Coal No More: What If?

Deck: 

An analysis of what risks would have to be taken to significantly reduce carbon emissions by using natural gas in the short run.

Fortnightly Magazine - September 2006

In 2004, 52 percent of U.S. power supply was generated by about 310 GW of relatively inefficient coal-fired steam-electric capacity, which emitted 32 percent of U.S. anthropogenic carbon dioxide (CO2), or 517 million metric tons (mmt) of carbon. Clearly, a key objective in the relatively near term (i.e., by 2025-2030) should be to reduce this large source of anthropogenic carbon emissions in the form of CO2. The preferred option has been natural-gas-fired combined-cycle systems, which emit only about one-third as much carbon and have an investment cost of only about $500/kW. The systems also have a lower heating-value efficiency of 60 percent, which is equivalent to a heat rate of 6,300 Btu/kWh (higher heating value basis).

Ideally, a sound objective would be to replace the existing 311-GW coal-fired steam-electric capacity with natural-gas-fired combined-cycle units, but at an average operating factor of 70 percent, this alone would require 11.7 trillion cubic feet of gas (Tcf)/year. Then there is the projected growth in total electric power industry capacity of about 922 GW in 2003 to about 1,186 GW in 2030. This should be met with natural-gas-fired combined-cycle units until a revival of nuclear power and the commercialization of the modified Integrated Coal Gasification Combined-Cycle (IGCC) process. IGCC involves a catalytic water gas shift step that converts the entire output into hydrogen and carbon dioxide (CO2) and the CO2 is removed and sequestered in suitable underground formations or in the deep ocean. Although IGCC technology has been developed and demonstrated, investment costs (excluding the cost of CO2 sequestration) are still in the $2,000/kW range.

Eventually, of course, the objective is to convert the electric system to use inexhaustible, emission-free sources of power and, over the longer range, photovoltaic, and solar-thermal power.

U.S. natural gas for combined-cycle power generation falls far short of the goals listed above. Construction of the roughly 4 billion cf/d capacity Alaska pipeline would help, as would a sharp increase in liquefied natural gas (LNG) imports, but the prospects for Alaskan natural gas for the lower-48 states still are uncertain and the projections for increasing U.S. LNG imports are not very reassuring. To resolve these problems, an all-out effort is required to commercialize the modified IGCC process with CO2 sequestration.

Replacing Existing Coal Capacity

In terms of gas-supply availability, what is the feasibility of replacing the existing 311 GW of U.S. coal-fired-steam-electric capacity operating at 70 percent load factor and replacing it with natural-gas-fired combined-cycle capacity operating at a 60 percent lower heating value efficiency corresponding to a higher heating value of 6,300 Btu/kWh with an investment cost of only $500/kW? This would essentially eliminate conventional pollutant emissions and reduce CO2 emissions by two-thirds in an effort to control global warming. It also deals with the feasibility of increasing projected U.S. gas-fired combined-cycle capacity operating at 50 percent load factor. If wholesale natural-gas prices in 2006 and 2007 return to NYMEX (Henry Hub) Natural Gas Futures of $11.30/million Btu [1], this simply would not be economical with coal delivered to power plants at 1.5/million Btu from 2004 to 2025 (2030 in the latest projection).

In late May and early June, NYMEX gas prices dropped slightly below $6/MMBtu after recovery of Gulf production from hurricanes Katrina and Rita, as well as a great deal of excess storage. Based on May 25-28, 2006, trading dates, gas prices may stay competitive at $5.90 to $11.30/million Btu [1]. As shown in Table 1, the DOE’s Energy Information Administration (EIA) data confirm that the trend of declining total U.S. gas supply (including imports) and increasing natural-gas-fired combined-cycle capacity is continuing, although at a slower pace, making increased natural-gas-fired combined-cycle capacity (in addition to high gas prices) a less likely solution to the greenhouse-gas emission problem. However, a 2000 estimate of an investment cost of $1,642/kW [2] for the modified IGCC power generation that incorporates a catalytic water gas shift step—which converts the carbon monoxide in the raw synthesis gas into more hydrogen and CO2, followed by CO2 separation and sequestration—now appears far too low in the light of recent information. Moreover, this cost estimate excludes the cost of CO2 sequestration.

The natural-gas requirements to replace the 311 GW of coal-fired steam-electric plants with gas-fired combined-cycle plants at 70 percent load factor and a heat rate of 6,300 Btu/kWh would be 11.7 Tcf/yr. In addition, at the projected net increase of 170 GW of combined-cycle capacity from 2001 to 2025 at 50 percent load factor and a heat rate of 6,300 Btu/kWh, it would require another 4.6 Tcf/yr (Tables 1 and 2). Moreover, coal-fired steam-electric capacity would continue to increase from 311 GW in 2001 to 412 GW in 2025 in spite of the environmental problems caused by the resulting increase in CO2 emissions.

This increase in CO2 emissions may be reduced if a significant portion of the new capacity uses the modified IGCC technology in which carbon monoxide in the original synthesis gas is converted to hydrogen and CO2 by catalytic water-gas shift (CO+H2O $ CO2+H2) and the CO2 is removed and sequestered in suitable underground formations. Moreover, the existing 311 GW of coal-fired capacity in 2001-2002, already emitted 516.5 mmt of carbon in the form of CO2 of the total of 1,609 mmt of U.S. carbon emissions in 2004 [3], or nearly one-third. In the Reference Case for 2004 [4], gas consumption for power generation from 2001-2025 increases 3.0 Tcf, so that the net increase of gas consumption from 2001-2025 including replacement of the existing 311 GW of coal-fired capacity would be 11.7 + 4.6-3.0 Tcf, or 13.3 Tcf. Or, a total projected gas consumption in 2025 of 31.3 + 13.3, or 44.6 Tcf, far in excess of what is currently considered feasible (see Tables 1 and 2). Even with the reduced gas requirements of 3.3 Tcf/yr to fuel the smaller increase in combined-cycle capacity from 2002 to 2025 of 123.5 GW [5] (Tables 1 and 3), it still would require 11.7 Tcf/yr to replace 311 GW of U.S. coal-fired steam-electric capacity plus 3.3 Tcf/yr for the 123.5 GW of increased 2002-2025 combined-cycle capacity, less 3.8 Tcf projected increase in total electric power consumption, or 11.7+3.3-3.8 = 11.2 Tcf/yr for a total of 41.8 Tcf/yr, well above what appears achievable.

Moreover, coal-fired capacity would increase to 394 GW in 2025. Finally, the net increase of combined-cycle capacity from 2003 to 2030 of 88.5 GW [3] (Tables 1 and 4) would require only 2.4 Tcf/yr at 50 percent load factor and a higher heating value heat rate of 6,300 Btu/kWh. The increase in projected demand for power generation would drop to 1.3 Tcf/yr, but this still would lead to total gas requirements of 11.7 + 2.4-1.3 = 12.8 Tcf/yr, or a total projected consumption in 2030 of 39.3 Tcf. Again, this is far in excess of what appears feasible. Moreover, total coal-fired capacity still is projected to increase to a whopping 457 GW by 2030, without any indication how much of this would come through essentially CO2-emission-free IGCC plants using CO2 removal and sequestration.

LNG and Future U.S. Gas Demands

As shown in Table 5, the expectations of ever increasing U.S. imports of LNG rising further above the 6.37 Tcf in 2025 [5] are not materializing. This is because of global competition reflected in higher net-back prices in Europe and Asia, as well as the use of stranded natural-gas resources for the production of premium distillate petroleum fuels by the catalytic Fischer-Tropsch Process—so-called Gas-to-Liquids (GTL) Plants. As a result, the steady rise in LNG imports from 6.2 percent to 20.8 percent of total supply shown in Table 5 for EIA’s Annual Energy Report (AEO) 2003, AEO2004, and AEO2005 reverses in the projections of AEO2006 [6] to a mere 15.5 percent. The projected level of U.S. LNG imports in 2030, according to AEO2006, is 4.36 Tcf. There currently are only four on-shore U.S. LNG import terminals: Everett, Mass., Cove Point, Md., Elba Island, Ga., and Lake Charles, La. Terminals also are being built in Mexico and Canada, in close proximity to U.S. markets.

Positive Factors

Numerous IGCC projects are in the advanced planning stage in spite of investment costs on the order of $2,000/kW and remaining uncertainties about CO2 sequestration. With coal at $1.50/MMBtu and natural gas currently at about $7.00/MMBtu with likely major escalations during the 2006/2007 winter, IGCC may become competitive with natural gas-fired combined-cycle generation with an investment cost of only about $500/kW and a heat rate (higher heating value) of 6,300 Btu/kWh.

The April 2006 to Oct. 30, 2007, working gas-storage season began with a record 1,700 Tcf in storage—well over 400 Tcf above last year, and about 660 Tcf above the five-year average [7]. This upward trend of working gas volumes continued into May 2006 [8] and should add to the sources of greater stability for natural-gas prices in 2006/2007.

From 1994 through 2004 there was only one year (1998) in which U.S. natural-gas replacement did not exceed—often by a considerable margin—annual production of 18-20 Tcf/yr (see Table 6, Parts 1 and 2). Moreover, 2005 should be a banner year with a record of 27,397 gas well completions and a record average active rig count of 1,186.

In any event, the electric power industry will have to use caution in making natural-gas-fired combined-cycle power generation its preferred choice to reduce carbon emissions and meet demand increases. The uncertain outlook for natural-gas supplies and prices calls for increased reliance on wind power and new light water nuclear power, as well as accelerated commercialization of the IGCC process modified to convert the output to a hydrogen-CO2 mixture with CO2 removal and sequestration.

Acknowledgement:

This author gratefully acknowledges the support of the Illinois Institute of Technology Department of Chemical and Environmental Engineering and of Gas Technology Institute for much of the underlying research for this article.

 

Endnotes:

1. Natural Gas Week, Vol. 22, No. 21, May 18, 2006, p. 6.

2. “Evaluation of Innovative Fossil Fuel Power Plants with CO2 Removal,”

Electric Power Research Institute, Palo Alto, Calif., and U.S. Department of Energy, Office of Fossil Energy, Germantown, Md., and National Energy Technology Laboratory, Pittsburgh, PA., Interim Report, DocumentNo. 000316, December 2000. Prepared by Parsons Energy Group, Inc. and Wolk Integrated Technical Services.

3. Annual Energy Outlook 2006 With Projections to 2030, Energy Information Administration, Office of Integrated Analysis and Forecasting, U.S. Department of Energy, February 2006, Document No. DOE/EIA-0383(2006)

4. Op. Cit., AEO2004.

5. Annual Energy Outlook 2005 With Projections to 2025, Energy Information Administration, Office of Integrated Analysis and Forecasting, U.S. Department of Energy, February 2005, Document No. DOE/EIA-0383(2005).

6. Op. cit., AEO2006, p. 155, Table A-13.

7. Natural Gas Week, Vol. 22, No. 16, April 17, 2006, p. 5.

8. Natural Gas Week, Vol. 22, No. 20, May 15, 2006, p. 5.