By James Laughlin, Industrial WaterWorld Editor
Revised rules governing effluent guidelines for the steam electric power industry were scheduled to be released December 14th by the US Environmental Protection Agency. The new rules are expected to include new discharge limits for mercury and selenium in flue gas desulfurization wastewater, and could include a variety of other contaminants of concern. The final rule approval is expected by April 2014.
While the exact details of the guidelines are not known at that this writing, they will include a discussion of the best available technologies (BAT) that could be used to remove the contaminants of concern.
The options for treatment are likely to include physical/chemical treatment, biological treatment and zero liquid discharge. While power plant operators have a long history with physical/chemical treatment, those systems alone may not be able to reach the lower limits expected in the new rule. Biological treatment and ZLD may be required but will be a learning experience for most plant operators.
EPA has not updated the guidelines for the electric power industry since 1982. The new rules are being driven, in part, because of the growing number of air regulations imposed on the industry. EPA has expressed concern about the potential for cross media transfer of pollutants from the air to other media, said Paul Chu, Senior Project Manager for the Electric Power Research Institute.
"A lot of power plants are putting together FGD systems and are capturing pollutants that tend to be in the vapor phase of flue gas," he said. "You remove pollutants from the air, but you've transferred them to water and solids."
Mercury and selenium are the two major contaminants of concern in FGD wastewaters, although there are other contaminants that may be regulated, including boron as a possibility.
The key concern for power facilities is the treatment systems required to reach the effluent limits imposed by the new rule.
"Power plants want a cost-effective, reliable technology that they can operate with 99.9 percent reliability and know they are in compliance 24/7/365," Chu said. "Some people prefer physical/chemical treatment because they are comfortable with it; they are comfortable with tanks, they are comfortable with clarifiers, with managing of the solids."
Currently there are only about six biological plants operating in the U.S. power industry, and they tend to require different skills and more attention than physical/chemical systems.
"It's clear to us a lot of people are not comfortable with them," Chu said. "The biggest concern that people have, what happens if they get an upset condition and the bugs die? 'We are a bunch of engineers here, we don't have a microbiologist on staff. Do we need a microbiologist to run these things and understand them?"
"Certainly the plants that do have biological systems are getting generally good performance, but there are some periodic hiccups. When you look at the data at some of these facilities, you do see periods of time when removal efficiencies drop off. And it's not clear exactly what's happening," Chu said.
Hollie Scott, Water for Power Lead at CH2M HILL, has been following the issue of BAT systems for power industry wastewaters.
He said mercury is a hot topic these days, especially because of the Great Lakes Initiative, but is not hard to remove with appropriate improvements to in-plant wastewater chemistry and the addition of organo sulphides. Selenium, however, will be a bigger challenge.
"With the advent of limestone forced oxidation scrubbers, you end up with a much more oxidative environment in the scrubber, and what used to be selenite that you could remove without tremendous difficulty is now converted to selenate, which is extremely difficult to remove," Scott said. "That drives you up a level in complexity and can drive you to the installation of biological treatment to reduce selenate to elemental selenium so you can actually remove it."
CH2M Hill has worked with clients in the coal mining industry to treat stormwater mine runoff for selenate, with much of the work being driven by lawsuits filed by environmental groups. His company is currently preparing a report for the North American Metal Council looking at various options for the control of selenium.
"That has given us some insights in at least what we think is coming for our power industry clients," Scott said.
He said he had talked with clients who had operated biological systems in the power industry, but ended up shutting them down in favor of other treatment options.
"I suspect those facilities were installed with the thought that this would provide them with the treatment capability they needed for some significant distance out into the future. And that proved not to be the case," he said. "Biological treatment is a different skill set. The folks I've seen associated with physical/chemical treatment in power plants are pretty sharp folks, but their entire focus is in a different direction."
Depending on the constituents included in the revised effluent guidelines, and the removal levels that must be achieved, zero liquid discharge may become a viable, if very complex, option for power plants.
"If you get to things like boron, where there really isn't a full scale, economically viable, well established technology for the removal of boron… ultimately the last line of defense is zero liquid discharge," Scott said. "But then you are talking about huge costs in terms of both capital and operation."
Chu said there is currently only one ZLD system being used to treat FGD wastewater in the US, and that's a partial ZLD system. The concentrated soup left after the process is used for fly ash wetting for disposal in a landfill. A handful of ZLD systems are being operated in Italy.
"A lot of people interested in ZLD have made the trip to Italy to look at those plants," Chu said. "We wanted to see what the Italians had done, why they had done it and what they had learned.
Along with capital costs, concerns with thermal ZLD include the large amount of energy required to evaporate the water. Other issues include scaling and corrosion in the ZLD system. The Italian facilities have suffered in the past with materials of construction not surviving the ZLD environment.
Disposal of the concentrated salts can also be an issue, Chu said.
"The Italian systems manage their crystallizer solids by sending it to a salt mine in Germany. That's not totally convenient for plants in the US," he said.
One joke equates zero liquid discharge systems to operating a chemical plant on the back of a power plant - and operating the power plant to suit the needs of the chemical plant.
"Power companies are in the business of making power, and operating a chemical plant is not the type of expertise our companies have," Chu said. Reliability is also a concern. "If you are down for corrosion issues, can you operate your power plant? Do you need redundancy in all your equipment just to insure you can operate? This all impacts costs."
Power plants that are considering ZLD are doing so because of their concerns about where the effluent guidelines are headed in the future. "One rationale, it's mercury and selenium today, and tomorrow it will be something else. At some point you will have to put in ZLD," Chu said.
Other Waste Streams
EPA may regulate other wastewater streams beyond FGD wastewater. One could be landfill leachate, Chu said. If that's the case, power plants will have to decide whether they can co-manage the leachate in their main treatment plant, or if it will have to be treated separately. Chu noted that if a power plant closes, the landfill often remains, which could require plants to treat the leachate stream "for eternity."
Bottom ash and fly ash wastewaters are also a consideration.
"It's just a matter of time when EPA will regulate fly ash wastewater and restrict it," Chu said. "If that's the case, you are potentially looking at moving from wet ash to dry ash approach."
Bottom ash is less soluble and easier to treat, but new effluent limits also might drive a move to dry technologies.
"The long term vision of power plants is to minimize discharge and recycle and reuse wastewater," Chu said.
The challenge with water recycling, along with treating for new constituents, is first understanding the water streams flowing through a power plant, Scott said.
"Typically when we get involved with a client, they know the flow coming into the plant and the flow leaving the plant, and they know the regulated constituents in the flow leaving the plant, but beyond that, there tends to be very little information," Scott said. "They don't know their internal flows, and they don't know the contaminants that are in those streams.
"The first thing we do is look at data gaps and how to get at least some data, because if you are going to initiate an internal recycle program, then you need to know how much flow is available, you need to know what level of contaminants there are," Scott said. Also, "You need to be careful about cycling up concentrations of contaminants so you don't take something from a level that is within the bounds of your permit to something that is out of bounds that would force you to treat."
Taking hard look at the water balance of facility can often lead to changes in operation that can significantly reduce the amount of water required, or the amount of contaminants that must be removed.
"When we look at water issues, there are modifications you can make inside the power block that have a significant impact on your water consumption, or contaminant concentrations," Scott said. "For example, switching to dry ash handling. We've seen circumstances where it looks like a switch to dry ash handling pays off in terms of reduction in total flow to be treated."
"Sometimes you have to start walking back up in the power plant and say, okay, what potential changes can be made, and if you make them, how much do you save, and will it pay for the change."
While coal combustion residuals might not be specifically addressed in the new effluent guidelines, many people in the industry believe that the time will come when power plants will be forced to retire their storage pond systems.
"You don't have to raise the specter of TVA Kingston. Everyone knows its out there," Scott said. "People are already evaluating what they are going to do with their ponds. There's a lot of pond retirement work going on in advance of the issuance of the coal combustion residuals rule."
Scott said as power companies consider their treatment options for meeting the new effluent guidelines (ELGs), they might also consider building in enough redundancy to help them retire ash storage ponds.
"From an economic standpoint, if you look at the impact of ELGs and anticipate what's going to happen with coal combustion residuals (CCR) and work those two issues together, you are going to come up with a more economical solution than if you attack the ELGs today and then wait until the CCR is issued to deal with that one," he said.
Whatever treatment system plants install, "You would probably install excess capacity just from a reliability standpoint," Scott said. "If you plan well, you can use that excess capacity to work down the volume in your ponds."