Siemens announced it has successfully tested power generation gas turbine blades produced entirely through metal-based 3D printing, also known as Additive Manufacturing.

The blades, tested under full-load engine conditions at 13,000 revolutions per minute and temperatures above 1,250 degrees Celsius, were produced by Siemens subsidiary Materials Solutions. Siemens purchased Materials Solutions, which specializes in high-performance parts for high temperature applications in turbomachinery, last year.

The tests were conducted at the Siemens testing facility in the industrial gas turbine factory in Lincoln, UK, using a Siemens SGT-400 industrial gas turbine.

In 3D printing, a digital design is fed to a machine that “prints” thin layers of material one at a time. Though 3D printing at the consumer level is frequently done with plastics, Siemens’ blades were made from the powder of a polycrystalline nickel superalloy, and designed with a cooling internal geometry to increase the overall efficiency of Siemens gas turbines.

“This is a breakthrough success for the use of additive manufacturing in the power generation field, which is one of the most challenging applications for this technology,” said Willi Meixner, head of Siemens’ Power and Gas division.

No commercial production date was given for 3D printed turbine blades, though Meixner said 3D printing reduced the lead time for prototype development by 90 percent. The company now uses 3D printing extensively for rapid prototyping, and has already introduced serial production solutions for compressor and combustion components in gas turbines.

The power sector is facing a new reality. It is one we have spoken about in theoretical terms. Hollywood has used it as a scenario in its disaster films, and legislators have warned about it as a potential “Cyber Pearl Harbor.”

The “red lines” that conventional wisdom once held would prevent disruptive or destructive attacks against electric utilities have been crossed numerous times. Given the lack of serious repercussions, we can safely assume they will be crossed again. The notion of cold-war era “Mutually Assured Destruction” as a deterrent force has dimmed and cyber criminals have taken notice.

With Stuxnet, the 2013 New York Dam attack, the 2014 “Sandworm Team” campaign against U.S. electric utilities, the December 2015 Ukraine power-grid attack, and with IBM releasing an end of 2016 report pointing to a 110-percent increase year-over-year in industrial control system attacks, the writing is clearly on the wall.

The threat is growing and the time is now to take serious action to secure the Industrial Control/Operational Technology (OT) networks that light the world.

To do this, we should start digging deeper into the potential pathways adversaries may use to conduct these attacks. We will examine a few scenarios in this article and discuss ways to counter them.

Combined Cycle Single Shaft Generation Unit Anatomy

Attackers are Attracted to Electric Utilities

Electric utilities are a distinct target for threat actors that seek to inflict financial or strategic harm. In the well documented 2015 Ukraine attack, adversaries were able to inflict serious harm with just a multi-hour outage…imagine the harm they could inflict with an outage lasting days?

The increasing interconnectivity between automation control systems and IT networks across power generation, transmission and distribution introduces a growing attack surface within the Electric Utilities ecosystem and introduces a security imperative upon this industry’s key stakeholders worldwide. For the purposes of the attack scenarios in this article, we will focus in on power generation plants but it should be noted that across transmission and distribution the potential for attack is real and growing.

Understanding the Ecosystem in Attack Scenarios

A power generation unit is a multi-component environment, consisting of a core-turbine and generator and various auxiliary systems that handle energy availability and utilization. The nature of these systems varies per the generation unit energy source (i.e., thermal, hydro, etc.).

Our attack scenarios relate to a combined-cycle generation unit. A combined cycle generation unit includes both gas and steam turbines, and uses the excess thermal heat of the former to generate steam for the latter.

Combined Cycle Generation Unit OT Network

The main auxiliary components include:

• Heat Recovery System Generator (HRSG) that captures the excess heat to generate steam from water, and streams it to the steam turbine.
• Condenser that captures the excess steam from the steam from the steam turbine and condenses it back to water. This water is then streamed back to the HRSG for another reheating cycle.

These attack scenarios will focus on a single shaft 1X1X1 unit, in which one gas turbine and one steam turbine share a common generator.

A Look into Potential Attack Scenarios:

The sound operation of the generation unit relies on the integrity of its OT networks that gather, process and take action based on real-time temperature, pressure and flow data.

An attacker seeking to inflict long-lasting damage on a power plant would likely refrain from a movie-style hit and run approach. Indeed, power plants are typically designed with sufficient redundancy to withstand a sudden component failure. Thus the approach taken would be to inflict continuous small scale damage which aggregates over time into severe damage to equipment and plant safety.

An attacker would typically know in advance what systems within the generation unit to target. However, the attacker would try to establish an initial foothold on the most vulnerable point. There are numerous entry point possibilities, from outdated XP engineering stations to misconfigured servers or endpoints that initiate internet-facing communication.

Parallel Bypass Diagram

Upon completion of the initial compromise, the attacker would begin to carefully explore the environment and seek a path to the system it has predefined as the desirable target. As a case in point, it is suspected that the Ukrainian attackers used spear-phishing as a penetration point and then spent months conducting reconnaissance before perpetrating their attack. This path varies in respect to the initial compromise vector, but it will typically include breaching an engineering station and altering the configuration of a controlled PLC.

Attacking the HP Bypass System

The bypass system is a critical component in combined cycle generation units. Its main purpose is to isolate the steam turbine from the flowing steam, which is accomplished by redirecting the superheated steam to dedicated piping leading to the condenser. Steam bypassing is necessary during startup, shutdown or steam turbine trip.

Startup and shutdown require the use of the bypass system due to the difference between the gas and steam turbines. The gas turbine takes a considerably shorter timeframe to achieve full operating speed, versus the steam turbine which should not be started before the metal in the rotor and blades reaches the steam temperature. Thus, the gas turbine excess thermal energy is available to the HRSG steam generation before the steam turbine can accept it. In such a case, the bypass system redirects the generated steam directly to the condenser.

In a similar manner, in a controlled shutdown the bypass system enables the steam turbine to be taken offline at its own pace, increasingly reducing the provided steam load. However, in a case of an emergency trip, the bypass system will be operated immediately in full gear.

The tasks of the control system involve the throttling of the redirection, pressure letdown, and attemperation valves. The orchestration of these operations relies mostly on processing of temperature and pressure data. Typically, the respective PLC set-points are determined and configured upon the initial system setup.

Malfunction of the bypass system directly impacts the generation unit components’ lifespan, exposing the turbine metal to thermal stress and undermining the metal reliability. Another example is a scenario in which the bypass system operates as expected, but a failure occurs in the process of steam attemperation. In this case the condenser will be exposed to steam at a temperature level it is not equipped to handle.

We have now established why the bypass system might appeal to an attacker. In addition, let us remember that this system is not part of the day-to-day routine operation of the power plant, and changes that an attacker inflicts on its respective PLC’s set points will not have an immediate disrupting effect, and thus will likely go unnoticed by the generation unit operators.

Attacking the Bypass Valve

Attack Vector 1: Attacking the Bypass Valve

Object: damage the steam turbine

Method: causing the steam turbine to start prior to metal parts reaching required temperature.

Path: the PLC sends the valve actuator openclose instructions that are based on temperature data it receives from the steam turbine’s IO. Once the metal temperature in the steam turbine reaches the required temperature, the PLC instructs the actuator to open the bypass valve and assume standard steam flow from the HRSG to the turbine.

The attacker alters the temperature set points in the engineering station of the respective PLC, causing the redirection valves to prematurely cease bypass and allow superheated steam to flow into the turbine.

Attacking the Steam Conditioning Valves

Attack Vector 2: Attacking the Steam Conditioning Valves

Object: damage the condenser

Method: allowing superheated and high pressure steam to enter the condenser.

Path: The temperature and pressure of the superheated steam from the HRSG must be reduced prior to entering the condenser. This process is known as steam conditioning, and involves the use of attemperation and pressure letdown valves on the steam prior to its entering the condenser. Steam conditioning is required, because the condenser is initially built for the post turbine excess steam which features significantly lower temperature and pressure levels. Introducing superheated high pressure steam to the condenser would cause aggregated damage to its metal parts.

The PLC controls the throttling of the valves based on steam temperature and pressure data. Similar to the scenario above, the attacker lowers the temperature set points in the engineering station of the respective PLC, causing the spray valve to prematurely cease and exposing the condenser to superheated steam it is not designed for.

Counter these Threats with Deep Visibility into your OT Networks

In both scenarios outlined above, what enables such an attack to succeed is the lack of sound monitoring tools for OT networks. Without visibility into network asset communications attackers can reside undetected, learn the network layout and system behavior and gain the knowledge to inflict harm. Having visibility includes, for example, knowing when a high-risk change to a set point on a key PLC happens. But it also includes visibility into the actions and activities of an attacker before the attack – when the adversary is trying to investigate the environment and move laterally to the target. There is a great deal of discussion at current surrounding Deep Packet Inspection for OT networks – as exemplified by recent discussions at the annual S4 conference. Look into these security solutions for your networks – because you should have a deeper level of visibility into what is going on within them than your adversaries.

By Rajan Chudgar and Dan Gabaldon

There is a reason for the seemingly endless series of conferences and press releases on energy storage, and why the topic is near the top of the agenda for many energy and facility managers across the country. In the last three years, more energy storage has been deployed in the U.S. than the previous five years combined

Convergent Energy + Power worked with Central Maine Power to install a 3-MWh battery asset engineered by Lockheed Martin. A single energy storage system can yield multiple, complementary sources of value, known as “value stacking.” Photo courtesy: Convergent Energy +

This growth has been fueled by a 50 percent decrease in storage system costs over the last two years, combined with ample regulatory support at the state, regional, and federal level, as well as an explosion of commercial activity by start-up and more established energy storage system developers.

The potential benefits for commercial and industrial facilities are significant and multiple. The most common application of behind the meter (BTM) energy storage systems today is to reduce demand charges.

They can also be used to participate in demand response programs, saving facilities the need to respond to load curtailment events with reductions in facility activities, or relying on – increasingly environmentally challenged – diesel-fired back-up generation units. Others employ energy storage systems to reduce process wastes due to “unclean” power, and eliminate bothersome momentary power losses that cause industrial process control systems to reset. With growing momentum in many states to reduce the value of exports of excess PV production (i.e., net metering) and to boost demand charges, energy storage systems are increasingly being paired with PV systems to maximize their value and protect the investment from changing regulatory regimes. Energy storage systems can assist utilities in stabilizing severe grid issues that could create sustained power outages. And this list doesn’t begin to exhaust the sources of value from energy storage that commercial and industrial users are exploring. Perhaps most intriguing, advances in energy storage system software enables the capture of multiple sources of value (known as “value stacking”) from a single installation.

This in a nutshell is the promise and challenge of energy storage. It is a highly flexible tool for addressing a multitude of economic and operational issues, but it is complex and rapidly evolving. How should energy and facility managers act to start taking advantage of this new resource?

The term itself requires a bit of explanation. Energy storage, in general, is defined as the ability to store energy using thermal (e.g., chillers), electro-mechanical (e.g. Flywheels) or electro-chemical (e.g. Li-Ion batteries) solutions. While thermal and electro-mechanical solutions can be a good fit for a some applications, the industry buzz and growth is primarily due to rapid technical and economic advances in electro-chemical systems, which in turn are being propelled by developments in the transportation and computer hardware sectors. Within the electro-chemical space there are a large number of chemistries, each with pros and cons with respect to parameters such as capacity, discharge duration, energy density, (“roundtrip”) efficiency, ability to cycle without deteriorating system efficiency and capacity, safety and environmental risks, and overall cost for a given application.

Currently, the most widely applied chemistries are Lithium Ion, Zn, Vn, and sodium.

Not surprisingly, given the combination of a profusion of rapidly advancing technologies, applied to rapidly evolving set of overlapping and complementary use cases, the potential for confusion is high! Where to start? How much are the real costs? Should one buy, lease, enter into a PPA or explore some other structure for procuring an energy storage system? Is best to buy components and integrate them oneself or buy an already fully configured system? Which single or combined applications make sense for your facility, and what are the financial paybacks? Are there subsidies that one can apply to reduce the cost of energy storage? What are the operating and commercial risks? What types of warranties and insurance products are available, and at what price? What are the practical implications for permitting and installing a unit? How will it interact with existing energy/building management systems? Who are the market leaders in energy storage?

How to get started?

Many experts like to compare energy storage to a Swiss Army knife. It can do lots of different things, so the place to get started is to understand how your underlying energy management needs map on to its range of capabilities. One can bundle the various services energy storage is capable of providing into four basic sets use cases:

1. Economic value: The energy storage solution is going to drive down my overall electric costs. This may be realized by some combination of reducing peak demand, shifting load over time, or increase my revenue by enabling me to participate in demand response or other wholesale market programs. The magnitude and mix of these different value streams will naturally depend on where your facilities are located and the applicable tariffs and wholesale power programs in which you can participate and your load shape, including integrating other distributed energy resources available to your facility (behavioral or automatic load reduction, fossil-fired or PV distributed generation, etc.)
2. Reliability value: The energy storage solution is going to reduce potential brownouts and/or blackouts and be a bridge to potentially other generation sources for long term outages
3. Power Quality value: The energy storage solution is helping with voltage, frequency or other dynamic power quality problems that are causing damage to my systems or processes
4. Green value: The energy storage system complements other green solutions (e.g. solar or wind) to increase the value of the “green” system – such as enabling you to store excess on-site power production for use during other times of the day, or to times when you can “clip” high cost demand charges or offset high time-of-use prices for grid supplied energy – and further reduce my carbon footprint.

Note that in many cases a single energy storage system can yield multiple, complementary sources of value, known as “value stacking.” Storage systems can use smart software packages to enable a system to provide multiple sources of revenues and savings, while also providing the user enhanced reliability.

Once you have determined your primary use case, the next steps naturally including configuring the right system to address that use case, deciding how to contract for the energy solution, and perhaps most simply and essentially, finding the right team – or teams – to work with to design, install, and possibly operate and finance your system. Here are some simple lesson learned and tips you should consider as you move forward in your energy storage adventure:

System configuration: The most fundamental issues include understanding how much peak power capacity you want to be able to store, how long you need the battery to discharge, and the number of times it will need to “cycle” (from charge to discharge) over the course of its life. In general, today energy storage is most economical for discharge periods of four hours or less.

Be sure you understand how your electric bill and potential revenues will respond to how you actually plan to use the system, today and into the future. Do take into account the full costs of actually installing the unit, including seemingly mundane items like the cost of the housing of the storage unit and the potential cost of changes to the local distribution system. Understanding the implications of adding for your existing building management system and other forms of distributed energy resources (PV, back-up generation and UPS, automatic demand response systems, etc.) is also critical to getting the design right for capturing maximum value and minimizing risk. And most energy storage users are well aware of how critical is to get the software solution for the system right, including ensuring it provides the level of load and market forecasting, as well as integrating storage with your load and other DER equipment to optimize value.

Additional practical considerations may include, size and weight, safety factors, subsidies, your current and expected electricity rate and structure, warranties and performance guarantees. As Enovation Partners and Lazard have illustrated in great detail with their “Levelized Cost of Storage” studies, specifying exactly what kind of capabilities you desire for your energy storage system can have a material impact on the cost and investment return you can expect

Ownership options: As in the case of PV and other energy assets, there are a wealth of options for accessing energy storage. Do you want to own, lease, or get a performance contract? Each of these options will have a relationship to the key use cases and your appetite for different types of risks and rewards. For example, large and sophisticated users with abundant and low cost capital may prefer to own the energy storage unit outright, while others may prefer the convenience of employing a Power Purchase Agreement (PPA) as they do with PV installations, while others may prefer a shared or guaranteed savings contract, similar to the approach taken to funding energy efficiency programs Keep in mind the primary use case for you should always be the key performance characteristic for any ownership option.

Supplier choice: The downside of participating in a vibrant, rapidly advancing field like energy storage is that the field vendors and solutions providers are rapidly changing, with often limited and/or hard to compare track records and claims of expertise. Finding the energy storage solution and vendor that best suits your needs – including your needs for financing and addressing different commercial risks – requires more than simple price comparison. The technology is new, so it’s more critical to find the right people – with practical, real experience with energy storage – than relying on otherwise familiar name brands. It pays to do a bit of “homework” on the team to understand the applicability of their experience to your situation; different markets/use cases require different skills and experience. Get a clear understanding of the range and level of responsiveness to issues you can expect from them, and the depth of capabilities (operations, dispatch, design, financing, degree of integration required) they will bring to you. And do not hesitate to check references!

Contracting: Even though the industry is new, you should expect increasingly robust insurance and warranty options, with critical terms now much better – though still imperfectly – defined and priced. If financing is important for you, keep “bankability” on warranties in mind; be sure you understand the technical, regulatory, merchant risks you’re taking. There is also a growing array of specialized service providers with whom you can contract to provide services like testing, unit dispatch, and maintenance should you choose to outsource these services.

Don’t let the complexity put you off. Energy storage is rapidly becoming a standard element of the energy management planning tool kit. While it will require some initial investment to understand the technological and commercial basics, we believe it will be well worth the effort.

Authors
Rajan Chudgar is president of Viridity Energy. Dan Gabaldon is managing director of Enovation Partners.

Today’s U.S. power market continues to shift away from large baseload centralized coal-fired generation for multiple reasons, including low natural gas prices. Renewable generation continues to rise and is becoming a significant portion of many power producers’ portfolios. In areas where energy from decommissioned centralized units is being replaced with renewables, the demand for small, fast responding, simple cycle, natural gas or dual fuel, peaking capacity is increasing. Reciprocating Internal Combustion Engine (RICE) technology has been gaining popularity as a primary power generation resource since it offers the flexibility to meet these needs. This article will provide answers to frequently asked questions related to this technology and identify a few consideration items.

RICE Technology offers several advantages over combustion turbines, making them a very attractive option. Photo courtesy: MAN Diesel & Turbo

Isn’t RICE a New Technology?

RICE technology dates back to the 1800s. Outside the U.S., RICE units operating on liquid fuel are commonly used for power generation with sizes ranging from several kilowatts to over 40 MW. In the U.S. power market, internal combustion engines have historically been limited to small emergency services such as backup generators or pump drives. Recently, medium speed natural gas or dual-fuel capable RICE units in the 9- to- 18-MW range have been gaining popularity for various applications.

What are the Common Applications for RICE Technology?

Power generators (utilities, municipalities, cooperatives, IPPs) as well as industrial users and institutions are considering RICE technology for various services. These services generally include:

Peaking Capacity: Provide peaking power at a high efficiency to reduce fuel costs.

Backup for Renewable Generation: Power output from renewable resources can vary significantly over a short period of time. A fast responding highly efficient resource that is also capable of starting/stopping frequently is required for this load following application.

Black Start Capability: Small RICE units have historically been utilized for emergency backup generation. Larger units may be utilized to black start a facility since they rely on few auxiliary systems to support startup.

System Regulation / VAR Support: With large rotating (coal) generators being removed from service and more renewable (PV) based power flowing through the transmission system, RICE units can be a cost effective option for regulation / VAR support.

Distributed Generation / Microgrid: This application relies on the generation being located close to the load. The loads are generally small, ranging from hundreds of kilowatts to about 100 MW. The small size and modularity of RICE units makes this an attractive technology for this service.

Cogeneration/Combined Heat & Power (CHP): The waste heat from RICE generation units can be recovered to produce either hot water and/or steam. While RICE CHP applications are common in the international market, the US is expressing increased interest in this area.

RICE or Combustion Turbine, Which Technology?

RICE technology offers several advantages compared to combustion turbines making them an attractive option. This is especially the case for simple cycle facilities under 225 MW that will be relied upon for peaking and/or ancillary services. However, each application is unique and needs to be evaluated holistically on a case by case basis. While Table 1 provides a high level comparison of RICE and combustion turbine technologies, additional key factors such as permitting, expected hours of operation, life cycle costs, market conditions, etc. also need to be considered during the selection process. Additional information is provided in the following sections.

RICE vs. CT & Cost Trend

Heat Rate: Figure 1 shows nominal output vs heat rate for commonly used combustion turbines in today’s market. The purple squares represent nominal 25 – 100 MW aeroderivative CTs used for peaking applications while the blue diamonds represent frame turbines. It can be seen that while RICE units range from 9 to 18 MW, the full load heat rate is in the range of 8,100 – 8,700 BTU/kWH which is better than most CTs.

Heat Rate Plot

Performance – Flexibility, Response Time, Turndown: As renewables become a larger portion of baseload generation, there is an increasing demand for reliable, dispatchable power that not only can be placed online quickly, but can also be started and stopped frequently due to changing load conditions.

RICE units are capable of ramping up to full load in less than 5 minutes and are able to operate at about 33 percent of their nominal rating without compromising heat rate. This technology also does not incur a penalty for frequent starts/stops since maintenance cycles are based on hours of operation. Combustion turbines generally ramp at a slightly slower rate (10 – 15 minutes) and can turn down to about 40 percent of their rated output, however, heat rate is compromised.

Due to their smaller size, multiple RICE units would be required to achieve the output of a single large CT; for example 5 x 18 MW RICE vs 2 x 45 MW CT. In this example, the minimum output from this RICE facility would be about 6 MW whereas the CT facility would be 18 MW. While the use of multiple RICE units may be advantageous for turndown, reliability, redundancy, system response time, heat rate, etc. capital and O&M costs need to be evaluated to determine which technology is most cost effective for the application.

The Fairmont Energy Station is a 25-MW project equipped with four Cat G16CM34 generator sets. The plant was commissioned in 2014. Photo courtesy: Caterpillar Inc.

Sensitivity to Ambient Temperature: The power output of a combustion turbine varies significantly with compressor inlet temperature. As the ambient temperature increases above ISO conditions, power output decreases. To counter this effect, common industry practice it to utilize an inlet air cooling technology (ie evap cooler, chiller, wet compression, etc.) to reduce the compressor inlet temperature and maximize performance. As a point of reference, in a dry desert climate (about 105F), combustion turbines can experience a 15 percent to 20 percent reduction in output relative to ISO conditions.

Reciprocating internal combustion engines are less susceptible to changes in ambient temperatures. The output vs temperature correction curve for RICE is essentially flat and reduction in power output generally starts to occur when the ambient temperature climbs above 105F. For this reason, inlet air cooling is not utilized on RICE units.

Water Consumption: As previously stated, combustion turbines typically utilize an inlet air cooling technology to increase output. These technologies not only consume water, but also have stringent requirements for water chemistry. Water treatment systems are required to produce, store, and pump the process water. Depending on the supply water quality, treatment system, and type of inlet air cooling technology utilized, a process waste water stream may also be generated requiring disposal. The addition of this infrastructure can significantly increase project costs.

RICE applications do not require inlet air cooling, therefore water usage is significantly reduced. Additionally, air cooled heat exchangers (ie radiators) are typically utilized to reject heat from a closed loop cooling water system. Since this system only requires periodic make-up (similar to topping off the radiator in an automobile) permanent water treatment systems are not required.

Minimum Fuel Gas Pressure: Whether it is CTs or RICE, each OEM specifies the minimum required fuel gas pressure for their product. The required natural gas supply pressure for combustion turbines can range from appx. 400 to over 900 psig. A soft correlation also exists where the units with the lower heat rates (better efficiency) require higher gas pressures.

RICE technology requires gas pressure in the range of appx. 75 – 150 psig at the power island. The lower fuel gas supply pressure requirement becomes very attractive in areas where the guaranteed supply pressure is low. Adding on-site compression or contracting a higher guaranteed pressure from the gas supplier can significantly increase overall project costs.

Noise Considerations: Combustion turbines are typically equipped with enclosures which provide sound attenuation. These enclosures may also provide equipment protection allowing CT units to be installed outdoors if required.

Compared to combustion turbines units, RICE units are quite loud with typical sound levels exceeding 110 db. For this reason, it is common practice to locate RICE units inside of a building (engine hall) to provide sound attenuation. Although much larger in size, the engine hall also serves to protect the equipment similar to the CT enclosures. If RICE units are to be installed near sensitive noise receptors, serious consideration should be given to performing a noise survey to determine what measures need to be taken to reduce noise emissions. While noise from the engine systems may be mitigated by the building design (siding, insulation, etc.), exhaust and/or inlet silencers, low noise radiators, and other reduction features may also be required to reduce overall noise emissions. The engine hall, supplemental systems (ie. HVAC, lighting, maintenance crane, etc.), and noise reduction features can significantly impact the total installed cost of a RICE facility.

What Does the RICE OEM Scope of Supply Include?

The scope of supply can vary based on a project’s needs and overall contracting approach. In general, the RICE OEM typically provides the following: RICE gen-sets & auxiliary skids, radiators, emissions control systems, ductwork, stack, silencers, starting system, switchgear, control system, and integral platforms/supplemental steel. The owner (or EPC) is responsible for providing the buildings (engine hall, administrative offices, warehouse, maintenance shops, etc.), HVAC systems, main power transformer, site development, foundations, utilities, commodity materials, and installation.

How Much Does a RICE Facility Cost ($/kW)?

For the same size area developed on a project site, RICE units provide less power per square foot (power density) compared to other technologies. For this reason, the cost of a RICE facility is very sensitive to the MW (number of units) installed.

Figure 2 shows a trend for MW Installed vs Installed Costs ($/kW) for RICE facilities utilizing 9 MW units. The installed cost on a $/kW basis decreases significantly as additional units are installed. After appx. 50 MW (ie. 5 – 6 9MW units), the slope of the curve starts to level off as the economy of scale benefits are realized. For small facilities (appx. 27 MW and less), costs associated with site development, balance of plant, construction, etc. can range between 65 and 75 percent of the total cost. In comparison, for larger installations (about 80 MW and larger), these costs are between about 40 and 50 percent.

How Much Will it Cost?

Larger 18-MW RICE units are gaining popularity in today’s market. Although not shown, for these units, a similar trend exists, though there is significantly less sensitivity (flatter curve) in the 18- to- 36-MW range. After 54 MW, the curve starts to flatten in a similar manner as that for the 9 MW units.

The estimated capital cost of a facility must take several factors into consideration which include but are not limited to; equipment costs, estimated material quantities, site location, site type, noise restrictions, market conditions, labor rates, constructability, indirects, contingency, etc. These factors can significantly impact the cost of a RICE facility and therefore project specific estimates should be developed in lieu of relying on industry benchmark data.

To provide some points of reference, the installed cost of a 2 x 9 MW RICE facility can range from $1800 – $2700/kW while a 12 x 18 MW RICE facility can range from $990 – $1400/kW. American Public Power Association indicated in a 2016 report the cost for new CT and RICE based capacity as $854/kW and $1,496/kW respectively. The US Energy Information Administration (EIA) released a report in April 2013 titled “Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants” showing $973/kW for an 85MW Conventional CT while RICE technology was not identified. In the same report, EIA also stated “It should be noted that all estimates provided in this report are broad in scope. A more in-depth cost assessment would require a more detailed level of engineering and design work, tailored to a specific site.”

South Texas Electric Cooperative’s Pearsall Power Station, equipped with 24 Wartsila 34SG engines. Photo courtesy: Wartsila.

What Else Do I Need to Know About RICE Technology: As previously stated, the determination of RICE vs CT technology needs to be evaluated on a case by case basis since each application is different. While RICE may provide advantages to CTs in specific applications, there are several non-obvious items that a potential owners/operators should be aware of. A few of these items are discussed below.

European Content: While US suppliers offer RICE technology, the engine-generator sets in the 9- to- 18-MW range for power generation facilities are manufactured in Europe. For this reason, the use of European codes, standards, design philosophies/practices, and material supply must be allowed to some degree.

Auxiliary Power: RICE units are capable of ramping up to full load in less than 5 minutes. To achieve this, the engines need to be kept warm during standby (not operating). This is typically accomplished by utilizing electric heaters in the cooling water system to maintain temperature. The electrical load can account for about 1 to 3 percent of the total auxiliary power consumption. Depending on the location of the facility, the expected dispatch, the amount of time the units may be in standby, etc. this cost should be taken into consideration when evaluating technologies.

Air Permitting: While the reciprocating engines can ramp up quickly to provide power (about <5 minutes), the emissions control equipment on the back end is much slower to respond. Depending on the hours of operation, installation location, time between starts, etc., the SCR systems may require significantly more time to reach operating parameters. During this period, air emissions are not controlled to optimum levels. The facility’s permitting process needs to take this into consideration so emissions limits do not restrict the availability of the flexible resource.

Sky Global One, a 51-MW gas-fired plant west of Houston, began commercial operation in April 2016. The plant features six 8.6 MW Jenbacher J920 FleXtra gas engines from GE. Photo courtesy: GE.

Dual Fuel Units: Most dual fuel RICE units in the US are required to operate on natural gas with ultra-low sulfur diesel as the backup fuel. When operating on natural gas, a small amount of the liquid fuel is also consumed. The technology selection process and facility design need to take this into consideration.

Summary: While RICE technology is not new, the application of utilizing multiple 9- to- 18-MW units as the prime mover for a generation facility is fairly new to the US power industry and gaining popularity. The benefits of a fast responding, high efficiency, flexible, dispatchable facility that requires low fuel gas pressure and minimal water make RICE units a very attractive resource. However, due to the low power density, the installed cost ($/kW) of a RICE facility is very sensitive to site specific factors. Each application is unique and must be carefully evaluated holistically to ensure the benefits of RICE technology can be realized cost effectively.

Authors:
All three authors work for Sargent & Lundy LLC. Arvind Patel is a vice president and project director for RICE Projects & Business Development. Nelson Rosado and Adam Redd are managers of RICE Projects.

Discharge limits for metals have become more stringent under the latest revision to the Steam Electric Effluent Limitation Guidelines (ELGs). Several key mechanical design and operational considerations are critical to ensuring that flue gas desulfurization (FGD) wastewater systems produce compliant effluent and are operable and maintainable.

A well-designed FGD treatment system includes specialized types of mechanical equipment that promote particle growth while minimizing shear to provide optimal conditions for metals removal. In addition, piping configurations and layout considerations must be well-thought-out to minimize solids plugging and also keep a suitable amount of flexibility and adaptability for potential changes in future plant operations.

Several mechanical design and operational considerations are critical to ensuring wet flue gas desulfurization wastewater systems produce compliant effluent. Key design and operational considerations are critical to compliance and flexibility. Photo courtesy: CH2M

Wastewater Treatment Process and Suggested Design Improvements

Complex chemistries associated with the wastewater generated from FGD systems usually require treatment systems with chemical and physical treatment processes for soluble metals and suspended solids removal followed by biological treatment processes for nitrate, nitrite, and selenium removal. Current metals removal is based on adding iron salts to remove anionic (negative ion) metalloids, such as arsenic and selenium, along with organosulfides to precipitate mercury and other cationic (positive ion) metals. To make these particles grow larger, which facilitates downstream settling, an anionic polymer is typically added last, which along with gentle stirring (flocculation), promotes larger particle formation just prior to clarification. Metal hydroxide precipitation is an acidic reaction, thus pH control is also required for metals precipitation. Chemical treatment is followed by coagulation of the resulting solids, and a clarifier for physical solids separation (Figure 1).

Chemical and Physical Treatment System with Sludge Recirculation System

Combined Chemical Treatment – The chemical and physical FGD treatment system typically involves an equalization tank followed by chemical treatment in multiple tanks to facilitate the precipitation/adsorption of metals. Our findings show that separate mix tanks are not needed for chemical treatment, and in fact counterproductive, as multiple mix tanks and long mixing times resulted in shearing of the precipitated mercury solids (Figure 2). Since iron salt addition is acidic and mercury removal is affected by pH, pH control was needed for all treatment steps other than polymer addition. Testing has demonstrated that use of a single mix tank was equal if not superior to multiple tanks, particularly if sludge recirculation is employed.

Mercury Treatment

Desaturation and Scale Minimization – FGD wastewater tends to be slightly acidic and supersaturated with gypsum. It is desirable to adjust the pH to neutral or slightly alkaline to optimize metals removal. With the use of organosulfides, a pH of 6.5 to 8.5 is typically optimal, with mercury removal optimal at the lower pH. This pH control and reduction in calcium sulfate supersaturation is referred to as desaturation. Desaturation is typically accomplished by adding a slurry of lime and controlling pH to 8.5, depending on the optimum pH for metals removal.

However, reducing the formation of scale on downstream equipment is desirable. It has been our experience that for FGD wastewater that has significant magnesium content compared to calcium, use of lime actually increases downstream scaling. For those situations, using sodium hydroxide or sodium carbonate plus sludge recirculation were found to be better at reducing the supersaturation of calcium sulfate and minimizing scaling than adding lime.

Sludge Recirculation – CH2M has found that sludge recirculation provides several benefits, other than reducing calcium sulfate supersaturation. Sludge recirculation increases particle size, due to precipitation of new solids on older particles. The resulting solids are crystalline and compact, whereas solids that form in the absence of pre-existing solids in the water tend to be amorphous and trap water, making them less dense. The larger, denser solids created with recirculation settle and dewater better than when sludge is not recirculated. CH2M has done this recirculation in a closed sludge loop, using a single set of pumps for sludge wasting and sludge recycle. This is done by routing the recycle line first over the sludge storage tank(s), then on to the mix tank.

Minimize Salinity Variability – Keeping in mind that the complexity of the FGD wastewater chemistry typically requires a downstream biological treatment system for the reduction of nitrate, nitrite, and selenium, it is desirable to minimize the variability in salinity and other factors whose upset could affect the consistent performance of a downstream biological treatment system. Incorporating equalization, clarification, and internal recycle of sludge and filtrates from the dewatering system can limit rapid changes in salinity that improves the downstream reliability of the biological treatment system.

Selecting Mechanical Equipment to Minimize Shearing

Use of organosulfides has greatly reduced the solubility of metals, particularly mercury, however, CH2M has found that plants that have high-shear mixers and pumps have significant generation of colloidal-mercury-containing solids that are passing through their clarifiers and media filters, with mercury concentrations exceeding 1 ppb, and TSS exceeding 30 mg/L. In recent projects, CH2M added mix tanks with low-shear mixers for organosulfide coupled with iron and polymer addition to enhance an existing pond treatment and achieved mercury concentrations of less than 12 ng/L.

Mixers – CH2M tested a broad range of mixers to identify models with minimal shear for the removal of mercury and other metal-organosulfide precipitates. Hyperboloid mixers (Figure 3) equipped with variable-frequency drives provided a balance between providing adequate mixing and minimizing shear. Equipped with bottom supports, these mixers could also be operated at low water levels while maintaining solids suspension, making them ideal for equalization tanks.

Low Shear Mixer

Pumps – Based on the mechanical nature of pumping fluids, precipitated metal particles can be broken apart due to their fragile nature. Therefore, it is necessary to utilize pumps that minimize the shear when conveying the FGD wastewater or sludge from one-unit process to another. Power plant sludges can also be highly abrasive, causing rapid wear of conventional positive displacement pumps. Rotary lobe positive displacement pumps can be equipped with abrasion-resistant wear plates coated with tungsten carbide, limiting wear to resilient rotors that can be quickly replaced through end plates, without decoupling the pumps from their associated piping. This type of pump can also be reversed for back-flushing.

Downstream Filtration and Metals Removal – CH2M has found that metals removal is dependent on recirculation to generate large, dense solids; appropriate dosing with coagulants (ferric chloride) and flocculants (polymers); appropriate mixing intensity that limits shear; avoiding pumping where feasible; and using low-shear pumps for sludge recirculation. When this is done, solids settle well in conventional clarifiers, and filtration is not needed. However, when mixing results in solids shear, media filtration does not help mercury removal. A significant concentration of mercury can be present as particles smaller than 5 microns, which is the particle size effectively removed by media (sand) filtration. Many of our clients have found little additional mercury removal with sand filters over a well-operated clarifier.

Moreover, CH2M has found that sand media filters develop severe scaling problems with FGD wastewater because filters are typically fed low-solids water, with only the sand to provide solids for scale to form on. CH2M has tested membrane filters developed for high suspended solids applications (membrane biological treatment) and was able to limit scaling by maintaining a high concentration of solids on the upstream side of the membranes.

Piping Configurations Minimize Solids Accumulation and Plugging

Once the solids particles have been formed by chemical addition, the FGD wastewater is typically treated in a flocculating center well clarifier where the solids are gently mixed for particle growth (flocculation) then settled and removed. However, solids are prone to plugging. Well-designed piping configurations minimize the potential for settling of the solids within system piping. Additionally, ELGs do not allow for any dilution of the FGD wastewater to achieve the regulated limits, thus minimization of flush water for the movement of the solids and clearing of any blockages is desirable. Any flush water introduced into the system is also considered FGD wastewater.

Clarifier Piping – For the clarifier operation, a closed-loop sludge wasting and recycling system design (Figure 1) allows for maintenance of a scour velocity in the sludge piping that minimizes plugging and eliminates the need for the introduction of any flush water except in the instances when a treatment train is shut down. Sludge is continuously recycled while a fixed amount of solids is wasted to a solids storage tank to feed the plant’s dewatering operation. The continuous recycle keeps the FGD solids moving throughout the piping system and minimizes the potential for plugging in the pipe due to solids settling. In addition, minimizing the sludge recirculating pipe lengths to limit the potential for solids plugging is recommended. Thus, it is desirable to locate the sludge pumps next to sludge sumps and recirculation lines as close to the mix tank and sludge storage tanks as possible. This can be achieved by constructing a tunnel underneath of the clarifier for housing of the sludge pumps. Situating the sludge pumps directly underneath the clarifier in this below grade tunnel allows for a short, straight run of pipe directly to the sludge pumps and minimizes piping for the sludge wasting and recirculation.

Sludge Wasting and Recirculation Rate – CH2M has found that solids recirculation ratio of 20 parts old solids to 1 part newly formed solids is optimal and can be accomplished by providing a time ratio of 20:1 of recirculation to wasting. Pinch valves are used with a timer to alternate wasting and recirculation. Pipes are located after the valves such that they drain into their respective tanks by gravity to minimize plugging. By providing a constant recirculation at a velocity of 5 ft/sec, deposition of solids in piping is minimized compared to a system where sludge wasting is intermittent or at continuous but variable flow.

Mix Tanks Piping – It is important to introduce the treatment chemicals into the mix tanks such that adequate mixing occurs to maximize the interaction with the solids particles for a given residence time, which allows for maximum potential for solids particle growth. Thus, injecting the chemical feed near where the FGD wastewater is introduced into the mix tank takes advantage of the turbulence from the inlet flow to assist with the chemical mixing. Since minimal mixing is used to prevent shear of particles, there can be a tendency of solids to settle and buildup in the mix tank becoming thicker over time. By providing a dip tube along with a hyperboloid mixer, the accumulation of solids in the tank can be minimized. The mixer can be tuned to promote bottom suspension of solids rather than turbulent mixing (avoiding shear on solids).

Dip Tubes – Dip tubes (Figure 4) act as a vacuum pulling these solids out of the tank, preventing buildup. Chemical treatment can also be introduced into the dip tube between the mix tank and clarifier. Situating the top of the dip tube slightly below the top elevation of the mix tank allows the tank contents to overflow into the next tank and prevents overfilling should plugging at the bottom of the dip tube occur.

Dip Tube

Layout Considerations Simplify Operation & Maintenance

Since FGD solids are prone to plugging, careful consideration must be made when laying out the mix tanks, clarifiers, sludge storage tanks, and dewatering systems such that pipe lengths and any stagnant lines are minimized. When possible, it is advantageous to locate the chemical and physical treatment system and the biological selenium treatment system within close proximity to each other.

Common Dewatering – Both treatment processes (chemical/physical treatment and biological treatment) generate waste solids that must be dewatered. Having both treatment trains located in proximity to each other allows for the sharing of solids storage and dewatering equipment. The majority of the solids in the FGD wastewater treatment train is generated in the chemical and physical treatment system. The additional loading from the biological solids is relatively small and does not significantly affect the sizing capacity of the dewatering equipment required to dewater the solids generated from the chemical and physical treatment system.

Common Access – Clarifiers can also be situated in a way that allows for a common platform and access walkways to be at a common height for common access. Major process treatment equipment is accessible from a main level where pipe racks can also serve as walkways among the associated solids dewatering equipment.

Editor’s note: Originally presented at the International Water Conference®: November 6-10, 2016. Please visit www.eswp.com/water for more information about the conference or how to purchase the paper or proceedings.

Authors:
All of the authors work for CH2M. Thomas E. Higgins, Ph.D., P.E. is Power Water and Process Senior Technology Fellow; Dennis Fink, P.E. is Senior Project Manager; Brian Choi is Senior Process Engineer. Krystal Perez, P.E. is Global Practice Lead for Power Water and Process; Jeff Tudini is Project Manager and Environmental Engineer.

Engineers are known for taking on numerous technical issues to improve the efficiency and output of electrical generators.

But for large-scale wind turbines, much of the improvement comes from just one factor – size.

The continued growth of wind turbine generation has largely mirrored the growth of turbine blades, the MW rating and the height of the hub. The first units are now dwarfed by today’s larger wind turbines.

Recent research from the journal Nature Energy suggested both land-based and offshore turbines have the potential to grow even further, which would continue to lower overall wind power costs as the average per-turbine generation grows.

The study, which surveyed 163 wind power experts, demonstrates just how quickly wind turbines have grown. The very first wind turbines in the 1980s featured an average rotor diameter of 18 meters. That grew to an average rotor diameter of 73 meters in 2005, and 102 meters in 2015, or large enough to sweep an area 50 percent larger than a football field.

The world’s largest turbine blade, manufactured by LM Wind Power, stretches a full 88.4 meters long, allowing for a total diameter of nearly 177 meters. The blade may have been the largest object ever transported on roads in Denmark. Its 218-kilometer trip to a testing facility in Aalborg took just six hours, but it required nine months of planning and coordinating to pull off. Photo courtesy: LM Wind Power

Yet that’s not the projected limit. By the 2030s, that average rotor diameter is expected to reach 135 meters. Siemens has a rotor diameter of 142 meters being offered today for onshore.

The length of offshore wind turbines could grow even more dramatically. These types of wind generators featured a rotor diameter of 90 meters in 2005 and 119 meters in 2015. By the 2030s, that rotor diameter could reach 190 meters.

Ed Hall, general manager of engineering for onshore wind at GE, said the larger nature of offshore turbines comes down to a lack of neighbors that might be inconvenienced and the economics of scale.

“Since the infrastructure for offshore turbines is very expensive, you’ll want to put as large a turbine as you can to recoup the costs,” he said.

Hub heights have grown as well. On land, the current average of 82 meters is expected to give way to an average of 115 meters in 2030. Offshore hub heights have grown slower to a current average of 90 meters, but that’s expected to give way to an average of 125 meters in the 2030s.

The result is improved turbine performance and lower generation costs, even though the average turbine capacity in the U.S. has remained roughly the same since 2011.

Last year, Siemens developed and erected a 115-meter concrete hub for MidAmerican Energy in Adams County, Iowa. Taller hub heights don’t just allow for longer blades. The taller heights allow turbines to access stronger and more consistent winds at higher elevations, which can boost power production by 10 percent or more, according to Siemens. Photo courtesy: Siemens.

Michael McManus, head of business development and strategy of onshore Americas at Siemens Windpower, said his company has greatly increased the size of land-based turbines even as the general capacity remained the same.

“If you look at the pretty recent past, we had a 2 MW class turbine that’s evolved from an 83-meter rotor to a 120-meter rotor, which is a significant jump in rotor diameter.”

Turbines with larger capacities can handle even larger blades, McManus said. Siemens’ 3-MW class direct-drive turbine now sports both a 130-meter rotor and 142-meter rotor.

Vikaas Rao-Aourpally, vice president of sales and business at Goldwind Americas, said the rate of growth has been staggering.

“Even over the last five years, the sizes that are coming out are remarkable,” he said. “When I started at Goldwind six years ago, the average size was maybe 100 meters at most. Now, we have a variant of a 3-MW turbine that has a 140 meter diameter.”

As of right now, the world’s largest turbine blade, manufactured by LM Wind Power, stretches a full 88.4 meters long, allowing for a total diameter of nearly 177 meters. That blade, designed for an Adwen AD8-180 wind turbine, is expected to provide 25 years of use.

Goldwind’s GW3S turbine – a 140-meter-rotor prototype in Hebei province of China, with a rated capacity of 3.4MW. Photo courtesy: Goldwind

LM noted such a large blade design needed to balance swept area, energy production and weight as well as the load transferred to the wind turbine. The blade is now undergoing fatigue testing to simulate high wind conditions.

Though at the rate wind companies are refining their manufacturing processes, the current blade size record might not stand for long. Siemens is also examining methods for lengthening turbine blades, which requires a careful examination of the entire manufacturing process and logistics, and finding ways to create new structures that can withstand increased loads.

“We are bound by these limits, though we continue to research and test new materials that could enable larger higher-performance structures,” McManus said.

The growing size of the rotors has become the main method for increasing the overall energy capture of the wind turbine. McManus said bigger rotor diameters greatly impact the amount of energy generated.

As a result, Siemens plans to continue expanding rotor diameters for all of its turbine classes as much as possible.

In the U.S., specific power – the ratio of generator size to rotor area – reached 250 W/m² by 2015.

Of course, energy companies can’t automatically put the biggest rotors everywhere. McManus said a number of factors can influence what types of turbines clients choose to install in their wind facilities. The primary factor is the cost of electricity. The influencers include climatic, logistical and regulatory contributors.

Rao-Aourpally said the U.S. has some federal regulations on hub heights that much of the rest of the world doesn’t have, though that isn’t stopping some wind developers.

“The restrictions aren’t a hard-and-fast rule, but just make for a longer development and permitting process,” he said. “Customers are starting to explore that.”

Additionally, turbines have to be specifically designed to handle the weight of bigger blades, even if the capacity rating remains the same, Rao- Aourpally said. Today, Goldwind and other companies are designing turbines with growth in mind.

“New turbines are, from the drawing board, being built to support larger blade sizes,” he said.

GE’s Digital Wind Farm hardware and software package allows engineers to capture fast-flowing data from the turbine, the facility as a whole and the grid to further optimize wind energy production. Photo courtesy: GE

Hall said turbine manufacturers are now working more closely with blade manufacturers to ensure blades and turbines can improve in sync and eliminate any potential bottlenecks.

But one factor in particular has emerged as a key concern – logistics. Wind turbine blades are generally manufactured in one piece to ensure the most durable structure possible, which makes travel from the manufacturing site to the wind facility a challenge.

Siemens often has to move 53-meter to 70-meter blades long distances and find specialized trucks and trailers to safely handle them. The company increasingly relies on the expertise of shipping companies to ensure blades can grow.

“We partner with transportation companies to determine the most cost-effective way to ship the turbine components,” McManus said. “That has a big impact on our work. We’re now turning to shipping by rail.”

At this point, Siemens hasn’t yet created a wind turbine blade too big to ship.

The gargantuan 88.4-meter LM Wind Power blade may have been the largest object ever transported on roads in Denmark. Its 218-kilometer trip to a testing facility in Aalborg took just six hours, but it required nine months of planning and coordinating to pull off.

LM carefully planned the route to ensure the blade wouldn’t run into an impassible curve or low bridge, but the company still had to dismantle guardrails and sign posts at certain points to make room.

Even with new logistical challenges that come from enlarging the equipment, the economy of scale and new construction techniques are driving down the up-front costs of wind development.

For example, construction of hubs tall enough and strong enough to support heavy equipment operating in high winds can become increasingly cost-prohibitive, McManus said.

“With steel towers, as you go taller, the cost increases exponentially due to economic shipping constraints combined with the increased cost of the foundation to support the structure,” he said.

One solution Siemens offers to neutralize this problem calls for switching from flanged, interlocking steel tubes to a tower constructed of match casted concrete segments. The patented match-casting process allows for construction by segments, without the use of grout in the joints during construction which provides a rapid construction cycle equal to steel towers at a lower cost of electricity at high hub heights.

Siemens put that technique to use last year for a 115-meter hub at a MidAmerican wind facility in Adams County, Iowa.

Hub heights don’t just allow for longer blades. McManus said taller heights allow turbines to access stronger and more consistent winds at higher elevations, which increases the annual energy production of the turbine and thus lowers the cost of electricity for customers.

The Nature Energy research indicates the offshore wind market is less mature, with relatively slower blade and hub growth. Though transportation logistics allow for turbines with much larger capacities – usually in the 6 MW to 8 MW range – the cost of the foundation and installation are much higher than on land. As a result, turbines with much larger capacities are generally necessary to cover up-front costs.

Though the continued growth in wind equipment size creates issues with physical scaling laws or transportation, the Nature Energy survey indicates wind experts are confident turbine developers will be able to overcome them.

Though size is the most useful method of improving wind power production, companies aren’t neglecting other methods. Rotor design enhancements, improved component reliability and reduced financing costs are expected to help as well, according to the Nature Energy Study.

Rao-Aourpally said Goldwind, as well as other companies, are switching away from traditional gearboxes within rotors to permanent magnet direct-drive technology, which turns a magnet-based generator. Not only does the new technology improve efficiency, it also results in lower maintenance and less downtime.

“The lack of a gearbox means one less item for annual maintenance,” he said.

McManus said digital controls can improve performance as well. As wind itself can behave unpredictably, finding ways to automatically adjust and harness how currents are moving at any given moment can help keep production steady.

“There’s a high degree of focus put into the controls of the machine and the park as a whole to optimize the performance of the machine at any given wind condition,” McManus said.

Hall said GE’s Digital Wind Farm hardware and software package allows engineers to capture fast-flowing data from the turbine, the facility as a whole and the grid to further optimize wind energy production.

“Every wind current is of interest to engineers, and analyzing them could enable us to extract 1-2 percent more power from the machine,” he said. “We can even forecast energy production from the farm and use that to determine how to satisfy power use for the grid.”

Thanks to improved efficiencies and lower up-front costs, the survey suggests the total cost of land-based wind power should fall by 24 percent by 2030 and 35 percent by 2050. Offshore wind prices should fall even faster, with a 30 percent decline by 2030 and 41 percent by 2050.

With that kind of motivation, wind power platforms should continue to evolve quickly, and growth will remain a popular solution, Rao- Aourpally said.

“The trend of going bigger and larger is going to continue,” he said.

Spare parts management is a complicated, laborious – but critically important – aspect of nuclear plant operation. Ensuring that the right part is available at the right time and the right place requires detailed inventory management, diligent quality control, exacting acceptance testing, etc.

The very fact that spare parts management can be complicated and laborious, however, means that it may be amenable to economic and efficiency improvements. Extra attention in such areas could have big impacts on cost reduction. While several efficiency improvements have been implemented over the years – such as industry-wide databases to locate available replacement parts at nearby plants – a different type of evolving technology could provide the next step change.

Additive manufacturing, 3D printing, flexible manufacturing – whatever term you want to use – is inching its way toward use in the commercial nuclear power industry. I admit that the concept still sounds a bit exotic, and it may take some time to establish compliance with strict material specifications, regulatory and quality assurance requirements, but the prospect of on-demand printing of replacement parts is not that far in the future. In fact, additive manufacturing is already being used to expedite and reduce the cost of certain non-metallic replacement items for nuclear power plants such as electrical connectors.

Moreover, 3D printing is not really that new of a technology. BMW, the German auto maker, has been using 3D printing technologies since the early 1990s, initially for performance race cars, but increasingly for commercial vehicles. The Phantom model, produced by BMW’s Rolls Royce division, now includes more than 10,000 3D-printed components, everything from plastic holders for warning lights to car lock buttons and electronic parking brakes.

BMW cites a number of benefits from 3D printing: faster turnaround times for prototypes; a more efficient production process for complex and high-quality parts; and enhanced quality through tool-less manufacturing. It’s not much of a stretch to translate these benefits to the nuclear power industry, is it? And 3D printing offers another key benefit for the nuclear industry: since parts made for nuclear plants are rarely mass-produced, 3D printing could churn out tailor-made components at lower cost compared with traditional manufacturing methods.

The Department of Energy is funding several projects to investigate the prospects for 3D printing in nuclear power.

At the GE Power Advanced Manufacturing Works facility in Greenville, SC, GE-Hitachi Nuclear Energy (GEH) will use 3D printing to produce mechanical test samples. The samples will then be shipped to the Idaho National Laboratory for irradiation in INL’s Advanced Test Reactor, after which detailed testing will be conducted to compare the irradiated samples with unirradiated samples.

GEH believes 3D printing could reduce manufacturing times by up to a factor of ten, while minimizing waste and enabling low-volume production. Based on the current state of 3D printing technology, initial components will be limited to about 400 cubic millimeters (bread machine size). Potential replacement parts for GEH may include fuel debris filters, control rod drives, and anti-vibration components for jet pumps in boiling water reactors.

“316L stainless steel is our first target alloy,” said Fran Bolger, manager of new product introduction for GE Hitachi Nuclear Energy. “For this material, we already have most of the key data that supports the demonstration of material quality. Some additional data will be generated later this year.”

Depending on regulatory requirements and industry demand, GEH believes parts could be offered to commercial plants as early as 2018. Assuring quality will be paramount. “The metal powder, 3D printing machine and associated build parameters will need to be evaluated for material quality, and the specific printed part build will need to include samples that can be evaluated through nondestructive and destructive testing,” said Bolger. “Some parts may require custom testing critical to the application, such as pressure drop performance.”

Westinghouse is also pursuing 3D printing, leading a second DOE project that will develop and demonstrate a laser-based 3D printing technique for manufacturing metal parts certified for use in nuclear structural applications.

“This is a valuable opportunity for Westinghouse to advance our most innovative nuclear technologies while collaborating across the industry with the best minds in the most advanced research facilities,” said Jim Brennan, Westinghouse senior vice president of the Engineering Center of Excellence.

That last phrase – vitality and economic viability – gets to the heart of it. With all the difficulties swirling about the industry these days, vitality can seem out of reach…a forlorn gaze into the glory days of the nuclear past. However, perhaps 3D printing is part of a technological disruption that will provide a nuclear power industry parallel to the shift from dot-matrix to laser printing: faster, cheaper, at higher quality.

So go ahead. Print that part.

The photos are startling: large cities like Beijing and New Delhi enveloped in a gray haze; people wearing face masks in an attempt to protect their lungs; empty playgrounds on days when children must be kept inside because pollution levels are so high. The smog red alerts in mainland China have forced factories, schools, and roadways to shut down. These red alerts indicate that the air is “hazardous,” but what exactly does that mean? How are these levels calculated and how do pollution levels around the world compare with levels in the United States? The answer is a bit more complicated than comparing the red alert level of one country to another.

Air quality indices (AQI) are used around the world to communicate current or forecasted pollution levels to the public. Often described as colors, such as green, yellow, orange, red, etc., the colors correspond to a numerical index value. However, these index values are not directly comparable from one country to the next because government agencies use different calculations. It’s not uncommon to see AQI values in China as high as 600-900, but in the United States the AQI tops out at 500. In China, an individual score is awarded to each of the six pollutants tracked as part of their index (ozone, CO, SO₂, NO₂, and particulates such as PM₁₀ and Pm_2.5) and the final AQI is the highest of these scores. The individual pollutant scores are calculated by a formula published by China’s Ministry of Environmental Protection. In contrast, the US EPA calculates an AQI for each of the same six pollutants, but does not use an overall AQI score and uses different formulas. The governments of Canada, India, Britain, Mexico and South Korea also calculate AQI values, but each uses their own scale and methodology to rate air quality.

Global Map of Modeled Annual Mean Pm2.5 Concentration (μg/m3)

Many people around the world face serious air pollution issues. In fact, the World Health Organization (WHO) recently published a study that estimates 92% of the world’s population lives in locations where outdoor air quality fails to meet the WHO guidelines. Air pollution levels in India recently surpassed those in China, and the two countries are roughly tied for most premature deaths due to air pollution. Because AQI values are not directly comparable, a more accurate way to compare pollution levels around the word is to view them on a concentration basis. The map on this page shows average predicted Pm_2.5 levels in micrograms per cubic meter (μg/m³ – mass of pollutant per volume).

The WHO standard for Pm_2.5 is 10 μg/m³. High levels of Pm_2.5 are particularly dangerous to human health because the small particles can travel deep into the lungs and even enter the bloodstream. Fine particles and ozone are the main contributors to smog and reduced visibility. Many countries with high levels of PM and other air pollutants lack rigorous environmental regulation or rely on sources of energy with higher emissions (and few emissions controls) due to economic realities.

Since the Clean Air Act was passed in 1963, the US has made large strides in improving air quality. Many areas once classified as “nonattainment” (exceeding ambient air quality standards) have worked to improve air quality and are now classified as “in attainment.” Before the Clean Air Act was passed, levels of pollution in some areas of the US rivaled those in heavily polluted areas of the world today.

Industry and regulatory agencies have found ways to work together to improve air quality in the US. These two groups don’t always agree on the appropriate level of regulation, but constructive dialogue between stakeholders helps agencies craft regulations that improve air quality and allow for economical operation. The success story of improved air quality in the US can serve as a model for other countries looking to improve the health and well-being of their own populations.

A staggering 230 MW/h of energy storage systems were installed in the last three months of 2016, more than the previous 12 quarters combined.

That strong finish put the total amount of energy storage systems installed in 2016 at 336 MW/h, or 100 percent over 2015 according to GTM Research and a report by the Energy Storage Association.

The U.S. energy storage market is now estimated to reach 7.3 GW in 2022, representing an investment of $3.3 billion.

Ravi Manghani, GTM Research’s director of energy storage, said the huge amount of fourth-quarter installations was due to a burst of deployments with a very short development time.

And that burst could continue, thanks to California.

GE Hitachi, Advanced Reactor Concepts to Cooperate on Small Modular Reactors

GE Hitachi Nuclear Energy and Advanced Reactor Concepts LLC have agreed to collaborate in the development and licensing of an advanced small modular reactor based on Generation IV sodium-cooled reactor technology.

The two companies hope to advance an >aSMR design for global power generation with initial deployment in Canada, including the pursuit of a preliminary regulatory review by the Canadian Nuclear Safety Commission, based on earlier technology licensing success in the United States.

This collaborative commercialization program will also work to confirm projected construction and operating costs and identify a lead-plant owner and operator for the joint aSMR.

Arbitrators Award $125 Million for Defective Steam Generators at San Onofre

The owners of the San Onofre Nuclear Generating Station were awarded $125 million by an arbitration panel for the plant’s defective replacement steam generators supplied by Mitsubishi Heavy Industries.

Southern California Edison, the majority owner of San Onofre, filed the request for arbitration to the International Chamber of Commerce in 2013, claiming the failure of the defective equipmentlead to the permanent shutdown of the plant.

In 2012, a small radiation leak lead to the discovery of extensive damage to hundreds of tubes inside the virtually new generators.

Southern California Edison decided to close the plant for good in 2013 after concerns over whether the plant was too damaged to restart safely.

Hydroelectric Generators are the Oldest Still Operating in the U.S.

A new study by the Energy Information Administration indicates hydropower plants account for 99 percent of all currently operating capacity built before 1930.

The average hydroelectric facility has been operating for 64 years, and the 50 oldest electric generating plants are all hydroelectric and have been in service since 1908.

However, relatively few new hydroelectric facilities are being built. Of the nearly 200 GW of capacity added over the last 10 years, only 1.7 GW were conventional hydro.

Though the deterioration of spillways at Oroville Dam recently caused a flooding scare after heavy rains, that plant’s operation date of 1968 makes it younger than 63 percent of California’s currently-operating hydroelectric facilities.

Half of all hydroelectric capacity is located in Washington, California and Oregon. Those three states plus Vermont generate half their power from hydroelectric sources.

European Developers Propose Offshore Wind in New York and Massachusetts

Areas in New England just outside of those that have been earmarked for offshore wind development have attracted interest from German developer PNE Wind AG and Norway developer Statoil ASA.

The sites are south of Long Island in New York and Martha’s Vineyard in Massachusetts. The two companies want the U.S. government to open these sites for offshore development.

Both requests were unsolicited and a continued sign of interest in offshore wind in the Atlantic coast. Statoil already has another project slated in the area after purchasing the development rights.

So far, the U.S. government has awarded 12 leases for wind projects.

EmberClear Proposes 1.1 GW Gas Plant in Illinois

EmberClear Corp. has unveiled plans for a gas-fired power plant to be constructed near Pawnee. If approved, construction would begin next year with production starting in the summer of 2021.

The proposal is seeking an expansion of enterprise zone tax breaks near the site, though it’s only one step in the process, said John Kinnamon, vice president of the Midwest Region for EmberClear told the State Journal-Register.

“The enterprise zone is just a start. It by no means makes the project a certainty,” he said. “There are a whole lot of things that have to happen before we get to that point.”

The company has scheduled an open house on the project, which was requested by county officials, for next Tuesday.

Solar Posts Record Growth, Set to Triple Through 2022

The Solar Energy Industries Association reported record-breaking U.S. solar growth in 2016, with nearly double the growth of the previous record.

Utilities, commercial entities and residential projects installed 14.76 GW of solar last year, driven mostly by utility-scale developments.

Additionally, the association noted the total U.S. solar market should nearly triple in size over the next five years, though installations are expected to dip 10 percent this year to 13.2 GW. That decline still puts new solar development at 75 percent more than in 2015.

The association blamed the dip on a large number of utility-scale developments scheduled for completion before the original expiration of the federal Investment Tax Credit, which has been extended.

The cost of solar photovoltaic systems fell 20 percent in 2016, the biggest yearly decline since GTM Research started tracking data.

Carbon Emissions from Generation Fall Below Transportation Emissions

A new report from the U.S. Energy Information Administration indicates carbon dioxide emissions for power generation have fallen below emissions from the transportation sector for the first time since the late 1970s.

Electric power CO₂ emissions fell to 1,803 million metric tons from October 2015 through September 2016, continuing a 10-year downward trend.

Transportation CO₂ emissions rose slightly to 1,893 million metric tons during the same time period.

Power emissions mostly come from coal and natural gas-fired electric generators, with coal generation running from 206 to 229 pounds per million British thermal units, depending on the type of coal used.

Natural gas emits an average of 117 pounds per million British thermal units, as it requires less fuel to generate electricity.

Wind Energy Supplied 5.5 Percent of U.S. Demand in 2016

Wind power accounted for 5.5 percent of all electricity consumed nationwide, up from 4.7 percent in 2017. Total wind generation reached 226 million MWh during 2016.

Additionally, Iowa, South Dakota, Kansas, Oklahoma and North Dakota all generated more than 20 percent of their electricity from wind, according to data from the U.S. Energy Information Administration.

With a total new wind turbine investment of $13.8 billion, the U.S. now has a fleet of over 52,000 turbines operating in 40 states, the American

Wind Energy Association reported. In total, 14 states produced over 10 percent of their electricity from wind, and 20 generated over five percent.

New Mexico had the fastest wind growth, as the increase of 73 percent brought the state to a 10.9 percent share of wind generation.

Georgia Power Cancels Study for New Nuclear Plant

Georgia Power has cancelled a study for a potential new power plant near Columbus.

In a letter to the Georgia Public Service Commission, the utility indicated the study wouldn’t be needed as soon as expected, and that it intends to pursue a new nuclear generation option, the Atlanta Journal-Constitution reported.

The decision does not affect development of new nuclear reactors at the Vogtle plant near Augusta, which is three years behind schedule and $3 billion over budget.

Reactors for the Votgle expansion are currently expected to be provided from Westinghouse. Toshiba, the parent company of Westinghouse, recently announced it would halt all future nuclear construction after a $6.3 billion loss in its nuclear sector, though the company promised to finish any nuclear projects currently under way, including Vogtle.

GE Provides Turbine, Financing for Pennsylvania Combined-Cycle Plant

GE announced it will provide a single-shaft engineered equipment package, including a high-efficiency 7HA.02 gas turbine, for Ares EIF’s Birdsboro Power combined-cycle power plant under construction in Birdsboro, Pennsylvania.

The deal for the plant, expected to produce 488 MW upon commercial operation in 2019, also includes financing from GE Capital. The Birdsboro Power project was developed by EmberClear Corporation, and the order includes one 7HA.02 gas turbine, one D650 steam turbine, one heat recovery steam generator (HRSG), plant controls and additional equipment. The gas turbine will be manufactured in Greenville, South Carolina, and the steam turbine in Schenectady, New York.