Abstract Booklet 2006 - Swanson School of Engineering - University ...

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SESSION 13
GASIFICATION TECHNOLOGIES:
APPLICATIONS AND ECONOMICS – 3
GE and Bechtel’s IGCC Reference Plant Update
Rich Rapagnani, GE Energy, USA
For background, GE Energy purchased ChevronTexaco's gasification technology business in
June of 2004, and soon thereafter formed an IGCC alliance with Bechtel Corporation to
jointly develop and commercialize an IGCC reference plant. Rated nominally at 630 MW,
this IGCC Reference Plant provides customers a commercially competitive, cleaner coal
alternative for coal to power. Moreover, the GE and Bechtel IGCC Alliance provides this
IGCC product on a turnkey basis, including commercial guarantees, thus offering the total
package customers need for successful commercialization of their project.
This presentation provides to the conference attendees an update on the GE and Bechtel
IGCC Reference Plant design status, a look at the fuel flexibility benefits inherent in such a
plant design, a preview of the expanded fuel envelope capabilities under development by GE
and a discussion of the business aspects supporting development of IGCC projects.
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Beluga Coal Gasification Feasibility Study Phase 1
Ronald Schoff, Robert Chaney, RDS-Parsons Corporation, USA
The Beluga Coal Gasification study aims to determine the economic feasibility of siting a
coal-based gasification plant in the Cook Inlet region of Alaska for the co-production of
electric power and marketable by-products. The plant products may include synthesis gas,
Fischer-Tropsch (F-T) liquids, fertilizers such as ammonia and urea, alcohols, hydrogen,
nitrogen and carbon dioxide, that would be manufactured for local use or for sale in domestic
and foreign markets. The project was divided into two phases. In Phase 1, the Agrium
fertilizer plant in Nikiski serves as the case study site and customer for product gases
(including hydrogen, nitrogen and carbon dioxide), steam and power from the coal
gasification facility. In Phase 2, an assessment of alternative locations and plant designs
based on local and export markets for the suite of potential products will take place. The
Phase 1 case study results, reported here, will feed into the Phase 2 central Alaska regional
study. The project may be broken into four major subject areas, described below:
Gasification Plant Design: The coal gasification plant investigated in this study is designed
to provide the Kenai Nitrogen Operations (KNO) plant with the following suite of required
products:
• 282 million standard cubic feet per day (MMSCFD) of hydrogen at 400 psig and of
suitable quality for ammonia production.
• Stoichiometric quantity of nitrogen (approximately 100 MMSCFD) at 400 psig and
99.99% purity.
• 1,500,000 lb/hr steam at 1500 psig and a minimum temperature of 825°F.
• 300,000 lb/hr steam at 600 psig and 625°F.
• 2,500 tpd CO 2 suitable for urea production (25 psig)
• Electric power to satisfy the auxiliary power requirements for the gasification plant
and the KNO facility, to make the entire facility electric power independent.
Two cases were considered:
Case 1: Process the syngas from the gasification plant to supply required hydrogen and
nitrogen to the KNO ammonia synthesis loop compressor and produce sufficient steam and
power for the KNO needs. Capital Cost was $1.64 billion.
Case 2: Process the syngas from the gasification plant to supply required hydrogen and
nitrogen to the KNO ammonia synthesis loop compressor, but do not produce power from a
gas turbine. Rather, independently produce the required steam and power for the KNO
facility with a CFB coal-fired boiler. Capital Cost was $1.87 billion.
Financial Analysis - The Power Systems Financial Model Version 5.0 (now the standard
used by NETL for IGCC systems analysis) was used to perform the financial analysis.
Factors in the analysis included: coal and limestone supply and cost, by-product markets,
and impact on local natural gas and electric power markets. Project return on equity
investment (ROI) and a discounted cash flow analysis were key results. Identification of key
model sensitivities also occurred.
Case 1 possesses superior financial potential relative to Case 2. For Case 1, the ROI was
11.1% with a Payback Year of 2023, assuming start-up in 2011. For Case 2, the ROI was
6.0% with a Payback Year of 2031. While both cases produce enough raw materials
necessary for ammonia and urea production at the Agrium facility, Case 2 is more
expensive, produces less export power, and requires slightly more coal feed in order to do so.
Sensitivity analysis was performed on all model inputs in both cases. The items found to
have the greatest impact on the financial results are the plant EPC cost, system availability,
ammonia/urea prices, and coal price.
Environmental Issues The analysis of the design basis indicates that a proposed IGCC
facility at the Agrium Kenai Plant is feasible in terms of current environmental permitting
and compliance requirements imposed by federal, state and local regulations.
Carbon Capture/Use - The potential for use of CO 2 for enhanced oil recovery in regional oil
fields was a major consideration. It was determined that CO 2 floods could economically
produce up to 300 million barrels of oil in Cook Inlet fields with oil prices at $35 to $40/bbl
and CO 2 price at from $0.50 to $1.20/mcf. The production potential is equal to that achieved
locally over the last 25 years by conventional methods.
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2006 Cost and Performance Estimates of Fossil Energy Power Plants
Jared P. Ciferno, RDS-Parsons Corporation, USA
Julianne Klara, NETL, USA
In 1999, the Department of Energy s National Energy Technology Center (NETL)
sponsored a report entitled Market-Based Advanced Coal Power Systems in response to a
newly deregulated power industry. The study, conducted by Parsons Corporation, compared
the performance and economics of power systems that were advanced, yet market-ready
within a 5 year time frame that included Pulverized Coal Boiler (PC), Natural Gas
Combined Cycle (NGCC), Integrated Gasification Combined Cycle (IGCC) and 2nd
Generation Pressurized Fluidized Bed Combustion (PFBC) power plants. In the 7 years
since this report was published, natural gas prices have more than doubled while proposed
emissions regulations such as EPA s Clean Air Interstate Rule (CAIR) and the Proposed
Power Plant Mercury Rule, have forced the potential inclusion of control devices and
operational strategies to lower future power plant emissions. Furthermore, concern over the
potential effect of CO 2 emissions from fossil fuel power plants on the global climate is a key
issue for the future of power generation worldwide. With energy demand projected to rise by
over 60% through 2030, limiting CO 2 emissions from power plants is becoming ever more
pressing. Finally, technological advances such as the anticipated introduction of a synthesis
gas fired gas turbine and expected improvements in the operation of gasifiers will affect the
overall plant performance. As a result of changing economic, regulatory and technological
issues, the 1999 study has become outdated. The effort that is currently underway is the 2006
Market-Based Advanced Coal Power Systems study, expanded to include three competitive
gasifier technologies, with and without CO 2 capture. Economic issues, including the rapid
increase in natural gas prices and the shift in the industry back to coal-based plants, are
considered here. Pollution control technology advances, brought about by anticipated
regulation, result in cleaner plants. Advances in gas turbine, gasifier and other balance of
plant equipment are taken into account. Cost and performance results of the study effort will
be discussed in this paper and at the conference presentation.
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Advanced Clean Coal Technologies for Capture
Minish Shah, Praxair, Inc., USA
In the absence of any regulations on CO 2 emissions in the US, the focus is on building new
power plants that are CO 2 capture ready. This paper compares and contrasts two advanced
clean coal technologies for CO 2 capture: Integrated Gasification Combined Cycle and Oxy-
Coal Fired Boiler. The gasification has been widely promoted and the oxy-fuel combustion
is also gaining support as a viable alternative for CO 2 capture. Both of these technologies are
touted for their potential to capture CO 2 at low cost. There are significant differences in the
commercial readiness and the CO 2 capture readiness. These issues will be highlighted and
the cost and performance with CO 2 capture will be presented for both the technologies. All
the individual components of IGCC plant with CO 2 capture have been demonstrated in large
scale operation in different applications. The main obstacles to commercialization of IGCC
are uncertainties related to costs and reliability. Adding CO 2 capture capability to IGCC will
impact the performance of all the major sub-units (gasification, combined cycle and ASU).
Therefore, to make IGCC CO 2 capture ready, significant preplanning will be required. The
oxy-fuel technology allows utilities to build power plants based on air-fired PC boiler,
technology they are most familiar with and one which requires lower initial investment
compared to IGCC. And for CO 2 capture, two new sub-systems (an air separation unit and a
CO 2 clean-up unit) can be installed only when needed further minimizing up-front
investment. However, there has been no large-scale demonstration of some of the subcomponents
of this technology. Although in theory, the oxy-coal fired boiler can be operated
to mimic the air-coal fired boiler, testing at smaller scale will be necessary to understand
flame and heat transfer characteristics and materials compatibility due to different chemical
environment within the boiler. The learnings from such testing will also be needed to
establish whether any design changes are required for the CO 2 -capture ready plant. The CO 2
clean-up will also require further development to address issues related to impurities such as
SO x and NO x .
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Power Systems Development Facility Update on Six Trig Studies
Luke H. Rogers, Southern Company Services, USA
George S. Booras, Electrical Power Research Institute, USA
Ronald W. Breault, National Energy Technology Center, USA
Nicola Salazar, Kellogg Brown and Root, Inc., USA
The pursuit of more cost-effective and reliable coal technologies with superior
environmental performance continues to drive the development of the Transport Gasifier at
the Power Systems Development Facility (PSDF). This paper presents the results of six
updated system and economic studies of Transport Integrated Gasification (TrIG) plants.
Southern Company and Kellogg Brown and Root (KBR), in conjunction with the U.S.
Department of Energy (DOE) and other partners, are developing the TrIG process at the
PSDF for commercial application in the power industry. The PSDF is an engineering scale
demonstration of the KBR Transport Gasifier along with a high-temperature, high-pressure
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