By Editors of Power Engineering

THE WORLD’S first floating offshore wind facility has officially begun production.

The 30-MW Hywind Scotland farm, built 25 kilometers from Peterhead, is now delivering power to the Scottish electrical grid, Statoil reported.

“Hywind can be used for water depths up to 800 meters, thus opening up areas that so far have been inaccessible for offshore wind,” said Irene Rummelhoff, executive vice president of the New Energy Solutions business area in Statoil. “The learnings from Hywind Scotland will pave the way for new global market opportunities for floating offshore wind energy.”

Additionally, Statoil and partner Masdar plan to install a 1 MWh lithium battery storage unit to Hywind Scotland.

The company believes the costs of establishing floating offshore wind will fall significantly over the next decade.

“Statoil has an ambition to reduce the costs of energy from the Hywind floating wind farm to € 40-60 €/MWh by 2030, said Rummelhoff. “Knowing that up to 80 percent of the offshore wind resources are in deep waters where traditional bottom fixed installations are not suitable, floating offshore wind is expected to play a significant role in the growth of offshore wind going forward.”

Precision reverse engineering resolves vibration issues

By Rod Whittaker

OVERHAULING A STEAM TURBINE as part of a planned maintenance schedule is a regular task for many large-scale industrial enterprises that depend on these units to generate electrical power. However, for one pulp manufacturing plant in Eastern Canada, the refurbishment of its 25 MW Stal Laval radial steam turbine would need expert engineering to resolve the vibration issue – the first time this repair has been completed in North America and it would be successfully delivered by Sulzer.

Industrial processes that have high power consumption often use on-site power generation to provide a cost effective power supply, but this entails also providing the necessary levels of maintenance support to keep the turbine operational. In many cases, this will be provided by a specialist service engineering company that has the necessary facilities and expertise to deliver timely repairs and maintenance.

Minimizing repair times

Steam turbines are used around the world to generate power, but the vast majority are of the axial flow design. In situations where radial flow designed units need to be repaired, they are usually shipped to Europe, where they are more accustomed to this design. However, this increases the total repair time, which is a crucial factor when the entire manufacturing process relies on this power source.

Manufactured in the 1970s, the 25 MW Stal Laval radial turbine uses steam that enters along the center-line of machine and expands outwards through two contra-rotating rotors until it reaches the exhaust pipework on the periphery of the turbine. The two rotors, left hand (LH) and right hand (RH) are made up of nine and eight stages respectively and are each coupled to a generator.

Although more common in Europe, radial turbines are also used in marine applications due to their relatively compact dimensions, compared to an axial turbine with a similar power output. Their design means that they are limited to a maximum output of approximately 30 MW, making them more suitable to small industrial generating sets rather than power generation for the grid.

In-depth assessment

Initially, the customer contacted Sulzer asking for assistance with investigating a vibration issue on the steam turbine. Working with the customer, the Sulzer team examined the vibration data and also conducted a visual inspection of the rotors during a brief shutdown period.

Analysis of the inspection showed that the RH rotor had helical linear cracks on all of the steam inlets, both rotors had excessive steam seal clearances and both of the rotor couplings would need to be replaced. Due to the design of the turbine, the only way to repair the steam inlets would be to completely remanufacture the right-hand stub shaft.

As the depth and complexity of the repair became apparent, it was clear that the project would require some of the specialist facilities in the Edmonton Service Center, which has considerable experience in reverse engineering complex components. With the aim of delivering a more reliable and efficient turbine, Sulzer instigated a metallurgical root cause failure analysis of the damaged shaft to determine if there were any design modifications that could be implemented before remanufacturing began.

Even the repair of conventional steam turbines requires a considerable amount of high specification machine tooling and large capacity over-head cranes as well as a highly skilled workforce. When the repair involves an almost unique design, the experience and skill of the engineers really comes to the fore.

Reverse engineering improvements

The Edmonton Service Center specializes in the refurbishment and delivery of performance upgrades for large compressors and turbines. The ability to design and create replacement parts through reverse engineering enables the team in Edmonton to deliver improved reliability and extended service life for a wide range of plant assets.

The initial investigation showed that the material used to create the RH stub shaft could be replaced with ASTM A470 class 7 forging, which is commonly used in the modern turbine industry. The class 7 material has a higher nickel and chromium content, giving it a higher yield strength and better resistance to heat and corrosion than the original.

The new stub shaft was designed, machined, tested and inspected before it was ready for final assembly. In the meantime, the rotors were also refurbished with special attention paid to the steam seals which provide a uniform pressure drop between each turbine stage. The original seals featured an outdated design that was machined out and modified to accommodate the common ‘J-Strip’ seal which was installed and gave a tighter clearance between each stage of just 0.010″.

Precision manufacturing

Finally, the repair team turned their attention to the creation of two new rotor couplings, which connect the turbine rotors to the generators. The couplings are installed using a set of eight high tensile, tapered pins and a series of large, threaded sleeves that together ensure a uniform torque transfer.

The rotor couplings also act as a journal bearing, supporting the overhung rotor. As such, the couplings had to be machined to a very tight tolerance with a high quality surface finish to ensure the perfect fit. The Edmonton Service Center is equipped with modern machining technology that allowed the high precision couplings to be manufactured on time.

At-speed balancing

Once all of the machining was complete, the left and right hand rotors were reassembled, checked for run-out and then low speed balanced in Edmonton. The last operation required the completed rotors to be shipped to Sulzer’s Houston Service Center, where the company has its own at-speed balancing facility.

This crucial process uses vibration diagnostics to analyze the radial vibration at the bearings and ensures that the optimum balance is achieved at operating speed as well as minimizing the deflection and vibration amplitudes during ramp up and coast down.

With the balancing complete, the rotors were returned to the pulp manufacturing plant, where the field service team assisted with the installation and commissioning of the turbine.

Rod Whittaker, Project Manager at Sulzer’s Edmonton Service Center concludes: “Being the first time such a repair has been attempted in North America, there were some considerable challenges in this project, not least the precision machining of the new couplings. Fortunately, our extensive experience and technical expertise has ensured that the turbine refurbishment was completed on time and the generator will continue to provide reliable service for many years to come.”

Rod Whittaker is project Manager at Sulzer’s Edmonton Service Center.

Compressed air is an essential utility in manufacturing processes for all types of power plants ranging from traditional coal to nuclear- or gas-fired power plants, and new-generation solar and geothermal power plants. It powers applications like pneumatic conveying for fly ash, limestone and mill rejects, or dust suppression for coal-handling plants. Because of its critical function, compressed air is often referred to as the fourth utility behind water, gas and electricity.

Factors to consider when selecting your system

With the latest technology innovations, today’s compressor and dryer systems are increasingly more efficient. It’s important to find a system that meets the demands of your power plant so you can take advantage of additional energy savings. As you’re looking at different options, here are some factors to consider:

Quality of Instrument Air

ANSI /ISA – 7.0.01 – 1996 is a globally-recognized standard for instrument air as defined by the Instrument Society of America. As recommended by the Standard, lubricant content in compressed air should be as close to zero as possible because any introduction of oil to the system could cause serious issues like oil carryover in power plant applications.

An increase in flow & temperature also increases oil carryover through downstream filters. At close to 105°F, oil carryover from the oil-injected compressors and high-efficiency filters increases from 0.05 ppm to almost 0.3 ppm. The higher oil carryover contaminates the desiccant of the downstream dryers, leading to a decrease in the dryers’ performance. Water and oil then have the ability to enter the compressed air system where solenoid pilot valves and I/P converters may stick together and potentially trip the entire power plant.

Efficiency

Machine operating efficiency can be significantly affected when oil is introduced to the compressed air system. Oil can force power plants to start and stop their compressor systems, resulting in downtime, increased energy consumption, penalties and lost profits. In worst case scenarios, oil contamination can also force a complete plant shutdown.

In gas-based power plants, gas turbines are particularly sensitive to machine starts and stops because each start and stop reduces the life of the gas turbine. Not only is there machine degradation, but each trip in the system and shutdown results in losses due to potential penalties and lost profits. These penalties are often levied for non-dispatch of power by the transmission companies, which could cost up to $250 per MW. Not to mention, each stoppage could last anywhere from 2-4 hours depending on how long it takes to locate the fault and restart the gas plant.

Let’s take a look at some examples of how much it can cost for an average penalty and its effects on a plant’s profit.

A 750 MW gas-power plant tripping for 4 hours with a penalty of $250 per MW:

$250 X 750 X 4 = $750,000 per stoppage on account of penalties

A 750 MW gas-power plant with a 20 percent profit on the sale of power at an average power cost of 10 cents per MW and a stoppage of 4 hours

$0.1 X 0.2 X 750 x 1,000 x 4 = $ 600,000 on account of lost profits

These costs and penalties are even higher for coal-based plants because it can take up to 16 hours to restart a machine, and large quantities of heavy-fuel oil are required to atomize air and heat boilers to temperatures that auto ignite pulverized coal. It’s important that coal-based power plants consider the additional cost of using residual oil and atomizing air while calculating the risk of oil contaminating the plant’s compressor system.

Power Costs

With oil-injected compressors, pressure loss is a big concern that can greatly increase power costs. Most instruments and actuating valves in an oil-injected compressor require a compressed air pressure of 30-75 psig at its point of use. Once the air has passed through the compressor, dryer and air receiver, the pressure required increases to 90 psig, which means that the compressor must work at 100 psig downstream of the oil-removal filters to maintain this pressure level. Pressure drops are common when air is filtered, which means the pressure at the outlet of the screw element must be 107 psig. As the machine runs around the clock, the separator and oil-removal filters can choke, causing the outlet pressure to increase to 120 psig as the number of operating hours increase.

Unlike oil-injected compressors, oil-free systems do not experience pressure drops as air passes through separators and downstream filters. Oil-free compressors can maintain a consistent 100 psig without using more energy, which can save plants an estimated 10 to 12 percent on power costs. Since these compressors do not require filters or the addition of oil to the machine, regular maintenance checks and services are also less frequent.

Pressure Dew Point

According to the ANSI /ISA – 7.0.01 – 1996, the pressure dew point as measured at the dew point outlet should be at least 18°F below the minimum temperature to which any part of the instrument air system is exposed. Moreover, the pressure dew point should never exceed 39°F.

Ambient temperatures vary widely across the U.S. and throughout the year with low ambient temperatures ranging from -10°F to 50°F and high ambient temperatures from 40°F to 110°F.

Because ambient temperatures are not fixed, a variable dew point of -30°F to 39°F is used based on ambient conditions.

This variable dew point requirement can be met using heat of compression desiccant dryers, which are dew point suppression dryers. Heat of compression dryers require very little additional energy in the form of compressed air or electrical heating. As these dryers use the heat of compression energy to regenerate the desiccant, they can save up to 20 percent of compressed air energy costs when compared to guaranteed dew point dryers.

Conclusion

Power plants can save up to 30 percent on the power costs of compressed air when they select an oil-free compressor with a heat of compression dryer as opposed to an oil-injected compressor with a heatless desiccant dryer. In a typical combined-cycle plant of 750 MW with 3 large, 160 KW compressors, this would save approximately 100 kW. If the system runs for 8,600 hours at a power cost of 10 cents per unit, savings could equal:

100 x 8,600 x 0.1= $ 86,000 per year

Deepak Vetal is product marketing manager (Oil free Screw and Centrifugal Compressors) at Atlas Copco Compressors LLC.

By David Seery

In August, personnel from WesDyne Sweden AB, along with colleagues from WesDyne International LLC (both fully owned Westinghouse subsidiaries), and Westinghouse Electric Company LLC, used specialized robots to inspect all required boiling water reactor core shroud weld seams at the Kernkraftwerk Mà¼hleberg (KKM) Nuclear Power Plant in Mà¼hleberg, Switzerland.

To successfully perform this inspection, the team used WesDyne’s T-crawler robot family, together with a novel time-saving nondestructive testing solution. This solution contributed to completing the work several hours ahead of the planned outage window. This was the fourth such inspection the global team has performed for KKM since 2011.

Meeting the inspection requirements for this core shroud’s weld seams is an accomplishment that speaks to the collaboration between utility, WesDyne and Westinghouse personnel to share needed information, plan, design and implement a solution to an access puzzle that is both effective and economic.

During the 1990s, the weld seams of some boiling water reactor core shrouds were found to have intergranular stress corrosion cracking. This discovery prompted organizations around the world, including the Electric Power Research Institute Boiling Water Reactor Vessel Integrity Program and the Swiss Federal Nuclear Safety Inspectorate ENSI to require that the weld seams of some boiling water reactor cores be thoroughly inspected. For KKM, this requirement must be satisfied every two years.

The Challenge

Determining the extent of indications in the weld seams of core shrouds requires that inspection tools are able to maneuver in and around the reactor core to access the weld seams and acquire accurate and thorough data. The indications can include both axial and transverse (off-axial) intergranular stress corrosion cracking. KKM added a requirement in 2015 to detect transverse indications.

The inspections are performed under water – to depths of up to 80 feet (~25 meters).

The reactor design at KKM also includes internal parts that make access to portions of the welds in the already narrow annulus region of the reactor even more difficult. The reactor internals include jet pumps, instrumentation sense line piping, vertical riser pipes, and the structures that support each of these components. Adding to the challenge are tie rods that were installed as mitigation against potential weld seam intergranular stress corrosion cracking, a modification made to the core shrouds of some boiling water reactors.

The general requirement at KKM is that inspection tools are able to navigate gaps less than 2 inches (5 centimeters) wide, and in certain limited areas, to deliver probes in gaps as narrow as 1 to 1.25 inches (2.5 to 3 centimeters). In addition, the inspection robots are off-camera during significant portions of scanning and movements between areas, requiring careful planning to achieve accurate and full data acquisition.

The Solution

WesDyne had considerable experience performing underwater inspections within the restricted space of the annulus region in other boiling water reactor designs. For other inspections of this nature, WesDyne had developed a family of modular design inspection tools – the T-crawlers – and had been applying these robotic tools since 2006. However, the reactor models for which they were originally designed did not have nearly as many internal structures and, therefore, WesDyne’s existing inspection tooling was unable to sufficiently maneuver around some of the reactor internals presented by KKM’s core shroud to complete the inspections.

WesDyne leveraged the modular T-crawler design to grow the number and variety of these robust and complex robots to meet KKM’s needs, allowing several manipulators to be realized to meet the specific requirements of each examination area, including the areas with very narrow gaps.

WesDyne personnel worked closely with KKM personnel, who facilitated pre-job walkdowns and provided details that allowed the WesDyne team to develop the additional robotic manipulators and plan for the off-camera inspection durations.

Knowledge gained the first time WesDyne conducted these inspections for KKM in 2011 prompted the creation of an additional type of tool for the T-crawler robotic family, the T-hin.

Ultimately, four separate robotic manipulator designs were created, with each tailored to examine one or more weld groups. Two of the designs, the T-horizontal and the T-hin, have both left and right configurations. This feature facilitates parallel examination, working in different directions, along like welds as needed. Some of the robotic manipulators can freely roam the core shroud using suction cups and a well-developed control system. The suction cups are also important for the other designs – the T-horizontal and T-vertical, where they are used as part of attitude (tilt) control mechanics, as part of at least one motion axis, or simply for providing a solid anchor point against an otherwise featureless surface.

While all free-movement, remotely operated robots pose a challenge in determining and tracking accurate and repeatable positioning, WesDyne made procedural adjustments to accommodate the inspection durations during which the robotic scanners would be out of visual camera range at KKM. To ensure the full welds were captured, WesDyne developed procedures for establishing landmark positions using several different techniques at multiple points around the entire weld areas. The quality of the data and weld coverage of the inspections improved with each inspection, allowing highly accurate indication characterization.

The easy-to-handle system requires only a small crew onsite and proved to be a good choice for the job: Not only could the family of robots be grown to accommodate inspection needs, these compact T-crawler robots allow inspections of different areas of the core shroud to be performed concurrently with each other and in parallel with other reactor vessel outage activities.

Once submerged under water, the lightweight robotic inspection systems do not require use of a crane even for larger movements between inspection areas; they can be handled manually with poles and ropes. Additionally, they have a small footprint on the refueling floor and do not require a separate rail system or other bulky support equipment to be installed in the reactor.

Careful planning using multiple probe solutions allowed the field team to configure each T-crawler manipulator so that a single setup in most cases accommodated performing inspections of all of the welds intended without the need to lift for reconfiguration. Once the manipulators were attached and positioned, the scanning moved along quickly, with two systems working in parallel. Since this work was performed concurrently with other preparatory work being conducted on land before immersion in water, the T-crawler manipulator technicians and operators worked closely together. Direct communication and tight coordination was maintained between data acquisition personnel and machine operators, and extended to other groups that performed examination and maintenance activities in the pool and on the refueling floor. Teamwork was very important for staying within the timeframe and completing the work safely and accurately.

Operators using the numerous members of the T-crawler manipulator family interchangeably benefit through use of a single motion control software interface, reducing the risk of human performance errors when switching between the robotic manipulators. The software interface is highly flexible to support the free-roaming movements of the T-scanner robots and is capable of performing the complex scan patterns required for data acquisition. Using code the company had already developed, WesDyne tailored it as needed for KKM’s landmark sightings and special movement patterns.

In preparation for the 2015 inspection, the team continued nondestructive examination technique development, adding and qualifying a novel nondestructive examination solution to cut the time required for data acquisition while also meeting the new requirement to inspect for transverse indications. The approach combined the existing advanced phased-array ultrasonic testing with the more conventional time of flight diffraction technique (TOFDT). Advanced phased array greatly reduces scanning time because it effectively provides very fast additional scan axes by electronically “steering” the ultrasonic testing beam using precisely controlled delays to an array of transducer elements, whereas only single elements would be used in conventional forms of ultrasonic testing requiring slower mechanical scanning. The same dynamic beam-steering also allows different approach angles to illuminate indications, which provides useful detection and characterization information using a single probe, where several would have been needed previously. The use of TOFDT provided an extra degree of accuracy for certain types of characterization needs. Combining the best of these two existing nondestructive examination technologies allowed inspecting the welds for both lateral and transverse indication detection and sizing, including accurate depth determination, within a single scan.

By 2017, following the companywide continuous improvement goals, the team has achieved many refinements to accommodate the access challenges of the weld seams of the KKM reactor core, as well as improvements to optimize data acquisition and inspection efforts. The series of examinations have shown repeatability of the system, providing the data needed by KKM to satisfy regulatory requirements for continued operation of the plant.

The T-crawler system is compatible with all major nondestructive inspection data collection systems and can be adapted for other components with challenging inspection scenarios.

David Seery is a lead engineer for Control Systems at WesDyne Sweden AB.

By Raul Pereda

Natural disasters have hit nearly every continent in 2017. We have seen flooding and monsoons in Southeast Asia, landslides in Africa, earthquakes in Mexico and Central America, and a barrage of hurricanes that destroyed many Caribbean islands and impacted the south and east coasts of the United States.

In these cases, thousands of homes were destroyed, schools were closed, water treatment facilities faltered, and hospitals were shut down. To restore critical infrastructure, reliable power is a must. One underestimated area of destruction that presents a major barrier to recovery is widespread power outage. With our growing dependence on technology and interconnected systems, power reliability is a basic need for disaster-affected communities, right alongside medical care, water, and food.

Consider that even before this year’s consecutive hurricane, flooding, and earthquake devastation, six of the top ten biggest natural disasters worldwide happened in the last decade. In the U.S. alone, the average cost to the economy from weather-related outages is estimated at $18 billion to $33 billion a year, and early estimates of the combined damage from the recent record-breaking storms could reach $290 billion.

It may be difficult to predict when a natural disaster will occur, but governments and municipal authorities can put proactive plans in place to ensure power infrastructure is restored with minimal down time so that citizens are not left in the dark.

An Emergency Power Lifeline

One effective disaster preparedness solution for high-risk areas is a mobile gas turbine generating package that provides quick and reliable power and superior performance for emergency or fluctuating power demands.

Media coverage of disaster relief sometimes focuses on the use of portable, standby diesel or petrol generators. However, for large-scale restoration of municipal power, industrial gas turbines are required and also need to be mobile in order to be effective in emergency situations.

With lower cost than standard industrial turbines and higher efficiency, an emergency mobile package powered by an aero-derivative engine is able to generate 30 megawatts of power, enough electricity to light up to 30,000 homes in times of temporary power loss.

For example, in March 2011, the devastating 9.0 magnitude Tohoku earthquake – one of the largest in recorded history – hit the northeastern coast of Japan. This earthquake and subsequent tsunami caused massive damage to nuclear reactors and infrastructure, causing immediate loss of power and forcing thousands of residents to evacuate. To make matters worse, several other nuclear and conventional power plants also went offline, causing rolling blackouts across several regions in Japan and leaving tens of thousands of people without power for weeks.

Tokyo Electric Power Company (TEPCO) needed an emergency power solution that could be quickly deployed. After assessing infrastructure damage, PW Power Systems provided a 135-megawatt solution utilizing three FT8 MOBILEPAC gas turbine units (25 MW each) and two SWIFTPAC units (30 MW each) that were quickly installed at two TEPCO sites to aid Japan’s relief efforts. Both plants were fully operational and contributing to the national grid with equipment supplied from the United States within 45 days.

More recently, during the holy month of Ramadan in 2015, the Algerian government suffered a series of power outages at its two main generating plants throwing a fasting population of thousands into darkness. Given the importance of this holy time of year, it was crucial for the country’s leaders to restore electricity as quickly as possible. In this situation, four FT8 MOBILEPAC units were completed, commissioned, and brought online in less than three weeks.

Emergency power covers scenarios as diverse as disaster relief, peak periods, and sudden blackouts. Since the first
FT8 MOBILEPAC was deployed in 2004, PW Power Systems has delivered more than 130 units around the world, demonstrating the versatility of mobile turbine solutions. Whether to connect rural African communities in Guinea, restore power at a downed plant in Venezuela, deliver electricity to the Caribbean island of Martinique during a high-season outage, or add capacity to an isolated grid in Algeria to avoid unrest, emergency mobile power solutions have served as a lifeline to those in desperate need.

Powerful Rapid Response Activation

When a pre-commissioned emergency turbine solution is delivered to a site-ready location, it can be generating power in less than 24 hours. For example, the FT8 MOBILEPAC gas turbine package manufactured by PW Power Systems needs little on-site preparation and does not need any foundation or concrete pad allowing for quick installation. In emergency configuration, the unit can be shipped in a single Antonov aircraft for rapid worldwide delivery. The package is comprised of two trailers: one contains the gas turbine, electric generator, exhaust collector, diffuser, and engine lube oil systems, and start package. The second trailer carries the 15 kV switchgear, control system, operation panel, protective relays, batteries and charger, and motor control center.

These mobile gas turbines also produce significantly less emissions than reciprocating engine solutions, making them an ideal fit for environmentally conscious customers and developed markets with stringent environmental regulations.

Faced with today’s seemingly increased threat from natural disasters, reliable and fast-track emergency power solutions are needed more than ever. Furthermore, with increased electrification of developing nations, the world’s energy consumption is predicted to increase substantially. In times of great need, a mobile aero-derivative turbine is a quick-dispatch solution with the ability to deliver the flexibility and performance needed to adapt to rapidly evolving power demands.

Raul Pereda is president and chief executive officer of PW Power Systems.

Close supervision of key milestones aided successful installation

By Larry Johnson, PE

When commissioning completed in August 2017, all those involved with the Ray D. Nixon Power Plant sulfur dioxide (SO2) scrubber and activated carbon injection system project were pleased with the results. The $57 million project was a success: No construction surprises had emerged; no old unforeseen utility corridors or foundations were unearthed and the system worked as designed, all at a significant cost savings.

Colorado Springs Utilities, responding in part to more stringent SO2 limits imposed by the Colorado Regional Haze State Implementation Plan and federal standards, is sending a positive message to its state and community by reducing emissions from the coal-fired plant south of Colorado Springs. By saving an estimated $10 million through a competitive selection process, the utility also showed responsible management to its ratepayers. The story of how the collective team pulled that off is one of careful planning, closely managing and distributing project risk.

“Our contract agreement established a foundation for managing risks and to assign risk to the party best suited to manage the risk,” said Steve Duling, program director for Springs Utilities. “When planning the project, we had discussions on how and when risks would transfer from one party to another.”

Tackling risk with Project Management Institute techniques

The Unit 1 Nixon scrubber project would retrofit its 225-MW coal-fired electric generating unit with a flue gas desulfurization system and a activated carbon injection (ACI) system to control mercury emissions. Along with needing to comply with Colorado’s haze control plan, the other emissions issue was the EPA’s sulfur compliance deadline of Dec. 31, 2017. The new equipment is designed to reduce emissions to less than 0.085 lbs/MMBtu for sulfur and less than 0.8 lbs/TBtu for mercury.

Springs Utilities hired Stanley Consultants to serve as their owner’s engineer providing construction and project oversight. The first task was to generate a performance specification to contract an engineering, procurement, construction and commissioning(EPCC) contractor. Stanley Consultants was also called on to design new transformers, an isophase bus duct, a new fire suppression system and to assist in procuring new ultra-low NOX burners.

The EPCC method of project delivery came with a guaranteed maximum price for the installation of the scrubber. While the EPCC format was followed in principle, the contract in effect could be described as more of a hybrid, where all parties shared various risks at different phases of the project. The owner wanted to place the appropriate execution risk on the EPCC contractor, cap the owner’s cost exposure and still allow the project team to identify and share cost savings while maintaining quality and meeting schedule.

Both Springs Utilities and its owner’s engineer had been trained in Project Management Institute practices and risk management techniques and put them into practice on the scrubber and ACI project. Because of its complexity, negotiating the contract took longer than anticipated, but it ultimately provided a good return on investment.

The owner agreed to bear some of the unforeseen existing conditions risks associated with early project work, such as identifying underground utility corridors, ductwork condition and old foundations.

“As the owner, we believed these were risks most appropriate for the owner to carry,” Duling said. “We carried the contingency until underground was completed. If we didn’t take that risk, the respondents to this RFP solicitation would have to put in the cost of contingency and if they didn’t encounter anything, they would have benefited. Our carrying that risk saved us and our ratepayers money.”

Springs Utilities worked with its owner’s engineer to build a matrix that identified risks associated with each phase of the project, assess the likelihood of a risk event, the potential monetary value of the event and documented mitigation steps for each risk. The risk matrix broke the analysis into the following categories: existing conditions, construction, performance, timing and quality. The risk management committee, comprised of Springs Utilities and the owner’s engineer, met monthly to update the risk matrix and draw down the contingency fund for risks that had passed.

At one point, Springs Utilities held $11 million in contingency money to pay for potential risk events. The team conducted regular risk review meetings. As key milestones passed during construction, the contingency was released as risks were passed or were mitigated. Prior to commissioning, the fund was down to less than $500,000.

“The process was to take the work breakdown structure and identify potential risks and assign values to them. The consortium had some risk; the owner had some,” Duling added.

For example, one Springs Utilities-held risk was obtaining approval of the site development plan from the county and a railroad crossing agreements. It was assigned a potential risk value of $200,000. The mitigation plan was to gather as much information as possible from the consortium team and make sure the applications were complete to prevent resubmittal. The team also stayed in close touch with the agencies having jurisdiction.

All team members played parts in risk management. Engineers directed geospatial surveys, inspected ductwork, fans, panels inside ash bins and decided what to reuse and replace. The inspections had to be carefully planned because of limited outages during which this information could be collected.

Savings shared between owner, contractor

Following the process laid out in the competitive solicitation, Springs Utilities utilized a shared savings agreement based on using value engineering methods. The agreement identified two contract phases, the initial guaranteed maximum price and the final guaranteed maximum price. The initial guaranteed price gave Springs Utilities 70 percent of savings and the contractor 30 percent. During the final maximum guaranteed price phase of project, Springs Utilities received 80 percent of project savings and the contractor 20 percent. Duling credits market conditions as a large factor in the favorable terms achieved through the competitive solicitation.

Overall, construction stayed on time and budget at a quality level that satisfied the owner’s expectations. Duling credits the contractor for its expertise and being willing to rethink their plans when changes were needed. For example, the initial lime recycle system vendor would not hold to its original quoted pricing and another vendor was hired. He said the contractor constantly looked for efficiencies in how they sequenced work. The scrubber and carbon injection system are scheduled to be online by this fall and the plant fully emissions compliant by December.

“We weren’t sure how it was going to play out. There’s so many ways risk was being managed, from us recognizing we didn’t have the resources internally to deliver the project and hiring an owner’s engineer,” Duling said.

“EPCC with an owner’s engineer is just another tool in the tool kit. If it’s the right project; if it’s new generation source or having to put SCRs on, it may warrant this type of approach. You need to plan and analyze where the market’s at and learn the internal drivers that influence your project.”

Larry R. Johnson, P.E., is vice president and senior project manager with Stanley Consultants. His 30 years of experience includes medium and large power generation projects, management of professionals, technicians and support personnel in all aspects of multidiscipline projects.

By Mark Gillespie, P.E., and Ben Erickson

Dating back to the late 1980’s, the principle of inlet chilling has been utilized to increase power output of combustion gas turbines. Since gas turbines are constant volume machines, air mass flow through the unit increases as ambient temperature decreases, increasing power output at colder ambient temperatures. Chilling of combustion turbine inlet air is an effective means to augment existing plant output during hot periods when power demand is greatest.

Duke Energy teamed with Amec Foster Wheeler (now Wood) and installed the Chiller Uprate Project at the Hines Energy Complex, which increased the plant’s summer capacity by over 200 MW net. The Hines Energy Complex (located near Bartow, FL) consists of eight F-class combustion turbines arranged in 2×1 configuration for combined cycle operation with a total ISO site capacity of 1912 MWs.  It is important to note that the four separate power blocks were commissioned at various times between 1999 through 2007, so each block is slightly different than the others.

While various technologies such as fogging, wet compression and evaporative cooling exist to chill inlet air, the Chiller Uprate Project chose to utilize a closed-loop chilled water system. The Chiller Uprate Project scope included the design and installation of a chiller plant, a thermal energy storage (TES) tank, a mechanical draft cooling tower, cooling coils into the combustion turbine inlet ducts, and a closed-loop chilled water distribution piping system. On hot ambient days, the chiller plant works in conjunction with the TES tank to supply chilled water to the combustion turbine inlets, reducing the inlet air temperature to 50°F, thereby recovering approximately 200 MW of “lost” power capacity.

Unique to the Chiller Uprate Project is the scale at which it takes advantage of off-peak power conditions at night to charge the TES tank. The stored energy is then utilized during daytime peak demand to boost power output, in effect creating energy storage similar to a battery.  The TES tank, one of the largest in North America, stores over 17,000,000 gallons of chilled water (over 315,000 ton-hour capacity) and can support 12 hours of full-load cooling operation. During off-peak times (typically overnight), the tank is cooled to 36°F by the chiller plant, which consists of eight 3500-ton chiller units. The system is designed to charge the entire working volume of the TES tank in a 12-hour period.  The tank maintains the chilled water temperature and holds a thermocline, which keeps the warm water from mixing with the cold water during charge and discharge periods.   The stored chilled water, in conjunction with the chiller output, cools the combustion turbine inlet air to increase the output of each combustion turbine anytime the ambient temperature is above 65°F. The system can also be operated in ‘super peak’ mode for a limited time each day, during which the chiller plant is shut down and the TES tank supplies all the chilled water required to reach 50°F inlet air temperatures. This saves approximately 20 MW of parasitic load, further improving plant output during peak power demand conditions.

Chiller System Design at Hines

The chiller system is divided into two main loops – primary and secondary. The primary loop serves two functions depending on the mode of operation of the plant. During ‘charging mode’, the chilled water in the TES tank has been expended and the tank temperature is “hot”. Water is drawn through the diffuser at the top of the tank, cooled by the chiller plant, and pumped back to the bottom diffuser of the tank by the primary pumps. The chiller plant is sized to be able to cool the entire working volume of the TES tank in a 12-hour period. During ‘partial discharge’ mode, the TES tank and chiller plant work together to supply chilled water to the coils at the combustion turbine inlets. The function of the primary loop is to cool approximately half of the hot return water and pump it to the inlet of the secondary pump skid where it is blended with cold water from the TES tank and sent back to the cooling coils. Flow through the primary loop is controlled by a control valve at the outlet from the chiller plant.

The secondary loop serves one function: to pump cold water from the TES tank and chiller plant to the cooling coils at the combustion turbine inlets. Flow through this loop is controlled by eight dedicated control valves – one per combustion turbine. These control valves adjust chilled water flow to each cooling coil, controlling the turbine inlet air temperature (T2) to a desired set point (e.g., 50°F).

The chiller plant consists of eight, centrifugal, duplex, Trane chillers, eight primary pumps (one per chiller), and a central electrical room (including HMI for system control). A four-cell mechanical draft cooling tower provides necessary cooling water to the chillers. The chiller plant equipment is housed in eleven pre-fabricated modules that were fully constructed at the Stellar Energy’s factory before being shipped to site for assembly. Interior walls were removed to allow greater access for maintenance activities, creating one unified chiller plant consisting of an east and west wing (four chillers and five primary pumps in each) as well as a central electrical room. The secondary pump skid houses nine large pumps in a standalone structure nearby.

Another innovative portion of this project is the inlet air condensate capture system. When cooling the hot and humid ambient air down to 50°F, a large amount of condensate is produced (up to 60 gpm per combustion turbine). Rather than wasting this clean water, the inlet coils were outfitted with a condensate capture system. The collected condensate is pumped from each turbine inlet house to a new, 200,000-gallon stainless steel collection tank where it is used for cooling tower makeup. The use of this clean water reduces both cooling tower chemical consumption and externally sourced makeup water.

Technical Challenges

The project is one of the largest combustion turbine inlet air cooling systems including a TES tank installed in the United States. Key challenges addressed in the design and installation of this project included providing a 17 million gallon TES tank with an internal diffuser system, coordination of combustion turbine inlet ductwork modification during planned plant outages, over a mile of underground large HDPE piping in an existing plant footprint, and the implementation of a control scheme to manage the turbine inlet air temperature to meet turbine vendor requirements.

TES Tank Design and Construction

The construction process for the thermal energy storage tank, while not groundbreaking in concept, was challenging in scale. The TES tank measures 215 feet in diameter and over 93 feet in height and includes a liner to inhibit leakage. The tank was constructed by CROM through a process that included erection of a metal diaphragm, application of shotcrete, installation of 700 miles of high strength carbon steel pre-stress wire, and finally the addition of insulation. Effective operation is dependent upon maintaining a thermocline between chilled water and warm return water. This was accomplished with a complex diffuser system designed to slow entrance and exit velocities of the water to reduce mixing effects creating a small region of the tank with a high temperature difference (typically 36°F on bottom and 70°F on top). The internal piping and diffuser required careful designing and planning for constructability. Performance testing demonstrated the diffuser system’s ability to maintain a thermocline thickness of approximately 4 feet.

ALL GOOD stories must have a hero and a villain. At least that’s what my high school English teacher taught me long ago. And while I generally agree with the sentiment for fiction writing, I don’t believe the concept is readily applicable to the nonfiction reality of the power generation industry. In a world where disparate types of generation are required to balance disparate needs – reliability, economics, environmental sustainability – the concept of hero versus villain seems a bit forced. They all can be heroes.

Still, as competitive pressures mount, we are seeing more of the “us versus them” perspective at play. In this reality, a clearer vision, appreciation, understanding, and fear of the opposition could benefit the nuclear power industry and drive needed change.

There is no denying that renewable energy growth, market inefficiencies, and legislative inaction constitute a large part of the threat to nuclear power. The increased competitiveness of natural gas-fired power, however, stands at or near the top of that threat list. And while it’s naà¯ve to think the nuclear power industry can significantly marginalize natural gas (that ship has sailed), the industry can use the ascendancy of natural gas to define a target to aim at. Nuclear needs to aim squarely at the opposition – at getting within the economic orbit of natural gas.

I’ve written in the past about the Delivering the Nuclear Promise initiative and how the U.S. industry is using that effort to enhance the competitiveness of existing plants. In this column, I want to focus on new plants, specifically small modular reactors (SMRs).

An economic analysis performed by SMR Start – an industry group comprising many of the SMR vendors and a few of their potential customers – evaluates the market opportunities and cost-competitiveness of light water SMRs. Not surprisingly, the report paints an optimistic future: “The analysis of various policy and market uncertainties shows that there are many conditions and scenarios that could occur that would result in SMRs being comparable with the costs of a natural gas combined-cycle plant.” OK, so the SMR proponents have clearly named the enemy and are taking aim.

There are caveats, however. The report goes on to state: “By 2030, after the first few plants begin operation, SMRs would be cost-competitive without further private-public partnerships. For most scenarios, the costs of SMRs are within the range of natural gas plants, such that a utility could choose an SMR based on factors such as long-term price stability and fuel diversity.” So parity with natural gas remains the objective, but it might take a while to get there. OK, I can understand that: electricity demand is slack and may not create much of a market for SMRs until the 2030 time frame; the NRC will take some time to approve new SMR designs; and additional research, development, and demonstration will be needed to bring down the cost curve.

So while actions are taken to advance the technology and attack the cost curve, what else can be done to enhance the viability of SMRs? One way may be to look at alternate applications of SMR-based plants. NuScale is exploring at least five alternate applications for its NuScale Power Module (NPM): hydrogen production as a feedstock for fuel and chemicals manufacture; water desalination; hybrid wind/nuclear power production; carbon emissions reduction from oil refineries; and as a source of highly reliable power.

In a September article, World Nuclear News reported on a speech by NuScale Vice President of Regulatory Affairs Thomas Bergman at the World Nuclear Association Symposium, where he shared details on these alternate applications.

For water desalination, NuScale looked at integrating the NPM with each of the three primary desalination technologies – reverse osmosis, multi-stage flash desalination, and multi-effect desalination – and found promising deployment opportunities for each. For example, with reverse osmosis, a single NPM module could produce up to 340,000 cubic meters of potable water.

NuScale also conducted a study with Utah Associated Municipal Power Systems (UAMPS) and Energy Northwest on the benefits of pairing SMRs with UAMPS’ 58 MW Horse Butte windfarm in Idaho. The analysis found that the NPM offers flexibility in adjusting to the variable output of the wind turbines: (1) one or more NPM modules could be taken offline during sustained periods of wind output; (2) reactor output could be modulated in one or more modules to balance windfarm output over intermediate time frames; and (3) steam could be dumped to the condenser to adjust SMR output over short time frames.

These concepts definitely warrant exploration, but they are still on the drawing board. SMRs have a high hill to climb. The natural gas industry will be pursuing cost reductions as well…lack of governmental support may hinder further development…market forces may simply dictate against SMR technology. Still, if SMRs can enable the nuclear power industry to flip many of its conventional disadvantages relative to natural gas – capital costs, construction schedule, flexibility – from negative to at least neutral (and maybe positive), the enemy will have done a great service.