Two Chinese firms have announced plans to build a solar power facility within the irradiated exclusion zone surrounding the former Chernobyl Nuclear Power Plant in Ukraine.

GCL System Integration Technology, a subsidiary of the GCL Group, and China National Complete Engineering Corp. are partnering on the project, according to a GCL press release. Construction on the 1-GW plant should begin in 2017.

“There will be remarkable social benefits and economical ones as we try to renovate the once damaged area with green and renewable energy,” said Mr. Shu Hua, Chairman of GCL-SI. “We are glad that we are making joint efforts with Ukraine to rebuild the community for the local people.”

The Ukranian government originally sought to bring energy resources to the area, which spreads out over 1,004 square miles. The former USSR established the zone in the wake of the 1986 disaster at the plant in order to restrict the spread of radiological contamination and limit human contact.

“Its cheap land and abundant sunlight constitute a solid foundation for the project,” said Ostap Semerak, Ukraine’s minister of environment and natural resources. “In addition, the remaining electric transmission facilities are ready for reuse.”

CCEC will act as the general contractor for the project, with GCL offering consultancy and planning as well as PV facilities.

By Derek Laan and Rob Broglio

ZLD Pilot Plant for FGD wastewater at the Young Heung power plant in South Korea. Photo courtesy: Doosan Heavy Industries & Construction

On Nov. 3, 2015 the Environmental Protection Agency (EPA) released a new set of Effluent Limitation Guidelines (ELGs) the first update to the Clean Water Act rules in over 30 years as they relate to Steam Electric Power Plants. The new rules are mainly a reflection of changes to water use in the power industry. Air quality controls, mainly FGD systems have taken pollutants previously in flue gas and transferred them to plant wastewater streams.

These new guidelines were designed to address this concern but they also have many operators looking for what the best solution for their plant’s situation is as there are a wide variety of options for treatment. While there are a variety of wastewater streams addressed by the ELGs, FGD wastewater is one of the main points of concern for the guidelines. This article will focus on summarizing the ELGs as they relate to FGD wastewater treatment and the available treatment options.

The EPA began a study of existing water at Steam Electric Power Plants in 2009 and the results were published in 2013. The study looked at pollutants being produced by power plants, what wastewater treatment technologies were being used at power plants already and what future technologies were in development. Based on these results the EPA designated two levels of technology which must be used by all Steam Electric Power Plants between 2018 and 2023 depending on when a plants NDPES permit is renewed. The EPA has several levels of technology based guidelines and the levels selected for the ELGs are on the more stringent side. For existing plants the Best Available Technology Economically Achievable (BAT) must be implemented while for new sources, meaning new power plants or FGD systems, must implement Best Available Demonstrated Control Standard / New Source Performance Standards (NSPS). These technologies were considered to be both necessary to prevent pollutants from entering local bodies of water and economically feasible to be implemented by producers.

FGD wastewater is considered the primary concern of the ELGs. This can be seen in the fact that FGD wastewater has the most stringent treatment requirements and if any other streams in the plant are added to the FGD wastewater stream these combined streams must meet the guidelines for FGD wastewater. As a result many plants which previously mixed their low volume wastewater streams together are currently developing plans for separating them to minimize the amount of water that must be treated as FGD wastewater.

One major change is that surface impoundment or ponds has been severely restricted by the new CCR rule. This means that most plants will be closing their impoundment/ash ponds. As stated earlier the guidelines are technology based but effluent water also has limitations set by the EPA these can be seen in the Table A. The BAT for FGD wastewater has been established as Chemical + Physical treatment followed by Biological treatment. What that means is that all existing Steam Electric Power Plants need to have systems which meet or exceed these requirements set up by the time they renew their NDPES permit between 2018-2023. Chemical & Physical processes employed will likely be similar across most plants depending on their permit requirements and constituencies of the wastewater.

The Chemical + Physical treatment processes are used to removed TSS & many of the other metals which may be dissolved in the FGD wastewater with the exception of Selenium. The process will vary depending on the qualities of the FGD wastewater but adjustment in the amount of chemicals or retention times can be made to ensure the desired water quality. The first step is usually suspended solids removal. This involves adding a polymer to the water and produces gypsum which can be sold commercially. The solids produced are removed with a clarifier and the water moves on to the next process. The next step is metal removal which involves adding liquid chelate aluminum, hydrochloric acid & sodium hydroxide to remove mercury & arsenic. These metals react to the reagents added to the water, fall out of solution and are removed with another clarifier step. The final physical process used in most cases will be hardness removal which is necessary to lower the TDS (Calcium). The biological processes used to for removing selenium can’t operate in high TDS conditions. Hydrochloric acid, sodium hydroxide & sodium carbonate are added to the water followed by a polymer. These cause the dissolved calcium and magnesium to precipitate out and allow their removal with a final clarifier step. When the EPA was considering the ELG rules Chemical + Physical treatment processes only were considered but due to their inability to remove selenium and nitrogen as N from the water biological treatment was also included.

There are several available technologies for biological treatment which remove of selenium. They follow the same basic process by which dissolved Selenate (Se+6) and Selenite (Se+4) are reduced to elemental Selenium (Se) via the growth of micro-organisms. This process can only take place in environments where oxygen is absent. As the selenium is reduced to its elemental form it comes out of solution and is removed along with the biological sludge produced in a filtration step. However this process is not an easy one to maintain and the market has struggled to come up with solutions that consistently perform under the harsh conditions of FGD wastewater.

The temperature and conditions for growth of the micro-organisms fall into a specific range which should be maintained by having effective chemical & physical treatment processes preceding it. The main problem stems from high TDS levels impeding the micro-organisms ability to grow at an appropriate rate which can increase retention times or impede the biological process from happening at all. For this reason not all FGD wastewater streams will be appropriate for these processes and may need to be treated using evaporators or other disposal methods such as mixing with ash for disposal in a landfill. However several companies have come up with unique technologies to use biological treatment to precipitate selenium out of solution and then physically remove it from the wastewater.

One of these technologies is a fixed bed bioreactor. In this process the microorganisms grow on a fixed media and the wastewater flows with gravity over the media which serve as the surface area for the microorganisms to grow. Once the fixed media is completely covered with a thick layer of biofilm a backwash cycle is performed which removes this biofilm (sludge) and the elemental selenium along with it. These reactors have the advantage of being simple to operate and having the biological & filtration processes in the same step.

Other manufacturers attempt this process in a 2-step process. The first is again a bioreactor of which there are 2 main types: fluidized & moving bed. A fluidized bed bioreactor (FBR) works by having the media surface (typically sand) on which the microorganisms grow pressurized causing it to move around the bioreactor like a fluid. The biofilm sluffs off of the sand as it grows. A Moving Bed Bioreactor or MBBR works by having plastic media pieces to increase the total available surface area for the microorganisms’ growth. These media flow around the bioreactor and the biofilm sluffs off once it has become too thick. Once the selenium has all been reduced to its elemental form it must be physically separated from the water without going back into solution.

There are several different methods of filtration available to use after the biological step. A rapid clarifier is one approach that has been used. Normal clarifiers take a long time period but rapid clarifiers use higher amounts of polymers to cause the sludge to separate out more quickly. UF membranes have also been used by several companies. However UF membranes can become clogged preventing clean water from entering the membrane. This is fouling is avoided by bubbling air thru the membranes. However if oxygen is introduced to the water the selenium can reionize and come out of solution. Dissolved selenate and selenite are not blocked by UF sized membranes meaning selenium’s reionization must be avoided. However Doosan Heavy Industries & Construction has developed a unique MBR system which does not use air to scour the membranes. Doosan’s Low Energy No Aeration (LENA MBR) works by creating the scouring force of air bubbles with mechanical reciprocation. The membranes are mounted on a moving bed that reciprocates slowly back and forth, shaking foulants from the membrane. Replacing air scouring with mechanical movement ensures an oxygen free environment preventing the selenium from coming out of solution. Doosan’s LENA MBR has already been tested for selenium removal applications at mining sites and the company is working on testing it for FGD wastewater applications.

While Physical-Chemical + Biological Treatment is the BAT for existing sources of FGD wastewater new sources are required to use Zero Liquid Discharge (ZLD) systems. In addition to new sources the ELGs are offering the option of delaying their implementation until 2023 for plants who agree to install ZLD systems by that time. What ZLD means is that no water leaves the boundaries of the plant. In practicality this typically involves using brine concentrators and crystallizers to create a solid sludge for disposal at a landfill. There have been installations in power plants for this application since the mid 1970s. While ZLD is necessary for all new sources of FGD wastewater it may also be the best option for treating especially concentrated streams of wastewater for which other treatment options might not be feasible.

There are 3 main kinds of evaporators used in ZLD systems; Vertical Type Falling Film (VTFF), Forced Circulation (FC), & Spray Dry Evaporators (SDEs). VTFF’s work by having the FGD wastewater pass in a thin film over tubes which are heated by waste steam from the power plant. This creates a thickened brine stream and vapor which is condensed into a pure distillate for reuse in the plant. Typically after a VTFF process the thickened sludge is passed thru an FC evaporator which uses high pressure and steam to crystalize the stream followed by a centrifuge or other dewatering process to remove the final moisture. The thickened sludge from the VTFF can also be mixed with fly ash to create a thick cement like past for disposal at a landfill. Spray Dry Evaporators are used on their own and work by utilizing hot flue gas. FGD wastewater is sprayed over the flue gas which causes the water to flash evaporator and the solids to drop out. The vapor is then collected for reuse and the flue gas goes to the FGD system.

ZLD systems are the most stringent form of wastewater treatment but they are expensive both to purchase and can be difficult to operate. Scaling is the main operating problem in most evaporators due to the high salt concentrations in the FGD wastewater. This problem can be avoided by using seeded slurry techniques or thru softening of FGD wastewater prior to entering the evaporator. Cost is another important factor and in general a full ZLD system will be at least 1.5 times more expensive than the BAT option. One option to reduce the cost of these systems is to use an RO process before sending the water to the VTFF evaporator. This can significantly reduce the amount of water that needs to be processed by the evaporator reducing capital costs. Doosan Heavy Industries & Construction is currently constructing such a system at the Yong Dong Power Plant in South Korea and has been successfully piloting a similar system at another facility (see picture). While ZLD may be more expensive it may be the only option available to meet the requirements and most greenfield coal plants being constructed around the world are installing ZLD systems.

With the wide variety of options available for meeting the ELGs it’s important for each plant to understand what their needs are. Considerations like whether the plant might be shut down shortly after the final implementation of the rule in 2023 or other local discharge requirements will have mean similar plants might have different plans for meeting ELGs. The high cost of ZLD systems and the complicated nature of operating both biological selenium removal treatment and evaporators means it’s important for plant operators to begin evaluating their options early to ensure they are not caught off guard when they need to renew their NPDES permit.

Authors

Derek Laan is business development manager for the Water Business Development Team at Doosan Heavy Industries & Construction Co. Rob Broglio is senior sales manager at Doosan Power Services Americas.

Real-world image of the Hybrid Performance (Hyper) Facility at the National Energy Technology Laboratory. This cyber-physical system (CPS) is used to demonstrate novel controls and virtual simulations. Photo courtesy: NETL

Emerging technologies in the field of instrumentation and controls are poised to have a big impact on power production. While some technologies are still in the basic stages of research and development (R&D) and on the cusp of widespread adoption, others are now entering operating rooms to change our industry for the better. Some of the technologies represent major advances on conventional approaches. Others are adaptations from outside industries, and even nature, that are providing game-changing innovations for tomorrow’s power generation. Together, these technologies represent the power plant of the future where the most cutting-edge technologies are effectively leveraged to provide clean and efficient power for us all.

Embedded Sensing Through Advanced Manufacturing

Power system efficiency depends upon enhanced process control, which is grounded in acquiring high-quality measurements and information from throughout various energy subsystems including structural components and machinery. For fossil energy-based systems, this means placing sensors in harsh environmental conditions, including high-temperature, high-pressure, corrosive, and erosive environments, that are typical in gas turbines, solid oxide fuel cells, gasifiers, and boilers.

The U.S. Department of Energy’s National Energy Technology Laboratory (NETL) is currently supporting projects with the objective of developing innovative materials and packaging techniques that will increase sensor durability and survivability when deployed within the harsh environments of advanced energy systems. NETL is also supporting R&D that investigates advanced manufacturing methods to embed sensor technologies within components, thus removing sensing elements from direct contact with harsh environments. A representative project within this research area is through the University of Texas at El Paso (UTEP). The researchers at UTEP are studying the use of additive manufacturing (AM) in the form of electron beam melting to create “smart” parts, where the sensing elements are directly integrated into metal-based components. Fabrication methods for metals and other extreme environment materials such as ceramics, nickel-based superalloys, and refractory materials are highly complex and non-trivial tasks. Even more challenging is the prospect of embedding sensor elements in a manner that does not compromise the mechanical integrity of the part itself while also allowing for wireless signal processing and data communication out of the component. However, the benefit of these R&D efforts is very high since it enables a new level of insight for the purpose of real-time monitoring of process variables, component health, condition assessment, and life-cycle performance.

Real-Time Data Visualization and Augmented Reality

Measuring energy processes in real-time is critical for attaining greater efficiencies and also for monitoring the health of system components to ensure safe operation. Moreover, with our ever-increasing trend toward big data and large systems of information, synthesizing this data in a meaningful way that provides actionable information is a significant undertaking. Real-time data visualization is a powerful technique that allows for greater insight into complex, non-linear relationships within energy systems as well as greater understanding of physical processes.

Hybrid Performance 1

Graphic illustration of the Hybrid Performance (Hyper) Facility at the National Energy Technology Laboratory. Photo courtesy: NETL

Two companies, Nanosonic Inc. and Sporian Microsystems Inc. are currently investigating low-cost, rapidly deployable sensor technologies for real-time monitoring of heavy metals in water resources. Heavy metals of interest include the Resource Conservation and Recovery Act (RCRA) metals of arsenic, barium, cadmium, selenium, mercury, lead, chromium, and silver. Traditionally, water sampling for these materials is acquired via grab samples and analyzed via in-house or third-party laboratories where results can take up to 3 weeks to process. This lack of real-time information is disadvantageous for power plants seeking to comply with U.S. Environmental Protection Agency’s regulations for water quality including the effluent limitation guidelines (ELGs). Sensors that enable real-time feedback information regarding critical water treatment processes, such as flue gas desulphurization, will allow for optimized performance and cost savings in the form of more efficient metering and use of relevant chemicals. Additionally, these real-time sensors may be deployed in a distributed manner that provides both spatial and temporal imaging to enhance control operations and increase efficiency.

The need for real-time sensor measurements extends to other applications beyond water quality management. Tech4Imaging LLC, a small business based in Ohio, is currently developing breakthrough sensor technology in the field of real-time visualizations. The sensors under development are based on electrical capacitance volume tomography in concert with advanced algorithms for image reconstruction. This advanced 3D imaging technique for multi-phase flow measurement is able to distinguish solids, gas, and liquids (3-phase flow) in process streams at high temperatures approaching 900 °C. This represents a first-of-a-kind demonstration for this type of imaging within this high-temperature regime. Applications for this advanced 3D imaging and visualization technology will provide better feedback control and monitoring of high-temperature energy processes.

Recently, Pokémon Go became a cultural phenomenon that overlaid virtual images onto real-world displays of users’ immediate surroundings. The technology behind the popular entertainment app is augmented reality (AR), and it is a new horizon for advanced imaging and visualization within the industrial power sector as well. AR brings an unprecedented level of immersion into data. Beyond catching Pokémon, the greater boon has been the raised awareness to using AR technology for practical applications. One example is maintenance, service, and repair of system components. Recently, an app called “eKurzinfo” produced by Audi, has allowed users to access cloud-based AR information, including animated 3D maintenance instructions and how-to information, via a cell phone in real-time. In a similar manner, AR technology can be used to allow plant technicians to use handheld devices, such as a cell phone, to perform image recognition to identify the part under repair and then overlay relevant manuals with virtual annotations of wiring and other components in real-time to facilitate efficient repair.

Beyond the benefit of advanced maintenance practices, an additional prospect for using AR technology within industrial power plants includes the ability to visualize process data from “smart” components in real-time. By using a specialty headset, such as those manufactured by Microsoft’s HoloLens or a hand-held device, operators will one day be able to seamlessly interact with wireless sensor technologies embedded within components to reveal the inner workings and operation in a manner that has never before been possible. A real-time “look” inside components by viewing virtual image overlays and holograms of real-world data related to temperature, pressure, cracks, corrosion, and other failure mechanisms will enable step-change comprehension and response to protect the overall health of a plant during operation.

Advanced Controls via Cyber-Physical Systems

With the deeper saturation of renewables onto the grid, fossil energy-based power plants require improved flexibility to meet load-following profiles and stay competitive in an ever-changing power production landscape. The primary way for new (and existing) power plants to meet this new demand will be through adoption of advanced control schemes and use of novel platforms for demonstration.

Cyber-Physical Systems 2

Graphic illustration of underlying themes that form the basis of cyber-physical systems (CPS) research. Photo Courtesy: NETL

Cyber-physical systems (CPS), platforms that integrate real-world hardware with simulated components, represent a low-risk mechanism for testing advanced controls algorithms that leverage real-time data and process variables. NETL’s Hybrid Performance (Hyper) Facility in Morgantown, WV, houses a pilot-scale CPS capability to investigate novel control schemes for highly coupled energy systems such as solid oxide fuel cell-gas turbine hybrid systems. This unique facility draws collaborators from around the world, including the University of Genoa, DLR (German Aerospace Research Center), and Ames Research Laboratory. The highly specialized Hyper Facility is the only hardware-based simulator in the world focused on transient operation and dynamic control of hybrid systems.

To date, NETL has investigated a host of multivariable, advanced distributed control strategies including distributed proportional-integral-derivative, system identification (neuro-evolutionary algorithms, etc.), multiple-input multiple-output with state space as well as agent-based stigmergy, and biomimetic-based frameworks. Biomimetic-based methods use computational algorithms that reflect highly efficient processes occurring in nature such as the human nervous systems and ant foraging techniques. In collaboration with NETL, researchers at Case Western Reserve University (CWRU) have successfully used the latter technique as a way to detect faults for in-situ condition monitoring of energy systems. Using nature as a guide-in this case, ant foraging behavior-the CWRU team is able to analyze information pathways between sensors and actuators within a power system in a way that is analogous to the pheromone trails that ants use to find food. By analyzing the topology of these sensor information paths, changes may be detected that provide advanced warning of both sensor and component failures, which is essential to avoiding unplanned outages, planning repairs, and maintaining service life of components. This advanced topological deconstruction of the information structures within systems is just one way in which controls are evolving to meet the challenges of tomorrow.

Blockchain for Cybersecurity

As components become more and more intelligent, with the aid of embedded technology and wireless communication coupled with advanced controls, we can push closer to realizing a fully autonomous capability that leverages constructs such as the Internet of Things (IoT), also known as the “Industrial Internet.” IoT is the wave of the future, but issues may arise regarding the security of power systems resources and susceptibility to outside forces. Current events such as the recent Distributed Denial of Service (DDoS) attack, which used internet-connected devices to disrupt international media sites such as Amazon, Twitter, Spotify, and others, drives home the necessity of exploring novel ideas that will aid in protecting IoT components, which may one day include critical resource infrastructure for power plants. The power plant of the future must be equipped with cybersecurity in a manner that minimizes the vulnerabilities posed by being IoT connected.

Novel techniques that leverage well-established R&D areas of encryption, firewalls, and authentication must be created and deployed to meet this challenge. NETL is currently investigating the use of blockchain technology as a cybersecurity tool to maintain the robustness of integrated energy systems of the future. Blockchain is the term for the infrastructure that relies on a distributed ledger of transactions within a network. Virtual currencies such as Bitcoin use blockchain as the underlying protocol to ensure financial transactions. If you think of digital money like digital information, then blockchain is analogous to hypertext transfer protocol (http). In the late 1980s when http and digital information was invented, the true impact (email, smart phones, big data, virtual reality, etc.) of this disruptive technology was unimaginable. With digital money such as Bitcoin, we are already seeing the disruptive power of blockchain on the financial sector by using it to make reliable, secure transactions. The energy sector is now poised to have the same disruption via blockchain. The exact manner in which blockchain-based energy systems will impact cybersecurity for the power plant sector is unknown at this time. However, new R&D efforts will explore how blockchain can be incorporated with sensor networks and advanced controls architectures to mitigate vulnerabilities of future IoT-enabled components, thus realizing safe and robust operation for energy systems.

Conclusion

The power plant of the future will continue to provide reliable, affordable, abundant energy to the nation, but it will do so in a totally new way. Instrumentation and measurements will include meaningful, real-time data streams from new sources including “smart” components that feature embedded intelligence, advanced 3D imaging, and immersive data visualization enabled by new technologies such as augmented reality. This newly acquired information can be leveraged to develop novel controls strategies based on rapid feedback that will enable robust, flexible power generation systems able to function with unprecedented efficiency. Technologies borrowed from gaming, finance, and nature will offer unique solutions to complex challenges that will reshape how the power generation sector thinks about plant operation. Together, these technologies will usher in a new and better way of doing business in the power plant industry.

Author

Sydni Credle is project manager of Enabling Technologies & Partnerships at the National Energy Technology Laboratory.

By Brad Buecker

Combined-cycle power plants continue to be the primary replacement for the many coal-fired plants that have been or soon will be retired. Like their coal boiler predecessors, combined-cycle heat recovery steam generators (HRSGs) operate at high pressures and temperatures. Proper chemistry control and monitoring are critical to prevent corrosion and fouling upsets that may range from relatively minor to catastrophic.

Schematic of a triple-pressure, FFLP HRSG 1

Two examples of the latter, where some past failures have caused fatalities, are release of high-temperature, high-pressure feedwater from flow accelerated corrosion (FAC), and turbine blade failure (with the turbine spinning at 3,600 rpm) due to previous corrosion mechanisms. Continuous, on-line monitoring of complete circuit chemistry is essential for reliable and efficient operation. Yet, in this author’s experience of reviewing specifications for many of these projects, it has become obvious that plant designers often have difficulty separating important measurements from others that are of little value. This article provides an overview of the critical analyses that should be part of any HRSG water/steam chemistry monitoring system. Much more detailed information is available from the organizations listed later in this document.

Following Chemistry Through the HRSG Circuit

A number of different HRSG designs are possible, and space limitations prevent a chemistry discussion of these variations. For this article, we will utilize a very common design shown schematically below.

This design is termed, as can be found in the literature [1], a “feed forward low-pressure (FFLP)” HRSG, where all of the feedwater passes through the low-pressure HRSG evaporator for pre-heating. A small amount of steam is taken off the LP drum, but the vast bulk of the fluid is distributed to the high-pressure (HP) and, to a much lesser extent, intermediate-pressure (IP), evaporators. Also note that this schematic includes an external deaerator (DA). In many designs, the DA is integral to the LP drum. But, the issue of deaeration brings up a more important point, where advancements in chemistry control have in many cases eliminated the need for a deaerator. The following discussion does not include deaeration.

Chemistry control and monitoring have four primary goals during normal operation:

• Protect the entire steam generation network from general corrosion.
• Protect those areas (feedwater system, economizer, low-pressure evaporator) that are most susceptible to flow-accelerated corrosion.
• Minimize impurity ingress (the condenser is the prime location), which can cause severe localized corrosion, particularly in the HRSG evaporators.
• Protect the steam turbine from transport of impurities that can induce corrosion and deposition.

Also very important but often overlooked is corrosion protection when the unit is off-line. The author will hopefully be able to re-address this subject in a future article for Power Engineering.

We will begin our review of important monitoring details and chemistry control with the makeup water treatment system and then progress forward.

Makeup Water System

High-purity water is a requirement for high-pressure steam generators. Very common in the industry now is a core treatment method of two-pass reverse osmosis (RO), with polishing of the RO effluent either by portable mixed-bed (MB) ion exchangers or electrodeionization (EDI). Excluding RO and EDI instrumentation from this discussion, the recommended continuous readings and normal limits of the system effluent are:

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

Specific conductivity provides a blanket measurement of all impurities in the stream. Sodium is the most weakly held ion on the cation exchange resin of a mixed-bed unit, and is the first cationic constituent to come off if the resin reaches exhaustion. Silica is the most weakly held constituent on the anion resin, thus anion effluent silica analyses are very helpful for monitoring bed performance and exhaustion.

The author has seen many specifications that also call for pH measurement of makeup system effluent. This analysis is essentially useless for two reasons. First, in high-purity water without chemical treatment, pH is quite difficult to measure. Second, the concentration of either hydrogen ions (H+) or hydroxyl ions (OH-), which give water either acid or basic properties, is so small that corrosion from either of these constituents is not an issue.

Condensate Storage Effluent

At the plant level, it is still not often well understood that severe corrosion can occur in steam generators during outages. Due to the nature of combined-cycle operation, many facilities start up and shut down numerous times during the course of the year. To these cycles can be added maintenance outages, which obviously may be of much longer duration. If the units are allowed to cool, dissolved oxygen (D.O.) ingress can be a significant problem. One location of high D.O. is the condensate storage tank, which is typically vented to the atmosphere. Any filling of the HRSG, partial or full, from this tank introduces to the unit cool condensate saturated with oxygen. The reader is encouraged to search the Power Engineering archives for reference 2, which outlines the use of gas transfer membrane (GTM) technology for dissolved oxygen removal from condensate along with other methods, nitrogen blanketing and dehumidified air circulation, for layup protection of HRSGs. The GTM system outlined in the article consistently produces condensate with a D.O. concentration of less than 10 ppb. Reference 2 also discusses the layup techniques of nitrogen blanketing and dehumidified air circulation, which, if applied properly, are extremely valuable in minimizing off-line corrosion.

Analysis of a Failure 2

Condensate Pump Discharge

Condensate pump discharge (CPD) is an absolutely vital monitoring point, particularly for HRSGs with steam surface condensers. Condenser tube leaks introduce cooling water, with all of its impurities, to the condensate and of course then to the steam generator. There, the high boiler temperatures will induce reactions that have severe corrosion and scale-forming effects. We will examine some of this chemistry in a bit more detail later.

Recommended on-line analyses include:

• Cation (or degassed cation) conductivity: ≤0.2 μS/cm
• Specific conductivity: Consistent with pH generated by ammonia feed
• pH: For FFLP HRSGs on boiler water phosphate treatment, range of 9.2 to 9.8
• Sodium: <2 ppb
• Dissolved oxygen: ≤20 ppb

Evaluation of cation conductivity, specific conductivity, and pH are linked. In all steam generators, the pH is typically maintained in a mildly alkaline range, as this minimizes general corrosion of carbon steel. For FFLP HRSGs, the recommended pH range is 9.6 to 10.0 to protect the feedwater piping and LP economizer and evaporator tubes from both general corrosion and another mechanism, flow accelerated corrosion (FAC). We will examine FAC in a bit more detail in the next section. Ammonia (sometimes an amine) is the common chemical of choice for pH control.

NH3 + H₂O ⇔ NH4+ + OH-

Experience has shown that control of ammonia feed is easier if it is based on specific conductivity measurements rather than pH. So, during initial unit startup the correlation between S.C. and pH is established, with subsequent ammonia feed derived from S.C. readings.

So then what is the link to cation conductivity (C.C.)? Specific conductivity is influenced by all ions, including the ammonia introduced for pH control. Thus, S.C. is not effective for detecting impurity ingress, especially if a condenser tube leak or other source of contamination is slight. With cation conductivity, the sample stream passes through a cation exchange column that exchanges ammonium (NH4+) and any other cations, e.g., sodium, calcium, etc. for hydrogen ions (H+). The hydrogen ions combine with anions in the stream, primarily chloride and sulfate, which have remained untouched by the exchange column. Thus, the effluent from the column is a dilute stream of acids, primarily HCl and H2SO4. These acids have a greater conductivity than their salt counterparts, and so C.C. can be an excellent tool for monitoring impurity ingress. However, C.C. is influenced by carbon dioxide, which may reach measureable proportions if air in-leakage at the condenser is significant. Degassed cation conductivity (D.C.C.) employs a reboiler or perhaps a nitrogen purge vessel to “gas off” most of the CO₂ prior to the conductivity measurement. Thus, D.C.C. is a more true measurement of anions, except for one factor which on occasion is important. If an amine (an organic ammonia compound) is employed in place of ammonia for pH control, all conductivity readings may become meaningless. With variability due to the amine type, at least some of any of the typical neutralizing amines will carry over from boiler water into the steam. At the very high steam temperatures, the amine will decompose to small-chain organic acids, primarily acetate and formate, and perhaps some CO₂. These acids mask the conductivity of other constituents. The decomposition products are not removed by cation exchange columns or degassing methods.

Sodium monitoring is an important supplement to cation conductivity. All cooling water contains sodium, and it is a very easy element to monitor on-line. With a tight condenser, sodium levels in the condensate should be very low (<2 ppb), and in many cases less than 1 ppb. Sodium and cation conductivity measurements in parallel provide a quick indication of impurity ingress. And, this combination of instruments is effective for differentiating between a true upset and simply instrument error. Say for example that cation conductivity suddenly increases above 0.2 μS/cm but sodium remains steady. C.C. instrument error or a needed calibration is the likely culprit.

Measurement and control of dissolved oxygen has evolved greatly in the last two decades or so, which we will explore in the next section. D.O. measurement at the condensate pump discharge is important for evaluation of air leakage into the condenser. As we shall see, some oxygen in the condensate is essential for control of flow-accelerated corrosion.

Feedwater/ Economizer Inlet

This sample is very important because it is the last checkpoint before the steam generator, and is downstream of the chemical injection point. Also, this is the water used for steam attemperation. Many of the feedwater guidelines mirror or are similar to those of the condensate pump discharge, as, unlike the coal-fired units of the past, HRSGs do not have feedwater heaters. For FFLP HRSGs, feedwater values also represent the chemistry of the LP circuit.

Recommended on-line feedwater analyses include:

• Cation (or degassed cation) conductivity: ≤0.2 μS/cm
• Specific conductivity: Consistent with pH generated by ammonia feed
• pH: For FFLP HRSGs, range of 9.6 to 10.0
• Sodium: <2 ppb
• Dissolved oxygen: 5 to 10 ppb
• Iron: <2 ppb

The focus in this section is on D.O. and iron analyses.

When steam generators are first placed into service, the carbon steel feedwater piping and steam generator waterwall tubes develop a surface layer of magnetite (Fe3O4). Likewise, for any systems with copper alloys, the alloy forms a protective cuprous oxide (Cu2O) layer. With respect to steel, if uncontrolled oxygen enters the system, it can oxidize the magnetite to rust (Fe2O3), with severe corrosion consequences. For many years boilers were designed, and plant chemists were trained, to remove all traces of dissolved oxygen from boiler feedwater. Mechanical deaerators could typically reduce the D.O. concentration to 7 ppb, with the remainder being eliminated by feed of a reducing agent, aka oxygen scavenger, such as hydrazine. The combination of ammonia feed for pH control and reducing agent feed for D.O. control became known as all-volatile treatment reducing [AVT(R)].

But, it has now become relatively well known (albeit not known nearly well enough) that these conditions can generate the phenomenon of single-phase flow-accelerated corrosion (FAC) of carbon steel. FAC occurs at flow disturbances, e.g,. economizer and evaporator elbows, control valves, etc. The combination of the chemical environment and fluid impingement induces iron dissolution from the impacted location. Gradual wall thinning is the result.

The corrosion rate is also influenced by temperature (maximum near 300oF) and pH (corrosion increases with decreasing pH, particularly below 9.0). What chemists have discovered, and whose impetus came from research in the 1970s in Europe and Russia on supercritical boilers, is that with very pure water, a small but continuous pure oxygen feed to the condensate and feedwater of the units causes the magnetite layer to become interspersed and covered with the iron oxide FeOOH, which forms a dense and strong layer. This program is known as oxygenated treatment (OT). Scientists from EPRI (Electric Power Research Institute) modified this program for drum units, where the oxygen is introduced to the condensate from natural condenser air in-leakage. This treatment, combined with ammonia feed but no oxygen scavenger, will establish similar FeOOH surface chemistry on carbon steel. The program is known as all-volatile treatment oxidizing [AVT(O)]. A requirement is condensate/feedwater cation conductivity ≤0.2 μS/cm. The dissolved oxygen requirement explains the 20 ppb D.O. limit in the condensate pump discharge and the 5 to 10 ppb range in the feedwater outlined above. If the feedwater range cannot be established, it may be necessary to feed a small amount of pure oxygen to the feedwater. For the FFLP shown in Figure 1, the injection point would be at the boiler feed pump suction, downstream of the LP evaporator. AVT(O) requirements also explain the decreased importance of mechanical deaeration for HRSGs.

Iron monitoring is highly recommended to verify that the treatment program is controlling FAC. Improved instrumentation, primarily centered upon real-time particulate monitoring and corrosion product sampling, is available to track condensate/feedwater iron concentrations. An extremely important issue regarding corrosion of condensate/feedwater piping is that the iron oxide corrosion products travel to the steam generator and precipitate primarily on the hot side of the waterwall tubes. These porous deposits can induce chemical reactions underneath the deposit that might not occur at all in the bulk boiler water.

The reader will note no reference to copper in the above discussion. Very few if any HRSGs have copper alloys anywhere in the condensate/feedwater system (copper-alloy condenser tubes do not count). If, for some reason, copper alloys are present, AVT(O) cannot be used. Rather, AVT(R) must be employed with very careful monitoring of iron and copper corrosion.

Even though FAC is well known in some circles, the author regularly sees HRSG specifications that include language requiring oxygen scavenger feed. It often takes protracted conversations with developers and owner’s engineers to explain that this chemistry is no longer valid for condensate/feedwater systems that contain no copper alloys. Lest any readers not believe this recommendation, the author invites them to refer to EPRI or International Association for the Properties of Water and Steam (IAPWS) documents for further confirmation. These documents also outline in detail the mechanism of two-phase FAC, which, as its name implies, may occur in spots where a combination of steam and water exist. In HRSGs, the LP drum is the most likely spot for two-phase FAC. Deaerators and feedwater heater drains in conventional units are other likely locations.

Boiler Water

The reader will note that the analysis list below includes only a few numeric guidelines. This is because in drum units the allowable concentrations of impurities are quite dependent upon boiler pressure. EPRI, IAPWS, and others have developed charts and guidelines that illustrate limits as a function of steam generator pressure. The values in those documents should be used as an initial baseline with subsequent clarification after unit startup. In very large measure, boiler water monitoring is necessary to protect steam purity.

The recommended boiler water analyses do not differentiate between HP and IP evaporator circuits, but it should be recognized that HP is more critical due to the higher pressure and temperature.

• pH: Immediate unit shutdown if the pH drops below 8.0. Recommended range for phosphate-treated units, 9.2 to 9.8
• Cation conductivity
• Specific conductivity
• Chloride
• Silica
• Sodium
• Phosphate (for those units on phosphate treatment)

Boiler water chemistry is much more complex than many people understand. The most important analysis is pH. But, an accounting is needed for the influence of ammonia that transports into the HRSG HP evaporator from the feedwater if tri-sodium phosphate in particular is utilized for boiler water treatment. Computer programs are available to do this. [3] Such programs incorporate cation conductivity and specific conductivity measurements to accurately calculate impurity concentrations, including the worst of the bad actors, chloride. But now, on-line chloride analyzers are available for direct monitoring. A brief discussion of this chemistry is in order at this point. A large condenser leak or chronic small leaks can introduce chlorides at a level that may overwhelm the neutralizing capability of phosphate or caustic treatments. Chlorides, like other impurities, can concentrate underneath porous iron oxide deposits on the waterwall tubes. The following equation outlines the reaction that then may occur at the tube surface.

MgCl2 + 2H₂O + heat → Mg(OH)2↓ + 2HCl

As can clearly be seen, a product of this reaction is hydrochloric acid. While HCl can cause general corrosion in and of itself, the compound will concentrate under deposits, where the reaction of the acid with iron generates hydrogen, which in turn can lead to hydrogen damage of the tubes. In this mechanism, hydrogen gas molecules, which are very small, penetrate into the metal wall where they then react with carbon atoms in the steel to generate methane (CH4), a large molecule:

2H2 + Fe3C → 3Fe + CH4↑

Formation and intrusion of the gaseous methane and hydrogen molecules causes cracking in the steel, greatly weakening its strength.

Hydrogen damage is very troublesome because it cannot be easily detected. After hydrogen damage has occurred, the plant staff may replace tubes only to find that other tubes continue to rupture. [4]

Phosphate chemistry is still common, but only tri-sodium phosphate (Na3PO4) is recommended as the treatment chemical. (The old, discredited coordinated and congruent phosphate programs utilized a blend of TSP and di-sodium phosphate, with perhaps an occasional pinch of mono-sodium phosphate.) TSP is more robust than ammonia in generating alkalinity.

Na3PO4 + H₂O ⇔ Na2HPO4 + NaOH

However, even a TSP program can be problematic due to the peculiar solubility characteristics of TSP.

At the high-temperatures of utility steam generators, most of the phosphate precipitates on boiler internals during normal operation. A reduction in unit load or shutdown allows the phosphate to re-dissolve. This “hideout” plays havoc with chemistry control, and particularly for combined-cycle units that cycle regularly. Continuous phosphate analyses rather than grab sample analyses are much better for tracking hideout. Hideout issues have pushed a number of plant chemists to abandon phosphate treatment in favor of caustic treatment or perhaps even AVT. The latter though offers virtually no protection against contaminant ingress. For any units that are operated on AVT, and really for any units at all with steam surface condensers, condensate polishing is recommended to protect the steam generators. Yes, condensate polishing adds to upfront equipment costs and requires extra labor, but the safety a polisher provides can be enormous.

Silica is a compound that will carry over vaporously into steam, which makes monitoring quite important in the boiler water and especially the steam. For example, in a 1000 psi boiler the recommended maximum drum water silica concentration is 2.3 ppm. In a 2,400 psi steam generator the recommended maximum is 0.22 ppm! But again to re-emphasize, the allowable limits for silica and many of the other impurities are based on protection of steam purity. The following analyses are critical in that regard.

Steam

Main and reheat steam samples are the most important of all steam samples because the analyses reflect the total contaminant transport to the turbine, both from carryover in the drums and from direct introduction by attemperator water.

Recommended on-line analyses are:

• Cation conductivity (or D.C.C.): ≤0.2 μS/cm
• Sodium: ≤2 ppb
• Silica: ≤10 ppb
• Chloride*: ≤2 ppb
• Sulfate*: ≤2 ppb

Cation conductivity is basically a blanket measurement of steam purity. It does not provide any speciation of impurities. But, C.C. is the criteria that turbine manufacturers often select for equipment commissioning. New evidence suggests a more realistic D.C.C. limit of 0.1 μS/cm to better protect turbines. [6] Sodium is an important monitoring parameter, not only for possible salt carryover but also for the potential of sodium hydroxide transport to the turbine. With a well-operated unit, the sodium concentration should typically be well below 2 ppb, and often significantly below 1 ppb. Silica monitoring is of course necessary to keep track of vaporous carryover of this compound, which can deposit on turbine blades.

The reader will note the asterisk by chloride and sulfate. These are important parameters, as it is the salts of chloride and sulfate (and sodium hydroxide if too much caustic is allowed to accumulate in the boiler water) that precipitate on the last stages of the LP turbine and then cause corrosion during outages. In the past, the only accurate method for trace chloride and sulfate analyses was by ion chromatography (IC). As the author knows from direct experience, IC can provide good data in the hands of a skilled operator, but the technology is expensive and requires significant attention. Very recently a new analytical technique has been introduced, [7] and has been successfully tested. The instrument requires virtually no maintenance and in a test the author helped arrange provided accurate readings for both Cl and SO4 down to 0.2 ppb. The technology shows excellent promise for trace monitoring of these most problematic impurities.

Monitoring guidelines typically also call for saturated steam analyses for C.C., sodium, and silica. These can be valuable for evaluating carryover from the boiler drums, but saturated steam quickly becomes a two-phase fluid in the sampling line, which makes representative sampling somewhat difficult.

One final comment, the reader will note in the reference list mention of the Electric Utility Chemistry Workshop and the International Water Conference. These are both excellent annual events for acquiring technical information and for networking with industry colleagues.

Author

Brad Buecker is a process specialist with Kiewit Power Engineers in Lenexa, Kan., and a contributing editor for Power Engineering.

By Russell Ray, Chief Editor

Among the nation’s top 20 power-producing combined cycle plants in 2015, Tampa Electric’s Bayside Power Station was No. 9, generating 8,916 gigawatt-hours of electricity for the year. The plant was No. 17 on the same list in 2014. Photo courtesy: Tampa Electric

Editor’s Note: The Power Plant Operating Performance Report is published annually in Power Engineering magazine and on the website of Electric Light & Power. This report is based on data and analysis provided by Energy Ventures Analysis. The data is collected from Form EIA 923 “Power Plant Report” and EPA’s Continuous Emissions Monitoring System (CEMS). What follows is a summary and analysis of the information. Enjoy!

The use of natural gas to generate power in the U.S. continued to climb in 2015, matching coal’s contribution to power production at 33 percent of the generation pie for the year. But a close examination of the top-performing power plants in 2015 confirms a trend borne from stricter regulations for coal-fired power and a new era of long-term stability in the price of natural gas.

According to data collected by Arlington, Virginia-based Energy Ventures Analysis, total output from the nation’s coal-fired plants fell significantly in 2015 versus 2014, while the amount of power produced by gas-fired plants rose amid historically low prices for the cleaner-burning fuel.

“You had a lot of coal to natural gas switching in certain areas,” said Phillip Graeter, an analyst at Energy Ventures Analysis, which specializes in energy and the environment.

In 2015, the average capacity factor for coal-fired plants in the U.S. fell from nearly 60 percent in 2014 to 51 percent in 2015, as utilities dispatched less coal-fired power to take advantage of sharply lower gas prices, according to data from the Energy Information Administration (EIA).

NATURAL GAS

The nation’s gas-fired combined cycle power plants produced 1.1 million GWh of power in 2015. That’s up 18.4 percent compared with 2014. Together, the nation’s top 20 gas-fired generators produced more than 194,000 GWh of power in 2015, up nearly 9 percent from more than 178,000 GWh in 2014.

Of the nation’s combined cycle gas-fired plants, Florida Power & Light’s West County Energy Center, a 3,844-MW plant near Palm Beach, produced the most electricity in 2015 at 20,428 GWh. Georgia Power’s Jack McDonough combined cycle plant was No. 2 at 17,849 GWh, followed by Duke Energy’s Hines Energy Complex at No. 3 with 12,223 GWh.

In addition to more power and slightly better heat rates, the nation’s combined cycle gas-fired plants ran longer and harder in 2015. According to data from the EIA, those plants ran, on average, at 52.3 percent capacity in 2015, up from 43.9 percent in 2014. The capacity factor for some combined cycle units exceeded 90 percent.

Tom Hewson, principal at Energy Ventures Analysis, pointed to significant advancements in gas turbine technologies, which have led to better heat rate efficiencies. In 2005, the average heat rate in the U.S. was 38.8 percent versus 46.4 percent today.

“As long as gas prices are low and gas is heavily utilized, you are going to see some incredible capacity factors,” Hewson said.

In addition, today’s heavy-duty gas turbines, in combined-cycle mode, are more than 60-percent fuel efficient, thanks to better materials capable of withstanding higher firing temperatures, improved blade design and advanced cooling technologies. In a few short years, industry officials say combined cycle fuel efficiency could reach 65 percent thanks to new manufacturing techniques and improvements in metallurgy.

Another significant factor behind higher capacity factors for gas-fired plants is the retirement of large amounts of coal-fired generation. Nearly 18,000 MW of generation capacity in the U.S. was retired in 2015, and more than 80 percent of that capacity was coal, according to EIA. About 30 percent of those coal retirements occurred in April 2015 after the Environmental Protection Agency’s (EPA) Mercury and Air Toxics Standards (MATS) rule went into effect. Much of that lost generation was replaced with gas, Graeter said.

Florida Power & Light’s Cape Canaveral Clean Energy Center, a 1,295-MW plant commissioned in 2013, and the Thomas C. Ferguson Power Plant, a 536-MW plant commissioned in 2014 near Austin, Texas, achieved the best heat rates among combined cycle plants in 2015, each recording a heat rate of 6.65 million British thermal units (MMBtu) per megawatt-hour (MWh).

The best heat rates among combined cycle plants in 2015 ranged between 6.6 and 6.9 MMBtu per MWh. That’s a significant improvement compared with heat rates a decade ago, when the best heat rates for combined cycle units hovered between 8 and 9 MMBtu per MWh.

“With more combined cycles being built that are very efficient, it will be unlikely that we’ll see any heat rate above 7 in our top 20 list for the foreseeable future,” Graeter said.

The $500 million Ferguson plant, which was constructed by Fluor Corp., uses about 35 percent less fuel per MWh than the plant it replaced. Zachry engineered and constructed the Cape Canaveral plant. Equipped with three H-class gas turbines from Siemens, Cape Canaveral has 50 percent more capacity and is 33 percent more fuel efficient than the old plant it replaced. Cape Canaveral was named 2013 Project of the Year by Power Engineering magazine.

“With higher dispatch, the units become more efficient and that drops the heat rates,” Graeter said. “We also had a significant build in combined cycles in 2015. Obviously, all of those new combined cycles are much more efficient. This led to a lower heat rate for the entire fleet.”

Big plants typically dominate the top 20 list. Twelve of the top 20 power-producing combined cycle plants are owned and operated by Southern Company and NextEra Energy. What’s more, many of the plants on the list were commissioned in the last two or three years and were built adjacent to the old coal-fired plants they replaced, Hewson said.

COAL

Meanwhile, the average capacity factor for the nation’s fleet of coal-fired plants fell from nearly 60 percent in 2014 to 51 percent in 2015. “This is because of low natural gas prices,” Graeter said.

Also, total generation from coal dropped significantly in 2015.

Output from all U.S. coal-fired plants dropped 14 percent to 1.34 million GWh in 2015 versus 1.57 million GWh in 2014. Production from Georgia Power’s Plant Scherer dropped from 18,478 GWh to 16,981 GWh. Despite the drop in production, Plant Scherer was still No. 2 in power production from coal-fired plants, behind Alabama Power’s James H. Miller Jr. Electric Generating Station, which produced 17,594 GWh of electricity in 2015.

Altogether, the top 20 coal-fired power-producing plants generated 279,144 GWh of electricity in 2015, down more than 8 percent compared with the top 20 generators in 2014.

In addition to coal-to-gas switching, another factor behind the decline in power production and capacity factors is the down time created by efforts to comply with the MATS rule, which became effective in April 2015. The down time required to make those upgrades contributed to the declines.

All of the coal-fired plants on the top 20 list have been retrofitted to comply with new standards for mercury, coal ash and wastewater, Hewson said. “We won’t see a lot of turnover on this list,” he said. “They are as safe as coal plants can be in this power market.”

The Paradise Power Plant in Kentucky, which was No. 18 in power production among coal-fired plants in 2015, will drop off the list in 2017 as the Tennessee Valley Authority moves forward with plans to replace Units 1 and 2 with a new gas-fired combined cycle plant. Instead of adding fabric filters and other equipment to comply with new emission standards, TVA found it would be cheaper to build a new combined cycle plant, Hewson said.

“They are putting in the gas pipelines as we speak,” he said.

But the outlook for coal-fired power may not be as bad as everyone thinks.

If President Barack Obama’s plan to cut greenhouse emissions from power plants survives the court, the EIA was projecting that another 55,000 MW of coal-fired capacity would be retired after 2016. But Donald Trump, a Republican, won the presidential election in November, which means Obama’s Clean Power Plan (CPP) will likely be scuttled and some of those plants will likely be preserved to provide low-cost, reliable power for consumers.

“If indeed the CPP goes away, a lot of the economics people were using to retire coal units changes quite a bit,” Hewson said. “Now, people might think a little bit different on carbon.”

Without the Clean Power Plan, he said, power producers may be encouraged to invest in the coal-fired plants they were expecting to retire.

NUCLEAR

There was little change in the top 20 producers of nuclear power.

The 3,970-MW Palo Verde Nuclear Generating Station in Arizona remained No. 1, producing 32,526 GWh of power in 2015. Generation from the entire fleet of U.S. nuclear plants totaled 797,178 GWh, essentially no change from 2014.

Total nuclear power capacity fell from 101,121 MW in 2014 to 99,837 MW in 2015. The decline stems from the December 2014 shutdown of Entergy’s 1,900-MW Vermont Yankee Nuclear Power Station.

The decommissioning of Vermont Yankee has been accelerated by decades under a deal to sell the plant to NorthStar Group, a New York-based remediation company.

The market for nuclear power began collapsing late in 2015 amid a sharp increase in renewable power and low-priced gas-fired generation.

“For a few months, a lot of those nuclear generators were not profitable,” Graeter said

The Fort Calhoun Nuclear Generating Station near Omaha, Nebraska was closed Oct. 24, after the Omaha Public Power District voted in June to retire the plant. It was the fifth nuclear plant retired in the last five years. Following the retirement of Fort Calhoun, the U.S. has 99 commercially operating reactors at 62 nuclear power plants nationwide.

Nuclear power accounts for 57 percent of the nation’s zero-carbon electricity, according to the EIA. Yet, the business of nuclear power is collapsing because the market cannot support the nation’s available capacity.

More than a dozen U.S. nuclear power plants have either closed, are in the process of closing or are at high risk of closing.

“We’re seeing power prices drop significantly,” Graeter said. “That’s really undercutting the expected energy revenue those nuclear units need (to cover fixed costs).”

New York is the first state to offer support to an industry struggling to stay afloat. Earlier this year, state regulators approved the Clean Energy Standard (CES). Other states, including Illinois, may follow suit with similar measures.

The CES encourages the use of nuclear and renewable power by mandating a 40-percent reduction in greenhouse gas emissions by 2030.

The plan also requires power providers to get half of their power supplies from clean and renewable resources by 2030. Most importantly, the rule would pay the state’s nuclear plants up to $965 million in zero-emission credits.

The New York Public Service Commission, which approved the CES, described it as a “public necessity” that would benefit the state’s grid, its customers and the environment.

Thanks to the new incentives, Entergy’s Fitzpatrick nuclear plant, which was scheduled for closure in 2017, was purchased by Exelon and will continue producing power for homes and businesses in upstate New York.

“This is really helping them become financially whole again,” Graeter said.

By Anthony Armpriester and Ted McMahon

The Petra Nova project applies carbon capture technology to an existing coal-fired power plant to capture 1.6 million tons of CO₂ per year. The project, which is expected to be completed by the end of 2016, will capture 90 percent of CO₂ from the power plant. Photo courtesy: NRG Energy

When construction is completed, expected by the end of 2016, Petra Nova Parish Holdings, LLC (Petra Nova) will become the largest post-combustion carbon capture project installed on an existing coal-fired power plant. It is designed to capture 90 percent of the carbon dioxide (CO₂) from a 240 MWe slipstream of coal-fired flue gas-approximately 5,000 tons of CO₂ each day, or 1.6 million per year. Funded in part by the U.S. Department of Energy (DOE), Petra Nova is a joint venture between NRG Energy, Inc. (NRG) and JX Nippon Oil and Gas Exploration (JX) at the W.A. Parish Plant (WAP) in Thompsons, Texas, southwest of Houston.

DOE regards addressing climate change-from the development of new, clean energy technology to the mitigation of the effects of carbon emissions-as a top priority. And, as part of the DOE’s national laboratory system, the National Energy Technology Laboratory (NETL) is deeply committed to furthering the department’s mission, thereby advancing the security and energy future of our nation. NETL has extensive experience in developing technologies to help mitigate the environmental effects of fossil fuel combustion for power generation, including carbon capture.

NRG realizes climate change is a significant environmental challenge, and is working to be part of the solution. As the nation’s largest independent power producer, NRG is leading the industry with a goal at the forefront of sustainability efforts across the country-to reduce carbon emissions 50 percent by 2030 and 90 percent by 2050. Moving forward on these goals, In addition to moving forward on schedule and on budget on construction of Petra Nova, NRG has commenced construction on numerous community solar projects, including the largest in the U.S., converted multiple large coal-fired generating units to natural gas and is developing several energy storage and preferred resources projects.

NETL is using their expertise to provide project management support to NRG and JX for the execution of the Petra Nova project. This large-scale demonstration, the largest of its kind to date, will show how carbon capture technologies can have a meaningful and positive impact on the environment, while allowing fossil fuels like coal to remain a viable energy source for many more years. The project will also demonstrate technological advances aimed at lowering the energy requirement of the capture process; demonstrate the concept of integrating a cogeneration system into the carbon capture process, which provides energy to operate the system; and establish the impact of CO₂ capture and storage operations on the cost of electricity.

Carbon Capture Process

The Kansai Mitsubishi Carbon Dioxide Recovery (KM-CDR Process) resembles other amine-based gas treating processes, which have been used for many years in the natural gas, petrochemical, and refining industries, but MHI has adapted and scaled this process to recover CO₂ from low-pressure, oxygen containing streams, such as power plant flue gas.

Simplified Process Flow Diagram (Generic) 1

The MHI process uses a proprietary KS-1 high-performance solvent for CO₂ absorption and desorption that was jointly developed by MHI and the Kansai Electric Power Co., Inc. Figure 1 represents a simplified overview of the process with a description of how it works below.

The process consists of three main columns: a Quencher, where the flue gas is conditioned and prepared for the absorption process; an Absorber column, where CO₂ is absorbed into the amine-based solvent through a chemical reaction; and a Regenerator (or Stripper) vessel, where the concentrated CO₂ is released and the original solvent is recovered and recycled back through the process.

The flue gas is first routed to the Quencher for flue gas conditioning (i.e., cooling, dehydration, and trim acid gas removal). The flue gas is cooled because the absorption reaction is affected by the temperature of the flue gas (i.e., absorption of CO₂ in the solvent is an exothermic process that favors lower temperatures). This cooling process causes the water to condense out of the wet flue gas; hence, the dehydration. Next, certain constituents entrained in the flue gas, if not removed, will contaminate the solvent so the gas is scrubbed of these contaminating constituents in a deep polishing scrubber.

The cooled and cleaned gas exits the top of the cooler column where it is pulled through the blower. The blower, located downstream of the Quencher, is used to pull the slipstream off of the host unit and overcome the pressure drop through the plant as it passes up through the Absorber column.

From the blower, the flue gas enters the bottom of the Absorber column and flows upward through the packed column beds where it chemically reacts with the solvent (loading the solvent with CO₂). Counter-current flow, through multiple stages of structured packing, maximizes contacting surface areas and mass transfer rates of the CO₂ into the solvent. The CO₂-depleted gases are then washed and vented to the atmosphere.

The CO₂-rich solvent leaves the bottom of the Absorber and is pumped through a heat exchanger, heating the solvent as it is routed to the solvent regeneration section of the plant. This is the section where the weakly bonded compound is broken down with the application of heat, in the form of steam, to liberate the CO₂ and leave reusable solvent behind. The liberated CO₂ is sent to a compressor to compress it up to supercritical phase (resembling a liquid but expanding to fill space like a gas), for pipeline transport. The CO₂-lean solvent is routed back to the absorber, through a heat exchanger (for cooling), to repeat the process. A portion of the cooled lean solvent is diverted through a solvent filtration system to remove solution contaminants.

System Arrangement 2

Some of the solvent is lost during the process because of a variety of reasons, including mechanical, vaporization, and degradation. Furthermore, some contaminants, such as heat stable salts (sulfates, nitrates, and oxalates of amine) and thermal/oxidation degradation products, cannot be removed in the solvent filtration package and must be removed through a periodic reclaiming operation. Fresh solvent is added to make up for these losses incurred in the process.

This process is energy intensive and requires heat in the form of steam to release the CO₂ from the solvent and power to run the equipment, including the very large CO₂ compressor. A cogeneration unit (cogen) was constructed to supply these utilities. This standalone cogen approach simplifies retrofit, does not change basic combustion technology on the host unit, provides the flexibility to match the specific parasitic energy demands required, and allows for the safe operation of the system without disrupting existing operations. Finally, cooling is required (flue gas cooler, absorber wash sections, compressor) that needs to be served with the construction of a new cooling tower.

Design Considerations

The CO₂ capture plant is designed to process a portion of WAP Unit 8’s coal combusted flue gas to provide the capture capacity equivalent to a 240 MW gross unit. The original design team started with a 60 MW equivalent project, but it became clear early in the development cycle that having a robust CO₂ initial injection rate for Enhanced Oil Recovery (EOR) is essential to promoting a meaningful field response. After balancing the risks, technical limitations, and finite resources with the economies of scale decided to expand the project to a 240 MW equivalent.

With the system size determined, it is preferred to process the flue gas downstream of an installed FGD system because sulfur dioxide (SO₂) in the flue gas has an adverse effect on the amine absorption process. The team selected WA Parish Unit 8 for the project; however, the vintage FGD on Unit 8 was designed to be only 82 percent efficient, which does not achieve outlet concentrations at the levels necessary to minimize solvent contamination, so a polishing sodium scrubber within the KM-CDR Process is still required.

With Unit 8 the selected host unit, the interconnecting take-off point required evaluation. Several locations were considered and. various iterations of computational fluid dynamic (CFD) allowed the team to determine that the bottom of the Unit 8 stack breeching duct is the optimum takeoff location for the carbon capture system (CCS) flue gas supply duct.

Another challenge the team addressed was where to locate the CCS on the congested site. Based on the existing site constraints and general footprint requirements of the MHI process, the optimal location for the CCS was identified to be just west of (behind) the Unit 7 baghouse. This space was the largest area adjacent to Unit 8 that required the least amount of facility relocation/disruption. A warehouse occupied the space and needed to be relocated, but otherwise the location was determined to be reasonably open for a brownfield retrofit.

An interesting piece of the project is the large CO₂ compressor. It is generally recognized that pipelines are the most economical and safest method for transporting large volumes of CO₂, and the most efficient state for pipeline transport is a dense-phase liquid. In this ‘supercritical’ mode, the captured CO₂ has to be compressed to a pressure above the critical pressure prior to transport [which occurs at a pressure higher than 1,100 pounds per square inch (psi) above 90°F for pure CO₂]. Accordingly and given the high flow volumes for this project, centrifugal compressors are typically used in these applications.

The physics to compress CO₂ in a centrifugal compressor is the same as that for any other gas; however, CO₂ has many unique characteristics (comparatively higher molecular weight gas) that must be considered in the compressor design. The team investigated the best solution from existing turbo machinery providers and concluded, based on economics, efficiency, and power consumption, that integrally geared (IG) turbo compressors incorporate the optimum design concept for CO₂ compression. This is because IG machines have the ability to operate their impellers in close proximity to their optimum speeds. Couple this with the reduction in inter-stage pressure loss and ability to perform inter-stage cooling, the IG machine provides an overall efficiency improvement over similar inline machines. Consequently, the CO₂ Compression System selected for this project is an 8-stage IG machine split into a low pressure (LP) side and a high pressure (HP) side, with a triethylene glycol (TEG) dehydration unit in between, which removes moisture from the CO₂. The CO₂ Compressor package selected for this project has a large (27,000hp) motor to increase the CO₂ up to supercritical conditions for pipeline transport.

Cogen Facility and BOP Systems

In addition to locating the CCS process, the team needed to locate Balance of Plant (BOP) equipment to service the CCS. The following systems were needed:

• Combustion turbine generator (CTG)/heat recovery boiler (HRB) cogeneration system
• Cooling tower
• Water treatment facilities (deminerlized water “demin” and waste water treatment)
• BOP piperack
• Integration of existing facility site services (i.e., raw water, potable water, firewater, ammonia, etc.)

All of the above-listed components needed for the integration of the BOP systems are commercially available and well-proven. Previous study work determined the type and location of the cogeneration system to be within an underutilized area northwest of the CCS island. The other system components: cooling tower, water treatment facilities, and associated interconnections (between the islands as well as existing site facilities), were identified and laid out in a prudent best-fit arrangement. For example, to minimize the large-diameter cooling water piping runs, the cooling tower was eventually sited within the CCS island because it is the user of cooling water. Figure 2 illustrates the BOP and CCS general arrangement of the systems at Parish.

For the cogen unit, the team explored a wide array of combinations capable of producing the range of steam required, including various configurations of frame machines, aeroderivatives, micro turbines, and package boilers to flexibly serve the unique parasitic energy needs of CCS. As a result of this work, the prime mover of the cogeneration facility was identified to be GE 7EA combustion turbine (CT)-which was installed in a separate exercise in 2013. With the early installation of this equipment in simple cycle peaking configuration, a critical piece of infrastructure was already in place and offered a near-term source of revenue in advance of carbon capture integration.

Then, during construction of the CCS island, the existing CT exhaust stack was removed and a Heat Recovery Boiler (HRB) was installed. The exhaust gas from the CTG will be directed through the HRB to raise single pressure steam at the conditions needed by gas treatment process. Duct burners were also installed to supplement the exhaust gases and to help control steam production as required by the CCS system. The HRB design includes environmental controls to minimize emissions of carbon monoxide and nitrogen oxides from the Cogen unit.

Conclusion

Coal is an abundant and domestic fuel that provides about 38 percent of the electricity generated in the U.S. Demand for electricity, vital to the nation’s economy and global competitiveness, is projected to increase by 25 percent by 2040. The continued use of coal is essential for providing an energy supply that supports sustainable economic growth. Unfortunately, the average generating unit age is nearly 42 years old and these units are in need of substantial refurbishment or replacement. Additional capacity must also be put in service to keep pace with the nation’s ever-growing demand for electricity.

However, coal is also a carbon-intensive fuel. Development of post-combustion capture is necessary to ensure we can continue to develop this abundant energy resource responsibly and sustainably. Additional development and demonstration is needed to improve the cost and efficiency of technologies that capture and store CO₂ emissions. Carbon capture technologies offer great potential for reducing CO₂ emissions and mitigating global climate change, while minimizing the economic impacts of the solution.

The Petra Nova Project represents an important step in advancing the commercialization of technologies that capture CO₂ from the flue gas of existing power plants. Once the plant becomes operational, its success could become the model for future coal-fired power generation facilities. The addition of CO₂ capture capability to the existing fleet of power plants will enable those plants to continue to produce clean electricity and simultaneously reduce the impact of CO₂ emissions.

Authors:

Anthony Armpriester is director of Engineering at NRG Energy, Inc. Ted McMahon is project manager at the National Energy Technology Laboratory.

AMETEK Land, the leading industrial combustion efficiency and environmental pollution emissions monitoring specialist, announces a number of enhancements to its Lancom 4 Portable Gas Analyser to improve usability and provide attractive features as standard.

Now available as a free download, Lancom 4’s innovative data acquisition software, Insight, is a powerful tool that allows users to interface their analyser with a PC for remote control and data logging. Insight offers graphing and analysis tools for data visualisation and reporting purposes, providing even easier access to data. Communications between Insight and the user’s PC requires a USB-RS232 interface converter, which is now supplied with every Lancom 4 for quick and easy set up.

In addition, Lancom 4 now includes Wake and Sleep functions, allowing measurements and data logs to be recorded over an extended period, and a rugged Carry Case, ensuring that the instrument is protected at all times when in use. All are now supplied as standard at no extra charge.

Upgrading to Lancom 4 also has been made much easier. Hardware items, such as external printers or analogue output modules, can be simply plugged in, with no firmware configuration needed. This means that these items can be fitted in the field, avoiding the need to return the instrument to the factory.

Lancom 4 is renowned as the world’s most versatile and accurate portable flue gas analyser for checking or testing a boiler system or pollutant process. It has the capability to monitor up to 9 different gases, a total of 17 measurement parameters with one instrument as well as the ability to data log up to 250,000 records.

Sensors

Schaevitz LLC Alliance Sensors introduced its GHS-19 series of spring-loaded LVIT (Linear Variable Inductive Transducer) gaging sensors. They are contactless devices designed for dimensional gaging and position measurements in factory automation and in various industrial and commercial applications such as automotive testing, mil/aero test stands, robotic arms, and packaging equipment, where the sensing element cannot be attached to the object being measured. Using LVIT technology with its simple coil design, the GHS-19 series offer excellent stroke-to-length ratios.

GHS-19 Features:

– Low cost drop-in replacement for spring-loaded LVDTs, with same connector and pinouts

– 0.75 inch (19 mm) diameter aluminum or stainless steel body with1/2-20 mounting thread

– EXCELLENT stroke-to-length ratio means much shorter housings

– Full scale ranges from 0.5 to 4.0 inches (13 to 100 mm)

– 1 pound (0.45 kgf) maximum tip force

– Contactless operation prevents sensor wearout from dithering or rapid cycling

GHS-19 sensors have a 0.75 inch (19 mm) diameter aluminum or stainless steel body with a 1/2-20 UNF-2A threaded nose 1.5 inches (38 mm) long and two 0.75 inch (19 mm) hex jam nuts for drop-in installation in place of spring-loaded DC-LVDT gage heads. The sensors’ 0.25 dia. probes are equipped with a No. 9 contact tip, producing a maximum tip force of 1 pound (0.45 kgf). They are offered with a PT02-10-6P. Operating from a variety of DC voltages, these sensors are available with a choice of one of four analog outputs, and they all include ASG’s proprietary SenSet field calibration feature.

Instrumentation

The Sensor Connection a division of Harold G. Schaevitz Industries LLC, has expanded its line of measurement and control instrumentation with the addition of the model TCA-MS-K-1. This Single Channel Type K Thermocouple Amplifier Module converts the low output voltage signal from a Type K thermocouple probe to a single independent linearized 0 to 5 VDC output voltage. This output is ideal for interfacing to instrumentation equipment including data loggers, temperature indicators, chart recorders, and controllers. A unique feature of this product is the fast dynamic response of 1 mS.

The Sensor Connection a division of Harold G. Schaevitz Industries LLC is an American company whose management has a combined experience of over 50 years in the sensor industry. We have a technically trained staff to help you select the ideal sensors for your application. Our core product offering includes Exhaust Gas Thermocouples (EGT) Probes, Thermocouples, RTDs, Linear Position sensors, Rotary Position sensors, Pressure sensors and switches. In addition to our standard products, we have capabilities to design and build custom products to suit your specific application. Major markets served include Motorsports, Marine, Heavy Vehicle, R&D Test labs, Power Generation, Military, and Industrial Manufacturing Assembly & Test.

Sensors

Alliance Sensors Group has expanded its sensor product offering by adding to its line the LRL-27 Series of long-stroke LVIT position sensors. These are contactless devices designed for factory automation systems and a variety of heavy duty industrial or commercial applications such as solar cell positioners, wind turbine prop pitch and brakes, material chute or gate positioners on off-road or agri-vehicles, robotic arm position feedback, and packaging equipment.

Operating from a variety of DC voltages, the LRL-27 series offer a choice of four analog outputs, and all units include ASG’s proprietary SenSet field scalability feature. With their compact yet robust design, superior performance, and excellent stroke-to-length ratio, LRL-27 sensors are ideal for industrial and OEM position sensing applications.

LRL-27 Features:

– LVIT Technology (Linear Variable Inductance Transducer)

– Contactless operation prevents wearout from dither or cycling

– 5 Nominal ranges from 250 to 450 mm (10 to 18 inches)

– Excellent stroke-to-length ratio

– 27 mm (1.05 inch) diameter anodized aluminum housing sealed to IP-67

– Radial cable exit version comes with swivel rod eye ends

– Axial termination versions with either M-12 connector or 1-m cable

The LR series also includes the LR-27 for shorter stroke applications, LR-19 series for applications where a short length and smaller diameter body is required, and the spring loaded LRS-18 series. Technical data sheets and additional information can be found at www.alliancesensors.com.

Fans

Multi-Wing America has released the OPTIMISER 10 Fan Specification App. OPTIMISER 10 is an easy-to-use resource for original equipment engineers to specify the most efficient, tailor-made Multi-Wing fan for their application. It is ideal for specifying fans in heating, ventilation, air conditioning and refrigeration (HVACR), as well as engine cooling in off-highway equipment and power generators.

OPTIMISER 10 Fan Specification App features an intuitive user interface, advanced natural-frequency sound calculations, and visual display of total efficiency on the fan performance curves. OPTIMISER 10 offers blade profile previews with available diameter ranges, materials and rotations.

“This app allows our customers to identify the most optimized and efficient customized fan for their equipment,” says Jim Crowley, president of Multi-Wing America. “OPTIMISER 10 also provides important data on sound, total efficiency and performance curves that engineers need to develop the best fan specification.”

Cables

CDM Electronics announced the availability of custom overmolded cable assemblies designed to withstand demanding environmental conditions in a wide range of industries including commercial, industrial, medical, military, and agricultural. The overmolding process provides a seamless seal of the junction between a connector and cable to ensure the utmost protection against liquids, dust, heat and impact. Overmolding additionally enhances strain and flex relief, as well as maintains the integrity of connections in applications requiring repeated mating/unmating cycles.

Designed for long life and reliable performance, CDM’s overmolded cable assemblies improve performance and reduce total cost in an extensive variety of applications in which harsh environments, abrasion and EMI/RFI are factors. As these assemblies are usually custom, they may be engineered for a broad array of applications including intermediate and light-duty power cable assemblies for industrial usage, RF coaxial assemblies, military/tactical assemblies, D-subminiature and mini assemblies. Overmolded assemblies are equally suitable for wire harnesses, telecommunications and medical assemblies.

CDM’s overmolded cable assemblies offer 360-degree strain relief and EMI/RFI shielding, optimized pull strength, and flexible support at the cable exit. They are provided with an unlimited variety of interconnects, cables, and thermoplastic materials in a range of colors to provide unparalleled design flexibility and aesthetics. Common materials include polypropylene (PP), Santropeneâ„¢ (TPV), Polyvinyl chloride (PVC), polyethylene (PE), acrylonitrile butadiene styrene (ABS) and thermoplastic polyurethane (TPU).

Bulk Handling

Building upon the standard crowned roller, the Martin® Roller Trackerâ„¢ from Martin Engineering uses a unique ribbed lagging made of durable polyurethane to increase performance and wear life. The roller does not come in contact with the belt edge, which means no fraying and excellent tracking for single-direction or reversing belts. The result is more centered cargo loading, less spillage and increased safety from the hazards of belt wander, leading to higher productivity and a lower cost of operation.

Used for lower tension belts from 500-1500 mm (20-60 in.) in width, running at a speed of up to 5 m/s (984 fpm), crowned roller trackers have a slightly larger diameter at the center than at the edges. Realignment is based on the basic principle of the belt contacting the raised portion of the raised portion of the roller first (the crown) first.

When the belt wanders off-center, the assembly tilts to the opposing side and steers it back toward the normal position. By retaining a consistent path on the return side, the belt passes over the tail pulley and enters the loading zone centered, delivering equal cargo distribution and reducing spillage.

Previous designs had lagging made out of a single smooth piece of rubber or soft gripping material, to retain a hold on the belt and train it back into position. Being in constant contact across the entire surface of the belt caused the material to wear quickly, requiring frequent and expensive replacement. The Martin Roller Tracker improves upon this technology with ribbed lagging made from thick, rugged polyurethane. Covering the entire belt width using less surface contact, the ribbed design reduces lagging wear and improves resistance to better train the belt back to center. This design is also very cost-effective to manufacture, contributing to a reduced purchase price.

Industrial Lighting

Larson Electronics, a company that specializes in industrial lighting equipment, has announced the release of a 150 watt explosion proof LED light mounted atop a telescoping aluminum pole.

The EPL-APM-150LED-RT explosion proof LED work light produces 17,500 lumens of light capable of illuminating an area 9,500 square feet in size. The telescoping pole mount is designed for permanent mounting operations while offering five foot to 12 foot adjustability. The LED light head on this unit produces a wide flood beam of light that is ideal for illuminating large workspaces and job sites. The light head on this unit contains 12 LEDs arranged in rows and paired with high purity optics producing a 60 degree flood beam. The light fixture carries an IP67 waterproof rating, is dust-proof, and protected against high pressure jets.

This telescoping LED work light is comprised of a removable LED light head mounted atop an anodized aluminum adjustable pole fabricated with 2.5 inch by 2.5 inch tubing for the first stage, two inch by two inch tubing for the second stage, and one inch by one inch tubing for the third stage. The tower is anodized and the brackets are powder coated for durability and rust resistance. The EPL-APM-150LED-RT is equipped with a powder coated flat mounting bracket that is easily attached to any flat surface. This hazardous location LED work light is equipped with 50 feet of 16/3 SOOW oil and chemical resistant cord that is terminated in an optional explosion proof cord cap. The light is universal voltage capable and can be operated with 100 to 277 volts AC.

Monitoring

Brà¼el & Kjà¦r announced the release of its new Vibration Monitoring Terminal Type 3680.

The device enables users to effectively:

– Protect against structural damage risks in construction and mining

– Assess human response to ground-borne vibration from road and rail traffic

– Monitor background vibration to ensure sensitive equipment operates correctly

The robust unit provides uninterrupted, tri-axial, real-time ground vibration measurement to help avoid harming buildings. It automatically delivers alerts to avoid breeching set limits and provides reports proving regulatory compliance.

The Vibration Monitoring Terminal also reliably assesses vibration impact from traffic. It enables users to efficiently conduct background surveys prior to new construction, as well as receive accurate data to evaluate vibration mitigation techniques.

In addition, the system monitors background vibration for organisations such as hospitals, semiconductor manufacturing plants and museums. It helps ensure patient comfort at medical facilities, trusted monitoring of delicate equipment to avoid costly errors and reduced risk of artefact damage.

The Vibration Monitoring Terminal operates stand-alone or with Sentinel for comprehensive, multi-location, vibration compliance monitoring. Standalone devices come with a smartphone app enabling setup, remote display and operation from anywhere and data transfer to standard post-processing applications.

Sensors

SignalFire Wireless Telemetry introduces the Pressure Scout, an intrinsically safe wireless pressure sensor that supports pressure monitoring and alarm reporting as part of the SignalFire Remote Sensing System. The first in a line of wireless integrated sensors, the Pressure Scout consists of a pressure sensor integrated with a wireless node and internal battery. The Pressure Scout is a low-cost alternative to conduit-wired or other wireless pressure monitoring solutions. Ideal applications for the Pressure Scout include well tubing and casing pressure monitoring, tank level monitoring and compressor station status monitoring.

As part of a wireless remote monitoring and control network, the Pressure Scout provides a robust, long-range (up to ½ mile) transmission to the Signal Fire Gateway where pressure data becomes available via a Modbus RTU or TCP interface. Available in standard pressure ranges, the Pressure Scout performs rapid (5 sec) pressure sampling with configurable alarm reporting (report by exception). Units offer local pushbutton zeroing. Operable in temperature ranges from -40°C (104°F) to 80°C (176°F), the Pressure Scout operates in challenging outdoor environments, sustaining signal strength through terrain, structures, or weather. Class 1, Division 1 certification is pending.

Operating on extremely low power, the Pressure Scout utilizes an internal battery that powers the integrated pressure sensor and radio for up to 10 years. For example, an application requiring a five second pressure sample interval for alarming, with a one minute reporting interval will last for 6.5 years. Extremely compact, units are both easy to install and maintain.

The iPhone 7, the Tesla Model 3, the latest 4G organic light emitting diode (OLED) television. Cool stuff, right? The whiz-bang hallmarks of an ever-advancing, innovative, high-tech society.

And yet, how many people do you know who actually own any of these things? Some, certainly – especially the iPhone 7 – but probably not most. [And before I get any hate mail, yes, I know the Tesla Model 3 is not actually on the streets yet, but you can reserve a purchase slot for $1,000.] The majority of us take good care of our existing toys and tools and transition to the newer technology when the price has come down, when the bugs have been worked out, when our current version is finally showing its age. In other words, we are maintainers.

I stole the title of this column from an essay by Andrew Russell and Lee Vinsel published by the digital magazine Aeon. One line from the lead paragraph of the article reads: “Maintenance and repair, the building of infrastructure, the mundane labor that goes into sustaining functioning and efficient infrastructure, simply has more impact on people’s lives than the vast majority of technological innovations.” Hard to argue with that.

Think back to the Northeast Blackout of 2003, which knocked out more than 61,000 MW of capacity, left 50 million people without power across parts of the United States and Canada, and resulted in 11 deaths. A devastating event to be sure…and the economic impact was actually many times greater than the value of the lost electricity. A 2004 analysis by the Electricity Consumers Resources Council (ELCON) reviewed a number of economic studies and pegged the total cost at $4-$10 billion, encompassing lost wages, overtime costs, food spoilage, disrupted deliveries, and more. ELCON offered a challenging conclusion: “From a public policy perspective – in the US or Canada – it really does not matter if the total economic damages are $4 billion, $6 billion or $10 billion, or anywhere in between. The point is that this type of event is unconscionable to the extent that a single utility’s failure to properly trim trees is deemed the ‘root cause’ of the August 14 Blackout.”

Maintenance matters, whether it’s the grid, a power plant fleet, the highway system…or your house, your car, your body. There’s nothing profound about that statement. The message, however, is easily marginalized in our society’s mania over the newest app, our homage to the fruits of innovation.

Which is not to say that innovation is unimportant. The world needs both innovators and maintainers, because both are essential in keeping the wheels of progress moving forward.

Russell and Vinsel get rather philosophical at the end of their essay: “Entire societies have come to talk about innovation as if it were an inherently desirable value, like love, fraternity, courage, beauty, dignity, or responsibility. Innovation-speak worships at the altar of change, but it rarely asks who benefits, to what end? A focus on maintenance provides opportunities to ask questions about what we really want out of technologies. What do we really care about? What kind of society do we want to live in? Will this help us get there? We must shift from means, including the technologies that underpin our everyday actions, to ends, including the many kinds of social beneficence and improvement that technology can offer.”

I’m not sure I’d cast the differing roles of innovators and maintainers in such stark, opposite terms. In fact, I don’t see an inherent conflict between the two – they can and should co-exist.

The “innovation” in the nuclear sector could envelop a wide range of advances. Fusion, traveling wave reactors, maybe even small modular reactors sit on one end of the curve, representing technological advances that could herald a re-imagined nuclear renaissance.

But “innovation” also could take the form of new ways of thinking about existing technology, focused on how we can run and maintain nuclear plants to be safer, cheaper, and more efficient. Can advanced sensors, data analytics, and augmented reality provide the tools to soup up the mundane maintenance of nuclear plants and revitalize their technological and economic viability?

Let’s face it. There won’t be a large number of new nuclear plants in North America over the next 15 years. Demonstrating to the world that the industry can maintain these plants through 60-80 years of operation may be the best path to sustained relevance.

All hail the maintainers.

We may as well address the elephant in the room in this first issue produced after the election – what’s going to happen to renewable energy under President Donald Trump?

For instance, one of Trump’s major campaign promises was to bring back coal and coal mining jobs, though whether that’s even possible could more than fill another column. He also pledged to encourage both the production and use of natural gas in his official campaign website.

Though the website is mum on the subject of renewables, he declared investment in solar to be “a disaster” during the debates and he’s frequently called large wind turbines “monstrosities” that kill birds.

Beyond what Trump has actually said, conventional wisdom from the pundits and his eagerness toward opposing President Obama’s initiatives suggests he’ll pull out of the Paris accords, trash the Clean Power Plan and end tax credits for renewables.

On the surface it would seem those in the renewables business might face dark days under the Trump administration, but it’s not time to start folding up those solar cells into coal storage bins quite yet. In fact, renewable energy is set to weather the Trump administration just fine.

To start, even reliably red states have quietly embraced renewable energy. Texas, the long-time capital of oil production, has also become the top producer of both solar and wind energy. Other conservative strongholds such as North Dakota, Arizona and Wyoming also rank high on wind and solar production, and it hasn’t sparked a political revolt.

Then there’s Kansas. In general, the state hasn’t been faring well under Governor Sam Brownback’s ambitious economic experiments, and the state has been hemorrhaging jobs.

One exception has been wind production, which continues to blossom in the state.

That strong flow of jobs and revenue is too much of an oasis to monkey around with.

While we’re on the subject of government, the solar tax credits extension managed to pass in a polarized and Republican-led Congress.

While it’s true a Trump administration might embolden Congress to change as much as they can as long as the Republicans hold two of the three branches of government, tax credits for renewables isn’t nearly as big a lightning rod to the general public as, for instance, Obamacare.

But even if the political winds of change turn into a storm against renewable, there’s always market forces. And right now, renewable energy looks like a smart investment. The cost to build and maintain wind and solar facilities continue to drop as the technology continues to improve.

A growing number of large companies are making very bold and very public investments in renewables, including Walmart, Microsoft and Google. Amazon has been a particularly strong leader in renewables, as the company has built enough solar and wind facilities to already power over 40 percent of its cloud services this year, with plans to increase that to 50 percent next year.

Don’t forget the parade of countries, most notably Canada, France and the UK, that have pledged to end power production via coal by 2030 or earlier thanks to the UN’s Paris Agreement. While natural gas remains an option, the rush from coal will create a huge opportunity for renewable projects.

Long story short, interest in renewable energy remains high, and companies dealing in wind and solar will stay busy.

And that will ensure the continued development of the technology, which could further lower prices, improve efficiencies, and build interest.

Don’t get worked up by the bluster and posturing. Even if our new political reality takes away existing incentives, the future of renewable energy will just keep getting brighter.

The United States’ approach to cyber security for its critical industrial infrastructure and control systems has been a mixture of voluntary guidelines and standards, combined with regulated congressionally-mandated standards. Somewhat predictably, the outcome has been hampered by the conservative risk appetites of enterprises. Federal regulations and standards prescribed by the National Institute of Standards and Technology (NIST) and the Federal Information Security Management Act (FISMA) have also helped drive security on IT-based systems.

The term Industrial Control System (ICS) encompasses several types of control systems used in industrial production, including Supervisory Control and Data Acquisition (SCADA) systems, Distributed Control Systems (DCSs), and other smaller control system configurations like Programmable Logic Controllers (PLCs), which are often found in natural gas-fired generation.

Because of the inherently isolated design of ICS, security was assumed to be automatic. This, however, has proved far from true. PLC and SCADA systems can be comprised. Simply placing a firewall as a logical perimeter defense mechanism, leaving all internal systems with very few or no security controls, only allows for a greater compromise, since a disgruntled employee could sabotage a system from the inside.

Another challenge for ICS security is slow vendor adoption of security solutions within applications and hardware solutions. A natural gas-fired generation plant has multiple interconnected systems, and each vendor utilizes its own unique solution, which is independent of other vendors’ solutions. This approach results in multiple vendors providing multiple solutions to solve the same problem of cyber security. The lack of harmonized, integrated cyber security solutions exacerbates problems inherent to the administration of cyber security within an ICS.

Gas-fired plants utilize systems such as OSI PI, Emerson EDS, RTU, Historians, and other tools on their network to dispatch plants remotely, curtail power for wind assets, and manage fleet operations. Power generators can reduce the total cost of ownership and improve plant reliability by reducing forced outages using integrated cybersecurity solutions. The placement of a firewall between the ICS system and any other network that interfaces with the DCS or SCADA helps achieve a goal of separating control network into zones. Network segregation is the first step to an in-depth defense approach.

Secondarily, plant owners should identify all network traffic that must leave the SCADA or DCS network by TCP and UDP port and make sure rules and access control lists (ACL) are hardened to only those ports needed to communicate in or out of the network. By hardening a firewall, engineers can eliminate significant unwanted traffic from entering or leaving a DCS system.

In 2012, then-Homeland Security Secretary Janet Napolitano reported that cybercrime was the number-one threat to the United States, ahead of terrorism. This remains the case today. However, the gas-fired power industry is not sitting still. Gas industry professionals and engineers are fighting back by strengthening control center security, generation plants, storage facilities, and other critical infrastructure.

The implementation of regulated standards for the gas industry, combined with a structured monitoring and enforcement mechanism, will be required for all critical infrastructure enterprises to maintain and grow a society’s standard of living. Without regulated standards, the temptation to do nothing (or the bare minimum) exists, which could result in a greater loss to the enterprise and society than the cost of implementing security measures in the first place. Critical infrastructure for gas-fired generation has moved from mechanical controls to digital technologies, computer networks, Internet-driven devices, and virtual infrastructure.

Enterprises want the best for their stakeholders, and that means keeping the valves pumping gas while maximizing returns on investments. But there are many instances where executing the right thing for the enterprise or society comes into direct conflict with maintaining profitability or working within budgets. This can delay the execution of wise decisions, thereby impacting security.

There’s no flawless system for eliminating cyber threats. Nation states have learned from Stuxnet that attacking critical infrastructure like natural gas-fired generation plants presents an easy method to injure organizations monetarily, or even threaten the lives of people. But by applying the right methods, gas-fired power plants can achieve a layer of defense. They can implement malware prevention, account management, intrusion detection, patch management, and security monitoring. Such building blocks are crucial to the health of infrastructure.