Platte River Power Authority Rawhide Energy Station Unit 1 is a 280 NET MW load unit that in 2016 had a capacity factor of 91.57 percent, the third highest for comparably sized US coal plants. However, such high performance does have a downside – there is very little opportunity for plant operators to gain much-needed experience in efficiently executing startups/shutdowns and confidently managing upset conditions.

Half of the Rawhide Unit 1 operators have less than a few years of experience, and a notable portion of their experienced operators will retire in coming years. When new plant controls were recently installed, the plant knew that to attain true operational excellence from their operators they needed to commit to a formal training and certification program, which in Rawhide’s case meant using a high-fidelity simulator.

Rawhide’s previous experience with simulation proved disappointing in that neither engineering nor operations took full ownership, which resulted in the simulator becoming outdated and unused. This time around, they were determined to chart a different course to extract the most value they could from it. Rawhide chose simulation technology that would not only retain its value as a training tool for the operations staff, giving them a safe environment in which to become adept at handling complex operating scenarios, but could also be kept up to date with industry standards and used by the engineering staff for control logic testing, patch verification and continuous improvement of plant operating procedures.

In less than four months, Rawhide will have conducted over 400 man-hours of operator training and is already seeing significant benefits, including a 44 percent reduction in startup and shutdown time and related fuel usage. Rawhide discusses the value of the simulator from both an operation and an engineering perspective and how it is helping to drive consistency, cultural change and continuous operational improvement.

Rawhide Unit 1 is a 280 NMW load unit that in 2016 had a capacity factor of 91.57 percent, the third highest for comparably sized US coal plants. Headquartered in Fort Collins, Colorado, Platte River Power Authority (PRPA) has long been a proponent of using simulators for training both experienced and inexperienced operators.

Their previous experience with simulation, however, proved disappointing in that neither engineering nor operations took full ownership of the simulator, resulting in it not getting the attention and maintenance required to function properly or be used effectively.

Over the past several years, Rawhide Energy Station has been seeing a relatively high turnover of operations personnel. Half of the Rawhide Unit 1 operators have less than a few years of experience, and a notable portion of their experienced operators will retire in coming years. While good news on almost any other front, the fact that Rawhide Unit 1 runs continuously with very few maintenance issues was a disadvantage to them in terms of operator training. On the positive side, the unit recently completed a run time of 393 days without any forced or planned outages. On the downside, operations personnel were not getting much opportunity to refresh/hone their skills or gain much-needed experience in efficiently executing startups/shutdowns and confidently managing upset conditions. In fact, PRPA had noticed that startups and shutdown times were getting longer and were often inconsistent.

All of this, coupled with the recent change out of their Foxboro controls to Emerson’s Ovation system, convinced plant management that to attain true operational excellence they needed to commit to a formal training and certification program based on high-fidelity simulation. They wanted a simulator that would not only retain its value as a training tool for the operations staff, giving them a safe environment in which to become adept at handling complex operating scenarios, but one that could also be easily maintained and used by engineering staff for control logic testing, patch verification and continuous improvement of plant operating procedures.

Rawhide chose Emerson’s Ovation embedded simulation technology in which the high-fidelity plant models are built with and maintained using the same familiar engineering tools as the DCS, something that would allow Rawhide to more easily maintain the simulator, keeping it current with control logic and other plant changes.

Project Goals

At this point, the project goals were quite clear for PRPA: Implement a new high-fidelity simulator that could a) be used by the operations department to train control room and FGD operators, and b) be used by the engineering and I&E departments for control logic testing, patch verification and development of other skills.

PRPA’s vision was to use the simulator to drive cultural change, consistency in plant operations, and continuous operational improvement.

Project Requirements:

1) The new simulator would need to be on site and ready to use within 12 months.

2) The simulator training room would need to be located as close to the real control room as possible; however, it would not fully replicate the main control room due to cost considerations and the need to make efficient use of the newly built training room.

3) The new simulator models would need to fully replicate the main plant and FGD controls not just for training purposes, but so that plant engineers could also use it to fully test logic, graphics, and patches prior to loading them into the real Ovation DCS environment.

Rawhide engineers also wanted to be sure that they’d have the capability to make simulator tuning and algorithm modifications themselves so that they could avoid the mistakes of the past and keep the simulator current with the real plant, thereby retaining the value of their investment over the long term.

To ensure a successful project, PRPA and Emerson had to work collaboratively, as a single team, toward these common goals and objectives.

Project Implementation

One of the most important factors in the success of the project was having a single, Emerson project manager to oversee the entire project from start to finish — from initial design, to testing, to installation and commissioning. After an initial team meeting held at the Rawhide Energy Station, Emerson began work on creating the high-fidelity models for the unit. PRPA provided Emerson with a lot of information including newly written startup and shutdown procedures to guide them in developing the simulator. Four months later, PRPA attended the first of five two-week verification meetings at Emerson headquarters in Pittsburgh, PA. PRPA opted to travel to all verification and factory acceptance test meetings rather than conduct them virtually because they felt this option provided them with the best environment to work closely with Emerson and develop a solid, long-term working relationship.

Throughout the process, PRPA brought different operations crews to the verification meetings, giving everyone an opportunity to contribute and “own” part of this important project. The rotations were scheduled during a crew’s relief week, maximizing their effectiveness while minimizing disruption to normal work schedules.

The initial plan was for PRPA to make four, two-week trips, but some unforeseen issues required them to schedule an additional two-week trip. Once this bump in the road had been resolved, the process moved quickly and the Factory Acceptance Test went smoothly. The new simulator was shipped to Rawhide in October 2016 and the Site Acceptance Test was completed just prior to Thanksgiving.

“In a quest for continuous improvement, Rawhide plans to continue using the simulator to refine operating procedures and further reduce startup and shutdown time.”

Benefits of Embedded Simulation

Since installation of the new simulator, Rawhide’s engineering department has been able to do exactly what it wanted — test all major logic changes without risk to the actual plant, watching the outcomes as they play out in real-time in the simulated environment. This capability has greatly enhanced their efficiency and contributed to the overall success of the department – not only are they testing logic changes, but they are also able to confidently load Microsoft and Ovation security patches on the real system after testing them in the simulated environment, making it easier and less stressful to keep the control system up to date. The engineering department has also used the simulator as a test bed when making global changes to graphic macros and overviews, saving considerable time and stress while eliminating the risk of a unit trip.

Conclusion

Platte River Power Authority has been quite pleased with the impact that the new high-fidelity simulator has had on their training program. In the first four months, operations completed over 400 man-hours of simulator training and have already seen significant benefits, including a 44% reduction in the time operators require to perform plant startup and shutdown scenarios.

In a quest for continuous improvement, Rawhide plans to continue using the simulator to refine operating procedures and further reduce startup and shutdown times. Rawhide operators are now able to experience operating conditions and malfunctions that most of them had not previously seen.

With the high-fidelity simulator being used as a cross-functional tool, Rawhide is in the enviable position of being able to test logic changes, install patches and determine graphics best practices prior to implementing them on the “real” Ovation DCS. The ability to make changes in a controlled virtual environment without worrying about taking the unit off line is invaluable to PRPA as they continue to drive toward a culture of operational excellence at Rawhide Energy Station.

Editor’s Note: This article is based on a paper presented at POWER-GEN International 2017 in Las Vegas, Nevada.

In 2016, Netflix and YouTube were responsible for more than half of the world’s downstream Internet traffic.1 By 2020, analysts expect bandwidth demands from online streaming services to have grown even larger. In the face of this rising demand, utilities must accept the changes to provide reduced costs and risks to ratepayers.

While significant improvements in data center energy efficiency have been made in recent years, data centers still consume approximately 2 percent of the world’s electricity – and demand for data center services continues to grow.2 These trends, coupled with a shift to the cloud and growth in the “internet of things,” have created a high level of pressure to develop more powerful and efficient data centers – and more of them. This, in turn, is putting greater demands on our nation’s electrical grid. As evidence, the hyperscale data centers being designed today will ultimately require several hundred megawatts of critical power. In the face of these changes, there are certainly challenges to overcome, but utilities that embrace these market trends will succeed in the end.

BUILDING A FOUNDATION FOR SPEED TO MARKET

The two primary concerns of those investing in new data centers today are the cost of power and speed to market. Solutions that get mission-critical facilities online faster with a reliable, low-cost source of power (renewable generation being the highest in demand) create a competitive edge and provide the proper foundation for companies that are in the business of big data.

A utility must first develop an intentional and comprehensive strategy focused on the unique aspects of the mission-critical industry. Ideally, a dedicated team with knowledge of the challenges and requirements associated with successful data center projects will be assembled to develop the strategy, assist with site selection and field inbound inquiries from potential data center customers. Often this team will be organized within the economic development department of a utility. The team should work closely with internal stakeholders to educate them on the industry and identify cost and/or schedule advantages that might be available to potential data center customers. Next, those advantages should be highlighted in marketing collateral and across the utility’s online presence.

To help a prospective data center customer achieve faster speeds to market and/or lower rates, the following questions should be considered:

1. Can incentives or custom tariffs be offered? Can lower rates be justified through other benefits the utility might realize by adding a large load with a high-power factor into its system?

2. Are there opportunities to share infrastructure and/or the costs of developing new infrastructure? Can the utility own the backup generators typically installed at a data center and leverage them when not needed by the data center?

3. Are there areas within the existing transmission system where an added load can provide additional/ ancillary benefits (defer costly upgrades, load balancing, etc.)?

4. What does a typical (or ideal) data center customer look like and/or want? A collaborative approach is recommended to see that their needs are incorporated into the planning process.

The following sections will discuss further the details of each of these questions and other important factors to consider.

UNDERSTAND REGIONAL ADVANTAGES

Do you understand the regional characteristics of your service territory and how you stack up against other regions of the country with respect to the data center market? Are you in a warm or cold climate? Are your large industrial rates relatively high? Do you have a relatively high risk for natural disasters or extreme weather events? If so, it is important to get in front of these potential issues early on by developing mitigation strategies for each of these potential fatal flaws.

For example, a utility client in Kansas that was working on attracting data center loads was immediately assumed by a potential customer to be in tornado alley. However, after review of historical weather data, it was clear that the risk for tornadoes in the utility’s service area was much lower than in other regions of the state and the Midwest in general. The utility decided to get in front of this early on and turn what could have been a red flag into a competitive advantage.

LEVERAGE EXISTING INFRASTRUCTURE

A robust evaluation of area water, sewer, fiber and electric utility infrastructure can prevent data center owners from having to perform costly upgrades and can also expedite the process of obtaining permits and easements. Utilities should analyze their local transmission system to identify which substations have spare capacity that could serve a large load or where geographically diverse feeds to the data center could be economically designed and installed. Similarly, areas with excess generation capacity, such as areas with high wind penetration, that are being curtailed by transmission system constraints should be identified. Adding a data center upstream of the constraints might serve to increase the capacity factor of underutilized generation assets.

Just as important, fiber access routes that are readily available with geographically diverse carrier paths should be identified. Ideally, access to a variety of carrier networks will be available through a direct backbone connection. Low latency into major markets/population centers is another key consideration, especially if targeting a niche segment such as financial services which would prefer to be as close to Chicago or New York as possible.

Lastly, utilities often own and operate their own communication paths and networks. If a segment of a utility’s communication network could aid a data center’s connectivity to a backbone network without sacrificing grid reliability, this could present a large cost savings to the data center owner and/or bring additional sites to the forefront that would not have otherwise been viable. Utilities planning future network upgrade projects might want to evaluate and consider partnering with a data center customer or fiber carrier to identify cost-sharing opportunities and make sure the projects can meet the future infrastructure needs of both parties.

UTILIZE A ROBUST SIT SELECTION APPROACH

The two main drivers for power generation site selection are also the drivers for selecting data center sites: access to the transmission system and ample water supply. This means that the same methods used to evaluate a power generation site can be leveraged to pursue candidate sites for data centers. By evaluating a transmission system’s ability to handle power flows from a generation

source, planning engineers can also determine its ability to handle a load for a data center. For water availability, end use has little impact on the evaluation; therefore, current methodologies can be also applied.

“Those unafraid to explore new ideas and deviate from traditional thinking will succeed in attracting mission-critical loads and the benefits that come with them.”

It is increasingly important to evaluate the variability of power prices between sites. This involves looking not only at the published tariff rates for each utility, but also evaluating potential applicable rate riders, such economic development riders. Additionally, for projects desiring renewable power supplies, the availability of power purchase agreements (PPAs) from renewable power facilities should be investigated and compared to the locational marginal prices (LMPs) in the area to determine if economically attractive PPAs are available.

Locating a data center near a power generation facility – existing or planned – may mean lower development and operational costs. Bringing a data center closer to the synchronous machine will also typically mean an improvement in power quality.

Additional site selection advantages can be found if a utility can identify and guide data center owners to ideal locations for adding loads to the grid. Working together is advantageous to both parties, providing data center operators with the location they desire while protecting the grid from unnecessary and potentially costly load issues.

INVEST IN CERTIFIED SITES

Do you know where an ideal location for a data center within your utility’s footprint would be today? If you don’t have a certified sites program in place, this is an easy way to show data center developers that you understand their needs and will be a good partner in the years to come. Furthermore, it gives a utility an easy way to show how and why their region is ideal for a data center while potentially influencing a data center’s final location to maximize the net benefit to the utility, like locating in an area that reduces transmission constraints or increases a generator’s capacity factor. Data center owners will certainly perform their own due diligence, but a utility with information and answers to a potential customer’s questions at their fingertips will increase the odds that a site will be shortlisted by a site selector versus eliminated from consideration due to unknowns.

BUILD ONE PLANT INSTEAD OF TWO: MICROSOFT AND BLACK HILLS ENERGY CASE STUDY

Does your current integrated resource plan call for new generation capacity in the coming years? By partnering with a large data center customer, you might be able to defer or eliminate the need to build a new plant which will reduce costs and risks to your ratepayers.

An excellent example of this is the collaboration that occurred in late 2016 by Microsoft and Wyoming utility Black Hills Energy. A new tariff was designed that gives Black Hills access to Microsoft’s backup generators to meet its peak demands which will defer, and possibly eliminate, the need for Black Hills to build additional generating resources.

Discussions between Microsoft and Black Hills subsequently led to another innovation, whereby natural gas-fired backup generators were deployed in the data center as opposed to less efficient and more costly diesel generators.

OPPORTUNITY KNOCKS

With electricity sales trending downward (five out of the last eight years) primarily due to increases in energy efficiency, utilities have an unprecedented opportunity to capture market share in the critical power industry based on the growth that is certain to occur in the years to come. Those unafraid to explore new ideas and deviate from traditional utility thinking will succeed in attracting mission-critical loads and the benefits that come along with them:

– Additional revenues and/or plant utilization

– Jobs and economic development in the region

– More predictable load profiles

– Deferred investments in new plants

– Lower risks and costs to ratepayers

With consumer demand for cat videos and online streaming expected to do nothing but skyrocket, it’s clear the time to act is now. A focused strategy that creates a win-win for the utility as well as the data center will prevail in the end.

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Parker Hills is a senior consultant and project manager in Burns & McDonnell’s Business and Technology Consulting Group. He is responsible for providing project development assistance, strategic siting assistance, due diligence assessments, economic analyses and strategic consulting services for a wide range of power, mission critical and renewable energy projects.

REFERENCES

1. Global Internet Phenomena: Latin America & North America. Sandvine. 21 June 2016.

2. US Department of Energy, Lawrence Berkeley National Laboratory. United States Data Center Energy Usage Report. 2016.

By Eric Bateman

Thermal power plant protocols for upgrading turbine-generator units specify guidelines for controlling humidity when the unit’s internal components are exposed during maintenance. For this requirement, desiccant dehumidifiers and supporting equipment deliver the optimal return on investment over other options.

Planned maintenance

The first line of defense in guarding against moisture and corrosion begins with sealing off the work area to avoid ingress of ambient air into the dehumidified space. In addition to shutting off windows, manways and other entryways, openings such as compressor bleed valves are sealed to prevent air exchange between high humidity ambient air and dehumidified air. In some cases, such as with a recent turbine dehumidification project at a Mexican power plant on the Yucatan peninsula (where it rains almost every day during the summer), a temporary enclosure around the turbine and generator is designed to achieve the targeted humidity control. For these circumstances, additional man-hours and assembly time, along with de-assembly after re-commissioning needs to be planned into the project.

During scheduled maintenance, the relative humidity is maintained according to original equipment manufacturers (OEMs) guidelines and the operator’s in-house maintenance criteria. Most power plant operators adhere to industry best practices and protocols for efficiently performing turbine maintenance.

In addition to controlling relative humidity, an efficient moisture removal strategy is also included in any pre-outage planning process because exposure to impurities even at trace levels can damage rotors, stators and other components.

Internal unit components such as generator windings exposed to outside elements during maintenance are susceptible to moisture. Ferrous metals like iron and steel are well known for their corrosion in the presence of moisture. Microscopic and gross corrosion shorten their life and can idle the plant for additional repairs. Desiccant dehumidifiers that can operate off of portable generators can protect metallurgy from more subtle and expensive forms of corrosion. In addition to the turbine and generator, other idled equipment and sub-components within the power plant could also be subject to “standby corrosion,” which can often go undetected under high humidity and stagnant conditions.

Temperature control

During turbine operation, temperature control is also important considering that heat does not distribute evenly over potentially corroded metallurgy, such as what has been experienced with turbine blades. This can result in unsatisfactory vibration. So, the cost of avoiding this problem is justified considering the major damage and forced downtime that can result from prolonged vibration.

With high temperatures and relative humidity, the engineering solution may call for additional equipment to enhance dehumidifier performance, such as when a chiller is used to pre-cool inlet air to the dehumidifier. The chilled water cooling coil removes much of the heat and moisture at the dehumidifier inlet where the moisture is reduced even further by the dehumidifier’s desiccant material. Desiccant dehumidification systems are typically utilized for reducing relative humidity (RH) down to as low as 1 percent RH.

In many cases, targeted humidity levels depend on the client’s in-house maintenance policy. To resolve these challenges, a solution can be engineered for the facility with the exact air flow rates, temperature and humidity settings. In one dehumidification application involving motor cooling, Aggreko’s chiller/dehumidifier-based temperature control system provided a 30 degree temperature differential between outside ambient air and the treated dehumidified air.

This design was limited to one chiller to control costs and included a booster fan to enhance efficiency, resulting in only a one degree temperature loss along the 200 feet of insulated ductwork. As with other temperature control and humidity solutions, once engineers “spec-out” equipment needs, the length of ductwork, location and size of plenums and other factors influencing moisture-free air flow can then be designed into the proposal.

Implementation

Fossil fuel power plants may include areas where moisture is retained much more tenaciously. For these instances, the superior dry environment created by a desiccant can significantly remove moisture, making it possible to greatly accelerate the overall drying and moisture removal process. Desiccants, from 3,000 to 10,000 CFM, can be operated off portable generators. Other powering options include propane, natural gas or steam heating.

Ducting that’s designed to create a “circuit” between the desiccant dehumidifying unit and the exposed turbine-generator requires precise engineering to optimize air flow and overall moisture removal efficiency. Obstacles such as sharp bends as seen when navigating around a maze of contractor equipment must be factored into the design. To maintain efficiency, it may be necessary to use insulated duct to ensure that any condensation that may occur inside the duct does not flow back into the desiccant. In addition, ductwork connected to exact-sized plenums deliver accurate flow rates at steady humidity and temperature settings.

Unplanned shutdowns

In addition to a planned shutdown, unplanned maintenance or a shutdown due to low seasonal power demand may extend for months or even years. This is when primary and auxiliary plant equipment may be subject to extensive moisture damage. Considering these concerns, the industry paradigm is to maintain humidity levels at or below 40 percent to prevent corrosion. Above the 40 percent threshold, industrial pollutants like sulfur dioxide (SO2) accelerate corrosion rates. Corrosion is generated at an exponential rate when relative humidity exceeds 60 percent. So, if the relative humidity of the work space or area surrounding the generator or auxiliary equipment can be restricted to below 40 percent, then equipment can be maintained in a well-preserved condition for start-up.

Dehumidified air keeps components such as boilers, condensers, turbines, rust- free when the plant is shut down. In the case of fossil fuel power stations, layup can be due to furnace, boiler repair or less expensive power availability from an alternate source. During such periods, dry air circulation in the facility prevents rusting and other harmful moisture related problems. Expensive metal parts like rotors, compressor parts, bearings, buckets and blades and gearbox components corrode, while non metallic parts deteriorate.

Special applications

Dehumidification technology can also prevent or reduce corrosion while the facility is operational and supplying electricity into the grid. For example, large volumes of air are required to operate a gas turbine. The power output and fuel consumption of a gas turbine generator are highly dependent upon the flow, temperature and quality of the air drawn into the combustion chamber. Relative humidity and contaminants carried with it influences air quality, which is why dehumidification systems, with filtration and an optional heating devices provide ice-protection, have been especially developed for harsh environments to maintain optimal airflows all year long.

These systems remove damaging contaminants from the air, improving output and extending the effective life of the turbine. The removal of weather hoods and the installation of inlet cooling and dehumidification will lead to substantial reduction in pressure drop through the turbine inlet.

Further efficiency gains can be achieved through the installation of evaporative cooling systems. 

These systems incorporate evaporative cooling, from chillers to air handlers, to cool the incoming air stream. Cooler air has a higher density, boosting the output of the turbine. System-wide benefits include reduced filter changes, maintenance and downtime; extended operational life of the turbine; and increased power generation due to lower air temperature supply and reduced inlet pressure drop.

“Dehumidification technology can also prevent or reduce corrosion while the facility is operational and supplying electricity into
the grid.”

Many of the recent generator unit upgrades have primarily taken place onsite rather than offsite, including repair or rewinding of stators, rotors, excitors, etc. This is why onsite rewinding activities need to be kept moisture free. Without the need for more expensive nitrogen blanketing, desiccant dehumidifiers can achieve very low relative humidity levels within the enclosure housing the unit. Depending on the conditions predicating microscopic level corrosion, the addition of mechanical refrigeration can enhance desiccant performance. The advantages of each type of dehumidification system compensate for the limitations of the other.

Case study

A Texas power plant took a routine outage for maintenance on one of its turbines, where dehumidifiers were installed to blow dry air through both the turbine and generator windings. This costs less and is safer than nitrogen blanketing. For years, the standard practice was to blanket turbines with a continuous flow of nitrogen from external tanks or nitrogen generators. Nitrogen, inert and extremely dry, provides excellent protection. However, providing the volume of nitrogen required to blanket a large turbine for weeks on end is extremely expensive, and working around high concentrations of nitrogen requires safety precautions.

Another alternative, coating the turbine and components with corrosion inhibitors or grease, is less effective and requires additional days of downtime for coating and cleanup. Desiccant dryers that attract and remove moisture from a manufacturing space, are far more effective for corrosion prevention than either wet layup with corrosion inhibitors or preservation in grease. Precise positioning of dehumidification equipment close to the turbine and generator unit undergoing maintenance is important considering the tight space limits and hundreds of contractors working at the plant site during the planned shutdown, such as with this Texas facility.

Considering this challenge, one large desiccant dehumidifier can be used instead of many smaller dehumidifiers with practical setup advantages. The optimal solution for this project included a 2250 cfm and a 3000 cfm dehumidifier with custom-fit plenums for both units to attract and release moisture from high volumes of air surrounding the turbine, stators and windings, leaving exposed surfaces clean and dry while removing any residual moisture in the stators and windings.

Installation and speed of removal also factored into the project’s success. The availability of adequate and reliable temporary power was another concern that had to be overcome and was included in the proposal. The engineering proposal submitted to the client included custom-made elbows and plenums that fit the openings of the turbine inlet and outlet. Aggreko already had a master service agreement with the plant to provide temporary power and climate control support for multiple stages of plant maintenance, so portable equipment was readily available.

Preservation programs

Going forward, as renewable power sources achieve grid parity with fossil fuel based power; there could be an increased need for dehumidification services as more fossil fuel plants are idled when less expensive power becomes available from alternate sources. A recent report from the investment banking firm of Morgan Stanley noted that numerous key markets have reached an inflection point where renewables will become the cheapest form of power generation by 2020, a dynamic they see spreading to nearly every country they cover. Case in point: a thermal generating plant in Brazil was idled for four years when hydroelectric power became more economical.

Until recently, 80 percent of Brazil’s electricity was generated by hydropower, but with reservoirs in Brazil emptying due to an unprecedented drought since 2014, this bespoke thermal plant was re-commissioned and operational in only seven weeks following the four -year outage. Plant availability is reported to be greater than 98% due to a well planned preservation program and close cooperation between the power producer, OEM and service suppliers. A key component of this program was the incorporation of desiccant dehumidifiers.

Similar scenarios are beginning to play out more frequently in North America as renewable-based power generation increases, compelling the idling of thermal generating plants on a more frequent basis, lasting months or even years. Against this backdrop, comprehensive system-wide preservation programs can include boilers (flue and water side), complete boiler houses, and piping and steam turbines that can be efficiently preserved by using dehumidification. In the case of stand-by or idled units, the flue side of the boiler can be protected, as well as the steam turbine. Additionally, all water can be drained away from the water side, and replaced with dry air.

Conclusion

Inevitably, having worked continuously with the central power generator plays a significant role in optimizing continuous high-volume dehumidification, whether for planned maintenance or within the scope of a prolonged preservation program. The repository of information obtained during the course of a master service agreement with the electric utility client for services like temporary power and climate control helps pinpoint the need for people, equipment and processes for impending dehumidification challenges.

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Eric Bateman is the Utilities Sector Lead for the Southern and Central regions of North America at Aggreko, which is the world’s largest temporary power and distribution company.

A quick scan of the headlines in the industry press would suggest energy storage is busting out, as utility scale storage systems are being built to deal with the infamous duck curve, or imbalance of power production from renewable energy. The use of storage will be part of one big happy scenario of cheap, clean power, the theory goes. Every day you can read about another municipality, state or utility that has adopted a 100 percent renewable power grid goal, and despite derailment of the Clean Power Plan, utilities have not altered their renewable objectives. 

A report by research firm GTM Research and the Energy Storage Association that showed utility-scale battery storage installed capacity grew by 221 MW in 2016, or about double that of 2015. Total utility storage is 622 MW. The figures are proof of growth of long-duration batteries and an increased confidence that large energy storage will help manage peak demand, the report argued. GTM analysts predict a 10-fold revenue increase in storage system sales by 2022 to $3.3 billion.

Another report by Navigant Research released in mid-2017 predicted that the global market for distributed energy storage will reach 27.4 GW and $49 billion by 2026.

The premise is that utilities can’t have a high percentage of renewable energy in their system without some storage to have power available when the sun isn’t shining or the wind isn’t blowing. Most peak uses are early evenings and during the hottest parts of the day for air conditioning. If fossil fuel is to be taboo, storage must be part of the answer. 

Considering the above, here’s our question: Why are there not more battery energy storage systems being installed? At the current rate of growth, getting from 622 MW to 27 GW in eight years appears to be an impossibility.

Most of the new storage added last year — 120 MW — was built in California, and that was required by state regulators. Storage isn’t a part of most utility resource integration plans because they have a variety of power generation sources for spinning reserves, demand side management and grid sharing arrangements. 

The simple answer to our question is that storage isn’t cost-effective – yet. Storage costs are falling; therefore, it is frequently prognosticated by many — particularly storage vendors and their associations – that storage will fill the void in the grid created by intermittent output by renewable sources. But is that assumption true? When will storage become cost-effective? The answer is intertwined with the technology that will eventually win out. 

The cost equation 

Storage technology is designed to assist electricity generators both in front of the meter — transmission assistance, peak generation replacement, frequency regulation, distribution substation and distribution feeder — and behind the meter, for microgrids, island grids, commercial and industrial systems and small commercial and residential (Greentech Media). 

Cost is the tripping, rather than tipping, point right now. Stanley Consultants conducted a study for Maui Electric Co. to analyze problems it was having with abrupt power fluctuations in its 180 MW system, 30 MW of which is wind power. Early morning and sunset happen to be when more power is used, when the utility couldn’t count on wind power generation. Engineers evaluated a storage solution, but it was too expensive. The utility decided on fast-starting reciprocating engines to fill the gaps that renewables created. Lithium-ion storage systems have been or are being planned in the islands, but the costs are higher than what might be acceptable on the mainland. 

What type of storage technology is the most viable for wide-scale application? The storage systems in the conversation include zinc, lead-acid, lithium ion, and flow batteries, compressed air, flywheel and pumped hydro. According to the Lazard annual research report, Levelized Cost of Storage Analysis, costs of all these technologies, without taking tax breaks and other subsidies into account, is trending downward, dropping 60 percent since 2012.

Lithium ion technology, led by Tesla and cell phone manufacturers, is in the early winner. Flow batteries show promise, while the rest of the technologies are essentially Cinderellas.

Storage still not competitive 

Without factoring in subsidies, onshore wind is the cheapest form of energy generation, followed closely by gas combined cycle and solar, according to Lazard (2014), which includes capital, fixed operations and maintenance, variable maintenance and fuel costs in its calculations. At about $295 a megawatt hour (MW/h), battery storage comes in on the high side of energy types, surpassed only by diesel generators. A 2016 follow-up study showed similar results, with wind and solar-only much cheaper than solar thermal with storage. 

Storage costs are comprised of the initial and replacement capital expenditure for the batteries, switching and distribution systems and ongoing operations and maintenance costs, including the cost of recharging batteries. For example, most power producers prefer to supply renewable energy directly to customers, rather than recharging a storage system because there’s at least a 10 percent power loss during the process. 

The cost of lithium ion batteries — just the batteries themselves without factoring in other system costs – is about $300 per kilowatt hour (kWh), with a potential floor coming in a few years around $180 per kWh, according to a variety of experts we spoke to at the recent Energy Storage North America conference. This scenario of battery costs — they comprise 40 percent of a system’s total cost – dropping by more than a third has the potential of driving energy storage on both sides of the meter. At the same time, questions remain about how long will they last and their degradation rates. Also, how do you handle the heat load when they are charging or discharging? These are all unresolved cost components. 

Flow batteries are promising, attractive to utilities because of the modular nature of the systems — energy and power components can be sized separately — and their longevity, but material handling and containment is an issue. Overall, venture capital funding for a variety of battery technologies remains strong. 

Storage demand hasn’t reached a tipping point 

Storage isn’t a guaranteed need for most U.S. utilities, which have a variety of power generation technologies in their generation mix. Nuclear, coal, gas and hydroelectric are common sources of stable, baseload generation. For them, storage isn’t in the plan.

For example, while Xcel Energy’s Upper Midwest 2016-2030 Resource Plan calls for providing 63 percent of its generation mix from carbon-free sources and continuing its transition from coal to clean energy including renewables, the plan doesn’t mention storage to complement 33 percent of wind and solar power. It doesn’t have to: Nuclear, hydro, natural gas and coal make up the rest, providing a stable baseload. The scenario is similar, albeit with different generation sources, in the utilities Colorado operations, where it is aggressively pursuing wind and solar power. 

The policy side does not favor storage. Clean energy policies provide economic benefit for renewables but not directly to storage investment. State public utility commissions also provide no consistent means to allow utilities recovery of energy storage costs. Cost recovery varies from state to state. Most state mandates have a “you have to consider it” provision, with no regulatory teeth, for storage. 

Utilities are adding wind and solar generation but not investing in storage because they can “ride the grid” by buying power from the grid. Utilities are thinking about what’s the structure going to look like and getting ahead of the need for storage.

Tucson Electric Power is working towards a 30 percent renewable power base by 2030. It has three storage pilot projects with a combined capacity of 22 MW. The utility said, “We’re also making greater use of energy storage systems, which can boost power output levels more quickly than conventional generating resources to maintain the required balance between energy demand and supply. Such systems are expected to rapidly decline in cost over the next several years.”

“Utilities are adding wind and solar generation but not investing in storage because they can ‘ride the grid’ by buying power from the grid.”

In 2017, Tucson Electric Power signed an agreement to purchase power from a solar-plus-storage system operated by NextEra Energy for an all-in cost less than $0.045 kWh ($45 MWh) over 20 years. The system includes a 30 MW, 120 MWh storage system. This compares to a contract signed by Kauai Island Electric Cooperative for $0.11 kWh for a storage/solar system, far below what it costs to run diesel generators. 

Then, in late 2017, Xcel Energy, when conducting open bidding to replace 650 MW of power that is being produced by its Comanche Units 1 and 2 in Pueblo, Colorado, surprised the industry by receiving 23 bids, which came in at a median price of $38 MWh for solar with storage, and $21 MWh for wind plus storage. The low prices generated excitement in the industry about the future of renewables and storage.

No further action has been taken on the proposals. The bids were made when federal tax credits for wind and solar were at risk in Congress. Since then the U.S. placed tariffs on solar panel imports, which could raise solar costs. Xcel will write its plan based on the bidding process and submit it to regulators in July, 2018. 

The Xcel plan should make an interesting test case. It is one thing to dip an exploratory toe into the storage pool; another to rapidly ramp up its use. A larger commitment by the industry as a whole will depend on the cost-benefit ratio for each utility. 

Is storage a part of a renewable future? 

A renewable energy future is likely to incorporate storage, be it in front of or behind the meter, or used to add backup or other functionality for distributed grids. But how much will utility-scale storage be needed? 

Regulation matters, as we have seen with storage projects required by law in California. Despite regulatory environmental change, cities and states remain committed to a cleaner energy future. According to one report, 27 U.S. cities have committed to powering completely with renewables, and only four cities — Aspen, Colorado; Burlington, Vermont; Greensburg, Kansas and Georgetown, Texas — power all of their electricity with renewables. Southeast Energy News, May 22, 2017. 

The Sierra Club is, of course, taking dead aim at adding the legal stick of binding commitments. It has the goal of adding 100 cities by 2018, with the goal of implementing those commitments by 2035. California (50 percent renewable energy by 2030); New York(50 percent, 2030), Vermont(90 percent, 2050) and Hawaii(100 percent, 2045) have set mandates. 

Even without regulatory mandate, power generation is headed towards renewables. In a KPMG survey of 150 senior energy industry executives, 67 percent of respondents cited the growth of renewable technologies as the most disruptive trend shaping the sector. More than 60 percent of respondents said they believe the U.S. will get half of its power from renewable energy by 2045 or sooner. (Greentech Media) 

Even the wind in the renewable sails does not guarantee storage as an essential component to the future grid, however. Adoption of utility-scale storage will depend on regional and unique circumstantial considerations. Storage makes sense for some — islands, microgrids, heavy wind and solar producing areas, for example — but may not for Eastern and Midwestern utilities where the sun doesn’t always shine and wind is intermittent. Those areas can more easily replace coal fired generation with natural gas to balance their electricity demand loads, based on the current and projected natural gas price forecast.

Conclusion 

The tipping point is what percentage of renewables can a system support without storage? A study by the National Renewable Energy Laboratory concluded that a utility with at least 40 percent of its generation in renewables will need a storage system to provide reliable power. How far away are we from the tipping point? Despite every day headlines of new solar and wind installations, those two forms of generation power just 6.5 percent of the nation’s energy grid (2016 Energy Information Administration). It is a long way from 6.5- to 40 percent of renewable generation, or the battery storage tipping point. 

In lieu of legislative mandate, the predictions of a storage boom are not going to materialize as have been predicted. Utilities can cover load balancing in a reliable fashion with their present power generation fleets. While promising, a utility-scale investment in battery storage is not economically feasible in the current rate structures. A more than 4,000 percent increased investment in highmegawatt storage systems over 8 years is not achievable.

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Charles Spooner is a senior project manager at Stanley Consultants. His experience covers a wide section of the power generation market, including complex, large generation and emission controls projects.

Greek mythology seems to have a story for just about every challenging situation in life. Early this year, the potential resurrection of Yucca Mountain got me to thinking about the Greek myth about Sisyphus. As you may recall from your high school Greek mythology lessons, Sisyphus was a conniving king who ended up condemned by the gods to the underworld, where he spent eternity rolling a boulder up a hill, only to have it roll back down when he reached the top.

Over time, the adjective “Sisyphean” has come to refer to actions that are difficult and ultimately futile. That’s the way I’ve come to feel about Yucca Mountain.

When the Trump administration released its budget request to Congress earlier this year, it included money for the Department of Energy to resume efforts to relicense Yucca Mountain for high-level waste disposal. The earmark received support from the House, but was removed from the omnibus budget bill that ultimately passed. The ongoing and seemingly endless debate around this issue once again highlights how political Yucca Mountain has become.

The state of Nevada is clearly gearing up for a fight. Most of its political leaders — the governor, both U.S. Senators (one Democrat, one Republican), and three of the four U.S. Representatives — are on record as opposing any plan to move the Yucca Mountain repository out of mothballs. A legal defense fund has been replenished. Nevada’s Board of Examiners — a stage entity that reviews expenses authorized by the state legislature — approved a $5.1 million contract in February with an outside legal team to support the state in opposing efforts to resurrect Yucca Mountain.

Moreover, opposition to Yucca Mountain has become something of a political litmus test in Nevada, akin to the support expected from Midwest politicians for ethanol legislation. Political survival essentially depends on it.

The front page of Congresswoman Dana Titus’ web site prominently displays a photo of Yucca Mountain with a statement affirming her decades-long opposition. Congresswoman Jacky Rosen has done her one better, introducing a bill in late April titled the “Jobs, Not Waste Act.” The name says it all. The bill would prohibit the Secretary of Energy from taking any action relating to Yucca Mountain until the Office of Management and Budget conducts a study on the economic viability and job-creating benefits of alternative uses of Yucca Mountain.

Congressman Mark Amodei is one of the few public officials in Nevada who has expressed a willingness to consider moving forward with Yucca Mountain. In return for waste disposal in Nevada, he wants funding for infrastructure projects and more research into the recycling of nuclear waste.

The issue has also wormed its way into the Nevada governor’s race. The current governor, Brian Sandoval, is term limited, but the two leading Republican challengers — Attorney General Adam Laxalt and Las Vegas businessman Danny Tarkanian — have taken decidedly opposite sides on the issue. Laxalt squarely supports continued efforts to oppose Yucca Mountain, promising to “battle the poster-child for federal overreach — a battle over an unwanted nuclear waste repository at Yucca Mountain in our beloved Nevada.”

“The Trump Administration recognizes how important Yucca Mountain is to Nevada and America.”

Tarkanian sees Yucca Mountain as a job creator, a significant tax base, and as an opportunity for Nevada to become a technological leader in nuclear fuel reprocessing. “In pushing to revive the project, the Trump administration recognizes how important Yucca Mountain is to Nevada and America,” Tarkanian said.

I am not going to try to summarize the billions of dollars of technical analysis and scientific research that has gone into characterizing Yucca Mountain as a viable repository for used nuclear fuel. That would be Sisyphean. To stick to the political flavor of this column, though, let me call on Nye County Commission Chairman Dan Schinofen, in whose county Yucca Mountain sits. As reported in an online article in The Spectrum by Lucas Thomas, Schinofen would like to see a more constructive dialogue around Yucca Mountain: “As far as the safety goes, the safety evaluation reports, the reports to the NRC staff, it said the science was sound. I really think they’re preferring political science over nuclear science. I respect we can have a difference of opinion, but we can’t have different facts. And the facts that are in evidence now show that it can be operated and constructed safely.”

Unfortunately, in today’s political climate, it seems like we can have different facts. So what’s my prediction on Yucca Mountain? Not gonna happen. Too much local opposition, not enough federal leadership. So we’ll kick the can down the road again on high-level waste disposal.

Wait…maybe there is another option. Remember the Greek maiden-turned-monster Medussa, she with the snakes for hair? Maybe she can just turn the waste to stone.

TOKYO – Japan’s government proposed an energy plan last month that sets ambitious targets for nuclear energy use in the coming decade despite challenges after the 2011 Fukushima disaster.

The draft, presented to a government-commissioned panel, said that by fiscal 2030 nuclear energy should account for 20-22 percent of Japan’s total power generation. The industry ministry’s draft plan also sets a 22-24 percent target for renewable energy, with the remainder coming from fossil fuels, in line with goals set in 2015. The Cabinet is expected to approve the plan around July.

The targets appear difficult to achieve given that electric utilities are opting to scrap aging nuclear reactors rather than pay higher costs to meet post-Fukushima safety standards. Uncertainty over what to do with massive radioactive waste in the crowded island nation is another big concern.

Nuclear energy now accounts for less than 2 percent of Japan’s energy mix since most reactors were idled after the 2011 disaster. Only five reactors have since restarted.

Japanese utilities have decided to scrap 15 reactors, including six at Fukushima, since the accident, bringing the number of usable reactors down to 39. Experts say 16 more that remain idled are likely to be decommissioned and not being considered for restarts.

Takeo Kikkawa, a Tokyo University of Science professor and energy expert on the panel, said the nuclear target would be impossible to achieve within 12 years unless all remaining reactors are granted permission to run 20 more years past their standard 40-year operational life. Without the extension or building new reactors, Japan will have no workable reactors by 2050.

Less nuclear energy means higher reliance on fossil fuels, contrary to Japan’s emissions reduction pledges, he said. Japan has set a goal of cutting its carbon emissions by 26 percent from 2013 levels by 2030 and by 80 percent by 2050.

SUB SAHARAN Africa’s power generation sector is expanding at an astonishing rate, and there has never been a better time for American companies to participate in this marketplace and be a part of its remarkable growth.

 Home to six of the world’s ten fastest growing economies and with the world’s fastest growing middle class, demand for electricity across Africa is at an all-time high, and rising. Africa’s rapidly urbanizing population of 1.2b people is set to double by 2050, and its terawatt hour consumption is set to quadruple to 1,600 by 2040.

To support this growth and keep pace with the demand, governments across Africa have been reforming their regulatory and business environments to attract more private sector participation from international companies. One such example is the widespread adoption of the Independent Power Producer (IPP) model which accounts for the fastest-growing source of finance for Africa’s power sector (over 120 active IPPs in 2016 alone valued at over $25b).

The continent’s abundant natural resources, including coal, gas, hydro, solar, wind, bio-mass, geo-thermal, coupled with the political will to ensure its energy future, have led to increased cooperation between governments, finance institutions and the private sector. As a result, the majority of infrastructure investment in Africa is focused on power projects, encompassing projects of all types and sizes, from small-scale off-the-grid solutions, to major generation plants, and sophisticated grid and transmission solutions.

While it is no surprise that companies from around the world are being drawn to the continent by the sheer number and scale of the opportunities, the demand for the latest technology, solutions, and skills presents a distinct advantage for American companies whose products and services are very highly regarded. However, many American companies have been slow to approach Africa’s power sector. This is in large part due to a lack of information around the opportunities, a lack of regional knowledge, and an outsized perception of the risks involved in operating on the continent.

Companies hoping to enter or expand their market presence in the African power sector need to look at a variety of factors, from commercial considerations, to legal, political and regulatory environments, as well as financial risks and requirements. Given Africa is notorious for its lack of widely available and reliable data sources, and many African markets are unfamiliar to American companies, those who are active across the continent rely on advisors with local knowledge and expertise to support and guide them, especially on market entry.

A 2018 report by ISI Consultants, a firm specializing in helping American companies grow their business in Africa and the Middle East, highlights the latest generation, transmission, and distribution trends, and discusses many of the risks and bottlenecks companies must prepare for. According to Ian Oliver, Client Services Director at ISI Consultants, “Companies don’t need to go it alone when looking at African markets. In addition to specialist consultants like us, there are a number of government resources available to help American companies.” One example that he cites is the US Department of Commerce which, in addition to its network of Trade Specialists spread across 106 U.S. cities, has 50 staff based in 12 countries across Africa offering a variety of services to assist US companies. “We recently engaged the Advocacy Center at the Department of Commerce on behalf of a client bidding on a local government tender” says Oliver “and it really makes a difference.” Sandra Collazo, Trade Specialist, at the US Department of Commerce explains “The Advocacy Center works tirelessly on behalf of U.S. companies who are bidding on public-sector contracts with overseas governments and government agencies to enhance their chances through a variety of services. This includes activating their network of international commercial offices and diplomatic missions to speak directly to those local governments, including deploying the Ambassador to endorse a company’s product or service and to help ensure fair and equal treatment for US companies in those competitive bids.” In addition, the Commercial Service has Liaisons at the multilateral banks, including the Africa Development Bank, who counsel companies interested in pursuing projects with these international funding organizations.

The power generation sector in Africa is becoming more and more accessible to international companies. Increased private sector participation, more transparent business environments, and a hunger for the latest products and know-how present an opportunity to American companies of all sizes. With the right advisors and the full suite of resources available through the US Department of Commerce, those companies who expand in Africa now will be well-positioned in a sector with a growth trajectory that has no end in sight.

For additional information on U.S. Department of Commerce — Commercial Services programs, go to: http://www.export.gov

2017 WAS A BREAKOUT YEAR for battery-based energy storage in the US electric utility space. With 431MWHr of new capacity added during the year, it nearly doubled the total of existing prior amounts, with the total now exceeding 1GWHr of storage. 2018 should again double the total installation, with the total then to exceed 2GWhr. Both behind the meter and front-of-the-meter areas are growing, and by 2019, the US market for energy storage should exceed $1.2 billion, according to GTM and the Energy Storage Association.

Global markets were just as exciting. Outside of the US, another 1.9 GWHr of storage capacity was added, with Australia coming in second, just behind the US, at nearly 420MWHr of new capacity. Germany, China and Japan rounded out the top five installers, with 380, 330, and 280 MWHr respectively. This is substantial, especially considering the populations of Australia and Germany to be about 8 percent and 25 percent that of the US. There is now enough installed base to provide significant O&M information for the benefit of upcoming owners of such technology. By 2022, this will be a reasonably mature technology, with global deployment totals increasing tenfold between the beginning of 2018 and the end of 2022.

There are several mainstream utility system suppliers currently engaged in projects of 10MWhr and larger. Early in 2018, FERC directed the regional authorities, in the ISO/RTO category, to explicitly define tariffs (i.e. revenue opportunities) for the specific services that energy storage facilities can provide to the grid. These are sure to include fast-response regulation services for load and frequency, spinning reserve, black start, and energy arbitrage.

While battery energy storage systems (BESS) are in the high-growth spotlight, there are alternative technologies which can provide even better ROI for existing traditional plants. Thermal storage of media at both low and high temperatures create interesting opportunities. Storage of sufficient chilled media at just 40 deg-F (5 deg-C) improves the economics, efficiency and output capabilities for gas turbines, replacing simple inlet sprays or chilling systems with a more energy efficient alternative, using easily operated and maintained existing technologies. For the more conservative owners, there’s no need to worry about the risks of a “science experiment” here.

As grid operators prepare for even greater levels of bi-directional power flow, the fast regulation capabilities of storage will be needed to keep the grid stable and responsive. Flywheels added to BESS can amplify fast regulation down to millisecond response times. While not yet ready for primetime, flow battery systems promise greater lifetime and reduced physical footprint over the current technology of choice, lithium-ion batteries, so “stay tuned for further developments” here. Markets for BESS will be decades long, as renewables continue to penetrate, and older traditional coal-fired and nuclear generators age out of national fleets.

“While battery energy storage systems are in the high-growth spotlight, there are alternative technologies which can provide even better ROI for existing plants.”

Now is the time for existing utilities, IPP generation asset owners, and new facility investors to embrace the maturing of storage technologies, the decrease in prices for deployment, and a more promising regulatory environment. Simple paybacks for installations in the most prime areas will easily be less than one year and will typically be in the 1-3 year range. This should stimulate development for new storage elements at existing generation sites, as well as grid-critical substation nodes. Today’s generation asset owners will need to familiarize themselves with the upcoming tariff rates for storage-centric ancillary services, and the new financial opportunities unfolding, in what is expected to be a paradigm shift for “hybridized” sites — those with combinations of traditional generation plus storage. That shift will take place over the course of just the next few years. Those who enter early into these new ancillary services markets will reap the larger rewards by responding with storage installations at the best physical locations to support the grid, from the perspectives of their ISO/RTO.

As a close watcher of trends within the power generation industry over the past dozen years, I feel confident that the changes brought about by deployments of utility scale storage will be as profound as the penetrations of renewable sources and cheap natural gas, and at least as fast.

POWER-GEN International 2018

Expand your experience and attend POWER-GEN International 2018 in Orlando, FL. See what sessions and topics will be explored in the Energy Storage track!