The Future of Coal-Based Power Generation

Posted on: Wednesday, 26 March 2008, 03:00 CDT

By Katzer, James R

Despite its image as a dirty fuel, coal remains an economic choice for baseload power generation - and it can, in fact, have very low emissions. Coal is used to generate more than half of the electricity produced in the U.S., and about 40% of the electricity produced globally (1). For China and India, the coalbased fraction is much higher.

Global CO2 emissions from coalbased power generation exceed 7 billion m.t./yr - about 41 % of the total energy-related CO2 emissions. The U.S. and China emitted similar amounts - roughly 2.5 billion m.t. each in 2006 (2). Power plants are some of the largest single-point sources of CO2 emissions, with a typical 1,000-MWe coal- fired power plant emitting more than 6 million m.t./yr. Total CO2 emissions from some of the larger (3,000-6,000 MWe) power plants in several countries are given in Table 1 (3, 4).

Coal is a critical fuel for power generation. It remains the least expensive of all the fossil fuels - at $l-$2 per million Btu, compared with $6-12 per million Bm for natural gas and oil. It is also very abundant, with proven global reserves estimated to be about 900 billion m.t. - the equivalent of about 160 years' supply at current production rates (5). Today, the three largest coal consumers - China, the U.S., and India - have about half of the world's coal reserves and limited reserves of other fossil fuels; the U.S., with about 255 billon m.t. of recoverable coal, has 27% of the world total ( 1).

Worldwide, primary energy demand is projected to grow by just over 50% by 2030, with electricity demand doubling. Coal-based power will, by necessity, account for a large portion of this growth, and will essentially maintain its current share of the electricity generation portfolio. Thus, the use of advanced technology to minimize the environmental footprint of coal-based power generation must be a major objective.

This article, which is based on the work done for MIT's "The Future of Coal" study (6), focuses on the technologies that are available and under development for generating electricity from coal. It includes discussion of their costs and environmental performance related to criteria pollutants (e.g., SO^sub 2^, NO^sub x^, particulate matter), and of their amenability to CO2 capture and sequestration. In order to compare technologies, a common set of design criteria and operating conditions and assumptions was selected:

* each plant is a greenfield unit with a 500-MW^sub e^ net generating capacity

* it burns Illinois No. 6 high-sulfur coal

* it has a capacity factor of 85%

* emissions are controlled to somewhat below today's best demonstrated performance

* cost estimates are based on detailed designs for a plant on the U.S. Gulf Coast, with 2000-2004 costs indexed to 2007

* only commercially demonstrated technologies are considered

* cost estimates are for the Mh plant (where N is a single-digit number) for those technologies that are still evolving, such as integrated gasification combined cycle (IGCC) and pulverized coal combustion with CO2 capture

* the levelized cost of electricity (COE) (i.e., the constant- dollar price required over the life of the plant to cover all operating expenses, payment of debt, and accrued interest on initial project expenses, plus the payment of an acceptable return to investors) is calculated using the EPRJ-recommended approach.

This analysis allows a rough cost comparison among the technologies to be made. Actual costs will depend on the coal type, plant site and location, dispatch strategy, and a myriad of other design and operating decisions. (Further details are available in Ref. 6.) The point of this discussion is to compare the technologies with and without CO2 capture. (The technologies and costs for CO2 transport and geologic storage are treated independently.)

Puiverized-coal power generation

Figure 1 shows the typical unit operations that are used in an advanced pulverized-coal (PC) combustion plant without CO2 capture. The system can be depicted as three technology blocks: the boiler block, the steam-cycle turbine block, and the fluegas clean-up block. The design and operating conditions of the steamcycle block largely determine the overall generating efficiency of the system.

For conventional PC combustion plants, the typical operating conditions of the steam-cycle block and the resulting overall electrical generating efficiency (based on the higher heating value, HHV) are:

* subcriticai steam cycle unit - typical steam-cycle operation at 1,000[degrees]F and 2,500 psi, 33%-37% unit efficiency

* supercritical steam cycle unit - typical steam-cycle operation to 1,050[degrees]F and 3,530 psi, 37%-42% unit efficiency

* ultra-supercritical steam cycle unit - typical steam-cycle operation to 1,110[degrees]F-1,140[degrees]F and 4,650 psi, 42%-45% unit efficiency.

Today's existing U. S. coal fleet consists mainly of subcriticai units with a limited number of supercritical units, although interest in supercritical technology in the U.S. has recently increased. Europe and Japan have built about a dozen ultra- supercritical units during the last decade (7).

Moving from subcriticai to ultrasupercritical generation reduces coal consumption by more than 20% per kW^sub e^h of electricity generated. And. the higher the efficiency, the lower the CO2 emissions per kWeh of electricity generated. As a result, at a minimum, we need to move to the highest-efficiency generation that is economically justified to reduce CO2 emissions.

Coal combustion power generation with CO2 capture. Because it is commercially proven for capturing CO2 emissions from gas streams in other applications, amine absorption would be the logical technology choice for capturing CO2 from PC combustion plants today. It would be applied as a process unit at the end of the fluegas train, as shown in Figure 2 for supercritical generation. However, a relatively large amount of energy is needed to recover the CO2 from the amine solution and thus regenerate the solution to capture more CO2. Less energy is needed to compress the CO2 to a sufficiently high pressure to convert it to a supercritical fluid.

For a supercritical generating unit, the overall efficiency is reduced by about 9 percentage points, from about 38% to 29%. To maintain constant electrical output, a PC plant equipped to capture 90% of the CO2 in the fluegas requires 32% more coal than a plant without CO2 capture. Improvements can be expected, but there are physicochemical and thermodynamic limitations to how large these improvements can be.

The main disadvantage of CO2 capture from air-blown PC plants is that the fluegas has a relatively low CO2 concentration (because of the large volume of nitrogen - 79 vol.% - that is present in the combustion air, and thus, the fluegas stream). This issue can be addressed, at a cost, by combusting the coal in oxygen rather than air. For PC combustion, such an approach is known as oxy-fuel PC combustion.

Another approach is the production of power in an integrated gasification combined cycle (IGCC) facility. Using this approach, the coal is gasified (rather than combusted) with oxygen and steam to produce a syngas stream consisting of hydrogen and carbon monoxide (with some impurities), which can be burned in a turbine. For CO2 capture, the CO can be converted to CO2 and H2 via the water- gas shift reaction. The CO2 is ultimately removed from the syngas stream at high pressure, before the syngas is combusted in the gas turbine. IGCC is discussed in greater detail later.

Oxy-fuel PC combustion

The more-advanced oxy-fuel combustion technology helps to address the issue of high CO2 capture and recovery costs, but it does so at the expense of requiring an air separation unit (which would be needed to produce an onsite oxygen source for enhanced combustion) with its associated energy costs (8). When coal is burned in essentially pure oxygen, the resulting fluegas is virtually pure CO2 and H2O after particulate and SO^sub 2^ removal. The advantage is gained through the ability to directly compress this fluegas stream, with drying, to produce supercritical CO2 for sequestration.

This technology is in active pilotplant development and the early stages of commercial demonstration, with at least two 10-25-MWe commercial demonstrations moving forward. Because of the early state of development, the performance and cost estimates are not as firm as are those for PC or IGCC systems. However, oxy-fuel PC combustion has the potential to provide a lower COE, and a lower cost per quantity of CO2 avoided, than the respective costs for PC combustion with CO2 capture.

Integrated gasification combined cycle (IGCC)

The other oxygen-enhanced option is IGCC generation, shown without CO2 capture in Figure 3. Typically, oxygen is used to combust sufficient carbon in the gasifier at 500-1,000 psig to increase the temperature to around 1,500[degrees]F. At this temperature, water (steam) that is added to the coal reacts with the remaining carbon, converting it to a mixture of carbon monoxide and hydrogen (syngas) with a range of minor impurities. This syngas stream is cleaned and then burned in a turbine in a combined-cycle power block (i.e., a setup that combines both a gas turbine and secondary steam turbine), much like the natural gas combined cycle (NGCC) units that are in use today. Because in an IGCC unit all the gases are contained at high pressure, high levels of particulate, sulfur and mercury removal can be cost-effectively achieved. Emissions levels from an IGCC system should be similar to those from an NGCC unit. Mineral matter in the coal is removed as a vitreous slag.

The gasification reactor is the biggest variable in an IGCC system, in terms of type (water-slurry or dry feed, operating pressure, etc.) and the amount of heat removed from it. For electricity generation without CO2 capture, radiant and convective cooling sections follow directly behind the gasification reactor. These capture waste heat from the syngas stream to produce high- pressure steam for additional power generation in the steam turbine. In this configuration, the overall efficiency of the unit can approach or somewhat exceed 40%.

IGCC with CO2 capture. To capture CO2 from an IGCC system, two additional components are required a pair of water-gas-shift reactors, and an additional absorption unit to scrub CO2 out of the syngas stream (Figure 4). This is in addition to the absorption unit required to scrub the H^sub 2^S out of the syngas mat is present in all IGCC systems. In the water-gas-shift reaction, the carbon monoxide in the syngas is reacted with steam to produce CO2 and H2. Removal of the CO2 yields a relatively pure hydrogen stream (which can then be burned cleanly in the gas turbine).

Because the CO2 in the syngas stream after the water-gas-shift reaction is present at a relatively high concentration in a high- pressure stream, the energy required to capture this CO2 is less than that required to capture the comparably more-dilute CO, that is present in typical PC-combustion fluegas.

Today, IGCC without CO2 capture has been demonstrated in several large power-generating units in the U.S., Europe and Japan. At a smaller scale, gasification with integrated water-gas shift and CO2 removal is commercially practiced for hydrogen production. However, they have yet to be integrated and demonstrated at the scale of operation required for power generation.

Points of comparison

Table 2 summarizes the operating and cost parameters associated with conventional PC combustion, oxy-fuel coal combustion, and IGCC technologies. These figures are indicative of the costs for a plant built on the U.S. Gulf Coast in 2007 dollars, and allow for comparison among the competing power-generation options.

Without CO2 capture, conventional PC combustion has the lowest cost of electricity; the COE for IGCC is about 10% higher. However, when CO2 capture is considered, IGCC yields the lowest COE.

The cost of CO2 capture and compression for supercritical PC is about 3.3 cents/kW^sub e^h; for IGCC, it is about one-half that, 1.6 cents/kW^sub e^h. The cost of CO2 avoided is about $46/m.t. of CO2 for conventional PC combustion, about $34/m.t. for oxy-fuel combustion, and about $22/m.t. for IGCC. These numbers include the cost of CO2 capture and compression to convert it to a supercritical fluid, but they do not include the cost of CO2 transport and injection (discussed later).

Its lower COE would appear to make IGCC the technology of choice for CO2 management in power generation. However, oxy-fuel combustion has significant potential. Furthermore, the cost difference between IGCC and conventional PC combustion narrows when lower-rank coals are used and/or when the plant is sited at a higher elevation. Because IGCC requires greater levels of compression than PC combustion, the higher compression costs at higher elevations due to the lower ambient pressure have a larger impact on overall IGCC economics. Under these conditions, potentially significant reductions in the CO2 capture/recovery cost for PC combustion could make it economically competitive with IGCC with CO2 capture in certain applications. In addition, the power industry still has lingering concerns about the operability and availability of IGCC.

Thus, it is too early to close the door on any of these technologies.

Rehabilitating coal's 'dirty' reputation

Coal-based power generation has the reputation of being dirty, largely based on air emissions considerations. Table 3 compares the commercially demonstrated and projected emissions performance of conventional PC combustion and IGCC (7, 9).

Electrostatic precipitators (ESPs) or baghouses are employed on all U.S. PC units, so typical particulate matter (PM) emissions are very low. Improved ESP or wet ESP designs can reduce PM emissions even further, but at a cost. Today, fluegas desulfurization (FGD) is applied on only a little more than a third of U.S. PC capacity, so typical SOx emissions remains quite high. The "best commercial" performance in Table 3 refers to emissions reductions that have been demonstrated at full commercial scale (7, 9, 10). Further reductions are possible. When CO2-capture technologies are implemented, emissions levels are expected to be lower(11).

The "best commercial" emissions performance levels for IGCC are onethird to one-tenth those of a conventional PC combustion facility, and with CO2 capture would be even lower.

In addition, IGCC produces a dense, vitreous slag that ties up most of the toxic components so that they are not easily leachable ( 12), and IGCC uses about 30% less water than supercritical PC systems. Although this does not address the entire lifecycle for coal, coal use in the electricity-generation step can, in fact, be much cleaner than it typically is with the use of additional advanced control technology.

Table 4 gives the estimated incremental cost to achieve the level of emissions control used as the design basis for this analysis, which is somewhat better than today's best demonstrated commercial performance, relative to no emissions control. This incremental cost is about 1 cents/kW^sub e^h, or about 20% of the 5.5 cents/kW^sub e^h total COE (13-15). CO2 capture and recovery will increase the COE somewhat more than this, about 2 cents/kW^sub e^-h, based on today's technology. Cost reductions can be expected when this technology begins to be commercially practiced.

The lifecycle of carbon capture and sequestration

The entire lifecycle of carbon capture and sequestration (CCS) is illustrated in Figure 5. The discussion that follows considers the last two boxes in the figure - pipeline transport and injection - and their estimated impacts on COE.

Although oil and gas reservoirs and enhanced oil recovery operations (EOR; in which CO2 is injected under high pressure into aging oil and gas reservoirs, to stimulate production) are often discussed as potential locations for underground long-term CO2 storage, these storage-sites-of-opportunity have limited long-term potential to sequester CO2 on the scale that will be needed to have a major impact on global warming. For instance, today, the total use of CO2 for EOR is 35-40 million m.t./yr, which could be supplied by a few early CCS projects, or by the CO2 emissions of just two of the largest coal-fired power plants in the U.S. (Table 1 ). Larger- volume, long-term storage will likely need to rely on deep saline aquifers. These geologic formations underlie large portions of the U. S. (Figure 6), particularly those areas with a large amount of coal-based power generation and where additional capacity is expected to be added.

The primary mode of CO2 transport for sequestration operations will be via pipelines. There are more than 2,500 km of CO2 pipeline in the U.S. today, with a capacity in excess of 40 million m.t./yr CO2. These pipelines were developed to support EOR operations, primarily in west Texas and Wyoming, and involve the transport of CO2 as a dense single phase at ambient temperatures and supercritical pressures. To avoid corrosion and hydrate formation, water levels are typically kept below 50 ppm. The pipeline technology is well-established.

However, rather than having long-distance CO2 pipelines running across the country, a typical CCS power plant project might look something like the one shown in Figure 7 (16). A good location would be one that has sufficient storage capacity accessible within about a 100-km radius. Location is important, but once sited, the CO2 storage requirement for the lifetime of the power plant - which would be on the order of a billion barrels of liquid CO2 - should be within that area. Different portions of the reservoir would be utilized over the life of the plant.

Pipeline transport costs are highly non-linear with respect to the amount of CO2 transported. These economies of scale help to bring down the overall transportation costs for large CCS projects. For example, for 6 million m.t./yr of CO2, the estimated transport cost is about $1 .OO/m.t. per 100 km; at 30 million m.t./yr of CO2, the cost falls to about $0.25/m.t. per 100 km (17). However, these are average costs, and actual values can vary significantly from project to project, due to both physical (e.g., the terrain the pipeline must traverse) and political considerations. For a 1 -GW0 coal-fired power plant, pipeline capacity of about 6-7 million m.t./ yr of CO2 would be needed, at a cost of about $1.00/m.t. of CO2 per 100 km.

The major cost for injection and storage is associated with drilling the wells. Other significant costs include site selection, permitting, characterization and monitoring, as well as lines and connectors required for injection. In general, no additional pressurization of the CO2 is required because of the high pressure in the pipeline and the pressure gain due to the gravity head of the CO, in the well bore. Monitoring costs are expected to be small, on the order of $0.1-$0.3/m.t. of CO2 (16).

Costs for injecting the CO2 into geologic formations will vary depending on the formation type and its properties. For example, costs increase as reservoir depth increases and as reservoir injectivity (i.e., the rate at which supercritical CO2 can be injected into the geologic formation) decreases the lower the injectivity. the more wells must be drilled for a given rate of CO2 injection. Injection costs typically range from $0.5/m.t. to $8/ m.t. of CO2 (17). Although limited in scale, combining storage with EOR can help offset some of the capture and storage costs. EOR credits, measured in terms of additional oil produced due to CO1 injection, of up to $20/m.t. of CO2, may result. Projected costs, on a levelized per-kW^sub e^h basis, are summarized in Table 5. These numbers are on the high end of the current range of estimates. Transport and injection costs, which include the costs of constructing pipelines and drilling the injection wells, as well as the system operating costs, are significant, but both are small and do not represent potential economic showstoppers. In general, the largest costs are for capture and compression.

For IGCC facilities, the projected cost of CCS would increase the busbar cost (i.e., the cost at the power plant gate) of electricity by about 50%, from 5.8 cents/kW^sub e^h to about 8.2 cents/kW^sub e^h. This power would be very-low-emissions (or "green") electricity, with low CO2 emissions. Furthermore, it is economically competitive with electricity generated by wind power and by new nuclear power plants (1).

Comprehensive geological studies suggest that there are no technical show-stoppers for CO2 injection and storage, with respect to its efficacy and safety. However, a variety of technical issues - such as the time dependence of injectivity. flow behavior of the injected CO2 volume in the reservoir, rate of dissolution in the saline water, rate of mineralization, and extent and type of monitoring required - must be resolved.

During 30 years of successful injection experience, no critical issues have arisen. For instance: the Sleipner Project in Norway (18) has been injecting 1 million m.t./yr of CO2 into the Utsira Saline Formation since 1996 using a single well bore; Weyburn in Canada (19) has injected 0.85 million m.t./yr of CO2 into the Midvale reservoir for EOR since 2000; and In Salah (20) has been injecting 1 million m.t./yr of CO2 into the water leg of the gas field.

None of these projects have encountered any problems, and to date there has been no sign of CO2 leakage.

Key points

About half of U.S. coal reseves are bituminous coal, and half are subbituminous coal and lignite. With lower-rank coals and higher plant elevations, the gap between IGCC and conventional PC combustion with capture narrows. Cost improvements for PC with capture could make it economically competitive with IGCC in certain applications, and with oxy-fuel coal combustion, as well. Thus, it is too early to pick winners for coal-based power generation with CO2 capture.

Using today's proven, advanced control technologies, criteria pollutant emissions from coal-based power generation can be very low. With CO2 capture, overall emissions can be even lower, resulting in a small environmental footprint. With CO2 capture and sequestration, coal can provide base-load electricity that is cost- competitive with wind and new nuclear facilities. Thus, coal remains an economic choice for base-load generation of very-low-emissions electricity.

The path forward

The technologies for power generation with CO2 capture are all commercially available today and can be expected to improve in cost and performance as they benefit from more expansive operation at commercial scale. Major R&D breakthroughs are not needed to allow for their use today.

It is also technically feasible to safely and effectively store large quantities of CO2 in saline aquifers, and the U.S. storage capacity appears very large, although, as mentioned earlier, some technical issues still need to be resolved. A broad range of regulatory issues, including permitting guidelines and procedures, liability and ownership, monitoring and certification, site closure, and remediation, also require resolution. For CCS to be available on a large scale, it is critical to gain political and public confidence in the safety and efficacy of long-term geologic storage of CO2.

To resolve these issues and establish CCS as a viable technology for managing CO2 emissions, it is necessary to establish three to five largescale (1 million m.t./yr CO2) CCS demonstration projects in the U.S. These projects should use differentgeneration technologies, focus on different geologies, and operate for several years to fully achieve the learnings that such demonstrations have to offer.

Effective demonstration of technical, economic and institutional features of CCS at commercial scale with coal combustion and gasification plants will give policymakers and the public confidence that a variety of practical carbon-mitigation options exist, shorten the deployment time, and reduce the cost for CCS when a comprehensive policy regarding carbon emissions is adopted. H will also help to maintain opportunities for the lowest-cost and most widely available energy form to meet society's energy needs in an environmentally acceptable manner. If completed expeditiously, this program can provide the U. S. with a variety of robust technical options for addressing CO2 emissions from power generation.

Furthermore, honing the required technologies will involve the core of chemical engineering, and will require a significant amount of chemical engineering talent and experience. In addition, the need to improve current technologies and develop new technologies will require much innovation by chemical engineers. Thus, the importance and the scale of the energy issues discussed here certainly point to critical challenges for the profession.

Literature Cited

1. Organization for Economic Cooperation and Development and International Energy Administration, "World Energy Outlook 2006." OECD/IEA. Paris (2006).

2. Energy Information Administration, "Emissions from Energy Consumption for Electricity Production and Useful Thermal Output at Combined-Heat-and-Power Plants." in "Electric Power Annual." EIA. www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html (2007).

3. Tollefson, J., "Countries with Highest CO2-Emitting Power sectors." Nature, 450, p. 1 (2007).

4. 'Carbon Monitoring for Action." www.carma.org.

5. BP, plc, "Statistical Review of World Energy 2006." BP ( 2006).

6. Massachusetts Institute of Technology, "The Future of Coal: Options in a Carbon-Constrained World," MIT. Cambridge. MA. http:// web.mit.edu/coal/ (Mar. 2007).

7. PowerClean Thematic Network, "Fossil Fuel Power Generation State-of-the-Art," PowerClean Thematic Network of the European Union Fifth Framework Energy R&D Programme. J. McMullan. Chairman, Univ. of Ulster, Coleraine, U.K., pp. 9-10 (2004).

8. Dillon, D. J., et al., "Oxyfuel Combustion Processes for CO2 Capture from Advanced Supercritical PF and NGCC Power Plants." Proceedings of the 7th International Greenhouse Gas Technologies Conference, Vancouver, BC (2004).

9. U.S. Environmental Protection Agency, "Continuous Emissions Monitoring System (CEMS) Data Base of 2005 Power Plant Emissions Data" U.S. EPA. Washington. DC (2005).

10. Thompson, J., "'Integrated Gasification Combined Cycle (IGCC) - Environmental Performance." presented at Plans IGCC Symposium, Pittsburgh, PA (2005).

11. Holt, N., "Preliminary Economics of SCPC and IGCC with CO2 Capture and Storage." presented at the second International Freiberg Conference on IGCC and XtL Technologies. Freiberg. Germany (May 2007).

12. Electric Power Research Institute, "Long-Term Leaching Tests with Coal Gasification Slag." Report No. GS-6439. EPRI, Palo Alto, CA (1989).

13. Oskarsson, K., et al., "A Planner's Guide for Selecting Clean- Coal Technologies for Power Plants," World Bank Technical Paper No. 387, World Bank, Washington. DC (1997).

14. Tavoulareas, E. S., and J. P. Charpentier, "Clean Coal Technologies for Developing Countries." World Bank Technical Paper No. 286, World Bank. Washington, DC (1995).

15. Rutkowski, M. D., et al., "The Cost of Mercury Removal in an IGCC Plant," Final Report prepared by Parsons Infrastructure and Technology Group for U.S. Dept. of Energy. National Energy Technology Laboratory (Sept. 2002).

16. Dooley, J. J., et al., "Carbon Dioxide Capture and Geologic Storage." A Technology Report from the second Phase of the Global Energy Technology Strategy Program. Battello Memorial Institute (Apr. 2006).

17. Intergovernmental Panel on Climate Change. "IPCC Special Report on Carbon Dioxide Capture and Storage." http://arch.rivm.nl/ env/int/ipcc/pages_media/SRCCS-final/ IPCCSpecialReportonCarbondioxideCaptureandStorage.htm (2005).

18. Arts, R., et al., "Monitoring of CO2 Injected at Sleipner using Time-Lapse Seismic Data," Energy, 29 (9-10), pp. 1383-1392 (2004).

19. Wilson, M., and M. Monea M., eds., "IEA GHG Weybum CO2 Monitoring and Storage Project Summary Report 2000-2004," Proceedings of the 7th International Greenhouse Gas Technologies Conference. Vancouver. BC (2004).

20. Riddiford, F., et al., "Monitoring Geological Storage: In Salah Gas CO2 Storage Project." Proceedings of the 7th International Greenhouse Gas Technologies Conference. Vancouver. BC (2004).

JAMES R. KATZER, CONSULTANT

JAMES R. KATZER is an independent energy consultant (P.O. Box 1346, Blue Hill, ME, 04614; jrksail@comcast.net). A member of the National Academy of Engineering, he serves on several National Research Council panels that are studying resource needs and commercial status of a range of energy technologies to meet U.S. energy needs. As a visiting scholar at the Massachusetts Institute of Technology from 2004 to 2007, he was the executive editor/ director of the MIT study entitled, "The Future of Coal in a Carbon Constrained World" (6). Prior to that, he was manager of strategic planning and program analysis for ExxonMobil Research and Engineering Co., and he held a succession of technical and management positions in Mobil oil Corp. Before joining Mobil, Katzer was a professor on the chemical engineering faculty at the Univ. of Delaware. He has authored more than 80 publications in technical journals, holds several patents, and has co-authored and edited several books. He received a BS from Iowa State Univ. and a PhD in chemical engineering from MIT.

Copyright American Institute of Chemical Engineers Mar 2008

(c) 2008 Chemical Engineering Progress. Provided by ProQuest Information and Learning. All rights Reserved.

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