By Connie Senior, Director of Technology Development, ADA-ES, Inc.
This article examines the selection and procurement of equipment for control of mercury air emissions from coal-fired utility boilers.
MATS rule and implications for emissions control
EPA was charged, under Section 112 of the Clean Air Act (CAA) and recent court decisions, to determine a National Emission Standard for Hazardous Air Pollutants (NESHAP) for coal- and oil-fired electric utility boilers. EPA’s response under the CAA was the MATS rule, which was published in the Federal Register in February 2012. Compliance with the rule is required within 60 days plus three years of publication, which means that the compliance deadline for MATS is April 2015. States can grant one-year extensions, so some utilities will have until April 2016 for compliance.
The emission limits for mercury, particulate matter (PM) and acid gases for existing coal-fired boilers in the MATS rule are given in Table 1. Mercury limits are specific to coal rank; at least 80 to 90 percent reduction of mercury will be required for bituminous- and subbituminous-fired boilers and 60 to 80 percent reduction will be required for lignite-fired boilers. However, limits for other pollutants are not dependent on the coal rank. Plants that already have SO2 control will be allowed to use an alternate limit on SO2 emissions to control acid gases. Otherwise, HCl emissions must be controlled.
What are the technology options?
There are a number of factors that affect mercury removal from coal flue gas. Because of the complexity of the interactions between mercury and other flue gas constituents, there are not “one-size-fits-all” solutions for mercury emissions control, in contrast to the options for control of SO2.
The major methods for controlling mercury emissions are (1) use of air pollution control devices (APCDs) for other pollutants (the “co-benefits” approach); (2) activated carbon injection (ACI), with or without a halogen additive; and (3) ACI plus another technology, such as an alternate flue gas conditioning agent or dry sorbent injection (DSI). The selection of one of these methods depends on a number of factors.
By themselves, ACI and DSI are simple, low-cost systems, which consist of a storage silo, a feeding system, and a distribution system. Multiple lances are inserted into the flue gas duct to disperse the sorbent. The sorbent is collected in the boiler’s particulate control device, either a baghouse or an electrostatic precipitator (ESP). The sorbent can be injected either upstream or downstream of the air preheater. The injection location is determined by the available residence time in the duct (which is critical for injection upstream of an ESP) and by potential interference from SO3 flue gas conditioning, in the case of ACI. Computational fluid dynamics (CFD) modeling is typically carried out as part of the design process in order to achieve the best possible sorbent distribution in the duct.
Addition of halogens to the fuel, if desired, is typically accomplished by spraying an aqueous solution containing a halogen salt onto the coal feed belt.
Which technology is right?
The good news for utilities is that, for most boilers, one of the methods for mercury control will allow the boiler to meet the MATs limit. Deciding which approach is the best requires a combination of experience and, in many cases, field testing of candidate technologies.
In general (as illustrated in Table 2), achieving MATS limits on boilers burning low-rank coals (subbituminous and lignite) can be done using ACI, with or without a halogen additive for the following configurations: baghouse; an ESP in series with a baghouse (EPRI’s patented Toxecon process; or dry flue gas desulfurization (FGD). Low-rank boilers that have an ESP often inject SO3 for flue gas conditioning (FGC). The effectiveness of activated carbon can be sharply reduced in the presence of high levels of SO3. In such cases, a utility should consider an alternative FGC agent, fuel switching or the installation of a Toxecon baghouse downstream of the ESP in order to get the needed performance from an ACI system.
Utilities that sell their fly ash for concrete manufacture need to be careful in selecting the appropriate mercury sorbent. Most activated carbon vendors offer “concrete-compatible” carbons, which are supposed to have minimal impact on fly ash properties. Non-carbon mercury sorbents are available for demonstration testing, although these sorbents have not been used commercially yet.
Boilers burning low-sulfur bituminous coals can achieve the MATS limits as long as the SO3 concentration in the flue gas is not too high, as it would be if the boiler had a selective catalytic reduction (SCR) unit for NOx. SCRs oxidize some fraction of the SO2 in the flue gas to SO3. Injection of alkaline sorbents (e.g., trona, hydrated lime) using a DSI system can reduce the concentration of SO3 and improve the performance of ACI for mercury capture.
Boilers burning high-sulfur bituminous coals face more difficulty than those burning low-sulfur bituminous coals, because of the higher concentrations of SO3 in the flue gas. A DSI system can remove SO3 from the flue gas and increase the ability of activated to remove mercury.
For boilers that have a wet or dry FGD, the “co-benefit” approach is often a viable control option. In order to get the high levels of removal needed for MATS compliance, 90 percent or more of the mercury must be in the gaseous oxidized form (Hg2+) at the scrubber inlet, as illustrated in Figure 2 with full-scale data taken from published Department of Energy (DOE) and Electric Power Research Institute (EPRI) field tests. Dry FGDs appear to be more effective at removing oxidized mercury, because in wet FGDs some of the absorbed Hg2+ can be re-emitted as Hg0. A number of vendors sell wet FGD additives to cut down on the amount of mercury re-emission.
To get to the level of mercury oxidation shown in Figure 2, the native chlorine in the coal must be very high (2000 µg/g or greater) or additional halogen must be added to the fuel or flue gas. In many cases, a bromine compound is added to the fuel in concentrations that are equivalent to an additional 50 to 150 µg/g bromine in the fuel (about 2 to 6 ppmv additional HBr in the flue gas).
SCRs oxidize mercury effectively if sufficient halogen is present in the flue gas. Boilers with both an SCR and an FGD can often achieve the MATS limit for mercury with sufficient halogen present and, in the case of boilers with wet FGD, low re-emission of mercury across the scrubber unless the SO3 is too high. Activated carbon could be used for “trim control” in many SCR-FGD boilers, in order to remove the incremental mercury needed to meet the limit.
With any new technology, the balance-of-plant impacts must be considered.
Potential issues with ACI and halogen addition include impact on fly ash sales, increased corrosion rates, increased PM emissions, and multimedia emissions of trace metals. Where there is a concern about balance-of-plant impacts, demonstration field testing is strongly recommended.
Navigating the Procurement Process
Some retrofit technologies or upgrades needed for MATS compliance can be installed before 2015 without much difficulty, but other technologies will require more time. ACI for mercury control and DSI for acid gas control, if needed, can be procured and installed before 2015 in many cases (providing the utility starts the process in 2012), because these systems have a typical lead time of 18 months, according to a recent report by The Brattle Group. Before selecting a control technology, field testing of technologies for mercury control is often a good idea, as illustrated in Figure 3.
Because the MATS rule is a multi-pollutant rule, MATS compliance will require resources (construction labor, materials, shop time) that might be in short supply locally or nationally. Bottlenecks in resources (e.g., the availability of boilermakers) could cause additional delays. Most of the construction and installation activities for retrofits can take place with the units on line. If an outage is needed for the final tie-in to the boiler system, it often can be scheduled concurrently with a plant’s maintenance outage. The Brattle Group analyzed data on the length of outages for coal-fired boilers with and without equipment installation. On average, less than a week of additional outage time was required to install ACI or DSI.
The need to control multiple pollutants provides challenges for the utility industry as they prepare for achieving April 2015 compliance with the MATS rule. In addition to compliance with mercury emission limits, plants must manage compliance with new limits on acid gases and PM, as well as the associated balance-of-plant impacts of these control technologies. Activated carbon injection and/or halogen addition will allow plants to meet the MATS limits, if they are proactive in planning, testing and procurement.
Celebi, M.; Spees, K.; Liao, Q.; Eisenhart, S. Supply Chain and Outage Analysis of MISO Coal Retrofits for MATS. The Brattle Group, Cambridge, MA, May 2012.
Connie Senior is the Director of Technology Development at ADA-ES, Inc in Highlands Ranch, Colo. She has been working in the area of coal combustion and emissions control for over 30 years. She has a BSChE degree from Rice University and a PhD from the California Institute of Technology in Environmental Engineering Science.