The coal-fired Williams and Wateree plants of South Carolina Electric & Gas were subject to review for emissions under the Best Available Retrofit Technology (BART) rules under the U.S. Environmental Protection Agency’s regional haze program, but look to be in good shape due to past compliance actions.
EPA, in a Feb. 28 Federal Register notice, said it is proposing a limited approval of a revision to the South Carolina state implementation plan (SIP) submitted by the South Carolina Department of Health and Environmental Control (SC DHEC). This revision addresses the requirements of the Clean Air Act and EPA’s rules that require states to prevent any future and remedy any existing anthropogenic impairment of visibility in mandatory Class I areas (national parks and wilderness areas). States are required to assure reasonable progress toward the national goal of achieving natural visibility conditions in Class I areas.
EPA is proposing a limited approval of this SIP revision on the basis that the revision, as a whole, strengthens the South Carolina SIP. EPA has previously proposed a limited disapproval of the South Carolina regional haze SIP because of deficiencies in the state’s submittal arising from the remand by the U.S. Court of Appeals for the District of Columbia Circuit to EPA of the Clean Air Interstate Rule (CAIR). Consequently, EPA is not proposing to take action in this rulemaking to address the state’s reliance on CAIR to meet certain regional haze requirements. Comments on this proposed partial approval are being taken until March 29.
Of the 21 BART-eligible sources, 19 sources demonstrated that they are not subject to BART, EPA noted. Seven of the 19 (Albermarle, BP Amoco Chemical-Cooper River Plant, Rhodia-Charleston, Eastman Chemical, INVISTA-Spartanburg, Owens Corning-Anderson, Milliken Chemical-Dewey) are exempt from further BART review because they are only major sources for volatile organic compound emissions. Twelve of the 19 (Bowater, DAK Americas, International Paper-Georgetown, INVISTA-Camden Plant, ISG Georgetown, MeadWestvaco-Kraft Mill, Santee Cooper-Jefferies, Santee Cooper-Winyah, Santee Cooper-Grainger, SCE&G-Canadys, Stone Container-Florence, Wellman-Palmetto) are not subject to BART because their modeled visibility impact is less than a legal threshold.
In addition, although modeling exempted them from BART, DAK Americas took an emissions limit for further assurance of their exemption. South Carolina found that two of its BART-eligible sources, SCE&G’s Williams and Wateree plants, had modeled visibility impacts of more than the minimum threshold for BART exemption and are considered to be subject to BART. SCE&G Williams and Wateree, the two BART-eligible electric generating units (EGUs) in the state, relied on CAIR to satisfy BART for SO2 and NOx. Therefore, these facilities were only required to evaluate PM emissions in their BART determinations. Because of the court remand of CAIR, EPA is not taking action in this proposed rulemaking to address the state’s reliance on CAIR to meet certain regional haze requirements, including BART for SO2 and NOX emissions from EGUs.
New Wateree and Williams scrubbers help with attainment
SCE&G Wateree consists of two identical pulverized coal-fired, wet bottom boilers (Units 1 and 2). Units 1 and 2 are equipped with fabric filter baghouses to control PM emissions, and low-NOx burners and selective catalytic reduction (SCR) to control NOx emissions. SCE&G also installed two wet limestone scrubbers to control SO2 emissions in the summer of 2009. Although designed to control SO2 emissions, the FGD systems provide the added benefit of removing sulfates, a principal constituent of condensable PM10. The operation of the FGD systems is projected to reduce visibility impacts to well below the state’s BART contribution threshold.
To address the BART requirement at Wateree, SCE&G prepared an analysis of several additional options for PM10 addressing the statutory factors. The cost effectiveness of the various options ranged from $11,238 to $19,056 per ton of PM10 removed. SC DHEC determined that the additional annualized costs associated with additional PM10 control options were excessive and that no additional control measures were cost effective.
SCE&G Williams consists of a single pulverized coal-fired, dry bottom boiler (Unit 1). Unit 1 is currently equipped with low-NOx burners and SCR to control NOx emissions and an electrostatic precipitator to control PM10 emissions, the latter of which has been demonstrated to achieve performance levels comparable to those being specified as best achievable control technology for new coal-fired boilers. The existing control device, therefore, is considered representative of BART for PM10.
To address the BART requirement, SCE&G evaluated for Williams several additional options for control of PM10 and addressed the statutory factors. The cost effectiveness of the various options ranged from $307,420 to $376,318 per ton of PM10 removed. SC DHEC determined that the additional annualized costs associated with additional PM10 control options were excessive and that no additional control measures were cost effective.
In 2009, SCE&G retrofitted Williams Unit 1 with a FGD system using limestone slurry in a spray tower to remove SO2 from the gas stream. Although designed to control SO2 emissions, the FGD system will provide the added benefit of removing sulfates. PM10 emissions will be reduced from 925 tons per year to 464 tons per year following the installation of the FGD system.
Coal changes at industrial plants seen as too expensive
Under the reasonable progress section of the regional haze program, EPA and the state of South Carolina evaluated compliance options for coal-fired industrial plants. EPA is now proposing to approve the state’s findings.
DAK Americas operates a facility in Moncks Comer that produces chemical fibers. Boiler No. 2, a 206 MMBtu/hr bituminous coal-fired boiler, was subject to a reasonable progress control review. Currently, the existing air pollution control device is a baghouse to control PM and a 1% sulfur limit on the coal supply. Boiler No. 2 is the only coal-fired boiler at the site. SC DHEC reviewed five technologies for reasonable progress: low-sulfur coal, wet FGD, spray dryer absorber (SDA), fluidized-bed combustion, and dry sorbent injection. The FGD and SDA options are the most cost-effective options but would only reduce emissions 33–48 tons and are anticipated to be $3,758 and over $4,000 per ton, respectively. SC DHEC deemed all the available control options to be above its $2,000 per ton of SO2 controlled cost effectiveness threshold.
Giant Cement Co. has a Portland cement manufacturing facility located in Harleyville. In 2005, Giant completed the modernization of this facility. The modernized facility consists of one dry process cement kiln system that replaced four wet process cement kilns. The modernized cement kiln system is more energy efficient than the previous wet process cement kilns. A Prevention of Significant Deterioration (PSD) permit to construct and operate the kiln system was issued in 2003, and the first clinker was produced in March 2005.
Based on the information in the reasonable progress control analysis that Giant provided, SC DHEC concluded that switching to low-sulfur coal is not a cost-effective solution to address SO2 emissions at the Giant facility. Sulfur input to the cement kiln system as a result of coal usage is less than 5% of the total sulfur input, which corresponds to between 55 and 69 tons of SO2 emitted per year. Switching to a low-sulfur coal reduces emissions between 24 and 36 tons of SO2 per year, but at a cost ranging from $7,801 to $11,152 per ton of SO2 reduced. SC DHEC concluded that none of the control options would be below its cost effectiveness threshold for reasonable progress.
Holcim (US) Inc.’s Holly Hill plant produces Portland cement. The two wet process cement kilns identified in the reasonable progress analysis at the Holly Hill facility were shut down in 2003 and eventually demolished. They were replaced with a single, more efficient preheater precalciner kiln system which began operation in 2003. Holcim prepared a reasonable progress control analysis to assess the potential switch to lower-sulfur fuel oil from 3% sulfur coal, which is the sulfur level that the current permit is based upon. The analysis demonstrated that this switch would result in a maximum SO2 reduction of 4,011 tons at an additional cost to Holcim of $41,039 per ton of SO2 removed. SC DHEC concluded that additional reductions from this facility would be above its cost effectiveness threshold.
International Paper operates a paper mill located in Georgetown. Units subject to a reasonable progress analysis are the No. 1 Power Boiler, No. 2 Power Boiler, No. 1 Recovery Boiler, and No. 2 Recovery Boiler. The power boilers currently burn a diverse fuel mix consisting of wood, coal, tire-derived fuel, fuel oil, natural gas and propane. These power boilers are permitted for several additional fuels that are currently not being utilized. The fuels that contribute to sulfur emissions are coal, tire-derived fuel and No. 6 fuel oil. The recovery boilers primarily burn black liquor solids, but also burn limited amounts of No. 6 fuel oil, primarily during start-up.
International Paper prepared a reasonable progress control analysis for the Georgetown plant which looked at three options. The first option was to replace all coal, No. 6 fuel oil and tire-derived fuel with natural gas. The second option was to replace all sulfur fuels with low-sulfur fuel oil. The mill’s title V permit limits No. 6 fuel oil consumption in the power boilers. Therefore, the second option was looked at two ways: replacing as much fuel oil as possible with low sulfur fuel oil and leaving the balance as natural gas; and, assuming the mill would not be limited on firing low-sulfur fuel oil, calculating a complete fuel switch to low-sulfur fuel oil. The third option was to replace all coal, No. 6 fuel oil, and tire-derived fuel with low-sulfur distillate oils. The annual SO2 emissions reductions from these options ranged from 2,281 to 3,284 tons of SO2. However, the cost-effectiveness estimates for the fuel switching options ranged from $6,417 to $10,012 per ton SO2, which are above SC DHEC’s cost-effectiveness threshold.