NATURAL GAS SUPPLY ASSOCIATION

805 15th Street N.W., Suite 510
Washington, D.C. 20005

Background: The Role of Natural Gas in Reducing Emissions from Coal-Burning Electric Utilities



Introduction


"Why should a coal fired utility consider incremental gas based compliance options in a rapidly changing regulatory environment?" The simple answer is economics: the ability to cost-effectively achieve discrete environmental goals while benefiting from the simultaneous collateral reduction of multiple air, water and solid waste pollutants.

Gas-Based Options
The paper presents three options for utilities to use gas in conjunction with their base fuel coal - gas reburn, co-firing, and seasonal burn. Their applicability and cost-effectiveness will depend on site - specific conditions including: operating constraints, access to supply, capital and operating costs of competing options, and a myriad of federal, state and local regulations involving utility operations and the Clean Air Act. Each gas based strategy is inherently more flexible than stack control technology while providing collateral benefits in reducing multiple air pollutants: SO2, particulates, air toxics, and mercury. Natural gas options also mitigate the potential for ammonia slip and formaldehyde emissions that occur when using some stack control technologies. Additional non-air benefits from using incremental natural gas loads include: reduced ash and sludge disposal requirements and effects on ground and surface waters.

Incentives for Utilities
Options for utilities to use incremental amounts of gas as part of their compliance strategy can reduce up-front capital costs and increase operational flexibility while minimizing dependence on a single fuel. Competition in electric generation markets heightens the importance of implementing low capital cost and flexible solutions to regulatory challenges. Capital intensive compliance solutions may exacerbate the transition cost problem which will face utility shareholders and rate-payers in an emerging competitive generation market. Utilities have long recognized the need to keep their environmental compliance options open. This was evidenced by their Acid Rain Phase I decisions to primarily switch to lower sulfur coals to minimize capital cost.

It is important to thoroughly understand the incentives for utilities to consider gas options when evaluating compliance options. The ability of utilities to monetize all the benefits gas may bring to a particular facility's situation can help keep costs down for the utility customers. Since the total cost of compliance will ultimately drive many compliance decisions, cost avoidance and trading markets for collateral emissions reductions can provide additional benefits to utilities choosing to add gas to their fuel mix.

Gas Industry Improvements
The fundamental changes taking place across the gas industry have increased reliability of service, lowered delivered gas cost, and continue to provide new tools and services for price volatility risk management and transportation. Contracting for reliable gas supply in the new competitive gas industry is far different today from what many recall from the fully regulated situation that faced the industry and its customers in the 1970's.

While initial capital costs are lower for gas-based options, natural gas acquisition costs have generally been higher than that of coal. Short term price volatility and transportation capacity also raise some concerns regarding future delivered gas price levels and associated risk exposure. Through competitive changes in the gas industry many tools have been developed and used which enable gas consumers to mitigate much of the apparent risk.

Electric Utilities and The Clean Air Act


Importance of Flexibility
The 1990 Clean Air Act Amendments (CAAA) allow and in effect encourage utilities to address emissions problems through regulations that rely on market based solutions rather than the traditional command and control approach. Utilities now have the freedom and flexibility to creatively solve environmental problems. The hypothesis of this paper is that the successful utilities of the future will be the ones that find ways to meet their obligations at lower costs while increasing their operating flexibility and performance. Natural gas use in combination with the primary fuel, coal, can be an effective way to achieve this.

Why is flexibility so important? The CAAA produced a myriad of regulations for pollutants like SO2, NOx, Ozone, and air toxics. In some cases the regulations have been approved but the final standards are not yet known. Some of the standards are being phased-in over many years but are subject to change depending upon results of future testing and emission modeling. Compliance schedules are staggered out into the next century creating situations where utilities must develop and implement compliance plans without knowing the end goal. The reality of this situation makes it imperative that utilities not lock themselves into high capital cost environmental compliance solutions that may prove to be ineffective in the future.

Uncertainty
The regulatory process is also very dynamic with a pattern of environmental legislation tending to be more and more restrictive. Examples of issues being studied that could lead to further regulation are:

How Gas Fits In
Given the regulatory uncertainty that lies ahead, coal-burning utilities should be investigating all the available compliance options. One option to consider is the selective use of gas where it can be used to supplement rather than displace coal. Using just enough gas to gain an incremental reduction in emissions due to its clean burning characteristics may be the right answer. For example -- gas cofiring, reburn or seasonal use of gas can be low capital cost solutions that may help address situations where:
Adding a small amount of gas to the utility's portfolio of fuels provides the utility with another option to respond to the changing business environment. It also enables a utility to begin to understand the gas business and gain a degree of comfort in understanding how to purchase, store, delivery, and handle gas. The introduction of gas to a utility's fuel mix may introduce new technical, operation and organizational concerns that may take some time to resolve. However, those utilities that begin to use even a small amount of gas will be ahead of the learning curve in the event they need or decide to burn more substantial amounts of gas in the future to meet regulations.



Example: Utility Preference for Flexible Low Capital Cost Compliance Solutions: Phase I of the Acid Rain Program
In October 1991, Electrical World published a special report entitled "Equipment Options for Meeting the New Clean-Air Laws."[i] They said: "Early indications are that switching from high- to low-sulfur coal will be a dominant CAAA compliance strategy." They were right. 62% of the affected Phase I units have elected to fuel switch or blend coals. Another 15% elected to obtain additional SO2 allowances, 10% elected to install flue gas desulfurization, 9% have already met required reductions due to existing State regulations or other reasons, and 4% retired facilities or did boiler repowering.[ii] Of the 62% that fuel-switched, about 50,000 MW switched to lower sulfur coal or a coal blend and about 1000 MW switched to gas.[iii] Estimates of scrubbing requirements have dropped due to the availability of low-sulfur coal at reasonable costs. A total capacity for new scrubbing over both phases was projected to be 30-40 GW. Now, only about 14 GW of scrubbing is expected to be needed in Phase I.[iv]

The utilities' actions lead to two conclusions. One, utilities for the most part will look for low capital cost solutions when faced with an uncertain future. Two, the market approach strategy of the CAAA worked with each segment of the industry (coal suppliers, gas suppliers, equipment suppliers and allowance trading) competing for its share of the market.

Application & Benefits of Natural Gas Strategies

Natural gas can be used to complement coal in existing coal-fired boilers by leveraging the clean burning characteristics of gas to reduce emissions. Gas can also solve or improve some plant operational problems. Three major ways to use gas with coal are gas reburning, cofiring, and seasonal use of gas.

Gas Reburn
Natural gas reburning is a practical technique for achieving high levels of NOx control without chemical reagents or catalysts and, in some cases, without modifying or replacing existing burner equipment. In gas reburning, a small amount of natural gas, typically 10% to 20 % is injected above the primary combustion zone to create a fuel rich zone where NOx is reduced. Overfired air is injected above the reburning zone to complete combustion. Overfired air is injected above the reburning zone to complete combustion.

Conventional reburning can reduce NOx emissions by 50 to 70%. Gas reburning in a coal boiler has been able to lower NOx to around 0.25 lb. NOx/MMBtu[v]. Capital cost varies considerably but generally is about 20 to 30 $/kW, capital plus operating costs of 2.8 mills/kWh.[vi] In addition to providing leveraged NOx reduction, the replacement of some of the base fuel with natural gas results in proportional reductions of SO2, CO2, toxics and particulate (PM-10) emissions. The economics of these additional reductions should be part of the overall fuel selection economics.

Advanced gas reburning is the integration of conventional gas reburning and Selective Non-Catalytic Reduction (SNCR). It could play a role in helping achieve beyond RACT NOx reductions being contemplated by the Ozone Transport Region. Energy and Environmental Research has shown NOx emission reductions of about 85% in pilot scale tests and projects that a new design can achieve over 90% reduction. Full-scale demonstration of this technology is being considered by GRI and others.

The Gas Research Institute (GRI), the Electric Power Research Institute (EPRI), the US Department of Energy (DOE), the US Environmental Protection Agency (EPA) and others have cosponsored several demonstration projects that prove the viability of gas reburning. GRI recently agreed to cosponsor a gas reburn test for one of the cyclone boilers at Kodak Park.

Gas reburning offers these benefits: Application of Reburning for NOx Control in Cyclone Boilers
Gas reburning may be particularly attractive solution for cyclone boilers. Air and crushed coal are introduced through the cyclone burner into the cyclone barrel. The larger coal particles are thrust out to the barrel walls by the cyclonic motion of combustion air where they are captured and burned in the molten slag layer which is formed; the finer particles burn in suspension. The mineral matter melts and exits the cyclone via a tap at the cyclone throat which leads to a water-filled slag tank. The combustion gases and remaining ash leave the cyclone and enter the main furnace.

Typical Low-NOx burners and staged combustion techniques are not applicable to cyclone boilers because these techniques rely on developing a locally oxygen deficient or reducing atmosphere to hamper NOx formation. A reducing condition in the confines of a cyclone barrel is unacceptable due to the potential for tube corrosion and severe maintenance problems which result.

B&W has obtained encouraging results from an engineering feasibility study, a pilot-scale evaluation, and a U.S. Department of Energy Clean Coal II project to demonstrate the cyclone reburning technology on a full-size utility boiler[vii].[viii] [ix] The host site for the demonstration was the Wisconsin Power & Light s 110-MWe Nelson Dewey Station. A nominal 50% NOx reduction and no negative side-effects are well within capability of the reburn technology.

When a cyclone boiler is retrofitted with reburning technology, the cyclone owners would continue to burn coal in cyclones and use a nominal 25% of total boiler heat input into the reburn burners. When gas is the reburn fuel, approximately 25% of heat input is substituted from coal to natural gas. The choice of the reburn fuel is site-specific and depends on technical and economical factors. Availability of adequate boiler residence time and mixing between the reburn fuel and combustion gases are major technical factors. Economical factors would include (but not limited to) availability or ease of access to a gas line, the differential cost between coal and gas, and the operating conditions of the boiler (baseloaded/cycling, remaining life of boiler). For retrofit applications, it is recommended that site-specific engineering and economic feasibility studies, be performed - including the determination of the optimum fuel type, in order to assess the reburn technology potential.

Cofiring
Cofiring is the simultaneous firing of natural gas and pulverized coal in a boiler's primary combustion zone. The gas can be supplied to the boiler via ignitors, warm-up guns or gas burners. The gas input can vary from less than 10% to 100% of the total fuel input depending on boiler design and the needs of the boiler operator. Cofiring reduces SO2, CO2 and particulate emissions in proportion to the amount of gas used. It also cuts maintenance costs and improves boiler operations. NOx emissions also decline significantly, but the amount of reduction varies considerably between boilers. The equipment is commercially available and in some cases may already be in place. The installed capital cost is low, from $2 to less than $20/kW[x]. GRI has co-funded numerous projects that have successfully demonstrated the economics of cofiring.

Chevron has worked closely with PacifiCorp on a commercial cofiring project that began in May, 1994. The utility was close to complying with state 2 hour SO2 emissions, but not quite 100% of the time on coal. Cofiring was an economic choice for them that eliminated the need to add a scrubber. PacifiCorp spent $3 million at their Naughton Plant to make Units 1 & 2 gas capable. Had they installed a scrubber for Units 1 & 2, their capital cost would have been $75 million plus $2 million/year in O&M expenses. Unit 3 uses high sulfur coal and has a scrubber.

Only a small amount of gas is being intermittently used by PacifiCorp for cofiring because the current quality of the coal is very close to the emission standard. Having gas at the site gives the utility an economic alternative to reducing emissions if the coal quality changes in the future. This is a good example of gas providing the flexibility the utility needed at a capital cost lower than the scrubber alternative.

Some practical applications for cofiring are: The Gas Research Institute (GRI) and the Electric Power Research Institute (EPRI) have documented the benefits and costs of using natural gas through numerous tests. Some of the major benefits are:

Benefit Nominal Value
Mills/kWhr		 Range
Mills/kWhr
Fire low-cost coal 1.10 0.50 to 1.50
SO2 emission reductions 0.30* 0.30 to 3.00
Improved capacity factor 0.70 0.50 to 1.50
Salable ash 0.40 0.00 to 0.70
Improved Availability 0.20 0.00 to 1.00
Turndown 0.10 0.10 to 0.10
* Based on $150/ton allowance cofiring credit EPRI's report used $750/ ton SO2 removed, based on a 10-year levelized basis using Flue Gas Desulfurization. This equates to about 1.50 mills/kWhr for a unit with 10,000 Btu/kWhr, using a coal that emits 4 lb. SO2/MMBtu) Mills/kWhr equates to cents/MMBtu in this table. See Appendix for complete description of benefits of cofiring[xi]

This table illustrates that aggregating the benefits of gas can support a substantial spread between coal and gas prices. This is why it is extremely important to try to identify all the possible benefits. To put these values in perspective, the average gas to coal differential based on gas and coal delivered to utilities in 1993 was $1.23 per MMBtu[xii] .

Seasonal Use of Gas
Some states are addressing the seasonal nature of ozone formation in their NOx control requirements. For example, most States have accepted the EPA's RACT guideline for NOx control that allows a boiler owner to average the NOx emissions resulting from switching fuel during the year. Coal could be used in the winter with NOx emissions exceeding coal RACT as long as a cleaner fuel, like gas, is used in the summer months with emissions below coal RACT. The average for the year must be at least equal to coal RACT. This can be an important consideration for gas reburning economics because ozone formation peaks during the summer when gas prices are generally lowest. The seasonal use of gas can reduce the annual cost of NOx control.

Seasonal use of gas offers these benefits: Evaluation of Coal and Oil Boiler Performance and Emissions in Seasonal Gas Fired Operation1
The switching of a utility boiler from coal or oil to natural gas can result in significant reductions in NOx emissions, and such conversions have been performed at a number of stations. Because utility boilers are a major source of NOx in the Northeast Ozone Transport Region (OTR), NOx emission reductions from these facilities are expected to be an important component of the region's ozone attainment compliance strategy. NOx reductions of 50 percent or more are achievable by switching utility boilers to gas, however no studies have yet examined the potential for NOx emission reductions from the widespread switching of coal and oil utility boilers to 100 percent natural gas on a seasonal basis, April through October, in the OTR. The Coalition for Gas-Based Environmental Solutions sponsored a study by Energy Ventures Analysis, Inc. (EVA) to create an inventory of existing coal and oil units in the OTR, characterize current utility NOx emissions, and project NOx emission performance if the units switched to 100 percent natural gas on a seasonal basis. The study incorporated publicly available information submitted by utilities as well as information from facilities that have switched units from coal or oil to gas.

The study revealed that utilities' experience with switching coal or oil units to gas has shown very site-specific results on NOx emissions. The NOx reductions resulting from switching units to gas were related to expected factors such as boiler type and size, base fuel, and NOx controls, however emissions results from different units of similar design varied significantly. Some of the factors contributing to these differences included individual unit configuration, unit loading, operational settings, and base fuel characteristics. An important consideration when reviewing these experiences is that NOx reductions rarely have been the primary reason for switching to gas, consequently all units may not have been optimized for low NOx emissions. In some instances, units may have switched to gas to take advantage of seasonal price or availability benefits, or to achieve certain performance objectives, such as improved load following. In addition, several utilities report switching to gas to achieve other environmental goals such as reduced opacity and SO2 emissions.

Study Methodology
The study assesses the potential role of switching coal and oil boilers to natural gas for NOx control in the OTR. The first task was to identify all the utility boiler stations located in the OTR. EVA identified 343 utility steam electric power plant units located in the OTR, however 51 units are currently gas-fired and another 53 units were designated to be retired within the next 10 years according to utilities' integrated resource plans. The remaining 239 coal and oil boilers, which account for 80 percent (52.8 GW) of OTR generating capacity, represent the realistic population of potentially relevant units.

In its second task EVA characterized the baseline NOx emissions for the stations and determined the gas capability of each site. The information for the units was obtained from Form 767 data submitted to the Federal Energy Regulatory Commission (FERC). Because utilities are not required to identify their NOx emission estimate method, the data likely represent either the use of default EPA emission factors for boilers or, if available, stack test results. The baseline data represent 1992 emissions and do not incorporate NOx reductions expected to be made under the Reasonable Available Control Technology (RACT) and Title IV (acid rain) programs. The units were characterized as having one of four levels of gas capability: (1) no gas capability and investment required to gain access and convert unit, (2) some gas capability at station and investment required to expand deliverability and convert unit, (3) gas is an alternate fuel and investment may be required to expand deliverability, or (4) gas is primary fuel and no investment is needed.

Finally, the NOx performance of units converted to gas was assessed using information from several sources: (1) historic data from units converted to 100 percent gas capable, (2) projected performance for units planned to be switched, (3) survey of boiler manufacturers and A/E firms, and (4) existing data from GRI and EPRI research on switching units. Boiler manufacturers and A/E firms contacted by EVA were either unable or unwilling to provide formulae to estimate NOx reductions using publicly available data.

Summary of Results
The information compiled by EVA on the current status of utility boilers in the OTR is presented in Table 1. The total NOx emissions from all boilers in the OTR in 1992 were 806,900 tons, with coal boilers expected to be in service beyond 2002 accounting for 643,700 tons or 80 percent of the total. Utilities surveyed by EVA for this study experienced a range of NOx reductions from switching to gas with average NOx reductions of 50 percent in coal boilers and 36 percent in oil boilers. Because boilers often burn more than one fuel, when calculating potential NOx emission reductions from gas switching, the reductions are applied only to the base fuel. If the average utility results for NOx reduction are applied to the NOx emissions from the base fuel use, total emissions in the OTR from coal and oil-fired utility boilers would be reduced by 344,100 tons to 462,800 tons-NOx per year. Realistically, it is very unlikely that all or most utility boilers will be switched to 100 percent gas, however the analysis demonstrates opportunities for significant reductions in NOx emissions. Studies by other parties suggest that even greater reductions are possible, although these may be based on boilers that are most compatible with gas combustion and may not be attainable in all units.

Coal boilers generated most of the NOx emissions from utility boilers in the OTR and represent a major target for NOx reductions. Using FERC Form 767 data, EVA identified 11 units nationwide that had used 100 percent gas and were willing to disclose NOx emissions data. These units realized 11 to 75 percent reductions in NOx emissions with the average reduction being approximately 50 percent. Four of the 11 units achieved NOx emission rates of 0.2 lb/MMBtu when firing 100 percent gas, and the median average emissions were 0.28 lb-NOx/MMBtu. Studies by the EPA, GRI, and EPRI have suggested that reductions of 50 to 80 percent are possible by switching coal boilers to gas, but little supporting documentation was provided.

Oil-fired units produced 85,800 tons of NOx emissions in 1992. Emissions reduction data was available from 5 utilities that had converted oil boilers to gas. The utilities realized NOx reductions of 5 to 37 percent with the average being about 36 percent. The data suggests that emission levels of 0.2 lb-NOx/MMBtu would be achievable on an oil unit switched to gas if additional NOx control measures such as overfire air, flue gas recirculation, and/or staged combustion are implemented. In two cases, utilities thought emissions of 0.15 lb-NOx/MMBtu were realized.

Some utilities reported problems in using 100 percent gas in their coal and oil boilers. Several utilities experienced derates or slight losses of boiler efficiency. Because some oil boilers are designed for heat release rates significantly higher than coal or gas boilers, switching these units to 100 percent gas could result in unit derates. These problems appeared to be technical limitations of particular units and are not expected to be encountered in other gas switching applications. A summary of factors influencing NOx emissions is detailed in Table 2. EVA's report contains the complete inventory of OTR utility boilers including boiler type and capacity, fuel consumption and quality, and 1992 reported NOx emissions.

While the experience of the utilities revealed a range of NOx reductions when switching coal and oil boilers to gas, it seems that reductions in the 30 to 50 percent range are typical and significantly greater reductions can be achieved through boiler optimization. Given the significance of utility boilers as a source of NOx in the OTR, it appears that switching these units to 100 percent gas may represent an important attainment measure.

TABLE 1
NOx EMISSIONS FROM OTR UTILITY BOILERS IN 1992

Coal Boilers Oil Boilers
Number of Stations 138 93
Capacity (GW) 31.4 20.8
Total Fuel (million MMBtu/yr) 1,777 487
Base (Coal/Oil) Fuel
(million MMBtu/yr)
 1,749 446
Total NOx (tons/yr) 643,700 83,400
Base Fuel NOx (tons/yr) 633,200 76,400
Typical NOx Reduction 50% 36%
Potential NOx Reduction (tons/yr)
(from switching to 100% gas)
316,600 27,510
Source: FERC Form 767 Data
Does not include units scheduled for retirement before 2002.

NOTES:

1 Excerpt from "Evaluation Of Coal And Oil Boiler Performance And Emissions In Seasonal Gas Fired Operation" - a study performed by Energy Ventures Analysis, Arlington, Virginia for the Coalition for Gas Based Environmental Solutions. November 1994.

i Bretz, E.A., "Equipment Options for Meeting the New Clean-Air Laws," Electrical World, October 1991, pp. 52-54

ii "Acid Ran Compliance Strategies for the Clean Air Act Amendments of 1990," Energy Information Administration, DOE/EIA-0582, March 1994, pp. x

iii Huetteman, T.J., "Environmental Constraints and Fuel Competition in Electric Generation Markets," Presentation to Institute of Gas Technology, Seventh International Symposium on Energy Modeling, April 26, 1994

iv Torrens, I.M. and Platt, J.B., EPRI, "Electric utility response to the Clean Air Act Amendments," Power Engineering, January 1994, pp. 43

v ""Reburn Projects Meet Goals," Power Generation Tech Update A publication of Gas Research Institute on the use of natural gas in utility electric power generation. September 1994, vol. 2, no. 1

vi "Reduction of NOx and SO2 Using Gas Reburning, Sorbent Injection and Integrated Technologies," Clean Coal Technology, Topical Report Number 3, September 1993, pp. 13

vii G.J. Maringo, etal., "Feasibility of Reburning for Cyclone Boiler NOx Control," EPA/EPRI Joint Symposium on Stationary Combustion NOx Control, New Orleans, Louisiana, March 23-27. 1987.

viii H. Farzan, etal., "Pilot Evaluation of Reburning Cyclone Boiler NOx Control," EPA/EPRI Joint Symposium on Stationary Combustion NOx Control, San Francisco, California, March 6-9, 1989

ix H. Farzan, etal., "Reburning Scale-Up Methodology for NOx Control from Cyclone Boilers," International Joint Power Generation Conference, San Diego, California, October 6-10, 1991

x "Gas Cofiring A Viable Dual-Fuel Option," Prepared by Energy and Environmental Analysis for the Gas Research Institute, pp. 2

xi "Gas Cofiring for Coal-Fired Utility Boilers," Prepared by SFA Pacific, Inc. Mountain View, California and Electric Power Technologies, Inc., Menlo Park, California. EPRI TR-101512, November 1992

xii "Monthly Energy Review," EIA, August 1994

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This page was placed October 6, 1996; last updated August 31, 1997.