In a major step toward the deployment of the next generation of advanced nuclear technology, NuScale Power asked the U.S. Nuclear Regulatory Commission (NRC) on Dec 31, 2016, to approve the company’s small modular reactor (SMR) commercial power plant design.

This is the first-ever SMR design certification application to be submitted to the NRC and marks a significant milestone for NuScale and the power generation industry. NuScale SMR’s will supply affordable, clean, reliable power in scalable plants whose facility output can be incrementally increased depending on demand. Its significant operational flexibility is also complementary to other zero-carbon sources like wind and solar.

Once approved, global demand for NuScale plants will create thousands of jobs during manufacturing, construction and operation, and reestablish U.S. global leadership in nuclear technology, paving the way for U.S. NRC approval and subsequent deployment of other advanced nuclear technologies.

NuScale CEO John Hopkins said, “The world’s demand for electricity and clean water will increase significantly over the next several decades. Our technology can meet that challenge with clean and reliable power, improving the environment and the quality of life for humankind.”

NuScale’s application consisted of nearly 12,000 pages of technical information. The NRC is expected to take the next two months to determine if any additional information is required prior to commencing their review. Thereafter, the NRC has targeted completing the certification process within 40 months.

“We reached this tremendous milestone through the efforts of more than 800 people over eight years,” said NuScale COO and CNO Dale Atkinson. “We have documented, in extensive detail, the design conceived by Dr. Jose Reyes more than a decade ago. We are confident that we have submitted a comprehensive and quality application, and we look forward to working with the NRC during its review.”

The application delivery was commemorated January 12th, 2017 at NRC headquarters, in the Washington suburbs, by NuScale Chief Executive Officer John Hopkins, Co-founder and Chief Technology Officer Dr. Jose Reyes, Chief Nuclear Officer Dale Atkinson, and Vice President Regulatory Affairs Tom Bergman, hand delivering DVD’s containing the application.

The first commercial 12-module NuScale power plant is planned to be built on the site of the Idaho National Laboratory. It will be owned by the Utah Associated Municipal Power Systems (UAMPS) and run by an experienced nuclear operator, Energy Northwest. UAMPS CEO Doug Hunter stated, “We are delighted that our friends at NuScale have completed this step, which is key to our project licensing and our target commercial operation date of 2026 for the UAMPS Carbon Free Power Project.”

As U.S. Department of Energy (DOE) Secretary Ernest Moniz has previously said, “Small modular reactors represent a new generation of safe, reliable, low-carbon nuclear energy technology and provide a strong opportunity for America to lead this emerging global industry.” As the sole winner of the second round of the DOE’s competitively-bid cost-sharing program for SMR technology development, NuScale is the only SMR developer currently receiving DOE financial support.

“Without the leadership, vision and support of the U.S. DOE, our technology design, development, testing and license application could not have proceeded to this point,” said Dr. Reyes. Conservative estimates predict approximately 55-75 GW of global electricity will come from SMRs by 2035, equivalent to over 1,000 NuScale Power Modules.

Steve Kuczynski, CEO of Southern Nuclear and Chairman of the Nuclear Energy Institute’s New Plant Advisory Committee, said “At Southern Company, we are building the first new-generation nuclear plants in the United States. We are committed to nuclear energy and we want to have NuScale SMR’s as an option. We have worked with them for many years and look forward to the NRC certification.”

Combined heat and power (CHP) projects promise many benefits to a wide array of large energy users, and CHP has a long history of adoption and success in many industries. Despite its wide adoption, many energy users considering the development and installation of a CHP project face a set of tasks and challenges that they are not always fully equipped to handle since their primary business is usually quite different from power and thermal energy production.

By focusing on best practices from the start of project development, to execution, and on to long term operation and maintenance, new owners of CHP systems can mitigate risks and maximize the chances of success for their project.

There are a number of good reasons to implement CHP technologies, but the first and

foremost driver for these systems in an industrial or commercial business setting is to earn a compensatory return on investment that is comparable to other long term capital investments being made in the business. Secondary benefits can include improving environmental performance through dramatic increases in efficiency, improving reliability or providing back up generation at site, and managing long term energy risks more effectively.

Successful CHP projects are built on strong technical and economic foundations as represented in Figure 1.

The Spiritwood Station, a CHP plant in North Dakota, began commercial production in November 2014. Photo courtesy: Great River Energy

All of these factors are important, and all of them must be present to achieve a successful project. Weakness in even one area can rule out an otherwise promising project, so it is important to investigate, develop, and mitigate risks in all of these areas during the development process.

Building Blocks for CHP Projects -1

Taking them in turn, having your facility in an environment that promises good long term energy economics for CHP is the start of a good project. Higher electric rates (taking into account the entire rate structure and rules) generally predict a good opportunity for CHP. A detailed rate analysis and study of the rules for interconnecting CHP systems to the utility needs to be performed early in the development cycle to identify utility costs and charges that will be imposed when the CHP system is installed and operational. Other elements of a strong economic foundation include opportunities to credit capital replacements that the CHP system can avoid. For example, an aging boiler may have only two (2) years of remaining useful life, which the CHP system can effectively replace, creating a meaningful benefit in the cash flow analysis of the project. Lastly, many utilities and jurisdictions have incentive programs for qualifying CHP technologies and projects which can offset capital costs and make projects more attractive.

Another important consideration is to understand that by implementing a CHP system, you will effectively be taking a long term position in the energy market – usually the natural gas and electricity market. CHP systems typically increase the natural gas consumption and reduce the electricity consumption at the respective facility meters, transferring some of the facility’s energy price risk from the power market to the gas market. This can potentially be a benefit to the facility by opening up additional risk management options, such as hedges, which can secure longer term price stability. In any event, part of the project economic analysis needs to account for the market risks that come with the CHP operation.

A long term investment horizon is generally needed when considering a CHP investment. CHP systems are durable assets that typically have twenty (20) year useful lives (or longer) when properly maintained. This is different than many energy efficiency projects, and should be judged on an appropriate basis that is more akin to production expansions and facility improvements. It is also important that facility management have realistic and reasonable expectations for return on investments from CHP systems. They can be among the most attractive investments available to any industrial or commercial energy user, but often get lumped with energy efficiency proposals that have very fast payback thresholds which can rule out otherwise attractive projects.

CHP Project Models -2

A CHP system is a production system which provides electricity and thermal energy to the industrial or commercial loads of the facility. It makes sense, therefore, to find applications to “sell” as much output as is possible from a system. This requires host facilities which have high, durable, and predictable electric and thermal loads for most of the year. The best CHP projects will earn the highest returns when they run around the clock at full electrical and thermal output.

The last foundational element of good project development is selecting the best fit technology. There are a wide range of possible technologies for CHP applications, and each provides a range of cost, performance, and operational considerations. Early stage project development should sort these options against the facility energy and economic profiles to narrow the selections to a manageable number. A more detailed comparative analysis can then be run.

When considering technical options for the project, the following considerations could be important to keep in mind:

• Output and system sizing – specifying the largest system technically possible may not provide the highest return on investment. Modular systems with multiple prime movers can sometimes offer advantages to best match facility loads and provide redundancy and improved reliability.
• Heat rate – since useful heat will be an output of the CHP system, the highest efficiency equipment may not be necessary and in fact may penalize the project with higher costs and lower value.
• Load following – a properly sized system should run at full output most of the time, so ramping and load following capability may not be the most important characteristic of the equipment selection.
• Grid isolated operation – designing an onsite generation system to operate in an islanded mode can add value to the project, but brings complexity and cost, and may not be utilized that often.

Well management project development is completed in phases, which invests in engineering, permitting, and other development activities in a proportionate way as the benefits of the project become clearer and better defined. The following are some basic milestones and activities which can guide a more detailed development plan:

First Look

• Factored cost estimates
• Basic system sizing assumptions
• Basic system operating profiles
• Preliminary annual energy savings and operating costs

Feasibility Study

• Budgetary cost estimates
• Hourly facility load profiles
• Basic design and siting decisions, including system sizing
• Main equipment selection
• Hourly energy and financial model with all rate information

Financial Investment Decision (FID)

• Detailed design basis with FEED
• Engineering based cost estimates with uncertainty analysis
• Hourly energy and financial model with time of use rates
• Energy price forecasts
• ROI risk analysis

As a project matures in the development process, it is important to continuously analyze project uncertainties and risks. To this end, a probabilistic analysis can be beneficial, which characterizes the uncertainties of key input variables based on historical or market-based data, and forecasts return on investment under thousands of simulated scenarios through a Monte Carlo analysis. This can help a project team present the result as a probability in the form of a statement such as, “This project has an X% chance of earning a Y% internal rate of return or better.” In this way, management can judge the risks and certainty of a proposed project in a much more informed way than static models with fixed assumptions can provide.

A variety of project execution models exist as well when the time comes for detailed engineering, procurement, and construction. The following represent just three common arrangements, with many other combinations and approaches also being possible.

Each approach offers advantages and disadvantages, along with risks to the owner.

Considerations for selecting an execution approach can include:

• How much internal staff an owner has to support project execution
• How much risk an owner is willing to take directly on equipment performance and construction
• Recognition that owners can transfer only so much risk to a turnkey EPC contractor – much of the risk in a project comes in the form of imperfect design basis information or other issues outside the control of the contractor, which creates residual risk for the owner in any event

• Collaborative approaches, such as using an open book EPC development and pricing process, followed by a closed book execution, can result in high quality projects and more predictable costs

When it comes time to present a project to management for funding approval, there are a number of important factors to take into account. The most fundamental is to understand the financial metric, such as a return on investment hurdle rate, that the project will need to meet for approval. CHP projects are by their nature long lived assets which add long term value to facilities when they are implemented and maintained properly. They should therefore be judged on par with other long term, facility expansion capital projects.

One special case that often arises in commercial and industrial CHP projects is a third party design-build-own-operate-maintain (DBOOM) structure. This often sounds like an attractive deal, especially to facility teams who believe it can be a source of financing outside of the internal capital approval process. However, these structures bring complexity and risk, and sometimes cannot achieve the financial result that owners are seeking – namely off-balance-sheet treatment of the investment. There are cases where DBOOM structures are a good fit, but it is important to analyze a project’s components separately with regard to design, construction, financing, operation and maintenance. It is possible to achieve goals of outsourcing operation and maintenance responsibility without bundling it with the financing and EPC of the project.

Finally, the value of a CHP project will only be realized if a well-designed, comprehensive Enterprise Asset Management plan is implemented for this type of asset. Many facilities will not have managed a power generation plant previously, so maintenance procedures, data collection, computerized maintenance management systems (CMMS), reliability procedures, and safety procedures will all need to be designed and implemented for the plant. Starting early and getting expert input to these aspects of a plant will yield long term benefits.

CHP projects can deliver significant value for facilities that choose to develop and implement them. By following best practices for the development, design, construction, and asset management of CHP systems, a higher quality, lower risk result is more likely to be achieved.

Author

Thomas G. Adams is vice president of Power Business Development for ABS Group.

By Muhammad Saqib Riaz, Ph.D.

A steam turbine is designed and optimized for a specific set of steam conditions. After long term operations either the steam path components deteriorate or due to changes in steam conditions, a re-optimization of the steam path components is required to regain higher turbine performance. Steam Turbine retrofits are performed to achieve various goals such as improved turbine efficiencies, heat rate or power output. Retrofits are also performed to address turbine reliability and or maintenance issues. Availability of newer technologies and materials for steam path components can be utilized to not only increase steam turbine performance, but also to extend maintenance intervals, and extend life. Retrofits can also accommodate required changes to the thermal cycle based on emerging needs of the power plant. The effectiveness of the retrofit is achieved by utilizing the best available technologies configured to the plant’s specific needs.

Common Steam Turbine Fleet Issues

Steam turbines face challenges that are either associated with turbine deterioration or due to original design limitations. Often times certain modes of operation can lead to reduction in turbine component life. Below sections discuss some of the common issues observed in the steam turbine after long term operation.

Typical High Pressure Steam Turbine Issues:

Based on the steam conditions, each section of a steam turbine faces different challenges. High pressure (HP) section of the steam turbine is exposed to highest pressure and temperature condition. Any deterioration in HP section results in highest loss in the steam turbine performance compared to other sections. Due to higher pressure, tighter clearances are required to reduce steam leakage. A common issue observed in older units is inner casing and blade ring distortion that leads to rubbing of components that open up clearances and increase leakages. At the HP steam inlet, failure of the Bell Seal Ring and welded joint failure at the nozzle chamber have been observed on multiple units. Many units have steam turn-around in the steam paths that result in loss of steam pressure without doing any useful work. Bolt cracking due to material or high thermal conditions is also observed in multiple units. Older rotating blades and vanes mostly had cylindrical airfoils providing much lower level of performance.

Typical Low and Intermediate Pressure Steam Turbine Issues

By the time steam reaches intermediate pressure section (IP), the pressure is dropped but due to reheating of steam, the temperature can be as high as 1000 – 1150°F. In the low pressure (LP) section both temperature and pressures are lower compared to other sections of the steam turbine.

The challenges observed in these sections are somewhat different compared to HP sections. Casing distortion issues still exist in the IP section due to high temperature observed by the steam path components. Older rotors have center bore and shrunk-on discs in the LP section that reduce rotor reliability and also contributes towards shaft vibrations. Similar to HP section, the rotating blades and vanes mostly had cylindrical airfoils providing much lower level of performance. Typically older LP section blades are grouped blades with tennons that generally have reliability and maintenance issues.

Advances in Steam Turbine Technologies:

To improve competitiveness, every original equipment manufacturer (OEM) develops newer and improved technologies to address issues identified in above sections. These newer technologies focus on improving performance along with reliability and maintainability of the product.

One of the most common improvements provided in a retrofit design is the upgrade of existing blades with three dimensions blade vanes that are bowed and twisted to reduce secondary losses in the steam path. Shrouds are made integral to the blades to improve reliability of the blades. Roots with generous radiuses are designed to reduce local stress. Advanced computational fluid dynamics (CFD) tools are used to study the flow characteristics to ensure losses are minimized. Multiple rows of blades are modeled in these analyses to understand interaction between different stages of rotating and stationary blades. Unsteady CFD analyses are performed to study flow behavior at various operational conditions and blade profiles are optimized to reduce losses.

Validation is a key part of the design cycle. Mitsubishi Hitachi uses a test rig, where all newly designed blade profiles are tested. Extensive instrumentation is applied in the steam path to collect pressure and temperature data that is used to calculate blade efficiency, pressure distribution etc. These results are then compared with design calculated parameters for validation purposes.

In the design of the steam turbine, the goal is to extract maximum amount of energy from the steam before the steam enters into the condenser. As the steam reaches towards the end of the LP section, the pressure of the steam is much lower resulting in large volumetric flow. At this stage longer blades are required to handle the large volumetric flow to reduce exhaust losses. Longer blades are designed to achieve higher turbine performance and cost reduction. With longer last stage blades, a 4 flow LP section performance can be achieved with a 2 flow LP section. Mitsubishi Hitachi being a world leader in steam turbines has one of the largest offerings of last stage blade designs for various application ranges.

Common Features Applied on New Generation of Last Stage Blades – 1

Last stage blades are one of the most important and complex part of the steam turbine that produces more than 10% of the total turbine output, and demand high reliability design under complex loading. New generations of last stage blades are designed as one piece with shroud as integral part of the blade. These integral shrouded blades (ISB) not only makes assembly easier but also provide higher levels of damping compared to conventional grouped blades. At the time of assembly, ISBs have some gap at the shroud and snubber connections but with increasing speed, the gap closes and entire row of blades acts as one continuous coupled structure. With continuous coupling it is much easier to control synchronous and non-synchronous vibrational characteristics of the row of the blades. To improve fatigue life of the blades, the tennons are removed to reduce stress concentrations and larger roots with generous fillet radiuses are applied to reduce local stresses to prevent stress corrosion cracking (SCC). Figure 1 shows some of the common features applied on latest last stage blades.

During the development of last stage blades, significant resources are used to ensure the robustness of the design. For design validation, full scale blades are manufactured and assembled on a test rotor that is especially manufactured for the new blades. This assembled rotor is then rotated with the help of an electric motor in a vacuum chamber to study vibrational characteristics of the blades. To excite various vibration modes, air excitation is used that is provided via nozzles located at different radial positions of the blades. A Campbell diagram is generated from the strain gage data that are installed on the blades to understand the vibratory response.

To study the blades behavior in steam environment, Mitsubishi Hitachi uses their Steam Turbine Load Test facility located in Takasago, Japan. The last three or four stages of the LP section are manufactured in full scale and assembled on a test rotor. The entire steam path is instrumented heavily with pressure, temperature and strain gages. Pressure transducers are traversed along the length of the blade to capture pressure profile. The data obtained from this test is used to validate CFD and other design calculations. Mitsubishi Hitachi’s steam load testing facility is the largest testing facility in the world in terms of steam flow rate. The testing is performed at a wide range of condenser vacuums and steam flows to study blade behavior at extreme operating conditions. For low load operation, a drive turbine is used to operate the turbine.

The next level of design validation is performed at an in-house power plant located at Mitsubishi Hitachi’s Takasago factory. This combined cycle power block consists of a gas turbine, steam turbine, HRSG and an air cooled condenser. New technologies such as last stage blades, seals, and coatings developed are applied in the steam turbine for long term reliability and performance testing. The steam turbine is heavily instrumented to collect turbine data throughout the unit. This facility helps design engineers understand the long term deterioration modes of the steam turbine components. Mitsubishi is the only company in the world to have such a type of test facility. Figure 2 provides an aerial view of the power plant and images of the steam turbine.

Mitsubishi Hitachi In-house Combined Cycle Power Plant – 2

In some cases, to push design validation to next level, validation testing is also performed at the customer turbine site. This type of testing can range from torsional testing of the entire rotor train to last stage blade testing to study blade behavior at certain operating conditions. Relevant components are instrumented to collect desired data that is later compared with design calculations for validation purposes.

Advanced Sealing Technologies:

Turbine performance is greatly impacted by steam leakages. Any steam that is not passing through the steam path is a loss. In high pressure turbine sections, steam leakage is more crucial as any small clearance opening will result in much larger amount of leakage than in the lower pressure sections of the turbine.

The following section describes seals developed by Mitsubishi Hitachi for application in various sections of the steam turbine which are shown in Figure 3.

Active Clearance Control (ACC) Seals:

ACC seals have been in use for more than a decade with remarkable results. Conventional spring back seals are assembled with a fixed, generally larger clearance. In case of ACC seals, at the time of startups and shutdown, the clearances are larger to ensure no rubbing during transient events, but during steady state operation the clearances are reduced by the steam pressure applied at the seal rings. This ensures small clearances during steady state operation to reduce leakages and maximize performance.

Leaf Seals:

The non-contact nature of leaf seals provides long term performance sustainability. A stack of thin leaf plates are housed in a casing which is accompanied by additional labyrinth seal teeth. At the time when rotor is stationary, the leafs touch the rotor but as the rotor starts to rotate, due to hydrodynamic force, the leaves lift upward leaving a very small clearance between rotor and leaf seal making it a none contact seal. The wider geometry of the leaf seals provide higher axial stiffness and can be applied at locations of higher differential pressures. Long term operation has shown negligible wear on the leaf seal and on the rotor.

Abradable Seals:

Abradable seals have a layer of softer abradable material applied on the packing rings with sealing tooth on the rotor. On conventional seals, in the event of rubbing, the seal tooth wears down due to rubbing with hard rotor material. This results in larger clearances for long period of time until the seals are replaced. For abradable seals, in case of rubs, the seal tooth does not wear rather it wears the abradable material. The sharp seal teeth keeps steam leakage low and help sustain performance for longer periods of time.

Guardian Packing & Vortex Shedder® Seals:

Guardian seals have guardian posts made out of low friction wear resistance material. In case of a rub event, the guardian posts come in contact with the rotor, while remaining seal teeth that have slightly larger clearance are protected.

Vortex shedder seals have dimple like features on the seal fins. These dimples generate flow vortices that provide resistance to the path of leaking steam thereby reducing leakage.

Types of Steam Turbine Retrofits:

Retrofits on a steam turbine are performed to achieve different goals. Based on the requirements from the customer, the scope of the retrofit can vary significantly. The below list provides a few high level retrofit classifications:

• Small modification to the unit to achieve specific turbine operation conditions. This may involve changing one or more rows of blades.
• Entire steam path upgrade along with new inter-stage packing seals (with or without rotor replacement)
• Steam path upgrade with new bladed rotor along with new seals and new inner casing (if applicable)
• Entire turbine section replacement.

The benefits of the above retrofit scopes can be greatly increased through the application of new technology components.

Different Sealing Technologies Applied to Reduce Steam Leakages- 3

Retrofit Case Studies:

The following retrofit examples show different levels of modifications performed in each case.

Retrofit Case 1: HP /IP Steam Path Retrofit

In this case an old HP/IP steam path was replaced with an upgraded steam path. A new mono-block rotor was applied along with latest technology integral shrouded blades to improve performance and reliability of HP and IP sections. At the main steam inlet, the Bell Seal Ring configuration was converted to stack ring inlet design to improve reliability and reduce leakages. To reduce inner casing distortion, a thermal shield was applied at the inlet of the IP section. Seals were improved throughout the steam path with application of ACC and leaf seals where applicable. The steam path was optimized to swallow larger amount of the steam as more steam was available for power generation. The outer casing of the turbine was reused and the upgrade was designed to fit within the existing outer casing. The project surpassed the guaranteed efficiencies with around 4.4% improvement in HP efficiency and around 7% increase in IP efficiency beyond degradation recovery. Figure 4 provide a schematic of the steam path after upgrade.

Retrofit Case 2: LP Steam Path Retrofit

This case study is related to the retrofit applied to the LP section of the steam turbine. A boreless new rotor with high efficiency ISB blades was provided as part of the retrofit. LP end blades were replaced from grouped blades to longer integral shrouded blades that provided larger annulus area to reduce exhaust losses. The exhaust flow guide for the last stage blade was redesigned to guide steam smoothly out of the LP section. Similarly the inlet throat area was redesigned to ensure a smooth transition of steam to the first stage in LP Section. The inner casing was optimized to accommodate longer last stage blades. As a result of this upgrade, the LP section was able to achieve more than 10% higher efficiency including degradation recovery.

Case study 3: Industrial Steam Turbine Retrofit

Industrial steam turbines are used not only for power production but they are also commonly used to supply process steam. Due to multiple functions of the industrial units, the changes required in the turbine over the life span of the unit are more common. In many cases the need for the process steam changes over time or the economics of the plant operation does not allow certain modes of operation.

All these scenarios can be addressed during retrofit opportunities.

HP/IP Steam Path Retrofit – 4

In this case study, new steam conditions drove to the optimization of the steam path.

The need for extraction steam was also changed and the goal of the retrofit was to close one existing extraction and add one extraction that has new pressure and flow requirements. During the retrofit, the main objective of the customer was to minimize the number of modifications while maximizing the unit power output. As a result of this effort, multiple options with varying impact and complexities were provided to the customer to select the option that best matched their needs.

HP/IP and LP Section Replacement Retrofit Project – 5

Case study 4: HP/IP or LP Section Replacement

In this type of retrofit, the entire section of the steam turbine is replaced. This provides maximum flexibility to the design engineers to achieve retrofit goals due to reduced constraints associated with retained components. In such types of retrofits the main constraint is to fit the new outer casing within existing bearing span. The steam path can be optimized to achieve higher level of performance by adjusting blade path base diameters, applying latest technology ISB blades, best possible sealing combinations etc. Casing distortion and cracking issues are addressed by redesigning the casing and with the application of thermal shields. Welded rotor (HP Section) and mono-block boreless rotor with 12% chrome material (LP Section) are applied. New inner and outer casings allowed flexibility to put larger last stage blades. Inlet and exhaust steam flow path were designed using state-of-the-art CFD programs by making 3D models of relevant sections. This helped in reduction of losses in the steam path resulting in higher turbine section performance approaching that of new units. Figure 5 provides an image of an HP/IP and LP section retrofit project showing improvements applied in the steam turbine.

Conclusion:

Steam turbine retrofits are performed to achieve higher performance and improved heat rate coupled with improved reliability and maintainability.

Changes in thermal cycle can be accommodated along with addressing the customer’s operational issues. Newer technologies and material can be applied to improve both turbine performance and component life. The scope of the retrofit project can vary significantly based on the needs and requirements of the customer from modifying several stages and extractions, to complete section replacements.

Author

Muhammad Saqib Riaz is manager of Steam Turbine Engineering at Mitsubishi Hitachi Power Systems Americas in Orlando, Florida.

Aerial view of a coal combustion residual (CCR) site. Photo Courtesy: EPRI

Coal combustion residual (CCRs) have historically been managed either in ponds (wet storage) or landfills (dry storage). Management in ponds is particularly prevalent in the eastern U.S., where ponds ranging in size from ten aces to several hundred acres have been in operation for decades. In 2015 the US Environmental Protection Agency (EPA) promulgated regulations that established requirements for disposal of CCR.

While the CCR Rule does not explicitly prohibit CCR management in ponds, the strict requirements for ponds, along with the subsequent passage of the Effluent Limitation Guidelines for Steam Electric Plants and the retirement of many older coal-fired power plants, combined to produce essentially the same effect, greatly accelerating pond closures.

EPA did not have permitting and enforcement authority under the CCR Rule, but instead relied on citizen lawsuits. In 2016, federal legislation was passed that provided states authority for implementation of the rule. This change clarified actions for most power companies, which were facing dual and sometimes conflicting regulatory requirements at the state and federal level. However, this is not expected to change the ultimate transition from wet to dry management of CCRs, and the attendant closure of many CCR ponds over the next 5 to 15 years. The remainder of this article discusses closure implementation under the federal CCR Rule (Part 257.100 – 257.104) for ponds containing CCRs derived from bituminous coal-fired plants. State implementation requirements must be as least as protective as the federal criteria.

Assessing the Options

The CCR Rule provides two basic closure options: closure in place (CIP) and closure by removal (CBR). CIP is typically simpler and less costly than CBR, and has been the alternative of choice in the past. CBR might be considered when consolidating CCR from smaller ponds into one location, or if leaving the pond in place would have a significant long-term impact on groundwater and surface water.

With CIP, a cap composed of compacted clay and often a geomembrane, is placed over the former impoundment to limit the amount of infiltration from precipitation or snow melt into the CCR. In some cases, the footprint of the facility may be consolidated prior to capping to 1) remove CCR from undesirable areas, for example immediately adjacent to water bodies, 2) provide material to build up appropriate slope to assure runoff from the cap, and/or 3) reduce the overall CCR management footprint.

With CBR, all of the CCR is excavated and taken to a lined landfill for disposal or to a beneficial use location. The landfill may be on site or off site; off-site facilities may be owned by the power company or by a third party. CBR to on-site landfills will typically have lower cost and lower impact to the surrounding community than CBR to off-site landfills, but on-site landfills are only possible if there is suitable space on the property.

While the cost of CIP is significantly less than CBR in most cases, choosing the most appropriate option for a site also depends on other factors, including but not limited to:

• Environmental Impacts/Benefits
• Community Impacts
• Time to Completion
• Sustainability Metrics

Integrating these factors with economic considerations and overall company management strategy can be a complex task.

A Decision Framework to Evaluate Closure Options

Given competing advantages and disadvantages between CIP and CBR, use of a scientific, quantifiable decision framework that considers beneficial and adverse impacts over multiple environmental and community pathways can aid evaluation of the two alternatives. Environmental pathways where the relative impact of CIP and CBR on chemical concentrations can be predicted and quantified include groundwater, surface water, and air. Quantifiable community impacts include inhalation of particulate matter generated during construction and material transport, construction worker safety, community safety as a result of increased truck traffic to and from the site, and green & sustainable remediation (GSR) measures such as energy use, greenhouse gas emissions, and raw material consumption.

Because of the multifaceted nature of these variables, a decision framework cannot provide an absolute determination on the best approach, rather, it provides a relative comparison of each variable to support an overall decision. Figure 1 provides an example of such a tool to evaluate the impacts (beneficial or adverse) of the two options, and the relative difference in impact between the closure options for each pathway.

Closure Options – 1

Example decision tool summary comparing relative impacts of closure in place (CIP) and closure by removal (CBR) for a hypothetical site.

Results of applying this framework will vary depending on site-specific variables, such as site size, hydrogeology, landfill availability, and proximity of the community. However, some generalizations can be drawn based on experience derived from using the decision tool:

• Groundwater and Surface Water Quality: If groundwater or surface water quality was impacted by a facility prior to closure, CIP and CBR will have beneficial impacts; they are both effective if the base of CCR is above the water table and there are no lateral flows into the facility (non-intersecting groundwater table). CIP is generally less effective than CBR if there is a continuing source of groundwater flow through the CCR after capping (intersecting groundwater table). Because surface water impacts at closed facilities are derived from groundwater, the same relationship holds
• Air Quality, GSR, Worker Safety, and Community Safety: CBR is generally expected to have greater adverse impacts on these pathways than CIP because the CBR construction project is larger scale for longer duration, generates more truck traffic, and uses more energy than CIP.

The Tennessee Valley Authority (TVA) used this decision tool to support its environmental impact statements for closure of ten CCR surface impoundments.

Groundwater Monitoring under the CCR Rule – 2

The evaluations indicated that CBR would have greater adverse impact than CIP on air, safety, and GSR measures for nine of the ten impoundments (one impoundment could not be evaluated), while the relative beneficial impacts of CIP and CBR on groundwater and surface water quality were site-specific and variable. This comprehensive evaluation was factored into TVA’s overall determination that CIP was the preferred closure option for the ten impoundments.

The rest of this article focuses on methods for closure in place.

Closing in Place

The CCR Rule contains general requirements for closure and cap design. However, closing CCR ponds is more complex than typical landfills. Ponds can vary significantly in many aspects and each closure requires careful attention to site-specific attributes that can impact the final design, such as: type of pond (e.g., valley fill vs. raised berm), pond size and percent filled, geotechnical characteristics of CCRs and surrounding containment structures, water management, post-closure stability and land use, proximity to surrounding communities, existing groundwater impacts, and equipment and material availability.

The final closure design and completion schedule can vary considerably according to the complexities introduced by these factors; closure of some large ponds could take as long as 5 to 15 years.

Site Investigation and Engineering Design

Some decades old ponds may not have complete information regarding pond dimensions, geotechnical characteristics of the ponded CCRs and berm materials, and surrounding hydrogeology. This information is needed to ensure pond stability during and after closure, as well as to identify and mitigate any actual or potential environmental releases.

Typical geotechnical investigations inside the pond include obtaining data on CCR stratigraphy, grain size, Atterberg limits, undisturbed samples for consolidation and strength testing, porewater pressures, hydraulic conductivity, and in situ testing using cone penetrometer equipment and piezometers. Hydrogeologic information includes stratigraphy, groundwater levels, groundwater quality, and aquifer characteristics. If groundwater quality impacts are documented, corrective actions can be built into the closure design.

Adaptation of Potential Failure Mode Analysis (PFMA) has been used to aid in the identification of potential problem areas that need to be addressed prior to closure. The PFMA process was developed by the Federal Energy Regulatory Commission for hydropower dams as a risk reduction tool. PFMA is not required for CCR ponds but can be used to facilitate a more focused site investigation and risk mitigation program.

Pond Dewatering and Surface Stabilization

The CCR Rule requires removal of free water by drainage or solidification, and stabilization sufficient to support the cap. Free standing water is typically removed via gravity drainage (decanting) or pumping, at rates that avoid excessive entrainment of suspended solids, and do not cause instability of the CCR, which can threaten the structural integrity of interior dikes or the perimeter containment system, or cause overtopping due to displacement by the CCR. Discharge of any free water or porewater collected during dewatering may be subject to National Pollutant Discharge Elimination System regulation under the Clean Water Act.

Following removal of free water, the CCRs are typically at or near saturation and have low shear strength. Varying methods of porewater removal and surface stabilization are generally employed to improve the stability of the surficial deposits and their ability to safely support construction equipment. Porewater removal methods include shallow well point systems, enhanced gravity drainage using a network of open trenches or drain tiles, or filtration dewatering with geotextile tubes. Stabilization is usually accomplished by incorporating a bridging or blending layer. A bridging layer (e.g., soil, bottom ash, or high strength geotextile/geogrid) distributes the construction load over a larger area of the soft CCRs, thereby increasing the factor of safety (FS) for bearing capacity. A blending layer (e.g., soils, fly ash, quicklime) serves to lower the CCR moisture content, thereby increasing bearing capacity.

Final Cover System and Post-Closure Care

Operating ponds have a relatively flat surface; consequently they will require some reshaping to achieve suitable grades to shed runoff during the post closure period. Many closure designs use CCR material to achieve final grades, either by redistributing CCR already in the pond, often reducing the pond footprint, or by consolidating CCR from other smaller ponds near the site. If sufficient CCRs are not available, soil is often used to achieve grades. For large sites in particular this can be a significant construction activity, requiring excavating, trucking, and placement of more than a million cubic yards of fill material.

The CCR rule includes the following requirements for the final cover system, intended to minimize infiltration and erosion:

• Permeability less than or equal to the bottom liner or natural subsoils, and in no case greater than 1×10-5 cm/s;
• Minimum 18 inch soil infiltration (barrier) layer;
• Minimum 6 inch soil erosion layer capable of sustaining vegetation;
• Accommodation for settling and subsidence.

The rule does not specify the components of the barrier layer, but the rule preamble suggests that composite barrier layers (compacted clay and a geomembrane) have shown better long-term performance than compacted clay alone. Alternative covers that meet the aforementioned requirements can also be proposed.

The CCR Rule contains requirements for a 30-year post-closure care, including maintenance of the cover and groundwater monitoring. The post-closure care period can extend beyond 30 years if the facility is in assessment monitoring for groundwater impacts (see below).

Emergency Action Plan

The CCR Rule requires operating ponds with high or significant hazard potential ratings to have an Emergency Action Plan (EAP). The hazard potential rating system was developed by the Federal Emergency Management Agency for dam safety, and pertains to the potential adverse consequences of a dam failure, not the probability of a failure occurring. A significant hazard potential indicates potential for economic loss and environmental damage, but no probable loss of human life. A high hazard potential indicates potential for probable loss of life in the event of a failure.

EAPs must contain, among other things, inundation maps that show estimated extent of release from a CCR pond in the event of a failure, to assess the likely downstream impacts. EAPs for conventional dams assume water is impounded behind the dam for estimating the extent of inundation and potentially impacted facilities. Ash ponds impound a mixture of water and saturated fly ash during active operation, which could result in rapid movement of free water and liquefied ash during a release. However, some states also require EAPs for closed CCR ponds, which do not impound free water. EPRI is working with the Army Corp of Engineers Engineer Research and Development Center (ERDC) to develop physical and numerical models to better simulate the dynamics of ash flows from closed ponds in the event of a failure, which will enable improved predictions of the potential extent of inundation as a function of ash saturation.

Groundwater Monitoring

Depending on if and how states implement the CCR Rule, ponds may be required to monitor groundwater under federal and state rules. Since the monitoring requirements of the CCR Rule do not necessarily align with state groundwater monitoring requirements, some facilities may have multiple groundwater monitoring programs using different monitoring wells, different constituent lists, and different sample frequencies.

Establishment of a groundwater monitoring program is site-specific, based on: 1) whether monitoring is performed for the CCR Rule, a state program, or both; 2) the configuration of the site, including proximity to surface water; 3) the proximity of other potential sources of contamination; and 4) site hydrogeology.

All groundwater monitoring programs lead to one of two end points: 1) no release to groundwater is detected in which case groundwater monitoring continues for a specific period, which is usually specified in the governing regulations; or 2) a release to groundwater has been detected, which can trigger additional monitoring and can lead to establishment of a remediation or corrective action program. Figure 2 illustrates the life-cycle for groundwater monitoring under the CCR Rule which has three distinct phases of groundwater monitoring:

• Detection monitoring is the first stage of groundwater monitoring, based on seven indicator constituents sampled in monitoring wells as close to the waste boundary as feasible. If a statistically significant increase (SSI) in concentration relative to background is observed at any one monitoring well for any single constituent, and the SSI cannot be attributed to a source other than the CCR facility, then assessment monitoring is triggered.
• Assessment monitoring expands on the list of constituents, using the same monitoring well system as for detection monitoring. Concentrations for assessment monitoring constituents are compared to a groundwater protection standard (GWPS), which is either the federal maximum contamination level (MCL) or background concentration if background is higher than the MCL or if a constituent does not have a MCL. If any assessment monitoring constituent at any monitoring well has a concentration at a statistically significant level (SSL) relative to the GWPS, and the SSL cannot be attributed to a source other than the CCR unit, then corrective action is triggered. If there are no SSLs for the assessment monitoring constituents, then the facility remains in assessment monitoring until concentrations return to background levels for two consecutive sample events, at which time detection monitoring continues (unless the time is greater than 30 years post closure).
• Corrective action monitoring is performed for constituents with concentrations determined to have SSLs, using monitoring wells installed within the area of corrective action, which are not necessarily the same as the detection/assessment monitoring well system. Assessment monitoring continues during corrective action monitoring. Corrective action continues until concentrations in the corrective action monitoring wells decrease to levels lower than the GWPS for three consecutive years.

Groundwater monitoring continues for the 30-year post-closure care period, assuming that the facility is in the detection monitoring phase. Groundwater monitoring continues indefinitely if the facility is in assessment monitoring.

Summary

CCR pond closures are expected to continue and accelerate over the next decade in response to the recent promulgation of the CCR and ELG rules, along with the decommissioning of many older coal-fired power plants. Pond closures can be quite complex due to the variability among ponds and the unique geotechnical characteristics of wet, fine-grained CCRs. Community and worker safety are of paramount importance in the closure design and construction activities. Detailed knowledge of site-specific engineering and environmental characteristics of the ponded material, containment structures, and hydrogeologic conditions is critical to ensuring a safe closure and long-term performance of the facility.

Longview unit 1 is the most efficient coal-fired plant in the U.S. with a best-in-class heat rate of 8,900 Btu/kWh (9,390 kJ/kWh). Longview’s advanced supercritical boiler, low cost fuel source, and other project efficiencies combine to produce the lowest cost of dispatch of any coal-fired plant in the PJM region. Photo courtesy: Longview Power

The Longview Power plant is the newest coal-fired plant in the 13-state PJM Interconnection. The plant was commissioned in December 2011 following construction by a consortium of Siemens Power Generation Inc. and Aker Kvaerner Songer Inc. As built, the plant had a Foster Wheeler supercritical boiler, a Siemens steam turbine/generator set, and a Siemens distributed control system (DCS).

Soon after commencing commercial operation, the plant started experiencing a number of very serious problems which caused the unit to be offline for long periods of time. Some of the problems were related to material issues with the first-of-a-kind, once-through Benson low mass flux vertical tube advanced supercritical boiler. Other problems were related to inaccurate and unreliable process measurements. Additional problems were related to flawed control logic, hardware issues and software bugs in the plant’s DCS.

The severe operational issues as well as major changes in the power markets lead to Longview Power filing for Chapter 11 bankruptcy protection in 2013. In early 2015, Longview Power reached a settlement of all construction claims and emerged from bankruptcy with a rehabilitation of the unit underway. The plant hired Black & Veatch as the owner’s engineers and overall project managers for the rehabilitation project. As part of the rehabilitation, Foster Wheeler corrected the issues with the boiler and upgraded air quality control system to handle higher sulfur fuel and Siemens completed upgrades and modifications to correct the vibration issues with the turbine generator. Additionally, the plant hired Emerson Process Management to completely replace the original DCS with an Emerson Ovation DCS. In total, Longview Power and its contractors spent $120 million on the rehabilitation project which was completed in November 2015.

Today, Longview unit 1 is one of the most efficient coal-fired plants in the United States with a best-in-class heat rate of 8,900 Btu/kWh (9,390 kJ/kWh). Longview’s advanced supercritical boiler, low cost fuel source, and other project efficiencies combine to produce the lowest cost of dispatch (delivery of electricity) of any coal-fired plant in the PJM region.

Sootblowing History

Prior to the installation of the Powerclean NX system, the plant operated pre-made sequences of sootblowers on specified timing intervals. This mode of operation resulted in the erosion of tubes in some areas of the unit and excessive slag buildup in other areas of the unit. The slag buildup was most pronounced in the platen superheater and finishing superheater as well as on the nose slope. To control the slag buildup, plant operators would periodically drop load to shed the excess slag. The large slag falls resulting from the load drop would damage the lower furnace slopes and submerged flight conveyor. These large slag falls were also responsible for more than one unit trip due to furnace pressure swings.

The plant experienced other issues as a result of their historical sootblowing practices. The unit would exhibit a noticeable swing in operation when the furnace walls would go from heavily loaded to clean after the furnace sootblowers operated. The heavily loaded operation was accompanied by an increase in reheat spray flow which negatively impacted unit heat rate. Additionally, the furnace sootblowing activity caused erosion around the wall sootblowers which required frequent pad welding to repair. The unit would also exhibit swings in operation due to the variation in sootblowing practices between the different operating shifts. As a result of these issues, the plant operations and engineering departments had to constantly observe the growth of the deposits and balance between full load operation, cleaning frequency, and operational stability.

In early 2014, Longview Power hired Babcock & Wilcox (B&W) to evaluate the unit for potential rehabilitation. B&W performed testing of the unit and reviewed all aspects of operations. Along with the other findings and recommendations, B&W recommended employing an intelligent sootblowing system to help improve unit operations and stability by providing better, more consistent heat transfer management.

Unit Description

Longview Unit 1 is a wall-fired, supercritical Foster Wheeler boiler rated at 700 MW net. The unit is a mine-mouth plant and burns run-of-mine, high sulfur bituminous coal. The boiler has platen superheat surface, vertical and horizontal reheat surface, and a parallel back-end arrangement which splits the flue gas between the horizontal reheat and primary superheat sections. Design main steam conditions are 1112°F (600 °C) at 3495 psi (241 bar) while the design reheat steam conditions are 1130 °F (610 °C) at 4192 psi (289 bar). Figure 1 shows a side view of Longview unit 1.

Longview Unit 1 has 52 Diamond Power IR sootblowers for cleaning the furnace walls. The unit has 70 Diamond Power long-retractable IK blowers to clean the tube sections in the convection pass. The unit also has 4 air heater blowers. Steam is used as the sootblowing medium for all blowers. All blowers are controlled by the Diamond Power SentrySeries control system.

Powerclean NX Description

The Powerclean NX system is a performance-based system which uses the actual heat transfer performance of the furnace and each tube bank to direct sootblowing operations. The system integrates with all sootblower control systems including DCS-based systems and is designed for fully automatic operation of the sootblowers. The Powerclean NX system is composed of three major components: a detailed boiler performance model, a robust expert system, and a full-featured queuing system.

Longview Unit 1 Side View – 1

The boiler performance model is based on B&W’s boiler design standards which have been developed from B&W’s extensive experience designing, building, modifying, and testing all types of boilers. The performance model uses measured operational data and the actual design of the boiler to calculate cleanliness factors for each heat transfer section including the furnace. The model also calculates other important measures such as furnace exit gas temperature (FEGT), boiler efficiency, and heat rate.

The output from the performance model as well as plant operational data is sent to the expert system. The Powerclean NX expert system is an easy to use and understand rule-based decision logic system. The expert system allows for the creation of different cleaning strategies for specific areas of the furnace and convection pass. The strategies can not only determine when blowing should be initiated, but also when blowing should stop and when blowing should be paused temporarily.

Once the expert system determines cleaning is needed in an area of the boiler, the sootblowers from that area are sent to the Powerclean NX sootblowing queue for operation. The queue dynamically orders the sootblowers based on a combination of blower effectiveness and time since last operation. The effectiveness of each sootblower is based on historical data and measures how much impact a particular blower has on a target metric. After ordering, the queue operates the blowers until either the queue is empty or the expert system calls for sootblowing operations to cease.

Installation and Configuration

The Longview 1 Powerclean NX system consists of a Windows server computer containing all required software. The server was installed in the control room to allow operators access to the Powerclean NX graphical user interface. The Powerclean NX system retrieves the required operational input data from the plant’s PI historian via an OPC connection to the existing PI-OPC server. The Powerclean NX system communicates with the Diamond Power sootblower control PLC via an OPC connection through the supplied RSLinx software. Figure 2 shows the communications setup at Longview 1.

Longview Connection Diagram – 2

Unit Cleanliness Factors – 3

The Powerclean NX software was configured with ten cleaning regions in the furnace and convection pass. Additionally, the software was configured with a single cleaning region for the air heater. Each cleaning region was configured with its own set of rules in the expert system. The sootblowers in the convection pass region were set up to operate in left/right pairs. The blowers were paired up in this fashion to reduce the risk of upsetting the unit from side-to-side. The software was further configured to allow simultaneous operation of two sootblowers in the furnace, two sootblowers in the convection pass, and two sootblowers in the air heater.

The Powerclean NX system was initially installed in mid-2014, but was not ready for full operation until September 2015 due to instrumentation and plant operational issues. The plant rehabilitation project delayed getting the Powerclean NX system tuned and in full-time automatic operation until mid-January 2016.

Results

Plant operators and engineers have seen a number of benefits and improvements since bringing the Powerclean NX system online. They have not had to drop load to shed slag and have not experienced any large slag falls. The plant hasn’t had a forced outage from furnace pressure swings since operating with the Powerclean NX system. Plant engineers also believe they have seen an overall reduction in sootblower operations even though some areas, such as the nose arch, are being cleaned more frequently. The change in sootblower operations is difficult to quantify because the blowers were operated in large sequences prior to the Powerclean NX system. Plant engineers have seen an improvement in unit stability due to the consistency of sootblowing operations across all loads and operating shifts. Plant operators like the way the Powerclean NX system cleans the unit and rarely operate the blowers manually. Other specific results are discussed in the following sections.

Coal pulverizers at the Longview Power plant, the newest coal-fired plant in the 12-state PJM Interconnection. Photo courtesy: Longview Power

Unit Cleanliness

The cleanliness factors for each of the major heat traps in the boiler are shown in Figure 3. The data shown in the figure is for operation above 770 MW gross. Overall, Figure 3 demonstrates that unit cleanliness is being maintained even though overall sootblower operations have decreased. The decrease in cleanliness of the platen and secondary superheater (SSH) sections from November 2015 through January 2016 was caused by initial Powerclean NX tuning adjustments.

Furnace Exit Gas Temperatures

The gas temperatures exiting the furnace are shown in Figure 4. The data shown in the figure is for operation above 770 MW gross. PIGT is the platen inlet gas temperature and is defined as the exit plane which extends from the nose arch to the front wall of the boiler. FEGT is the furnace exit gas temperature and is defined as the exit plane which extends from the nose arch to the roof of the boiler. The figure compares the average PIGT and FEGT for the period September 2015 through January 2016 (before Powerclean NX was operational) to the averages for the period February 2016 through May 2016 (after Powerclean NX was operational). Both PIGT and FEGT show a slight improvement (lower temperature) with the Powerclean NX system in full operation.

Reheat Spray Flow and Unit Heat Rate

The reheat spray flow and unit heat rates are shown in Figure 5. The data shown in the figure is for operation above 770 MW gross. The reheat spray flow was reduced significantly as a result of the Powerclean NX system. This is because the Powerclean NX system does a better job of managing the heat transfer in the components upstream of the reheater.

Furnace Exit and Platen Inlet Gas Temperatures – 4

Reheat Spray Flow and Unit Heat Rate – 5

The upstream components are absorbing more heat which reduces the burden on the reheater and subsequently reduces the amount of spray required to control the reheat steam temperature.

The reduction in reheat spray flow was accompanied by an improvement (reduction) in unit heat rate as seen in Figure 5.

Conclusion

The Powerclean NX intelligent sootblowing system was installed on Longview unit 1 to help control slag accumulation and improve unit operations and stability. The system was configured to run a real-time, detailed boiler performance model to determine the heat absorption throughout the unit. The system was also configured to control pairs of blowers in seven different cleaning regions. Each cleaning region was configured with its own cleaning strategy using the Powerclean NX expert system. Once in full operation, the Powerclean NX system eliminated the need for periodic load drops, reduced sootblower usage, reduced reheat spray flow, improved unit heat rate, and stabilized unit operations. The Powerclean NX system helps make Longview unit 1 one of the most efficient, low-cost coal-fired plants in the United States.

The power generation project development environment has drawn participants who do not routinely undertake new, large-scale capital projects. While many companies have mature processes for asset development, other smaller entities are allowing aging plants, evolving regulations, and the lure of historically low gas prices to lead them into the unfamiliar territory of new development.

The degree and formality of front-end planning associated with process industry projects is historically more complex than what’s typically used in the power industry. At the core of the discussion, this may be a legitimate issue-that there is an increased level of R&D-type activities associated with process facilities, resulting in increased pro forma analysis and technical validation. With that said, there is evidence improved front-end planning can enhance the opportunity for companies to develop new assets with reduced exposure to cost overruns, delays, and lost shareholder credibility.

It would be unfair to conclude power owner organizations are less conscientious with their capital expenditures than their colleagues in other business sectors. More likely, they are drawn to an industry-accepted culture that informally sets cost and schedule expectations unrealistically. Even seasoned power companies can learn there is no automatic guide for accurate estimating in the early phase of project development and unique project conditions can lay waste to estimates factored off of seemingly identical facilities.

Process industry owners seem better conditioned to accept that there is a level of project definition essential to accurately defining scope and understanding the resultant cost and schedule implications. While it is easier to predicate planning and analysis on extrapolation and factoring, project results have demonstrated there is substantial risk associated with over reliance on historical reference. A contributing factor is that project development teams naturally evolve when the bias of project advocates results in aggressive attempts to force-fit reference material to match current opportunities.

The differences in project development for each business sector is as much about expectations as it is real differences. As noted, front-end planning is a formal, owner-driven process that explicitly defines the level of anticipated scope, cost, and schedule accuracy associated with evolving project definition. Participants are expected to carry a project through a formal gated process with full acknowledgement that early cost estimates and schedule projections may be significantly different than the eventual estimate that will evolve with scope maturity. There can be an incorrect assumption that proposed projects have underlying commonality limiting cost and schedule variance. Projects receive an early estimate with undeserved credibility. This, in turn, generates lasting expectations. Projects move forward in both power and process business sectors in a similar manner with the difference being that the process industry withholds commitment and stakeholder exposure until scope advances. More importantly, formal business planning is tempered until legitimate analysis is possible. Many process projects are abandoned without ever reaching the public radar screen or becoming subject to critical assessment. The same projects in the power sector could easily advance to the point of requiring public “cancellation” or worse: Full execution with an ever present label of being over budget and behind schedule.

This does not imply that front-end planning can automatically translate to power projects. There are notable differences. Each attempt to apply principles of the planning process will require careful attention to identify elements that can be put to use. Even when technology and design configuration are seemingly stable, there is much to study and clarify before reliable financial analysis can be accomplished. The additional study and analysis will add time and cost to the project development process, but experience demonstrates it is money well spent.

The industry can improve both perceived and actual cost /schedule performance by taking a page from colleagues in other sectors. Attention to project definition is essential when setting baseline goals used to steer project decisions and to measure project performance. Being overly aggressive to save time and money during the early stages of project development can backfire, creating an environment in which successful project execution becomes nearly impossible. Careful evaluation of industry best practices associated with the owner’s role in front-end planning can lead to a thoughtful and comprehensive approach, which will more than pay for itself. The Construction Industry Institute’s “Front End Planning Toolkit 2014.1” is one example of easy to understand material that can be used to facilitate an orderly and effective process.

The “It’s a Small World” attraction at Disney World is iconic. Its feel-good objective is to build awareness of the diversity of the human race and the value that can come from engagement with people that look, talk, and act differently.

This sense of global awareness is increasingly important to U.S. nuclear plant owners. What happens elsewhere can have impacts here, particularly as units age and materials issues emerge. Fukushima is the definitive example, but other recent issues highlight the importance of staying plugged into what’s happening around the world. Let’s look at two.

Baffle-former bolts are bolts that attach vertical core baffle plates to horizontal former plates in the core barrel of pressurized water reactors. The purpose of the core baffle is to direct coolant flow through the core and provide some lateral support to the fuel assemblies. To cool the baffle structure, a portion of the water flowing through the reactor vessel is directed between the core barrel and baffle plates in either a downflow or upflow configuration.

In early 2016, hundreds of degraded or missing baffle-former bolts were discovered during outage inspections at the Indian Point and Salem nuclear power plants. The issue appears to be limited to four-loop reactors with a downflow configuration and bolts made of type 347 stainless steel. The degradation is attributed to irradiation assisted stress corrosion cracking over years of operation.

Notably, such degradation was first detected in PWRs outside the United States in the late 1980s. The NRC communicated this overseas operating experience in 1998, and the industry adopted inspection and evaluation guidelines that included inspection of baffle-former bolts during the time when bolt degradation is most likely to appear. It’s not yet clear why the extensive degradation was not detected in a more timely fashion, but the NRC conducted a risk-informed evaluation and determined that the issue did not pose an immediate shutdown risk to the affected plants.

Indian Point 2 and Salem 1 replaced potentially degraded bolts with type 316 stainless steel bolts and were able to restart. The other U.S. reactors susceptible to this issue are accelerating scheduled inspections to examine their baffle-former bolts, and at least one – D.C. Cook – has replaced some baffle-former bolts. The NRC also is evaluating a generic industry communication.

The second issue with potential global repercussions involves investigations by French authorities into excess carbon levels in certain steel forgings and the potential falsification of quality assurance records. These investigations have rocked the French nuclear industry, forcing French utility EDF to take some plants off-line for additional inspection and analysis.

The carbon issue came to light in 2014 when excess carbon levels were found in the reactor vessel manufactured for the Flamanville EPR plant under construction in France. Excess carbon levels can affect the mechanical properties of steel, potentially rendering it more brittle. EDF has said that its latest tests of the Flamanville reactor vessel demonstrate its structural integrity, but the French nuclear authority ASN has not yet released its analysis of the test results.

Citing concerns about the extent of condition related to the excess carbon issue, ASN ordered the shutdown of 18 plants in France to allow more detailed analysis. ASN and EDF subsequently reaffirmed the ability of the plants to safely operate, and all have since returned to service.

ASN also is investigating suspected instances of falsified quality documents at Areva’s Le Creusot forge, dating back more than four decades. Thousands of documents are being reviewed to assess whether, and the extent to which, employees may have modified quality control data. As reported by the Financial Times, David Emond, head of Areva’s component manufacturing business, said that employees would sometimes round numbers up or down so they fell within technical safety limits. Emond noted that while 70 components with falsified documents had found their way into French nuclear reactors – and 120 into overseas power plants – no safety problems have so far been discovered.

The mention of those 120 overseas power plants highlights the global impact of this issue. The ASN actions in France prompted the NRC in early January to release a list of 17 U.S. nuclear reactors with parts from Le Creusot, although the agency does not see a need for plant shutdowns. In a blog post, NRC spokesman David McIntyre said, “We are confident at this time that there are no safety concerns for US nuclear power plants raised by the investigations in France. Our confidence is based on the US material qualification process, preliminary structural evaluations of reactor components under scrutiny in France, US material aging-management programs, our participation in a multinational inspection of Creusot Forge, and information supplied by Areva about the documentation anomalies.”

It’s often said that a nuclear plant issue anywhere is a nuclear plant issue everywhere. The issues described above bear truth to that adage. My apologies if the Small World song plays over and over in your head for the next week.

As an air quality environmental engineer working with the utility industry for the last 20 years, I have two firm convictions. First, a successful and healthy society needs both reliable electricity and clean air. Second, we can simultaneously achieve both of these elements.

Increased air pollution is linked to significant decreases in life expectancy. Additionally, a positive correlation exists between electricity consumption per capita and life expectancy at birth. Some of the worst air pollution in the world occurs in developing nations due to uncontrolled combustion as well as from indoor air issues due to the use of wood and dung as cooking fuels. Therefore, I submit to you several observations to help you protect the phenomenal air quality we enjoy in the United States while supporting the utilities who provide Americans with some of the most reliable and cost-effective electricity in the world.

• Understand Governmental Inertia

Stopping a regulation before it is fully implemented is relatively easy; no one is betting that the Clean Power Plan (CPP) will be implemented on existing utilities. The CPP will likely never be implemented since the Supreme Court stayed it in February 2016. However, existing regulations which have already survived numerous court challenges are a different matter entirely. For eight years, the Clinton EPA initiated a policy reinterpretation in order to shift “routine maintenance” activities into projects that required major New Source Review (NSR) construction permits with add-on control devices. The eight years of the Bush EPA attempted to both rollback this reinterpretation as well as provide clarification on the definition of “routine” and provide exemptions for Pollution Control Projects. The eight years of the Obama EPA rolled back the NSR reform of the Bush EPA. This seesaw effect on regulations played out over years of court challenges and appeals, some of which reached the Supreme Court. The lesson to learn is that no single administration can drastically change established environmental policies, at least not without an act of Congress. This is due in no small part to the portion of the Clean Air Act which allows for average citizens and environmental interest groups to file suit forcing EPA to act.

• Learn from the Previous Successes of Market-Based Environmental Policy

EPA’s Acid Rain Program is an unparalleled success, incentivizing the reduction of air pollution while increasing power production. Likewise, the current drop in U.S. greenhouse gas emissions correlates directly to the decrease in the cost of natural gas versus coal. U.S. power producers are cost-savvy, experienced and understand their customers wants and needs. Utilize their knowledge base and challenge them to creatively balance our air quality and energy generation issues. Many programs have been so successful that controls have reached the point of diminishing returns (for example baghouses). Find the new low hanging fruit where addition of controls can have a substantial impact on pollution reduction.

• Provide Regulatory Clarity for Utilities

The lead time for a new power plant ranges from 2 to 10+ years depending on the facility’s type (natural gas-fired reciprocating engine, simple- or combined-cycle turbine, coal-fired boiler or nuclear power plant). When beginning to plan a new power plant project, a utility needs to understand the environmental regulations that will be in place at the start its operation. Additionally, utilities are beholden to many masters, such as the regional transport authority, possibly a public service commission, local non-governmental Organizations (NGOs) and the changing demand growth of their customers. The last thing any utility needs is legal uncertainty regarding environmental regulation. (For more information, look no further than the tug-of-war between CAIR and CSAPR and between CAMR and MATS.) One place to start would be to define “routine maintenance” in an amendment to the Clean Air Act.

Reach out to utilities as well as to NGOs in order to understand what has worked and where improvements can be made. Force compromise between these disparate groups. In the long run, an imperfect regulation provides more certainty to the power generation community than four years of regulatory limbo. Above all, like a good physician, first do no harm.

Entergy announced it will close the two nuclear reactors at Indian Point Energy Center in 2020 and 2021.

The closure was announced as part of a settlement with New York State, which will drop legal challenges against the plant. Additionally, the state will support renewal of operating licenses for Indian Point.

The shutdown will complete Entergy’s exit from its merchant power business due to low wholesale energy prices.

New York Governor Andrew Cuomo confirmed the deal Monday.

The deal was an agreement between Entergy, the governor’s office, the office of New York attorney general Eric Schneiderman and environmental group Riverkeeper, TheNew York Times reported.

Entergy noted that low energy prices, lower power generation costs for other sources and increased operating costs, including $200 million already invested for license renewal contributed to the decision

Duke Energy Announces Florida Solar Facility

Duke Energy announced it will soon break ground on an 8.8-MW solar power station on 70 acres near Live Oak, Florida.

The company hopes to bring the Suwannee Solar Facility online by the end of 2017. Duke will be the owner and operator.

Duke Energy Florida also owns and operates the Perry Solar Facility in Taylor County and the Osceola Solar Facility in Osceola County.

Babcock & Wilcox Acquires Universal Acoustic & Emission Technologies

Babcock & Wilcox Enterprises Inc. announced the company has acquired Universal Acoustic & Emission Technologies Inc., a Wisconsin-based provider of custom-engineered acoustic, emission and filtration solutions.

Universal AET will be renamed Babcock & Wilcox Universal, and become part of B&W’s industrial operating segment. The deal has an estimated value of $55 million.

The renamed company will continue to provide custom-engineered acoustic, emission and filtration solutions — including gas turbine inlet and exhaust systems, custom silencers, filters and custom enclosures — to the natural gas power generation, mid-stream natural gas pipeline, locomotive and general industrial end-markets.

ABB Wins $100 Million Order for HVDC Upgrade

Los Angeles Department of Water and Power has awarded ABB a $100 million contract to modernize the Sylmar HVDC converter station in California.

The station, commissioned in 1970 north of Los Angeles, is a key part of the electricity link between the Pacific Northwest and southern California.

The Sylmar converter station is the southern station of the Pacific Intertie, a 1,360 kilometer HVDC link that connects to the Celilo converter station near the Columbia River, Oregon. The Pacific Intertie transmits electricity from the Pacific Northwest to as many as three million households in the greater Los Angeles area.

NextEra to Build 300-MW Wind Project in North Dakota

NextEra will build a 300-MW wind facility dubbed Emmons-Logan in south-central North Dakota.

The development comes as part of a power-purchase agreement with Great River Energy, a wholesale energy provider to 28 distribution cooperatives in Minnesota.

Construction on Emmons-Logan will begin in 2019 and the 133 GE turbines will be in place and commissioned at the end of that year.

When Emmons-Logan is completed, Great River Energy’s wind capacity will surpass 700 MW.

The energy provider already purchases 151 MW of energy from two NextEra’s wind energy centers in eastern North Dakota and northwest Iowa.

Two Gas-Fired Plants Totaling 1,900 MW Slated for Ohio

Clean Energy Future are developing two additional gas-fired power plants to go along with two other gas plants the company has already revealed, all in Ohio.

The two planned plants are a 940-MW facility in Lordstown and a 960-MW facility in the town of Oregon, the Columbus Business First reported.

Clean Energy Future indicated the two new facilities will both be located next to facilities already under construction, with the 940-MW first phase of the combined cycle Lordstown plant to begin operations next May and the 960-MW first phase of the Oregon plant under construction for an unspecified commissioning date.

New York Governor Calls for 2.4 GW of Offshore Wind Power by 2030

New York Governor Andrew M. Cuomo called for the development of 2.4 GW of offshore winddevelopment in the second major power generation move to come from his office this week.

The first step in the ambitious development slate would be a 90-MW offshore wind project 30 miles southeast of Montauk, which Cuomo urged the Long Island Power Authority to approve. The Authority has already said contract negotiations are nearly complete, and the project will come up for a vote in January.

The full 2.4 GW would be developed by 2030, enough to power 1.25 million homes. The governor’s office called it the largest commitment of its type in U.S. history. Full details of what the office is calling the Offshore Wind Master Plan are slated to be finished by the end of this year.

TVA Names New Senior VP, Chief Nuclear Officer

The Tennessee Valley Authority has named Mike Balduzzi its senior vice president and chief nuclear officer.

He will report to Joe Grimes, executive vice president of generation, and oversee the operation and optimization of TVA’s nuclear fleet.

Balduzzi has 34 years of experience in the nuclear industry with numerous leadership roles in operations, maintenance and oversight activities at facilities such as Vermont Yankee, Nine Mile Point and Pilgrim. He joined TVA as senior vice president of nuclear operations in January 2014.

Southern Power Acquires 276-MW Bethel Wind Energy Center

Southern Power announced it has acquired the 276-MW Bethel Wind Energy Center from Invenergy Services.

The purchase price was not disclosed. Blattner Energy constructed the facility, and Invenergy Services will operate it when it’s officially commissioned later this month.

Including Bethel Wind Energy Center, Southern Power now owns more than 3,200 MW of renewable energy sources across 36 solar, wind and biomass facilities either announced, acquired or under construction.

Southern Energy, the parent company of Southern Power, has completed or is developing 6,500 MW of renewable generation since 2012.

LG&E and KU Energy Names New President and COO

LG&E and KU Energy have announced that Paul W. Thompson has been named president and COO of the companies. Victor A. Staffieri remains the chairman and CEO.

Under the new structure, Staffieri will continue to report to Bill Spence, PPL chairman, president and CEO. Thompson will continue to report to Staffieri.

Thompson joined LG&E in 1001 in Business Development and has held a number of leadership roles. In his current role, he is responsible for all operational areas including generation, energy supply and analysis, electric distribution and transmission, gas distribution and storage, and customer service.

Thompson has a bachelor’s degree in mechanical engineering from Massachusetts Institute of Technology and a master’s degree in business administration in finance and accounting from the University of Chicago.

Duke Energy Sells Latin America Assets for $1.2 Billion

Duke Energy announced it has completed the sale of 2,300 MW of power assets in six Latin America countries for $1.2 billion.

The hydroelectric and thermal assets in Peru, Chile, Ecuador, Guatemala, El Salvador and Argentina were sold to I Squared Capital. Additionally, Duke seeks to sell assets in Brazil to China Three Gorges Corp.

“We are pleased to have closed this transaction so quickly,” said Duke Energy chairman, president and CEO Lynn Good. “The sale of the Brazilian assets is expected to be completed in the near future.”

GE, APR Energy Renew Alliance With Mobile Gas Turbines

GE and APR Energy have jointly announced they have renewed their strategic alliance in the gas-fired turbine market.

Under the agreement, APR Energy has global exclusivity as the rental provider of GE mobile gas turbines under 50 MW.

As part of the agreement, APR Energy will acquire new Generation 8, GE TM2500+ mobile turbines as part of its ongoing efforts to upgrade and standardize its fleet.

Additionally, the two companies will collaborate on leads for customers looking for interim or rental power solutions as they work to more permanent power solutions.

“We are very pleased to continue our partnership with APR Energy,” said Jeffrey Immelt, chairman and CEO of GE.

“We have been impressed with their high level of customer service and ability to deliver turnkey power generation projects in remote locations all around the world.”

About this time every year, industry observers attempt to forecast the events of the future.

I compare this annual exercise to playing golf on a sheet of ice. No matter how straight your line is, you will miss the target most of the time.

Nonetheless, it is a worthy endeavor meant to compel discussion and debate over the direction of the most important industry in the world.

So, how will things unfold in the power sector in 2017? Specifically, which markets will take a major leap forward or backward this year?

At the risk of landing in the bunker, I’ll take a shot – Fore!

Digital Solutions

If you work for a tech company or service provider in power generation, your company has either launched a new digital offering or is in the process of developing one.

Although GE is a clear leader in this sector with its Predix platform, it is not the only player in this growing market. Led by its Sinalytics platform for big data, Siemens launched Digital Services for Energy last year. ABB launched a digital offering for power plants known as ABB Ability, a new centralized software platform leveraging ABB’s Industrial Internet of Thing (IoT) capabilities. Also, Schneider Electric unveiled an IoT solutions platform known as EcoStruxure, allowing companies to build a real-time digital model of individual assets and overall portfolio.

So how big is this market? GE said an estimated $90 billion is expected to be invested in the digitalization of energy by 2020.

Power producers can’t ignore the value of digital technologies and services. Opportunity is knocking for power generators in desperate pursuit of increased efficiency and reliability amid flat or declining demand for electricity.

Energy Storage

The power sector is rapidly evolving, and energy storage is at the center of this evolution. Storage costs have plunged 60 percent in two years.

According to market research firm IHS, the energy storage market is set to “explode” to an annual installation size of 6 gigawatts (GW) in 2017 and over 40 GW by 2022 – from an initial base of only 0.34 GW installed in 2012 and 2013. What’s more, a report from IMS Research shows the market for storing power from solar panels will rise to $19 billion this year. That’s up from $200 million in 2012.

Storing electricity on a large scale has long been pursued by electric utilities in hopes of using the power to cover periods of peak demand. The technology to store large amounts of power appears to be commercially viable. Some grid-scale systems are viable now, while others are on the verge of viability. The next step: Getting projects funded and online.

The industry’s interest in the energy storage market was plainly evident last year at POWER-GEN International 2016. Attendance for all of the sessions on energy storage was standing room only. In 2017, POWER-GEN will be doubling the number of sessions on energy storage.

According to Navigant Research, energy storage could grow to become a $21.5 billion market by 2024.

Large-Scale Solar

Utility-scale solar capacity is expected to grow to 27,000 MW in 2017, up from 10,000 MW in 2014. That’s an annual growth rate of 39 percent, which makes solar the fastest-growing renewable resource for U.S. electric utilities. Also, the Department of Energy is projecting utility-scale solar capacity will rise by 8,500 MW in 2017 and 2018 combined.

But these figures project a false reality. In fact, the market for large-scale solar in the U.S. will weaken in 2017, driven by the expiration of the solar investment tax credit (ITC) and an over-procurement of capacity. Though the ITC was extended, investor-owned utilities have secured enough solar capacity to meet their commitments, thanks to record low prices for power purchase agreements.

“In 2017, while the residential and non-residential PV markets are both expected to grow year over-year, the U.S. solar market is expected to drop just over 4 percent on an annual basis,” according to a report by GTM Research.

Natural Gas

Not surprisingly, a significant amount of generation fueled with natural gas will be added in the U.S. in 2017 and 2018, according to the Energy Information Administration (EIA). U.S. power producers are expected to build 11,200 MW of gas-fired generation this year. In 2018, they will add a whopping 25,400 MW of gas-fired capacity.

“If these plants come online as planned, annual net additions in natural gas capacity would be at their highest levels since 2005,” EIA said.

As a result, the industry’s major gas turbine manufacturers have launched some innovative gas turbine designs that are faster, more efficient, more flexible, and more durable than the designs of a decade ago. I guarantee 2017 will mark further improvements in fuel efficiency, which will benefit power producers worldwide.