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Gallatin Environmental Integrity Program

Issue 4 and Volume 122.

As a result of new and more stringent environmental regulations, the power industry faces a twofold challenge to significantly reduce sulfur dioxide (SO2) and other acid gases, mercury (Hg), particulate matter (PM) and nitrogen oxides (NOx) from air emissions while concurrently eliminating wet disposal of ash generated by coal fired power plants.

The Tennessee Valley Authority’s Gallatin Air Quality Control System (AQCS) Project is a robust response to this challenge with the application of a state-of-the-art dry scrubber and selective catalytic reduction (SCR) air quality control technology and an industry-leading on-site dry ash storage process.

TVA’s Gallatin Plant is located on the Cumberland River – Old Hickory Lake near Gallatin, Tennessee. The coal-fired station consists of four twin furnace tangentially fired boilers each with low NOx burners.

The Gallatin Plant provides power to more than 560,000 residences and businesses and employs over 200 in the Nashville region. The Project extends the life of the TVA Gallatin Fossil Plant for the next 20 years by addressing the needs for air quality improvement and lined disposal of coal combustion residuals (CCR).

Three primary elements of design and construction were included: (1) four dry scrubber units, which reduce SO2, Hg, Hydrogen Chloride (HCl) and PM emissions, (2) four (SCR) units which reduce NOx, currently under construction (3) a new EPA-compliant dry, lined landfill facility on plant property for providing storage needs for the 400,000 cubic yards of dry CCR generated yearly and (4) a one-mile haul road corridor that connects the scrubber facility with the landfill. Several aspects of the AQCS Project will be discussed including system design overview, challenges and performance.

Fleetwide Strategy

In support of its compliance with the Environmental Protection Agency’s (EPA’s) Clean Air Acts and as a means of enhancing the quality-of-life for Valley residents and being a good steward of the Valley’s natural resources, TVA has invested significantly in an aggressive fleetwide clean air control program. In addition, TVA has committed to closing wet coal combustion residuals (CCR) impounds, converting wet ash management facilities to dry ash management, across the fleet.

In order to reduce NOx, TVA has installed SCR technology on 21 of its coal units resulting in a 92 percent reduction in NOx emissions since 1995. All of TVA’s natural gas-fired combined cycle plants have SCRs to reduce NOx emissions. Figure 1 shows the progressive reduction in NOx Emissions at TVA power plants, from a peak in 1995.

To reduce SO2 emissions, TVA has switched to low-sulfur coal at some fossil plants and equipped approximately 70% of its coal-fired capacity with scrubbers. TVA has reduced SO2 emissions by 94 percent since regulations began in 1977. Figure 2 shows the progressive reduction in SO2 emissions at TVA power plants from a peak in 1977.

Commensurate with TVA’s fleetwide master strategy, a large scale AQCS retrofit was undertaken at Gallatin Fossil Plant. Planning for the AQCS retrofit began in 2011and detailed design and construction for the installation began in 2013.

Gallatin Fossil Plant Overview

Gallatin Fossil Plant (GAF) is located on 1950 acres of land on the north bank of the Cumberland River in Sumner County, Tennessee, approximately seven miles south of the nearby town of Gallatin. The plant has four generating units with a combined summer net generating capacity of 976 megawatts. Groundbreaking occurred in 1953. The first of the four generating units went into operation in 1956.

Figure 3 provides an aerial view of the GAF plant and facilities prior to the start of AQCS installation in 2013.

The four generating units are Alstom/CE twin furnace tangentially fired boilers. Units 1 & 2 each have a maximum continuous rating (MCR) of 250 MW Gross and Units 3 & 4 each have a MCR of 275 MW Gross. Prior to the start of the new AQCS projects, emission control on these units was Electrostatic Precipitators (ESPs) to collect fly ash and low NOx burners to limit emission of NOx on each boiler

From the beginning of plant operations in the 1950s until 2015, coal ash was handled via wet sluicing operations. Historically, GAF consumed approximately four million tons of coal which yield approximately 235,000 tons of fly and bottom ash CCRs annually but has varied historically based on consumer demand.

GAF AQCS Project

The new AQCS at Gallatin includes SCRs to reduce NOx emissions and dry flue gas desulfurization (DFGD) scrubber units to reduce SO2, Hg, and PM emissions on all four units. The first two scrubber units went into operation in Spring 2015 and the final unit went into service in February 2016. The first two SCR units went into operation in Spring 2017, while the last two are planned to be in operation by the end of 2017. Figure 4 is a rendering of the plant with all AQCS additions.

DFGD

The new DFGD systems at Gallatin are currently operating on all four units. The DFGD systems are designed to reduce SO2 emissions nominally by 96%.

The retrofit and installation project also included replacement of the existing Induced Draft (ID) Fans, and decommissioning of the existing ESPs. New ID Fans were installed to provide for the additional flue gas pressure drop in the DFGD system and SCR project components.

Various commercially available DFGD technologies were considered and bids were solicited for the application of two types of technologies: circulating dry scrubber and spray dryer absorber. After a detailed bid evaluation, a type of circulating dry scrubber technology was selected. Each Unit was retrofitted with a DFGD System, consisting of an absorber followed by a pulse jet fabric filter (PJFF) to control SO2, SO3, HCl, Hg, and PM emissions.

The two main reagents used in the DFGD system are pebble lime for SO2, SO3 and HCl removal and activated carbon for Hg removal. Fly ash and DFGD reaction byproducts are removed in the PJFF and collected in the PJFF hoppers.

SO2 / SO3 / HCl Removal

The primary processes utilized in the acid gas removal technology are (1) the introduction of water to lower the gas temperature and (2) the reaction of the acidic gases with hydrated lime to form and then remove the calcium salts. As the chemical reaction is facilitated in the liquid film, in principle, the closer the gas is cooled to the adiabatic saturation temperature of the flue gas, the higher the removal efficiency will be. However, the closer the gas is to the adiabatic saturation temperature, the higher the corrosion potential and the need for expensive corrosion resistant materials of construction as well as the potential for wet solids build-up on the scrubber surfaces. In practice, the removal efficiencies required at GAF can be achieved at a 35°F approach to the adiabatic saturation temperature. Consequently, the operating temperature is limited to no less than a 35°F approach to the adiabatic saturation temperature.

Mercury Removal

The chemistry related to mercury in coal as it goes through combustion and downstream flue gas treatment processes is quite complex. Elemental mercury in the flue gas is oxidized to an extent depending upon the type of coal burned, the constituents of the flue gas and the presence of catalytic reactors in the flue gas path. As such, there are three forms of mercury in the boiler flue gas: elemental (Hg0), oxidized (Hg2) and particulate-bound Hg. In the DFGD system, most of all three of these forms of mercury are removed with the other solids in the PJFF. The mercury removal is enhanced by adsorption on the activated carbon injected in the flue gas at the inlet of the fabric filter.

PM Removal

Flue gas flows from each absorber to a dedicated PJFF. The PJFFs remove the dry solid reaction products, unreacted reagent and fly ash entrained in the flue gas before the flue gas is discharged to the atmosphere.

The fabric filter bags collect a layer of solids on their outer surfaces between cleanings and the movement of the flue gas through this layer enhances the gas-solid contact. Over time, the filter cake collected on the bags becomes too thick and must be cleaned off the bags. The filter bag cleaning system is designed for on-line and off-line cleaning of PJFFs. The cleaning system is fully automatic and utilizes compressed air for cleaning.

Each fabric filter is furnished with a fluidized trough hopper. Blowers introduce fluidizing air into the fluid trough to keep the solids fluidized. The recycled solids are sent back to the absorber with the remainder of the solids going to the byproduct & flyash (BPFA) handling system for disposal.

A unique feature for the PJFF units was the use of 10 meter fabric filter bags. By using the longer bags, the number of fabric filter modules was reduced to four, limiting the overall footprint of the units.

BPFA Handling and Disposal

The BPFA generated by the new DFGD systems is characterized as (CCR). The material contains both fly ash and free lime, resulting in a CCR that exhibits cementitious properties i.e., reacts and hardens in the presence of water. It is projected that the units will produce between 435,000 and 932,000 cubic yards of CCR per year.

BPFA material is discharged from each PJFF and directed to storage silos via a vacuum conveying system. Each BPFA storage silo has a dedicated fluidizing system which keeps the BPFA in a suspended, fluidized state and promotes the flow of the BPFA towards the silo outlets.

The BPFA is conditioned and discharged to trucks for transport to a new onsite Landfill.

Landfill

Prior to the installation of the new DFGD systems, CCR’s generated at GAF were wet sluiced to an on-site 400 acre ash pond complex. The dry CCR generated by the DFGD system is stored in a new, lined on site landfill. The landfill was designed to accommodate 20 years of CCR storage capacity, with footprint of approximately 52 acres.

SCR

The SCR systems at GAF are currently being installed and are designed to reduce NOx emission from 0.4 to less than 0.03 lbs/MMBtu, achieving a reduction efficiency of greater than 92.5 percent.

One SCR reactor is installed for each generating unit and will tie in to the existing boilers at the outlet of the economizer section. The flue gas exiting the SCR units will return to the existing Air Preheaters. The SCR systems utilize anhydrous ammonia (NH3) as the reducing reagent.

Conversion of NOx in boiler flue gas is accomplished by mixing a reducing agent (ammonia) with the flue gas. The flue gas, mixed with ammonia, is then passed through a catalyst to promote a selective reaction of the reducing agent with the NOx to form nitrogen gas and water vapor. The catalyst is configured in layers in a vertical flow reactor vessel in which flue gas enters from the top and exits from the bottom. The mixing of the reducing agent and the flue gas is accomplished in the gas duct upstream of the reactor vessel. The ammonia is supplied to the flue gas by a number of lances arranged within the reactor inlet duct. A system of static mixers is employed to promote turbulent flow and mixing of the gas and ammonia.

The flue gas mixing system was designed to sufficiently mix reagent ammonia and flue gas such that the Ammonia to NOx distribution at the inlet face of the first layer of catalyst will be less than or equal to 2 percent RMS at full load and not more than 5 percent at minimum load. The relationship between Ammonia to NOx distribution and observed Ammonia slip is evident in Figure 6.

Muzio et. al (2009) derived the plot shown in Figure 6, using FERCo’s process model for SCR performance. In this figure ammonia slip is plotted as a function of NOx reduction for varying Ammonia to NOx distribution. It is evident from the plot that for overall NOx conversion greater than 90 percent the Ammonia to NOx distribution becomes increasingly important. In order to reach a target 2ppm ammonia slip, the maximum achievable NOx conversion is nominally 93 percent with the required Ammonia to NOx distribution approaching 2 percent RMS. While these results are based on a model plant, the relationship between conversion efficiency slip and distribution should hold constant for any medium sized coal fired unit. It is expected that the achieved mixing may degrade over time due to ash deposition and buildup. Therefore design for a lower catalyst inlet Ammonia to NOx distribution at 2 percent RMS affords greater margin to meet the design conversion and slip requirements within the operating life of the catalyst.

Anhydrous Ammonia Tank Farm and Vaporizer

A new Anhydrous Ammonia Tank Farm and Vaporizer (ATF) system was installed to receive, store and deliver ammonia vapor to the SCR units. This system consists of three 18,000 gallon ammonia storage tanks, forwarding pumps and vaporizer units, as well as truck unloading facilities.

Air Preheater Modifications

All four units at GAF utilize three (3) regenerative type air preheaters which were placed in operation when the units initially were placed in operation in the late 1950s. All twelve existing air preheaters utilize a Bi-Sector configuration and originally employed a 3-layer construction typical of the era that the units were built.

The operation of a conventional 3-layer air preheater downstream of an SCR system poses the threat of fouling the air preheater heat transfer surface. Ammonia slip from the SCR combines with SO3 and water vapor to form ammonium bisulfate (ABS). ABS deposits are sticky and readily combine with fly ash to form a difficult to remove deposit on the air preheater heat transfer surface. The temperature zone at which ABS forms occurs near the center of a typical air preheater, far from cleaning equipment installed at either the hot or cold side of the APH rotor.

The location of the deposits in conjunction with the presence of a gap between the hot and intermediate layers, as well as the open-channel configuration of the intermediate elements, severely limits the capability of cleaning systems to remove ABS deposits in a conventional 3layer configuration.

In order to mitigate the effects of ABS deposition a new basket configuration was developed for the GAF units. The new configuration utilized deeper cold end elements and eliminated the intermediate layer. The depth of the cold end layer was set to ensure that the ABS deposition zone would fall solely in these elements. Further, new closed channel elements were utilized for this layer to ensure that the maximum sootblowing steam penetration could be achieved. Finally, new cold end steam sootblowers were also installed on all Units. This combination of modifications and cleaning devices has been proven to effectively mitigate the impact of ABS deposition in air preheaters operating downstream of SCRs.

Boiler Modifications

Boiler modifications, including the removal of economizer heat transfer surface for Units 3 & 4 as well as the installation of Hot Water Recirculation Systems (HWRS) for all units, was required to ensure that flue gas entering the SCR units exceeds the minimum operating temperature for the complete load range.

Prior to modification of the Unit boilers, the temperature of the flue gas exiting the economizer was too low for normal SCR operation at low load. The SCR units are designed to operate in the range of 620 – 690oF. At temperatures below the design operation range, SO3 in the flue gas will react with ammonia to form ammonia sulfur salts (ammonium sulfate and bisulfate) that deactivate the catalyst.

An extensive study was completed to evaluate the options for control of the economizer gas outlet temperatures.

Utilizing operating data gathered in December 2011 the existing boiler units were modelled. The models were used to evaluate options and established general operating impacts under each of several gas temperature control configurations.

In particular the goal of the analysis was to select modifications that would increase the flue gas temperature over the complete load profile while also minimizing the impact to the unit thermal efficiency.

Environmental Compliance

The DFGD Systems are designed to meet the emissions limits summarized for the specified 20 years design life. All equipment is specified to support these performance guarantees.

The SCR systems are designed to meet the emissions limits and performance guarantees.

The units currently utilize a 100% Powder River Basin (PRB) coal.

The systems are designed to meet the performance requirements stated in Tables 1 and 2 for both the PRB coal and a 50%/50% blend of PRB and Eastern Bituminous coals.

Project Results and Performance

Units 1 & 3 operating data was collected during the 2015 and 2016 operating years in order to analyze the performance of the DFGD systems. During this period the units burned 100% PRB coal.

Unit 1 average SO2 emissions were analyzed during the months of June and August of 2015, prior to the DFGD system being placed into service, and compared to data sets from February and March of 2016 post DFGD system operation.

As is evident in Figure 7, the DFGD system operation resulted in a marked decrease in SO2 emissions. Across the complete load range presented, average SO2 emissions ranged from 0.03 to 0.05 Lbs/MMBTU, significantly lower than design target emissions of 0.06 Lbs/MMBTU.

Unit 3 average SO2 emissions were analyzed during the months of February and March of 2015, prior to the DFGD system being placed into service, and compared to data sets from September and October of the same year, post DFGD system operation. Similar to the results presented for Unit 1, the DFGD system operation resulted in a marked decrease in SO2 emissions.

Across the complete load range presented, average SO2 emissions ranged from 0.02 to 0.05 Lbs/MMBTU, significantly lower than design target emissions of 0.06 Lbs/MMBTU.

Conclusions and Summary and Wrap-Up

Over the course of five years, a new air quality control system addressing numerous plant emissions was installed at TVAs Gallatin Fossil Plant. The AQCS retrofit was implemented to reduce SO2, Hg, PM and NOx emissions at the plant in accordance with TVA’s fleet wide clean air control program. In addition, a new dry, lined landfill facility was added to handle CCR from the units. An analysis of SO2 emissions data indicates that the DFGD units are operating within expectations based on the load and fuel profile. The plant upgrades have been comprehensive and will extend the life of the facility for decades.