The FBI considers the energy sector to be at risk for attacks. If a cyber-attack occurs at a utility, the incident is likely not an isolated event. When companies communicate these episodes to the FBI, trained agents can see patterns, predict reoccurrences, and back track the offenders.

In this, the third in a series of columns on cyber security, FBI Supervisory Special Agent (SSA) Bruce Barron, an expert on this matter at FBI headquarters, spoke with me about cyber security in the utility industry. SSA Barron began working cyber investigations in 1998 as an investigator before joining the ranks of management in 2008 as a Cyber SSA, serving in the role of Unit Chief. In 2016, SSA Barron transferred to a specialized outreach unit for energy private sector engagement.

FBI organization

The FBI is a field-based organization; cases are handled in the field with headquarters providing coordination. Field offices seek good working relationships with utilities to engage with all aspects of the energy sector, from pipelines to generation to transmission. Headquarters assigns specialized cyber security offices to make regular outreach to the targeted community, with an emphasis on pre-incident contact. Several different FBI subgroups work with the utility, and other industries, to investigate and prevent cyber-attacks.

“Reach out if you are unsure if a report is warrented. Talk to us and let us decide.”

– Bruce Barron, FBI
Supervisory Special Agent

Before an Attack

In advance of an attack, utilities should reach out through their local field office and establish a relationship. When developing response plans, focus on recovering from the attack but include when to reach out to law enforcement and the preestablished agency names and contact information.

Cyber-security agents want relationships with the energy sector. If a utility doesn’t know how to initiate contact, they can reach out to the cyber division watch center (cwatch@fbi.gov). This group will do the initial information intake, send the data to the proper local unit, and make sure that a connection happens.

Field officers will regularly conduct outreach directly to utilities using FLASH (FBI liaison alert system) notifications and PINs (Private Industry Notification). Some of these alerts are sent out to only select companies depending on the nature of the information.

During an Attack

According to SSA Barron, if a utility sees a cyber-attack occurring, they should do what is needed to protect their network and get services back up. As soon as practical, the utility should reach out to the FBI if the event was significant. For example, a few phishing emails might not warrant reporting; however, a loss of data, an attack that reaches the operating network, touches an industrial control system, or anything that impacts service should be reported. Keep system and security logs so that the intruders’ actions can be identified. The FBI’s goal is to investigate while minimizing any disruptions to the victim networks. Recovery comes first.

After an Attack

After an attack, the FBI has the legal and technology tools to find and dismantle the threat and collect intelligence, while minimizing the impact in of the investigation on the utility. Threat response includes investigating to find out the perpetrators use of tactics, techniques, and procedures (TTPs) which are sent to the specialized cyber-security offices. The Department of Homeland Security also provides specialized services for asset recovery and works with utilities on mitigation of the attacks effects.

I asked SSA Barron what he wants utilities to know. “Reach out if you are unsure if a report is warranted. Talk to us and let us decide. For example, a single but sophisticated phish sent to a system administrator or executive can be a significant threat. We’ll look for commonalities such as failure of network segmentation, stolen passwords, or unpatched software with known vulnerabilities.”

What can Average Joe (someone not a Chief Information Officer) do? SSA Barron says that everyone is part of awareness. Look for anomalies and loss of control. Participate in FBI grid exercises, practice incident response, and know how to reach out to FBI. “Most importantly, figure out who in the company can give consent to allow the FBI to collect digital evidence from the victim networks. Cyber investigations depend on electronic evidence that can quickly be lost if not collected soon after an incident.”

The FBI can only do their job if they can look at the evidence.

Renewable energy continues to represent a growing source of power generation in the U.S. economy, and is supported by a strong lending environment. In 2017 alone, renewable energy provided a remarkable 18 percent of total U.S. power generation — doubling renewable power contributions in just 10 years.

This amazing growth was driven by many factors, most critically the production tax credits subsidies and the robust finance market. However, there are several financial challenges facing the renewable energy market, notably the Renewable Electricity Production Tax Credit (PTC) phase-down, Tax Cuts and Jobs Act (TCJA) and Section 201 Solar Tariffs, all of which are going to have an impact on the renewables industry.

One of the biggest financial challenges for renewable energy is the PTC and ITC extension with phase-down. The PTC and ITC have been the key financial drivers for wind and solar power project development and help sustain the supply, construction, management and operation of renewable power generation assets. The tax credits were extended through 2019, with a phasing down by 20 percent each year beginning in 2017.

To survive and thrive during this phase-out of tax credits, the renewable power industry needs to continue to compete with natural gas and fossil fuel energy resources specific to each regional market. Lower capital cost of wind turbines and solar PV panels, higher efficiencies in equipment name plate capacity, and optimizing operations are all helping renewable power stay competitive in the market. To compete with natural gas, developers of renewable projects may consider secure financing supported by Utility PPAs, Commercial & Industrial (C&I) PPAs, Energy Hedges and Proxy Revenue Swaps. Utility PPAs are rather scarce in certain markets and C&I PPAs, while increasingly prevalent, can take significant time to close. Depending on the power market, and taking into consideration the specific market risks, Energy Hedges and Proxy Revenue Swaps may make a project financeable. “We’ve selectively identified other contract alternatives to traditional utility PPAs and have found that sophisticated banks are able to finance against such alternative contracts”, said Steve Ryder, CFO for Invenergy LLC. Despite challenges with offtake agreements, coal plants continue to be retired, and renewables are in high gear to replace some of this capacity as the PTCs are phased out.

Another financial challenge for renewables is the uncertainty around the impact of the Tax Cuts and Jobs Act (TCJA). There is concern around the supply and cost of tax equity, though to-date the industry has not seen any material changes on this front. However, questions remain as the tax credit drops down and it is uncertain if stakeholders will lose their appetite for renewable projects. According to Saad Qais, CFO for Goldwind North America based in Chicago, “A few tax equity players are assessing the impact of BEAT (Base Erosion Anti-abuse Tax) on their tax capacity. It’s largely expected to be minimal; however, general liquidity in the tax equity market remains limited.” We just do not know the full impact yet, and we will need to watch the project deal flow.

The most recent financial challenge to the renewable industry is the U.S. Federal Government Section 201 Solar Tariffs, which took effect on Feb. 7, 2018. These tariffs impose a tariff level at 30 percent, with a five percent declining rate per year over the four-year term on Solar PV Cells. As this drives up the cost for U.S. solar projects, it will be interesting to see if the renewables industry is able to ensure the existing market continues to thrive while developing new technologies and enabling free markets. Adapting new technologies, such as new battery storage equipment and software application, will keep renewables competitively priced in this market.

The advocacy work with the International Trade Commission on Tariffs and lobbying efforts to defend federal and state tax incentives may continue with trade associations such as Solar Energy Industries Association, American Wind Energy Association and many others. Stakeholders in the renewable energy industry may consider pursuing public policies and private industry partnerships to keep existing, robust markets open, while opening new ones for continued growth. For example, a known industry priority is reforming electricity markets to enable renewables resource use at the highest values. Public and private industry is adding value by adopting innovative new technologies that help to improve, modernize and increase efficiency of the US energy grid, such as battery storage, smart grids, fuel cells, distributed generation and other innovations.

The renewable energy market continues to be a growing and successful industry, but is not without its share of financial challenges. According to the U.S. Department of Energy, total installed U.S. solar power capacity is expected to reach nearly 100 GW by the end of 2020 and total installed U.S. wind power capacity is projected to reach 113.43 GW by 2020. By any measure, renewables have seen great financial success. The financial challenges facing the renewables industry will be measured by how effectively the industry adapts and competes in the market without subsidies when compared to natural gas and fossil fuels.

In 2009, I had the privilege of visiting the V.C. Summer Units 2/3 nuclear construction site while it was mostly dirt being moved around. My tour guide — a senior manager from the new plant development team — took me to where one of the containment buildings would stand, unrolled a site map on the hood of his pickup truck, and pointed out where the various main structures would sit when completed. It was a heady moment, and it was impossible to miss the pride in his voice.

I shared his excitement, and enjoyed tracking progress at Summer over the next few years. To myself and other engineers in the power industry, time-lapse videos showing the placement of concrete and the installation of large plant modules were technological eye candy.

The demise of the Summer project, therefore, has been particularly painful to watch. Beyond the loss of thousands of jobs, a large tax base, and a reliable generating asset, there is a psychological impact that will shape perceptions and decisions on nuclear for years to come.

Sadly, tracking progress at Summer has shifted from eye candy to estate sale. Will Dominion’s offer to purchase SCANA ultimately go through? Will Santee Cooper survive as a public utility in South Carolina or will it be sold, dissolved, disaggregated by the state? Will any of the equipment or components at the Summer site be salvaged for use elsewhere? Will Summer’s sister plant under construction in Georgia, Vogtle 3/4, be able to avoid Summer’s fate?

The blame game is already in process, and the legal cases will likely circle through the courts for years. For a failed $10+ billion project, there is obviously a lot of fault that needs to find a resting spot.

I claim no inside knowledge, but it occurred to me that some of the bedrock operating principles associated with the nuclear power industry appear to have been absent, or at least under-emphasized, in the Summer project.

In 2012, the Institute of Nuclear Power Operations (INPO) published Traits of a Healthy Nuclear Safety Culture (INPO 12-012) to reinforce the industry’s commitment to safety as the overriding priority. The traits defined in this document reflect the “core values and behaviors resulting from a collective commitment by leaders and individuals to emphasize safety over competing goals to ensure protection of people and the environment.”

INPO 12-012 lists 10 traits and their associated attributes. Some, such as Effective Safety Communication and Leadership Safety Values and Actions, are clearly specific to safety. Most of the rest, though, are applicable to new plant development, at least in my humble opinion. I’ll touch on a few.

Questioning Attitude: “Individuals avoid complacency and continuously challenge existing conditions and activities in order to identify discrepancies that might result in error or inappropriate action.” Regardless of who you prefer to assign blame to — the owners, the vendors, the contractors — there were undoubtedly discrepancies between expectations and reality. These discrepancies led to “inappropriate actions,” or at least a lack of appropriate actions, and created a culture where complacency set in.

“For a failed $10+ billion project, there is obviously a lot of fault that needs to find a resting spot.”

Problem Identification and Resolution: “Issues potentially impacting safety are promptly identified, fully evaluated, and promptly addressed and corrected commensurate with their significance.” Replace “safety” in that sentence with “schedule,” “budget,” or “project completion” and it is equally applicable to new plant development. I am not saying that issues were never identified along the way at Summer. For example, the difficulties associated with implementing a new modular construction approach within the tight quality standards of the nuclear power industry were recognized relatively early on. However, the combined effects of multiple problems were neither sufficiently recognized not sufficiently addressed.

Environment for Raising Concerns: “A safety-conscious work environment is maintained where personnel feel free to raise safety concerns without fear of retaliation, intimidation, harassment, or discrimination.” Remove the references to safety and you have a desirable principle for effective project management. I’m not claiming there was any sort of explicit or implied pressure applied to those who worked on the Summer project to keep quiet about issues. I do wonder, however, whether a more open environment may have led to an earlier assessment of rising project risks.

During the early days of the Vogtle and Summer projects, I heard multiple people say that the industry had to bring them online both on schedule and on budget to demonstrate that the cost overruns of the construction projects in the 1980s and 1990s were behind us. Well, let’s face it. We definitely failed on that front.

Vogtle still has a chance to save the industry some face. Adopting a few healthy traits may be part of the equation.

Among the “…vastly different circumstances” that Russell Ray mentions in his opinion piece in the January 2018 edition of Power Engineering are dozens of existing qualifying facilities (QFs) that have not been advantaged by state renewable energy policies and continue to rely on PURPA to provide access to markets, and fair and sustainable rates that are competitive with utility generation costs.

The constant drone that QF energy and capacity rates are “above market” may be true for some, but not all, especially in the context of existing QFs and regulated states like Michigan. For the past 30-plus years Michigan’s avoided costs have been based on actual utility generation costs. Therefore, if existing QF costs are “above market” as some claim, then so is utility generation. Market rates are irrelevant in Michigan because utilities do not recover their generation costs at market rates, especially those in MISO, as that is a short-term balancing market and not reflective of true generation cost. Existing, longterm QF generation is not equivalent to purchasing short-term market power because utilities rely on their own long-term generation to serve their load, and recover their actual costs, not markets rates.

The “modern realities” of PURPA, as Mr. Ray states, are that existing QFs are being overlooked and the long-term benefits they bring are left out of the debate. The “old reality” is that Michigan remains a regulated state under law passed in 1939. Therefore, the realities that PURPA was meant to address in 1978, and as revised in 2005, are still applicable today.

Changing PURPA in ways that allow utilities to game the processes for setting avoided costs so that existing QFs are forced out of business is not good energy policy and is not in the best interest of a diverse and robust energy supply. Yes, the world is changing, Mr. Ray, and good energy policy ensures everyone gets to come along for the ride. Modernizing PURPA for the 21st Century cannot happen while ignoring the fate of existing QFs, or else we risk throwing the proverbial baby out with the bathwater. Changes to long-standing law must be made with all affected parties being considered or they will simply create bad public policy and do nothing to advance the industry or benefit ratepayers.

Gary Melow, Director of Michigan Biomass

Editor’s Note: The following article is based on a technical paper recently presented at POWER-GEN International 2017 in Orlando, Florida.

A microgrid can be defined as a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that act as a single controllable entity with respect to the grid and that automatically connects and disconnects from the grid to enable it to operate in both grid connected or “islanded” mode.

Power electronics for each micro-source can provide the control and flexibility for the microgrid to meet its power demands. The Microgrid controls need to ensure that:

• New micro-sources (Solar PV, Fuel Cells, Micro-turbines etc.) can be added to the system without modification of existing equipment.
• The Microgrid can connect to or isolate itself from the grid in a rapid seamless fashion
• Active and Reactive power can be independently controlled
• Voltage sag and system imbalances can be corrected
• Satisfy the Microgrid load dynamics

Each Micro-source has its own controller that interfaces to the micro-source power electronics. Even though the micro-source controllers are designed so communication to each other device is not required having a Distributed Control System (DCS) that monitors all the micro-source controllers and the loads of the entire Microgrid aids operations and provides more robust control. A DCS provides operations with the ability to view the status of the entire Microgrid in a common location. In addition, central logic can quickly detect separation of main distribution grid to switch modes of devices to help ensure frequency is maintained. It can also be a platform for intelligent load shedding to replace standard under-frequency load shed systems and can provide a common interface to an Energy Management System.

“The growth of renewable energy resource installations, emerging utility scale energy storage and demand response is bringing unprecedented opportunities and challenges to the electric distribution system.” [1] Utility systems are now facing a systems-integration challenge with complex coordination and integration necessary for these distributed resources.

“When distributed energy is integrated into distribution networks at customer sites, issues arise with respect to reverse power flows — from customer (load) to grid. The traditional system is designed for power flow from grid to customer, not the two-way flow of power. Since reverse power flow is not controlled by the distribution utility (let alone the transmission operator), at high penetration levels of Distributed Energy Resources (DER) this becomes a major problem which is further compounded by the intermittency of renewable energy sources due to weather variability, e.g. wind not blowing; sun not shining; clouds.” [2]

Microgrids offer a solution for utilities and customers to cope with these issues. They control generation and loads at the local level and can disconnect or island from the grid in times of disruption, either from inadequate supply during normal times or outages because of natural disasters. During normal operations, e.g. no shortages of generation due to outages, microgrids offer the additional benefit of optimizing supply and demand via comparative pricing vs the distribution utility, e.g. buying from the utility when market prices are lower than microgrid costs and selling to the market when costs in the microgrid are lower than market prices.

Microgrids provide a solution to customers who experience problems with reliability and outages. They become standby option to maintain power in emergencies. It is also the reason that back-up generation, mostly diesel generators at locations to serve critical load, are now being called “Microgrids”.

In summary, a microgrid can be defined as a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that act as a single controllable entity with respect to the grid and that automatically connects and disconnects from the grid to enable it to operate in both grid connected or “islanded” mode. A microgrid is capable of operating autonomously from the electrical grid by supplying all its generation.

Microgrid Configuration

The microgrid is a grouping of distributed energy resources and interconnected loads. Figure 1 below shows a generic configuration and principal components that most advanced microgrids would typically incorporate.

There is generation that can be dispatched such as diesel generators or microturbines and there is intermittent generation that cannot be controlled such as wind and solar. The microgrid also contains energy storage. This can be batteries or flywheels. It can also be in the form of Hydrogen gas. Often excess solar or wind power can be used to make Hydrogen that can be burnt later in a microturbine or used in automobiles. A microgrid can have critical loads that should always have power such as life support facilities or data centers. There are normally noncritical loads such as heating, air conditioning and lighting.

Normally there is a Point of Common Coupling (PCC) to the main distribution grid unless the microgrid is an island where there is no connection to the main distribution grid.

Key issues that are part of the microgrid structure include the interface, control and protection requirements for each micro-source as well as microgrid frequency control, voltage control, load shedding during islanding, protection, stability and overall operation. The ability of the microgrid to operate connected to the grid as well as smooth transition to and from the island mode is another important function.

Micro-source Controller

The basic operation of most microgrid’s today depend on each micro-source controller to:

• Regulate power flow on a feeder as loads on that feeder change their operating points
• Regulate the voltage at the interface of each micro-source as loads on the system change
• Insure that each micro-source rapidly picks up its share of the load when the system islands

Another important feature of each micro-source controller is that it responds in milliseconds and uses locally measured voltages and currents to control the micro-source during all system or grid events. The systems are designed so that communication among micro-sources is not necessary. This arrangement enables micro-sources to “plug and play”. Micro-sources can be added to the microgrid without changes to the control and protection of units that are already part of the system. The basic inputs to the micro-source controller are steady-state set points for power, P, and local bus voltage, V.

Energy Manager

The microgrid may contain an Energy Manager that enhances system operation of the microgrid through dispatch of power and voltage set points to each micro-source controller. This function could be as simple as having a technician enter these set points by hand at each controller or to a state-of-the-art communication system with artificial intelligence. The actual values of dispatch of P and V depends on the operational needs of the microgrid. Some possible criteria are:

• Insure that the necessary heat and electrical loads are met by the micro-sources.
• Insure that the microgrid satisfies operational contracts with the bulk power provider.
• Minimize emissions and/or system losses.
• Maximize the operational efficiency of the micro-sources.

Protection

The protection coordinator must respond to both system and microgrid faults. For a fault on the grid, the desired response may be to isolate the critical load portion of the microgrid from the grid as rapidly as is necessary to protect these loads. This provides the same function as an uninterruptible power supply at a potentially lower incremental cost. The speed at which the microgrid isolates from the grid will depend on the specific customer loads on the microgrid. In some cases, sag compensation can be used to protect critical loads without separation from the distribution system. If a fault occurs within the island portion of the microgrid, the desired protection is to isolate the smallest possible section of the radial feeder to eliminate the fault.

DCS Enhances Microgrid Control

Even though the micro-source controllers are designed so communication to each other device is not required having a DCS that monitors all the micro-source controllers and the loads of the entire microgrid aids operations and provides more robust control. A DCS provides operations with the ability to view the status of the entire microgrid in a common location. In addition, central logic can quickly detect separation of main distribution grid to switch modes of devices to help ensure frequency is maintained. It can also be a platform for intelligent load shedding to replace standard under-frequency load shed systems and can provide a common interface to an Energy Management System. Figure 2 is an overview of the microgrid at Stone Edge Farms.

The Hydrogen Electrolyzer uses excess solar power to make hydrogen for use in fuel cell and Toyota Mirai. The hydrogen is a form of energy storage. Each of the nodes has its own microsource controller and work independently. The farm has a connection to the main distribution grid but if it were to become an island each micro-source controller would respond to help maintain frequency. In this situation one of the battery inverters is put in master mode. In this mode, the battery inverter is given a frequency setpoint and will automatically charge/discharge the battery in response to changes in frequency. The other battery inverters remain in P,Q mode. This is very similar to placing a generator in Isochronous mode and leaving the remaining generators in droop mode. The DCS is currently being used to provide remote monitoring and supervisory control. It sends setpoints to the micro-source controllers. The DCS will also be used to check for disturbances such as loss of the master battery inverter and automatically send a command to another micro-source controller to switch the inverter from P,Q to Master mode. This may also have to be done if the charge remaining on the battery becomes low. The DCS also helps in re-connecting to the main distribution grid. Currently the grid breaker is manually closed when the synch-check indication shows the microgrid in phase with main grid. This condition often is only true for very short time making it difficult to manually close the breaker. However, this procedure can be automated in a high speed (50msec) control task of the DCS eliminating this timing problem.

Figure 3 shows an overview of the communication network for a DCS when used in an off-grid microgrid such as an island community. The electrical demand of the island must be satisfied from a variety of power producers. This microgrid contains energy manager software that resides in a separate server that receives all required data from the DCS and writes all its calculation results back to the DCS. The DCS is responsible for interfacing to all the actual power producers. The DCS also provides central monitoring and control. It should be noted that the energy manager could be part of the DCS instead of a separate machine as shown.

Energy Manager Functions

The primary Energy Manager functions are described here.

Load Forecasting — This function provides the capabilities to forecast system load, as well as generation from solar assets. To forecast system load, this function utilizes historical load and weather data and will provide profiles for similar day types. Profiles are maintained for various day-of-week types, seasons, and weather variables. To forecast system load based on forecasted weather, appropriate profiles are selected and adjusted to fit the current system load and weather condition. To forecast solar generation, forecasted solar irradiance and temperature are retrieved from on-line weather services. This, coupled with the physical characteristics of the solar plants such as inclination angles, capability limits, efficiencies, as well as telemetered local conditions are used to generate the solar generation forecast.

Scheduling and Dispatching — This module determines the optimum commitment schedules and Economic Dispatch schedules for the conventional generation facilities, as well as for the battery storage facilities. The primary input to the optimization process is the net load forecast, defined as the difference between the system load forecast and solar generation forecast. This function takes the capabilities of generation units such as maximum and minimum capacities, incremental cost of generation, ramping capabilities, etc., into consideration. It also takes constraints, such as minimum up/down times, outage schedules and other pertinent parameters into consideration.

DCS Data Acquisition Functions

As shown in Figure 3, the DCS is responsible for interfacing directly to all the energy producers. It provides all the required data acquisition functionality. It gathers all the power being consumed in the electrical substations and the power being produced. It also can read the weather and solar irradiance forecasts from a website. This data is then sent to the energy manager over a secure communication link and the results from the energy manager are received over the same link. All the information is made available to operations in a central location on graphic displays. The data acquisition system will automatically gather the status and values from the feeders, and collect them at one central location. This data can be displayed on a monitor (the HMI or human-machine interface).

The DCS contains project-specific graphics like single-line diagrams (SLDs) on which live status of the breakers can be displayed. The operator continuously sees the live status indicating if a breaker is open, closed, bad, tripped, etc. Critical analog values like bus voltages, frequency, power, etc are also displayed. From these DCS graphics the operator can remotely operate breakers and perform tagout operations.

Since data is being continuously acquired by the DCS, it can be stored for later retrieval (the historian) for future analysis. The historian is limited only by its disk space as to how long it can retain data. Disk space may also be augmented by tape drives or DVD writers.

By checking the data, alarms can be reported on the operator workstations or printed out. Alarms may be generated if an analog value goes above or below some limits, e.g. if the bus voltage or frequency falls below an acceptable limit. Alarms may be generated on a change of state of a digital value, e.g., if the grid or generator breaker opens.

With the data, available, the software can automatically generate reports on an hourly, shift, daily, monthly or yearly basis.

Basic DCS Control Functions

Listed below are other control functions that can be implemented in the DCS to enhance the microgrid controls.

Point of Common Coupling Control

A microgrid may have a Point of Common Coupling connection to the distribution utility (the macro-grid) and a rate structure/contract that stipulates the maximum quantity of energy (MWh) that can be consumed in a demand period. If this limit is exceeded, the microgrid manager must pay a penalty or demand charge, and often this ratchets the demand charge up permanently.

Because this consumption demand is measured in energy (MWh) and not power (MW), the control logic can be used to predict the energy consumption at the end of the time. An anticipated error can be estimated by measuring the present rate of power consumption and extrapolating to the end of the demand period. If this predicted value exceeds the maximum demand limit, the control logic can automatically trim load or increase generation from energy storage to limit the energy consumed from the macro-grid, or, an alarm can be generated for the operator to take corrective action.

Frequency Control

The way frequency is controlled depends on the types of power producers the microgrid contains. When the microgrid is connected to the main distribution grid the frequency is maintained by the grid. The problems occur when the microgrid is disconnected from the grid.

If the microgrid contains gas and steam turbines the simplest way to maintain frequency is to place the largest gas turbine into isochronous mode and keep the remaining generators in droop. Whenever there is a load change the isochronous machine will move very quickly to keep its speed at 3600 rpm for a 60Hz system. The loads on the machines in droop can be adjusted by centralized logic in the DCS to ensure the isochronous machine always has spare capacity to respond to a load change.

According to [3] there are two ways of performing frequency control of the microgrid. It can be done locally using a PI controller at each micro-source controller or in a centralized way. Per [48] inverters are typically controlled to emulate the droop characteristics of synchronous generators. The two primary objectives of this control are to hold the frequency at the desired value when running as an island and to load the power producers in the most economical manner.

In the case of the microgrid at Stone Edge Farms where there are no generators one of the battery inverters is put into master mode and the others remain in P,Q mode. In this master/slave configuration the master inverter is given a frequency set point and it automatically adjusts the charging and discharging of the battery to maintain the desired frequency. The other battery inverters in P,Q mode match the frequency of the master. However, the P,Q inverters can be adjusted by centralized logic in the DCS to make sure the master has spare capacity. This frequency control configuration is analogous to having one generator in isochronous mode and the remaining ones in droop.

Figure 4 shows a high-level overview of frequency logic that could be applied to the microgrid shown in Figure 3 above where all generators are in droop and inverters are in P,Q mode. The amount of power that must be produced is the current generation plus any correction due to frequency deviation from the set point value of 60Hz. This total required MW amount is then distributed to the power producers. The way the power is distributed is determined from the economic dispatch function from the energy manager. The energy manager software is running say once per minute while the logic in the DCS is running every one second or faster. The advantage of having this base frequency control in the DCS is that while the energy manager is not running the DCS is constantly ensuring the frequency is maintained. The logic in the DCS can automatically detect if a power producer tripped and automatically re-allocate its power to the remaining power producers. Similarly, it instantly detects if an operator has placed a device in manual mode and constrains the power that device is making and re-distributes the remaining load. The same holds true if a power producer reaches a high or low limit. In between runs of the energy manager software the frequency control in the DCS loads the available power producers based on the desired values from the last run of the energy manager to ensure the power is being produced in the most economical way.

Breaker Control and Interfacing to IEDs

Remote breaker control logic allows an operator to issue OPEN and CLOSE commands from the single line diagram graphics displayed on an operator workstation. Before a command is executed, the control logic checks to ensure that the breaker is in the proper state for the operation. This means to check for proper status (e.g. breaker open), open faceplate, activate faceplate, arm, and allow only the corresponding command (breaker close command). If a command is issued and the status indicator does not reflect the new state (the breaker does not indicate that the operation was successful) within a certain amount of time, an alarm is generated.

The DCS can typically communicate with intelligent electronic devices (IEDs) using various protocols such as:

• Modbus over RS485 serial link
• Modbus over TCP/IP
• DNP
• Profibus
• IEC 61850
• IEC 60870-5-104

Load Shedding

Load shedding is critical in controlling a microgrid. Contingency analysis and load shedding software automatically responds to electrical disturbances such as loss of grid or loss of power producer so that stable conditions can be restored.

If a power source (grid, generator, or an inter-connect breaker on a generation bus) is lost, then the power that was originally available from that power source must be shed in a fraction of a second so that the remaining power producers are not over-loaded, and so that the disturbance to the process is minimized. A large chunk of downstream feeders may have to be shed immediately to prevent a blackout.

Often there is only an under-frequency relay system. This is the simplest method of carrying out load shedding. For this scheme, the circuit breaker interdependencies are arranged to operate based on hardwired trip signals from an intertie circuit breaker or a generator trip. Even though, the execution of this scheme is fast, breaker interlock load shedding possesses several inherent drawbacks:

• Load shedding based on worst-case scenario
• Only one stage of load shedding
• Almost always, more load is shed than required
• Modifications to the system are costly

A priority based load shed system can be implemented in the DCS that only sheds the amount of load required. The load shed logic selects the feeders to be shed from a list of available feeders, and selects the feeders in order from the least important feeder to the more important ones. The logic also checks that the load-shed breaker is available for automatic tripping (e.g. closed and has a MW flow) and desirable (i.e. connected to the importing bus and not to the exporting bus). This list of breakers for each possible load-shed case is continuously updated and made available at the controllers.

The moment a power source is lost, the selected breakers are shed automatically by the system. Graphic displays are provided to the operator so he can see which loads will shed if a contingency were to occur so he can prevent a critical load to plant operation from tripping. At any time, he can adjust the priority or temporarily remove it from the load shed system and then restore it later. The columns of the matrix are the contingency cases and the rows are the breakers. If a cell is highlighted with a MW amount for the breaker this indicates that load will shed if the contingency should occur.

Loads are shed on detecting opening of a power-source breaker.

When the microgrid is disconnected from the grid it is then its own electrical island. The frequency of the island must be maintained from its own power producers. If the microgrid load exceeds its generation, then the frequency of the island will fall below the nominal value of 50 Hz (60 Hz in the USA). If the frequency goes below a minimum threshold value, the system will shed enough low-priority loads to bring the frequency back to the nominal value.

At any time, operations, can change the load shed priority scheme. There may be times when a load is critical and should not be shed and at other times it can be. A graphic display provides the user with the ability to change a breaker priority or to temporarily remove it from the load shed system and restore it later.

Voltage Control

When microgrid loads are turned on and off there is a varying active (MW) power demand. If some of the loads are large inductive loads (i.e. motors) this will also cause a varying reactive (MVAr) power demand that can cause fluctuations in bus voltages. Each micro-source controller can respond to changes in voltage but centralized voltage control in the DCS can enhance this control by satisfying the reactive demand within the constraints of:

• Keeping the power factor of tie-line power close to unity or at the operator-entered power-factor set-point. This eliminates power-factor penalties. If the microgrid is running as an island, then all the reactive power must be generated internally.
• Ensuring that generators always run within their reactive capability.
• Keeping bus voltages within allowable limits.
• Keep all generators and inverters on same bus with equal power factors

Reactive power can be controlled by:

• Turning capacitor banks on and off.
• Adjusting the excitation on generators and synchronous motors.
• Adjusting tap positions on transformers.
• Adjusting the VAR’s on inverters that may be for solar, wind or batteries

Capacitor Bank Control

Switching capacitor banks ON when reactive power demand is high helps satisfy the reactive demand and gives more MW capacity to the generators. This can lead to a monetary savings. When it is cheaper to generate power rather than buy power, it is desirable to have more in-plant generation capacity. If the generator can run at a higher power factor it can make more MW for the same amount of fuel and reduce the amount of purchased power.

Thus, switching on a capacitor bank reduces the MVAr load demand on that bus, and therefore reduces the MVAr imported from the grid which in turn may reduce the MVAr from the generators.

Capacitor banks help reduce losses in the electrical network by satisfying the reactive demand locally.

Generator MVAr Control

If the microgrid contains generators the amount of reactive power produced by a generator can be controlled by adjusting the Automatic Voltage Regulator (AVR) set-point on the machine. The generators AVR are programmed with a voltage setpoint equal to the nominal voltage of the bus that they are connected. When there is a change in reactive demand the AVR will automatically respond with enough reactive power to maintain the bus voltage. When this occurs often time’s one generator will end up with a low power factor and others with a very high-power factor. The centralized voltage control logic will redistribute the VAr’s so all machines have equal power factors.

This logic also ensures that each generator stay within its reactive capability.

Since changing generator MVAr will automatically change the voltage of the bus downstream of the generator, control logic will also ensure that the operator cannot move the bus voltage outside its allowable operating range. If the bus voltage goes outside this range while in MVAr Auto mode, the control logic will automatically adjust the generator’s MVAr to bring the bus voltage within limits.

Inverter Control

If the microgrid does not contain generators the Var’s on the inverter can be adjusted to hold voltage. If the microgrid is running as an island the master inverter is given a voltage setpoint. The DCS can send Var setpoints to the slave inverters in P,Q mode to redistribute the VArs in such a way so that all inverters have the same power factor.

Transformer OLTC control

If the microgrid transformers have on-load tap-changing (OLTC) control, then the DCS control logic can calculate the desired tap position of the transformer so that the voltage of the bus immediately downstream of the transformer is kept within limits, normally within ±5% of the nominal value.

The OLTC control logic can be placed in OLTC Auto or Manual mode from the operator workstations. When in OLTC Auto mode, the optimum tap positions calculated by the control logic are used so that the transformers’ downstream buses are within their voltage limits. When in Manual mode, operator-entered tap positions are used. The operator may also manually raise or lower the taps by clicking on buttons.

OLTC control may be implemented as an Auto-mode control (recommended tap position is calculated automatically), or as Manual-mode raise/lower control, or simply as a tap-position advice to the operator (no automatic control) as desired by the customer.

Conclusion

A DCS is well suited to be a microgrid central controller. It can monitor all the micro-source controllers and the loads of the entire microgrid that allows operations to view the entire microgrid from a common location.

In addition, central logic can quickly detect separation of main distribution grid to switch modes of devices to help ensure frequency is maintained. It can also be a platform for intelligent load shedding to replace standard under-frequency load shed systems and can provide a common interface to an Energy Management System. It can also be used to provide secondary load frequency and voltage control.

References

1. Microgrids: A primer, EPRI report, September 2013

2. Robert Lasseter, Abbas Akhil, Chris Marnay, John Stephens, Jeff Dagle,Ross Guttromson, A. Sakis Meliopoulous, Robert Yinger, and Joe Eto, ”The CETS Microgrid Concept”, 2002

3. A.Madureira, C. Moreira, and J. Pecas Lopes, “Secondary Load-Frequency Control for Microgrids in Islanded Operation”,

4. M.C. Chandorkar, D. M. Divan and R. Adapa, “Control of Parallel Connected Inverters in Standalone AC Supply Systems”, IEEE Transactions on Industry Applications, vol. 29, no 1, pp136-143, 1993.

5. Q.C. Zhong and T. Hornik, “Control of Power Inverters in Renewable Energy and Smart Grid Integration”, Wiley-IEEE Press, 2013

6. J.M. Guerrero, J.C. Vasquez, J. Matas, L.G. de Vicuna, and M. Castilla, “Hierarchical Control of Droop-Controlled AC and DC Microgrids-A General Approach Toward Standardization”, IEEE Transactions on Industrial Electronics, vol. 58, no. 1, pp. 158172, 2011

7. J.M. Guerrero, M.C. Chandorkar, T.L. Lee and P. Chiang Loh,” Advanced Control Architectures for Intelligent Microgrids — Part I: Decentralized and Hierarchical Control”, IEEE Transactions on Industrial Electronics, vol. 60, no. 4, pp. 1254-1262, 2013

8. J.A.P.Lopes, C.L. Moreira and A.G.Madureira,”Defining Control Strategies for Microgrids Island Operation”, IEEE Transactions on Power Systems, vol. 21, no. 2, pp. 916-924, 2006

9. Owens, Brandon, “The Rise of Distributed Power”, General Electric Report, 2014

10. Huff, Frederick C., Del Real, Roberto, Payne, Steve, “The Electrical Control and Energy Management System of a University: University of Texas a Case Study”, IDEA Campus Conference, 2009

By Tom McDonnell and Lee Ward

Many hydroelectric plants today use outdated control and electrical systems. As a result, these plants experience a greater risk of operational stoppages and downtime. A modern DCS system can mitigate these risks. Photo courtesy: Rockwell Automation

The average U.S. hydroelectric plant has been operating for 64 years. Such a lengthy service record shows the plants have staying power. But it also invites questions about aging hydro control systems.

The need for station and unit control reliability is critical in these decades-old plants, especially as power producers seek to maintain competitive and profitable plant operations amid declining peak generation prices. But their aging or obsolete systems, combined with the lack of operational and diagnostic information available in those legacy systems, can make excellent reliability control elusive. Many hydroelectric plants today use outdated control and electrical systems.

As a result, these plants experience a greater risk of operational stoppages and downtime. Operators are more likely to face support challenges and difficulty with maintaining regulatory compliance, in addition to spending time and resources performing manual data collection and reporting. And as these systems reach the end of their useful life, they must be replaced.

Modernizing to a contemporary, whole-station, unified control system can alleviate these challenges and facilitate tighter integration between unit control and associated subsystems.

If your hydro control systems are due for replacement, consider upgrading them to a modern distributed control system (DCS). A modern DCS system offers more than centralized plant control, monitoring and reporting. It can also tap into industrial Internet of Things (IIoT) data derived from your equipment to give operators a deep understanding of real-time events. This can help them make informed decisions, on-site or remotely, and optimize your station’s performance.

Rethinking Modernization

Modernization is an effort that involves more than migrating from an old legacy system to its modern equivalent. It often requires rethinking applications and upgrading multiple technologies within a plant. In the end, however, it can transform a hydroelectric plant’s processes and help reposition its operations for the next 20 to 30 years.

In fact, power producers can more efficiently manage their assets to help improve their bottom line by modernizing old or obsolete automation systems that make up only a fraction of their bottom line. Modernization can also help producers leverage advanced analytics to monitor and optimize multiple plants across their fleet.

The power generation industry has long been a leader in data collection and analytics, as well as regulatory compliance. Modernization continues that reputation by leveraging the power of the IoT. For instance, by linking power production and equipment performance data to information systems, power producers can gain access to real-time metrics and predictive insights into virtually every aspect of a station’s operation. This improved visibility can help producers increase reliability, reduce maintenance, achieve more precise control, and improve diagnostic capabilities.

For plants undergoing modernization, the key is to understand not only what new technologies they should leverage, but also what business improvements they can deliver. This is especially important in today’s competitive world of generation, where justifying capital spending on automation is becoming more challenging and requires a solid business case.

Digitally Transform Your Plant

Bulk-electric-system plants lag other industries when it comes to connecting and digitizing operations. But plants that have begun the journey are proving it’s better late than never.

Just look at the case of one generation plant. It was hobbled by spurious trips that impacted generation and manual reports that took hours to produce every day. The station transitioned to a scalable, information-enabled DCS. And it replaced its proprietary network with an open EtherNet/IPâ„¢ network. After making these changes, the station saw nuisance fail-safes drop by nearly 90 percent and restart times improve by 25 percent.

In hydroelectric unit operations, the ability to access, analyze and act on data can create a richer operating environment at all levels of the station. Operators can make real-time comparisons of turbine performance and drop reaction time for dispatching. With broad-based deployment of integrated intelligent condition monitoring technologies, technicians can drill down into unit equipment health to monitor and diagnose assets. Furthermore, executives can connect global fleets of hydro, fossil and other assets to track and compare their performance over time.

A modern DCS system helps makes this all possible.

Define Your Strategy

Some strategic decisions must be made before you can upgrade your hydro control system. Key questions to answer include:

What is the short-term, mid-term and long-term vision for the facility?

Each journey to a connected operation is unique for every facility. For instance, a short-term objective for some power producers may be to upgrade the unit controls with their plant. The long-term vision object, however, may be to create a tightly integrated plant control system that incorporates the excitation system, governors, turbines, control system, vibration monitoring, and power distribution and protection equipment.

Will you replicate or improve on your current DCS?

Replication means replacing automation hardware with new components, but keeping all functionality unchanged. This approach may be less expensive upfront, but it can have a higher lifecycle cost because it delivers minimal operational improvements.

Making improvements to your DCS requires more initial investment than simply replacing components, but it has the potential to offer a far superior return. For example, you could configure new HMI displays to improve operator visibility into asset performance, allowing improvement on the time it takes to respond to alarms and recognize the root-cause of issues. Another improvement could be writing new controller code to automate manual operations and improve process control. Improvements to your DCS like this can help decrease downtime, enhance safety and reduce risk.

Will your upgrade be vertical or horizontal?

In a horizontal upgrade, you replace each turbine automation system in a sequential fashion. In a vertical upgrade, you replace the turbine automation system in conjunction with the upgrade to its associated systems, such as excitation, vibration monitoring and ESCADA.

“Making improvements to your DCS requires more initial investment than simply replacing components.”

This decision is often driven by your plant configurations and generation commitments. For example, you may have three turbines that supply power to an industrial facility, and two turbines must remain in service to meet production requirements. In this case, a horizontal upgrade approach would make the most sense to make sure two turbines are always available to supply power.

Will you upgrade all at once or with a phased approach?

Upgrading your entire DCS all at once is the simplest to execute. It also has the lowest overall purchase and installation costs. But enduring all the required downtime in one period is often too much for plants.

Spreading the downtime out across multiple periods is usually preferable. Specifically, a three-phase migration strategy that replaces HMI, controllers and finally I/O can spread your migration costs out over a longer period, minimize your risk, and reduce the amount of downtime your plant experiences.

Modern and Secure

The number of reported cyber-attacks on critical infrastructure has been on the rise in recent years. Security must be a non-negotiable element of your hydro control-systems upgrade project. Your strategy should be comprehensive and strive to:

– Safeguard your intellectual property.

– Protect against intrusions that threaten productivity, quality, and worker or environmental safety.

– Maintain critical systems on which populations depend.

– Achieve network availability and avoid network-related downtime.

– Support, while properly controlling, any remote access to your operations.

A good place to start is with the NERC CIPTM Reliability Standards. Familiarize yourself with the standards and how they apply to your facilities, systems, processes and workforce. Also, conducting a security assessment will help you understand the risks and areas of vulnerability that exist within your organization.

When it comes to implementing security, adopt a defense-in-depth approach. It’s a multilayered security approach based on the notion that any one point of protection can and likely will be defeated. It uses physical, electronic and procedural safeguards across six layers:

1. Policies and Procedures

2. Physical

3. Network

4. Computer

5. Application

6. Device

Finally, don’t overlook something as basic as working with trusted vendors. They can be just as integral to helping meet security goals as they are to your production, safety or quality goals. Request that all vendors disclose their security policies and practices, and ask if they follow core security principles when they design products.

There is an abundance of available industry resources that power producers can take advantage of to help bolster their security efforts. Converged Plantwide Ethernet (CPwE) reference architectures from Cisco and Rockwell Automation, for example, provide useful guidance for managing network-access security and addressing unknown risks.

Make the Most of Your Replacement Project

Aging hydro control systems will need to be replaced sooner rather than later. Upgrading to a modern DCS system will allow you to get the most from your replacement project. By combining centralized control with production intelligence, operators can get the most from their plant, as well as new and emerging IIoT technology.

Operators are under increasing pressure to find ways to improve the dispatch capability of their combined cycle facilities. Increased penetration of renewable generation has resulted, and will continue to result, in greater differences between peak and off-peak net load demand. Like it or not, combined cycle plants are under increasing pressure to chase variable wind and solar resources.

Several options can be employed to improve the reliability and flexibility of combined cycle plants. Each option must be considered within the context of the overall facility and the future outlook of power market pricing. This article highlights recent combined cycle dispatch trends and outlines plant dispatch improvements in the following areas:

• Startup/Ramping
• Part Load
• Peak Load

Select case study examples are presented to illustrate real-world opportunities.

EVALUATING the OPTIONS

Low gas prices, widely accepted to be stable for the foreseeable future, coupled with an unprecedented number of coal plant retirements, have placed gas-fired combined cycle plants in the slot of “baseload” generation. The reality, however, is that the combined cycle fleet (along with the remaining coal fleet) is largely responsible for filling the gap between inflexible nuclear generation and variable wind and solar. This need to fill the gap, or match net load demand, will play an increasing role in the economics of combined cycle plants.

Weekly reports issued by the Electric Reliability Council of Texas (ERCOT) and made available to the public provide a good illustration of how ERCOT load and wind output do not necessarily correlate well, leaving dispatchable generators responsible for filling a highly volatile gap, as presented in Figure 1. The example presented in Figure 1 shows a randomly selected week in spring where net load demand ranges from about 12.5 gigawatts (GW) to 41 GW within the span of a few days.

Many markets are experiencing extremely low off-peak prices and fewer high dollar on-peak prices; therefore, increased reliability and flexibility will be instrumental in keeping combined cycle plants economical. Improvements discussed herein can help enhance a combined cycle’s ability to make money for a utility through increased revenue and decreased cost.

Options should be evaluated on a cost/benefit or net present value basis, where project costs and incremental operational costs are weighed against avoided costs and increased revenues.

Improvement options and project examples are presented in the following sections.

IMPROVEMENT OPTIONS AND EXAMPLES

Startup/Ramping

Startup and ramping characteristics have historically been a secondary consideration for combined cycle plant design. Long start times and slow ramping capabilities are largely a result of a lack of perceived economic value, coupled with less apparent design ramifications. Additionally, operating and maintenance practices may not have been established with frequent cycling events in mind. The following are some common areas of potential improvement.

“This need to fill the gap, or match net load demand, will play an increasing role in the economics of combined cycle plants.”

Review Maintenance Practice

Often, changes in operating modes can lead to maintenance plans and strategies that differ from those used in the original design or commissioning. Figure 2 shows the operational impact caused by operating mode changes. Preventive maintenance plans were historically developed with time-based strategies, for example, monthly, quarterly or annual tasks or inspections. These time-based strategies used assumptions of expected operating profiles, starts/stops and ramp rates. Moving to more operating and condition-based maintenance tasks can improve equipment reliability. Condition-based maintenance and online condition monitoring continue to play an important role in managing overall equipment reliability and high impact equipment failure reduction.

Review and Audit of Startup Sequence

The start sequence should have been established on the basis of major equipment original equipment manufacturer (OEM) recommendations during plant commissioning. Plant commissioning engineers sometimes fail to follow OEM recommendations by either taking a more aggressive approach or, possibly, a more conservative approach according to their personal experiences with other, seemingly similar combined cycle plants. Over the years, previous plant management and operations might have taken similar stances and decided to modify start logic. Often, the first step in evaluating potential improvements to a plant’s startup capabilities is to perform an audit for which engineers develop an independent conceptual start sequence using equipment OEM recommendations. The conceptual start sequence can then be compared against current practices to determine what might, and what will not, work. The result may be a modified start sequence that can serve as a baseline for all further start improvement considerations. Implementation may be as simple as a revised operating procedure and distributed control system (DCS) logic.

Elimination of Purge on Startup

Purging the gas turbine and backend equipment during startup can be a lengthy process that lasts anywhere from five to 20 minutes. Eliminating purge on startup is possible by modifying the fuel and ammonia supplies. National Fire Protection Association (NFPA) 85 allows for elimination of purging at startup as long as the operator implements proper valving arrangements (i.e., triple block valves, double venting, valve on/off position switches and pressure switches or transmitters) and performs certain actions (valve proving at shutdown and continuous monitoring of valve positions and pressures). Purge credits can be maintained for 8 days or indefinitely if the pressurized pipe method is performed using air or inert gases as a sealing medium.

This relatively inexpensive plant modification allows for much faster gas turbine power production. This approach does require careful consideration for how to maintain continuous monitoring during shutdown, which can be considered onerous when accounting for issues such as position feedback noise.

Water Chemistry

When a change from baseload to cycling operation is considered, the plant water treatment system should be reviewed to ensure that it is sized appropriately. Because of startup blowdown, each startup requires additional makeup water, which sometimes requires modifications to increase the capacity of the existing water treatment system. This often results in adding capacity to the raw water inlet screen and filters and expansion of the demineralized water treatment system. Adding demineralized water storage tanks can reduce the size of the water treatment system depending on the cycling frequency of the unit. Alternatively, one solution that could drastically reduce startup water usage is the addition of a condensate polisher. Condensate polishers purify the condensate of various impurities, such as iron from the feedwater, which can concentrate in the heat recovery steam generator (HRSG) and impact performance and component life. In addition, condensate polishers can reduce the unit startup times resulting from water chemistry-related delays, minimize condenser leaks and reduce boiler cleaning frequency.

Heat Retention and Preheating

HRSG and steam turbine ramp rates are dictated by starting temperature. Two methods of improving ramping rates during startup are retaining the heat absorbed from the last time of operation and preheating equipment and piping in advance of a start sequence. A stack damper, coupled with insulation up to the point of the stack damper, is utilized to isolate the HRSG from the stack during shutdown to minimize natural draft cooling of the HRSG. An auxiliary steam supply, often from an auxiliary boiler, can be utilized to reduce startup times and the impact of cycling on the unit. Auxiliary steam is supplied to the HRSG drums, condenser sparging, steam line warming and steam turbine seals to warm systems preceding a startup. While it may be a long and difficult process to add an auxiliary boiler to an existing site, it is possible. Ideally, the site already has an auxiliary boiler with sufficient capacity, whether the boiler was used for other purposes and not properly tied into the cycle or whether tie-ins are already present but not being used to their full extent. In addition, auxiliary boilers can be equipped (or retrofitted) with heating coils in the auxiliary boiler mud drums to further reduce their startup time.

Thermal Decouplin of Steam Turbine

During startup, steam turbine admission temperature cannot be controlled using interstage attemperation. The reason is that interstage attemperators have only limited control of the steam temperature leaving the second to last superheater and reheater sections, and spray flow is restricted to maintain superheat before the final superheater and reheater sections. Much of the heat available in the gas turbine exhaust is subsequently absorbed by the final sections, and the resultant steam conditions to the steam turbine are largely unaffected by the interstage conditioning. Because of this, a traditional approach to starting a combined cycle entails holding the gas turbine at a very low load, with reduced exhaust temperature, for a period of time sufficient to warm the steam turbine and ancillary equipment. This works well from an equipment preservation perspective but results in a very slow startup. Adding final point attemperation to the main steam and hot reheat piping between the HRSG and steam turbine allows better control of steam turbine admission temperatures, freeing the gas turbine to ramp at a rate allowed by the HRSG. By adhering to the HRSG OEM pressure section ramp limitations, the gas turbine ramp time to minimum emissions compliance load (MECL) can be reduced, improving combined cycle responsiveness and minimizing startup emissions.

Automation

Typically, plant startup procedures call for visual checks and manual operation of valves (i.e., steam line and HRSG vents and drains). The time frame required for this process depends on whether the start was anticipated, plant staff availability to perform and other conditions. Installing proper instrumentation and block valve actuation maximizes control room operator capabilities and reduces start times. Typically, a start sequence audit will reveal such opportunities for automation.

Feed-Forward Controls

When the gas turbine is started or ramped at high rates of change, rapid changes occur in steam production and nitrogen oxide (NOx) production. Modifying the steam attemperator controls and possibly the drum level controls to include a feed-forward loop informed by gas turbine ramp rate settings improves responsiveness in maintaining adequate boiler feed pump head and improves the consistency in admission steam temperature to mitigate side effects of fast ramping, such as temperature excursions, load holds, load runbacks and trips. Ramping the gas turbine quickly can result in rapid changes in NOx production. Since NOx is typically measured only at the stack, fast ramping can lead to over injecting or under injecting ammonia. Over injecting ammonia can result in higher ammonia slip, potentially exceeding permit limits, and greater conversion of ammonia salts, increasing the potential of deposition on the low-pressure (LP) evaporator and economizer sections. Under injecting can result in stack NOx emissions exceeding permit limits. To mitigate these issues, the addition of feed-forward controls should be considered.

EXAMPLE 1

— Elimination of Purge on Startup

The example presented is a 3-on-1 combined cycle (three gas turbine/HRSG trains supplying steam to a single condensing steam turbine generator) based on Mitsubishi G-Series gas turbines. Figure 3 is an example startup curve showing the combined cycle block load at startup before and after applying NFPA 85 purge credit retrofits.

Assuming a dispatch profit margin of $6 per megawatt-hour (MWh) and 150 starts per year, the estimated benefit of incorporating natural gas and ammonia supply purge credit designs would result in a profit of approximately $1,400 per start, or $210,000 per year. These savings are likely understated because the assumed purge time used was five minutes. Purge times on the order of 10 to 15 minutes are more typical for combined cycle plants.

EXAMPLE 2

— Thermal Decoupling of Steam Turbine

A feasibility study was performed for reducing startup times on a 1-on-1 combined cycle based on a Siemens-Westinghouse 501FD3 gas turbine, Nooter/Eriksen HRSG and Fuji Electric Type KN steam turbine. One of the options considered included the addition of final point attemperators. Adhering to the HRSG OEM pressure section ramp limitations, the gas turbine ramp time to MECL could be reduced by about 140 minutes, as shown in Figure 4, during a cold start event.

Part Load

Part load performance and turndown capabilities are becoming increasingly important as the difference between net load demand peak hours and off-peak hours grows. The benefits of keeping a unit online rather than cycling the unit off and on can be huge. A unit online is much more reliable and responsive than a unit offline. In addition, avoiding start/stop cycles can help preserve the life of the asset. The following are some common areas of potential improvement.

Boiler Feed Pumps

Operating a boiler feed pump at low flow increases pump stresses and strains on both the pump and feedwater control valves, causing premature wear or, in severe cases, failure. Solutions to mitigate this include upgrading the pump to a design more suited to frequent starts/stops and implementing a variable frequency drive (VFD) or fluid coupling drive. When modifying an existing feedwater pump(s) is considered, a VFD is often evaluated as the lowest installed cost option because of the minimal physical changes required to the pump and motor; whereas, a fluid coupling requires shifting the motor to accommodate for the space of the coupling. Additional benefits of VFDs include the ability to use a single VFD for multiple redundant pumps in addition to improving the plant heat rate at lower loads. However, fluid couplings are typically the more cost-effective approach for a new-build combined cycle because they have a lower capital cost and can be designed into the pump layout.

Piping

High energy piping, from small bore attemperator feed piping to the large bore steam lines, is also impacted by the increased thermal cycles, often leading to pipe support failure and resulting in inadequately supported piping. The best solution to mitigate this impact is to take a proactive approach to performing high energy pipe support audits every couple of years.

If unsure of where to start, the best practice is to perform a balance-of-plant equipment audit to ensure that equipment is operating within its design capacity, determine any potential impacts associated with part load operation and identify potential opportunities to improve part load turndown and/or efficiency.

EXAMPLE 3

— Boiler Feed Pump Upgrades

Black & Veatch recently supported a client with a 2-on-1 General Electric (GE) 7FA combined cycle plant that was experiencing boiler feed pump reliability concerns. The plant was designed for baseload operation, and to save capital cost, the original feedwater pumps were provided with only a balancing drum and slinger type oil lubrication. Because the feedwater pumps had no active control of the shaft axial position, the balancing drum was damaged as the pump accelerated to speed on each startup. Black & Veatch was engaged to study the feedwater pump failure information, perform a system assessment and make recommendations for pump improvements. Discussions with the client and the pump OEM led to the purchase and installation of a new pump with active thrust bearings and forced oil feed lubrication, which is better suited for cycling operation. In addition, the new pump was able to reuse the existing soleplate, motor and piping connections, thus minimizing the outage time for installation.

Black & Veatch’s design also focused on improving pump operation minimum flow control, including improved piping layout, tight shut-off valve and elimination of concerns with flow accelerated corrosion of the high velocity pump minimum flow piping. The piping system hydraulics and piping stress were analyzed to ensure successful long-term operation. The improvements eliminated reliability and maintenance issues with the original minimum flow control valve and provided the flow capacity required for cyclic operation of the existing feedwater pumps. Feedwater pump suction piping was rerouted to eliminate an intermediate high point in the suction piping that was an operating concern with potentially catastrophic effects on pump operation. Finally, an in-depth study of the pump protection instrumentation and logic, comparing the existing systems with industry best practices, was performed; control system changes for pump protection were recommended from this list.

Peak Load

Increasing the peak output capacity of a combined cycle must be carefully evaluated as balance-of-plant design limitations, often in the areas of electrical export, water/steam production, steam turbine flow, heat rejection, and air permit limits can increase project cost or even render certain upgrades infeasible. In general, a combined cycle already equipped with supplemental HRSG duct firing and an oversized steam turbine is often more amenable to such upgrades. The following are some common areas of potential improvement.

Evaporative Cooling

There are generally two forms of evaporative cooling: wetted media and fogging. Wetted media evaporative cooling requires a large surface area typically made of a cellulosic or glass fiber material that is wetted using a filtered water stream. As the air passes through the wetted material, water is vaporized, and gas turbine compressor inlet temperature approaches wet-bulb temperature. The moisture-laden air is cooled and at a higher density, thus increasing mass flow and output of the gas turbine, often with the additional benefit of improved gas turbine efficiency. As a general rule, wetted media evaporative cooling is capable of cooling the gas turbine inlet air by about 85 percent of the difference between the dry-bulb and wet-bulb temperature. Typically, no modifications are required for the bottoming cycle or electrical systems, provided that some margin currently remains. Fogging technology works in a manner similar to wetted media except that the water is introduced into the inlet airstream in an active manner. Atomized high purity water is injected into the inlet airstream through an array of nozzles. Water injection is controlled using a weather station, which is often mounted on the fogging pump skid. Since gas turbine filters and inlet filter houses are not designed to pass saturated air, the compressor inlet air temperature is typically maintained slightly above wet-bulb, by approximately 1 to 2° F (0.56 to 1.11° C). A schematic of a fogging system is presented on Figure 5.

Chilling

Chilling reduces the gas turbine compressor inlet temperature, thus increasing gas turbine output and often reducing gas turbine heat rate by removing heat from the inlet airstream through indirect cooling. Chilling works by sending a chilled coolant (often water or a water/glycol mixture) from a condenser to a finned tube heat exchanger, or chiller coil, situated in the gas turbine inlet airstream. The chiller coil then removes heat from the inlet airstream and returns the warmed coolant to the chiller unit, which is typically an electrically powered mechanical vapor-compression refrigeration cycle. Unlike evaporative cooling, chilling works through indirect cooling, and no water is imparted into the gas turbine inlet airstream. In addition, chilling is capable of reducing the compressor inlet air temperature below the ambient wet-bulb temperature, potentially as low as 45° F (7° C).

Gas Turbine Upgrades

Gas turbine upgrade options vary depending on the OEM and model. Upgrades can be as common as extended life hot gas path parts or minor software upgrades, or more extreme, such as an entirely new compressor or hot gas path design. Upgrades can be performed to improve reliability, maintainability, performance or a combination of these. Unlike evaporative cooling or chilling, many gas turbine upgrade options improve performance throughout the year. In addition, much more significant improvements are often possible. Drawbacks might be high initial cost, higher long-term maintenance fees and possibly having to permit the upgrade as a major modification.

Steam Turbine Upgrades

Steam turbine upgrades are something to consider for a plant’s next major overhaul. Advances in steam turbine technology (improved airfoil profiles, sealing techniques, materials and cooling techniques), along with the potential to “open up” the steam turbine flow path for increased output, can have large returns, especially for a combined cycle already equipped with supplemental HRSG duct firing and an oversized steam turbine.

EXAMPLE 4

— Evaporative Cooling

A client was interested in increasing output during summer conditions for a 3-on-1 combined cycle based on GE LM6000 gas turbines, two pressure non-reheat steam turbines, and an air-cooled condenser. Two evaporative cooling technologies were considered: wetted media and fogging. Wetted media evaporative cooling is considered to be a proven passively controlled technology requiring minimal electricity. However, its limited ability to improve performance, coupled with the need to retrofit the existing inlet air filter housings for the added space and weight of the wetted media and water trough, made that option unappealing.

Fogging is capable of depressing the gas turbine inlet air temperature better than wetted media. In the above application, because of the inlet air duct arrangement, the retrofit installation would have to be mounted just inside the inlet air louvers, upstream of the filters. Since the filters are not designed to pass saturated air, the inlet air temperature would need to be maintained above saturation; a 1° F (0.56° C) margin was selected as the target control. The fogging nozzle array could be placed farther downstream, just upstream of the compressor inlet; however, water agglomeration on birdscreen and structural members just upstream of the bellmouth has the potential to impinge on the compressor blades. Fogging relies on electricity to drive high-pressure (HP) positive displacement pumps and a source of high purity demineralized water. In addition, there is some risk associated with fogging because it is an actively controlled technology; a potential exists for issues caused by overspray. As with wetted media evaporative cooling, no modifications were identified as being required for the bottoming cycle or electrical systems. Combined cycle hot day operation net plant output was estimated to increase by about 5 to 8 percent, and net plant heat rate was estimated to decrease by about 1 to 1.5 percent for both evaporative cooling options considered, depending on hot day relative humidity.

EXAMPLE 5

— Steam Turbine Upgrades

A client wanted to increase the summer capacity of a 3-on-1 combined cycle based on GE 7F.04 gas turbines, Foster Wheeler HRSG with supplemental duct firing capabilities and an oversized Toshiba two casing steam turbine with combined HP and intermediate-pressure (IP) casings and two flow LP casings. A proposal to upgrade the steam turbine was reviewed, and a thermodynamic model of the plant was created to assess feasibility of the upgrades and balance-of-plant limitations. Proposed upgrades included new fully bladed HP-IP rotor, HP-IP nozzle diaphragms, HP inner casing, new LP blades for the first two stages, diaphragm packing seals, gland packing seals and other associated steam turbine hardware along with necessary generator stator, rotor, hydrogen cooler, excitation and protection upgrades.

The preliminary assessment revealed that the level of duct firing would be limited by the HP turbine exhaust pressure limit because of restrictions in the reheat piping and LP turbine flow passing capabilities.

The upgrade proposal was revised accordingly to reflect the discovered limitation, resulting in significantly diminished guaranteed fully fired steam turbine output.

The isolated phase bus duct and generator circuit breaker were found to be undersized, which would require further attention and potential replacement should the project proceed. The estimated combined cycle net maximum increase in power was about 4.5 percent.

SUMMARY

Combined cycle plants are under increasing pressure to chase variable wind and solar resources. Combined cycle flexibility is expected to play an increasingly important role in keeping the plants economically viable through improvements in reliability and flexibility.

The options described and examples presented in this paper demonstrate that there are many avenues to consider. Whether the objective is to minimize downtime, improve start responsiveness or maximize output and/or heat rate, there are solutions that could offer high payoffs. Understanding and evaluating the options is paramount to the success of a combined cycle facility.

Tecogen InVerde CHP units at the Princeton Club in New York City

What do the Excelsior Hotel, the Cathedral Village Retirement Home, Grand County High School, Statz Farms, the Willard Apartments, and Supreme Sports Club have in common? They all represent the new face of the combined heat and power (CHP) market. Relatively small commercial facilities that are installing CHP to save money on energy bills, keep the lights on and maintain heating and cooling when the grid goes out, and make themselves more competitive in an ever-changing market. Gone are the days when only large industrial facilities consider CHP and utilities fight them tooth and nail. The new CHP market includes installations of all sizes, in increasing numbers of applications, using expanding fuel types, and with new business models that include utility ownership.

These fundamental changes are happening in response to the evolving electric market structure and customer preferences as distributed energy resources (DER) become more widely used and accepted. Increasing interest in distributed energy is shifting the nature of the electric grid in the US and how electric utilities provide service to their customers.

Market Potential for CHP

While the basic concept of CHP goes all the way back to Thomas Edison, who employed it in his first commercial power station, the majority of the CHP capacity in operation today was installed during the twenty year period from the late 1980s through the early 2000s. This is when the Public Utility Regulatory Policy Act (PURPA) enabled CHP systems that met efficiency standards to sell electricity back to the local utility at beneficial rates. Many of these were large utility scale systems located at industrial facilities and to this day the majority of U.S. CHP capacity is located in the industrial sector, accounting for 86 percent of installed capacity, with the remaining 14 percent located in the commercial/institutional sector. After changes to PURPA and the recession of the late 2000s, growth of CHP capacity slowed significantly. While industrial facilities still represent the majority of capacity additions, new CHP capacity in the commercial sector is growing at a faster rate, reflecting a changing market atmosphere.

CHP provides a significant amount of our nation’s power and heat supply, providing electricity and thermal energy for almost 4,400 facilities around the country. The 82 GW of CHP capacity currently operating in the US represents 12 percent of electricity production and 8 percent of power generation capacity, much more than most other types of distributed generation technology. And while this is a lot more than most people realize, it’s not anywhere near the technology’s full potential. ICF studies estimate the technical potential for additional onsite CHP at existing industrial and commercial facilities to be 140 GW, almost double the current installed base. In fact, a variety of game-changing factors have emerged that are shifting the economics and value proposition for CHP in the US.

Drivers for CHP Growth

Energy Resiliency

CHP can improve energy resiliency for end-users, reducing the impacts of an emergency by keeping critical facilities running without any interruption in electric or thermal service. Properly sized CHP systems can effectively insulate facilities from a grid failure. In so doing, they provide continuity of critical services and free up power restoration efforts to be focused on other facilities that rely on grid power. When designed to operate independently (in “island” mode) from the grid, CHP systems can provide critical power reliability for a variety of facilities while also providing electric and thermal energy on a continuous basis, resulting in daily operational cost savings. CHP systems can be configured in a number of ways to meet the specific reliability needs and risk profiles of various customers and to offset the capital cost investment for traditional backup power measures. Many facilities will typically have backup generators on-site to supply electricity in the case of a grid failure; however, the regular operation and maintenance of CHP systems and access to a consistent fuel supply provide several advantages over backup generators which sometimes fail to start or can run out of on-site fuel during extended grid outages.

“The 82 GW of CHP capacity operating in the US represent 12 perce of electricity production and 8 percent of power generation capacity, more than most other types of DG.”

Earlier this year Hurricanes Harvey and Irma slammed into Texas and Florida, wreaking havoc on local economies, infrastructure, and communities. The storms caused widespread damage and economic losses, and extended power outages affected the regions for days. Many commercial and industrial facilities in the areas were able to continue operating due to CHP. The Texas Medical Center in Houston was able to continue operations during Harvey due to its 48 MW CHP system. Operated by Thermal Energy Corporation (TECO), the CHP plant serves chilled water and steam to more than 19 million square feet in 18 institutions on the Texas Medical Center campus, and was designed to provide 100 percent of the overall power needs so the campus can function off the grid as needed. Although surrounded by flooding during Harvey, the medical center continued to maintain normal patient care during the storm, and was able to provide community support services as the flood waters receded. Overall, a CHP system that runs every day and saves money continuously is more reliable in an emergency than a backup generator system that only runs during emergencies.

Economic Resiliency

By efficiently using America’s abundant supply of natural gas and the growing amounts of renewable fuels such as biogas and landfill gas, manufacturers and commercial businesses are improving their competitive position and maintaining high-paying jobs for their communities through the use of CHP. Thought to be in short supply only a few years ago, the shale gas revolution has transformed the outlook for natural gas, providing manufacturers with a reliable and clean fuel source at a cost well below their international competitors. Many manufacturers are finding that the efficient use of these resources through CHP further increases the economic value to their operations, while enhancing power reliability and overall energy security. One such example is Proctor & Gamble’s Mehoopany Plant in Northeastern Pennsylvania. In 2013, the plant expanded its existing CHP system by adding a second combustion turbine and heat recovery steam generator. Using 100 percent local natural gas, much of which comes from the ground under the plant, the CHP system produces 64 MW of electricity, 140,000 pounds of steam per hour, and hot air to two of the plant’s paper machines, displacing natural gas that had been used to directly dry paper. Given that the Mehoopany facility is nearly 20 percent of P&G’s global energy footprint, the CHP system has represented a major step toward the company’s business objective to improve both its finances and its environmental record. The plant is now totally independent for its site energy needs, is selling excess electricity back to the local grid, and realizing an annual gross savings of $16.5 million per year.

As a result of new and more stringent environmental regulations, the power industry faces a twofold challenge to significantly reduce sulfur dioxide (SO2) and other acid gases, mercury (Hg), particulate matter (PM) and nitrogen oxides (NOx) from air emissions while concurrently eliminating wet disposal of ash generated by coal fired power plants.

The Tennessee Valley Authority’s Gallatin Air Quality Control System (AQCS) Project is a robust response to this challenge with the application of a state-of-the-art dry scrubber and selective catalytic reduction (SCR) air quality control technology and an industry-leading on-site dry ash storage process.

TVA’s Gallatin Plant is located on the Cumberland River — Old Hickory Lake near Gallatin, Tennessee. The coal-fired station consists of four twin furnace tangentially fired boilers each with low NOx burners.

The Gallatin Plant provides power to more than 560,000 residences and businesses and employs over 200 in the Nashville region. The Project extends the life of the TVA Gallatin Fossil Plant for the next 20 years by addressing the needs for air quality improvement and lined disposal of coal combustion residuals (CCR).

Three primary elements of design and construction were included: (1) four dry scrubber units, which reduce SO2, Hg, Hydrogen Chloride (HCl) and PM emissions, (2) four (SCR) units which reduce NOx, currently under construction (3) a new EPA-compliant dry, lined landfill facility on plant property for providing storage needs for the 400,000 cubic yards of dry CCR generated yearly and (4) a one-mile haul road corridor that connects the scrubber facility with the landfill. Several aspects of the AQCS Project will be discussed including system design overview, challenges and performance.

Fleetwide Strategy

In support of its compliance with the Environmental Protection Agency’s (EPA’s) Clean Air Acts and as a means of enhancing the quality-of-life for Valley residents and being a good steward of the Valley’s natural resources, TVA has invested significantly in an aggressive fleetwide clean air control program. In addition, TVA has committed to closing wet coal combustion residuals (CCR) impounds, converting wet ash management facilities to dry ash management, across the fleet.

In order to reduce NOx, TVA has installed SCR technology on 21 of its coal units resulting in a 92 percent reduction in NOx emissions since 1995. All of TVA’s natural gas-fired combined cycle plants have SCRs to reduce NOx emissions. Figure 1 shows the progressive reduction in NOx Emissions at TVA power plants, from a peak in 1995.

To reduce SO2 emissions, TVA has switched to low-sulfur coal at some fossil plants and equipped approximately 70% of its coal-fired capacity with scrubbers. TVA has reduced SO2 emissions by 94 percent since regulations began in 1977. Figure 2 shows the progressive reduction in SO2 emissions at TVA power plants from a peak in 1977.

Commensurate with TVA’s fleetwide master strategy, a large scale AQCS retrofit was undertaken at Gallatin Fossil Plant. Planning for the AQCS retrofit began in 2011and detailed design and construction for the installation began in 2013.

Gallatin Fossil Plant Overview

Gallatin Fossil Plant (GAF) is located on 1950 acres of land on the north bank of the Cumberland River in Sumner County, Tennessee, approximately seven miles south of the nearby town of Gallatin. The plant has four generating units with a combined summer net generating capacity of 976 megawatts. Groundbreaking occurred in 1953. The first of the four generating units went into operation in 1956.

Figure 3 provides an aerial view of the GAF plant and facilities prior to the start of AQCS installation in 2013.

The four generating units are Alstom/CE twin furnace tangentially fired boilers. Units 1 & 2 each have a maximum continuous rating (MCR) of 250 MW Gross and Units 3 & 4 each have a MCR of 275 MW Gross. Prior to the start of the new AQCS projects, emission control on these units was Electrostatic Precipitators (ESPs) to collect fly ash and low NOx burners to limit emission of NOx on each boiler

From the beginning of plant operations in the 1950s until 2015, coal ash was handled via wet sluicing operations. Historically, GAF consumed approximately four million tons of coal which yield approximately 235,000 tons of fly and bottom ash CCRs annually but has varied historically based on consumer demand.

GAF AQCS Project

The new AQCS at Gallatin includes SCRs to reduce NOx emissions and dry flue gas desulfurization (DFGD) scrubber units to reduce SO2, Hg, and PM emissions on all four units. The first two scrubber units went into operation in Spring 2015 and the final unit went into service in February 2016. The first two SCR units went into operation in Spring 2017, while the last two are planned to be in operation by the end of 2017. Figure 4 is a rendering of the plant with all AQCS additions.

DFGD

The new DFGD systems at Gallatin are currently operating on all four units. The DFGD systems are designed to reduce SO2 emissions nominally by 96%.

The retrofit and installation project also included replacement of the existing Induced Draft (ID) Fans, and decommissioning of the existing ESPs. New ID Fans were installed to provide for the additional flue gas pressure drop in the DFGD system and SCR project components.

Various commercially available DFGD technologies were considered and bids were solicited for the application of two types of technologies: circulating dry scrubber and spray dryer absorber. After a detailed bid evaluation, a type of circulating dry scrubber technology was selected. Each Unit was retrofitted with a DFGD System, consisting of an absorber followed by a pulse jet fabric filter (PJFF) to control SO2, SO3, HCl, Hg, and PM emissions.

The two main reagents used in the DFGD system are pebble lime for SO2, SO3 and HCl removal and activated carbon for Hg removal. Fly ash and DFGD reaction byproducts are removed in the PJFF and collected in the PJFF hoppers.

SO2 / SO3 / HCl Removal

The primary processes utilized in the acid gas removal technology are (1) the introduction of water to lower the gas temperature and (2) the reaction of the acidic gases with hydrated lime to form and then remove the calcium salts. As the chemical reaction is facilitated in the liquid film, in principle, the closer the gas is cooled to the adiabatic saturation temperature of the flue gas, the higher the removal efficiency will be. However, the closer the gas is to the adiabatic saturation temperature, the higher the corrosion potential and the need for expensive corrosion resistant materials of construction as well as the potential for wet solids build-up on the scrubber surfaces. In practice, the removal efficiencies required at GAF can be achieved at a 35°F approach to the adiabatic saturation temperature. Consequently, the operating temperature is limited to no less than a 35°F approach to the adiabatic saturation temperature.

Mercury Removal

The chemistry related to mercury in coal as it goes through combustion and downstream flue gas treatment processes is quite complex. Elemental mercury in the flue gas is oxidized to an extent depending upon the type of coal burned, the constituents of the flue gas and the presence of catalytic reactors in the flue gas path. As such, there are three forms of mercury in the boiler flue gas: elemental (Hg0), oxidized (Hg2) and particulate-bound Hg. In the DFGD system, most of all three of these forms of mercury are removed with the other solids in the PJFF. The mercury removal is enhanced by adsorption on the activated carbon injected in the flue gas at the inlet of the fabric filter.

PM Removal

Flue gas flows from each absorber to a dedicated PJFF. The PJFFs remove the dry solid reaction products, unreacted reagent and fly ash entrained in the flue gas before the flue gas is discharged to the atmosphere.

The fabric filter bags collect a layer of solids on their outer surfaces between cleanings and the movement of the flue gas through this layer enhances the gas-solid contact. Over time, the filter cake collected on the bags becomes too thick and must be cleaned off the bags. The filter bag cleaning system is designed for on-line and off-line cleaning of PJFFs. The cleaning system is fully automatic and utilizes compressed air for cleaning.

Each fabric filter is furnished with a fluidized trough hopper. Blowers introduce fluidizing air into the fluid trough to keep the solids fluidized. The recycled solids are sent back to the absorber with the remainder of the solids going to the byproduct & flyash (BPFA) handling system for disposal.

A unique feature for the PJFF units was the use of 10 meter fabric filter bags. By using the longer bags, the number of fabric filter modules was reduced to four, limiting the overall footprint of the units.

BPFA Handling and Disposal

The BPFA generated by the new DFGD systems is characterized as (CCR). The material contains both fly ash and free lime, resulting in a CCR that exhibits cementitious properties i.e., reacts and hardens in the presence of water. It is projected that the units will produce between 435,000 and 932,000 cubic yards of CCR per year.

BPFA material is discharged from each PJFF and directed to storage silos via a vacuum conveying system. Each BPFA storage silo has a dedicated fluidizing system which keeps the BPFA in a suspended, fluidized state and promotes the flow of the BPFA towards the silo outlets.

The BPFA is conditioned and discharged to trucks for transport to a new onsite Landfill.

Landfill

Prior to the installation of the new DFGD systems, CCR’s generated at GAF were wet sluiced to an on-site 400 acre ash pond complex. The dry CCR generated by the DFGD system is stored in a new, lined on site landfill. The landfill was designed to accommodate 20 years of CCR storage capacity, with footprint of approximately 52 acres.

SCR

The SCR systems at GAF are currently being installed and are designed to reduce NOx emission from 0.4 to less than 0.03 lbs/MMBtu, achieving a reduction efficiency of greater than 92.5 percent.

One SCR reactor is installed for each generating unit and will tie in to the existing boilers at the outlet of the economizer section. The flue gas exiting the SCR units will return to the existing Air Preheaters. The SCR systems utilize anhydrous ammonia (NH3) as the reducing reagent.

Conversion of NOx in boiler flue gas is accomplished by mixing a reducing agent (ammonia) with the flue gas. The flue gas, mixed with ammonia, is then passed through a catalyst to promote a selective reaction of the reducing agent with the NOx to form nitrogen gas and water vapor. The catalyst is configured in layers in a vertical flow reactor vessel in which flue gas enters from the top and exits from the bottom. The mixing of the reducing agent and the flue gas is accomplished in the gas duct upstream of the reactor vessel. The ammonia is supplied to the flue gas by a number of lances arranged within the reactor inlet duct. A system of static mixers is employed to promote turbulent flow and mixing of the gas and ammonia.

The flue gas mixing system was designed to sufficiently mix reagent ammonia and flue gas such that the Ammonia to NOx distribution at the inlet face of the first layer of catalyst will be less than or equal to 2 percent RMS at full load and not more than 5 percent at minimum load. The relationship between Ammonia to NOx distribution and observed Ammonia slip is evident in Figure 6.

Muzio et. al (2009) derived the plot shown in Figure 6, using FERCo’s process model for SCR performance. In this figure ammonia slip is plotted as a function of NOx reduction for varying Ammonia to NOx distribution. It is evident from the plot that for overall NOx conversion greater than 90 percent the Ammonia to NOx distribution becomes increasingly important. In order to reach a target 2ppm ammonia slip, the maximum achievable NOx conversion is nominally 93 percent with the required Ammonia to NOx distribution approaching 2 percent RMS. While these results are based on a model plant, the relationship between conversion efficiency slip and distribution should hold constant for any medium sized coal fired unit. It is expected that the achieved mixing may degrade over time due to ash deposition and buildup. Therefore design for a lower catalyst inlet Ammonia to NOx distribution at 2 percent RMS affords greater margin to meet the design conversion and slip requirements within the operating life of the catalyst.

Anhydrous Ammonia Tank Farm and Vaporizer

A new Anhydrous Ammonia Tank Farm and Vaporizer (ATF) system was installed to receive, store and deliver ammonia vapor to the SCR units. This system consists of three 18,000 gallon ammonia storage tanks, forwarding pumps and vaporizer units, as well as truck unloading facilities.

Air Preheater Modifications

All four units at GAF utilize three (3) regenerative type air preheaters which were placed in operation when the units initially were placed in operation in the late 1950s. All twelve existing air preheaters utilize a Bi-Sector configuration and originally employed a 3-layer construction typical of the era that the units were built.

The operation of a conventional 3-layer air preheater downstream of an SCR system poses the threat of fouling the air preheater heat transfer surface. Ammonia slip from the SCR combines with SO3 and water vapor to form ammonium bisulfate (ABS). ABS deposits are sticky and readily combine with fly ash to form a difficult to remove deposit on the air preheater heat transfer surface. The temperature zone at which ABS forms occurs near the center of a typical air preheater, far from cleaning equipment installed at either the hot or cold side of the APH rotor.

The location of the deposits in conjunction with the presence of a gap between the hot and intermediate layers, as well as the open-channel configuration of the intermediate elements, severely limits the capability of cleaning systems to remove ABS deposits in a conventional 3layer configuration.

In order to mitigate the effects of ABS deposition a new basket configuration was developed for the GAF units. The new configuration utilized deeper cold end elements and eliminated the intermediate layer. The depth of the cold end layer was set to ensure that the ABS deposition zone would fall solely in these elements. Further, new closed channel elements were utilized for this layer to ensure that the maximum sootblowing steam penetration could be achieved. Finally, new cold end steam sootblowers were also installed on all Units. This combination of modifications and cleaning devices has been proven to effectively mitigate the impact of ABS deposition in air preheaters operating downstream of SCRs.

Boiler Modifications

Boiler modifications, including the removal of economizer heat transfer surface for Units 3 & 4 as well as the installation of Hot Water Recirculation Systems (HWRS) for all units, was required to ensure that flue gas entering the SCR units exceeds the minimum operating temperature for the complete load range.

Prior to modification of the Unit boilers, the temperature of the flue gas exiting the economizer was too low for normal SCR operation at low load. The SCR units are designed to operate in the range of 620 — 690oF. At temperatures below the design operation range, SO3 in the flue gas will react with ammonia to form ammonia sulfur salts (ammonium sulfate and bisulfate) that deactivate the catalyst.

An extensive study was completed to evaluate the options for control of the economizer gas outlet temperatures.

Utilizing operating data gathered in December 2011 the existing boiler units were modelled. The models were used to evaluate options and established general operating impacts under each of several gas temperature control configurations.

In particular the goal of the analysis was to select modifications that would increase the flue gas temperature over the complete load profile while also minimizing the impact to the unit thermal efficiency.

Environmental Compliance

The DFGD Systems are designed to meet the emissions limits summarized for the specified 20 years design life. All equipment is specified to support these performance guarantees.

The SCR systems are designed to meet the emissions limits and performance guarantees.

The units currently utilize a 100% Powder River Basin (PRB) coal.

The systems are designed to meet the performance requirements stated in Tables 1 and 2 for both the PRB coal and a 50%/50% blend of PRB and Eastern Bituminous coals.

Project Results and Performance

Units 1 & 3 operating data was collected during the 2015 and 2016 operating years in order to analyze the performance of the DFGD systems. During this period the units burned 100% PRB coal.

Unit 1 average SO2 emissions were analyzed during the months of June and August of 2015, prior to the DFGD system being placed into service, and compared to data sets from February and March of 2016 post DFGD system operation.

As is evident in Figure 7, the DFGD system operation resulted in a marked decrease in SO2 emissions. Across the complete load range presented, average SO2 emissions ranged from 0.03 to 0.05 Lbs/MMBTU, significantly lower than design target emissions of 0.06 Lbs/MMBTU.

Unit 3 average SO2 emissions were analyzed during the months of February and March of 2015, prior to the DFGD system being placed into service, and compared to data sets from September and October of the same year, post DFGD system operation. Similar to the results presented for Unit 1, the DFGD system operation resulted in a marked decrease in SO2 emissions.

Across the complete load range presented, average SO2 emissions ranged from 0.02 to 0.05 Lbs/MMBTU, significantly lower than design target emissions of 0.06 Lbs/MMBTU.

Conclusions and Summary and Wrap-Up

Over the course of five years, a new air quality control system addressing numerous plant emissions was installed at TVAs Gallatin Fossil Plant. The AQCS retrofit was implemented to reduce SO2, Hg, PM and NOx emissions at the plant in accordance with TVA’s fleet wide clean air control program. In addition, a new dry, lined landfill facility was added to handle CCR from the units. An analysis of SO2 emissions data indicates that the DFGD units are operating within expectations based on the load and fuel profile. The plant upgrades have been comprehensive and will extend the life of the facility for decades.