Draft Notes from Site Visit at Duke Energy's Allen Steam Station on October 22, 2009 

EPA conducted a site visit at Duke Energy’s Allen Steam Station (Allen) located in Belmont, NC 

on Thursday, October 22, 2009 to learn about the operations at the plant, specifically the FGD 

system and the FGD wastewater treatment system. Table 1, located at the end of this 

memorandum, identifies the site visit participants. The presentation that the Allen personnel gave 

during the site visit is provided as Attachment 1 to this memorandum. An overall plant water 

balance diagram and process flow diagrams of the FGD wastewater treatment system are 

included within Attachment 1. 

This memorandum describes the information collected during the site visit and the pre-site visit 

phone call, which was held on October 13, 2009. 

Plant Overview 

 Allen operates five steam electric units and each has a coal-fired boiler. Units 1 

and 2, which both came on line in 1957, each have a capacity of 165 megawatts 

(MW). Units 3, 4, and 5 came on line in 1959, 1060 and 1961, respectively, and 

each has a capacity of 275 MW. All five generating units burn bituminous coal. 

The sulfur content of the coal is 1 to 1.2 pounds SO2/MBTU and the chlorine 

content of the coal is 50 to 1,500 ppm. 

 The electric generating units at Allen are operated on a cycling basis and are not 

baseload units. The table below contains some general information for the five 

generating units. 

Unit Installation 

Date 

Gross 

Capacity 

(MW) 

Particulate 

Control NOx Control SO2 Control 

1 1957 165 

Electrostatic 

Precipitator (ESP) 

(cold-side) 

Selective noncatalytic reduction 

(SNCR) 

Wet FGD installed 

in Feb 2009 

(common FGD for 

Units 1, 2, and 5) 

2 1957 165 ESP 

(cold-side) SNCR 

Wet FGD installed 

in Feb 2009 

(common FGD for 

Units 1, 2, and 5) 

3 1959 275 ESP 

(cold-side) SNCR 

Wet FGD installed 

in May 2009 

(common FGD for 

Units 3 and 4) 

4 1960 275 ESP 

(cold-side) SNCR 

Wet FGD installed 

in May 2009 

(common FGD for 

Units 3 and 4) 

5 1961 275 ESP 

(cold-side) SNCR 

Wet FGD installed 

in Feb 2009 

(common FGD for 

Units 1, 2, and 5) 
Page 2 

 Allen recently retrofitted all five units with two wet FGD scrubber systems to 

control the sulfur dioxide (SO2) releases from the plant. Units 1, 2 and 5 exhaust 

to FGD Absorber 1, and Units 3 and 4 exhaust to FGD Absorber 3. The FGD 

systems were installed in February 2009 (Absorber 1) and May 2009 (Absorber 

3). The wet FGD scrubbers are designed to achieve greater than 95 percent 

removal of SO2. [QUESTION FOR ALLEN: What SO2 percent removal do the 

FGD scrubbers actually achieve?] The SO2 percent removal from the 

scrubbers varies with load and sulfur concentration of the coal being 

burned. During the official performance testing of the scrubbers in 2009, 

when 2.4 pounds SO2 per mmBtu coal was burned at full load, the scrubbers 

performed at 96.95% removal with no additives. Allen has also installed an 

FGD wastewater treatment system to control the discharges of the wastewater 

generated during the operation of the FGD scrubbers. 

 Allen operates ESPs to control fly ash and particulate emissions from the plant. 

Allen also operates SNCR systems to control nitrogen oxide (NOx) emissions 

from the plant. The SNCRs operate year-round. Additionally, the boilers are 

operated with low-NOx burners and a separated overfire air system. 

 The ESPs at Allen are particulate control devices that remove the fly ash and 

other particulates from the flue gas. Allen utilizes ESPs to remove the fly ash 

from all five units. The ESPs are designed to remove greater than 99.9 percent of 

the fly ash from the flue gas. The fly ash and other particulates are collected in 

hoppers and usually pneumatically transferred to fly ash silos. However, Allen 

also has the capability to handle the fly ash wet, by sluicing the fly ash in the 

hoppers and transferring the fly ash transport water to the ash basin. 

 All five generating units have the following configuration: 

 Boiler (SNCR system contained in boiler); 

 Air preheater; 

 ESP; and 

 Wet FGD scrubber system. 

 Allen operates a once-through cooling system. The cooling system has a flow rate 

of approximately 780 MGD. The source of the cooling water is the South Fork 

River. 

 The Allen plant is located on 1,000 acres adjacent to the Catawba River. 

 [QUESTION FOR ALLEN: How many employees work at the plant?] As of 

December 7, 2010, there are 167 employees working at Allen Steam Station. 

Ash Handling 

 Allen stated that they previously sent all bottom and fly ash to an 

impoundment/basin; however, Allen converted to dry fly ash handling systems in 

April of 2009 to extend the life of the ash basin. Allen is still sending all the 

bottom ash and pyrites to the ash basin. 
Page 3 

 Allen stated that another reason the plant decided to convert to dry fly ash 

handling was because of the selenium limit on the effluent from the ash basin 

(Outfall 002). 

 The dry fly ash handling system retrofit was completed in June 2009. The total 

capital cost of the dry fly ash handling system was $39 million. 

 Installation of the dry fly ash handling retrofit consisted of installing the following 

pieces of equipment: dry handling valves, vacuum filter separators, Nuva feeders, 

compressors, high pressure piping, and ash silos. The tie-ins for the equipment 

were installed during regularly scheduled unit outages. [QUESTION FOR 

ALLEN: Approximately how long (days, weeks?) did it take to complete the tiein?] Approximately seven days was taken to complete the tie in of the dry ash 

handling system. The following is a description of the dry fly ash handling 

system components: 

 Between the hoppers (which collect ESP and economizer fly ash) and the 

existing wet ash handling hydroveyor equipment, the plant installed a dry 

handling valve. The dry handling valve allows Allen to switch between 

operating the dry and wet fly ash handling systems. 

 The vacuum filter system consists of vacuum pumps and filter separators. 

The vacuum pumps use 350 psi air pressure to create a vacuum, pulling 

dry ash collected in the hoppers to the filter separators. Allen has eight 

filter separators (two for Units 1 and 2 combined and two for each of Units 

3, 4, and 5). The filter separator allows the air to separate from the dry fly 

ash. The air is vented from the top of the filter separator after passing 

through filter bags, which are like mini baghouses. The filter bags are 84 

inches long and there are 84 bags per filter separator. The filters remove 

any fly ash and other particulates from the vented air and the filters are 

pulsed with air occasionally (based on the pressure drop across the filters) 

to remove the fly ash that accumulates on the bags. 

 The ash then falls by gravity from the filter separator into the Nuva 

feeders. There are two Nuva feeders for each filter separator for a total of 

16 Nuva feeders for the plant. Because the dry fly ash is blown to the 

silos under pressure, the Nuva feeders are required to transition between 

the vacuum system (i.e., the filter separators) and the pressure system. 

Therefore, Allen’s dry ash handling system is considered a combination 

vacuum/pressure system. 

 The Nuva feeders allow the ash handling system to transition from the 

vacuum system to the pressure system. While the first of the set of two 

Nuva feeders is receiving ash from the filter separator, the second is 

transferring ash out the bottom so the compressor can blow the ash to the 

storage silo. Once the first Nuva feeder is full and the second is empty, 

the plant switches the valves so the first Nuva feeder can begin 

transferring ash and the second can begin receiving ash. 

 The fly ash is blown a distance of 1,800 feet to one of two ash storage 

silos. Allen stated that the pressurized pipe is significantly more 

expensive than the pipe used to transfer the sluiced bottom ash to the ash 
Page 4 

basin. Additionally, the pressurized pipe is more prone to leaks than the 

wet ash pipe. [QUESTION FOR ALLEN: What is the relative difference 

in cost between the piping?] 

The vacuum system is tied into pressurized piping that is provided 

specifically by United Conveyor (Nuvalloy) and the ash sluice line is highdensity polyethylene (HDPE) for the gravity fed system. The cost of the 

pressurized piping is approximately 3 to 5 times more (depending on the 

diameter of the pipe) than the HDPE piping on a linear foot basis. Actual 

cost estimates will be provided to Eastern Research Group (ERG) as 

confidential business information (CBI) as part of this submittal. 

 The silos have a storage capacity of approximately three days of fly ash 

when operating at full load (between the two silos). 

 The silos have a dry air system that blows air into the bottom of the silo to 

fluidize the fly ash. The silos also have filters at the top of the silos to 

collect any fly ash from the air that is vented. 

 Ash from the silos is trucked away for beneficial reuse. Allen stated that 

the ash is collected by trucks at a frequency of 110 times per day. Each 

truck collects approximately 1,700 tons of ash. 

 Allen has the capability of loading the trucks completely dry (sealed 

trucks) or conditioning the ash with water for loading (open trucks). 

 When fly ash is loaded dry, the ash is transferred from the silos to the 

trucks pneumatically with a double annular spout. A vacuum is pulled 

through the outer annulus of the spout, creating a tight seal with the truck. 

Ash is delivered through the inner annulus of the spout into the truck. The 

vacuum captures any fugitive dust and pulls it through the loading silo to 

the baghouse. It takes about 1 to 2 minutes for the ash to settle in the 

trucks before the spout is pulled away. 

 When the fly ash is loaded in a wet form, the fly ash is fed to a pug mill 

where it is mixed with service water to 17 percent moisture content, for 

optimal compaction. The fly ash is then dumped into the open trucks 

through a spout. 

 The area surrounding the silos has sloped concrete and drains to collect 

rainfall or other water that may have become contaminated with fly ash. 

This water is transferred to the stormwater basin and then pumped to the 

ash basin. 

 Allen stated that the dry fly ash is currently sold used for a beneficial reuse 

application. The plant is waiting on a permit to be approved which will allow 

Allen to landfill the dry fly ash. [QUESTION FOR ALLEN: For what beneficial 

reuse application is the fly ash being used?] The dry fly ash was used as 

structural fill for the constructed landfill. 

 Allen stated that they retained the capability of sluicing the fly ash with the 

existing wet system. When the fly ash is handled wet, the ash sluice is transferred 

to the ash basin at a flow rate of 1,200 gpm. [QUESTION FOR ALLEN: When 

does the plant use the wet fly ash handling system?] 
Page 5 

The fly ash system is operated on wet mode during all unit start ups (i.e. 

when fuel oil is being burned in the boiler). When the operating load 

increases, the fly ash system is switched to dry mode. In addition, the wet fly 

ash handling system is operated during any dry ash handling system 

malfunction. 

 Allen handles all bottom ash and pyrites wet. The bottom ash sluice flow rate is 

13,700 gpm. 

 Both fly and bottom ash are conveyed (pneumatically pumped or sluiced) at a 

frequency of two times per shift (2 shifts/day  4 times/day) for a duration 

approximately one hour. 

Ash Basins and Landfill 

 Allen has a retired ash basin, an active ash basin, and an ash pond (polishing 

pond). 

 The retired basin has a total area of 180 68 acres and stopped receiving wastes in 

1974. At the time of the visit, Allen was constructing a landfill over the retired 

ash basin. Allen stated that the plant has been permitted to store the dry fly ash 

and other coal combustion byproducts in the landfill. 

 The landfill has a total area of 68 acres. It will be constructed with a double-liner, 

a leachate collection system and a leak detection system. The double-liner will 

cover ash stored in the inactive ash basin’s cells and is comprised of the following 

layers (from bottom to top): an 18 inch clay liner, a geosynthetic liner, a rubber 

liner (the secondary liner), a drainage net, a drainage layer consisting of two feet 

of soil (clay), a second drainage net, and a rubber liner (the primary liner). The 

drainage nets and drainage layer comprise the leak detection system, which 

detects leaks from the primary liner. 

 Allen stated that the permeability of the clay liner is 10-5 cm/sec. The addition of 

the geosynthetic liner was necessary to obtain a permeability of 10-7 cm/sec. 

 Allen indicated that the collected leachate will be transferred to the active ash 

basin. 

 Allen expects that the total cost for the landfill will be approximately $XX. 

[QUESTION FOR ALLEN: Please confirm the cost and provide a breakout.] 

The breakout of the capital cost of the landfill is CBI. These costs will be 

provided to ERG as part of this submittal. 

 The lifetime of the landfill is expected to be 2.5 million cubic yards, which is 

expected to last for five years. [QUESTION FOR ALLEN: Please confirm the 

expected landfill capacity.] The landfill capacity, as noted in the landfill 

permit to operate, is 2,080,500 cubic yards (cu. yds.) for Phase 1, cells 1 and 2 

plus 3,958,200 cu. yds for Phase 2, cells 3 and 4. 
Page 6 

 The active ash basin began receiving bottom ash and fly ash (when handled wet) 

in 1974 when the inactive ash basin stopped receiving wastes. 

 The fly ash (when handled wet) and bottom ash enter the active ash basin, where 

the solids settle and the water flows through a series of three cells. The plant can 

direct the ash to any of the three cells. The effluent from the third cell overflows 

to a channel that flows towards the back of the ash basin (i.e., away from the 

Catawba River). Along this channel, the plant has the capability of adding ferric 

sulfate to aid in settling. The channel then flows into the main ash pond. The ash 

pond discharges to the Catawba River. Allen has the capability to add sulfuric 

acid or sodium hydroxide at the effluent of the pond to adjust the pH between 6 

and 9. 

 The neither the active ash basin nor the ash pond have a liner. 

 Allen stated that the FGD wastewater treatment effluent, described later, is 

transferred to the ash pond. Allen has the system configured such that the FGD 

wastewater treatment effluent enters into the ash basin channel and does not go 

through the ash basin cells. Allen stated that they have the capability to transfer 

the FGD wastewater through the cells if needed. 

 Allen stated that the plant will have the ability to extend the lifetime of the active 

pond by dredging the solids in the active pond and transferring them to the 

landfill. 

 Allen indicated that the State requires them to perform leachate monitoring twice 

a year. Typical chemicals that they test for are boron, magnesium and iron. 

 [QUESTIONS FOR ALLEN: How often do you inspect the active basin for 

structural integrity? When was the last inspection and what did the inspection 

consist of?] Inspections are conducted monthly by station personnel or after 

2 inches of rainfall in a 24 hour period. Annual inspections are conducted by 

a Professional Engineer (P.E.). The last monthly inspection was conducted 

on November 19, 2010 by station personnel. No immediate concerns were 

identified. In addition, an inspection was conducted by the North Carolina 

Department Environment and Natural Resources (NCDENR) Dam Safety, 

with no items identified. 

 [QUESTION FOR ALLEN: Do you perform groundwater monitoring around the landfill 

and/or ash basins? If so, how often do you perform groundwater monitoring and what 

parameters are monitored for? Where are the monitoring wells located? Please provide 

the groundwater monitoring data for the five most recent samples.] Groundwater 

monitoring is conducted semi-annually on a voluntary basis. See attached excel 

spreadsheet (“Allen Ash Basin Groundwater Data”) for analytical results and 

parameters. The locations of the wells are provided in the attached PDF file (“Plant 

– Allen Ash Basin Groundwater Locations”). The voluntary wells were not sampled 

in November 2010, due to transitioning from the voluntary wells to the newly 

installed compliance well system. 
Page 7 

FGD Systems 

 Allen operates two forced oxidation wet FGD scrubber systems that treat the flue 

gas from all five electric generating units. The FGD systems are located 

downstream of the ESPs and the flue gas from Units 1, 2, and 5 are combined and 

transferred to Absorber 1, while the flue from Units 3 and 4 are combined and 

transferred to Absorber 2. The FGD systems control the emission of sulfur 

dioxide from the units. The plant uses limestone slurry as the sorbent for sulfur 

dioxide absorption. 

 The FGD systems are designed to achieve a 95 percent removal of sulfur dioxide 

from the flue gas, based on a design coal of 2.8 lbs SO2/MMBTU. Additionally, 

when Allen built the FGD systems, they installed the equipment needed to be able 

to add dibasic acid (DBA) to the system. At this point, the plant has not used or 

tested DBA in the system. Allen stated that they may consider using formic acid 

sometime in the future. 

 The limestone is delivered to the plant via rail, stored in an outdoor pile, and then 

transferred to day bins. Allen has ball mills onsite to pulverize the limestone. The 

limestone is fed to the ball mills, along with service water, and the ball mills 

pulverize the limestone. From the ball mills, the slurry is transferred to 

hydroclones to collect limestone particles that are too large for use in the FGD 

system. The underflow from the hydroclones is transferred to the reject tank and 

then sent back to the ball mill for additional processing. The overflow from the 

hydroclones, which is approximately 50 30 percent solids, is transferred to the 

reagent tank for storage and then used as fresh limestone slurry in the absorber. 

The fresh limestone slurry is fed to the reaction tank of the FGD system and the recycle pumps 

pump the slurry to the various levels of the FGD scrubber. Typical solids concentrations in the 

absorber are 14-16%. [QUESTION FOR ALLEN: Is make-up water added to the reagent tank 

or the reaction tank to achieve the 14-16% solids?] Reaction Tank Solids are maintained at 14 

to 16% solids by dewatering only (that is sending the primary hydrocyclone underflow to 

the filter feed tank and then to the belt filter). Make-up water is added to the reaction 

tanks for level control due to dewatering (or taking the solids from 16% down to 14%), 

purging for chlorides (returning both the primary and secondary hydrocyclone underflow 

solids back to the reaction tank while sending the secondary hydrocyclone overflow to 

WWTS), evaporation or anything else that may cause a change in the level in the reaction 

tank. 

 Both absorbers have four spray levels; however, the plant typically only operates 

three levels at one time. The slurry is pressurized and sprayed downward into the 

scrubber vessel through spray nozzles. The flue gas flows counter-current to the 

falling slurry. As the spray droplets of the slurry contact the flue gas, the 

limestone reacts with the sulfur dioxide and oxygen, producing calcium sulfate 

(gypsum). 

 Allen intermittently purges volume of the gypsum slurry from the reaction tank to 

control the solids and/or chlorides concentration in the scrubbers. The process for 
Page 8 

dewatering (maintaining reaction tank solids at 14% to 16%) is different 

than “purging for chlorides”. The gypsum slurry is removed permanently 

from the reaction tank to control solids. The gypsum slurry is returned to 

the reaction tank when purging for chlorides. The chlorides concentration in 

the scrubbers is maintained between 3,000 and 10,000 ppm. The maximum 

design chlorides concentration is 12,000 ppm in the system. The typical percent of 

solids within the absorber is 14 % to 16 %. 

 The purge stream from the reaction tank is sent to the gypsum dewatering system. 

Allen stated that because of the low-sulfur coal that they are currently using, they 

typically have to purge from the FGD system to control the chlorides 

concentration instead of controlling the solids content in the scrubber. The 

percent solids are controlled; otherwise, the reaction tank agitators could 

fail. Dewatering and purging are two different processes within the FGD 

operation. The gypsum slurry is removed permanently from the reaction 

tank to control solids. The gypsum slurry is returned to the reaction tank 

when purging for chlorides. 

The purge stream is pumped to the primary hydrocyclones where the gypsum is separated from 

the water by centrifugal force. The gypsum is forced outward to the walls of the hydrocyclones 

and falls downward, while the water exits the top of the hydrocyclones. The gypsum from the 

primary hydrocyclones is transferred to the filter feed tank, which is then transferred to the 

vacuum filter belts. Allen washes the gypsum with service water as it is applied to the vacuum 

belt filter to reduce the chlorides in the gypsum. [QUESTION FOR ALLEN: Where does the 

plant transfer the gypsum wash water from the vacuum belt filter?] The gypsum wash water is 

returned to the reaction tanks. 

 Allen stated that the gypsum is shipped off site by a truck to a wallboard 

manufacturer in Mount Holly, NC. The following are the specifications that the 

gypsum must meet to be sold to the wallboard manufacturer: 

 Less than 10 percent moisture; and 

 Less than 120 ppm chlorides. 

 Allen stated that the moisture content in the gypsum is typically 4 percent and the 

chlorides concentration is typically less than 20 ppm 

 The overflow from the primary hydrocyclones is transferred to a holding tank, 

and then pumped to the secondary hydrocyclones. The underflow from the 

secondary hydrocyclones is returned to the scrubber. The overflow from the 

secondary hydrocyclones is sent to the FGD wastewater treatment system. This 

FGD purge stream contains 0.5 to 0.8 percent of solids. 

FGD Wastewater Treatment System 

 Prior to the site visit, Allen distributed a description of the FGD wastewater 

treatment system, provided as Attachment 2 to this memorandum. 
Page 9 

 The FGD wastewater treatment system is designed to receive transfers of FGD 

wastewater from the FGD system, which consists of secondary hydrocyclone 

overflow, at a flow rate of 400 gpm. The FGD wastewater treatment system 

consists of chemical precipitation and biological treatment technologies. 

 The secondary hydrocyclone overflow from the scrubbers is transferred to the 

equalization tank at the beginning of the wastewater treatment system. Allen also 

has a maintenance tank that is used as either a spare equalization tank or a spare 

sludge holding tank. The equalization tank also receives water from the filtrate 

sump (which includes filter press filtrate), gravity filter backwash reject, 

backflush waste from the biological treatment system, and off-specification 

biological treatment effluent. The wastewater entering the equalization tank has a 

pH of 6.7-6.9 and a temperature of 105-115o F. Allen stated that a significant 

amount of CO2 is released during the agitation of the wastewater in the 

equalization tank. 

 From the equalization tank, the wastewater enters three reaction tanks in series. In 

the first reaction tank, lime is added to increase the pH to between 8.6 and 9.2. 

The effluent from this tank enters the second reaction tank designed for 

organosulfide addition; however, the plant does not add organosulfide to the 

reaction tank because the plant determined that organosulfide addition was not 

necessary to meet its effluent limits. 

 After the organosulfide tank, the FGD wastewater is transferred to the third 

reaction tank where ferric chloride is added. Allen stated that they are tuning the 

ferric chloride dosage for the plant and questioning whether ferric chloride is 

needed in the system to achieve the effluent limits at the plant. According to plant 

personnel, the plant has dropped the dosage by 40 percent and has not seen any 

change in the performance of the system. [QUESTION FOR ALLEN: What 

parameters are analyzed to assess system performance?] The performance of the 

system is analyzed by evaluating total and dissolved selenium (Se), mercury 

(Hg) and total suspended solids (TSS) out of the physical/chemical system. 

Secondary characteristics that may impact the operation, rather than the 

performance, of the biochemical system are monitored (i.e. nitrate, 

phosphate, pH and alkalinity). 

Ferric chloride dosing at Allen WWTS has varied from 47 ppm to 20 ppm 

since the system has been operating. Current ferric chloride dosing is 30 

ppm. 

Based on the technology provider’s recommendations for Belews Creek, we 

started the system at 47 ppm ferric chloride dosing. Beginning in August 

2009, we began reducing this dosing incrementally until we reached 20 ppm 

in January/February 2010. During this period we did not notice a difference 

in the performance of the system as measured at the effluent from the 

physical/chemical and biochemical systems. We did however notice that we 

needed to use more polymer to maintain the same performance out of the 

clarifiers, TSS removal, and that the bioreactor cells required degassing at a 

significantly increased frequency. The increased gassing of the bioreactors 
Page 10 

has been attributed with a decrease in phosphate removal in 

physical/chemical. Although there was an increase in TSS in the clarified 

water, the gravity filters maintained a relatively unvaried TSS in the 

discharge from the physical/chemical system. 

Ferric chloride dosing was increased to 30 ppm which has resulted in 

improved TSS reduction across the clarifiers and a return to “normal” 

degassing frequencies in the bioreactors. Jar testing with various FGD 

waters and flocculating polymers has shown that a ferric chloride dosing of 

between 25 and 50 ppm usually results in optimum clarifier performance. 

 Ferric chloride dosing was as follows: 

 

 Beginning 3/09 47 ppm 

 7/30/09 40 ppm 

 9/17/09 30 ppm 

 2/15/10 20 ppm 

 3/22/10 50 ppm 

 5/14/10 40 ppm 

 8/6/10 20 ppm 

 8/10/10 30 ppm 

 The overflow from the ferric chloride tank flows through a flow splitter which 

distributes the flow evenly to two clarifiers. Allen operates the two clarifiers in 

parallel, each capable of handling 100 % of the waste stream flow. A polymer is 

added to the wastewater just prior to the clarifiers. 

 The sludge collected in the clarifier is transferred to a sludge holding tank and 

dewatered with a filter press. The filter press uses hydraulic power from 

compressors to remove water. The solids are transferred to an off-site landfill and 

the filtrate is recycled to the equalization tank. 

 The clarifier overflow is neutralized by hydrochloric acid addition (if necessary) 

and flows through three continuous backwash gravity filters operated in parallel. 

Each filter is capable of handling 75 % of the wastewater flow. The hydrochloric 

acid helps prevent scale formation in the filters. The effluent of the gravity filters 

is approximately 1 to 2 ppm TSS. 

 The effluent from the gravity filters is transferred to the biological treatment 

system feed tank. 

 Prior to entering the biological portion of the wastewater treatment system, heat 

exchangers cool the wastewater to 95o F, the optimal temperature for the 

biological treatment system. Allen stated that the heat exchangers were 

constructed with a titanium alloy which can withstand the high levels of chlorides 

and suspended solids in the FGD wastewater entering the biological treatment 

system. The heat exchanger requires 300 to 350 gpm of cooling water. 

[QUESTION FOR ALLEN: Is any make-up water added to dilute or cool the 
Page 11 

influent wastewater to the biological system?] Water is not added to dilute or 

cool the influent wastewater to the biological system. The influent 

wastewater to the biological system is cooled by using a heat exchanger. 

 

 Allen adds molasses-based nutrients to the wastewater as it flows from the heat 

exchanger to the biological treatment system. The nutrients provide a source of 

carbon to feed the bacteria. 

 Allen stated that the biological treatment system is nearly identical to the 

biological treatment system at Belews Creek and consists of two stages. The 

residence time in each stage is approximately 4 hours. 

 Both bioreactor stages contain eight biological cells operated in parallel. Each of 

the bioreactor cells contains beds of activated carbon media 20 feet deep. The 

wastewater is initially sent into the first-stage cells, where the flow into the first 

cell is evenly distributed to 16 distribution pipes to create an uniform distribution 

of flow into the top of the cell. The water level in the cell was designed to be 

approximately six inches above the activated carbon bed; however, at the time of 

the site visit, the water level was below the top of the carbon bed. Within the 

activated carbon bed, microbes create a fixed film on the surface of the carbon. 

Water flows from the top of each cell down through the carbon beds. Water from 

the first cell is then pumped from the bottom of the first cell to the top of the 

second cell. The wastewater continues in this fashion through all eight cells that 

make-up the 1st stage of the bioreactor. 

 The effluent from all first-stage of the bioreactor is transferred to the first-stage 

effluent storage area, before being sent to the second-stage bioreactor cells, which 

are also operated in parallel. Nutrients are added to the wastewater as feed for the 

microbes as the wastewater is transferred. As in the first stage, the wastewater is 

divided evenly among the eight second-stage cells and each cell has 16 distributor 

pipes to evenly distribute the flow into the cell. 

 Occasionally the bioreactor cells must be backflushed to remove accumulated 

solids. The plant pumps the effluent from the first-stage bioreactor cells 

backwards through each cell and it overflows into a spillover area. The plant then 

returns the backwash overflow to the equalization tank at the start of the FGD 

wastewater treatment system 

. 

 Because the first-stage bioreactor cells denitrify the waste stream, they produce 

nitrogen and carbon dioxide gas. To remove the gas from the cells, the plant 

occasionally performs a degassing operation where water is sent backwards 

through the cells, like a backflush, but the flush is only long enough for the gas to 

“burp” out of the system. The second-stage bioreactor cells are primarily anoxic 

and do not produce as much gas as the first-stage cells; therefore, Allen performs 

the degassing operation on the second-stage cells less frequently than the firststage cells. 

 
Page 12 

 Allen stated that the TSS concentration within the first and second stage 

bioreactor cells is approximately 40 ppm. The solids in the cells are mostly 

biological materials. 

 Allen stated that the system achieves significant reductions in dissolved metals 

concentrations in the first-stage reactors; therefore, the second stage is primarily a 

polishing step but it also provides a safety net for high metal loads. Allen stated 

that arsenic, zinc, nickel and selenium are typically below the limit of detection in 

the effluent of the biological treatment system. 

 

 Allen stated that the major improvement of the Allen biological treatment system 

over the Belews Creek system is the inclusion of oxidation-reduction potential 

(ORP) and pH probes on each individual cell (the Belews Creek system has one 

ORP probe for each stage). Additionally, the Allen system has sampling points on 

the effluent from the second stage (Belews Creek has sampling points on the 

effluent from the second stage recycle). These improvements have resulted in 

greater ease of operations for the biological treatment system at Allen. 

 Allen stated that the effluent from the FGD wastewater treatment system is 

transferred to the ash basin. Allen stated that there are no permit limits for the 

FGD wastewater treatment system effluent (internal Outfall 005); however, Allen 

stated that they are required to monitor and report the following parameters for 

the internal outfall: Se, Hg, As, Ni, Zn, Be, Ag, Cr, Cd, sulfates, chlorides, and 

pH. [Please provide monitoring data for the FGD wastewater treatment system, 

including FGD scrubber purge, effluent from chemical precipitation/influent to 

biological treatment, and effluent from biological treatment. Include all 

parameters that are being monitored. Additionally, please indicate the ferric 

chloride dosage rates at the time of monitoring (to identify when changes were 

made to the dosage).] Please refer to the completed Allen Steam Station 

Questionnaire for the Steam Electric Power Generating Effluent Guidelines 

for untreated FGD scrubber purge monitoring data. Please see attached 

excel file “Allen Biochem and PhysChem monitoring.xls” for monitoring 

data for the effluent from chemical precipitation/influent to biological 

treatment, and effluent from the biological treatment. 

Please note Method 245.1 was used for the mercury analysis for samples 

collected between 6/5/09 to 7/30/09 and Method 1631e was used for the 

mercury analysis for samples collected between 8/5/09 to 6/15/10. 

The analysis for the in process data is conducted by the wastewater 

treatment system (WWTS) operators within the WWTS lab and is intended 

only to indicate gross operational performance of the system. These results 

should not be deemed suitable for compliance purposes. 

Detection limits for the nitrate test is 0.1 ppm as N. Results detected below 

the detection limits are noted in red and indicated with a less than sign, “<”. 

 Allen stated that they are sampling the effluent from the FGD wastewater 

treatment system on a weekly basis. 
Page 13 

 The selenium limit from the ash basin effluent (Outfall 002) is 31 ppb. Allen 

expected the limit to be lowered to 21 ppb when the biological treatment system 

was designed. 

 Allen stated that because the electric generating units are operated on a cycling 

basis and are not baseload units, there are times when the units have been shut 

down for a few days. During these shut down periods, the wastewater treatment 

system does not receive any scrubber purge wastewater and therefore, the plant 

has to find a way to feed the microbes to keep them alive. Allen stated the 

following regarding there operations during shut downs: 

 If the plant knows ahead of time that they will be shut down for a couple days, 

they can build up additional scrubber purge in the equalization and maintenance 

tanks and then operate the FGD wastewater treatment system at a reduced flow 

rate until they begin operating again. 

 If the plant is down for several days without advanced knowledge, the plant can 

run service water through the system and feed nutrients to the bioreactors to 

sustain biological growth. 

 During pilot testing, the plant shut off the system for three weeks with the system 

sitting idle with water in it and when the system started operating again, it was 

achieving its typical performance after 24 hours. 

 Allen stated that the biological treatment system is fully operational within 1-2 

residence times after a complete shut down of the entire system. Additionally, 

Allen stated that the biological species in the bioreactor cells will respond to 

variations in influent chemistry (i.e. return to steady state) within 1-2 residence 

times. 
Page 14 

 Table 1. Site Visit Attendees 

Name Organization (Representing) Telephone E-mail Robert Wylie Duke Energy (704) 382-4669 Robert.Wylie@duke-enerKim Hamm Duke Energy Kimberly.Hamm@duke-eGreg Ausberger Duke/Allen Gregory.Augspurger@duBill Kennedy Duke Energy William.Kennedy@duke-Robyn Robbin

Jolly Duke/Allen (704)829-2412 Robbin.Jolly@duke-energ

Terry K. Hollifield Duke/Allen Terry.Hollifield@duke-enTed Manes Duke Energy Ted.Manes@duke-energySteve Immel Duke/Allen Steve.Immel@duke-energDon Scruggs Duke/Allen Don.Scruggs@duke-enerDonna Hill UWAG/Southern Company (205) 257-5234 dbhill@southernco.com Josh Hall EPA (202) 566-1002 hall.josh@epa.gov Jezebele AliceaVirella EPA (202) 566-1755 Alicea.jezebele@epa.gov Kurt Blohm ERG (Contractor to EPA) (703) 633-1675 kurtis.blohm@erg.com TJ Finseth ERG (Contractor to EPA) (703) 633-1698 thomas.finseth@erg.com