By Jose Alvoeiro and Carlos Calderaro

The 98.5 MW Huanza hydropower project in the central Andean region of Peru, where a 2.7-km long steel penstock was constructed. Photo courtesy: Stantec

To increase the reliability of electric power supply for its mining operations, Peruvian mining company Buenaventura elected to develop a hydroelectric project in the Pallca River basin of the Andes Mountains in Peru, approximately 130 kilometers east of the capital city Lima. Water conveyance for hydropower in the high mountains of the Andes is often a technical challenge and, in many cases, can result in significant construction costs.

The Andes’ steep terrain, unfavorable geological conditions, and restricted access conditions presented further challenges for a hydroelectric project in this area. This article describes the project’s challenges, solutions and how learnings can be applied to similar situations that can benefit power companies, developers, and the engineering community in general.

What was the main driver or need for the project? And, why was a hydropower project needed in this part of the Andes?

In 2007, there was wide concern in Peru that the rate of growth of newly installed electric generation capacity was insufficient to meet the projected demand of energy. In addition, the country was experiencing sustained GDP growth of more than 5 to 6 percent per year. This was particularly relevant to the mining sector, which is among the largest consumers of energy in Peru as mining projects are developed. Therefore, Buenaventura implemented a plan to secure its own power supply for its growing mining operations of precious metals.

Hydropower was the best solution for the project due to its low environmental impacts and ability to generate clean and renewable electric energy. The project also needed to fully integrate into the Peruvian national power grid to supply power to Buenaventura operations scattered in other parts of the country. Buenaventura turned to Stantec, whose role on the project was to design a 40-meter high concrete gravity dam on the Pallca River and to develop a conveyance system for moving water 712 meters below to a powerhouse with two identical generating units. The Huanza Hydroelectric Project began in 2007 and commercial operation started in early 2014.

What design or construction challenges did the team face?

The Huanza Hydroelectric Project is set at a very high elevation varying from 4,100 meters at the water intake to about 3,350 meters at the powerhouse in a distance of about 12 kilometers. Although the high altitude was a challenge, the very high head combined with steep terrain and restricted access proved to be the biggest challenge of the project, and particularly for the steel penstock design. A detailed logistic plan needed to be laid out for concrete and steel parts, including the can sections of the penstock. With the first section of the water conveyance structure a tunnel, several access tunnels or construction adits were excavated by drill and blast to facilitate construction, hence material removed from the excavations was also considered in the plan.

The location for the powerhouse on the banks of the Pallca River was only accessible through a narrow and winding road that climbed the Andes up to an elevation of 4,100 meters. This elevation presented challenges of a higher altitude, steeper terrain and unfavorable ground conditions. As a result of these factors, optimizing the design of the water conveyance structure in the steep mountainous terrain was critical for the Huanza Hydroelectric Project’s economic and construction viability.

In addition, safety was a top priority for the Stantec team. Living conditions were known to be quite difficult due to a high altitude and lower oxygen levels. Each employee assigned to work at the site would have a medical examination before ascending to the project site as a preventive measure and to look for any existing health conditions. In addition, only designated trained drivers were assigned to transport working staff to the site with clear communication protocols. Cell phone service was not available on site, so a dedicated radio frequency was utilized to coordinate vehicle traffic, especially when heavy trucks or off-road vehicles were operating on the access road.

How did the team overcome these challenges? Can you describe the design elements of the project?

After conducting the necessary surveys, geotechnical and materials investigations, hydrology and flood assessment and hydraulics and seismicity studies, the team needed to design a conveyance system from the Pallca reservoir to the powerhouse in variable ground conditions and changing elements. Stantec engineers designed a water conveyance system consisting of a low-pressure tunnel leading into a steel penstock.

As with most projects, unforeseen factors occurred during the construction phase, like navigating around existing archeological sites and limited access points. This resulted in an increase in the total length of the penstock. Despite the increased penstock length, Stantec engineers negotiated for a reduced product cost by working directly with the supplier of the steel plates for the penstock manufacturer — cutting back on costs that would otherwise have significantly increased the project budget.

This 2.7 km steel penstock was manufactured with high strength quenched and tempered steel plates. Photo courtesy: Stantec

The penstock was manufactured with very high strength quenched and tempered steel plates, using a specially designed gas-fired oven for stress relief. In the initial 700 meters, the penstock was exposed and installed in very steep terrain, and then it was buried in a trench excavated in soil along the winding access road.

In spite of the more difficult welding process and post-weld heat treatment, the material selection helped the project cost as the can sections weighed less, which better facilitated transportation and handling by cranes.

Stantec engineers optimized the design of the buried section to reduce the number of anchor blocks and to rely on the soil strength to withstand the forces resulting from changes in pipe bends, so as to reduce the amount of concrete and steel required.

Did this approach lead to any other benefits for the project?

An optimized penstock design resulted in lower head losses for the project and was key in an increased project output reaching 100 MW capacity after final commissioning tests.

Can you describe the design process for the dam and powerhouse?

The team was responsible for designing a 40-meter-high conventional concrete gravity dam with a 205-meter-long crest, which accounts for a daily peaking reservoir storage volume of 543,000 m3 at the normal supply level of 4,063 meters. The dam also incorporated a 12-meter-wide free overflow spillway with a sky jump terminal structure and a low-level outlet structure.

The powerhouse was a concrete structure with a steel roof and metal cladding containing two vertical shaft generating units with a total installed capacity of 55 MVA at the generator terminals.

How did the Huanza Hydroelectric Project benefit the nearby community?

The local community was involved with the project for more than 15 years and was very enthusiastic about improvement of the access roads, the hiring of local personnel during project construction, and the establishment of an annual fund for community improvements once the project started. Some of the community improvements included access road paving, improvements of bridges crossing creeks along the roads, road widening to accommodate larger vehicles, and increased traffic safety.

When completed in 2014, the Huanza Hydroelectric Project added an additional annual 510 GWh of clean energy into the power grid. The project also allowed for participation from locally-based contractors and laborers.

The penstock operates under a maximum design head of 800 m. Photo courtesy: Stantec

What were your top learnings from this project that could benefit other communities/power-generating companies facing a similar situation?

Early assessment of project sites can help teams discover an alternative penstock trace, like it did with the Huanza Hydroelectric Project. This is especially helpful in cases where there could be an environmental or archeological barrier.

In addition, specific design elements can help with project costs, like reducing the amount of concrete and steel by optimizing the penstock anchors in number and size; and reducing the weight of the steel cans by selecting a high strength material, which reduces the capacity and size of the lifting equipment.

Lastly, it’s important to work in close collaboration with the project contractor. This ensures the project design is fully optimized and helps determine whether or not the team is able to use available local materials versus ordering materials that might have longer lead times and higher costs.

Jose Alvoeiro is the hydropower sector leader at Stantec. Carlos Calderaro is the hydropower commercial director of WaterPower & Dams at Stantec

Even minor traces of chloride, sulfate, and sodium hydroxide can cause severe problems in steam systems, and especially turbines. In the case of sodium hydroxide, stress corrosion cracking of turbine blades and rotors may occur very rapidly. Chloride and sulfate salts deposit in the last rows of the LP turbine (the phase transition zone, PTZ) and can induce pitting that in turn leads to stress corrosion cracking and corrosion fatigue.

The Electric Power Research Institute’s (EPRI) recommended steam sodium limit is 2 parts-per-billion (ppb), with a concentration of 1 ppb “normally achievable in both drum and once-through units with good control of mechanical carryover or operating on AVT or OT.” The 2 ppb limit also applies to chloride and sulfate, again with the understanding that concentrations should normally be much lower.

Reliable on-line sodium analyzers have been available for years, but trace chloride and sulfate monitoring has been more difficult. Ion chromatography is a valid technique, but the instrumentation is expensive and requires much operator attention. The surrogate measurement for these two impurities has been cation conductivity, (or more properly termed, conductivity after cation exchange [CACE] to emphasize the fact that the sample is routed through a cation resin column to exchange all cations, e.g. ammonium, sodium, calcium, etc., for hydrogen ions).

Chloride/sulfate analyzer. Photo courtesy: METTLER TOLEDO Thornton.

This ion exchange process creates a sample of a dilute acid solution of chloride and sulfate, whose conductivity is then measured. An advancement that has become popular is degasified CACE, which utilizes a sample reboiler or nitrogen sparging compartment to scrub CO2 from the sample and minimize interference from this compound.

The common normal CACE or degassed CACE limit for steam is 0.2 µS/cm, but laboratory data has shown that the concentration of chloride and/or sulfate can be considerably greater than 2 ppb with CACE at the 0.2 µS/cm threshold. Thus, direct measurement of these troublesome impurities offers significant advantages, and a new instrument is now available to monitor trace concentrations (down to 0.5 ppb). The analyzer combines two well-established technologies to provide on-line measurements of these ions — capillary electrophoresis to separate the ions and conductivity to measure and calculate their concentration.

A sample and a known reagent are collected in a cartridge with a capillary, and voltage is applied across the cartridge. The ions in the mixture start separating and moving through the capillary towards respective electrodes at the ends of the capillary, thus causing separation of ions. Based on the size-to-charge ratio, different ions move at different speeds, forming clusters of each ion as they flow towards the electrode. Each cluster of ions passes a conductivity sensor on the cartridge just before they reach the electrode, and the sensor records a measurement based on the concentration of the ion. By comparing the measurement for the ions with the measurement for the known reagent, the analyzer calculates the concentration of the ions in ppb. This measurement can be repeated as frequently as every 13 minutes, drawing a fresh sample each time.

This ability to accurately monitor trace concentrations of chloride and sulfate offers an excellent enhancement to steam monitoring capabilities. Looking towards the future, company personnel have been asked if the instrument capabilities could be expanded to analyze for other trace compounds, most notably two of the primary decomposition products, formate and acetate, that are generated in steam boilers if any organic compounds (neutralizing or filming amines) are employed for pH control and corrosion protection. Research is underway, but a definitive answer is not yet available.

What About the Rest of the Steam Generating Network?

While protection of the steam system and turbine is extremely important, maintaining proper chemistry in the other sections of the steam generator is also vital to minimize corrosion and fouling. Impurity ingress from condenser tube leaks or malfunctioning makeup water systems can introduce impurities, including our old friends, chloride and sulfate, that can cause rapid damage in conventional boilers and HRSG evaporators. Poor condensate/feedwater chemistry control will induce corrosion that not only can cause catastrophic failures (flow-accelerated corrosion, FAC) within these systems, but introduce corrosion products to the boilers that then precipitate on waterwall tubes and influence corrosion chemistry. So, with those themes in mind, the following sections outline guidelines for continuous sampling of the other systems within the steam generator

Makeup Treatment System

The core process of most power plant makeup water systems is reverse osmosis (RO) followed by either mixed-bed ion exchange (MBIX) or electrodeionization (EDI) to “polish” the RO effluent to meet utility steam generator requirements. RO units typically are equipped with a number of instruments to monitor system performance, including pressure, temperature, flow, and specific conductivity. We will focus upon the recommended analyses of the final effluent from either a MBIX or EDI polisher.

Note: In this and several of the following sections, the normal limit for each parameter is included.

• Specific conductivity: ≤0.1 µS/cm
• Silica: ≤10 parts per billion (ppb)
• Sodium: ≤2 ppb

Control within these guidelines ensures that high-purity water is being distributed to the steam generator. A rise in any of the values indicates that either the MBIX resin has reached exhaustion or that a failure has occurred in the EDI unit. Prompt corrective action is necessary.

Particle monitor. Photo courtesy: CHEMTRAC

Often the design specifications for new plants call for continuous pH monitoring of makeup system effluent, but pH measurement of high purity water is very difficult. The analyses listed above are sufficient for evaluating process conditions.

Condensate Pump Discharge

Condensate pump discharge (CPD) is an absolutely critical monitoring point, particularly for systems with water-cooled condensers, as this is the most likely source for major condensate contamination. A condensate polisher will provide a buffer against contaminant ingress, but unfortunately polishers are often not considered necessary for drum units, when in fact they can be of great benefit.

Recommended CPD analyses are:

• CACE or degassed CACE: ≤0.2 µS/cm
• Specific Conductivity: Consistent with pH
• Sodium: ≤2 ppb
• Dissolved Oxygen: ≤20 ppb
• pH: 9.6 to 10.0 (This is the pH range for triple-pressure feed-forward low-pressure [FFLP] HRSGs, where the LP circuit basically serves as a feedwater heater for the intermediate-pressure (IP) and high-pressure (HP) evaporators. The range may be a bit lower for other HRSG designs.)

Sodium monitoring is very effective for detecting condenser tube leaks. With a tight condenser, sodium levels in the condensate should be below 2 ppb, and in many cases less than 1 ppb. Excursions of course suggest a leaking tube(s).

As with sodium, a rise in CACE indicates impurity in-leakage, although this measurement is also influenced by carbon dioxide ingression, typically via air in-leakage at the condenser. The CACE limit of 0.2 µS/cm is a standard requirement for implementation of all-volatile treatment oxidizing [AVT(O)] chemistry, which is the best choice for condensate/feedwater systems that do not have copper alloys (virtually all HRSG systems have no copper alloy components). No longer is oxygen scavenger feed recommended in all-ferrous systems, as this chemistry can induce flow-accelerated corrosion in HRSG low-pressure and intermediate-pressure economizers and evaporators, and attemperator lines.

Dissolved oxygen (D.O.) monitoring is important for evaluating condenser air in-leakage. A sudden increase in D.O. may indicate a structural or equipment failure in the condenser shell, at penetrations to the condenser, or even at remote locations such as the gland steam condenser. However, some air in-leakage is desired, as it provides the oxygen necessary for AVT(O) chemistry. In this regard, the D.O. normal limit was increased from 10 ppb to 20 ppb several years ago.

Previously we noted that pH measurement of high-purity water is difficult, and is not practical for demineralizer effluent. While direct pH monitoring is recommended for condensate and feedwater, the measurement is still difficult. However, in the absence of significant condenser air in-leakage, ammonia concentration, pH, and specific conductivity (S.C.) are directly related. S.C. is a very reliable measurement, and thus is normally utilized to control ammonia feed and pH in the condensate and feedwater.

LP Economizer Inlet/Boiler Feed Pump Discharge

These samples are necessary to monitor the feedwater before it enters the evaporators to ensure that the chemistry is being properly controlled to minimize FAC. Additionally, the measurements provide backup to those of the condensate pump discharge.

Recommended feedwater/economizer analyses are:

• CACE: ≤0.2 µS/cm
• S.C: Consistent with pH
• Sodium: ≤2 ppb
• Dissolved Oxygen (range): 5 to 10 ppb
• pH: 9.6 to 10.0 (This is the pH range for FFLP HRSGs. The range may be a bit lower for other HRSG designs.)
• Iron: ≤2 ppb

The discussion for CACE, S.C., pH, and sodium mirrors that for the condensate pump discharge, and also the first three, along with dissolved oxygen, are critical measurements for AVT(O) chemistry.

Integrated corrosion product sampler. Photo courtesy: Sentry

The reader will note the inclusion of iron in this set of parameters. Iron monitoring provides a direct measure of flow-accelerated corrosion and the effectiveness of the feedwater chemistry program. Typically, 90 percent or greater of iron corrosion products generated by FAC are particulate in nature. Several methods exist to monitor steel corrosion, and include:

• Continuous particulate monitoring
• Corrosion product sampling
• Grab sample analysis

A particulate monitor simply measures particle count in real time, and does not chemically differentiate what those particles might be. But, in high-purity feedwater systems, and in the absence of any copper alloy components, virtually all of the particles will be iron oxide.

A corrosion product sampler utilizes both a filter and ion exchange resin to capture suspended and dissolved iron. (It can also capture other metals including copper, if necessary.) After a designated run time, where the instrument also has a flow totalizer, analyses of the filter and ion exchange resin reveal the amount of metal captured. Straightforward calculations determine the corrosion rate over the period of time the sample was collected.

Finally, improved grab sampling techniques are available, in which, with proper sample treatment, iron measurements down to 1 ppb are possible. This method can provide near real-time data of corrosion rates, although on a snapshot basis.

Iron monitoring is often also recommended for CPD and boiler water samples to determine corrosion rates in other locations. With the on-line instruments, some form of sample sequencing can be arranged. Grab samples for each location can obviously be collected at any time.

Evaporator (Boiler) Water

Evaporator water sampling is critical for two primary reasons. First, whether the steam generator is an HRSG or conventional unit, the highest heat fluxes occur within the boiler. Thus, the effects of impurity ingress or poor chemistry are magnified by the high temperatures and pressures in these circuits. This issue is magnified by the fact that corrosion products from the feedwater system, most notably iron oxides, tend to precipitate on boiler internals. Iron oxide deposits are typically porous in nature, which allows impurities to concentrate underneath the deposits and cause corrosion, sometimes very severe, that would not occur otherwise.

Spectrophotometer. Not shown is the sample digestion equipment to convert particulate iron to soluble iron for total iron analysis. Photo courtesy: Hach

Secondly, boiler water chemistry must be established and monitored to ensure that steam purity matches the guidelines previously shown. Excess impurities in the boiler water can lead to problematic carryover to the steam circuits and turbine.

Recommended boiler water analyses include:

• pH (<8.0, immediate unit shutdown; typical range 9.0 to 9.8 with the precise range subject to steam generator design, pressure, and chemical treatment program)
• CACE
• Specific Conductivity
• Chloride
• Silica
• Phosphate (for those units on phosphate treatment)

The reader will notice no absolute limits listed for many of these parameters. This is due to the fact that allowable impurity concentrations vary as a function of boiler pressure. As pressure increases, and the density of water and steam converge, drum moisture separators become less effective, which in turn will allow greater carryover of water droplets into the saturated steam. Within the steam generator(s) proper, temperature and pressure influence corrosion, and in particular affect reactions underneath iron oxide deposits on waterwall tubes and other boiler internals. This influence is magnified at higher temperatures.

Also, the recommended chemistry control ranges will vary depending upon the selected boiler water treatment program, i.e., tri-sodium phosphate, caustic, or AVT-only chemistry. (Note: A concept known as sodium balancing is important for boiler water chemistry control, particularly for units with AVT-only programs. A discussion of sodium balancing is beyond the scope of this article.) Charts and graphs for acceptable control ranges may be found in EPRI guidelines or those from the International Association of the Properties of Water and Steam (IAPWS). In addition, software programs (including an excellent program developed by Mr. Randy Turner of Swan Analytical) are now available to precisely calculate boiler water conditions, and alert chemists and technical personnel to chemistry upsets.

Acknowledgement

The author wishes to thank Mr. Akash Trivedi of Metter Toledo Thornton for providing the detailed information regarding the chloride/sulfate analyzer.

Brad Buecker is senior technical publicist at ChemTreat.

Wisconsin Power and Light Company (WPL), a wholly owned subsidiary of Alliant Energy Corporation, submitted a Water Conservation Plan (WCP) under the requirements of Wisconsin Department of Natural Resources (WDNR) Chapter 852 — Water Conservation and Water Use Efficiency. The WCP covered WPL’s existing Riverside Energy Center (REC), existing Rock River Generating Station (ROR), Southern Area Beloit Operations, and future West Riverside Energy Center (WREC), which is planned to be in operation in 2019.

The four facilities on WPL property near Beloit, Wisconsin (collectively, referred to as the Riverside Site). The WCP outlined current and future measures to conserve water at each facility. HDR, Inc. was retained by WPL to aide in the development of the WCP and serves as WPL’s Owner’s Engineer for a variety of projects at the Riverside Site. The WCP was submitted in October 2015 and was approved by the state in June 2016.

Purpose of Plan

The purpose of the WCP was to outline water conservation practices to ensure water conservation and efficiency measures were addressed in accordance with Wisconsin Administrative Code (WAC) Chapter NR 852 for the Riverside Site. The WCP also supported the Application for Water Loss Permit Modification for WPL’s existing REC natural gas combined cycle (NGCC) facility, existing ROR natural gas peaking generation plant, Southern Area Beloit Operations, and the future WREC NGCC facility.

Power block at Alliant’s Riverside Energy Center.

The WCP summarized current water conservation measures in place as well as established potential future measures under consideration for each of WPL’s power generation facilities at the Riverside Site. Building on water conservation measures implemented during plant design and operation of the REC and ROR, WPL evaluated efficiency measures and programs to achieve long-term water conservation practices at each existing facility that may be incorporated into the design of the future WREC.

Background

The future WREC facility is a nominal 650-MW NGCC electrical generating facility, with a planned in-service date of 2019. The existing REC is a nominal 600 MW NGCC facility that has been in operation since 2004. The existing ROR facility consists of demolished generating units and 130 MW peaking units, which are located on the east portion of the ROR property.

An existing horizontal collector well (HCW) provides makeup water to REC, which mainly serves to supply water used in the facility’s mechanical draft cooling tower as well as other miscellaneous water losses that occur during the power generation process. An increased withdrawal from the HCW is proposed for operation of WREC, such that the HCW can provide makeup water to both the future WREC and the existing REC. The increase would result in a water loss averaging more than 2,000,000 gallons per day in any 30-day period above the authorized base level in the existing REC water loss permit. Therefore, under WAC Chapter NR 142.06(1)(b) and in accordance with Wisc. Stat. §281.35, approval for modification of the existing water loss permit is required. The ROR facility withdraws water from the nearby Rock River, where water is used for the facility’s heat rejection system (consisting of a once-through cooling configuration). The only water loss for the Southern Area Beloit Operations is a small quantity of potable water.

All three plants will discharge process wastewater to the Rock River.

Drivers for Water Conservation

Various conservation efforts within WPL are taking place and are being driven by several factors, including the following:

• Demand for industrial water use is expected to grow over time and it can be reduced through proper water management, efficient utilization of water supplies, minimization of wastewater production, and recycling of various water sources;
• Desire to conserve natural resources and to promote environmental stewardship; and
• Requirement to submit a Water Conservation Plan to WDNR in accordance with Wisc. Administrative Code Chapter NR 852.

Goals and Objectives

WPL’s water conservation goals are to conserve, recycle and reduce average day water usage at REC, ROR, the Southern Area Beloit Operations, and the future WREC facilities.

To meet this goal, WPL’s plan included:

• Complying with WAC Chapter NR 852;
• Developing strategic planning analysis and implementation timelines in accordance with NR 852;
• Promoting water conservation awareness to company employees;
• Incorporating stakeholder input in the evaluation of Water Conservation and Efficiency Measures (CEMs); and
• Pursuing cost-effective and technically feasible CEMs.

Conservation and Efficiency Measures

In order to develop a water conservation plan, WPL had to implement and/or evaluate water CEMs at the facilities identified as specified by WAC Chapter NR 852, Tables 1 and 2. The driver was to ensure that each plant efficiently utilizes the water supply source that such results in an overall water savings. Water savings would not be gained at the expense of other environmental considerations.

As a part of the evaluation, existing water mass balances were reviewed to determine if any gaps were present. It was found that some water flows were missing in the REC water balance and therefore further plant investigation was required in order to obtain the essential water flows. Once the information was gathered, the water mass balance was updated for the WCP.

“The ROR facility withdraws water from the nearby Rock River, where water is used for the facility’s heat rejection system.”

The team for the development of the WCP consisted of existing WPL plant staff including: plant manager, plant engineers, plant operators, chemistry expert, environmental staff, the WPL new plant development team and HDR. During the process, the existing plant went into an extended outage, which slowed the progress of development of the plan. However, in the end, the team was able to compile the necessary information and get valuable input from the appropriate personnel to finish.

CEMs, NR 852

WAC Chapter NR 852 requires all Power Production (PP) water users applying for a Tier 3 water loss approval to provide documentation showing planned implementation of, or completion of, specified CEMs that do not require retrofitting.

The CEMs in NR 852 that must be considered are broken into two tables: Table 1 indicates the mandatory CEMs that all PP water users must implement and complete; Table 2 indicates the required CEMs that PP water users shall implement that do not require retrofitting, except those CEMs that are not cost-effective or environmentally sound and economically feasible as determined by analysis conducted by the applicant.

NR 852 Table 1 Criteria

The CEMs listed in Table 1 of NR 852 are mandatory measures that a water loss permit applicant must show documentation indicating implementation and completion. The following is a list of the mandatory CEMs in NR 852.04, Table 1 and the required elements for each:

• PP-1, Water Use Audit

  a. Conduct a water use audit, determine water inflow and outflow from the facility and prepare written documentation of the audit results. Facilities shall identify once-through processes in the audit report.

• PP-2, Leak Detection and Repair Program

  a. Establish a protocol to repair leaks in a timely manner. Conduct a survey of leaks and develop a corrective action plan.

• PP-3, Information and Education

  a. Develop and deliver training to educate employees on the implementation of water conservation and efficiency measures at the facility. Information and education materials shall be made available to the department.

• PP-4, Source Measurement

  a. Measure or estimate all water withdrawals monthly or more frequently to allow for identifying and understanding variability in water use over time.

The mandatory CEMs from Table 1 are discussed in further detail in the following sections.

Editor’s Note: This article was published in EY’s Utilities Unbundled publication and that it has been reprinted with WEC Energy Group’s permission.

Wisconsin Energy was already one of North America’s largest electric and natural gas delivery companies but as far back as the early 2000s, its aging infrastructure made executives feel vulnerable. To position the company for the future, they invested US$3b in new power plants with a total capacity of 2,800 megawatts, US$1.3b to upgrade existing power plants and US$2.7b to upgrade the distribution system. Their Power the Future campaign began in 2003 with the installation of two natural-gas-fueled combined-cycle units to replace the 80+ year-old coal plant at Port Washington, WI and two new coal-fueled super-critical generating units at Oak Creek in Milwaukee County. All the new units had advanced emissions controls.

Just a decade later, and despite the acquisition of Integrys Energy Group, executives at the newly named WEC Energy Group (WEC) concluded that the generation portfolio that they had believed would keep the 4.4 million-customer utility commercially, economically, and environmentally viable until 2020-2030 needed an upgrade. With concern about greenhouse gases rising, low gas prices undermining the economics of their coal units, and demand for energy weaker than previously forecast, the only way to grow the company would be from within, by raising WEC’s operational game.

HEADING TOWARD THE TOP

In the Top Quartile by 2020 (TQ-20) campaign, WEC executives set an ambitious goal to raise the company to the top quartile of US utilities in power plant operations, diagnostics, and planning and maintenance by 2020.

“TQ-20 is really an effort for us to get a firm grip on the things that we can do that can make us more attractive in the market by controlling our operation and maintenance (O&M) expenses, and increase the overall availability of our generating units” explains Patrick Stiff, VP of Coal Generation and Biomass for We Energies, in the Milwaukee-headquartered utility, and subsidiary of WEC.

Fulfilling TQ-20 would require a deeper understanding of how the business operated, stronger benchmarking, experts to analyze the new data and most importantly, a deep commitment to change, according to Stiff. The company planned to take advantage of the new power of machine-to-machine connectivity and remote sensors to understand how every element of the operation’s generation fleet performs. They hoped to take this new trove of data and analyze it to find opportunities to improve performance and uptime, reduce cost and raise overall business efficiency.

The TQ-20 plan entailed:

• Better benchmarks. The TQ-20 team looked at a variety of sources, including the Electric Power Research Institute, the Palo Alto-based US electric power industry research center, for ideas of how We Energies could improve. “In many cases, we thought we were best practice. When we looked at what others were doing we saw many opportunities to learn, in addition to what we already were doing well, that could cause us to be better positioned to control our costs,” Stiff says. The new benchmarks gave them a number of fresh insights they continue to find helpful. “These days, we’re comparing ourselves to industry benchmarks such as planned outage factor (POF), equivalent availability factor (EAF) and equivalent forced outage factor (EFOF). We previously didn’t pay much attention to comparing ourselves to peer benchmarks around these,” he says.
• More experts. The team identified strong external and internal experts to analyze operations considering this additional new data, to try to understand where the systems and processes could be optimized.

We Energies specifically sought out experts to develop advanced work planning processes that helped the company utilize its field crews more effectively. They also monitored We Energies’ coal fleet in Wisconsin, offering diagnostics whenever they saw an opportunity for improvement. Finally, they helped them implement EPRI’s System and Equipment Reliability Prioritization (SERP), which We Energies executives believe will enable the company to achieve significant improvements in reliability and cost management.

The Oak Creek coal-fired power plant, owned and operated by We Energies, occupies 1,000 acres of land on the shore of Lake Michigan, 20 miles south of Milwaukee.

The internal experts — a select group of junior, middle and senior managers — not only helped analyze the fleet’s operations, but played a crucial role in educating staff about the advantages of the new operational methods.

In Stiff’s view, their outreach, especially form the executive level, made a tremendous difference to the employees’ degree of acceptance to the new processes, procedures and tools being implemented. “I really believe that our being out in the power plants in front of large groups talking about the initiative on a regular basis has been critical to our success in terms of having people be informed,” he says.

But actions mattered too: one key aspect was a promise to let a staff reduction that is a part of the overall TQ-20 plan occur entirely by attrition. This has helped ensure that the employees’ incentives stay aligned with the company’s interests, according to Stiff.

A CHANGED GAME

Two years later, TQ-20 is starting to take hold. Stiff says that after visiting many top-quartile utilities, they have made significant structural advances. “One of the things we learned in best practice visits, watching what top quartile companies were doing, was that they were paying extremely close attention to the condition of their equipment,” Stiff explains.

AN EQUIPMENT REGISTRAR

Top quartile companies created a central location to track the condition of all their equipment. Creating their own central tracking center will help We Energies make more strategic maintenance decisions and reduce outages. New metrics revealed a relatively large commitment to planned outages, and Stiff knew that driving outage days down through better management would be a significant opportunity for greater efficiency and effectiveness. Most leading companies have planned outages rates around 7 percent. “Historically we had been in the high teens or as high as 20 percent in a couple of years recently,” Stiff recalls.

“We are committed to staying the course here and seeing all the things that we’ve envisioned to take place be implemented.”

Over the next three or four years, he hopes to “compress the amount of time that we have units out of service for planned work, get more work done, and get the right work done during those outages such that our availability goes up.”

A new attitude to maintenance Overall, the TQ-20 team realized they needed to be more strategic about their attitudes toward maintenance. A new data-driven understanding of the life cycle of machinery, including realtime insights into wear-and-tear, has given them more insight into what was wearing out so that maintenance can be scheduled more efficiently. These insights have also shown that repairing non-critical equipment can be inefficient and that it can be more cost effective to hold off on repairs and instead replace those components at the end of their useful life. Further, they found that best practice companies focus their time and efforts on the most critical equipment, a practice that yields greater system reliability and cost savings, and they made a strategic decision to follow suit.

Letting their expert partners monitor their real-time data also revealed many other opportunities. “We’ve been working with them for over a year now and they’ve been very instrumental and helpful to us in identifying conditions in our power plants before they become critical,” says Stiff.

“They’ve provided us many insights that we believe have saved us millions of dollars,” Stiff adds.

The Presque Isle power plant occupies 65 acres of land on the shore of Lake Superior in Marquette, Michigan.

“Some of these items have been very specific. For example, during the coastdown for a planned outage of one of our turbines recently, one of our partner’s performance optimization center noticed a very small spike in the temperature on one of the turbine bearings. It didn’t alarm in the control room — it hadn’t reached a level that would trigger a local alarm. And those guys brought that to our attention. We looked at the information that they shared with us and decided that we would take a look at that bearing. When we opened up the bearing it had actually been partially wiped at the point of contact due to friction.”

Repairing that bearing early, before it had time to damage the whole turbine, saved the company money and assured unit reliability. “That’s one example of what they’ve been able to do for us, things that we otherwise wouldn’t have done for ourselves because we didn’t have the bandwidth to do it, we just didn’t have the folks to do it,” Stiff says.

Workforce management Not all the changes were mechanical. To handle maintenance more strategically, they decided to give the task of planning and scheduling to managers. “We went full circle and came back to having a planning and scheduling workforce that is solely management employees,” he says.

“We used to have a mix of represented employees and management employees doing that work, but we found that we had not given those employees the correct tools and the correct amount of time and room to do those jobs very effectively,” he says. Now, they are going back to the strategy used in the 1970s and 1980s when managers performed the planning and scheduling. “We believe long term that’s going to help us perform better, by giving them better tools such that they can perform at an even higher level” Stiff says. They also plan to track the scheduling data, which should yield ideas for even more scheduling opportunities.

A DETERMINATION TO WIN

This year, Stiff stepped back from day-to-day management of TQ-20 by assigning a manager to those duties, confident that his team is still on the right path. “We’re just starting to see people hit their stride in terms of making those jobs their own and making them work. So we’re really in this phase right now of starting to see a lot of things come together.” He receives weekly team updates and is very pleased with the continued focus and progress.

But he emphasizes that his short distance from the day-to-day campaign is not a sign that TQ-20 is any less important now.

“This is the single most important initiative going on in our business unit right now,” Stiff said. “We are committed to staying the course here and seeing all the things that we’ve envisioned to take place be implemented, adjusting where we need to and keeping our promises to our senior leadership team and to our employees that we’re going to make the changes that we need to make.”

Patrick Stiff is vice president of Coal Generation and Biomass at We Energies. Mark Scherluebbe is senior manager of Power & Utilities Advisory, Strategy, at EY.

Overhead View of Advanced Wood Pellet Loading (September 2013)

Ontario Power Generation (OPG) has been actively evaluating the use of biomass to decarbonize the production from its coal fired assets for some time. In recent years, this focus has shifted to the testing of second generation wood pellets to prove the ability to employ these new fuels safely and effectively within an existing coal fired unit. OPG has recently executed a project to convert Thunder Bay Unit 3 from coal to 100 percent biomass firing using steam exploded wood pellets.

In February 2015, this unit entered service on the new fuel, making it the first such unit worldwide to employ thermally upgraded wood pellets. The unique properties of the steam exploded pellets enable the use of outdoor storage and handling, similar to the baseline coal firing case. The ability to store, handle, pulverize and combust the pellets with only minor modifications to the plant systems and procedures has enabled the use of a low capital cost project approach that is not possible with conversions that employ traditional white wood pellets.

The conversion of Thunder Bay Unit 3 was executed with a capital cost of approximately $30/kW and has demonstrated the feasibility of this approach at full scale. Observations from the fuel evaluations, test burns and commissioning of this first-of-a-kind project are discussed.

OPG began a significant biomass test program in 2006, in direct response to Ontario provincial regulation O. Reg. 496/07 (August 2007) — “Ontario’s Cessation of Coal Use”. This regulation effectively prohibits the use of coal as a fuel to generate electricity in the province of Ontario as of December 31, 2014. Engineering studies were conducted for all of the OPG coal-fired stations to evaluate the feasibility of converting to natural gas, wood pellets or a combination of these two fuels. However, the economic downturn of 2009 reduced electricity demand in the province. This fact, combined with the addition of several gigawatts of NGCC capacity in the province resulted in a very limited role for the large coal-fired station at Nanticoke (4000 MW) and Lambton (2000 MW).

Conversion efforts then focused on the station in northwest Ontario at Atikokan. This unit is modestly sized at 205 MWe and is in an area of vast forestry resources, making it an excellent candidate for conversion as a peaking unit. The Atikokan unit has been completely converted from coal to biomass firing and entered service in July 2014. The total cost of the Atikokan conversion was about $170M CAD, yielding a specific capital investment cost of some $800/ kW ($CAD).

An Introduction to Advanced Wood Pellets

Concurrent to the efforts at Atikokan, OPG has been studying the potential of upgraded second generation wood pellets. The generic term “advanced wood pellets” describes an array of pelletized woody biomass that have undergone some type of thermal upgrading. The pre-treatment processes and specifics vary but include the use of torrefaction, hydrothermal carbonisation and steam explosion. In all cases, the intention with advanced wood pellets is to provide a fuel with properties that are like coal.

White wood pellets are the dominant fuel choice for the coal-to-biomass conversions. Wood is a relatively clean fuel and the production and logistics pathways to deliver utility scale volumes were already under development to support other markets. However, the use of traditional white wood pellets in a conversion project does require a significant capital investment. Mandatory new systems include covered storage to protect the pellets from exposure to the elements and dedicated receiving and handling systems to control dust generation and mitigate the risk of fires and explosions. These projects also typically require either new milling technology or the modification of existing coal pulverizers to properly and safely handle the wood pellet fuel.

The aim with the development of advanced wood pellet technologies is to produce a biomass fuel pellet that can be employed using existing power station assets with only minor modifications. In this respect, the pellets should be stored outdoors without covered storage so that they can be received, stored and reclaimed from the yard using equipment and procedures developed for coal. This initial item can have an enormous positive impact on the capital cost of a cofiring or conversion project. However, the advanced pellet must be able to weather the elements so that excessive dust is not generated from degraded pellets when they are handled.

Thunder Bay Generating Station

In December 2012, OPG was asked by the Ontario Ministry of Energy to explore the potential to convert Thunder Bay Unit 3 from coal to 100% biomass firing using a low capital cost approach. The Ministry had been previously informed of new developments with upgraded biomass fuels that might be utilised to avoid the high capital costs that are associated with a typical white wood pellet conversion pathway.

Thunder Bay Generating Station is in northwest Ontario, Canada on the north shore of Lake Superior. TBGS Unit 3 has a nameplate capacity of 163 MWe (gross) and includes a four-corner tangentially fired boiler. The boiler is equipped with five RP 783 pulverizers. The boiler was originally designed for Western Canadian lignite coal (Luscar) but was converted to fire Northern Powder River Basin (NPRB) coal in 1996.

Advanced Wood Pellet Fuel Evaluation for TBGS

As of 2013, OPG had already been evaluating upgraded biomass pellets for a period of about four years. Dozens of different samples and suppliers were analyzed and assessed through an internal OPG program and via collaborative efforts with other utilities. The areas of evaluation can be summarised into several categories: Weatherability, Dust Generation, and Milling.

The use of advanced biomass fuels will have other impacts on the unit, similar to the firing of any biomass based fuel. However, these areas highlight the unique differences between standard and advanced pellets. The observations by the OPG project team in each case are detailed below.

Fuel Evaluation — Weatherability

Pellet durability — also referred to as the pellet durability index (PDI) — is the standard indicator of the relative mechanical strength of a pellet. Durability can be determined via many techniques and methods. For the purpose of this discussion, we refer to the standard tumbler method as detailed in ISO 17831-1. The durability metric does not have any direct correlation to performance at full scale in an industrial setting. It is merely an objective, repeatable means to compare the relative quality of biomass pellets with respect to their mechanical strength and ability to resist degradation when handled.

OPG recognised that the standard durability test, conducted on air-dried, pristine pellets, was not a representative measure for pellets that would need to be stored outdoors without the benefit of covered storage. Earlier work by the project team had confirmed that exposure to water was the key mechanism leading to pellet degradation and the production of dust. The biomass power industry has used a number of different methods to simulate exposure to the elements, including climate chambers with high humidity environments and test rigs that simulate actual rainfall. OPG has adopted the use of immersion in water as a simple and objective test that can be conducted by any laboratory, utility or fuel supplier.

The simple weatherability test developed by OPG can be summarised as follows:

• Air dry an as-received pellet sample (at least 2000g) to constant mass
• Determine inherent, surface and total moisture
• Determine as received fines content and durability
• Completely immerse the air-dried pellet sample in distilled water for “x” hours
• Remove pellets from water and strain in a sieve for 5 minutes
• Determine the post-soak total moisture from a sub-sample
• Air dry soaked sample to constant mass
• Determine inherent, surface and total moisture
• Calculate water uptake (initial air dried sample to total moisture of soaked sample)
• Determine post-soak fines content
• Determine weathered durability of post-soak sample

This method will yield a direct comparison of pristine pellet fines and durability with that following a simulated exposure to the elements. It also return a value for water uptake — the absolute increase in moisture content following soaking — that will be an important consideration when milling is discussed.

The obvious question then is how long should the pellets be immersed in water. OPG has conducted trials using durations from one hour to one week in length, tracking an increase in water uptake and pellet degradation with increasing time submerged in water. A duration of 48 hours has been selected by OPG as the rate of water uptake is observed to flatten after two full days of soaking. This level of exposure also provides significant differentiation between pellets of varying qualities in this important area of performance. OPG has also observed a good degree of correlation with lab scale soaking for 48 hours and actual results with full scale outdoor storage over a period of months. This latter result will be discussed further in the operational commissioning section.

Current lab scale methods cannot be expected to predict specific performance in the field, especially for a range of environmental conditions and storage periods. However, the application of objective lab scale methods such as durability – and especially weathered durability — are very useful to compare the relative characteristics of fuels in this area. OPG had already evaluated many thermally upgraded pellets in the 2010-2013 period and initiated a new program to test all promising advanced wood pellet fuels specifically for the Thunder Bay project. Weathered durability was a key metric in this testing, used to identify fuels that would tend to maintain their pellet integrity during outdoor storage in the challenging conditions of northwest Ontario.

Ten samples were tested in this program, eight of which were torrefied wood pellets and two produced via steam explosion. Given the first-of-a-kind nature of the project and the important link between pellet integrity and fuel handling safety, the project team sought to identify pellets with outstanding performance in this area.

This work confirmed the trend for steam exploded pellets to perform significantly better than torrefied fuels when exposed to water. The lab scale weathering of a typical torrefied pellet is compared visually with that of the steam treated pellets selected for the TBGS conversion in Figure 1.

Immersion of the torrefied pellets in water has had a clear and significant negative impact on the integrity of the pellets. Note that the fines metric is an indication of the mass of the sample that is already dust. Significant exposure to water can be seen to produce dust from the original pellets even before they are tumbled again to simulate handling.

With respect to the water uptake value, we suspect that the individual torrefied wood particles are quite hydrophobic. The high level of moisture absorption in the soaked pellet sample is likely due to water accumulating interstitially in the voids between particles that have separated as exposure to water decreases the strength of their bonds.

Some torrefied pellets do perform better than others in this regard and there has certainly been progress in this area in the 2013-2017 period. However, during the time when the fuel selection was being made for the Thunder Bay project, steam treated pellets were seen to have a clear advantage.

Fuel Evaluation — Dust Generation

Wood pellets — including advanced wood pellets — are actually more problematic to handle when they are very dry as the pellets are more brittle and prone to produce dust when handled. In this respect, it is important to evaluate the amount of dust that is generated as well as the particle size of that dust. Finally, the use of water and surfactants as dust mitigation measures should be assessed. This scope of testing was executed on the steam treated pellets that were selected for the project based on their excellent performance in the weathering tests.

An external laboratory was engaged to conduct a third party evaluation on the advanced wood pellets as well as a typical PRB coal as a baseline. The method of dust generation used was a rubber-lined tumbler, operated for 48 hours. This testing also included the determination of the particle size ranges of any dust produced. Table 2 summarises these results.

These results confirm the favourable performance values cited earlier. The relatively small volume of very fine dust is particularly important as this can significantly reduce the risks associated with airborne dust generated during handling. The results for the AWP also compare well with those of the PRB coal. This baseline was important to the project team as the performance of the handling system on coal was both well controlled and well understood.

An additional set of tests was also conducted to evaluate the effectiveness of water and dust suppression agents to mitigate dust generation during handling operations. The lab scale Walker Wetting Test was employed to assess performance in this area. The results are shown in Table 3.

The BT-220W surfactant is the same wetting agent used at Thunder Bay GS for operation on coal. The Walker Wetting test results indicate a significant improvement should be realised when using surfactants to mitigate dust with the advanced wood pellet fuel.

Fuel Evaluation — Milling

The final major benefit of advanced wood pellets is their improved grindability, relative to standard white wood pellets. Several conversion projects (including OPG Atikokan GS) have successfully retrofitted coal pulverizers to handle white wood pellets. However, there are operational challenges, most notably with respect to milling capacity and the final delivered particle size of the wood dust to the burners can create issues downstream as well.

There is the potential to employ advanced wood pellets in an existing system with only minor changes to the physical mill and the operation of the pulverizers. Furthermore, there is an expectation that mill capacity (energy output) of the mill should be improved over the white pellet case and that the particle size of the pulverized wood dust should be significantly smaller, yielding a number of downstream benefits with pneumatic transport and combustion.

Even as early as 2013, the biomass power industry had realised that the standard Hardgrove Grindability Index (developed for coal) was not an appropriate metric to determine the relative grindability of biomass fuels, including advanced wood pellets. As of this writing, new methods are in development but no such tools were in place when OPG was evaluating fuels for Thunder Bay GS. It was decided to use pilot scale mill testing to assess the steam treated pellets in this area as OPG had already employed this technique for a previous white pellet evaluation at Thunder Bay.

Several campaigns of pilot mill testing were conducted at the Alstom Pulverizer R&D centre in Naperville, Illinois. This facility is equipped with a vertical spindle VR 31 mill that uses similar grinding technology to that employed in the full scale RP 783 pulverizers installed at Thunder Bay GS.

Parametric testing included the variation of the bowl rotational speed, roll-table clearance, roll loading pressure, fuel flow, air flow and classifier vane opening. The facility also offers the opportunity to physically modify the mill internals. In this case, the classifier static drum openings were increased to better reflect the full scale case at TBGS. Most importantly, tests were also conducted after the removal of the outlet venturi or discharge skirt (see photo on page 30). This modification resulted in the best performance of the pilot scale program and informed the project team of the potential to modify the Thunder Bay pulverizers in a similar manner.

The use of a pilot milling facility to test wood pellets had many advantages, especially regarding the flexibility to modify the physical configuration and the operational parameters. However, the nature of advanced pellets does result in certain observations that require some degree of interpretation. In particular, specific mill power was observed to be rather high, with values of about 20-25 kW/Mg. This is approximately twice the value that would be expected for coal grinding, using either a pilot scale or full scale mill. Fortunately, this result was actually much more favourable at full scale when grinding steam treated pellets in the modified mills at Thunder Bay.

Safety Evaluations

A standard suite of fire and explosion risk testing was conducted on the steam treated fuel selected for the Thunder Bay conversion project. These results confirmed the increased ignition risk with biomass fuels, compared to the PRB coal baseline experience (Table 4). Concurrent with this effort, third party evaluations of the entire (coal) handling system were conducted to identify issues of concern and areas for improvement.

The review of the handling systems identified many maintenance issues in the areas of containment and dust collection. Furthermore, several components of the system were also highlighted that would benefit from modifications to improve safety by avoiding and mitigating the build up of electrostatic charge. These items will be discussed in the conversion project scope.

Pilot Scale Mill Classifier with Discharge Skirt Removed

The project team was eventually satisfied that dust and ignition hazards had been properly addressed by the proposed modifications throughout the system — with the notable exception of the final drop into the existing coal bunkers. Under certain conditions, the free fall of pellets into the metal bunkers could result in an electrostatic discharge with the potential to ignite wood dust in that confined volume. A dedicated study of this issue was executed to identify possible solutions to the problem.

The electrostatic discharge study determined that the risk of bulking discharges were sensitive to the relative humidity in the environment. The steam treated wood dust was tested in accordance with ASTM D257 — “Standard Test Method for DC Resistance or Conductance of Insulating Materials (Modified)”. This work was conducted at two different levels of relative humidity. The results are summarized in Table 5.

The study concluded that the theoretical threshold value for volume resistivity is 1010 Ω-m, indicating that bulking (or cone) discharges do not occur below this value. The project team elected to utilize the existing bunker inerting steam system to humidify the bunker volume prior to loading pellets. Humidity meters were installed in the target bunkers and fueling operations commenced after the bunker relative humidity was increased to 55+ %RH. This is likely the first such direct manipulation of humidity to control an ignition risk in the industry.

Fuel Selection

Safety has always been the number one priority at OPG and the Thunder Bay project maintained that focus. Given the first-of-a-kind nature of the conversion project and the desire to largely use existing systems to handle and fire the new fuel, the selection of an advanced pellet fuel with excellent performance characteristics quickly became the first critical decision.

The internal OPG evaluation process determined that the steam treated pellets produced by Arbaflame AS (Norway) yielded clearly superior performance in the important areas of durability, fine dust generation and weathering. The Arbaflame pellets were also observed to have clearly superior performance with respect to water uptake when exposed to the elements. Additional testing in the areas of fire and explosion risks, liquid-based dust suppression and pilot scale milling all gave expected or acceptable results.

Concurrent to this effort, OPG also collaborated with several European utilities with their own advanced biomass programs. Most notable among these was Vattenfall who had previously formed their Black Pellet Evaluation Program to investigate the use of advanced biomass fuels in their fossil fleet. Vattenfall had independently selected Arbaflame as the leading candidate and had already conducted several major field tests, including a large scale co-firing trial at their Reuter West station in Berlin.

Consideration of the OPG test results, combined with similar favourable experience from other utilities, resulted in the project team decision to procure 1000 metric tonnes of Arbaflame pellets for a test burn at Thunder Bay in the fall of 2013.

Pre-Test Modifications

A significant amount of maintenance was performed on the existing fuel handling system, addressing items that were identified by third party walk downs of the equipment. In addition, several physical modifications were also executed, again in direct response to issues identified by pre-test safety studies.

• Reclaim Hopper Slide Gate Extension. The slide gate at the bottom of the initial reclaim hopper was extended by the addition of a metal plate (See photo on page 21). The additional length of the gate served to reduce the free flow area of the hopper mouth, limiting the volume of the fuel feed to the conveyor/feeder immediately downstream.
• Electrical Grounding. The existing conveyor and bunker systems were found to be well grounded but additional protection was installed on the dust collectors along the test fuel path. This consisted of providing dedicated grounds to each bag cage (See photo on page 21).
• Dust Suppression. The existing points of dust suppression were used for the test, including the use of the current BT-220W surfactant, at the present level of concentration. In addition, two new surfactant application points were installed and one further point using service water.
• Relative Humidity Meters. The electrostatic discharge safety report recommended that pellet loading to the existing bunkers should only be conducted in an environment with a relative humidity of 55 percent RH or higher. Intrinsically safe humidity meters were installed in the 3B and 3C coal bunkers used to handle the Arbaflame pellets during this testing (See photo on page 22).

The final significant equipment modification was with the pulverizers selected to handle advanced wood pellets during the test burn.

Two of the mills (3B and 3C) were modified to emulate the successful configuration adopted during the pilot scale mill testing. The discharge skirt (or outlet venturi) was removed from these mills to allow for a more expeditious path for fuel to exit the mill. The photo on page 23 shows the discharge skirt in the Thunder Bay mills prior to removal.

The roll-table clearances on these mills were also tightened, based on results from the pilot scale mill program.

No modifications were made to the pulverizer throats (vane wheel) prior to the initial field tests. This oversight will be discussed in the commissioning sections.

Reclaim Hopper Slide Gate Extension

Dedicated Grounding of Dust Collector Cages

Fuel Analysis

The chemical analysis of the Arbaflame advanced wood pellets is compared with the baseline Northern Powder River Basin (NPRB) coal in Table 6. The chemical analyses of the two fuels are actually quite similar, with notable differences in the acid gas precursors (nitrogen and sulphur), as well as the ash and moistures contents.

Of course, the major expected differences in fuel performance are not covered in a basic chemical analysis. The handling and milling properties of the advanced wood pellets were the main focus of the test burn. The 1000 Mg test fuel volume was delivered to site in August 2013 and piled in the yard as shown in the photo on page ??.

This fuel pile was sampled over the duration of the field test period to determine the fines and pellet durability. This is summarized along with lab scale weathering results in Table 7. In the August-September 2013 period, the fuel was stored outdoors as pictured, without the benefit of cover.

Initial Test Burn

As noted previously, several modifications were made to the existing handling system. In addition, the indicated classifier modification was executed on the target test mills only — mills 3B and 3C. These pulverizer levels are located near the bottom of the firing system (A-lowest through E-highest).

The first week of testing involved the testing of each pulverizer on advanced pellets, with supporting mills firing coal. The second week of testing employed both mills on pellets with the goal of evaluating pure biomass firing operation, including unit start up and shutdown.

Handling Observations

The initial loading point for the advanced wood pellets was reclaim hopper #2. The handling operations in the yard were accomplished using normal mobile equipment (as for coal). The photo on page 16 shows a typical loading operation during the first week of testing. The dust cloud formed by the inherent fines in the fuel volume is very apparent. However, it should be noted that this was the only location where airborne dust was observed during the test program.

Relative Humidity Meter

Previous testing by Vattenfall has confirmed the ability to control dust formation at the initial loading point by means of a simple water jet spraying across the mouth of the loading hopper. This additional mitigation was not deemed necessary by the commissioning team at Thunder Bay as the level of dust and the extent of propagation was deemed acceptable.

The favourable dust and handling performance of the pellets was confirmed by sampling at all of the downstream transfer points. To facilitate this sampling, the entire conveyor system was tripped during the initial test day and cross belt samples were.

As noted here, the durability of the pellets is essentially constant throughout the handling system and appears to be unaffected by the falls through the transfer points. The fines performance is also good, indicating that dust generation is limited as well.

As discussed earlier, each of these transfer points was equipped with dust suppression sprays, employing either surfactants or water. The effectiveness of these sprays on the advanced wood pellets was excellent and did not result in a significant moisture pick up. Those results along with the fines data are summarized in Figure 2 on page 24.

In addition to fuel sampling, the test program included dedicated airborne dust monitoring in the fuel yard, all conveyor galleries as well as wearable personal breathing zone monitors for staff working in handling operations. This effort was conducted for pellet handling as well as for similar volumes of NPRB coal.

The air borne dust monitoring results were very encouraging, superior to those for the baseline case handling coal.

The personal breathing zone results were all well below the Ontario Occupational Exposure Limits (OEL) for softwood dust (5 mg/m3), averaging around 0.30 mg/m3 for workers in the fuel yard, including mobile equipment operators.

Taken together, these results indicate the very real potential to employ second generation wood pellets in coal handling systems with relatively minor modifications.

Pulverizer Setup

As noted previously, mills 3B and 3C were physically modified for this test by removing their discharge skirts. The mill coordination curves (fuel-air curves) for these mills were also slightly modified to increase the mass flow of primary air at the lower end of the mill range.

This was done based on white pellet pneumatic transport experience acquired during previous testing within the OPG fleet. The revised fuel-air curve is shown in Figure 3 on page 26.

The biomass mills were also benchmarked with air flow (no fuel) to identify the expected mill differential and motor power for an empty pulverizer. This was done to yield a clean state set of data that was used to determine when the mill was clean following a shutdown.

Following a normal mill shutdown, the cleaning air flow and temperatures were set similar to the values noted here. When the pulverizer differential and motor power approached their “clean” states, the mill was considered to be empty.

Initial Mill Operation

With the boiler stable and operating on coal, the first modified biomass mill was placed into service on September 10, 2013. The classifier vanes were set to fully open (position “0”) for this initial test.

The mill differential and motor power both stabilized very quickly during this first test. However, it was also immediately apparent that the mill was rapidly rejecting fuel through the throat. It was necessary to increase primary air flow to eliminate the fuel rejection issue. The mill did stabilize at the minimum feeder setting with an air flow slightly above the modified coordination curve value.

This reject problem can be attributed to the use of the original mill throat that was designed for operation with air temperatures in the range of about 300ºC. Operation with colder air flows for biomass firing (initially about 120ºC) resulted in a significant increase in air density and therefore a similar drop in air volume and throat velocity. This mismatch was corrected after the initial testing by modifying the free flow area of the throat to better suit the new operating regime.

Mill Classifier Discharge Skirt (prior to removal)

Pulverizer Performance

Parametric testing was conducted on the modified mills, including the variation of fuel flow, air flow and classifier position. A good operational fit was determined at the mid-range classifier vane position 5 (about a 45º vane angle) and the mills was tested throughout the necessary load range.

Mill differential and motor power were both seen to increase significantly when the classifier was adjusted from the fully open position to the mid-range “five” setting used here. This observation was contrary to our experience with pilot scale mill testing, where the variation of the static classifier blades did not result in any significant impact on the solid particle performance.

Also, following the closing of the classifier vanes, mill rejects were observed to increase again. A large positive primary air flow bias was necessary to address this issue, again reinforcing the need to modify the mill throats for this service. The increased demand for air flow is very likely linked to an increase in fuel recirculation with the tightening of the classifier vanes. This was not observed at pilot scale but is certainly the expected trend with coal operation.

Pulverized Fuel Fineness

The industry is still learning what level of fineness is needed for efficient combustion performance when firing biomass fuels in suspension. Experience from existing white wood pellets conversion projects seems to indicate that about 90 percent passing 1000 microns is suitable for well-designed burner systems. Achieving that level of fuel fineness with white wood pellets in modified coal pulverizers is another matter entirely.

The results presented here for advanced wood pellet grinding routinely meet and exceed this threshold for fuel fineness. The commissioning team has instead used the fraction passing 500 microns as the main indicator of mill performance in this regard. This approach is somewhat more conservative and the values observed in this regime display more variation to operational adjustments.

For a fixed classifier position, pulverized fuel fineness is rather flat over the load range of the mill. This level of fineness has been found to result in well-defied, stable flames and a very bright and clear furnace environment. The fuel feed rates tested here are actually higher than the required flows for full boiler MCR with one mill out of service.

Advanced Wood Pellets at Thunder Bay GS (August 2013)

Mill Motor Power

Power consumption is seen to increase with the fuel feed rate and it is likely that motor power will be the load limiting factor in most cases. As indicated above, in the Thunder Bay scenario, the equipment was able to operate at high fuel flows, sufficient to supply properly sized fuel at the original nameplate capacity of the unit.

The specific mill power — expressed as kW/Mg — is also observed to remain relatively constant over the load range of the mill. The full scale results in this area (about 11-14 kW/Mg) are significantly lower than the values determined from the pilot scale rig (22-40 kW/Mg). This favourable variance is thought to be linked to the much higher dead weight and applied force in a full scale pulverizer.

Primary Air Temperature

The primary air temperature entering the mills was limited to about 120ºC for the initial proof of concept testing. A lower temperature was considered to reduce the risk of mill fires with the highly volatile fuel. The specific figure of 120ºC was selected based on OPG experience with white wood pellet milling.

This temperature was found to be suitable during testing, as indicated by the effective drying of the pellet fuel down to the inherent moisture level. Mill performance, pneumatic transport and combustion were all also found to be acceptable.

Unit Start with Biomass

A key objective of the second week of field testing was to evaluate the ability to start the unit on the advanced wood pellet fuel. Up to this point, the unit had been started on coal, with the biomass fuel replacing coal on a unit at about half load. For the first biomass start, the oil ignitors and warm up guns were put into service per the standard protocols, to heat up the furnace and raise boiler pressure.

Mill 3B was placed into service using the same parameters and procedures that had proved successful in the first week of the test burn. However, almost immediately, very high carbon monoxide (CO) levels were observed that did not decrease until well after the mill was taken out of service. Several other attempt were made to start the mill with the same negative results. These unsuccessful attempts included the use of a lower fuel feed rate in an attempt to improve pulverized fuel fineness.

Observations of the grinding roll deflection during these failed starts revealed that the fuel bed was very thin. Another mill start was executed that increased the fuel flow in an attempt to establish a thicker fuel bed. This effort did prove successful as this optimized mill configuration resulted in a minor CO emission spike that reduced to a level of less than 20 ppmv in several minutes. The adjustment of the low load mill fuel flow along with monitoring furnace temperatures prior to the admission of solid fuel has resulted in trouble-free unit starts since this initial issue was encountered.

Steam Temperatures

The initial test series also evaluated the capability of the unit with respect to steam temperatures, as the use of wood pellets in a boiler designed for lignite coal has been shown to result in issues in that area. The steam treated pellets used at Thunder Bay were initially tested at unit loads of about 25 percent and 50 percent MCR. In this range, steam temperatures were indeed slightly lower than for operation on the baseline coal. There was no real attempt to increase temperatures during the initial test burn. The burner elevation tilts were in the zero to 10-degree (up) range.

Combustion Performance

In general, combustion performance during the initial trial with advanced wood pellets was excellent. Stable, bright flames were easily established without oil support, resulting in a clear furnace environment. No burner system adjustments were required.

This image also indicates significant flame detachment on the level “C” burner (the lower of the B/C firing combination). This appears to be directly attributable to the use of higher than optimal primary air flow to control the fuel reject rate during early testing. As discussed earlier, higher primary air flow was required as the pulverizer throats were not yet properly modified.

Observations of the fireside conditions also indicated very little fuel falling into the bottom ash system.

The Thunder Bay Biomass Conversion Project

A project scope for a full unit conversion was developed to fully leverage the performance benefits observed in the initial field trials. The project had a clear focus on safety, with adjustments or modifications throughout the fuel handling system. The major items are listed here.

• 3 additional dust suppression systems (now totaling 7, on all transfer points)
• Metal and heat detection downstream of reclaim hopper
• Reclaim hopper slide gate extension to control fuel flow rate
• Replacement of transfer chute liners with static free materials
• Replace or de-energize any electrical equipment not meeting the required classification of Class 2, Division 2, Group G
• Installation of relative humidity meters in all bunkers
• Addition of an electric boiler to supply steam to the bunker humidification system
• Replacement of the entire M-3 conveyor belt with a conductive material
• Installation of rotary airlocks between the bunkers and feeders
• Removal of discharge skirt from all mill classifiers
• Modification of mill throats to decrease free flow area
• Purchase of a mobile stacker to handle pellets in the fuel yard

By Natalie Teuchert

Power plants are using drones to inspect critical power generation equipment, including firing ducts, catalysts, silencers, tube panels, stack dampers, baffles, heat recovery steam generators and pretty much anything else they can reach. Photo courtesy: HRST Inc.

Battery powered unmanned aerial vehicles (UAVs), or drones are finding applications in an increasing number of commercial industries and the power industry is no exception. Originally more commonly associated with military and recreational applications, drones have expanded their resume to include HRSG maintenance inspections. With increased affordability, advanced maneuverability and some proper lighting, drones have enabled a rapid evolution in inspection capability.

Drone Technology

Along with the reduction in cost, drones, or unmanned aerial vehicles (UAVs), are now being equipped with a growing number of features that makes them increasingly autonomous and easier to operate. By means of sensors and intricate programming, drones can now hover in place in 20+ mph winds, avoid obstacles, fly to a pre-established “home” point, and land with pin point accuracy at a location designated by the operator. Automatic flight paths can even be pre-populated onto a tablet or phone so that the pilot’s role is relegated to simply telling the drone to take off and the drone then does the work all by itself.

View looking down on silencer shows internals in proper position with support intact. Photo courtesy: HRST Inc.

View looking down on stack damper allows blade alignment and mechanical stop position checks. Photo courtesy: HRST Inc.

Camera costs have come down, all while their quality has improved to surpass 4K resolution. A new variety of gimbal attachments allow a larger field of view than previously possible. In some cases, drones can be fitted with multiple cameras to allow the drone to capture views that encompass the whole area surrounding the aircraft.

The improved portability and development of smaller models allow for drone use in tighter locations, particularly useful for HRSG inspections. With proper application and piloting, drones can be a safe and reliable inspection tool that can be used to take the guesswork out of what lies above.

HRSG Maintenance Planning

Some areas of the HRSG are rarely inspected because they are visually inaccessible from the ground which adds a degree of risk to maintenance planning. If there are no problems visible in my bottom burner elements, is it safe to assume that is also the case further up? Is it worth spending tens of thousands of dollars scaffolding with the chance of not finding anything? Situations like these often fall onto a maintenance manager’s desk. Decisions that should be easy become difficult when the cost of scaffolding, manpower and down time get factored in. In these situations, drones are a game changer. Guesswork can be eliminated by utilizing a drone to fly up and assess suspect areas. A 15-minute flight can fill in the blanks and stamp a yes or no on a wide variety of issues. If a concern area is seen when “looking up,” then the drone can help make the “repair now or later” decision. If the drone flies up and nothing is found, then the cost of scaffolding was saved and a good decision was still made to ensure peace of mind.

If the drone finds an issue, the drone can also optimize the cost of repair and decrease the unit’s downtime. If it turns out that the problem is about 1/3 up the height of the duct, scaffolding will still have to be erected to perform repairs, but it can be configured to meet the precise need, for example scaffold can be installed to span the needed ~40ft in height rather than the entire duct. Repair plans can be thought out and materials can be procured while the scaffolding is being erected rather than after. For these reasons, drone inspections can potentially reduce a multiday job to a one-day job with the problem positively identified in 15 minutes.

With equipment aging and maintenance budgets tightening, the ability to reduce inspection times, increase maintenance planning abilities, and having the proper information to know whether or not to spend large sums of money is vital.

History Condition Assessment

Drones continue to prove their worth in one-off unexpected uses, but where they are starting to add even more value is in history assessments. Many plants have opted to perform drone inspections annually or biannually to compare the condition of their equipment over time. The most common location for a condition assessment is the firing duct. Baffle and burner nozzle cracking can be inspected for crack size, location, and any changes from previous inspections. This can help determine when maintenance should be scheduled ahead of time rather than “right now”. If a crack propagated from 1” to 3” in a year, then plans can be made for a repair schedule. If there is no change, the decision can be made to continue monitoring.

“A 15-minute flight can fill in the blanks and stamp a yes or no on a wide variety of issues.”

Other HRSG areas benefit from history assessments as well. Tube bundles downstream of a duct burner can be monitored for any changes in coloration indicative of overheat. Operators can then adjust duct firing accordingly and extend the equipment life. Repairs can be monitored over time to make sure they are holding steady or need to be readdressed. Catalyst fouling can be inspected at all heights to determine when to clean. (Sometimes what appears nice and clean from the floor is in fact heavily fouled as you approach the roof level.) Stack damper blades and shafts can also be better assessed for cracking or deviation in position relative to years past.

The ability to track and plan maintenance based on solid historical information is much better than guessing what’s to come and scrambling to address the unexpected.

HRSG Drone Inspection areas

When HRST piloted our way into the drone business, the main focus was on the firing duct, but plants soon began asking about other sections of the HRSG. The list of areas that could benefit from a drone inspection soon grew. Found below is a sampling of the issues identified in 2017 drone inspections.

Duct burners:

• Cracked and damaged burner baffles
• Coked elements
• Bent or warped igniters
• Missing fuel tips
• Failed flame holder castings
• Debris stuck in the burner face

Tube harps:

• Tube overheat indications at the top of the bundle
• Center baffle damage
• Failing tube ties nestled in the bundle
• Fin/tube damage at tube ties and bumpers
• Tube leak indications

Catalysts:

• Heavy fouling near upper level (appeared clean from the floor)
• Water damage from roof leaking rain water
• Guide pin failures

Others

• Exhaust Flow Turning Vane and Flow distribution plate cracking and support problems
• Stack damper angle iron failed
• Stack damper not against stops
• Outside casing condition

Many of the issues identified required repairs or a monitoring schedule. The majority of the findings would not have been properly identified without the use of UAVs.

Firing duct drone Inspection. Photo courtesy: HRST Inc.

In the case of fouling SCR catalysts, the first catalyst we inspected was just going to be a test. From the floor, the catalyst looked perfectly clean as far up the duct as we could see. After flying about three quarters of the way up, heavy debris was found caking the catalyst. Old liner failures that caused insulation to liberate had been fouling the catalyst without anyone being able to tell from the ground level. It was completely unexpected.

In aging HRSGs with duct burners, downstream tube bundles have begun showing signs of oxide exfoliation that reduces the creep life of the material. What might be minor exfoliation at the floor level can be much worse at the top of the tube bundle due to the upward steam flow having higher temperatures near the roof. Several units have been found with severe damage at the roof level undetectable from the floor. This is an area very rarely inspected that drones can easily access.

Pilot in Command

Flying a drone inside an HRSG requires experience and skill. In the United States, flying a drone outside requires the pilot to be certified by the FAA and know how to follow FAA regulations. While locations inside the HRSG are not regulated by the FAA, in the case of stack dampers, the airspace enters a grey zone. Does the stack damper count as inside the unit or outside? In most cases, drones have cameras on the bottom of their rig which prevents them from looking at what is above. For this reason, typically, the easiest way to inspect a stack damper is by flying from the outside of the stack into the top and peering down at the damper blades and shafts. Since outside airspace does fall under FAA regulations, it’s crucial for the drone pilot in command to have a firm grasp of what’s required to operate. Several parts of the United States are located in unregulated airspace zones that do not require additional authorization, but if your plant falls close to an airport or other regulated zones, permission has to be requested from the FAA. In short, for your drone inspection to be successful, it is essential that your commercial drone pilot knows how to fly and the rules of the sky.

Duct burner nozzle Condition from drone inspection. Photo courtesy: HRST Inc.

Much like obtaining a driving learner’s permit, a drone license is acquired by studying a variety of airspace and operation rules and then taking a written test at an authorized testing center. With a passed result the pilot receives a remote pilot certification card. This ensures that each commercial pilot or remote pilot in command (PIC) knows where they can and cannot legally fly as well as the rules of operation.

Since it is a written test, it does not guarantee a pilot knows how to operate a drone. Each company is left to their own to determine training requirements for flying. This can include a certain number of logged practice flight hours, in-house testing, or training classes with outside companies. The FAA is strict on knowing the rules, but not so much in how pilot flight capabilities are determined.

Most companies are in the early stages of building their drone programs and establishing what they consider a qualified pilot. As far as HRSGs are concerned, flying inside a giant metal box in the dark introduces flight challenges not faced in most non-HRSG drone flights.

When flying outside, GPS location and positioning sensors can keep a drone hovering in an exact spot, regardless of fluctuating wind streams and conditions. Inside an HRSG, those same sensors often fail to function. A GPS signal cannot be obtained through the insulated HRSG casing, and the drone positioning sensors reflect off of the liner metal. If the sensors are left on, the drone may fluctuate positions rapidly as the GPS recalibrates its location during brief moments it’s able to connect. For this reason, the sensors are turned off for most indoor HRSG flights and flying is done manually, leaving the pilot to have to react to drafts and other factors which can impact the flight plan.

Tube condition at 15’ (bottom) and tube condition at 50’ (top) showing possible long term overheat. Photo courtesy: HRST Inc.

When training pilots for indoor flights, pilots should have several hours logged without the use of GPS or added sensors. Manual flying skills are a must.

Along with the FAA rules and tips, a few HRST HRSG flying tips are as follows:

• Practice flying without the sensors and GPS outdoors before attempting indoors
• Get used to flying in a weak to moderate wind without any sensors
• Wear a dust mask indoors so you don’t inhale whatever the drone kicks up off the floor
• Wear safety glasses, preferably spoggles to keep the debris out of your eyes
• As always, wear proper PPE in the event of a crash
• Use propeller guards so small bumps into the liner or HRSG components won’t cause a crash
• Find the proper lighting for the situation. You don’t want a washed out view for inspection or a muddled line of sight

Following these tips, along with having the proper training and knowledge of flight guidelines will allow for safe operation and a successful inspection.

Summary

As strapped maintenance budgets become more common with aging equipment, the need for time and cost-efficient inspections increases. Adding a drone to your regular inspection scope of visual inspection from the floor, targeted NDE and borescope inspection of the water-side components, fills in the inspection void of identifying taller issues. Drone inspections offer a safe, reliable, and affordable way to understand and track the condition of HRSG components in areas unable to be visually inspected from the floor level inspection. Drones are continuously improving. Extended flight times, improved sensors, and quicker outdoor flight FAA approvals are just a few improvements coming down the line. Offering reduced inspection costs, reduced downtime, quicker inspection times, and historical trending data, the drone “boom” isn’t landing anytime soon so now is the time to get on board.

Natalie Teuchert is a mechanical engineer, HRSG inspector and drone pilot at HRST Inc.

THE AWARD for the EPA regulation with the best intentions but the poorest execution goes to the New Source Review (NSR) program. Its vague and imprecise language (such as not defining “routine”) has left the rule subject to political whims.

The Bush EPA attempted to reform the rule in 2002 with common-sense changes (such as pollution control projects) only to have many of those modifications undone by the Obama EPA. One reform which did stick is the ability to conduct post-project emissions calculations by comparing to future projected actual emissions instead of future potential emissions. The benefit is that projected actual emissions will be lower than future potential emissions, therefore making it easier to avoid trigging NSR permitting.

The Trump EPA continues this seesaw by again addressing how to calculate if a modification’s emissions exceed the NSR permit thresholds. However, instead of “reforming” NSR, the current EPA administration seeks to “streamline” the regulation.

On December 7, 2017, EPA Administrator Pruitt issued a guidance memo on NSR for conducting the actual-to-projected-actual applicability test. This memo specifically responds to recent court rulings for DTE Energy Company. The DTE case stems from a 2010 overhaul project at the Monroe coal-fired power plant. Initially, DTE characterized the project as exempt from NSR permitting due to the exemptions for routine maintenance and demand growth. However, EPA initiated an enforcement action arguing that DTE’s emission projections were erroneous. After two trips to the 6th Circuit Court, the rulings determined that EPA could enforce against a company if EPA determined that the company’s predictions of post project emissions were erroneous even when the actual post project emissions did not show an increase above the NSR thresholds.

“The Bush EPA attempted to reform the rule in 2002… only to have many of those modifications undone by the Obama EPA.”

Administrator Pruitt’s 2017 memo makes much of the DTE lawsuits moot by changing EPA’s position on when enforcement actions will occur. Although this memo is “not a rule or regulation,” “does not change or substitute for any law, regulation,” and “is not legally enforceable,” it still provides useful clarification on a confusing, but important, permitting topic. Basically, there are no major changes to the current netting procedure itself, just in the post-analysis scrutiny.

Administrator Pruitt’s memo states that EPA will use its “enforcement discretion” to not second-guess a facility’s pre-project NSR applicability test nor will EPA consider a violation to have occurred unless there is an actual increase in emissions post-project that exceeds the NSR major project thresholds. However, note the following details:

• The facility must perform a pre-project NSR applicability analysis using the calculation procedures in the regulations. An analysis done after-the-fact loses some, if not all, protection. Additionally, check state regulations for any minor source permits that may be required. Coordination and/or communication with state regulators may be required.
• The facility must follow the applicable recordkeeping and notification requirements. Depending on if the net increase is below 50% of the NSR threshold or if it is between 50-100% of the NSR threshold, reports may need to be submitted to the state agency to fulfill the “reasonable possibility” requirements. Reports sent to the state agency would then be open to public scrutiny.
• This memo pertains where applicable state regulations are not stricter than this Federal guidance. For example, Missouri has a law that state regulations cannot be more strict than Federal laws, but California obviously does not.
• The facility is allowed to actively manage post-project emissions to avoid exceeding the NSR major project thresholds. This is a significant philosophical evolution. Given that the window for determining if post-project emissions exceed the NSR thresholds is five years, explicit guidance that EPA will allow active management of future emissions by reducing operation during this critical period opens up options for avoiding NSR permitting but incurring the ire of intervenor groups.
• No permitting action is necessary to make the future projected emissions enforceable.

Following the logic of not second-guessing industry, the Trump EPA may soon decide to apply the same principle to the Best Available Control Technology (BACT) requirements of the NSR program. However, lawsuits tend to span more than the four years between presidential elections. The wise power plant will actively monitor emissions and document each outage with the advice and confidential protection of counsel.