Natural gas can help coal burn cleaner A relatively small “investment” of gas might sharply increase the amount of coal power plants could use, without the accompanying penalties of increased SO, emissions and need f o r expensive air-cleaning equipment ~
Benjamin Schlesinger American Gas Association Arlington, Va. 22209
Oil backout legislation currently before the Colngress-the proposed Powerplant Fuels Conservation Act of 1980, which passed the Senate in June-contains a special “select gas use” provision designed to make it easier for converting facilities to meet Clean Air Act standards. A new Section 301 (a) (3) of the Powerplant and Industrial Fuel Use Act of 1978 ( P L 95-620) would be added, which would empower the secretary of energy to “allow the use of natural gas in conjunction with coal in such quantities as may be necessary to assist [existing electric power plants converting from oil to coal] in meeting applicable environmental requirements.” Whatever the fate of the proposed oil backout legislation this year, the concept of select gas use in dual coaland gas-capable boilers has received its first legislation recognition. What does this approach toward air quality control entail? How would it work? Would it be economical? Background T h e idea of blending different fuels, such as coal-oil slurries, gas-liquids, 0013-936X/80/09~14-1067$01.OO/O
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for economic or environmental protection reasons, is not a new concept. T h e advantages of coal conversion based on blended fuels were recognized by the Congress when it created special “fuel mixtures” exemption categories for both new and existing boilers as part of the Fuel Use Act. Because natural gas emits virtually no sulfur oxides or particulate matter when combusted (Table l), state public utility regulators, the public, and environmental interest groups alike encouraged industries and electric power companies to burn gas until the early 1970s, when supplies of gas appeared to become inadequate. Now, with the more favorable outlook for natural gas supplies, which resulted from enactment of the Natural Gas Policy Act of 1978 ( P L 95-621), as well as a brightened outlook for gas from unconventional and supplemental sources, it makes sense to suggest that natural gas can play a key, although more selective role in helping to mitigate air emissions, thereby facilitating coal conversion. Facility conversion In order to determine how select gas use might reduce emissions, as existing boilers convert from oil to coal, it was assumed that some mixture of coal and natural gas could be combusted in the Volume 14, Number 9, September 1980
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51 electric power plants named in Phase I of the administration’s proposed oil backout legislation. Preliminary analyses by the Economic Regulatory Administration, part of the U S . Department of Energy (DOE), and by the Environmental Protection Agency (EPA) indicate that the administration’s proposed coal conversion program could increase national SO, emissions by 227 000345 000 tpy, the DOE and EPA estimates, respectively (Table 2). This increase would raise total SO, emissions by about 1% over the present level of 35.3 million tpy, and would thereby negate about one-third of the environmental progress in SO, control achieved by industry between 1970 and 1975. Since some scientists believe sulfur oxide emissions return to earth in various forms, with attendant undesirable environmental effects, absolute SO, limitation at sources continues to be a national objective. Currently, the electric power plants which the administration proposes to convert to coal emit an estimated 513 000 tpy of SO,, excluding two oil-fired units which presently emit higher levels of SO, than allowed for coal use under their state implementation plans (SIPS). Thus, if 48 of the Phase I-named facilities were converted to coal (excepting the two present coal S I P violators and the one currently burning natural gas), they would collectively emit between 666 000 tpy ( D O E estimate), and 833 000 tpy (EPA estimate) of SO,. This would be an increase of 153 000-320 000 tpy, respectively. However, when a limited amount of gas is burned-either in the same boiler or in a separate boiler in the same facility-SO, emissions from the facility could be prevented from increasing beyond current levels. Thus, according to the DOE estimate, combustion of a 77% coal to 23% gas mixture would maintain SO, emissions at the level previously emitted by oil combustion. According to the EPA estimate, the coal to gas ratio would have to be 62%/38% (Table 3). In overall terms, 280-460 billion ft3/y more gas use (a 1-3% increase nationally) would permit up to 42 million tpy more coal use (a 7% increase) without increasing SO, emissions. The “bubble” concept The EPA could establish a mechanism under existing law, in conjunction with its announced “bubble” concept, that would permit facilities to control emissions on a site or even regional basis, rather than force each emission source within a particular site to 1068
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comply with every source standard. For example, a power plant that burns natural gas in one boiler and coal in its remaining boilers would be evaluated only on the basis of total emissions from the entire facility. Applying this concept to oil-fired power plants would allow their conversion to coal, and the select use of gas, without any cumulative SO, impact. While any detailed cost estimate would require #site-specificdata, one example of the cost-effective potential of applying this select gas use concept to EPA’s bubblle concept is the Norwalk, Conn., power plant (Connecticut Light and Power Co.). A mixture of 73% coal and ;!7% gas would enable this oil-fired facility to convert from oil to coal withoutflue gas desulfurization ( F G D ) scrubbers, and still meet Connecticut’s cloal use S I P at the 80% level. Nonattainment areas Two key national policy objectives-increased coal use to offset imported oil, and public health maintenance through air quality controlcome into severe conflict when attempts are made to site new coal-fired industrial and utility boilers in or near the nation’s “nonattainment” areas. These areas are so named because they fail to achieve lqational Ambient Air Quality Standards ( N A A Q S ) for one
or more pollutants. Any industrial growth and consequent emission increases in these regions must be accompanied by reduced emissions from existing sources, as required by SIPS. Nonattainment in many locations, however, often exhibits peaking characteristics, as illustrated in Figure 1 , which plots all 24-h average particulate levels recorded a t one nonattainment station in 1976. These were portrayed in sequence, from the year’s best day to its worst day. Typically, only a few days or weeks out of the year are actually in violation of the N A A Q S for short averaging times. For example, Figure 1 suggests that in East Liverpool, Ohio, 24-h standards for total suspended particulate matter (TSP) actually were violated only 18 days in 1976 (the three violating days times six, since particles are recorded every sixth day). Inspection of 1976 data shows this city was one of the nation’s worst nonattainment stations that year. Superimposing the particulate emissions associated with a hypothetical new 1000-MW coal-fired power plant 10 miles upwind of the East Liverpool monitoring station would cause an upward shift in the c u p e in Figure 1 . This is shown as the upper curve. From the East Liverpool example, a strategy of select use of gas capability
as part of the new coal-fired power plant could be applied in a combination of three ways to prevent the worsening of N A A Q S violation: environmental “peak shaving,” whereby operation with gas is required during all violating days planned seasonal operation with gas if violations have a history of occurring only during certain times of year, such as summertime inversions combustion of gas in part of the new facility, such as in a single-boiler unit, all year round to reduce the incremental pollution of the entire project, while reducing any remaining N A A Q S violations by other means. National estimates Expansion of the new facilities analysis to a national level by the procedure described below roughly quantifies the fuel use impact of the environmental “peak shaving” approach. Note that even a rough quantification of the other two approaches would require substantial additional site- and project-specific information. O n the basis of EPA National Aerometric Data Bank Standards Reports for 1976, seven sample nonattainment stations were selected from among the most severe T S P and SOz nonattainment areas throughout the U S . They were East Liverpool, Ohio;
FIGURE 1
19716 daily particulate emissions recorded at East Liverpool, Ohio.
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Primary 24-1.1 TSP standard
=
260 pglrn’
Recorded days of year aSeqlJenced from best to worst day NOTE Estimated added emissions caused by hypothetical new 1000-MW coal-fired power plant indicated by cross-hatched area
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Jefferson County, Ohio; Baltimore, Md.; Greenlee County, Ariz.; Rubidoux, Calif.; St. Louis, Mo.; and Steubenville, Ohio. These stations’ daily maximum 24-h T S P and SO2 readings for 1976 were plotted in ascending order, as shown in Figure 1, and were measured against the primary TSP/SO* NAAQS. Under the Clean Air Act, delay in attainment of N A A Q S for other contaminants, such as NO, or carbon monoxide, is permitted until 1987. The estimated emissions of the new 1000-MW coal-fired power plant with best available control technology (for instance, FGD with 90% removal, and electrostatic precipitators) were added to the existing loadings. The new curves were compared to the respective primary standards to determine the number of days the region would be above the 24-h primary standards for either T S P or S02. Gas would then be burned to avoid further N A A Q S violations on the resulting above-standard days. Incremental emissions of the 1000-MW power plant were estimated as follows: The 2000-MW Ohio Edison Stratton plant is located 10 miles upwind of the East Liverpool monitoring station. North Ohio Valley Air Authority personnel estimate that the Ohio Edison plant accounted for 65-7570 of both T S P and SO1 values at the East Liverpool station in 1976. Thus, 70% of the arithmetic mean 1976 T S P and SO2 values at East Liverpool were assumed to represent impacts of a 2000-MW plant. These values were then halved to approximate the impacts of a 1000-MW coal-fired power plant. Because the Ohio Edison Stratton plant was equipped only with electrostatic precipitators in 1976, the calculated SO1 impacts were adjusted to reflect the impact of flue gas desulfurization equipment, assuming that scrubbers would remove 88% of the s02.
The estimated increment to 24-h maximum ambient SO2 and TSP levels caused by a 1000-MW coal-fired power plant were calculated for each of the other six regions to account for differences in local coal sulfur content. This was done by multiplying the value obtained by the ratio of local coal sulfur content to that of East Liverpool’s. Quantifying gas demand The arithmetic average of the number of coal days and gas days was determined for the seven regions as explained above. The resulting 1070
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breakdown of the 82% coal days and 18% gas days required in order to meet 24-h primary T S P and SO2 standards was then assumed to be nationally representative, accounting for all site-specific and seasonal variations as follows: Table 4 lists the seven nonattainment areas, analyzed together with the number of days of compliance with short averaging time NAAQS, assuming the impact of the new 1000-MW coal-fired power plant IO miles upwind.
of nonattainment will show similar geographic patterns; thus it is assumed that about one-third will continue to violate short-term NAAQS. On this basis, one third of the 5.5 quad shortfall in U S . coal use by 1985, or 1.8, is expected in these areas. This level of coal use shortfall, relative to the April 1977 National Energy Plan (NEP-I) forecast, was derived from an American Gas Association analysis. The 1.8 quads were then allocated into 82% coal and 18% gas, to arrive at the estimated fuel use increases shown in
State-by-state compilations of all U S . air quality monitoring stations reported nonattainment in 1976 for T S P and SO2 were assembled from EPA data. The compilations also list the number of stations failing to attain N A A Q S for short averaging times only, with ambient N A A Q S met. The 1976 nationwide average ratio of stations with only short averaging time NAAQS violations to total nonattainment stations was 32% and 38%, respectively, for T S P and S 0 2 . The proportion of partial use of natural gas to reduce emission levels of particles and SO, was then developed under two separate air quality enforcement cases: Control of both annual and short aueraging time N A A Q S . From arithmetic mean determinations, as described above, air quality monitoring data for 1975 and 1976 indicate that 38% of the nation’s nonattainment areas for SO2 were in compliance with the annual, but not the short averaging time NAAQS. (The comparable figure for ambient particles was 32%.) Planned increases in U.S. coal use suggest that in 1985 the characteristics
Table 5. The utility/industrial split for new coal use was assumed to be 601 40. Control of short aceraging time N A A Q S only. At the remaining twothirds of nonattainment areas, those violating both short and long averaging time N A A Q S , it was assumed that alternative means are either available now, or could be made available to offset violations of annual NAAQS. Extending the added fuel use to the remaining two-thirds of nonattainment areas on a straight-line basis yields the estimates shown in Table 5. For these stations, however, it was assumed that the resulting coal use increases will fall 50/50 into utility/industrial applications, along lines of NEP-I. Conclusions for new facilities The foregoing estimate of the impact of allowing gas to be burned in new coal-fired boilers on a partial basis reveal the following (Table 5): By 1985, approximately 190 million more tons of coal (4.5 quads, or a national increase of some 30%) can be burned annually in new power plants and new large industrial boilers
laws may be needed, particularly in regulations pursuant to Section 123 of the Clean Air Act. In some existing facilities which convert from oil to coal, however, even the scrubber requirement may be waived with select gas use under the “bubble” concept. Finally, it must again be reiterated that this analysis is preliminary in nature. Analysis of specific facilities and locations would be required to assess accurately the benefit of the select gas use strategy in order to develop a more precise national estimate. Acknowledgments This article summarizes two energy analyses prepared by the American Gas Association-Analysis of Select Use of Gas to Enhance Coal Conversion (June 1979) and Analysis of Select Gas Use in Utility Coal Conversion for Limiting Sulfur Emissions (April 1980). The author gratefully acknowledges the assistance of AGA President George H. Lawrence, Michael I. German, Nelson E. Hay, and William Parham in the preparation of these analyses. located in nonattainment areas with a select gas use strategy (analysis case “B” in Table 5, extending to all U.S. areas of nonattainment). In conjunction with this strategy, a n estimated 1.0 trillion ft3/y of gas nationally (about a 5% increase in U.S. gas use) would be required by 1985 to prevent new coal-fired facilities from violating NAAQS. Under a more limited select gas use strategy, extending to nonattainment areas with short averaging time N A A Q S violations only, the use of 0.3 trillion ft3/y of gas would enable combustion of an additional 60 million tons (1.5 quads) per year of coal (analysis case “A” in Table 5). Finally, allong with contribution to increased U S . coal use, enhanced emergency capilbility benefits would be realized by new coal-fired facilities which are sited in nonattainment areas. Their gas capability, both physical and legal, would enable continued operations during restrictions or stoppage of coal supplies for any reason and malfunction or maintenance of plant equipment related to coal use, such as flue gas scrubber outages or breakdowns. Undoubtedly, enough serious air quality situations will remain a t some locations to preclude coal use altogether in new facilities, even with select use of gas. In addition, increasing use of coal gasification will often resolve the coal use vs. environmental effects dilemma in nonattainment areas and elsewhere. Thus, further site-specific studies of facility location
decisions and Clean Air Act licensing problems would be required to pin down the precise quantities of coal which may be used in new facilities, and accompanying requirements for gas, under the select gas use strategy. Nevertheless, application of this strategy appears to promise considerably more coal use-and in an earlier time frame-than anticipated by the D O E in its November 1978 draft Environmental Impact Statement on the Fuel Use Act. That law states categorically that “a boiler was assumed to be exempt [from F U A coal conversion requirements] if located in a county that is designated as an air quality ‘nonattainment’ area . . .” Select gas policy Natural gas would be sold on a premium basis, whether the gas is used throughout the year in part of the facility, or part of the year in the whole facility. Moreover, if natural gas is made available on this premium, assured basis to a coal-burning facility, the gas could be stored by the utility for use in emergencies. Under the current Clean Air Act, select gas use seems unlikely to replace flue gas scrubbers in new facilities;
regulations pursuant t o b o t h of these
Additional reading U. S. DOE and U S . EPA, “Energy/Environment Fact Book”; Washington, D.C., March 1978, p. 4. Office of Technology Assessment, U S . Congress, “The Direct Use of Coal”; Washington, D.C., April 1979, pp. 2 2 2 25. U S . EPA, “Air Pollution Control; Rec-
ommendation for Alternative Emission Reduction Options Within State Implementation Plans; Policv Statements.” Federal Register, Dec: 11, 1979, b. 71780. American Gas Association, “An Analysis of the Constraints on Converting Large Industrial and Utility Boilers from Natural Gas to Coal”; Arlington, Va., Nov. 2 3 , 1977. American Gas Association, “Evaluation of the President’s Proposed Supply-side Energy Strategy”; Arlington, Va., Sept. 6, 1977.
since 1977.
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