By Susan Peterson Sturm

A recent survey by IT consultants Capgemini found that 200 senior utility executives worldwide expect their companies to achieve a 5 percent productivity gain using digital solutions over the next five years. What is striking about this expectation is that the same group indicates they have achieved a total productivity gain of only 0.8 percent since 1990.

Digital is expected to be a gamechanger, so the industry’s broad adoption of digital solutions is no coincidence. Many basic business assumptions about how the industry operates have been turned upside down in recent years through the effects of power market deregulation, increasingly stringent environmental constraints, the creation of wholesale power markets and the addition of renewable generation resources, and others. Traditional business value streams and asset utilization models are being called into question, and new players and business models are emerging. This article examines how digital can help power generators not only to survive this challenging period but use digital technology to enable new business models and thrive.

There is much hype around digital, so industry veterans are right to be cautious. They are focused on producing safe and affordable power. Rarefied discussions about the best industrial IoT platform or the benefits of the cloud often result in an eye roll from those with 20 years or more in the industry. To keep it real and engage skeptics, digital is best looked at in the context of key challenges for a specific vertical. For example, an OEM or EPC for power generation has vastly different challenges than a utility power generator, independent power producer or an inside-the-fence industrial cogeneration site. To illustrate this approach, let’s look at the key challenges facing utility generators today.

Knowledge-retention

A key challenge for companies operating in mature power markets worldwide is the retirement of experienced operations personnel; in the United States, 40 percent of the workforce at electric and gas utilities will be eligible for retirement in the next five years, according to the American Public Power Association. As people retire, how does the industry retain operator and process engineering expertise? Digital can be a significant enabler when staring down the barrel of the “great generational shift.” Secure remote connectivity, like ABB’s Collaborative Operations Centers, provides increasingly scarce internal resources with expert support for operations and maintenance. Simulation and benchmarking can also help ensure that best practices are applied at every site.

As an example, ABB worked with a supercritical power plant in a remote part of Africa that was struggling with a lack of local expertise, operator variation and performance degradation of the boiler. Together with the plant owners we focused on soot blowing practices. We worked with local teams to create simulators that showed not only key performance indicators, focused on recoverable degradation, but also found ways to create operator tools to make consistently optimized decisions on when to perform soot blowing. Ultimately, we applied model predictive control (MPC) to close the loop and consistently execute soot blowing sequences. The solution achieved $175,000 per year in fuel savings and more consistent operation, enabling better execution in dispatch, supply chain and maintenance functions. Digital allows customers to scale these same solutions across a fleet of similar plants, thereby accelerating time to value.

Mastering competitive markets

For conventional base load plants built more than 10 years ago, ABB has looked at parts of the generation process that can impact both cost and revenue. For example, at a large coal-fired plant in Europe, ABB analyzed the combustion process, use of abatement materials and at opportunities to increase top line revenues through focused activity in ancillary services markets. Through optimization and closed loop control changes, we were able to reduce variable costs by $500,000 annually by reducing fuel consumption at start-up, improving combustion efficiency and reducing abatement costs. By helping the customer understand costs associated with engaging in primary frequency markets, we were able to grow top line revenue opportunities for the plant.

Developing a strong digital foundation

Any successful transformation requires strong alignment of people, process and technology. There is at least one supercool, disruptive technology that was never adopted because it did not have stakeholder engagement or did not take into account the business process changes needed to implement it. As a result, there is a need to be hyperaware of maturity. Here are a few considerations to help organizations address the ever-important people and process facets of digital adoption.

It starts at the top

Utilities are undergoing a cultural shift towards an information-based digital economy — where primary processes are digitalized – and moving away from the traditional business model that requires heavy investment in physical assets. In the face of this change, chief executives feel there is a real danger of getting left behind if they fail to rally their organization to the new digital order. The drive from leadership is key to the implementation of successful digital projects. It is vital that there is a clear link between any digital project and a company’s strategic priorities.

Pick partners with expertise and experience

Customers have rich networks of multiple digital partners – this view contrasts with some digital vendors that push for a single platform. The partners selected should be able to demonstrate industry expertise, proof-points of challenges solved and maturity in software development and cyber security. If digital partners have worked with companies experiencing similar market and operational challenges, the chances are the customer will benefit from the solutions applied and lessons learned.

Select open technologies

Power generators have complex technology stacks of varying age, often spanning several decades. The industry has plenty of technology debt to address over the next 20 years. Focusing on platforms and solutions that integrate well with others is key. Some platforms, for instance, use industry-standard, open-source and proprietary software. They combine technology leadership and domain expertise with strategic partnerships. This approach makes it easier for customers to integrate solutions with other platforms they have already deployed. It also enables system integrators to create new applications that interoperate with specific solutions. Such a broad, open and inclusive ecosystem delivers massive benefits to customers, compared to narrow, closed and exclusive proprietary systems.

Conclusion

The power generation industry has a track record of resilience and innovation in times of disruption. But it also demands solutions that help it deliver its higher purpose of safe, reliable and affordable power. If digital continues to deliver solutions to these challenges, and enable new business models to evolve and flourish, the digitalization of power generation will expand and escalate, faster than many expect.

Susan Peterson Sturm is the Digital Lead for ABB Power Generation & Water.

By Editors of Power Engineering

THE U.S. DEPARTMENT OF ENERGY’S Office of Fossil Energy announced a $50 million funding opportunity to design, construct, and operate two large-scale pilots for transformational coal technologies that improve coal-powered systems’ performance, efficiency, emission reduction and electricity cost.

DOE has previously supported a range of potentially transformational coal technologies aimed at enabling step-change improvements in coal-powered systems. Some of these technologies are now ready to proceed to the large-scale pilot stage of development.

Applicants to this new program should have already demonstrated technical success at a small-scale pilot stage, and a 20 percent minimum cost share on total award values is required.

The FOA will involve three phases:

– Phase I, Feasibility, will support efforts to secure team commitments; update the preliminary cost estimate and schedule for design, construction, and operation; secure construction/operation cost-share funding; and complete an environmental information volume.

– Phase II, Design, requires selected projects to complete a front-end engineering design study and complete the National Environmental Policy Act process.

– Phase III, Construction/Operation, will select two final projects to support construction and operation of the large-scale pilot facilities.

More information about this funding opportunity can be found at https://www.grants.gov/web/grants/search-grants.html?keywords=DE-FOA-0001788.

The Seven Deadly Sins of Cogen-Project Management

By Rob Swanekamp and Bob Sansone

During the construction boom in combined-cycle/cogeneration plants of the 1990s-known as the ‘dash to gas’-we were brought in, under different employers, to help several projects that had fallen behind schedule, or that were suffering from acrimonious relations between a major contractor and the Project Owner (Fig 5-1). In those days, multi-million dollar lawsuits got tossed back-and-forth like hot potatoes, as each project player unfurled its various contracts, and pointed to some obscure clause to argue the latest dispute.

Unfortunately, the projects reaching this point would spur highly skilled engineers and craftsmen to swap out their sweat-soaked tools of hard hats, wrenches, and welding torches, for the quill-tipped instruments of point/counterpoint, claim/counter-claim, and lawsuit/counter-lawsuit.

After seeing this sad story play out time and again, project after project, we noticed that all of the troubled projects had one thing in common: They were doomed from the onset because some fundamental precepts of project management had been misunderstood, or were ignored purposely.

Hear that boom?

Now, with a new construction boom in combined-cycle/cogen plants revving up, we’d like to remind today’s participants of some lessons learned in the last boom.

Let’s look at the seven phases that combined-cycle/cogen projects typically go through. Depending on how they’re managed, these can be either the seven steps to success or the seven deadly project sins:

Project conceptualization and definition

This is where it all begins. Where a developer’s vision starts to become a reality-at least on paper. Unfortunately, this first phase often was a problem in the 1990s, because when a reality revealed in the financial spreadsheets or CAD drawings clashed with the developer’s vision, then he often dismissed the reality, and ordered his team to move forward anyway (Fig 5-2). This “damn-the-torpedoes, full-speed-ahead” mentality famously worked in Naval warfare, but it failed over and over again in cogen-project development. So our advice to today’s developers is to be brutally honest here!

Resource assessment

Be brutally honest, too, in this second phase, assessing your resources. Even though it’s very early in the game, you need to bring onboard qualified people with relevant, and up-to-date experience on your specific type of project. One developer in the 1990s happened to have a trusted friend with the mechanical skills to fix any car, no matter the trouble, and to lay down a very nice welding bead in his backyard shop. So the developer brought his mechanically inclined friend into his project right from the get-go, and assigned him the job of sourcing, procuring, and erecting an F-class combined-cycle project. But that’s a job too big for a backyard mechanic, so the project was doomed right then.

Obtaining permits

After the right people are onboard, their efforts need to be tightly coordinated, as we saw in the permitting phase of this project: A small power producer was adding a new unit to its existing plant, so an environmental consultant was contracted to obtain the needed air-emissions permit. Reasonably enough, the consultant began by asking for the historical air-emissions data from the O & M crew at the existing unit. Paperwork went back and forth between the parties, an application was submitted, and soon enough, the new permit was issued. So at this point, the project appeared to be going smoothly.

But what wasn’t noticed until much further down the development road was that the three parties-the existing unit’s O & M crew, the environmental consultant, and the regulatory agency-were talking about air-emissions in three different scientific units: parts per million, dry (ppmvd), tons per year (tons/yr), and pounds per million British Thermal Units (lb/MBtu). As a result, the new permit was issued with three different-and conflicting-sets of emissions limits! Months later, when source testing of the new unit was being conducted, the developer happily submitted the data to the state regulators, showing full compliance with his permit -at least, with the permit-limits that he was looking at (in ppmvd). But the regulators evaluated the test-data using the different, and more stringent units. So they determined that the new unit had failed its source testing! This math mistake seemed innocuous enough, but the regulators refused to correct it by revising the permit, largely because earlier problems at the site had created an acrimonious relationship between the power producer and that regulatory agency.

Contract negotiations

Once the air permit is in-hand, a new cogen project seems to start galloping forward in this fifth phase. But whoa, Nelly! Contract negotiation turned out to be a very tricky art form during the dash to gas. Negotiating and writing so many different contracts- power-sales, steam-sales, and fuel-purchase agreements-proved to be more complicated than anticipated, because of contractual ambiguities that would “jump up and bite” the project later down the road. To paraphrase the old real estate adage, the three most important issues in this phase are risk, risk, and risk! Exactly who is taking it, according to the contracts’ fine print? Is it the fuel supplier because of fluctuating gas markets? The lender because of market currency? Or is it the equipment suppliers because of performance guarantees?

Tracking progress and assessing schedule

A phase that often plagued Project Owners during the dash to gas was the lack of an accurate schedule to assess actual progress. At many projects, everything reportedly was staying on-schedule and on-budget, until about three-fourths of the way through, when incremental slippage suddenly was reported in a critical-path milestone. These “surprises” typically resulted from the developer expecting his contractual threat of liquidated damages (LDs) to ensure project schedule and control. The most successful projects, in contrast, ensured project schedule and control the old-fashioned way: They had a human being – a highly evolved creature who thinks, and breathes, and tries, and cries- frequently go onsite to eyeball the actual progress. The need for an involved Owner’s Rep wasn’t a new lesson, it was a textbook example of the old management adage “You get what you inspect, not what you expect.” No, we’re not suggesting that today’s developers completely eliminate LDs from their contracts. We’re only saying that LDs by themselves aren’t enough. They need to be supplemented with onsite inspections by qualified people, and balanced by contractual incentives for early completion.

Commissioning and initial startup

In the dash to gas, this sixth phase often got so complicated and so tragic that it was likened to a Shakespearean drama by Larry Straight, the founder of Sterling Energy International, Inc., and one of the best Startup Managers in the business. Traveling between our many assigned projects, we understood Larry’s metaphor: the set would change, and the characters would have different names, but the basic plot remained the same. The developer was confident that he had a winning project, so his main objective was getting to the acceptance testing, and he just wanted all those egghead engineers to stay out of his way! The EPC contractor, for its part, was equally confident in its design/build efforts, so its main objective was to keep the developer from getting in its way. You see the misalignment of objectives here? You might be wondering, therefore, is this phase hopeless? Is the commissioning/initial startup doomed to be an adversarial process, like haggling with a used-car salesman? Absolutely not. There were some projects in the dash to gas that DID have a smooth, professional commissioning and initial startup. Their keys to success were well-written contracts that aligned the objectives for all parties, and a talented Startup Manager on the Owner’s team. Don’t confuse Startup Manager with Plant Manager, because startup management is a discipline of its own. Many a Plant Manager who is well-equipped to tend an existing plant, would get overwhelmed in the commissioning phase by all the reports, budgets, spare-part inventory, training programs, warranty issues, policy manuals, and other start-from-scratch tasks he must tackle.

The handoff to the running back!

After that initial startup was completed, and the plant passed its acceptance testing, project participants in the dash to gas hurried to open the champagne, and toast their victory. But their celebrations often were premature, because this seventh, and important step wasn’t done. Responsibility for the plant must be transferred from the EPC contractor to the owner. Yes, this was always completed in the legal sense, with a few quick signatures. But a proper turnover requires transferring the wealth of engineering knowledge from the EPC contractor to the owner’s O & M crew. The crew needs that knowledge to operate the plant reliably into the future. Think of it as handing off the football to the running back who can take it to the goal line! In our business, the “football” is called “the turnover package,” and it must not be fumbled. The turnover package is a vast pile of documents and electronic files that must be assembled, reviewed, revised, and archived. If the project is large enough, it may warrant a full-time employee handling the package, often given the title of Document Control Clerk.

If it’s a smaller project, the Plant Manager and an Admin Assistant might be able to handle the task. In either case, there needs to be a formal process to (a) review all the documents for technical and contractual accuracy before they are authorized for use by the O & M crew, (b) update those documents when-and only when-changes are authorized, and (c) remove from circulation and, if appropriate, destroy obsolete documents. The best turnovers that we saw kept to a minimum the number of controlled documents-typically stamped “Controlled Copy” in red-and create a “For Reference Only” set of documents-usually stamped in black. The best turnovers also made a formal distinction between ‘documents’ and ‘records’. Documents established engineering facts-such as the as-built diagrams of process and instrumentation systems (the P&IDs). In contrast, ‘records’ were legal evidence that some milestone had in fact occurred-such as the code-required inspections of the HRSG by an Authorized Inspector, or the regulatory-required calibration of the emissions-control system, prior to source testing stack emissions. Every plant, regardless of size, needs a well-organized filing system and a quiet space-a library, really-to retrieve, spread out, and discuss the overwhelming stack of documents and records. Your goal should be to maintain control of the paperwork without forcing the O & M crew to comply with a cumbersome, bureaucratic system, who are trying to fix some broken pump and get the plant back on-line as quickly as possible.

Rob Swanekamp is owner of HRSG User’s Group Conference and Exposition. Bob Sansone is the CEO of Power Gen and Construction Practice LLC

By Doug Lewin

The utility grid has been shaped by a century of regulatory action that provided the infrastructure and framework that allowed it to grow to the safe, reliable grid we know today.

But the energy landscape is rapidly transforming as new technologies emerge and customer preferences change. Utilities and engineers have more tools and opportunities available to them now than ever before. Adding to this, utilities are in an environment with an expanded set of policy goals and customers have an increasing number of alternatives to traditional supply. Combined, these options mean that innovation is more accessible – and potentially more confusing – than ever.

While utilities across the country are adapting to manage and navigate a new energy environment, it can be helpful to look at four states who have implemented innovative regulatory mechanisms to incentivize utilities to help customers better manage their energy.

Energy efficiency programs, in the right regulatory structure, increase system efficiency, empower customers and enhance utility shareholder value.

Illinois Introduces Regulation to Incentivize Energy Efficiency

After Illinois established energy efficiency programs in 2007, they found themselves facing a common challenge. Infrastructure spending came with a return on equity while energy efficiency was treated as an operating expense, meaning shareholders naturally leaned towards infrastructure spending over energy efficiency programs. To fix this (and address myriad other problems), Illinois passed the Future Energy Jobs Act in late 2016 that allowed the state’s electric utilities to earn a return on equity for energy efficiency spending. This model addresses the problem of misaligned incentives without removing the old cost-of-service model, essentially marrying the old with the new: cost of service regulation with incentives for customer empowerment and smart energy management.

Under the Future Energy Jobs Act, the return on equity for utilities equals capital spend if they reach 100 percent of their energy efficiency goal.

For every one percent above its goal, a utility can earn eight additional basis points. If they maximize the benefit, a utility that achieves 125 percent of its goal would be entitled to a return on equity 200 basis points (two percent) higher than its normal return.

This model effectively makes substituting cost-effective energy efficiency for infrastructure more desirable for both shareholders and customers.

Michigan Optimizes for Customer Empowerment

Following regulation put in place in 2008, Michigan recognized the powerful customer savings achieved by energy waste reduction and in 2016, sent a strong signal that consumer empowerment is important to the state by allowing utilities the opportunity to increase their incentives.

While the state removed previous mandates for efficiency after 2021, it allowed the utilities to retain the ability to earn their current incentive levels as long as they maintain a one percent reduction in retail sales each year. And if utilities are able to exceed that goal by 25 percent, they could then earn the lesser of either 17.5 percent of energy efficiency expenditures or 27.5 percent of net benefits. If they were to exceed their goals by 50 percent, they could then earn the lesser of either 20 percent of energy efficiency spend or 30 percent of net benefits.

Using performance incentive calculations from recent years, if utilities meet these aggressive goals, additional incentives could equal $3 million – $6 million for utilities, while their customers would save approximately an additional $30 million per year-a great example of customer and investor benefits.

This new law gives flexibility to the Michigan Public Service Commission to develop an alternative methodology for decoupling and/or other incentives should the commission determine that current methods are insufficient to ensure energy efficiency and demand response are not “disfavored compared to utility supply-side investments.”

Maryland Combines Efficiency, DR and Advanced Metering to Generate ROI

After restructuring in 1999, Maryland utilities discontinued their demand-side management energy efficiency programs. Around 2005, when it was apparent that the competitive retail market was not delivering energy efficiency programs and customer satisfaction was low, stakeholders reconsidered these programs and proposed a combination of energy efficiency, demand response and advanced metering infrastructure to the Public Service Commission.

Maryland created one of the most successful cost-recovery mechanisms for energy efficiency in the country. Operating expenses for energy efficiency and demand response were converted into capital expenditures that were able to earn a full authorized return on investment amortized over five years. In practice, investing roughly $125 million per year into energy efficiency creates a five-year, $500 million regulatory asset-earning ROI.

Additionally, the utilities benefit from full decoupling, removing the disincentive related to energy consumption levels. This, combined with the ability to rate base energy efficiency, has worked extremely well to align utility incentives with decreasing costs for customers.

This arrangement in Maryland has not only created significant return on investment for utilities, but it has boosted customer satisfaction scores. As recently as 2008, its JD Power scores were near the bottom, but have since reached the top quartile.

Utah Replaces Aging Power Plants with Energy Efficiency

In March 2016, the Utah Legislature passed Senate Bill 115, also known as the Sustainable Transportation and Energy Plan Act, allowing Rocky Mountain Power to “capitalize the annual costs incurred for demand-side management” and to “amortize the annual cost for demand side management over a period of 10 years.”

In addition to allowing a return on investment in energy efficiency programs, SB 115 also addresses two other major problems:

Many states are struggling to deal with older power plants – usually fossil fuel or nuclear – that are no longer economically viable due to low natural gas prices, higher adoption of energy efficiency, lower cost of renewables and more stringent environmental regulations.

Energy efficiency is usually paid for upfront and must be cost effective in the first year.

However, many energy efficiency installation measures like HVAC systems, insulation and LED lights are designed to save energy for at least 10 years.

As a result, some energy efficiency programs do not appear to be as cost effective as power plants. If power plants, transmission lines and substations were given the same financial treatment and paid for by ratepayers in the first year, very little infrastructure would ever be built.

SB 115 solves both these problems by making energy efficiency programs a 10-year regulatory asset, which greatly improves their cost effectiveness relative to other energy resources. And because Rocky Mountain Power only needs a portion of the funds from the energy efficiency regulatory asset each year, it can use the remaining funds as accelerated depreciation for an older, economically inefficient plant. This way, Rocky Mountain Power can recover the cost of an aging power plant and retire it early, replacing it with an energy efficiency asset, making for cleaner air and lower costs for consumers, all while increasing energy efficiency.

Meeting the Evolving Regulatory Model

While the four states mentioned previously have made significant progress and implemented innovative programs, much more work needs to be done to ensure that utilities are continuing to provide safe, reliable and affordable energy while meeting the changing needs of today’s customer. And to do this, the engineers within the utility will play a vital role.

The pairing of regulatory environments such as the ones seen in Maryland, Utah, Illinois and Michigan, along with the expectation of today’s consumer to be more involved and informed, indicates a shift to a distributed network model rather than a central power plant model. This will ensure a more reliable, safer and efficient grid and create additional opportunities for engineers to expand their skills and lead the way through this change.

For example, engineers can assess load pockets to identify congested areas and use demand response techniques to increase capacity factors, reduce peak demand and increase usage off-peak, decreasing the need for additional infrastructure. Another scenario could be identifying neighborhoods or commercial building areas where capacity factors are lower and potentially install a solution like thermal storage to manage peak capacity.

The skills traditionally required of utility engineers remain critically important, but as with every profession and skill, they are changing as technology advances and consumer expectations evolve. Therefore, having a strong line of sight into the regulatory changes and how to use demand side resources to increase the optimization of the system is something every engineer should understand.

Doug Lewin is Vice President of Policy for CLEAResult

By Todd Whiting

The U.S. Environmental Protection Agency (EPA) issued the final effluent limitation guidelines (ELGs) rule in September of 2015 for the steam electric power sector, establishing technology-based regulations that target reductions in toxic metals and other harmful pollutants from power plant wastewater discharges. The ELGs are based on technology improvements in the steam electric power industry over the last three decades and establish new requirements for wastewater streams from flue gas desulfurization (FGD), fly ash, bottom ash, flue gas mercury control (FGMD), and gasification of fuels.

The new rule sets stringent effluent limits on arsenic, mercury, selenium, and nitrogen for FGD wastewater and zero discharge of pollutants from ash transport water and FGMD wastewater. Additionally, rigorous limits are placed on arsenic, mercury, selenium and total dissolved solids in coal gasification wastewater based on evaporation technology, and strict controls are established on any new coal or petroleum coke plants that may be built in the future.

Although EPA’s rule does not require power plants to use specific technologies to comply, the new ELGs were developed based on the performance of what EPA determined to be the best available technology (BAT) for treating each specific process wastewater stream. For achieving compliance, EPA estimates that roughly 12 percent of steam electric power plants will have to make new investments including design modifications, process changes, facility expansions, or installing new treatment systems.

Challenges with FGD Wastewater

Quite possibly, the most challenging aspects to the new ELGs is addressing requirements related to treating FGD wastewaters. These difficult-to-manage discharge streams can be very different from site to site, with contaminant compositions influenced by a range of factors including coal type, makeup water quality, as well as the specific technology used in the plant for removing sulfur dioxide from exhaust flue gases.

According to Jonathan Shimko, director of power & water solutions at Tetra Tech, FGD wastewater is one of the biggest concerns for most people in the power industry due to the inconsistency of these waste streams. “The composition of FGD wastewater is highly dependent on the fuel source used in the plant,” Shimko said. “For this reason, FGD wastewater can exhibit significant regional variability-a station in the West might face a completely different set of challenges than a station in the East due to differences in the coal type. As one example, eastern bituminous coals tend to have higher chloride and sulfur content, generating an FGD product that can be more difficult to handle than subbituminous or lignite coals found in the central and Gulf regions.”

In addition to those constituents, coals can also contain varying ratios of other components such as calcium, magnesium, or dissolved silica, which will ultimately affect the FGD wastewater.

Since treating FGD wastewater is case-by-case, station-by-station, and fuel source-by-fuel source, a universal approach that could work for any situation is not readily available. “As such, addressing FGD wastewater requires a specific evaluation of the water quality, the quantity of water, and the systems that are in place,” Shimko said.

Shimko advises that as a first step, power plants should develop a thorough water balance at their sites, followed by an understanding of the plant’s water needs, including the way that water can be managed within the confines of the rule.”

FGD Treatment Strategies

For existing coal-fired plants larger than 50 MW, the ELGs set limitations on FGD wastewater for arsenic, mercury, selenium, and nitrate-nitrite as N and specify a BAT combination of chemical precipitation treatment followed by anoxic/anaerobic biological treatment. Power plants can also address FGD wastewater by implementing certain process changes rather than installing new wastewater treatment systems. According to the EPA, some power companies have expressed interest in approaches that would use FGD wastewater from a wet scrubber as makeup for the sorbent injected into a dry scrubber, and as a result, completely eliminate FGD wastewater discharge.

As another alternative, power plants have the option to participate in EPA’s voluntary incentives program for treating FGD wastewater, which provides deferred compliance to December 31, 2023 for plants that agree to meet stringent ZLD limitations based on the performance of thermal evaporation technologies. While the extension allows plants more time to gain a better understanding of their FGD waste streams and develop the most effective approach, larger plants anticipating future regulations may opt to pursue thermal evaporation as an insurance policy, as thermal evaporation would most likely cover any future regulations or contaminants that the EPA may target-such as boron.

But while vapor-compression evaporation technologies may offer a way to mitigate potential risks from future and more stringent federal or state regulations, adopting this strategy requires power plants to contend with a whole new set of cost, equipment, and operational challenges. For this reason, a great deal of industry effort is focused on the development of solutions that address the unique technical considerations of thermal treatment.

“Compared to chemical-biological treatment for surface discharge, thermal systems require a much higher capital investment,” Shimko said. “But, power plants also need to consider the long-term operation and maintenance (O&M) costs, as thermal is an energy-intensive process. The other big risks are related to scaling and corrosion from potentially high sulfate and chloride concentrations in the FGD wastewater. For this reason, the materials of construction are very important.”

Corné Pretorius, an associate with Golder Associates, echoes these same concerns. “It takes a tremendous amount of energy to evaporate water, especially when it’s a concentrated salt solution,” he said. “On the chemistry side, the concern is that industrial solutions tend to produce precipitates when they are highly concentrated. So, from a thermal evaporation perspective, scaling and corrosion risks need to be managed very closely to avoid equipment complications.”

Brine concentration technologies

One approach that is increasingly being explored as a strategy for mitigating the high operating costs associated with thermal systems is the use of advanced membrane filtration processes that can further reduce residual waste products prior to evaporation. “Advanced membrane technologies are now becoming commercially available that enable plants to pre-concentrate brine material,” Pretorius said. “By minimizing waste volumes, the requirement for thermal water reduction is lower, resulting in a shorter evaporation stage.”

Brine management

On the back-end of the treatment train, a significant amount of industry research is also focused on the development of solutions for responsibly managing concentrated residual wastes leftover from thermal evaporative processes.

Pretorius, whose work focuses on brine encapsulation and waste solidification, said brine concentrates can be blended with fly ash and other ingredients to form materials that harden much like concrete, reducing potential environmental risks associated with contaminant leaching and enabling for more environmentally-responsible landfill disposal. “The whole idea is to immobilize contaminants in a high strength material that demonstrates structural integrity and very low permeability,” he said.

Another option with managing brine is deep-well injection. “The availability of a deep well depends on the geology of the formation, and in some cases, brine pre-treatment may be required prior to disposal to facilitate continued use of the formation,” Pretorius said.

Yet another approach similar in scope to vapor-compression evaporation is crystallization, a high-energy process which optimizes the formation of crystals. “Instead of producing a combined mixed-salt precipitate through brine evaporation, crystallization processes result in a purer sodium sulfate, calcium sulfate, limestone, or calcium carbonate that potentially can be reused in industry,” Pretorius said.

But the challenge that comes with pursuing this option is the additional equipment, the expensive materials of construction, and the added complexity of managing a process for optimal crystallization of salts.

“That added complexity works to offset the benefit that would otherwise be realized by selling those resources back on the market, as they are not high value materials,” Pretorius said. “But still, crystallization can make sense in some situations-particularly when a local market is available, as transporting low-value commodities over long distances can quickly erode any financial gains.”

EPRI research evaluates potential technologies

As a resource to the coal-fired industry, the Electric Power Research Institute (EPRI) is conducting extensive research and testing of potential and commercially-available treatment technologies that could be implemented in plants for meeting performance standards as set by the new ELGs. EPRI’s programmatic research includes laboratory bench investigations, proof-of-concept pilot tests, and demonstration projects at or near commercial-scale focusing on a range of treatment issues including performance, reliability, cost-effectiveness, and thermal efficiency. In particular, efforts are heavily focused on evaluating promising technologies-including thermal evaporation processes-that could be utilized for treating FGD wastewater.

Pilot demonstrations are being carried out at partnering power plants, which include the Springerville Generating Station in Springerville, Arizona; the Water Research Center (WRC) at Georgia Power’s Plant Bowen; and Hoosier Energy’s Merom Generating Station located in Sullivan, Indiana.

“Much of what we are doing at these sites is focused on vetting different thermal volume reduction technologies that could be readily adopted,” said Kirk Ellison, technical leader with EPRI’s Water Management Technology program. “We are looking at novel technologies beyond traditional brine concentrators and evaporators to investigate their potential effectiveness and whether they offer better performance in terms of lower energy consumption, decreased operational and maintenance requirements, and less scaling potential. The energy that is required for concentrating brine wastes can be extremely high, so finding innovative technologies that can reduce energy consumption is very important.”

Ellison emphasized that a significant driver for EPRI’s work is dedicated to the management of by-products that remain following thermal processes. “Volume reduction technologies are a critical piece, but they do not represent the total solution,” Ellison said. “There is still a solid salt waste stream that needs to be disposed of in an environmentally-responsible manner. Without that end-game in mind, it’s hard to properly choose the right technology upstream of that.”

With the timing for ELG compliance fast approaching, Ellison advises that utilities focus on collecting quality and comprehensive data at their plants, which can go a long way to making more informed decisions.

“Many utilities face a tremendous amount of work prior to implementing new treatment technologies and must first evaluate their material balances, their water balances, as well as the wastewater chemistry at their site including how it varies over time,” Ellison said. “Much of this is a data issue, and the more that utilities can gather, the better off they will be in selecting the best approach and the most effective technology.”

EPRI demonstrations evaluate Purestream’s AVARA system

In 2016, three pilot demonstrations were conducted at each of EPRI’s demonstration sites investigating the commercial viability of Purestream’s Advanced Vapor Recompression (AVARA) system for achieving compliance with the EPA’s ELGs, and specifically in relation to addressing FGD wastewater requirements.

A patented innovation of traditional mechanical vapor recompression science, the AVARA system is a modular, fully-automated, thermal evaporation system that easily integrates into existing treatment trains and is designed to concentrate brine and remove chlorides and heavy metals from industrial wastewaters such as FGD wastewater. The system achieves significant volume reduction and distilled water recovery, enabling for discharge or reuse.

The first demonstration was conducted at the Springerville Generating Station evaluating the effectiveness of the AVARA system for reducing volume of cycled-up cooling tower water (similar in characteristics to FGD wastewater) from one of the plant’s evaporation ponds. The second AVARA pilot was performed at the WRC, where FGD wastewater was treated and concentrated brine generated from the process was encapsulated with fly ash and tested for dry disposal options. The third AVARA pilot, conducted at Hoosier Energy’s Merom Generating Station, included a 60-day evaluation of the performance of a 35-gpm AVARA system for treating FGD wastewater.

Results of the pilot tests demonstrated the capacity for the AVARA system to consistently treat and concentrate up FGD water for meeting ELG standards. Specifically, data gathered from the Merom Plant demonstration revealed that the AVARA system achieved 91.4 percent distillate recovery in processing 2,754,172 gallons of FGD wastewater. Waste brine in the system was concentrated up to between 180,000 and 200,000 ppm with 93% uptime maintained over the 60-day pilot. The AVARA system also demonstrated the ability to handle variable feed water and fluctuating flow rates, and energy use data suggested that the AVARA system can reduce equipment and operations costs by 40 percent compared to traditional thermal evaporation processes.

One of the main challenges in treating FGD wastewater at the Merom site included scaling from high levels of calcium sulfate in the feed water. During the pilot test, the high concentrations of calcium sulfate in combination with the thermal process created tenacious scale on the surfaces of the AVARA core heat exchangers. However, the AVARA system demonstrated the ability to still run and deliver consistent, successful results even as scaling occurred.

The ability of the AVARA unit to maintain performance under scaling can be attributed to the system’s novel design-during treatment, the cores remain fully immersed in process wastewaters, which serves to sustain heat transfer effectiveness and optimize thermal efficiency. The modular configuration of the AVARA cores also proved advantageous in terms of minimizing downtime as the system can be shutdown, drained, existing cores removed, new cores installed, and tanks refilled in 24 hours, at which operations can continue.

The AVARA’s anticipated cartridge core life will vary, but based on planned mechanical, chemical, and operational modifications, 180 days between core exchanges is expected. Design changes and modifications to the AVARA system are currently underway to increase the process efficiency of exchanging cartridge cores.

Todd Whiting is vice president of operations for Purestream Services.

By Bill Hickman

Over the last three decades, the nuclear industry has made tremendous progress in reducing the duration of planned outages. It is almost unimaginable to think that in 1990, the average planned outage took more than three months to complete. Today it seems equally unimaginable that average outage durations can be driven even lower than their current time of 35 days. Admittedly, reducing outage time averages poses both a technological and logistical challenge.

However, history is marked with seemingly impossible tasks that were achieved through high levels of innovation and collaboration.

Most were skeptical back in 1962 when President John F. Kennedy floated a bold idea of putting an American on the moon within the decade. Seven years later, the unthinkable was achieved when Astronaut Neil Armstrong made “one small step for man, one giant leap for mankind.”

The nuclear industry continues to transform, ensuring viability for consumers by creating new efficiencies through innovation and collaboration.

In the past two years, the Edwin I. Hatch Nuclear Plant, operated by Southern Nuclear, managed to complete work on both of its most recent refueling outages in record time. In Spring 2016, the plant completed work in 25 days and 17 hours. A year later, it improved that record by more than four days – completing work in just 21 days and 2 hours. This was achieved through the combined efforts and total commitment of the entire station.

It is possible for other plants to duplicate this success.

We’ve identified four key strategies that helped them to achieve these impressive results.

It’s Never Too Early to Plan

While some may say that 18 months to two years is an appropriate amount of time to plan for an outage, experience proves a longer lead time is key to improving outcomes and minimizing outage durations.

At Hatch, pre-outage planning extended to almost three years before work began on the two most recent outages. Having this much time before an outage begins gives operators plenty of time to engage all of the key stakeholders, and identify potential trouble spots.

“We have used the advance-planning time to work closely with our alliance contractors to ensure all their workers are fully trained and certified when they arrive on site,” said David Vineyard, Site Vice President for Edwin I. Hatch Nuclear Plant. “This means we can get to work right away.”

Operators like Southern Nuclear also benefit from developing specific milestones during the planning process to track progress.

Even with long lead times, an organization can run out of planning runway without clearly defined goals and objectives.

Establish a Culture of Empowerment

Even with the most thorough and well-organized plan, it’s people that execute the work and must be motivated to execute the plan. Empowering every worker to be a leader and take ownership of every project is critical to achieving success. Workers must feel comfortable making process improvement suggestions to management. Establishing this culture starts at the top with company leaders demonstrating they are truly open hearing from every member of the organization.

“At Southern Nuclear, we have a leadership and teamwork model that is embedded in everything that we do,” says Vineyard. “We want to make sure that everyone in the organization is engaged with their work and understands the important role they play in making a project successful. On any given outage, there are 1,000 or more workers on site. We need them all to be leaders if we’re going to be successful.”

This mentality extends to service providers and partners, too. Selecting the right partners from the start is critical. When operators view those partners as an extension of their team, efficiency improves.

Giving contractors a seat at the table and a stake in delivering better results, drives productivity.

Analyze and Optimize

Understanding and celebrating outage success go hand-in-hand. Reviewing lessons learned and applying to future outages is how the best plants achieve even better results. Southern Nuclear evaluates successes across the entire fleet, so it can apply best practices broadly.

“There’s no silver bullet to driving down outage duration,” says Vineyard. “But when we analyze everything comprehensively, we may be able to shave time off a single activity that impacts our ability to be more efficient with other activities.”

By necessity, the nuclear industry must be collaborative and share best practices. Outside partners bring lessons learned from other job-sites and organizations. Plants operators also should share and benchmark with other independent plants, or fleets to compare best practices and improve overall outage performance.

Dare to Think Differently

Almost all work in the outage planning process, and in all nuclear power generation for that matter, is designed to minimize risk.

However, one of the key tenets of the “Delivering the Nuclear Promise” initiative is innovation. The only way to innovate is for plant operators and their partners to be willing to try new approaches. The key to outage planning is taking smart and calculated steps that won’t derail an outage, or cause an irreversible issue if unsuccessful.

“We recently took a different approach by opting for a new contractor after working with another provider for 20 years,” says Vineyard. “This change could have created a large learning curve and potential speed bumps, but instead the new partner ended up being one of the driving factors that allowed us to achieve our record-breaking outage performance.”

At Southern Nuclear, new technologies are being used like robots for remote inspections, drones for dry well work, and data analytics to assist with planning. These technologies serve as additional tools that complement more traditional approaches, but they may someday become a primary aspect of operations.

The Future

The nuclear industry is boldly moving toward the future. Perhaps one day, we will look back on this time period with the same sense of accomplishment and pride we have about space exploration. Reducing outage durations is just one small step for a single nuclear station, and one giant leap for entire industry.

Bill Hickman is Vice President of Nuclear Operations for Day & Zimmermann

By R. Aaron Nickels, System Owner, Southern Company – Plant Bowen

In 2014, Plant Bowen, a 3,160 megawatt coal-fired power station, in Cartersville, Georgia was facing frequent membrane and micron-filter maintenance and replacement as a result of biological fouling and oxidation despite their use of a sodium metabisulfite (SMBS) dechlorination process. Free chlorine compounds are removed from feed water with the dechlorination process; protecting the memebrane elements and other chlorine sensitive equipment.

The facility undertook a three month evaluation of a non-chemical dechlorination process, the Hydro-Optic (HOD) UV water treatment technology, manufactured by Atlantium Technologies, Inc., to improve the overall quality of reverse osmosis (RO) feed water at the Plant.

Three RZ300-13 HOD UV systems were provided to Plant Bowen in March 2014 to accommodate a flow rate of 680 gpm (154 m3/hr) with 95 percent UV transmittance.

The units were installed in series on existing stainless steel piping after the media filters and before the micron and RO trains. At the conclusion of the evaluation period in May 2014, the technology had effectively removed free and total chlorine from boiler feed water to undetectable levels from inlet free and total chlorine levels above 1 ppm [1].

Following the successful demonstration of the technology, Plant Bowen incorporated the system into full-scale operations at the plant – a decision that has proved favorable for dechlorination efforts at facility.

Plant Process and Operations

Plant Bowen receives its source water from the Etowah River. Following clarification and multimedia filtration, water passes through a two-stage micron filter process before entering the RO system. The two-stage micron filter process is composed of two trains, each containing a 3-micron filter followed by a 1-micron filter.

The RO system consists of two 250 gpm (114 m3/h) trains (Train A, Train B) containing 72 membranes (DOW BWXFR-400/34i) per train. The RO system is arranged in a double pass configuration with 48 membranes in the first pass, followed by 24 membranes in the second pass.

The facility samples twice a week for feed water quality (pH and turbidity) and permeate and concentrate values of the RO system.

Given the Plant’s problem with microbial growth and the creation of a biological matrix in the RO filters that restrict flow; differential feed pressure, effluent pressure, normalized flow, and chlorine residual are measured daily. A 10 percent increase in differential pressure alerts operational staff to undertake a cleaning of the membrane system with a caustic and acid solution.

The membrane cleaning process requires the facility to run at half capacity for 48 hours since each train is taken offline for a 24-hour period to have the membranes rinsed before being returned to service.

Prior to the installation of new membrane elements in March 2014 an autopsy was performed on the existing elements and it was determined the facility had a sulfur reducing bacteria contributing to their microbial growth problems.

Operational staff felt that reducing the use of SMBS would lessen the biofouling potential since the bacteria’s food source would be eliminated; enabling nature to take its course and cause the bacteria die off.

However, under the existing system design this reduction could not be achieved given that free available chlorine was above 1 ppm. Alternative dechlorination methods were then evaluated.

As a non-chemical approach to decompose the free chlorine oxidant and protect the RO membranes, the HOD UV technology provided the facility with the opportunity to reduce or eliminate the use of SMBS and reduce maintenance and associated costs.

HOD UV Technology-Principles of Operation

The HOD UV technology is a physical process for disinfection that exposes bacteria, viruses and protozoa to germicidal wavelengths of UV light, measured in nanometers (nm), to render them incapable of reproducing or further infecting a water system. Through UV oxidation, UV light can also destroy chemical contaminants.

The technology measures four critical parameters including percent ultraviolet transmittance (UVT%), flow rate, UV lamp intensity (kW) and apparatus (consisting of Total Internal Reflection and Dose Pacing) in real time to maintain a specified UV dose.

The system uses a proprietary Total Internal Reflection (TIR) based design that when coupled with the comprehensive monitoring of critical parameters allows the system to achieve and maintain the specified UV dose.

The system’s patented TIR technology, which is similar to fiber optic science, recycles UV light energy within the HOD UV chamber.

This is especially important given that in traditional UV systems metal adsorbs or “detracts” the UV dose the closer it gets to metal, whereas the TIR enhances the UV dose. Simply put, the UV photons are effectively lengthened and provide a greater opportunity to inactive microorganisms and decompose the free chlorine.

The core of the technology is its water disinfection/chlorine-decomposing chamber made of high-quality quartz surrounded by an air block instead of traditional stainless steel. This configuration uses fiber optic principles to trap the UV light photons and recycle their light energy.

The photons repeatedly bounce through the quartz surface back into the chamber, effectively lengthening their paths and their opportunities to inactivate microbes.

Long-term membrane performance with HOD UV Dechlorination

Plant Bowen uses a five-year replacement cycle for the RO elements, the last installation occurred in March 2014. The HOD UV system was also installed and placed into continuous operation in March 2014.

After three years of operation, the RO membranes are operating at the same level as new elements.

Data for the membrane system’s differential pressure, normalized salt passage and rejection, permeate flow, and normalized permeate flow under the use of the HOD UV system was analyzed for a 940 day period from August 2014 to February 2017 (Figures 1-4 on pgs. 82-83). Normalized permeate flow is higher compared with a new membrane, while the quality of the permeate (salt passage and rejection) is similar to a new membrane.

Prior to the installation of the HOD UV system the membranes were cleaned one to two times per month; with marginal improvement since 2014. However, what’s most interesting is that the driver for cleaning the membranes has changed.

After three years of operation, the membranes are only up to 34 psi differential pressure from the original 28 psi when they were put into service; indicating a longevity of the membrane elements that didn’t exist without the use of the HOD UV technology. Comparatively, the pre-2014 membrane elements were running at a 50 psi differential pressure after three years of operation.

Based on the 5-year replacement cycle for the RO elements, they are scheduled for a change out in 2019.

If performance remains positive, the facility will evaluate the possibility of increasing the life span another year. This would result in an additional cost savings of $100K.

Performance of the micron filtration system has also been enhanced with the use of the HOD UV technology. In 2015 the 4 pre-RO micron filters were changed six times, then reduced to four times in 2016, and two times in 2017. The reduction in cleaning frequency has resulted in a net savings of $160,000.

Since the installation of the HOD UV systems the chemical feed rate has decreased by 75 percent; whereas the facility was originally feeding SMSB at 4 ppm rate in 2014, the 2017 feed rate was 1 ppm.

The monthly chemical usage had been reduced from 44.2 gallons per month in 2013, to 7.6 gallons per month in 2017. The facility has realized an annual cost savings of $5,000 with the reduction in chemical usage.

Although the HOD UV technology has been proven to effectively remove free and total chlorine to undetectable levels from inlet free and total chlorine levels above 1 ppm; the facility maintains the 1 ppm SMBS feed rate as an asset protection method in the event of a power failure that would prevent the operation and delivery of dechlorination control from the HOD UV system.

Since SMBS is an oxygen limited chemical there is the option to alter the SMBS dose from continuous to periodic thereby enabling a constant change between an anaerobic and aerobic state to enhance the instability of any bacterial growth. This option has not yet been explored at Plant Bowen.

Conclusion

Incorporating the non-chemical HOD UV technology into full-scale operations at Plant Bowen has proven favorable for dechlorination efforts at the facility. In addition to reducing the use of SMBS, the facility has also minimized the frequency of micron filter replacement.

These operational efficiencies have resulted in a net savings of $175,000, providing a two-year return on investment. Moreover, there has been no reduction in performance to the RO membranes with the use of the HOD UV technology.

As a result, Plant Bowen has been able to maintain the integrity of their feed water for the boiler and steam cycle, ensuring production and quality levels necessary for the facility to operate
efficiently.

References

[1] Boiler Makeup Water Dechlorination Using Advanced UV Technology at Plant Bowen Water Research Center. 3002002146 EPRI, Palo Alto, CA: 2014.

By Cal Crader, PE

Properly planning and executing a maintenance plan during a planned outage is a critical practice in avoiding unnecessary downtime in a power plant. Although each individual plant has their own approach to scheduling outages, it is typical for plants to have a major outage occur once every two to four years. During these major outages, most plants will upgrade and/or replace major equipment. As the turbine generators and the boiler are usually top of mind when it comes to maintenance, outages tend to be scheduled around those particular pieces of equipment. However, understanding the amount of time and money that is required to shut down and entire plant for a given period of time, it is important to take full advantage of the outage.

In recent years, plants have leaned in the direction of having fewer, albeit longer outages to get critical repairs and upgrades completed. However, there are still smaller outages at these same plants generally in years where major outages do not occur. These smaller outages are just as essential to take advantage of. Why? Because the smaller outages provide an ideal opportunity to assess what equipment needs to be upgraded and/or repaired, and how much time will be needed to accomplish everything during the upcoming longer outage. During this shorter outage, managers need to make the decisions about what will and will not be part of their plans for the prolonged, major outage in the following year. At this time, it is critical to assess your bus duct system, whether that be the isolated phase bus or a non-segregated bus. Far too often, these crucial systems are not given the attention they require, leading to costly, untimely and most importantly, preventable power plant shutdowns.

Operators have the impression that because there are not as many moving parts as something such as a turbine generator, the bus duct system does not require the same amount of attention. This common misconception will lead decision-makers to overlook this system when planning upgrades/repairs during a major planned outage. Unfortunately, this misconception can ultimately turn out to be a very costly one. If a bus duct system fails at an unexpected time, the plant will need to shut down for emergency repairs. Due to time requirements, these emergency repairs can cost exponentially more than a preventative maintenance strategy would have. Couple this with all the lost revenue the plant experiences while being down for an extended period of time, and it becomes increasingly clear that it is in an operator’s best interest to give the bus duct system the attention it deserves.

Isolated Phase Bus

Most plants either have an isolated phase bus or a non-segregated bus duct system. For the isolated phase bus, also known as the isophase bus, failure can be caused for a number of different reasons. Poor insulation, dirt, condensation and water intrusion can all be contributing factors as to why the isophase experiences complications. However, one of the biggest causes of isophase failure is localized overheating. Unfortunately, not only is this a common cause, but it also makes the repairs even more taxing, because crews must work in this extreme heat. Seeking assistance from a trained professional during a small, planned outage to assess the isophase’s condition and ensure that these potential pitfalls are documented and planned for is critical.

During the smaller, planned outage, a number of different areas should be checked in the isophase, starting with the bolted joints. The hardware should be correct, and the proper amount of torque should be present. Additionally, the plating condition, flexible connectors and the surface integrity needs to be documented.

Insulators are another area where small defects can lead to large problems. Any kind of damage needs to be observed (cracks, chips) and the amount of dirt build up should be assessed. Proper seals should be observed with the brushings and the hardware gaskets all need to be checked to see if they are functioning correctly. Another area that can lead to problems is the filter drain. Water build-up can be problematic.

All the bolted covers need to be removed so debris can be removed from the termination enclosures and all the insulators should be cleaned. If any equipment or hardware needs to be completely replaced, by having an assessment, operators and preventative maintenance experts can better plan the major outage. For everything to transpire effectively and efficiently, ordering required equipment and parts needs to be done ahead of the major outage so everything is on site when the plant is shut down and work needs to get done. Therefore, this is why it is so important to take advantage of the smaller outage and assess the challenge that lies ahead.

The Non-Segregated Bus

If a plant does not have an isophase bus duct, chances are there is a non-segregated (also known as non-seg) bus duct system present. Much like the isolated phase bus, the non-seg bus should have preventative maintenance done to it to keep it in working condition. Also, just like the isophase, assessing what damage and upgrades need to be taken care of should be done during the smaller outage.

Unique to the non-seg bus duct system, assessing the insulation on the bus bars is essential. As plants are continually uprating for maximum output, medium voltage bus bars also should be addressed to ensure they can take on this additional capacity. When plants fail to do this, failures are common. As bus bars experience overloads, the deterioration of their insulation is accelerated. Many maintenance personnel are observing that this added capacity requirement is leaving bus bars particularly vulnerable. Adding to the challenge is the type of material that most bus bars are insulated with. For a significant stretch of time between the years of 1960 and 1980 the most common material used was a polyphenylene oxide (PPO). It makes sense that this material was so popular; it was cost effective and did the job well. However, this material has a lifespan, and much of it has become very brittle over time. Replacing this PPO insulation on bus bars is essential.

There are new techniques recently developed to address this deteriorating insulation. A shrinkable tubing is now available made from a non-halogen based polymer that has been designed to withstand high voltage. Maintenance managers should have a qualified expert check the insulation on the bus bars to assess their condition. If the insulation has not been checked in years, there is a good chance that re-insulation is required and should be performed during a scheduled outage.

The bus duct system is a vital piece of the puzzle for a power plant. Preventative maintenance on the system is essential as emergency repairs can cost up to five times as much.

Cal Crader, P.E., is the CEO of SE Energy, LLC, a nationwide specialty electrical construction, engineering and consulting firm serving clients in the utility and power generation, transmission and distribution, and heavy industrial markets.

By Larry Berry

The one constant that all boiler owners and operators face is the ever-changing environmental regulations that are in effect one day and repealed the next. Being in compliance is continually subject to the whims of new political administrations and shifting environmental policies. Where Boiler MACT ultimately ends up or how the Clean Power Plan goes forward is purely speculation at this point-in-time. One criterion that won’t likely diminish in the near term is the ever-increasing need to implement low emission solutions. It’s a reality of the world in which we do business. The quest to be greener with even stricter emissions is here to stay.

The majority of these existing and unknown future air quality requirements for stationary combustion solutions will most likely require a burner retrofit in order to meet ever increasingly stringent air quality regulations.

Low NOx burner retrofits to an existing boiler, dryer or incinerator aren’t as simple as pulling out the old burner and bolting in a new one. There is so much more that needs to be considered as part of the engineering and purchase decision process.

Low NOx burners are often the go-to-strategy in reducing stack emissions based on several different compelling factors. Burners, in direct comparison to “back-end” solutions – Selective Catalytic Reduction (SCR) or Selective Non-Catalytic Reduction (SNCR) − are usually less costly from a total installed cost standpoint, without having to assume the burden of recurring costs derived from reagent injection and catalyst replacement. Low NOx burners have the added advantage of not requiring additional space/ducting requirements that are often associated with SCR. When combined with SCR, low NOx burners reduce the size of the SCR-related equipment (reagent usage, catalyst quantity and ducting size), resulting in one of the most cost-effective NOx solutions.

When placed in head-to-head comparison with many existing burner designs, low NOx burners have significant differences – from different fuel/air mixing designs, internal dimensions, pressure drop requirements, flame geometries and control requirements. All of these need to be thoroughly reviewed and vetted when you’re budgeting, selecting and installing new burners.

When considering a burner retrofit project you need to look at not only the burner but also far beyond. Following are the best practices that need to be key steps in the decision-making process. Many times, these can be interrelated, where addressing one issue causes problems in unrelated areas.

Examining the Dynamics Surrounding Existing Fan Capacity

The majority of current low emissions burners require relatively high air side pressure drops to achieve the desired fuel/air staging within the burner itself. Based on this design consideration, the pressure drop may be far higher than what the original burner was designed for. The dynamic of pressure drop is commonly referred to as “register draft loss” or RDL. The new RDL requirements necessitate reviewing the existing forced draft fan to assure that the fan is able to provide the static pressure to accommodate new burner systems. The onus should be placed on the burner supplier to review and confirm the capability of the existing FD fan based on both review of subject fan curves and review of boiler operating data showing system pressure drops or through the performance of static pressure testing of existing fans.

Many low NOx burners include added flue gas recirculation (FGR) that further mitigate and minimize NOx emissions. Often times, FGR rates can range from 5 percent to 30 percent of the total boiler flue gas flow. The FGR can be induced into the FD fan (commonly referred to as IFGR) and mixed with combustion air prior to entry into the burner/windbox. The incorporation of IFGR adds the mass flow requirement of the FD (and ID) fans, while at the same time increasing the furnace and system pressure drop. It is paramount to review the existing FD fan (and ID fan where applicable) to assure that the existing combustion air and flue gas systems are able to accommodate the new equipment and performance requirements.

In applications where the existing fans in operation are insufficient to meet and exceed the new performance metrics, it is desirable to investigate using larger fans and motors, utilize a separate FGR fan, or to reduce the maximum boiler capacity.

Understanding the Implications of Furnace Dimensions and Burner Spacing

The ability to lower burner peak flame temperatures is an integral strategic direction in the quest to achieve low NOx emission levels. Many current low NOx burner designs incorporate fuel/air mixing strategies to spread out and enlarge the flame envelop which leads to minimized peak flame temperature zones and lower NOx.

A thorough review of the furnace geometry is a key requirement in the ability to assure that new, potentially larger low NOx flames won’t impinge on the boiler wall surfaces – either rear or the sidewalls.

Another dynamic to factor into retrofit burner decisions for multi-burner boiler applications is the fact that low NOx flames tend to have increased diameters when compared to previous designs where adjacent burner flames can overlap to a point where NOx reduction is limited and CO emissions increase. Many times, burner internals can be custom designed to be able to produce a flame pattern that fits the majority of furnace geometries and burner spacings. This may lead to a compromise of the degree of emissions reduction if the furnace/spacing dimensions are overly constrained. Usually, burner suppliers incorporate a CFD (computational fluid dynamics) model study of the combustion process to provide the user assurances that the burner design provides the specified performance metrics within the operating and physical constraints of the furnace and burner spacing. Flame dimensions are also reduced by increasing the burner RDL, and in turn, the mixing energy. However, this will trigger a review of the FD and ID fans as described in the fan capacity analysis mentioned previously. Flame shaping and fan capacity are very often interrelated and must be considered in that context.

Examining the Relationship of Windbox Design and Dimensions

When entering into a retrofit burner situation, it is usually desirable to keep and reuse the existing burner windbox. Removal and replacement of the windbox, most notably in multi-burner applications, is a costly proposition. If the windbox requires deepening or replacement there are many downstream issues to consider ranging from space availability and component withdrawal distances on through to platform modifications and dismantling and reinstallation of windbox mounted equipment – most notably instrumentation and valves. The cost implications are substantial. With insulated windboxes, the issue of asbestos enters into the equation.

Typically, low NOx burners have larger internal length to diameter ratios when compared to conventional (register) style burners. This requires close review of the existing windbox depth. Since precise air/fuel control is essential to achieving lower NOx emissions, having equal air distribution to and around each burner is key to achieving peak burner performance.

Smaller windboxes have reduced air residence times which may result in improper air distribution between burners. This maldistribution can increase the ducting and burner pressure drops which can impact fan capacity. Adding FGR to an existing windbox further reduces the residence time in the windbox and negatively impacts air distribution.

The majority of the time, issues with windbox dimensions and distribution are overcome by performing a CFD flow model of the combustion air system (and FGR when applicable) – preferably from the fan outlet to and through the windbox. The results of the modeling often result in the need to add baffles/vanes in the ductwork and/or the windbox to assure the optimum distribution of air (and FGR) to the burners.

The Pros and Cons of Eliminating Air Pre-Heat

Many large industrial and utility boilers operating today incorporate preheating of the combustion air to help maximize boiler efficiency. Despite the advantage of better efficiency metrics delivery from the boiler, the preheating of the combustion air increases the burner flame temperature. The result is greater levels of thermal NOx emissions.

Through the elimination of burner air pre-heat, significant reduction in NOx reductions are achieved in operating conditions. Any efficiency losses are able to be offset through the addition of a boiler economizer surface to preheat the boiler feedwater rather than heating combustion air.

Although the required mass flow of air for combustion remains the same, the reduction of the air temperature in the windbox greatly reduces the volume of air entering the windbox which ultimately results in very low pressure drops across existing burners. Sufficient pressure drop (RDL) is needed to assure sufficient mixing of the fuel and air.

The burners become significantly oversized for applications that apply the elimination of air pre-heat. The associated very low throat velocities and resultant low mixing “energy” negatively impacts the ability of the burner to provide the fuel air mixing for proper operation and emissions. It also severely impacts the ability of the burner to turndown. To increase the RDL and associated mixing energy, many times new smaller burner throats or larger burner internals are required. When in multi-burner applications, an option to offset the low burner RDL is to reduce the number of operating burners per boiler.

Thorough Analysis of Furnace Waterwall Openings

Many times, low NOx burners incorporate a degree of internal staging (fuel and/or air) to achieve low NOx emissions. This may increase the throat diameter in relationship to the existing non-low NOx burners that are in place. If furnace burner walls contain boiler generating tubes, a review of the tube bending diameters around the burner openings is warranted. This exercise assures that the new burner throat diameter is not larger than the available waterwall openings and doesn’t require (expensive) modifications to the pressure components of the boiler.

Usually, the burner throat diameter can be reduced if there is interference with the furnace waterwall. This reduced throat diameter increases the burner pressure which results in the review requirement of the existing fan system − which again brings up the need to understand interrelated dynamics.

The Implication of Fuel Supply and Control Modifications

There are some low NOx burner designs that require specific fuel supply and/or control requirements. These range from multiple control valves and flame scanners all the way through to reduced boiler ramp rates, special fuel/air ratio curves and fuel and air flow measurements. It is imperative that you identify any changes required of existing fuel trains, the Burner Management System (BMS) or the Combustion Control System (CCS) and factor them into the overall assessment. FGR systems add another layer of control along with the associated additional dampers and control elements.

The Overall Performance Attributes of the Boiler

If the emissions reduction application includes FGR, additional mass flow through the boiler has the potential to impact the boiler superheat temperature to a point where superheater modifications or additional attemperation is required. This operating dynamic may require thoroughly reviewing the impact on the superheater. This is also pertinent to project applications where a new fuel is added to the boiler to assure compatibility between the new fuel’s characteristics and the installed superheater. The burner supplier should be able to perform a boiler impact study to assess the capability of the boiler internals with regard to the new burners/mass flow/temperatures/fuels.

What to Look For In a Combustion Solution Supplier

There are so many interrelated elements to factor in when considering a comprehensive burner retrofit project. It is imperative to have a close working relationship with the combustion solution supplier as so much is at stake from an operating and overall business standpoint. The match has to be right on all sides, from the burner itself to the people working the engagement.

Your burner supplier needs to reach far beyond the simple product solution. They need to be an integral partner in helping you to work through all burner project dynamics. The overall recommended product solution must go beyond the product itself to encompass all of the existing boiler ancillaries that may affect the success of the retrofit project.

Larry Berry is Director of Combustion Solutions for Victory Energy Operations.

Steven Thompson

PSEG’s new Sewaren 7, a 540 MW combined cycle generating facility in Woodbridge, New Jersey was put out to bid for mechanical contractors in August of last year. On many levels, it was a typical bid package: a gas fired combined cycle power plant consisting of a GE centerline package, a GE/Alstom designed C-Frame HRSG, a 20 cell ACC, and the balance of plant piping and equipment.

The project did, however, present two major challenges. First, the schedule was extremely aggressive – 11 months from turbine delivery to First Fire.

This was achievable, but would require a lot of careful upfront planning and coordination between contractors. Second, the site was extremely small, and elevated on an 8-foot-tall island.

The legacy plant at the site had sustained significant damage in Hurricane Sandy, and the new design called for the entire power block to be elevated on a sheet pile walled island to help protect it against future storm surges.

The severely restricted plot plan meant that the plant could be built in only one order, backing off the island as it was constructed, like painting your way out of a tight room. It also meant that multiple components could not be worked in tandem. For instance, the crane used to erect the turbine building would have to sit on the HRSG pad to do its work – meaning the HRSG construction couldn’t start until the building was complete. Similarly, the cranes to build out the ACC would have to sit on the pads of other balance of plant pieces of equipment, delaying their installation.

As the mechanical contractor, we ran scenario after scenario trying to fit so much work into such a tight schedule and a space – and we couldn’t do it.

The concept just didn’t seem viable. The schedule would either have to run out over 2 years, or we would need 600+ men on site – an unsafe and unmanageable number in such a tight spot, and also a number that the local union labor halls would struggle to provide. We needed to build outside the box – literally.

We turned to our historical experience in the power industry, and network of partners in the market, to propose a unique alternative: perform an off-site build of the Heat Recovery Steam Generator in one piece, modularize the Air-Cooled Condenser into fully built fan cells, and then barge the units to site while the rest of the plant was being built.

These would be the largest ACC units, and the largest HRSG, ever remotely built in the United States. Durr Mechanical proposed building the units at the Port of Coeymans, on the Hudson River, just South of Albany, and barging them 150 miles downriver to site in Woodbridge, NJ.

The Port of Coeymans, owned and managed by Carver Industries, is a unique facility: it is a full-service port providing marine logistics support, but also rents out waterfront space, with access to its docks and barges, to construction firms for off-site builds. We proposed dividing the ACC into 20 fully built fan cells.

The HRSG would be fully built out as a single 4,000-ton unit. PSEG accepted the proposal, and construction began.

Since both the ACC and the HRSG had been purchased in non-modularized formats, a number of engineering feasibility studies were performed. First, we needed to design temporary erection jigs for the ACC cells that would allow us to build an entire cell on the ground, and would also allow us to drive under it, mount it on a self-propelled motorized transport, and then allow a crane at the other end to pick the cell up in one piece to set on its support tower.

Then we needed to design a temporary transportable frame for the HRSG – this proved to be a much more complicated task.

We had to design and fabricate a steel structure that would temporarily replace an 8-foot-thick concrete foundation covering more than 7000 square feet. It would also have to be designed such that it could be driven under, mounted on a linked array of self-propelled motorized transports. It then needed to be welded to the deck of a barge, and resist wind and wave loads during transport.

Further studies had to be performed on how to stiffen the units to become self-supporting, and also how the units would act once floating on the water – attachment points and stiffeners were designed, wind and wave loadings calculated, tide surveys completed, barge and lashing surveys performed, and bridge height clearance certifications made. Both the Coast Guard and Army Corp of Engineers were engaged in the shipping logistics and permitting processes.

Construction at the Port of Coeymans began in January of 2017. The ACC cells were laid out in a grid fashion, with multiple cranes able to service multiple cells at once. They were built in sequence, with small crews moving in a water fall fashion from one cell to the next to maximize efficiencies and lessons learned.

Re-engineering of the units, including repositioning of the Steam Distribution Duct and Condensate Header Duct field welds to correspond to the modular boundaries, were carried out on the fly.

This created the need for an extremely integrated field engineering and project management team, with a team of representatives from the vendor and owner working with the contractor in the field full time.

The ACC cells were modularized into single and double fan units. They were welded out in their entirety, loaded onto self-propelled motorized transports, and driven down a 7% grade road towards the water, across the port docks and onto barges.

They were then barged down river, and offloaded at the installation site.

We were able to make regular deliveries, pre-scheduled months in advance, to tie in directly to the on-site construction sequence and scheduling.

At the same time, a separate construction crew began to assemble the HRSG. The HRSG C-frames were offloaded from overseas ships that had been redirected to the Port of Coeymans, and erected just as if it were happening on site, except that it was built on top of a mobile transport frame made up of over 250,000 pounds of steel and over 2 miles of welded connections. The GE/Alstom unit was made up of 10 C-Frames, the largest of which was over 700,000 lbs. In addition, the CO, SCR, and Duct Burner units were completely field assembled in places, forming a completed vessel 130 feet tall, 70 feet wide, and over 110 feet long.

Then, over 10,000 feet of piping was welded and hung from the unit, in addition to platforms, ladders, cable tray, and instrumentation. All of the internal welding was completed, all of the non-destructive examinations were performed, all of the pre-and-post weld heat treating was completed, all of the insulation was installed, and the inlet and outlet ducts were attached.

The HRSG transportation operation began in July of 2017. A combined self-propelled motorized transport array consisting of 138 separate axle units was linked together to form a single computer controlled unit.

This was then driven under the HRSG temporary lifting and transport deck, and the entire unit rolled over steel bridges and onto a 100′ x 400′ barge – one of the largest barges in the country.

The loading operation was so large and complex, that shipping along the Hudson River waterway was suspended during it.

The loading operation lasted approximately 13 hours – 8 high volume bilge pumps had to constantly compensate for the tide coming in and out at the same time the barge was being loaded with more and more weight. The entire unit was kept level throughout the whole operation to within a .5 percent tolerance.

It took another week of welding work to lash the unit down to the deck, before the HRSG was able to set sail down the Hudson River. The trip was covered by multiple news organizations, including USA Today, NBC Channel 4, and the Wall Street Journal.

The 150-mile journey took 36 hours, and the unit had to pass under 19 bridges – the lowest of which left us with just 9 feet to spare. It sailed past the Statue of Liberty and to the Woodbrige site, where we erected a 60-foot steel ramp bridge to drive the entire HRSG directly on to the site – without the use of a dock.

Once the lashings were cut, the HRSG was driven directly across the power block, onto its foundation, and lowered onto its anchor bolts. The process of tieing into the rest of the plant equipment began immediately.

During the 7 months of construction 150 miles away, the HRSG foundation pad was used by 2 separate large boom cranes – one to build the turbine building and one to build the balance of plant piping, pipe racks, and equipment.

It would have been impossible to even begin this work without the use of the HRSG pad as a staging area, so the concept was successful. The owner gained 7 months on the overall construction schedule, and we were able to move 300,000 manhours from a congested site to a fabrication shop environment 150 miles away. As a case study, we showed that performing off site builds for large pieces of power generation equipment, despite significant logistical challenges, is a viable avenue of schedule and cost surety.

It’s an answer to the trend of power projects in the Northeast to be built on ever smaller footprints and to ever tighter schedules.

The result – that Durr Mechanical safely and efficiently built and delivered the largest off-site power fabrication project ever attempted in the US, is one we expect to repeated on future projects.