings of the Environmental Defense lawsuit filed on October 17 against the TCEQ. A state response is pending.

Meanwhile, the 60-day expiration clock is ticking on the September 29 filing by environmentalists in U.S. District Court, where notice was given of a possible federal suit against TXU under the federal Clean Air Act.

This could impact the state’s fast-track permit process for at least one of TXU’s plants – and perhaps all of them.

Under this process, the end of November is also when a state administrative law judge is supposed to convene preliminary hearings on TXU’s permit requests. Actual testimony is scheduled to start in January, and the judge’s recommendation for or against the permits is due by April 23, 2007.

The TCEQ will then decide whether to issue the permits - that is if all the lawsuits and other challenges don’t apply the brakes to the whole fast-track process.

Meanwhile, the state’s new air quality attainment plan for urban North-Central Texas – prepared without knowing how many new coal plants will be built, or what technologies will be used -- is due out for public comment in December.

By June, the state must submit the final plan to the EPA.

If you thought that the Shootout at the OK Corral was something to behold – hold on to your hats and your boots!

2006-11-07T19:59:00.003-05:00

IGCC Cost Gap Cops Catch Another One

Talk about stacking the deck -- I get suspicious whenever I run across an after-the-fact study that justifies a questionable action. Don’t you?

Case in point is a recently published industry magazine article on the results of a study in connection with the City of San Antonio’s CPS Energy decision last year to build a 750-MW supercritical pulverized coal (SCPC) plant.

The article had a simple enough headline: “EPRI Publishes IGCC Cost Comparison Report” based on a new EPRI Report No. 1014510 prepared by Burns & McDonnell, Kansas City.

CPS commissioned the study, entitled “Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site”. They did this under terms of a settlement that was part of a deal with environmentalists who had opposed the air permitting process for their proposed coal burning plant. (You may recall the news out of San Antonio late last year - where the CPS Energy Director of Generation Planning declared, in defense of their decision, that “IGCC is not ready for prime time. It just ain't here.”)

A rehash of the executive summary
The magazine article basically summarizes the report’s finding that SCPC offers the lowest cost option, even when it is penalized for higher emissions.

These “independent” results show that the total capital costs of the 600 MW net rated IGCC plant are about 20% higher than for a similarly sized SCPC plant located, for study purposes, on a greenfield Gulf Coast site.

The study fuel was PRB coal, except that a case was included for the IGCC fired with 50% petcoke, which is available in the area and assumed to cost $0.50 per MMBtu less than the coal (assumed @ $1.65 per MMBtu).

The plant heat rates were comparable, so that fuel costs came out about the same for the 100% PRB cases, but substantially (20%) lower for the IGCC fueled with 50% petcoke.

Estimated O&M cost were about $8 million per year lower for the SCPC option (i.e. $30 million vs. $38 million for the IGCC).

At an assumed 85% capacity factor for both plants, this works out to about $1.8/MWh per year difference in busbar costs.

Bottom line: the EPRI 20-year levelized busbar cost (COE) computation shows that the IGCC plant with 100% PRB coal is about 15% higher than for the SCPC plant.
Q.E.D. – the cost gap lives on (unless you have a cheap waste fuel to use in the IGCC plant to help close the gap)

Scratch below the surface and find pay dirt
On the surface one would say “Ho hum, what’s new?” The report simply reconfirms the existence of the IGCC cost gap.

But if you go beyond the executive summary, and the magazine article, and dig a bit beneath the surface, it is easy to uncover a number of questionable underlying assumptions that had a substantial impact on the study results.

Nix on NOx
One thing that immediately caught my attention is the executive summary statement that, while emissions of sulfur, particulates and mercury are considerably lower for the IGCC, those of NOx were higher than for the SCPC option. (Usually IGCC NOx is also shown to much lower than for the SCPC, but the study data showed it to be about 20% higher on a per MWh basis.)

The reason for this is that CPS decided not to include an SCR in the back end of the IGCC in order, the report says, to avoid ammonium sulfite fouling of the HRSG.

(Seems that the European experience with SCR in IGCC plants has been ignored again. Annual HRSG cleaning is accomplished at the same time as annual GT maintenance – not that big of a deal.)

Was the omission of an SCR for the IGCC plant really a big deal?

Not until you realize, by digging into the study details, that the annual cost penalty for NOx emissions – regardless of the technology - was assumed to be about $6 million per lb/MWh.

That IS a big deal, and it added a penalty of over $3.5 million per year to the variable O&M cost of the IGCC plant, which emits 15 ppm NOx (or about 0.6 lb NOx per MWh) without an SCR.

Adding an 85% effective SCR to the IGCC design would drop the NOx to less than 3 ppm and “save” almost $3 million per year in the O&M cost – or almost 40% of the total difference in O&M costs.

Even if the additional cost of including the SCR were taken into account, at $6 million per lb/MWh per year for NOx it would make a sizable difference in the results.

To chill or not to chill?
Another troubling assumption buried in the details is that the comparison between IGCC and SCPC is made at an average ambient temperature of 73F(db)/69F(wb), with evaporative cooler off.

Since this compressor inlet temperature is above the threshold to acheive the max. rated power output of the Fr7FB gas turbines, the IGCC plant is operating at about 46 MW (or almost 8%) lower than its maximum net output capability (553 MW vs. 599 MW).

As the study points out, the decision not to add an inlet chiller was a conscious choice by CPS (as was leaving out the SCR).

Once again, the result has a major impact on comparative plant costs.

A matter of a little simple math
First and most obvious is that the values of capital cost per kW and the busbar cost per MWh for the IGCC cases would be decreased by almost 8% if the IGCC plant were credited with its full output capability.

This alone would reduce the gap in busbar cost by almost two-thirds (from 15% to 6%) for the 100% PRB fuel case. And it would make IGCC with 50% petcoke the winner by 4%.

A more subtle impact of using a de-rated IGCC output in computing study results relates to the fact that the gasification island had to be sized for the cold-day (max. plant rating) condition.

Since the gasification block accounts for roughly 2/3 of the IGCC plant cost this could be said to have added about 5% to overall plant capital cost.

When compounded with the derated kW used in the denominator, this increases the computed $/kW capital cost of the IGCC plant by almost 15% - or three-quarters of the reported 20% cost gap.

(Could it be? Is the cost gap is a myth after all?)

There's more..
With a little more digging a few other issues with the study come to the surface.

For one, there is the comment that neither GE nor ConocoPhillips showed any interest in participating in the study. That says that the selection of the Shell Gasification Process was by default, although, as stated, it was perhaps the right choice for the type of high-moisture coal used in the study.

Also, the selection of a Selexol acid gas removal system (made ostensibly to improve CO2 separation characteristics) may have been an expensive luxury, particularly given the relatively light sulfur removal duty assumed for the study. This helped drive up IGCC costs.

Another issue brings us back to the O&M costs for the IGCC option. Buried deep in the report, under a section titled “Byproduct Sales”, is a description of commercial uses for the type of vitrified slag produced by the Shell gasifier.

It says that these range from construction and paving fill, to blasting grit and water filtering medium. This raises the question: Why then is there an annual O&M cost of about $1.5 million associated with “fly ash and slag disposal” for the IGCC option?

Should this more properly be a credit rather than an expense, in which case there would a negative swing of $3 million per year to further reduce the IGCC plant O&M cost?

Finally, perhaps the most egregious statement, was that the cost of the SCPC option would be still be lower even if provisions for 85% CO2 capture were included in the evaluation of the two options.

From what I’ve seen elsewhere, that seems to run contrary to everything that has been published on the subject. It only adds to the serious questions that could be raised about the study results if one digs deep enough below the surface.

Conclusion: There’s need for continued study
To be fair, the EPRI report summary suggests a list of areas where the study should be continued and extended to examine the impact of alternative design assumptions.

These include using 1) an SCR and inlet chiller for the IGCC as well as using a two-pressure level HRSG rather than 3-pressure unit used in the study, 2) an evaluation of air-side integration for the IGCC plant design, and 3) considerations of other gasifier options primarily for enhancing CO2 capture.

It is also commented that there should be more detailed studies with more involvement of other gasifier and gas turbine vendors. Amen!

As if in an attempt to cover all of its shortcomings, the report closes with this recommendation to the industry:

Changes in market conditions, improvements in IGCC technology, different fuel specifications, or CO2 purity specifications could be enough to swing the economics in favor of IGCC. Therefore it is recommended that utilities consider IGCC technology for future generation needs.

Amen squared!

2006-10-30T09:02:00.002-05:00

Hell Bent on Going Nowhere?

The October issue of POWER magazine (www.powermag.com) does a commendable job in bringing the growing importance of IGCC to light. But just think how much better they would have done if their comparison of IGCC vs. PC technology weren’t flawed by a clearly conservative predisposition for maintaining the status quo.

This tilt came shining through, and it even went so far as using incomplete data to further the cause in favor of the PC option.

As a concerned member of the IGCC community, I feel compelled to question the validity of underlying arguments and data that lead to the conclusion that the electric utility industry (and presumably the public) is better off to delay the acceptance of IGCC technology until proven reliable like "the newest PC plants”.

Cars and sex? POWER kicks off with an editorial on “Balancing Risks and Rewards” which likens the choice to picking out a sports car vs. a sedan. Adopting a “sexy technology like IGCC” over PC is full of risk, it warns, and predicts that “System reliability and supply concerns will trump the glory of being the first on the block with an IGCC plant.”

Cutting through IGCC hype. This is followed by article entitled “Utilities Split on Readiness of IGCC” which, they say, is intended to cut through the fog of hype by not assuming that utilities “leap to be among the first to employ a sexy new technology”, whatever the risk.

It does a decent job of looking at key factors such as comparative costs, emissions, reliability, and supplier experience. My concern is with the selective choice of data that favor conventional coal plants.

In a table on cost comparisons, for example, IGCC capital cost predictably comes in 25% higher than PC, and “total cost of generation” about 12% higher. Can anyone really estimate the cost gap with any certainty anymore, given the spiraling cost of advanced PC plants with full emission controls?

It also reproduces a set of availability curves, attributed to EPRI, to play up the dismal history of six “successful” IGCC demonstration plants. Under the caption “Ready for Baseload?” it makes the point that IGCC has been able to reach 70% to 80% availability “but only after at least five years of operation”.

An goes on to a tale of “Adventures in Availability” that recounts the trials and tribulations of the Wabash River IGCC repowering project and how it suffered from a number of operational setbacks during its early years before settling out at around 75% availability for the past four years.

So what’s the problem? Frustration and concern. Why would any journalist, in an ostensible attempt at fairly presenting pros and cons, fail to include favorable availability history curves that appear in the EPRI version? (See chart below from 12/'05 EPRI presentation.)

The excluded data I refer to are availability curves for two commercially operating utility scale (>500 MW) refinery-based IGCC plants in Italy (ISAB and Sarlux).

Both base load plants operating on refinery residue as feedstock have exceeded targeted IGCC availability levels of over 90% within three years of startup.

Both plants were also project financed, by investors who were not put off by “risky IGCC technology” or fearful of backing “unproven site-specific IGCC plant designs.”

These are real plants, operating in a commercial environment. It is difficult to believe that their financing and performance were deliberately ignored to make the point that IGCC is too premature to be considered by serious utility planners.

I don’t know if any of this bothers you. But I felt compelled to set the record straight.

As you might guess, I am still peeved, but I feel much better!

Harry Jaeger
Gasification Editor
Gas Turbine World Magazine

2006-10-24T11:13:00.000-04:00

China Negotiating for Piece of FutureGen

Perhaps those close to the action were expecting it, but China’s announcement last week about plans to join the FutureGen Industrial Alliance came somewhat as a surprise to me.

It shouldn’t have though, considering China’s own aggressive program brought to light by the report at the GTC conference about its own coal-based polygen (IGCC power and methanol) demo plant that had logged over 6,000 hours through August. The 72 MW combined cycle block is powered by a modified Fr 6B gas turbine - about which even GE apparently was not aware.

The presentation by China's Institute of Clean Coal Technology has already been posted by GTC at: http://www.gasification.org/Docs/2006_Papers/37ZHOU.pdf

Makes a lot sense for China, as the world’s largest producer of coal and coal-based power (and emissions), to buy into the project. Entry price seems to be a bargain. As the release put it: "Under the scheme, each signatory needs to contribute US$10 million to the programme. In the meantime, participants can benefit from development of any new technologies."

Negotiations are said to be underway to work out details of China’s participation, with possible membership on the steering committee. India and South Korea have already signed on as “nation members”.

According to the Chinese FutureGen announcement, it appears that there are several more Chinese IGCC demo plants in the works “to improve current coal gasification technologies”.

We’d like to know more about the Chinese program and possibly run an article in the magazine.

Anybody out there who knows more, and what it could mean for accelerating the acceptance of the technology worldwide?

(The full announcement by the China Daily can be found at: http://english.sina.com/china/1/2006/1018/92303.html)

2006-10-18T12:29:00.000-04:00

IGCC Cited as Reason for Change in Wyoming's Coal Industry

Once again, a local energy news reporter gives us something to blog about, and to ponder.

This time credit goes to Mr. Dustin Bleizeffer, Energy Reporter of the Casper (WY) Star Tribune. He brings our attention to comments made by energy “expert” Dan Fessler, principal of Clear Energy Solutions LLC.

In essence, what Fessler said that was so interesting is that IGCC technology may be behind the need for Wyoming’s coal industry to decide on fundamental changes for the future.

Fessler’s message: the growing use of IGCC technology will enable other coal regions to bring their massive high-sulfur reserves to market.

One result of the wider deployment of IGCC will be that the rest of the nation will become less dependent on Wyoming coal, warns Fessler in his call for a change in thinking about the future of the industry. He thinks that Wyoming should be preparing to make better use of its resources at home, such as in gasification and coal-to-liquid plants.

The only reason that utilities pay the railroads the $50 per ton delivery cost of Wyoming coal is their low sulfur content.

And as the railroads move away from long term contracts it will only add to their influence on pricing and the potential loss of the traditional stability in the cost of coal-based generation.

Utilities are becoming increasingly wary about delivery reliability, making Wyoming coals less and less attractive for use at long distances from the mines.

But what alternatives do they have given the limts on sulfur emssions?

Increasingly utilities and developers are using IGCC technology when drawing up plans for future power plants.

We’ve seen a number of locally popular IGCC projects announced in Illinois, Kentucky, West Virginia and Indiana, where one of the main appeals has been promise of rejuvenating depressed coal mining industries. (As the editor recalls, the original impetus behind the development of IGCC technology was as an alternative to stack gas scrubbers for use with high-sulfur coal.)

Add the growing need to control CO2 emissions
The article goes on to comment on the importance that CO2 capture will play in the future, and the need for this to be factored into the planning of new facilities.

“C02 captured in the IGCC (gasification) process can be injected into coal seams to increase the production of coal-bed methane gas without the need to pull water from the coal aquifer -- a major source of controversy in the Powder River Basin” according to Fessler.

Time for a change?
Fessler has long been pushing for Wyoming to develop its own gasification and coal-to-liquids industries as a way to better utilize its enourmous energy assets.

The problem is that coal generates such wealth for the state that there is resistance to change from the status quo.

Fessler's position is that the coal export industry in Wyoming "bears a depressing resemblance to a Third World economy. We export a raw commodity, and we export a lot of young people. Yet the Powder River Basin is an infrastructure unrivaled anywhere on Earth."

Sounds like time for a change?

Energy reporter Dustin Bleizeffer can be reached at dustin.bleizeffercasperstartribune.net

The full article can be found at:
http://www.casperstartribune.net/articles/2006/10/14/news/wyoming/b4119babab985b2d87257206007f1470.txt

2006-10-12T22:25:00.000-04:00

More local news and views on gasification and IGCC

You may have seen the Oct. 2 press release from the office of Montana Gov. Brian Schweitzer. It told of the gathering of major project participants to announce plans to build the Bull Mountain CTL/IGCC project near Billings.

As planned, the $1.3 billion project would produce 22,000 barrels per day of coal-derived diesel fuel, and would also include a 300 MW IGCC plant to provide on-site power as well as export excess power to the grid. It promises to be one of the first such plants in the US. (See, for example: http://www.allamericanpatriots.com/m-news+article+storyid-16617.html)

Yesterday a local report on the project carried by the Billings News came out with some very negative comments, particularly with regard to the IGCC portion of the project.

The article that I refer to was written by a local reporter named Wilbur Wood, and it can be found at: http://www.billingsnews.com/printStory?storyid=21042

I suggest that you take a look at it and see for yourself.

Using emotional appeal to rally project opponents
What bothers us about this sort of thing, and we see over and over again, is that a local reporter, who is way over his head technically, can appeal to the emotions of his readership and negatively impact the way a project like this is received locally. It gives project opponents the rallying point that they are looking for to delay or kill needed development.

An example of what reporter Wood injected into his report on the governor's press release and his support of the project:

“The issue is a sensible energy policy for Montana” said Jeanne Charter, a Bull Mountain rancher and member of Northern Plains Resource Council, as she criticized the plans for the Bull Mountain project.
“We think Schweitzer is backing the slowest horse in the race. Renewables like wind and biodiesel are cheaper, faster and cleaner.”
Ms. Charter said that this project could take over a decade to build and those “billions of dollars” would be better spent on energy efficiency and renewable technologies that could come on line within a year or two and do “a lot more to support widespread prosperity (in rural Montana, that is) and provide more affordable energy.”
“This project will likely be obsolete before it is built, given that renewable energy costs (like solar electric cells) are coming down very rapidly,” she said.

More knocks from Great Falls
Reporter Wood went on to inject a quote attributed to Great Falls City Manager John Lawton as saying that “IGCC is a technology that up to now has not been commercially viable”.

It turns out that the city of Great Falls is partnered with five rural electric cooperatives in Montana in proposing to build a 250-megawatt coal-fired (PC) power plant, the Highwood Generating Station, west of Great Falls.

Clearly, competition from a 300-megawatt plant in the Bull Mountains as part of the CTL project would not be welcomed by the developers of the Highwood plant.

And there's more...
Mr. Wood still wasn’t finished with his jabs at the project, and at IGCC technology in particular. He went on to tell how he was contacted by Lisa Hardiman of Citizens for Clean Energy (CCE) – a Great Falls based group opposing the Highwood plant in part because its designers did not consider IGCC technology. (GTW had sent some supporting information on IGCC to CCE.)

Wood said that he replied to Hardiman that, while it is recognized that IGCC is “cleaner than any other current coal technology”::

1. It (IGCC) is extremely expensive, and likely will require massive government subsidies.

2. The entire process apparently creates more carbon than conventional coal-fired plants (though probably releasing lower amounts of other pollutants) and this carbon needs “sequestering before the promise of clean coal means anything".

3. IGCC by itself would use considerably less water than a plant like Highwood, (projected to use 1.7 billion gallons per year) but in a coal-to-fuel plant IGCC is only step one in a process to gasify, then liquefy, coal into “synfuel” – and this uses an enormous amount of water.

“Where does water come from?” “How much water is needed?”

Wood makes an unfounded “provisional” assumption of the amount of water that the plant will use and basically concludes that the proposed project will require tapping into the local aquifer, 8,600 ft below ground.

His parting blow: “Mining an aquifer to turn coal into liquid fuel sounds like a very bad idea, but even if people convince themselves (that) it’s a good idea, the massive costs may turn them away”.

As I said, if you want to see the full article published yesterday (10/12) in the Billings News, it can be found at: http://www.billingsnews.com/printStory?storyid=21042
They invite comment, which may be more important than your commenting to this blog.

Posted for your reading and action by:

Harry Jaeger
Gasification Editor
Gas Turbine World Magazine

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Memorable Memorial Day for

Kemper County IGCC Project

Mississippi Power announces that it will move forward to construct a 582MW IGCC power plant as Public Service Commission relaxes financial restrictions on the project.