The U.S. Departments of Energy and the Interior published a collaborative plan to continue accelerating the development of offshore wind energy in the U.S.

The “National Offshore Wind Strategy: Facilitating the Development of the Offshore Wind Industry in the United States,” states the U.S. could develop 86 GW of offshore wind by 2050. The strategy details the current state of U.S. offshore wind, presents the actions and innovations needed to reduce deployment costs and timelines, and provides a roadmap to support the growth and success of the industry.

The strategy was published just weeks after construction finished at the U.S.’s first commercial offshore wind farm off of Block Island, Rhode Island. The 30-MW wind farm was the Bureau of Ocean Energy Management’s (BOEM) first right-of-way grant and is expected to begin operating by the end of 2016.

The strategy identifies key challenges facing the industry and more than 30 specific actions that DOE and DOI can take over the next five years to address those challenges. The actions fall into three strategic areas:

• DOI proposes jointly developing standard data collection guidelines to foster predictability and inform safe project development, while DOE will work to increase annual energy production and reliability of offshore wind plants.
• DOI commits to numerous actions to ensure that the regulatory process is predictable, transparent, efficient and informed by lessons learned from regulators in other countries. Additionally, as the first generation of installed projects come online, DOI and DOE will collect field data on parts of offshore development including impacts on marine life and turbine radar interference.
• Studies are needed to help quantify the broad grid integration impacts of adding significant amounts of offshore wind energy to the power system.

Nancy Sopko, Manager, Advocacy and Federal Legislative Affairs with the American Wind Energy Association (AWEA), said the government made great strides with the release of the study.

“We commend the Department of Energy and Department of the Interior, through the Bureau of Ocean Energy Management, for their commitment to developing offshore wind power as a new, inexhaustible American energy resource,” Sopko said. “The National Offshore Wind Strategy, five years in the making, builds on tremendous momentum created by the first American offshore wind farm which completed construction this summer.”

By Russell Ray, Chairman, POWER-GEN International

The greatest minds in power generation gather once a year for the world’s largest forum for power professionals. It’s called POWER-GEN International, where experts throughout the world have been meeting for 28 years to discuss the mechanics, chemistry, operation and regulation of power generation.

More than 21,000 industry professionals from around the world will be gathering in Orlando, Florida, for POWER-GEN International 2016, Dec. 13-15 at the Orange County Convention Center. During the three-day event, the most innovative and cost-effective solutions for maintaining, operating and building new power generation will be shared with attendees.

More than 1,400 exhibiting companies from every sector of the industry will be showcasing their products and services on the exhibit floor. The exhibition opens at 11:30 a.m. Tuesday following the keynote session.

Jeff Holmstead, a leading climate change lawyer and former EPA assistant administrator in the Bush Administration, was one of 300 experts who spoke at POWER-GEN International in 2015.

POWER-GEN International offers a wealth of networking opportunities with leading professionals and key decision makers. More than 200 speakers will share their thoughts on trends, technology and project development in 43 conference sessions. A wide range of topics, from data analytics to gas turbine design, will be discussed by high-ranking regulators, developers, power producers and industry representatives.

The keynote session on Dec. 13 will feature four high-ranking executives, including Alex Glenn, president of Duke Energy Florida; Rick Halil, senior vice president and general manager of Energy at Burns & McDonnell; and Willi Meixner, chief executive officer of the Power & Gas Division at Siemens AG.

This year, POWER-GEN is coming to Orlando with four co-located events: Nuclear Power International 2016; COAL-GEN 2016; Renewable Energy World International 2016; and the GenForum. That’s five conferences and four exhibitions under one roof. Altogether, more than 300 speakers will be featured in nearly 80 conference sessions during the week.

At POWER-GEN, 36 conference sessions will be held under eight tracks: Emissions Control; On-Site Power; Plant Performance; Gas Turbine Technologies; Energy Storage; Industry Trends/Competitive Power Generation; The Digital Power Plant; and Power Project Financing.

“This year, we see a lot of papers on inlet conditioning,” said Bonnie Marini, director of Power Plant Product Line Management at Siemens Energy and co-chair of the Gas Turbine Technologies track at POWER-GEN. “We’re really expanding the scope of the track and covering a lot of different topics addressing changes in the market.”

Here’s a sample of some of the sessions that will be offered: “Energy Storage Trends and Case Studies;” ELG Compliance Strategies, Options and Technologies;” “Small and Medium Gas Turbines;” “Applications in Combined Cycle; “Advancements in O&M Practices;” “Latest Combined Cycle Designs;” “Making CHP Work for You;” “Boiler Operation & Performance;” Risk Management in Modern Project Financing;” and “Data Analytics and the Plant of Tomorrow.”

Six mega-sessions are also scheduled. “Large Frame Gas Turbines,” “The Digital Power Plant is Disrupting Traditional Power Generation. What is it and Where is it Going,” “Operating Generation Assets in the New Variable Renewable World,” “Coal-Hybrid Power for Resilient Generation,” “On-Site Power Trends,” and “Power Project Financing.”

POWER-GEN International is the largest gathering of power professionals in the world. Attendees will see or hear about new technologies that promise to change the way the industry generates power. Several sessions will center on the promise of energy storage, an emerging market driven by new mandates and demands for cleaner energy.

“We’re going to be talking about case studies around what people have done, what did they learn and what was the value?” said Raj Chudgar, president of Viridity Energy and co-chair of the Energy Storage track at POWER-GEN. “We’re going to have a session around financing and policymaking. The two big issues around energy storage are how much does it cost and how do I actually operate under the parameters of the regulatory bodies. We’re going to have a whole session around different technologies and uses. All energy storage is not the same. It’s key for us to provide this breadth and depth of orientation”

Here are some of the things you’ll learn if you attend POWER-GEN this year:

• Why Reciprocating engines are becoming increasingly popular for utility-scale power projects.
• How more sensors and new analytics software are going to help power plants reduce costs, increase sales and boost efficiency.
• How heavy-duty gas turbines, in combined cycle mode, are going to achieve 65 percent fuel efficiency, up from 61 percent today.
• Advancements in energy storage technologies and how close they are to commercial viability.
• The benefits and drawbacks of hybrid power pants.
• Clean Power Plan compliance challenges and the likely or unlikely scenarios surrounding this controversial rule.

four TECHNICAL TOURS

Technical tours of four power generation facilities will be offered to attendees on Monday, Dec. 12:

• The Sanford Power Plant, a combined cycle plant north of Orlando near Lake Monroe, features four combustion turbines with a capacity of 170 MW each. Altogether, the four HRSGs recover enough waste heat to produce a nominal 320 MW.
• Cane Island Power Park, a 710-MW natural gas-fired plant near Intercession City, is equipped with four gas turbines from GE, including an aero-derivative simple cycle turbine used primarily as a peaking unit.
• The Wind Service Training Center Orlando features the latest wind turbine technologies from Siemens. The equipment is used for hands-on safety, technical and professional development training.
• Orange County Convention Center PV Solar Installation, a 1.1-MW photovoltaic array on the roof of the North-South Building of the convention center. The $8 million project was placed online in February 2010.

PRE-CONFERENCE WORKSHOPS and CEU Credits

Attendees of POWER-GEN International can also choose from 31 Competitive Power College pre-conference workshops on Sunday Dec. 7 and Monday Dec. 9.

Some of the workshop topics include: “Effective Project management for the Power Project professional,” “Gas Turbine Fundamentals,” “Turbine Generator Failures and How They Can be Prevented,” “Cogeneration Power Plants: Case Studies of Successes and Failures,” “Power Project Opportunities in Brazil,” “Asia Pacific Power Generation Market: Strategic Review & Forecast,” and “HRSG Fundamentals.”

In addition, POWER-GEN attendees can earn CEU credits through exclusive training courses on valve installation, boiler control systems, boiler burner management, and thermal spray coating methods. For a complete list of CEU training courses: http://www.powergen.com/conference/training.html?cmpid=abmaemail.

Several sessions at POWER-GEN will be devoted to the industry’s transition to power fueled with natural gas and renewable resources. In 2015, renewable resources accounted for almost two thirds of new generation placed into service in the U.S. This trend will continue, which means gas-fired plants must be faster and more flexible to effectively offset the inherent fluctuations of renewable power.

In addition to speed and flexibility, POWER-GEN speakers will be exploring new methods and strategies for maximizing net fuel efficiency. Air quality control system upgrades for existing coal-fired plants and operation and maintenance practices for nuclear plants will continue to be chief staples of our conference program in 2016. What’s more, we will be taking a closer look at the technologies driving the digital transformation of power generation.

See you in Orlando!

About halfway through the spring 2016 outage at the Alvin W. Vogtle electric generating station in eastern Georgia, workers were ahead of schedule and gaining momentum. Vogtle ended the outage 32.5 hours ahead of their scheduled outage duration. According to Southern Nuclear Operating, this represents the best outage time in the company’s history.

“It’s all about teamwork, looking ahead, communicating, and following the schedule,” said Keith Taber, Site Vice President for Units 1 and 2.

Southern Nuclear, Westinghouse Electric Co., Day & Zimmermann and General Electric said the outage team developed an achievable schedule. They identified contingency planning for high-risk activities that, if not implemented correctly, could delay the outage. Once the team had a detailed plan, all that remained was for the working teams to follow the schedule, provide timely and accurate updates, and make sure their contingency plans were established and tested.

Refueling machine mast lowering a fuel assembly into the core. Core reload was done in 11.5 hours less than the planned schedule. Note – The blue glow occurs when a charged particle, such as an electron, travels faster than the speed of light in water – it’s called the Cherenkov Effect. Photo courtesy: Elizabeth Adams, Southern Nuclear

The team also maintained clear and consistent communications, and with early and frequent participation of new senior management who were involved in planning and accountability, removing any roadblocks that arose during the outage. Lessons learned from previous outages were examined and applied as part of continuous learning and improvement. The payoff was significant.

Any day added or removed from a planned outage equates to millions of dollars in expense or revenue. Outages are expected to be accurately planned and precisely executed in terms of safety, time and quality of work. For power plant outages, where completing more than 9,000 tasks is common, this is no small effort.

Planning

Structured, thorough planning in which all outage work is identified far in advance of the actual outage using tools such as condition-based maintenance data, operator data and subject matter experts, is the first step to a successful outage. This is necessary to schedule work being performed by plant and contract personnel in an integrated schedule that optimizes these resources. Planning starts several years in advance. Vogtle’s outage strategic plan maps out major projects through 2023. The more detailed milestone schedule includes the next three outages. Deadlines for “pre-outage” milestones occur year-round, the bulk of which are due in the six to nine months prior to refueling. In this case, there was only a six-month window between the spring and fall outages.

The detailed and collaborative planning done by the plant and by contractor personnel on the scope and schedule was the foundation for a successful outage, said Vogtle Outage Manager Mike Griffin.

“For this outage, we laid out the most accurate and realistic schedule we’ve ever developed,” Griffin said. “Schedule fidelity and table top readiness reviews were fundamental in delivering the best outage we have ever executed.”

Vogtle follows a set procedure and publishes its milestone schedule almost immediately following the last outage 18 or six months in advance, depending on the cycle year. Southern Nuclear and Westinghouse are Alliance Partners. For the latter, this means that as soon as Vogtle’s milestone schedule is published, Westinghouse aligns and schedules the people and equipment needed to make sure that all of the plant’s outage needs, for which the company is responsible, are met. Two months before an outage begins, Southern Nuclear and all of the contractors involved in the outage follow a strict procedure-based process. This process includes meetings onsite that Southern Nuclear and contractor executives attend to challenge the outage teams and verify the details concerning all aspects of implementing the outage, including budgeting and the progress of pre-outage activities.

Under the plant’s new senior leadership, Vogtle had already begun to improve cross-functional teamwork to facilitate earlier identification of methods to increase efficiency, which advanced their work management practices. It paid off just as well during the outage, Taber said. “The behaviors we’ve established for work management and the way we get things done while the units are online are really paying off now as we execute 2R18,” he said on Day 11 of the outage.

Cross-organizational teamwork was also positively affected with plant and contractor teams identified earlier. Westinghouse Outage Manager Larry Burrows said, “Normally in an outage, the team doesn’t feel like a team until five or six days into the outage. In this case, everyone knew who the teams were and who they would be working with two to three weeks prior to the start of the outage. New senior management really got the teams to take ownership of their work – there was a very positive can-do teamwork approach.”

Contractors were also brought on-site much earlier for the larger-scope work. This was coupled with extensive preplanning and improving the approach to such work, especially the installation of a new refueling machine.

An Example of Continuous Learning Success

Westinghouse was contracted to supply and install a new refueling machine for Unit 2. They had done the same for Unit 1, but not in the timeframe planned or desired. To correct that performance for the Unit 2 outage, Westinghouse and Vogtle personnel worked together to capture and take into account more than 100 lessons learned. They made changes to all four involved procedures: Installation, Demolition (of the old refueling machine), Site Initialization Procedure and Site Acceptance Testing. The improvement process began almost immediately after the Unit 1 outage ended.

This heated, lighted and ventilated temporary shelter allowed the teams to conduct pre-installation work without weather interference, saving time on critical path schedule. Photo courtesy: Elizabeth Adams, Southern Nuclear

This work included two refueling machine project management leads from Vogtle spending eight weeks with Westinghouse personnel at Westinghouse’s Shoreview, Minnesota, site, which is dedicated to designing and manufacturing equipment required to move fuel assemblies. One of them also spent a week at the Waltz Mill Field Services Center of Excellence located in Madison, Pennsylvania, where the installation team is based. The refueling machine team reviewed video footage Westinghouse had taken with a Go-Pro® camera during the Unit 1 installation. They applied this information during a rigorous retesting of the Unit 2 refueling machine and proceeded to make modifications which eliminated obstacles to the machine’s movement that had been encountered during the Unit 1 installation.

To accomplish it, Vogtle and Westinghouse project leads and engineers worked together and created a device they used to avoid a problem faced during the Unit 1 installation. The device is a mock-up identical to the lower portion of the refueling machine bridge. Using it, they were able to sweep the entire area of the machine’s movements along the embedded rail track on which it rides before the refueling machine was brought into containment for installation. The embedded rail track is used to guide the refueling machine during operation. Also based on lessons learned, Westinghouse pre-installed dozens of clamps and wiring connectors on the refueling machine, which reduced the scope of electrical work that would need to be done in containment on the critical path schedule. It also eliminated drilling inside containment for the clamp installation, which had proved time-consuming and presented foreign materials challenges during the Unit 1 installation. Additionally, the teams conducted electrical walk-downs in three phases: performing two independent reviews in Shoreview – one each by Westinghouse and Vogtle personnel – and a third on-site at Vogtle Unit 2.

Some pre-installation work needed to be conducted outside. To avoid delays that had been caused by inclement weather during the Unit 1 installation, the team erected a 50-foot-high, 136-foot-wide, 60-foot-deep tent with lighting, heating and ventilation that allowed workers to unwrap, inspect, prepare and pre-assemble portions of the refueling machine. They also were able to conduct walk-downs of the machine, including foreign material inspections and wiring placement verification. Additional pre-work included pre-identifying and stenciling into the refueling machine the locations of each weld that would be made in containment.

Time continued to be saved on the refueling machine with streamlined activities during the Site Initialization Procedure and Site Acceptance Testing phases – the final processes that had to be completed before the new machine could be used to reload the fuel. Time was saved by conducting encoder testing at the factory and by identifying and removing duplicative steps between the two final processes. The on-site testing sequence was also optimized to minimize movement of the refueling machine, and to reduce hoists over the reactor core.

All of this resulted in the Unit 2 refueling machine installation being completed in half the time of the Unit 1 installation and a day ahead of the planned schedule. Since this installation was driving the critical path schedule, this savings was helpful to the overall outage schedule.

Consistent and Improved Communications

On a more typical 18-month schedule, meetings between Vogtle and the outage support team would be held daily. On the six-month compressed schedule, the Alliance Partners and key contractors met twice each day. Mr. Taber attended many of those meetings, helping to drive accountability for work and follow-through, as well as remove obstacles if they arose. But more of a presence of senior management did not mean that people were less empowered. The decision-making was driven to the worker level whenever possible. Workers would report up twice per day and this proved a very effective approach for efficiency, accountability and removing potential barriers from completing tasks before they impacted schedule.

Another important improvement and among the top lessons learned per Mr. Griffin is the value of all-inclusive schedule reviews. “All-inclusive schedule reviews means that when we met to review an outage task, we included everyone required to make that outage activity a success. Every person on the team with a role was there to go through a dry rehearsal of what their job was and what was required to complete it,” he said. In the past, it was incumbent upon people to read the schedule and make it happen. The all-inclusive schedule reviews ensured that all of the tasks were completely understood by all team members, whether plant or contractor personnel.

Another significant communication improvement was equipment-based. Vogtle had made a major upgrade in communication technology to expand communication with, and within, containment groups. In past years, radiation protection, refueling and polar crane personnel wore headsets and belt packs to communicate but all were on different systems. With the new system, which was fully implemented during 2R18, more groups – including containment coordinators, radiation protection, polar crane, refuel team, Radium Inc. nozzle dam team and Westinghouse eddy current technicians had dedicated channels on the same system. An additional open miscellaneous channel was assigned to the refueling machine team. The contracted nozzle dam and eddy current teams brought in their own equipment and that equipment was connected to Vogtle’s new system, which had not been possible in the past.

Vogtle’s new communication system incorporates key panels in the Control Room and in the plant’s Outage Control Center. The new key panels equipped Vogtle’s Unit 2 Control Room personnel with the ability to communicate with the refuel team and containment coordinators, and Vogtle Outage Control Center personnel to connect to more than a dozen different groups at the press of a button. With safety always a top consideration, certain teams, such as the polar crane and refuel teams, could be heard and could communicate among themselves, but could not be interrupted by personnel outside the teams. This safeguard is meant to avoid distractions during heavy load and fuel assembly moves.

Westinghouse also applied a relatively new communication system this outage, known as the LiveCAN Field Communications System. This portable and rapidly deployable system supplied the Westinghouse full-scope refueling effort with audio, video and data communications capabilities. Developed by Westinghouse in 2015, LiveCAN connected Westinghouse field workers in containment to Westinghouse on-site project management personnel and to the Westinghouse Outage Control Center located at the Waltz Mill Field Services Center of Excellence. Real-time data sharing via the LiveCAN system assisted the Westinghouse refueling team in making a big contribution to the overall outage success. With fuel reload faster than predicted using the new refueling machine, the reload was completed 11.5 hours earlier than the planned schedule. The new refueling machine’s enhanced reliability and production capabilities will continue to contribute to improved refueling performance.

Adherence to Schedule

To help drive workflow in containment, Vogtle implemented another new strategy for 2R18 with the addition of containment managers, one each on the day and night shifts. During the outage, their main job was to drive critical path activities and ensure personnel were ready to perform a task the minute it could be undertaken. Vogtle wisely selected two seasoned veterans, Tom Petrak and Steve Waldrup. Both are former shift managers, Vogtle Outage Control Center leads and NRC-licensed Senior Reactor Operators.

Installing the new refueling machine – a critical path task. Photo courtesy: Elizabeth Adams, Southern Nuclear

Real-time data sharing via the LiveCAN system assisted the refueling team in contributing to the overall outage success. Photo courtesy: Shamus Fatzinger, Westinghouse

“We’re always looking a day or two ahead to try to identify what might challenge us from meeting the schedule. I see the role of containment manager as doing everything I can to help the people working in containment understand what the OCC [Outage Control Center] is trying to accomplish with regards to working the schedule,” Petrak said.

The guidance of containment managers with authority and a great degree of experience helped outage personnel develop more proactive behaviors, Waldrup said.

“I see the whole mindset of people inside containment changing,” he said. “I think we’re changing the culture on how we execute critical path – which is going to shrink the time it takes to do all these activities.”

During the spring 2016 outage, Vogtle performed most critical-path tasks in less than the allotted time, and the presence of containment managers receives some of the credit for this achievement.

With a large part of the outage work, 66 percent, Westinghouse also had an experienced outage manager in the field, Larry Burrows, and also made some strategic changes.

For refueling activities, Westinghouse flipped its model from the Unit 1 outage staffing of 10 technicians and 18 containment support workers to the Unit 2 outage model of 18 technicians and 10 containment support workers. Technicians can move fuel, but the support workers cannot.

While maintaining the same headcount, more technicians meant a qualified person was always available to move fuel and insert shuffles as soon as these tasks could be done rather than waiting until one was available.

“The skill level of the technicians and the containment support workers was very important,” Burrows said. “People were able to safely conduct their tasks with little supervision. I was there for many reasons, but a main one was to get ahead of any foreseen or emergent issues, remove the roadblocks and then let competent people get the job done.”

Burrows felt that the collaboration between the site personnel and contracted personnel was excellent.

“Whenever we needed site personnel to get involved so we could continue a task, they were ready, whether it was maintenance, mechanical, electrical or chemical groups,” he said. “We had great collaboration and the outage preplanning and execution were done very well.”

There was no single improvement that made the Vogtle Unit 2 spring 2016 outage the best in the company’s history.

There were changes in strategy, increased and all-inclusive participation in schedule review meetings, lessons learned examined and applied, an exemplary collaboration between teams and plant and contractor personnel, senior management support, employee empowerment and teams brought on-site earlier than in the past, among others.

Most importantly, the Vogtle spring 2016 outage was completed with no significant human performance or safety events. Every task was completed safely.

Performance like this will help the U.S. nuclear industry reach the goals of its Nuclear Promise initiative of continuing to improve safety, reliability and economic performance, including reducing operating costs 30 percent by 2018.

Author:

Donna Ruff is a communications consultant in PR and Trade Media Relations for Westinghouse Electric Co.

By Tim Miser, Associate Editor

Coal-fired power generation doesn’t command many exciting headlines these days. Coal-fired plants don’t have the appeal of newer renewable technologies, which often rely on cutting-edge innovations to generate power. And coal-fired plants aren’t always as clean or efficient as modern combined-cycle natural gas-fired plants. It’s probably fair to say that coal facilities have borne a greater burden than other forms of fossil generation in the never-ending race to comply with environmental regulations. But coal-fired generation continues to comprise a huge percentage of the United States’ generation portfolio, and it seems likely to remain important to the country’s power needs for many years to come.

Dan Lee

Ken Buttery

Vic Svec

With this in mind, Power Engineering (PE) magazine sat down with three executives in coal-fired power to discuss the industry’s wins and losses, strengths and weaknesses, and the challenges coal is likely to face in the coming years. Dan Lee is Senior Vice President of Fossil & Hydro Generation at American Electric Power (AEP). Ken Buttery is Regional Executive of Sales at GE’s Steam Power Systems. And Vic Svec is Senior Vice President of Global Investor and Corporate Relations at Peabody Energy.

PE: Let’s dive right in. What is the future of coal-fired power generation in the United States?

Dan Lee: Coal should remain part of our country’s balanced energy mix. It is still necessary for reliability to provide 24/7 dispatchable generation, and it’s also affordable generation that provides value for customers. It is challenging in certain areas because market prices are depressed and it is hard to sustain the budgets needed for maintenance and refurbishment of a coal plant when market prices are so constrained. An example is what we see in Texas, where coal generators are really challenged because market prices are so low. There is a discrepancy between the amount of revenue a coal plant needs to operate and what the market is delivering in unregulated areas. We also see low reserve margins in ERCOT because it’s a really difficult environment for coal plants, which is a concern.

Ken Buttery: Even today, coal power remains a significant contributor to the overall power generation mix in the United States. Increasing regulations over the past decade have, rightly, pushed existing units to lower their impact on the environment and reduce their non-greenhouse gases emissions, which has led to a significant demand for more sophisticated environmental controls solutions. A few U.S. utilities have invested in some degree of modernization of their coal-fired stations rather than retire them in favor of other fuel sources, and we are seeing a growing demand for digital solutions that can help plants run with higher efficiency, additional flexibility, and increased reliability over the remainder of a plant’s lifetime. On the other hand, the coal power generation installed base is aging in the U.S. and the average efficiency of 33 percent today is much lower than the latest generation plants which have been installed and commissioned in other parts of the world. Very few plants in the US operate at Ultra Supercritical conditions and the few newest units commissioned in the late 2000s operate with lower parameters and efficiency than the latest generation of plants recently put in operation in some other countries.

Vic Svec: While the factors affecting the coal industry in recent years have been unprecedented, coal remains an essential part of the energy mix. Coal keeps energy affordable and reliable and was responsible for more than one-third of the electricity generated in the United States last year. EPA’s estimates show coal generation continuing at a 675 to 750 million ton-per-year annual demand rate for decades to come-about the same path that we are on in 2016-and that’s under a Clean Power Plan (CPP) that has been stayed by the courts.

PE: What are the biggest technical challenges for the coal-fired power industry?

Dan Lee: There isn’t anywhere near enough funding and support to make progress on low-carbon technologies for fossil-fired generation, which will be critical for the future of coal generation. There needs to be more investment in research, and we are looking to the Department of Energy and others to lead that effort. Currently, the R&D in this area is not very robust.

Ken Buttery: Improving the efficiency of coal-fired plants in a competitive way has been one of the toughest challenges in the coal-fired power industry. Over the last decade, the industry in general, and GE in particular, have spent significant resources on developing the supercritical and ultra-supercritical steam cycle technologies, developing the right materials to operate at higher pressures and temperatures, and mastering their industrialization to make these solutions economically competitive. One of our latest plants has been in successful operation for over a year in Germany with an efficiency rate in excess of 47 percent-significantly higher than the global average of 33 percent, with amazing availability and flexibility.

Vic Svec: Emissions progress for coal begins with deployment of high efficiency, low emissions (HELE) power stations using technology that is available today. Our view is that longer-term investments in next-generation carbon capture, use, and storage (CCUS) technologies are needed to enable commercial deployment and transition to the ultimate goal of near-zero emissions from coal-fueled power.

Coal-fired generation continues to comprise a huge percentage of the United States’ generation portfolio, and it seems likely to remain important to the country’s power needs for many years to come.

HELE power plants and advanced emission controls are available off-the-shelf, broadly used today in the United States and around the world, and deliver major environmental improvements right now. HELE technologies, for instance, drive up to a 90 percent reduction of particulates, sulfur dioxide, and nitrogen oxides versus standard generation. Greater use of these technologies are important for coal, natural gas, and industrial applications and help advance society’s goal for low-carbon energy systems.

PE: What are the biggest business challenges for the coal-fired power industry?

Dan Lee: Current market prices are inadequate to sustain the capacity needs of the grid, and the future of coal and nuclear plants is at risk because of it. A future of all 24/7 capacity being provided by natural gas generation brings a number of potential vulnerabilities to the grid.

Ken Buttery: From a business perspective, our customers are looking for technology that will allow them to achieve better performance, greater reliability, and lower operating cost. Higher efficiency, lower emissions, better economics-that’s what our customers care about.

Vic Svec: Our business approaches sustainability around maximizing the three Es-Economy, Energy, and Environmental-and the same is true for generators. Fuel choices matter and policies matter over time for both generators and their customers. The challenge for generators is choosing an energy mix that meets environmental goals, provides low-cost electricity for customers, and offers proper returns over time. Peabody believes that coal producers should give strong attention to key standards in the areas of sustainable mining, energy access, and clean coal solutions. This includes a commitment to safe workplaces and coal land restoration, engagement with government, academia and other stakeholders to address major energy challenges, and support toward greater deployment of advanced coal and near-zero emissions technologies.

PE: What are the biggest legal/regulatory challenges for the coal-fired power industry?

Dan Lee: The uncertainty around what future regulations, including the CPP or its replacement, will require is probably the biggest challenge. We don’t know what the rules may look like or whether their compliance timelines will be reasonable. The timeline that was originally proposed in the CPP was unworkable, but the EPA improved it in the final rule. It is hard to say what the outcome of the legal review process might be, but that doesn’t change our focus on diversifying our fuel mix and delivering electricity to meet the needs and expectations of our customers.

Ken Buttery: The ability of nations to meet emissions goals set out in the Paris COP21 agreement, while meeting growing demand for electricity, will depend on the ability of fossil fuel-powered plants such as coal to deliver power more flexibly, responsively, and cleanly. With the CPP in the United States, we are particularly focused on addressing CO₂ emissions and water effluent regulations.

Vic Svec: Peabody believes greater public support is needed to bring CCUS technologies to commercial scale, and CCUS has been identified globally as absolutely essential to meeting the world’s carbon goals in a cost-effective manner. Since the 1990s, we have widely advocated a technology approach to reduce carbon and other emissions, invested hundreds of millions of dollars in clean coal projects and partnerships, and taken positions on issues such as those in our Statement on Energy and Climate Change. In 2015, Peabody’s President and Chief Executive Officer chaired a National Coal Council report that called for enabling carbon capture to achieve policy parity with other low-carbon options, such as solar and wind. The report was done at the request of the U.S. Secretary of Energy, who has recently articulated strong support for development of carbon capture with coal remaining a major part of our energy future. The report outlined what is needed to propel progress for CCUS technologies, which ultimately would lead to near-zero emissions from coal, and is recognized by global leaders as essential to our carbon goals. Key recommendations included a first-of-its-kind regulatory blueprint to remove barriers to construction and development of CCUS projects, as well as a call for communication and collaboration among global policymakers.

PE: How does the coal-fired power industry comply with emissions regulations while still remaining efficient and profitable?

Dan Lee: Historically, we’ve been able to find ways to comply with regulations because there have been technologies available to help us comply. That’s one of the concerns going forward with carbon regulations, because the technologies are not sufficiently demonstrated. Also, regulations ultimately have a trickle-down effect on our customers’ bills, so we are always mindful of that impact and work toward the most cost-effective, yet environmentally responsible, solutions.

Ken Buttery: In a post-COP21 world, the coal power industry can remain efficient and profitable by combining high-efficiency cycles (ultra-supercritical technology) with digital capabilities and environmental control solutions, what we refer to as smarter, cleaner steam power. For example, our new ultra-supercritical cycle, when used in double reheat technology, can deliver an additional 1.5 percentage points of efficiency compared to the best plants in operation today. This can add up to $80 million additional net present value (NPV) for a 1000-MW plant. Then you add in digital capabilities. GE’s Digital Power Plant for Steam can increase efficiency by up to 1.5 percentage points, reduces CO₂ emissions by 3 percent, and allows for 5 percent less unplanned downtime over the life of a plant. We are getting closer and closer to a 50 percent efficiency target and for each percentage point of incremental efficiency, we bring CO₂ emissions 2 percent lower. So for a customer with a large fleet, this provides significant incremental gains and cost savings, as well as a much better CO₂ footprint.

Vic Svec: Greater regulatory certainty has been an imperative for the utility industry for quite some time. This is a multi-part equation, though, that goes not only with continuous improvement in emissions but also the market-based cost of alternatives. Over time, coal has proven to have significant advantages in reliability and costs. When other fuels struggled during the polar vortex a few years ago, coal provided the majority of incremental power. The same was true in multiple regions this year during the recent heavy cooling degree season.

PE: What specific emissions regulations are most challenging to the coal-fired power industry?

Dan Lee: While we’ve been able to achieve compliance with the Mercury and Air Toxics Standards rule that went into effect in 2015, maintaining compliance continues to be a challenge. At some of our plants, we are using air pollution control systems to reduce SO₂ and NOx as well as mercury. We are still learning how to best balance the control systems to achieve targets for all three pollutants.

Ken Buttery: Environmental control solutions are available today to address all the sources of non-greenhouse gas emissions, NOx, SOx, particulate matter, mercury and other hazardous air pollutants from any industrial plant to meet and exceed the world’s strictest regulations. For example, dry desulfurization systems have been used for SOx control and as multi-pollutant control devices for several decades. Selective catalytic reduction technology controls NOx formed in combustion processes. And together with our GE Water business, we have developed spray dryer evaporator technology for wastewater treatment to support all needs up to zero liquid discharge applications.

Vic Svec: There’s no question that the CPP would prove challenging for the entire nation. A NERA Economic Consulting study concludes that the CPP will increase energy sector expenditures $220 billion to $292 billion from 2022 -2033. It would also increase the average U.S. retail electricity rate up to 14 percent each year over the same time period according to the study. That’s why scores of industry participants, attorneys general, states, and industry and citizen organizations are opposing the plan as poor law and poor policy for America’s electricity consumers.

PE: Will gas-fired or renewable power generation entirely replace coal-fired power in the foreseeable future?

Dan Lee: Gas-fired generation could potentially replace coal-fired generation, but it is too risky to depend upon natural gas as the only fuel for 24/7 generation. It’s in our nation’s best interest to maintain a diverse and balanced energy mix that includes coal, gas, nuclear and renewables. There will always be a need for 24/7, baseload generation to ensure the integrity of the grid. Renewables can replace energy, but they can’t replace capacity in the same way gas or coal can.

Ken Buttery: All analysis done on the subject shows that coal power will continue to be a vital part of the global energy mix. In GE, we see that a good energy mix of the various fuels, when combined with environmental protection measures and digital capabilities, will produce the best results. In most countries, a mix that includes renewables, gas, and state-of-the-art efficiency coal power generation will meet the competing objectives for reliable, affordable power in favor of the competitiveness of the economy while fulfilling the environmental targets. Power sources should be independent from global fluctuations as much as possible, affordable for their citizens as well as economic development, stable no matter what the season or weather conditions, and respectful of the environment. With 2660 GW of installed capacity and nearly 900 billion tons of reserves, coal remains a self-sufficient and affordable means to produce power, provide energy security and stabilize the grid.

Vic Svec: Entirely replacing coal-fired power is neither likely nor desirable. When it comes to creating a sustainable energy future, each fuel has inherent strengths and challenges, and all forms of energy are needed. Coal’s advantages include a track record of reliability, scalability, affordability, and security of supply. It fuels 40 percent of global electricity. In addition, thermal coal is expected to continue to fuel thousands of existing coal generating plants as well as scores more that are under construction across the globe.

WFGD ZLD System at ENEL Sulcis, Italy, showing Brine Concentrator and Mechanical Vapor Compressor in the foreground. Photo courtesy: Aquatech International.

In September 2015, the Environmental Protection Agency put forward the final rule for Effluent Limitation Guidelines (ELGs), which establishes revised water discharge standards for the steam electric power generation industry. The final rule took the EPA a decade to develop and it finally became effective on January 4, 2016. The onus is now on the power industry as a whole to study the rule in light of their current (and future) water discharge practices. Experienced technology suppliers will play a key role on the pathway to compliance by applying commercially proven Zero Liquid Discharge (ZLD) solutions to overcome site-specific challenges.

Falling Behind and Catching Up

The previous set of steam electric ELGs had been in effect since 1982 without revision. After careful study, the EPA determined that the ELGs were “out of date” and that toxic pollution levels that were being discharged into America’s watersheds were causing harm. The study reported that almost half of the waterbodies receiving power plant discharge exhibited pollutant levels that exceeded the limits established by the human health water quality criteria (EPA, 67840). At first glance, the term “out-of-date” can seem strange when discussing pollutant levels, since pollutants are pollutants and they cause harm whether in 1982 or 2016. However, the term “out-of-date” refers specifically to the advancements that have been made in air pollution control and flue gas desulfurization. These advancements have caused substantial changes to the nature of the waters discharging from the power plants to the local bodies of water. Three decades of technological leaps have left the effluent guidelines lagging behind.

While the effluent guidelines were stagnant, new water treatment technologies were being developed to treat these new types of waste waters.

The most significant technology to be born and mature with the industry was a process called Zero Liquid Discharge which is capable of completely eliminating water discharge to local watersheds.

ZLD has been applied to the power industry for almost 50 years with a proven track record.

The majority of ZLD systems operating within the power industry treat blowdown water from cooling towers and boilers, many of them recycling >99% of the blowdown water back to the cooling tower.

Not only does this eliminate a regulated discharge, but it also improves the water balance by reducing the make-up water volumes taken from local fresh water sources (especially important in arid regions).

The evaporation systems used in ZLD for water recycle consist of Brine Concentrators (Vertical-Tube Falling Film Evaporators) and Crystallizers (Forced-Circulation).

ZLD technology was pilot tested with Wet Flue Gas Desulfurization (WFGD) blowdown over 20 years ago. In the last decade, ZLD technology has been applied commercially to WFGD blowdown with great success.

The EPA has carefully studied the evaporative ZLD systems currently in operation on WFGD blowdown and is mandating ELGs as demonstrated by this technology for new discharge sources and power plants yet to be constructed.

One important exception to this mandate is the more relaxed posture by the EPA towards existing plants.

The new ELGs establish numerical limits for several Pollutants of Concern (POC), including arsenic, selenium, mercury and nitrates.

Although the preference for evaporative ZLD is clear, the EPA set effluent limits for only these POCs to allow the use of another technology (physical/chemical/biological treatment) that is capable of reducing these pollutants but doesn’t eliminate them.

Other pollutants of concern (including boron, bromide, chloride and TDS) are not controllable by physical/chemical/biological treatment and the final rule did not assign effluent limits for existing plants.

Window of Opportunity

Although the EPA decided not to make the effluent limits consistent with evaporative ZLD mandatory, a voluntary incentive program was established to reward existing facilities that pursue the best-practice of ZLD. This incentive comes in the form of a window of opportunity – a strategic delay in the implementation deadline. The guidelines are to take effect in the next NPDES cycle, beginning November 2018, which would give an existing facility approximately three years to develop and execute a compliance strategy based on physical/chemical/biological system.

Facilities that pursue this path are subject to the lighter regulations that limit only arsenic, selenium, mercury and nitrates. The incentive pathway would extend the implementation deadline to as late as December 2023 given that the steam electric power plant opts to adhere to more stringent ELGs (including a limit on TDS) which is consistent with evaporative ZLD as the treatment solution.

The existing facility is then given eight years (instead of three) to comply with the regulations, which not only defers the capital investment but also gives additional time for careful study and planning of the implementation strategy.

This is an especially significant opportunity for facilities that face additional Water Quality Criteria (WQC) above and beyond the limits established by the EPA. WQCs are established by state authorities for the protection of specific bodies of water. These criteria are driven by local factors that require special consideration for preservation of aquatic lifeforms and/or human use.

In many of these cases, evaporative ZLD may have been an immediate necessity to prevent the accumulation of halogens and dissolved salt content in the waterbody. In these instances, the incentive program offered by the EPA for delayed compliance is especially attractive.

Not only is the physical/chemical/biological treatment approach not able to control all of the POCs, but there are also expressed concerns about the efficacy of such an approach.

The EPA has documented power plant operators who have expressed concern about the stability of biological treatment systems due to high chlorides, temperature fluctuations and variability of the FGD wastewater. The EPA has dismissed these concerns. While this biological treatment has been proven effective on the POCs mercury, arsenic, selenium and nitrates, it has no impact on bromides, chlorides, boron or TDS.

The EPA has already acknowledged that evaporation can meet the established limits for Best Available Technology economically feasible (BAT). When these other POCs become numerically limited in the future, ZLD will become mandatory. Plants should strongly consider ZLD now to improve their standing in the future.

ZLD’s Proven Track Record

The past decade has witnessed the rapid success of Zero Liquid Discharge in treating WFGD blowdown.

Although the EPA ELGs list several possible methods for achieving ZLD, there are only two ZLD methods that have been widely used and are commercially proven.

The two proven ZLD methods both utilize Brine Concentrators and Crystallizers to recycle WFGD water as high-purity distillate.

Each method produces a final concentrate that is not discharged as a liquid from the plant. The first method produces a dewatered solid from the Crystallizer (see Figure 1) and the second method produces a concentrated brine at a very low volumetric rate that is blended with fly ash for solidification. The final solids generated by each method are suitable for landfill disposal. Zero liquid discharge is achieved and Effluent Limitation compliance is ensured.

The nature of WFGD blowdown conditions are variable over time and are heavily influenced by the coal type being burned as well as other operating conditions (Mandigo, 2007).

In a thermal evaporation process, the primary constituents that drive the design of WFGD ZLD system are the scrubber’s TDS/chloride content, hardness levels (Calcium and Magnesium) and TSS/heavy metals.

Experienced ZLD technology suppliers will design the system not only for average concentrations, but will also consider maximum and minimum concentrations in each aspect of the design. ZLD systems have a strong ability to handle wide variations in water chemistry which makes them an ideal solution if/when facilities consider operational changes driven by market dynamics; the ZLD system can be designed to meet current and future demands.

The most utilized ZLD process in operation to date consists of physical chemical pretreatment, Brine Concentration, and Crystallization which directly produces a dewatered solid cake for landfill disposal.

A block flow diagram of this process is shown in Figure 3, courtesy of Aquatech International.

The physical chemical pretreatment portion of the ZLD process conditions the feedwater by reducing TSS, heavy metals, and partially softens the WFGD blowdown water.

Due to the variability of the wastewater, this pretreatment step adds robustness to the process making operation of the Brine Concentrator stable and reliable, like the Brine Concentrators that have been operating in power plants for decades.

While pretreatment does consume chemicals and produce a pretreatment sludge for disposal, it can be configured to recycle the sludge in the form of calcium carbonate back to the FGD system for recovery: thereby, reducing plant chemical consumption and sludge disposal.

The pretreatment also importantly removes a fraction of the hardness content such that the crystallization stage is accomplished at moderate temperatures and will consistently generate a sodium chloride based salt which is suitable for landfill disposal. (Without removing a portion of the hardness upstream, calcium chloride and magnesium chloride salts would be generated which are more problematic for disposal given their deliquescent nature.)

Aquatech has applied this process for six power plants. Five ZLD plants have been operating since 2008 (Marlett, 2012) and one has been operating since 2012 (Roy, 2015).

Photographs of such ZLD facilities at the ENEL plants in Italy are shown in Figures 2 and 3, courtesy of Aquatech International.

The second proven ZLD process utilizes Brine Concentration and Crystallization to concentrate the FGD wastewater such that a low-volume liquid concentrate is produced and is mixed with fly ash for landfill disposal. A block flow diagram of this process is shown in Figure 4.

This process consists of clarification to remove suspended solids upstream of the Brine Concentrator, if required. One important distinction with this ZLD method is that the salts present in the WFGD blowdown water are concentrated directly by the Brine Concentrator and softening is not required upstream, further improving the OPEX. Depending on the WFGD anticipated water chemistry variations as well as the amount of fly ash available for blending, a Crystallizer following the Brine Concentrator may or may not be required.

In either case, the evaporation system produces a low-volume brine concentrate that is mixed with fly ash. This reduces the load on the thermal evaporators resulting in lower energy consumption for the ZLD.

The City Water Power and Light ZLD system (Mandigo, 2007), Iatan Power Generating Station ZLD system (Mandigo, 2009) and Merrimack Station ZLD system (Scroggin, 2013) were designed for this configuration.

This ZLD method is preferred in some cases as it offers advantages in lower energy consumption and no chemical softening treatment, which reduces chemical OPEX and sludge handling requirements. The Merrimack Brine Concentrator is shown in Figure 6.

Conclusion

With the final rule now in effect, existing steam electric plants are best served by holistically considering their discharge practices (current and future levels) and studying the improvements that can be gained with Zero Liquid Discharge.

ZLD systems offer a proven and robust solution that have the ability to handle wide variations in WFGD wastewater pollutant concentrations as they change over time and ensure continuous ELG compliance.

Operating facilities that choose ZLD technology will not only mitigate their compliance risk but also capitalize on the implementation extension offered by the EPA as an incentive to those who select the preferrable ZLD.

With this in view, existing plants are best served by working with experienced ZLD technology providers who have demonstrated the ability to apply commercially proven ZLD solutions to wet flue gas desulfurization blowdown.

Author

Greg Mandigo is a Senior Applications Engineer in the thermal technologies group of Aquatech International located in Hartland, Wisconsin. J. Michael Marlett, P.E., P.Eng is the Process Application Manager for Industrial Concentration at Aquatech International Corporation.

One of four Jenbacher J620 gas engines being lifted by crane into place for the Hudson Yards project in New York City. Photo courtesy: GE

Thomas Edison built the first electrical distribution system in 1882, delivering electricity from his Pearl Street Station in Lower Manhattan to nearby customers – and giving birth to the centralized electrical system. More than 130 years later, the confluence of low natural gas prices, high electric rates and the need for resilient power is motivating many commercial and industrial customers across the United States to return to Edison’s original concept, where power is generated closer to where it is used. The drivers for this trend of on-site generation are perhaps strongest back in Edison’s original test city of New York, where a combined heat and power (CHP) renaissance is underway.

An integrated solution, not a product

The types of customers who can benefit from CHP – which produces power and heat on-site – are as varied as there are personalities in New York City. Currently, CHP projects are under way at hospitals, apartment complexes, industrial facilities, data centers, and universities, to name a few.

Sometimes called cogeneration, CHP is not a new concept. GE has delivered more than 8,000 MW of gas engines in CHP applications around the globe. If all were located in New York City, they would meet more than half of the city’s peak power needs.

CHP captures the thermal energy from the engine’s exhaust and cooling systems to generate additional value, often in the form of heating hot water or to supplement building cooling loads. This combination can result in very high total efficiencies, at times exceeding 90 percent efficient use of the natural gas the engine consumes. Compared to other forms of distributed power such as solar power, CHP offers the added benefits of being available when it’s cloudy and at night, the capability to closely follow the electricity demand, a smaller footprint per megawatt of power produced, and the production of valuable thermal energy as a byproduct of power generation.

factors driving interest in CHP

The transmission and distribution infrastructure in North America was developed in the 20th century and is reaching a point where upgrades and reinvestment are needed, which is often paid for by higher electric rates. At the same time, gas prices in the US are at historical lows; in fact, the US just reached a 17-year low Henry Hub natural gas price. While the delivered price of natural gas in some urban centers is much higher than the Henry Hub price, the economics of on-site gas generation have never been better. Additionally, the very high efficiency of CHP plants enables a cost effective way of reducing greenhouse gas emissions.

New York City has experienced severe weather events in the past few years, such as Superstorm Sandy and Hurricane Irene. In the aftermath, many CHP systems kept the lights on at apartment buildings, hospitals, nursing homes, and college campuses. Further, the creation of thoughtful policy from the New York State Energy Research and Development Authority, known as NYSERDA, both in terms of incentives and end user education, has made New York City a fertile ground for CHP deployment.

Of course, the opportunity for CHP extends far beyond the five boroughs of New York City. North America’s power industry is undergoing coal plant retirements, and CHP will play an important role contributing to the power needs in an efficient manner. Available natural gas, combined with high electric rates and a climate conducive to both heating in the winter and cooling in the summer, is an accelerator for the CHP industry. As a rule of thumb, if there is year round thermal needs, and the electricity price divided by the natural gas price (in the same units), results in a ratio of 3 or more, a CHP system could be economically viable. In some cases, this ratio is much greater than 3. Further, if a potential utility customer is subject to a demand charge, based on peak energy demand, the economics could improve significantly.

GE has delivered more than 8,000 MW of gas engines in CHP applications around the globe. If all were located in New York City, they would meet more than half of the city’s peak power needs. Photo courtesy: GE

Challenges to faster adoption

Perhaps the biggest obstacle to CHP adoption is the acceptance of the status quo. Often, those who would benefit most from an on-site CHP are not intimately familiar with developing power generation projects or with the cost-saving opportunities of CHP. Building on-site power plants is not a core competency for most hospitals, apartment complexes or manufacturing facilities. Most engineering or facilities departments are rightfully focused on keeping their existing operations running smoothly, so taking on a CHP project is often deprioritized or seen as burdensome. After all, deciding if CHP makes sense requires both technical and economic assessments that rely on electrical, thermal and financial analyses. Interconnecting to the utility can be a cumbersome process, too; each utility has its own process for interconnection approval and detailed studies sometimes are required.

Ownership models can pose additional challenges. Sometimes those who occupy the building don’t own it, which then requires a broader team of stakeholders to complete the project. Finally, a building’s typical operating budget is not sufficient to cover the capital expenditure needed to design, engineer and construct a CHP system, so not having access to capital to fund the project can also be a significant issue.

Overcoming the challenges

While the macro drivers for CHP are largely in place in New York, finding ways to overcome the challenges is critical to enabling the economic savings for individual potential CHP users. Three ingredients are necessary for a successful CHP project.

First, the right team needs to be assembled to deliver an integrated, complete CHP solution. The design and development team working with the building owner must be familiar with local codes and standards and have relationships and demonstrated history with experienced electrical and mechanical contractors. The team also needs to have broad and deep expertise on gas and electrical interconnections, thermal and electrical controls, building heating/cooling integration, and equipment installation. Each CHP installation is unique, and having an engineering team that can work with customers to solve their specific challenges is a differentiator.

But having the right team extends beyond installation. Since many CHP systems are in place for 10 to 20 years, service providers must have similar staying power. And, since most CHP gas engines run as a baseload operation where efficiency matters, they need more specialized product support than that required by standby diesel engines running less frequently. With this in mind, technicians who are trained in maintaining gas engines, not just diesel engines, can help customers achieve optimal performance from their CHP installations.

Second, the right product is needed for the job. The electrical and thermal energy needs for each application will vary significantly by project. Since there is no “one-size-fits-all” product for CHP, selecting the technology that enhances the overall efficiency and economic return for the CHP solution is critical. Some CHP applications naturally will be a better fit for a gas turbine (for example, where a large amount of steam is needed), while other applications will be a better match for a gas engine as the prime mover (for example where higher electrical efficiency is more important). An experienced development and design team can quickly assess a facility’s energy uses to determine which type of prime mover will provide optimal returns. Also, for CHP projects that are islanded from the grid, or where reliability is paramount, a customer may choose to go with a less efficient engine that has a demonstrated track record of high availability and reliability.

Third, the right delivery model is needed. Delivery models have to be flexible, adjusting to the end user’s needs and goals. In the traditional delivery model, end users and building owners invested in and managed the CHP project themselves. Becoming more popular with customers today are energy service agreements, in which the end user pays no upfront capital expenditures and all of the initial capital, operations and maintenance costs are provided by the developer.

CHP case study

Hudson Yards is the largest real estate project in the city of New York since Rockefeller Center and the largest private real estate development in the history of the United States. The project is transforming the West Side of Manhattan by developing 17 million square feet of commercial and residential space. While Hudson Yards has received much publicity as it pushes current thinking on building design and real estate development within the City, it also is innovating on the energy front by incorporating a 13.2 MW CHP system to help decrease energy costs and improve resiliency across the site. The CHP system will generate electricity on-site, and the heat from four of GE’s Jenbacher J620 gas engines will produce hot and chilled water for the buildings. A single Jenbacher J620 gas engine generates roughly 3.3 MW of electrical power while also generating approximately 11 MMTBU per hour of recoverable thermal energy. This thermal energy comes from capturing the heat from the engine’s exhaust, jacket water, lube oil and intercoolers.

Engines were delivered during the summer, and the project is under construction.

Nick Lanzillotto, MEP-HRY Development, Related Hudson Yards, knew the project would be challenging and wanted to select a firm that had experience executing CHP projects.

“We are very excited Northeast Energy Systems has the ability to connect with our team on this project,” he said. “They have worked seamlessly with our engineering teams to design and deliver a complete CHP solution on a very complex project.”

Jonathan Coleman has firsthand experience on the need to create a tailored CHP design for each client.

As the Principal engineer at Vanderweil Engineers, he was the Engineer of Record for the Hudson Yards CHP project and is currently involved with multiple other CHP projects in New York City. “While the CHP concept is very simple, every project has its own particular set of technical and implementation characteristics which make them unique challenges,” he said. “In our experience, the best way to succeed is with an experienced team that can work together to solve problems and drive the project to completion. We have been fortunate to work with team members like Northeast Energy Systems and GE on some of the most difficult projects in the CHP industry.”

The digital CHP plant

The industry is building upon its digital industrial capabilities to help enable more efficient, reliable and cost-effective power generation.

A critical aspect to this is reducing, and ultimately preventing, unplanned downtime through asset performance management applications. For example, GE’s Web-based platform myPlant is a remote monitoring and diagnostics solution that allows plant owners and operators to monitor the performance of their engines remotely in real-time. In addition, it allows them to receive alerts on their phones or tablets if the engine is experiencing an anomaly.

Applications such as condition-based monitoring proactively evaluate the condition of components and take maintenance action only when an actual need arises. For example, myPlant can monitor and predict the lifetime of key components such as spark plugs by tracking the sparks’ performance and life over time so plant owners know if a spark plug may fail, or if they can extend their service interval. It is these developments, staged on GE’s Predix* software, that can provide real-time information and unit status – and help increase value of an operation. All of the nearly 200 installed gas engines in the Penn Power Group fleet in the United States are connected to myPlant software. Penn Power Group is the parent company of Northeast Energy Systems and Western Energy Systems.

As the nation moves to a grid with more real-time price signals at the distribution level, digital capabilities will be about more than reducing maintenance costs and downtime. They will also be about increasing revenue opportunities. For example, by combining engine performance data with information from the electrical grid – such as when demand (and prices) for electricity are highest – some of GE’s most advanced customers are able to intelligently and quickly make decisions about selling power back to the grid.

Moving from CHP interest to installs

CHP, and distributed power more broadly, are at a tipping point in North America, but multiple challenges are limiting CHP from living up to its potential. To unlock the opportunity, the right team, combined with the right products and the right delivery models, are needed. It will take the combination of these factors to enable a seamless transition to CHP, yielding a lower cost and more resilient source of power for building owners. It is only fitting that this renaissance starts in Edison’s old stomping grounds of Manhattan.

Authors:

Devon Manz is marketing and sales engineering leader for GE’s Distributed Power business. Al Clark is chief executive officer at Penn Power Group. Michael Norelli is the northeast business development leader for GE’s Distributed Power business.

By Tim Echols, Georgia Public Service Commission

Today, everyone seems to be talking about CO₂ and how to reduce it. Carbon-free energy sources are sought-after. Generous subsidies for wind and solar especially, both federal and state, have contributed to their individual success in various parts of the world. But if the wind is not blowing and the sun is not shining, green energy is not created. That is where carbon-free nuclear energy comes to the rescue. But in order to make it more “green and sustainable,” we must take action rather than letting the used fuel sit on a plant pad or be buried in the ground.

We put newspapers, milk cartons, aluminum cans, and all sorts of plastics on the curb in front of our house each week, yet the best we can do with used fuel is to bury it? We have in this country over 70,000 tons of used fuel stored at more than 100 sites in 39 states, and our 98 commercial reactors produce about 2,000 additional tons of used fuel each year. Because we don’t recycle this nuclear material, it would take nine Yucca Mountain repositories by the turn of the next century to house all of the used fuel being produced. Getting one Yucca has proved almost impossible, let alone nine.

Starting in 1990, the French did what the US backed away from-a commercial recycling plant for used nuclear fuel. They took the uranium-filled fuel rods, and figured out how to reuse 96 percent of the material, and how to do it safely. By separating the uranium and plutonium from the fission products, they took advantage of all the energy left in the material. More importantly, they turned the remaining four percent waste into an inert glass product that requires minimum security and safeguard protocols. If we did that here in the United States, it would significantly reduce potential waste going into a Yucca Mountain and extend the facility’s life.

So how is it that the United States would not want to do the same? Georgia Tech Professor of Nuclear Engineering Nolan E. Hertel, a renowned expert, notes that one result of the ban on nuclear recycling by President Carter, meant to prevent nuclear proliferation, is more than 2,400 tons of nuclear waste being stored on-site in Georgia.

In my opinion, the time has come for the nuclear energy industry to go greener and make the electricity it generates even more sustainable. We need to demonstrate the value of linking nuclear baseload and intermittent wind and solar. Here is how we can do it.

First, let’s recognize the energy value of the used nuclear fuel we currently discard. Did you know that our 70,000 tons of used fuel contains roughly enough energy to power every household in American for 12 years? “Valuing used fuel against the cost of permanent burial is a calculation best done by the companies that provide fuel management services,” says Jack Spencer of the Heritage Foundation. “Right now utilities have no incentive to do anything but store it.” This would require Congress to act.

Second, complete the federal construction project called MOX Project (Mixed Oxide) at the Savannah River Site, near Augusta. This plant, modeled after processes currently used in France at La Hague and Melox, will permanently change surplus nuclear warhead material into commercial nuclear reactor fuel. This reactor fuel could be used across the river at Georgia’s Vogtle reactors with slight modifications. The MOX Project facility is 70 percent complete, but haphazard funding from Washington is dragging out the project. We need Presidential support for this funding.

Third, recycling used nuclear fuel makes sense in the long run. This recycled material will be available at a discounted price compared to fresh uranium fuel the utilities currently buy. Ratepayers and shareholders will benefit from cheaper reactor fuel, especially in these times when low natural gas prices are causing nuclear plants to be at a financial disadvantage. The cost of nine Yucca Mountains will be astronomical, and recycling drastically reduces storage for the remaining 4 percent of used fuel.

Finally, let’s do the math. If we continue to close coal plants, which operate around the clock regardless of weather, and we continue to add intermittent energy sources like wind and solar and their natural gas backup generators, how are we going to reduce our net CO₂ emissions and provide the reliability that businesses and ratepayers expect? Nuclear energy is the answer, and recycling makes it greener and sustainable.

Author

Tim Echols is an elected commissioner on the Georgia Public Service Commission. He frequently writes about energy matters and speaks at conferences across the country.

By Bob Gallo, president and CEO of York, Voith Hydro, Inc.

Hydropower supporters have reason to believe the future is bright for the world’s oldest and most-widely used source of renewable energy.

No other source of energy combines hydropower’s affordability, contributions to combating climate change, and job creation. Far from an old and conventional source of energy, clean and renewable hydropower is constantly evolving and searching for new methods to squeeze energy out of the approximately 80,000 U.S. dams that do not produce power. In many cases, hydropower provides backup generation to support the development of intermittent energy sources such as wind and solar.

Nationally, hydropower’s benefits are unsurpassed. Reliance on hydropower reduces carbon dioxide emissions by 200 million metric tons each year – the equivalent of taking 38 million passenger cars off the road. All told, over 300,000 people work in the hydropower industry, and it also offers the lowest levelized cost of any source of energy. Indeed, many states throughout the country, particularly in the Pacific Northwest, enjoy low energy prices in large part due to their reliance on hydropower.

What’s more, we expect hydropower’s importance to grow in the coming years.

Over the summer, the Department of Energy released its long-awaited Hydropower Vision Report, a comprehensive analysis that details several pathways to fully utilize our water resources. The report finds that we can boost hydropower generation by 50 GW by 2050 through a combination of new conventional hydropower, pumped storage, small hydro development, and emerging technologies such as Voith’s StreamDiver designed for deployment on many of the very streams previously thought unfeasible for hydropower.

One of the major hurdles standing in the way of the hydropower industry is the current regulatory climate.

Over the past year, Congress has debated and ultimately passed legislation that would streamline the regulatory process for hydropower – a process many believe is hindering its development. The Energy Policy Modernization Act, which also addresses regulations governing the development and use of many other sources of energy, would smooth licensing by declaring the Federal Energy Regulatory Commission (FERC) as the lead agency in what can be a very long and costly process that touches multiple jurisdictions, agencies, and even governments. Without a clear lead agency and defined time frames and deadlines, otherwise promising – but capital intensive – projects can languish for years on end.

While Congress has made significant progress on this legislation in a time otherwise noted for stalemate, as of September, House and Senate negotiators had still yet to iron out their differences. When Congress returns to session after the November elections, it should make final passage of the Energy Policy Modernization Act one of its top priorities before the end of the year.

Make no mistake: without important regulatory reforms, our country will find it difficult to meet its growing energy needs. Nearly 500 hydropower projects, representing over 15% of our current installed capacity, will be up for relicensing in the next 15 years. At the same time, numerous coal-fired power plants will be retired due to environmental regulations and global market forces. This energy will need to be replaced with clean and baseload power.

Every effort should be made to ensure hydropower lives up to its tremendous potential and delivers clean and affordable electricity to homes and businesses from coast to coast.

The release of the Hydropower Vision report reminds us that we can and must do more to responsibly develop our precious water resources. With the passage of the Energy Policy Modernization Act, we will take a step to live up to the tremendous potential quantified in the report and ultimately deploy more hydropower in every corner of the country.

By Keyshon Bachus, Environmental Manager, EthosEnergy Power Plant Services

With continuous attention paid to greenhouse gases, natural resources, and emissions reductions, new regulations continue to be promulgated to address the environmental impacts of emissions. Gas-fired generating plants, oil and gas operations, and chemical companies tend to feel regulatory pressure far more often than other industries. A company’s environmental compliance record is only as sound as their environmental management system (EMS). A strong EMS is comprised of policies, procedures, training, and tools necessary to ensure compliance with the increasingly complex regulatory requirements. Most importantly, these EMS programs work in conjunction with a strong environmental culture, which requires buy-in from employees at all levels.

Setting The Bar High

A company’s environmental policies not only demonstrate commitment to regulatory compliance and environmental protection; they also set the expectations of how employees should tackle environmental issues. These policies and procedures ultimately paint the company’s picture of how employees will manage their processes and at the same time comply with rigorous environmental regulations. They constitute minimum expectations which employees are expected to follow. Environmental policies that are clearly written and thoroughly implemented will help to minimize potential environmental incidents, provide clear guidance to personnel on tackling complex environmental issues, and reduce incidents that may result in liability and enforcement. Companies should periodically review and update these policies to ensure that they incorporate new regulations and maintain alignment with the company’s values. Environmental policies should also include a company’s stewardship efforts, such as reducing waste, reducing water consumption, preventing pollution, and protecting biodiversity.

Empowering Teams

Open communication serves as a stepping stone to building a positive environmental culture. Team members closest to equipment or processes can sometimes provide insight necessary to achieve significant improvements. Ensuring that each team member feels empowered to do the right thing is vital. This requires each employee to take personal responsibility for compliance and to intervene in any situation that might be unsafe or potentially noncompliant. This also requires the company to provide each employee with the appropriate training and organizational support to complete their tasks safely and accurately. Having a proactive environmental culture allows team members to take ownership and understand their critical role in the organization’s compliance. Making sure that their voices are heard and that they are part of environmental decision making is imperative. Environmental culture surveys are one way to obtain their input. Survey results can indicate much needed improvements such as training, corporate oversight, and additional resources. The survey results help identify deficiencies and appropriate corrective actions that may be necessary to fully implement a company’s policies and procedures.

Understanding Environmental Requirements

There is a correlation between competency and environmental violations. When companies are cited for enforcement, it is often attributed to a lack of understanding of environmental rules and regulations. Most employees and companies want to do the right thing. However, lack of training, misunderstanding of permit conditions, or ambiguous environmental regulations can lead to compliance failures. It is critical that every company has a comprehensive environmental training matrix that outlines all training required by permits, plans, license, and any process knowledge that is necessary for compliance. The matrix should include training frequency and list job functions that would be subject to this training. When a site receives a new permit/plan or makes a process change that could affect compliance, it is imperative to retrain employees to ensure that any new requirements are captured. Good compliance management systems also manage change well. Training not only builds competency in employees, it also increases morale. Employees feel more confident about doing their job when they understand applicable environmental requirements. Employee confidence and competence can also minimize operator errors and prevent regulatory violations.

Jason Eichenberger

Jim Palmer

On April 17, 2015, the Environmental Protection Agency (EPA) issued the final version of the federal Coal Combustion Residual Rule (CCR Rule) to regulate the disposal of coal combustion residual (CCR) materials generated at coal-fired units. EPA also released the final version of the federal Effluent Limitations Guidelines and Standards (ELG Rule) on Nov. 3, 2015 to eliminate the discharge of bottom ash and fly ash transport water and place stringent limits on the discharge of flue gas desulfurization (FGD) wastewater. Over the last year, the power industry has been focused on planning and/or implementing ash handling conversions and FGD wastewater treatment systems and rightly so; however, the most challenging compliance projects will likely involve managing large volumes of plant stormwater following any ash pond closures required by the CCR Rule.

Typical power plant discharges are comprised of many streams. These categories, and average percentages of overall plant discharges, are summarized in the figure on this page. As you can see, a large portion of the total discharge is not currently regulated by ELG; however, many of the other flows are starting to be tightly regulated at the state level. Some state implemented metal limits imposed on general plant drains and stormwater outfalls in recently issued permits include mercury, aluminum, zinc, along with many others. These new limits can have significant compliance risk since the water quality in these streams can be impacted by relatively simple site activities.

Outage flows associated with plant wash down events and peak runoff from heavy storm events are the primary drivers that must be investigated when sizing a treatment system for these non-ELG regulated flows. Historically, this has not been an issue for plants that have large ash ponds. These ponds have been the heart of a plant water balance, and have provided both surge capacity and equalization of water quality for many years. Not only that, but ash sluice flows also provide a great deal of relatively clean water that has comingled with these other streams in the past. With ash sluicing flows being removed from the water balance and ash ponds closing across the country, utilities can expect much more fluctuation in their discharge water quality and flow rate. Some plants will have enough real estate to construct a new pond-based treatment system for these flows or potentially repurpose portions of their ash pond systems; however, many others are going to need alternatives that minimize footprint requirements while still accommodating large peak volumes of water.

Several tank-based solutions have been designed for treatment of these flows. Some use high-rate clarifiers and polishing filter systems, while others use concrete tanks with polymer feeds to remove solids prior to combining with other outfalls. These solutions can cost 50 percent to 80 percent more than a pond-based alternative for a given flow rate; however, they require only 15 percent to 30 percent of the site footprint and can potentially be provided with manufacturer performance guarantees as well. Site specific flow rates must be determined prior to sizing these systems. When performing water balance updates for ELG compliance, plants should be taking every opportunity to measure their outage flow rates and runoff from storm events. Site specific hydrographs can help minimize some of the conservatism in typical hydrology calculations, thus limiting the total installed cost of a stormwater treatment solution.

As the EPA, and consequently the power industry, begins to focus on limiting discharges or converting to zero discharge alternatives, it will become even more critical for utilities to understand the big picture of their overall water balances. Minimizing flows will increase concentrations for many of the constituents of concern and will complicate the water treatment systems, but reducing volume will likely save a much larger portion of the cost in the long term.