Boilers, Coal, Policy & Regulation, Policy & Regulations

GE’s Perspective on the ELGs

Issue 7 and Volume 120.

By Renee Twardzik

In late 2015, the Environmental Protection Agency (EPA) released new Effluent Limitation Guidelines (ELGs) aimed at reducing, or eliminating, toxic metals and other pollutants from entering surface waters from steam electric power plants. The new rules specifically address FGD wastewater from coal-fired power plants and identify chemical precipitation followed by biological treatment as the best available technology (BAT) for treating and discharging the waste from existing plants. They also reference evaporation/pozzolanic solidification for new facilities.

To get a better perspective on the impact of these regulations and what they mean for power plants, we sat down with three of GE’s experts on this topic to find out more about the guidelines, implications for power plants, and available technology. Our panel is made up of:

  • Bill Heins, General Manager – thermal ZLD products
  • Trevor Dale, Product Development Leader
  • Nelson Fonseca, Product Manager – anaerobic MBR and ABMet
Bill Heins
Trevor Dale
Nelson Fonseca

The panel was asked a series of questions concerning the ELGs and the technology. Here are their answers, which were edited for clarity, style and space.

Q: Tell me about the new guidelines. When were they released and what is their intended purpose?

Bill Heins: The EPA issued the final rule for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category in September 2015. The original rule, last updated in 1982, required further updating to adequately address certain pollutant discharge limits as well as other factors. The intended purpose of the National Pollutant Discharge Elimination System (NPDES) permit requirements is to minimize or eliminate pollutant discharge, and is promulgated under The Clean Water Act. The new guidelines are intended to make significant progress toward that goal, specifically addressing the flue gas desulfurization or FGD wastewater stream.

Trevor Dale: The EPA’s new effluent guidelines for power plants significantly impacts large (>50 MW) coal-fired power plants by setting strict limits on the concentration of toxic pollutants, such as heavy metals, that can be discharged in a plant’s wastewater. While the rule is not specifically limited to coal-fired plants, the contaminants of primary concern in the rule are those produced in appreciable concentrations when coal is burned for electric power generation. They outline multiple strategies to treat the wastewaters of interest and focus on a treat and discharge, also referred to as chemical precipitation followed by biological treatment, approach as best available technology. They also reference thermal evaporative approach for new sources and, under a Voluntary Incentive Program for existing sources, which provides more time to comply with the regulation.

Nelson Fonseca: The new ELG guidelines for the steam electric power generating industry provide a new national standard of water quality for wastewater effluents typically discharged from power plants, such as coal-fired power plants, to the environment. The goal of the new ELGs is to limit the discharge of several key constituents that pose a threat to the accepting water shed environments, such as selenium and mercury.

Q: What are Power Plants evaluating in their own facilities as they begin to design a path forward to meeting these guidelines?

Trevor Dale: Many things come to mind, depending on the plant and parent company, which are at the top of the list under consideration by power plants regarding this rule. Plant profitability and projected operating life, their date of compliance, auditing their current operations to determine where they are today relative to the rule, their local NPDES permit, or projecting where the NPDES permit will be. Since the ELG rule is a guideline from the EPA, each plant will get its own discharge limits locally via their NPDES permit. They are also looking at modifying existing operations internally to minimize the waste stream generated. This in turn will decrease the potential cost of a solution.

Nelson Fonseca: Coal-Fired Power Plants specifically have several water and wastewater streams to manage within the footprint of the plant prior to any discharges occurring. Not only do Power Plants need to consider the new ELGs, but also the new CCR rule, or coal combustion residuals rule. The CCR rule, unlike the ELGs, does not deal with water quality, but instead deals with the design and use of surface impoundments, such as ash ponds, for the storage of coal combustion residuals like combustion ash. The combined effect of both the ELG regulation and the CCR rule will require power plants to first re-think their overall water balance and management strategy, and then develop specific programs to deal with individual treatment of discharge streams. The discharge stream that may provide the most significant challenge for coal-fired power plants is the blowdown from the Flue Gas Desulfurization Absorber, or FGD absorber. The water quality of this stream is impacted by several factors including the type of FGD absorber that is in place, how it is operated, types of fuels used, source of makeup water, and loading of the electrical generating units over time. For this reason, utilities must strive to gain a good understanding of the correlation between the fuels that are burned, the process and operation of the air treatment train, and the resulting water quality. A thorough and detailed sampling and analysis campaign of the FGD blowdown water is a good start.

Bill Heins: When a plant is looking at their options for FGD blowdown water treatment, some things they will consider include type of coal, variability of coal feedstock, variability in their wastewater chemistry and how closely they anticipate being to their discharge limits, capital and operating cost, implementation timeline, and reliability and flexibility in plant operations. One of the interesting insights that has emerged from discussion since these guidelines were released is the fact that many power plants are looking to “future proof” their facilities in order to meet potential federal or more stringent state guidelines which may be promulgated in the future. Some customers are anticipating “down the road” changes and are looking to avoid a retrofit in the future.

Q: Coming into compliance with these new regulations can be costly for some plants. How does the long-term outlook help to offset the initial cost-burden that some plants will face?

Bill Heins: First and foremost, these regulations are mandatory, so compliance is a must. But, prior to rolling this out, the EPA did significant economic studies to ensure that the industry could handle it. Furthermore, the EPA evaluated the impact of the final rule with a positive economic benefit to the USA coming in somewhere in between $450 – $560 million annually. And for power plants themselves, the EPA factored in the cost of implementing the changes when they came up with the rule. However, they considered the cost of a traditional zero discharge system, not the evaporative / solidification approach, where we are able to cut 30 to 50% in capital expense and 20 to 40% in operating cost, as compared to the traditional zero discharge approach. Regarding the long-term outlook, the new rule is forcing customers to evaluate existing plants to determine if an upgrade makes sense, or if decommissioning older plants is the better approach. Every customer is determining their long-term strategy according to what makes the most economic sense for them. For example, if return or operating cost is more favorable at one particular plant over another, one plant may be retrofitted where another may be decommissioned.

Trevor Dale: To be honest, it’s a much larger decision than just focusing on ELG compliance. Each company will look at each unit operating within a plant and take the costs of complying with this new regulation with their other requirements around discharge/emissions, the costs of operation, and the future outlook; items like fuel prices, potential CO2 regulations, renewable generation, etc. They will make a decision if it makes sense financially to retire the unit, or plant, or continue generating power. Once the decision is made to continue operations, the real work on the water side starts with determining how to comply long term with the ELG requirements.

Q: What are the top 3 questions or concerns that you are hearing from power plants as they try to determine which solution is best for them? How are you guiding them in their decision?

Nelson Fonseca: One typical concern is the ability to come into compliance within the timeframe provided by the EPA. Many utilities have begun to develop a robust understanding of their overall water balance and water chemistry, but many feel that it will take time to develop. A second common concern is the bandwidth of solution providers to fill the coming demand from utilities. Utilities are concerned that there may not be anyone available to help them with their solution in time. The third concern has to do with getting a solution with guaranteed performance. Utilities do not want to buy equipment from several equipment vendors and take on the risk of the entire solution; they want one source of accountability that can provide a comprehensive solution backed up by a strong process guarantee.

Bill Heins: The top three areas of discussion I hear are fairly consistent across the board so far, and those are: cost which includes capital expense and operating cost; system reliability and long-term operating performance; and flexibility in making sure to choose a solution that will help keep the plant in compliance in the future. To answer the second part of your question, how are we guiding them, the simple answer is we’re not. Instead, we’re providing our customers with collaborative support, where we are literally sitting down with them to evaluate their facility, develop multiple solutions that could work, and helping them choose the optimum solution for their particular situation.

Trevor Dale: I agree with my colleagues, the customers really just want to hear their options. Many power companies have built internal teams to review their fleet-wide assets and the potential technologies that can meet the new requirements.

Q: The new guidelines specifically call out a chemical and biological approach as a Best Available Technology for retrofits. Considering that this approach may be less costly than an evaporative ZLD application, are Power Plants implementing this solution solely based on finances or is there a long-term benefit that they can realize as well?

Trevor Dale: Finances will play a key role in what technology gets implemented. Combined with that is the length of time the utility expects a specific plant will be profitably generating electricity, as they may be more likely to implement a treat and discharge approach for a plant with a limited lifetime. However, a newer, more efficient plant may make the ZLD investment more attractive as a way to “future proof” their plant against future water discharge regulations.

Chemical precipitation and biological treatment was referenced as BAT since it has been proven effective on FGD wastewater already. The effluent limits in the new ELG rule are very strict and the existing full-scale operations were key to establishing the long-term viability of this approach. Another benefit of this approach is the relatively small operational expense: the biological system operation is mostly automated, but requires a nutrient be added to ensure optimum bio-health for contaminant removal. This combined with sampling, testing, and other operations should only require a part-time operator.

Q: What is design process like to get this type of solution on board? How does a plant get started and what is the timeline for installation and commissioning?

Trevor Dale: While each system is unique, a good approximation of the timeline is in the range of one and a half (1.5) years to two and a half (2.5) years to full operation, depending on the existing infrastructure of the plant. This means that plants on the front end of the permit cycle, where their NPDES permit will renew in early 2018, need to be reviewing options very quickly. However, it really crosses the entire spectrum, since some plants have a good idea of what they’ll need to do while others have none. To support our customers, we’ve developed an audit process to evaluate a plant’s needs from a treat and discharge approach that pulls in expertise from our engineering, technology, and commercial teams.

Nelson Fonseca: The first step for utilities struggling to develop a path toward meeting the new requirements is to understand what they have now. This means having a very good understanding of their entire water balance and the water chemistry of specific effluents. The results will be the starting point in creating and evaluating scenarios and options that will ultimately form the basis for a new water management strategy. The results of such an exercise will also be invaluable when working with engineering firms and solution providers such as GE, when developing specific solutions. Once a path is chosen, development of the specific treatment flow sheet can begin. This step may involve additional water sampling and analysis, understanding of upstream processes and fuel sources, laboratory testing, and onsite pilot demonstrations if required. Once the treatment flow sheet is finalized and the execution teams begin their work, it typically will take anywhere between 1.5 to 2.5 years to build, commission and hand-off the plant to the end-user.

Q: What are the top 3 questions, or even concerns, you are hearing from power plants as they dive into this specific application? And how do you answer those questions?

Nelson Fonseca: The ability of a treatment system to handle the possible variability in water chemistry is a concern expressed by utilities; however, many are putting in a strong effort to understand that variability and plan for it as much as possible. As an example, some utilities have significantly improved the coordination between the fuels team, generating team and environmental team, which will help ensure that those managing the treatment plants can better prepare for “what is coming down the pipe.” GE’s approach is to collaborate with utilities early on in the project development cycle in order to identify the possible sources of variability and help develop a design basis that will not only meet their requirements today, but also reduce their risk in the future. Along with better internal communication, it is important to identify sources of variability early and build them into a design basis, and to design treatment systems with the flexibility to handle future variations.

Trevor Dale: One concern that has been raised is the viability of biological treatment on a variable water source such as FGD wastewater. The view is that the biological process will be interrupted and ineffective at removing the targeted pollutants as the wastewater varies. Thankfully, the EPA drew on a large dataset to answer this question in the ELG rule and wrote that biological treatment has been shown to be successful when operated in tandem with a properly function chemical precipitation process. This is why the EPA designated this treatment approach as BAT.

Plants are looking for new ways to minimize both the volume and variability of the waste streams. This in turn will minimize costs of compliance and can significantly improve the performance of the chosen solution. This is an area we are focusing on now and with GE’s recent acquisition of Alstom, with an installed base of >140 GW of FGD capacity, we are able to provide an even broader solution set and engineering services.


Renee Twardzik is global communications manager at GE Water & Process Technologies.