The system could not keep up with the steam boiler demand and required frequent clean-in-place (CIP) service, resulting in additional chemical and operator costs. During a visit to the plant, U.S. Water recommended an approach to improve their system reliability.

Reverse osmosis system. Photo courtesy: U.S. Water.

When the plant began experiencing issues with their equipment, the existing equipment manufacturer did not provide a representative to service the equipment. This left the plant paying $6,000 for an outside service technician visit. U.S. Water introduced the plant to the company’s integrated approach combing chemical, equipment and service, and shortly after, began designing a custom RO to meet their needs.

U.S. Water’s Engineering and Equipment team worked closely with plant management to build a custom solution. An efficient RO system was installed to produce enough makeup to meet the plant’s requirements, as well as a mixed bed demineralizer to further water purification and improve steam quality. A U.S. Water field rep also schedules monthly visits to ensure system reliability.

The equipment program was paired with U.S. Water Reports wireless communications system. U.S. Water Reports allows for daily operator logs and instant alerts if the system is experiencing any irregularities that may need immediate attention.

Since implementing the total solution, the makeup water system has become extremely reliable. During normal operation, the RO is producing 300 gallons per minute (gpm) makeup water to meet the plant expectation. It was also designed to produce 600 gpm in parallel (in case of emergency). Installing the new equipment resulted in no lost time on the RO system allowing for continued steam production, saving the plant $100,000 a year. Due to the high quality steam production, the plant is also able to avoid non-conformance fees, saving approximately $20,000 a year.

RO SYSTEM ACHIEVEMENTS

• Makeup water flow rate improved to 300 gallons per minute during normal operation
• Saved plant $10,000 a year in CIP chemicals cost
• Saved the plant $20,000 a year in outside service technical costs
• No lost time on the RO system, saving the plant $100,000 a year.

BY STEVE MORRISON

Tens of thousands of valves are required to manage the myriad of fluid and gasses in a power generation facility. Whether the valve is for isolation, flow reversal protection or something completely different, engineers and designers face endless safety considerations and performance options when selecting valves. Decision makers must choose a valve capable of accommodating the demand and stress placed on these plant piping systems.

To truly understand the best valve solution for an application, owners, engineers and contractors must work together to evaluate product design, performance, quality and lifecycle costs to select the most appropriate product for their needs.

Transportation of grooved pipe spools is more efficient, reducing trips, site congestion and shipping costs.

Design and Planning

During the design and planning phase, it is important to accurately specify the system parameters as well as media and flow conditions through the hydraulic circuit. Only then can engineers select the appropriate hardware solution to meet configuration, material and other system requirements.

One of the most commonly overlooked elements when designing and planning a pipe system for power generation plants are flow rates and Cv values. It is imperative that the right valve size and type are selected to enable peak performance. Improper valve selection can be both costly and risky. If a valve is too small, it will not pass the required flow, and the process will be starved. Alternatively, an oversized valve unnecessarily increases costs.

The Cv value – the uniform measurement of liquid flow capacity coefficients – is vital in any planning scenario for power generation plants because it is directly related to operation costs from power consumption of electric motors used to operate pumps. This is invaluable as more flow at a lower pressure equates to less energy needed for the pipe system to overcome the pressure drop.

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The Grooved Solution

A grooved pipe joint comprises four elements: Grooved-end pipe, gasket, coupling housing and bolts/nuts.

Full Speed Ahead

Anyone who has been involved in a power plant project knows that the construction schedule is one of the most important, and most challenging, aspects of a project to manage. Companies often push for an aggressive timeline in hopes of reducing labor costs and activating their new facility as quickly as possible. However, fast-tracked schedules can lead to a variety of problems, including reductions in work quality, unbudgeted overtime and missed deadlines.

Recent advances in design and information technologies have proven the value of prefabrication as a strategy for cutting installation times and improving overall project efficiency. When properly implemented, prefabrication can reduce installation labor costs, while reducing congestion at the construction site and allowing for more efficient component assembly.

Consider the Connection

Consider flange and mechanical-groove connections, as end-connection is an important factor when determining the optimal system designs. Unlike flanged valves, grooved-end valves can be assembled onto pipe spools under the controlled conditions of a fabrication shop, drastically minimizing joints made in the field, reducing labor costs and time in both the shop and field. The manner in which a flanged joint holds a seal is sensitive, particularly in transport, where damage can often occur. On a grooved-end valve, the seal is on the outside of the pipe and the mechanical coupling carries the load, mitigating concerns about weakening the seal during transportation.

In transport, pipe spools designed with mechanical-groove valves can be kept in one plane-what’s known as two-dimensional fabrication, and segments can be rotated into their 3D position on site. 2D spools may include a linear length of pipe, valves and fittings all connected in a flat pack type of configuration. This makes the spools easy to load and enables an increase in the linear footage of pipe on a truck (Figure 2). In fact, it’s possible to load up to three times more 2D spools than 3D spools on a single truck. This makes transportation more efficient, minimizing trips to and congestion at the construction site, resulting in reduced shipping and jobsite handling costs.

Systems designed with grooved-end valves generate time savings and other benefits in the fabrication shop as well as the field.

Systems designed with grooved-end valves generate time savings and other benefits in the fabrication shop as well as the field. In the ideal shop environment, fabrication and assembly of grooved pipe spools, including valves, has been shown to increase total shop throughput to 48 diameter inches or more per hour.

Once at the job site, the benefits offered by mechanical-grooved valves over flanged valves in prefabricated pipe segments become obvious. One painful example stands out: hoisting a pipe spool off a truck that includes a flanged valve creates stress and stretches the flange hardware, calling into question the integrity of the joint. By contrast, pipe spools featuring grooved mechanical valves can be lifted with confidence, because the stress is carried across the ductile iron body of the mechanical coupling and not on the hardware itself.

Reducing Risks and Associated Costs

Costs of installation and maintenance are other notable risks to consider when designing a flow control strategy. Grooved-end valves provide added benefits considering the speed and ease of which they can be installed and maintained. Mechanical-groove valves also eliminate the need for unions or other access points, reducing the total number of joints necessary to build and maintain the system, minimizing the system footprint and total installed cost.

Another recent innovation in grooved-mechanical valve design integrates pipe joining capabilities into the body of the valve itself. A knife gate valve has been introduced that provides, not grooved-end pipe connections, but mechanical couplings integrated into the body of the valve itself. This new design delivers a solution that reduces the number of components and install-time, delivering increased efficiency in the field and new prefabrication opportunities.

Prevailing technology requires that large knife gate valves be removed from service in order to be maintained or rebuilt, requiring riggers, electricians, and mechanical contractors working together to complete the often challenging task. An alternative maintenance method has also emerged that removes these risks and delivers a predictable maintenance cost, allowing all of the serviceable components of the valve; knife, packing gland, retaining plate, knife seal, seat and seat gasket, to be replaced as one pre-assembled seat cartridge. Innovations like these are changing the landscape and setting higher expectations within the construction industry.

Breaking with Tradition

Despite the availability of emerging technologies and the clear benefits they offer, less than optimal design solutions continue to be specified. Owners, engineers and contractors should consider a few more facts that add weight to the evidence favoring grooved flow control solutions over flanged.

Victaulic, a leader in pipe joining and flow control, offers grooved end valves that weigh one-third less than its comparable flanged valves. The grooved solution also provides a greater pressure safety factor and the weight difference makes it easier to handle and install – adding to the space and weight savings are gains in speed that come from installing a grooved valve versus a flange valve.

Ultimately, offering a higher ROI is the greatest market disruptor. Even in projects as massive as power generation facilities, choosing the right valves from the beginning matters. Like the right tools on a belt, the right pipe joining and valve solutions can simplify installation and maintenance scenarios, reduce constructions schedules and improve the ROI of a project by diminishing downtime and profit loss.

Hawaii plays a critical role in America’s self-defense and military readiness, and the island of O’ahu houses installations for the Army, Air Force, Navy, Marine Corps, and Coast Guard. Nestled between two mountain ranges, O’ahu’s central valley provides natural cover and centralized locality for the U.S. Army Garrison-Hawaii, whose mission includes “enabling readiness for a globally-responsive Army.” Military readiness requires a stable electricity grid, and Hawaii’s isolated location in the Pacific Ocean presents unique fuel supply and grid vulnerability challenges. In addition, Hawaii and the Department of Defense (DOD) are each pursuing ambitious renewable energy goals, so new generation projects on the island must support renewable energy targets alongside reliability, security, and economic drivers.

Located on the Schofield Barracks Army installation, the Schofield Generating Station is a collaboration between the U.S. Army and Hawaiian Electric Company. Photo courtesy: Burns & McDonnell

The Schofield Generating Station is a perfect example. Located on the Schofield Barracks Army installation, the 50-megawatt (MW) multi-fuel reciprocating engine plant is a collaboration between the Army and Hawaiian Electric Company. Upon completion in Spring 2018, the facility will enhance the flexibility, reliability, and security of the electric grid while advancing each party’s renewable energy goals through the use of biodiesel. The new generating station’s flexible technology also enhances the utility’s ability to integrate wind and PV onto the grid, thus serving as a renewable energy force multiplier.

The DOD is one of the largest energy consumers in the world, and the military installations in Hawaii are collectively the largest customers served by Hawaiian Electric. So when the Army Garrison requested improved energy security and increased renewable energy production on its installations, the utility desired a solution to satisfy its largest customer while also benefitting the rest of O’ahu. “Our primary goal was to provide reliable, renewable, and resilient power to the Army and all of our customers,” said Jack Shriver, Manager of Generation Project Development, “but there were several variables that impacted the design. We needed a location away from our vulnerable coastline, operational flexibility, fuel flexibility, black start capability, and obviously the permitting and economics had to work. It was an interesting challenge.”

The task for Hawaiian Electric involved developing a facility that addressed a diverse set of drivers:

• Energy Reliability. All existing generating stations on O’ahu are located on or near the coast, which means they may be vulnerable to coastal effects such as hurricanes and tsunami. Hawaiian Electric was seeking an inland location to mitigate those risks. Fuel flexibility was also a concern because O’ahu imports all of its fuel except for biofuel. It was important to build a facility that could switch fuels when necessary due to availability or cost.
• Energy Security. In addition to the inland location, the team desired a site within the boundaries of an Army installation to maximize physical security. The lease for the site required that the generating station provide power directly to the Army under certain mission critical conditions. Finally, it was decided that the new facility should not only be black start capable itself, but that it should serve as a source of black start power to other generating stations in the event of an island-wide outage.
• Renewable Energy Integration. The parties required a plant that could burn biodiesel fuel while exhibiting the operational flexibility to support a dynamically evolving grid. Hawaii’s best local energy resources are its sunshine and trade winds, and Hawaiian Electric plans to supply 100 percent of its electricity from renewable sources by 2045. Because these sources are intermittent, a new generating station must be able to support fluctuations in renewable supply through fast start and high ramp rate capabilities.

The Schofield Generating Station meets these goals and more. The plant will be owned and operated by Hawaiian Electric, connecting to the existing Wahiawa substation via a 46 kV transmission line included in the project scope. The plant is located on eight acres of land leased from the Army at Schofield Barracks, an installation that provides housing and services to the U.S. Army Garrison-Hawaii. Because the site is within the Army boundary approximately eight miles from the coast, it is invulnerable to coastal events and maximizes physical security.

During an emergency, the plant can provide a dedicated feed up to 32 MW to support critical facilities at Schofield Barracks, Wahiawa General Hospital, and Wheeler Army Airfield. The remainder of the generating station’s capacity can be used to restore critical infrastructure in the local community or to black start other units.

The plant includes six Wärtsilä 20V34DF reciprocating internal combustion engine (RICE) generators for a total net output of approximately 50 MW. These heavy-duty, medium speed engines can operate on natural gas or liquid fuels. The plant is designed and permitted to operate on both biodiesel and ultra-low sulfur diesel, but design considerations were included to accommodate potential installation of liquefied natural gas (LNG) infrastructure in the future. “We first looked for any technology that could solve the reliability equation. Then we looked at the technical details like start time, ramp rate, and fuel flexibility,” Shriver said. “Finally, when we factored in the heat rate and multi-shaft reliability, these engines were by far the best option for this application.”

The plant is expected to operate as a peaking unit that can quickly respond to changes in load or renewable energy supply. RICE generators can achieve start times under ten minutes to reach full power, with optimal heat rates and ramp rates when compared to other peaking technologies. Plus, the output and heat rate curves are essentially flat over the expected ambient temperature range, so the effects of hot, humid weather are negligible.

The plant will advance multiple renewable goals both directly and indirectly. First, the plant will run on at least 50 percent biofuel. Biodiesel operation directly enables Hawaiian Electric’s pursuit of 100 percent renewable energy by 2045, and Hawaiian Electric is already experienced with sourcing the fuel for other generators. The use of biodiesel also supports the Army’s goal to generate 1 gigawatt (GW) of renewable energy on its installations by 2025.

These same renewable energy goals are also indirectly supported by the Schofield plant because the fast start and flexible operation characteristics will allow for a higher penetration of renewables on the existing grid. Due to the impacts of high solar penetration and cost-effective energy efficiency projects, Hawaii’s load curve looks significantly different today than it did 10 years ago. The peak demand is lower and occurs later, when the sun sets and solar power gives way to traditional firm power generators. “In aggregate, rooftop PV is by far our largest generator on O’ahu during daylight hours,” says Shriver. The RICE technology at Schofield is better suited than the island’s existing generators to accommodate the high ramp rates required to compensate for wind and PV fluctuations. This flexibility will enable continued expansion of renewable technologies.

Upon completion, this plant will be an important energy source for the customers of Hawaiian Electric, and uniquely beneficial for its largest customer, the DOD. “The Army came to us with a specific request, but we worked together to make sure the solution was sustainable in the long term and supported all of our customers,” Shriver said. Hawaii and DOD are consistent early adopters of innovative energy technologies, leading American efforts to provide renewable energy solutions. To keep pace with renewable energy integration, the sustainability of O’ahu’s electric grid demands flexibility, reliability and security. Constructing the Schofield Generating Station is further proof that Hawaiian Electric can meet these needs now and in the future.

Author

Kieran McInerney is a development engineer in Burns & McDonnell’s Energy Division.

There is a trend across the USA to mandate increasing amounts of energy to be derived from renewable resources. Electric utilities in California, for example, are required to have 33 percent of their retail sales derived from eligible renewable energy resources by 2020. It is speculated that this requirement may later increase to 50 percent.

The challenges of integrating major renewable energy resources, such as wind and solar energy, into the electric distribution grid are well-known: intermittency and low predictability, which renders renewable-source generation not dispatchable. In layman’s terms, “they are on when they are on” and cannot be brought on line when called upon to satisfy immediate demand. Inevitably, this makes it difficult to match electric power demand and supply, which is very important for both users and producers of electrical energy. Currently, the solution to maintaining a stable grid with a generation portfolio including renewable technologies is to have fossil fuel-powered backup generation (typically aero-derivative gas turbine peakers or fast-start combined cycles).

Gill Ranch plot plant with compressed gas energy storage (CGES).

A more elegant solution to the supply-demand mismatch is energy storage, which is based on the principle of “time shifting”. In other words, excess energy from renewable generation during times of off-peak demand is stored for later use at times of peak demand when the renewable generation comes up short. Currently available and commercially proven energy storage technologies are pumped hydro and compressed air energy storage (CAES) for large-scale applications (i.e., hundreds of megawatts or even a gigawatt or more) and lithium-ion batteries for much smaller scale uses. Each technology has its advantages and disadvantages, which have been discussed elsewhere.

Conventional CAES technology uses relatively cheap electric power during times of low demand to compress air into a reservoir where it is stored at high pressure. During times of high demand, when the price of electric power is relatively expensive, the stored air is expanded through a gas turbine with additional fuel burn. In other words, more megawatt-hours of energy is generated than stored. In order to improve fuel efficiency, stored air is preheated in a regenerative heat exchanger by using the gas turbine exhaust. Thus, CAES economics rely on the price spread between electricity prices at peak and off-peak demand hours as well as fuel price to make money.

Although two CAES power plants have already been built and successfully operated for decades (one in Huntorf, Germany, and the other in McIntosh, Alabama), the technology has failed to catch on for widespread commercial deployment. One reason is the high initial cost for air-storage reservoir excavation and the unique, custom-design turbomachinery.

Cavern excavation cost can be avoided by utilizing depleted natural gas reservoirs. However, it has not been demonstrated that conventional CAES systems can safely use these ready-made “holes in the ground” to store the compressed air. This can be extremely dangerous since the natural gas left in the reservoir, or gas that may still be seeping into the reservoir from natural sources, could form a flammable mixture.

An alternative solution, which addresses these two concerns, is to utilize an existing and operational natural gas storage facility in a simultaneous capacity for energy storage. This is achieved by inserting a natural gas turbo-expander between the storage reservoir and the natural gas pipeline so that each time natural gas is delivered to the latter, saleable electric power is generated and supplied to the grid.

BASIC IDEA

The CGES concept is based on an analogy to the well-known CAES technology described in the introduction. Northwest Natural Gas Company’s Gill Ranch Storage facility in Madera, California, has two of the major CAES components already in place, namely the compressor train (comprising five units with variable frequency drives (VFD), inter- and after-coolers – basic fin-fan air coolers) and the storage space (depleted natural gas reservoirs). Thus, the present concept simply comprises the addition of a turbo-expander train to transfer the existing natural gas storage facility into a CGES power plant. The resulting power plant is analogous to CAES with the main difference being the storage medium (i.e., natural gas instead of air).

The heart of the CGES concept is a turbo-expander with gas heaters. A two-stage turbo-expander (TE1 and TE2) with a preheater (PH) and reheater (RH) generates power by expanding the gas from the reservoir to the entrance of triethylene glycol (TEG) dehydration unit. The variation between different implementation options is in the manner of gas heating and the temperature to which it is heated. The primary reason for gas heating is to prevent the formation of liquids within the expander. The natural gas from the reservoir is at 2,500± psia and approximately 100°F. If the expansion from the storage to the pipeline pressure (around 900± psia) were done without any preheating, gas temperature at the end of the expansion would be -18°F (very common in refrigeration plants); not desirable in this case due to liquid water and hydrate formation. An additional benefit of gas preheating upstream of each turbo-expander stage is increased power output due to increased availability. Without any preheating, the turbo-expander would generate about 8 MWe (320 MMSCFD gas flow); with preheating to 200°F at each stage, the power generation is about 11 MW with about 130°F at the end of the expansion.

There are essentially three ways to preheat and reheat natural gas during the expansion process:

1. Stored energy (adiabatic – no fuel burned, no emissions)
2. Waste heat from a process source or a prime mover exhaust
3. Fired heat exchanger (essentially, a furnace with a heater coil – what is shown in Figure 1)

Adiabatic CGES – Option 1

Adiabatic CGES is the “green” option; no gas is burned to accomplish preheating during expansion (i.e., zero emissions). The source for heating is the energy from compressor inter- and after-coolers. Since compression and expansion take place at different points in time, the energy from the former is stored in a thermal storage system (TSS) for use during the latter. In particular,

1. Heat energy recovered from the hot gas in compressor gas coolers is transferred to a storage medium and sent to a storage tank (“hot” tank).
2. When needed, heat energy from the “hot” tank in the form of the storage medium is sent to turbo-expander gas heaters to heat the natural gas.
3. Depleted (energetically, that is) storage medium from the gas heaters is sent to another storage tank (“cold” tank).
4. The charge-discharge loop is completed when the storage medium from the “cold” tank is sent to the gas coolers during compression.

The key design question in Option 1 is the selection of storage medium. There are three possibilities:

1. Molten salt (e.g., mixture of near-eutectic sodium nitrate (NaNO3) and potassium nitrate (KNO3) in 60/40 (% weight) ratio)
2. Heat transfer fluid (HTF) such as Therminol
3. Water

Natural gas temperatures during compression and expansion (between 100°F and ~300°F) preclude the molten salt option due to its high freezing point ~425°F. Furthermore, the same temperature range (100-300°F) makes water at relatively low pressures (100 to 150 psia) a suitable storage medium vis-à -vis HTFs.

The system is described in Figure 2. During compression/storage (charge) phase, original fin-fan gas-to-air coolers (IC and AC) are bypassed. Heat from the compressed gas is transferred to water in shell-and-tube heat exchangers, S-T IC and S-T AC. Heated water is sent to the “hot” storage tank.

“Cold” water for S-T IC and S-T AC comes from the “cold” storage tank. However, since the temperature of water in that tank (~145°F) is hotter than the cooling requirement (120°F), it is first cooled to about 90°F in a mechanical-draft wet cooling tower (COOLR). The cooling tower requires make-up water to replenish losses due to blow-down and drift. This might be an issue in a desert environment. Other possibilities exist; e.g., fin-fan coolers that can operate at night to cool the water in the tank or even a heat pipe.

During expansion/discharge phase, hot water from the “hot” storage tank (230-235°F) is sent to expander gas heaters (PH and RH) to heat the natural gas to 200°F. “Cold” water from PH and RH (~145°F when mixed) is piped to the “cold” storage tank.

CGES with Prime Mover – Option 2

Since there is not a source of readily available waste heat (e.g., a chemical process plant) near the Gill Ranch facility, a possible solution is to include a gas-fired prime mover (i.e., a gas turbine or a reciprocating gen-set) with exhaust heat recovery along with the turbo-expander. The system is shown in Figure 3 schematically.

Preheating and reheating (to 200°F) is accomplished by hot water in shell-and-tube heat exchangers (STHX). Circulating water is heated in a separate STHX (WHTR in the diagram) using hot water from the waste heat recovery unit (WHRU) – basically, a combined cycle heat recovery steam generator (HRSG) without evaporator and superheaters.

A prime mover (e.g., an aero-derivative gas turbine (GT) or reciprocating engine gen-set) generates electric power and exhaust heat, which is recovered in the WHRU, which also contains the selective catalytic reduction (SCR) system to reduce NOx and CO in the exhaust gas to regulated levels.

CGES with Line Heaters – Option 3

The third option involves turbo-expander gas preheating and reheating using gas-fired water-bath heat exchangers similar to those already in place to heat the natural gas from the storage reservoir prior to entry to the dehydration unit (see Figure 1 on page 27).

Obviously, from a high-level thermodynamic perspective, Options 2 and 3 are equivalent to each other in functionality; namely, burning natural gas to heat natural gas. The difference lies in the exergetic use of natural gas burned, which in Option 2 is superior to that in Option 3 via generation of electric power. They also suffer from the same drawback: emission of pollutants such as NOx, CO, CO₂ and UHC.

Note that, water-bath heat exchangers are limited in temperature (not much more than 200°F in the water-glycol bath). For higher gas temperature to enable higher turbo-expander output (discussed in detail below), a special-design fired heater with a heat transfer fluid (HTF) replacing water-glycol can be used.

PERFORMANCE METRICS

The following performance metrics are used for the evaluation of the aforementioned CGES options:

Net Power Output – Reservoir Discharge

Net power output during reservoir discharge is arrived at by subtracting the plant auxiliary load from the generator (gross) output of the turbo-expander and prime movers (if present). The generator output is measured at the generator terminals and is inclusive of generator and gearbox losses. The auxiliary losses are:

• Feed and circulation pumps (0.25% of gross output)
• Cooling tower fans
• GT auxiliary (0.5% of GT generator output)
• Turbo-expander auxiliary (0.5% of TE generator output)
• Miscellaneous (0.1% of gross output)
• Transformer (0.5% of gross output)

Primary Energy Efficiency (PEE)

This is the ratio of net plant energy output to the sum of compression energy input (electricity consumed by the motors) and the electric energy equivalent of the fuel consumed (in LHV) in fired line heaters (Option 3) or prime movers (Option 2). In the absence of fuel consumption during generation phase (or if it is ignored), it is also known as the roundtrip efficiency (RTE), which can be considered as a “pure” storage efficiency.

In mathematical terms, PEE is given as (with te and tc as times of expansion and compression, respectively, in hours)

The rationale for Equation 1 is this: The fuel burned in line heaters or prime movers for expander gas preheating and reheating is natural gas, which would otherwise be sent to the pipeline and, ultimately, to a (unknown) power plant for power generation. According to a recent article in Electric Power & Light magazine, average heat rate of gas fired power generation in USA is 8,430 Btu/kWh (HHV). In terms of LHV, this is equal to

h = 3,412/8,430 x 1.109 = 44.9%.

As such, it is a reasonably good representative system efficiency (average) to be used in the denominator of the formula on the right-hand-side of Equation 1.

Fuel Efficiency (FE)

Fuel efficiency is the ratio of the net energy generation to the sum of fuel equivalent of total compression energy consumption during reservoir charge and the fuel consumed (in LHV) in fired line heaters (Option 3) or prime movers (Option 2). The average gas-fired generation efficiency defined above (44.9%) can be used to calculate the fuel equivalent of compression power. In other words, the electric power from the grid to drive the charge compressors is assumed to be generated in a generic gas-fired power plant with an efficiency equal to the average of all gas-fired generators. Thus

CAPEX AND LCOE

Capital expenditure (capex) is the total outlay of money by the plant owner from the moment the NTP (notice to proceed) is signed to the moment the keys to the plant are handed over after all the acceptance and commissioning tests have been successfully performed. Capex calculation approach utilized in this study follows well-known cost estimate and roll-up conventions such as capacity factoring and cost factoring. The cost roll-up used herein for each CGES system option is as follows:

1. Installed Equipment Cost (E + M + L)
   • a. Unit Cost (E)
   • b. Installation Materials (M)
   • c. Installation Labor (L)
2. Total Installed (Direct) Costs
3. Indirect Costs (% of Total Direct)
   • a. Engineering
   • b. Contingency
   • c. Contractor’s Mark-Up
   • d. Owner’s Costs
4. Total Capex (Direct + Indirect)

Equipment unit cost is obtained from direct vendor quotes (e.g., turbo-expander OEM budgetary price quotes), from Thermoflow, Inc.’s PEACE (Plant Engineering And Construction Estimator) software program, which is a companion to Thermoflow’s GT PRO and Thermoflex heat balance software, and industry publications such Gas Turbine World (GTW) 2013 Handbook.

Installed cost factor, CFINST is

and its range is 1.5 to 2.0, i.e., 50% to 100% on top of the bare equipment cost, with a mean/median of 1.75.

If the cost of a plant or a particular piece of equipment is known from a previous job or project (or some other source), it can be used to make an order of magnitude estimate via capacity scaling:

where C0 is the known cost of a known piece of equipment or plant with a representative capacity of Q0 (e.g., MW rating of a power plant) and Q is the capacity of piece of equipment or plant under study. The cost of the latter, C, can thus be referenced to its scaled capacity via the scaling exponent a. The most commonly used exponent is 0.6 from the well-known “six-tenth rule of thumb”. Exponents for different equipment and plant types are available. From the data in Gas Turbine World (GTW) 2013 Handbook, the exponent a is calculated as 0.713 for gas turbine combined cycle power plants.

Capacity scaling method is used to estimate (“order of magnitude”) the capex of CGES options 1 and 2 from the cost estimates in a recent EPRI report on CAES [4]. See the section “CAES Performance-Cost” in the Appendix. Accordingly, the estimated capex for Option 2 (~650 MMSCFD gas flow, 45 MWe net) with a gas turbine or gas engine is ~$1,150/kW (-30% to +50% accuracy). Similarly, the estimated capex for Option 1 is ~$2,000/kW (-30% to +50% accuracy).

A more detailed but still study/budget level (-20% to +40% accuracy) capex roll-up is used in this study. Some key assumptions are as follows:

• Gas turbine, HRSG, major heat exchanger, pump, CEMS, DCS, electrical unit costs are from PEACE; installation costs are also estimated from PEACE results.
• Turbo-expander unit cost is from OEM quote; 25% installation M+L is assumed.
• Line heaters are estimated from capacity scaled invoice prices.
• Piping cost is set to 10% of bare equipment cost. Note that this is a minimum – in some cases, it can be as high as 80%. In fact, an examination of Gill Ranch numbers show that piping was nearly 25% of the total installed cost, which suggests 35-50% of bare equipment cost.
• As a default, CFINST of 1.40 is used (based on PEACE estimates). (Gill Ranch installed cost data suggests close to 2.0.)
• Gas engine installed cost is assumed to be $800/kW
• Engineering is 8% of TIC (Total Installed Equipment Cost – Direct Costs)
• Contractor’s mark-up is 6%

The chart below provides a graphical summary of the capex data.

A Monte Carlo simulation is done using Oracle® Crystal Ball software to gauge the uncertainty in capex estimates. Inputs to the cost roll-up such as equipment costs, installed cost factors, etc. are represented as uniform distribution with minimum and maximum limits, e.g. ±20% for expander cost, piping cost factor 0.10 to 0.35, etc. Based on the M-C simulation results, the capex estimates in this study are considered to have an accuracy of -20% to +40%, with the higher end being more likely. As such, this particular uncertainty band is in accordance with “study” or “budget” estimate classification. Accordingly, a project contingency of 15% is applied to the final roll-up along with 10% for owner’s costs.

Levelized Cost of Electricity (LCOE) is a widely used metric for comparing power plant system alternatives. Traditionally, it combines a power generation system’s ownership costs (capital and operating) and thermal performance (output and efficiency). This metric is useful when comparing power generation alternatives that use similar technologies. The standard formulation of LCOE is the sum of capital, fuel, and operations and maintenance (O&M) costs of plant ownership.

To evaluate CGES options, emissions and power purchased during compression are also included in the mix. One can also add firm capacity and annual energy generation replacement costs to the list (and in pure power generation cases one must). Due to the unique economic drivers for the CGES project, replacement costs are ignored.

Recent information suggests $15/ton is a good value for CO₂ emissions allowance price to use in LCOE calculation. (According to a Bloomberg news article in 2014, California sold 19.5 million carbon allowances at auction for $11.48 each. Futures based on permits that can be used to cover emissions in the same year settled at $12.15 a ton.)

Prices of annual sulfur dioxide (SO₂) and summer seasonal nitrogen oxides (NOx) emissions allowances obtained from the EPA’s Clean Air Interstate Rule (CAIR) and the NOx Budget Trading Program (NBP) are seen to have fallen dramatically in recent years. – i.e., from ~$800/ton in 2008 to about $16/ton by 2011 for NOx. This drop is attributed to several factors such as regulatory changes, environmental control systems such as FGD (Flue Gas Desulfurization) and SCR adopted by coal plants and lower coal-fired power generation.

It is impossible to predict the future trends. Thus, a representative $20/ton value is used herein. The same price is applied to CO emissions as just a “place holder” to quantify it in dollar terms. (As it turned out, whether NOx is $800 or $20 per short ton was rather immaterial.)

The following assumptions are used in the LCOE calculations

Capital charge factor (b) of 15%

• Levelization factor of 1.25
• Fuel price of $4/MMBtu(HHV)
• Capex and performance as described above
• Electricity purchase price of ¢1/kWh (assuming that compression is done during the time of excess capacity and low demand – this can even be a negative number – i.e., one is paid to use electricity!)
• Emissions costs as described above
• O&M costs for GT and gas engine (GE) from Table 1-5 in Ref. [8]
• Option 1 fixed/variable maintenance costs $1/kW and 1 mils/kWh (estimate)
• Option 3 fixed/variable maintenance costs $1/kW and 2 mils/kWh (estimate)
• SCR O&M 1 mils/kWh for GTs, 2 mils/kWh for GEs
• Turbo-expander O&M from the OEM quote

Average annual ambient temperature of 77°F is assumed for the generation runtime (peak hours during the day – especially hot in the summer). A 4% power output lapse is applied to the GT (small rise in heat rate is ignored). Turbo-expander and GE are assumed to be unaffected. This should take care of higher output during much colder times and lower output during much hotter times.

Note that inlet conditioning (e.g., chillers or evaporative coolers) for the GT for hot day power augmentation is not considered. This should be evaluated carefully during the detailed design phase.

PHASE I ANALYSIS

Three CGES options described above have been evaluated in terms of performance, emissions, capex and LCOE.

With the current natural gas compressor station in Gill Ranch and 4 hours of charge operation, natural gas turbo-expander generation entitlement is approximately 15,000 MWh.

From a capex and LCOE perspective, the optimal configuration is with the ratio of compression hours to generation hours of 1.7. Ignoring losses, this is the ratio of compressor inter/after cooling duty to expansion pre/reheat duty, which enables the “green” adiabatic CGES option. Note that, due to its high exhaust temperature/energy, with one gas turbine and WHRU, up to 224 MMSCFD gas can be heated to 200°F so that the lowest LCOE ratio is 1.4.

Adiabatic CGES (with thermal energy storage using hot pressurized water as storage medium) and CGES with line heaters are both rated at ~6.5 MWe at a capex of $2,860/kW and $1,710/kW, respectively. The PEE of the adiabatic CGES option is 41.8% with an LCOE of ~¢23/kWh. In comparison, adiabatic CAES at the same size would cost ~$3,750/kW with a PEE efficiency of 37.5% ($2,600/kW if air compressor and storage construction costs are ignored).

Combining CGES with a prime mover provides significant improvement in terms of performance, capex and LCOE. Emissions impact on LCOE is negligible and emitted quantities are well below permitting thresholds. In particular, with a 45+% efficient, 18 MW gas engine, additional 40,000 MWh generation is possible at a capex of $1,440/kW and LCOE of ~¢16/kWh with a PEE of 36% (cf. around 40% for CAES – adiabatic and ~20% GT plus expander options).

Key findings from the Phase I analysis are summarized in Table 1 on page 30.

Option 1 (adiabatic) was originally picked to minimize impacts from an environmental standpoint and yet provide a safe reliable energy storage project that met the utility requirements. The inherent technical problem associated with this process is the ability to capture and hold the necessary hot water from the heat of compression of the compressors. The time lag from when compressor injection occurred and when stored energy is needed during discharge required very large insulated storage tanks. Also the low temperature differential between the temperature of the compressor energy and the needed gas temperature caused the heat exchangers to be very large and very expensive. This resulted in significantly larger specific cost and LCOE vis-à -vis the other two options and Option 1 was eliminated from further consideration.

Economically, Option 2 with a prime mover and exhaust gas heat recovery was the clear winner. The type of the prime mover, i.e., gas turbine or gas engine, became the decision to be made. Note that the natural gas flow rate from the storage reservoir can be increased up to ~650 MMSCFD.

At 542 MMSCFD, the ratio of compressor inter/after cooling duty to expansion pre/reheat duty is 1.0. Thus, at the beginning of the study, this was determined as the maximum-flow case. Since a single gas engine is not capable of providing the heat necessary for the 542 MMSCFD of gas discharged, this option was not considered due to complexity and large capital costs.

Consequently, Option 3, with the gas turbine and exhaust gas heat recovery, was selected for study in Phase II.

PHASE II ANALYSIS

Two small industrial gas turbines from two different OEMs were selected for this phase, which will be referred to as GT A and GT B. The system in Figure 3 on page 28 was rigorously modeled in Thermoflow Inc.’s heat balance simulation software, Thermoflex. Due to the very high pressure of natural gas, REFPROP (NIST) property model was used in turbo-expander calculations. Gas turbine performance data was directly obtained from the built-in “engine library” in Thermoflex.

Table 2 on page 32 summarizes the CGES cost and performance comparison with the two gas turbines.

Table 2 CGES cost and performance with two different gas turbines with DLE combustors. Note that the capex numbers do not include the re-cylindering cost to reduce energy consumption during reservoir charging.

Gas turbine A is an aero-derivative gas turbine, which is sized to provide the necessary heat to the turbo-expander and produces approximately 21.5 MW, with the turboexpander producing approximately 14.8 MW. Total gross electrical output of the CGES facility utilizing this gas turbine is approximately 36.2 MW.

The exhaust temperature of gas turbine B, also an aero-derivative GT, is not high enough to bring the gas inlet temperature to the turboexpander to the same level as GT A. As a result, the turbo-expander power output is lower. Gas turbine B would produce 18.4MW, with the turboexpander producing approximately 14.3 MW. Total net electrical output utilizing GT B is approximately 32.6 MW. While this gas turbine could support most of the flow conditions, it is smaller and the process is less efficient.

The heart of CGES compression-expansion cycle performance simulation is the turbo-expander model. Due to varying storage reservoir and pipeline pressures, the selected equipment is expected to run in a wide range of operating conditions dictated by upstream and/or downstream pressures. Reservoir pressure is a linear function of the inventory and changes from 1,750 to about 2,500 psig between 35% and 100% full. The operating mechanism of the single-stage turboexpander is described in Figure 6 on page 34.

Note that, originally (as depicted in Figures 1-3), a two-stage turbo-expander with a reheat heat exchanger between the high-pressure (HP) and low-pressure (LP) sections was considered. Cost-performance evaluation indicated that increased complexity and cost were not worth the performance gain so that it was decided to go with a single-stage turbo-expander as shown in Figure 6.

From an operation and performance modeling perspective, a turbo-expander can be considered as an “orifice” in the flow-path of the fluid in question. Thus, the system between the reservoir and the pipeline can be imagined to be a long natural gas pipe with many obstacles along the way, e.g., miscellaneous valves, equipment, pipe joints and tees, etc. along with the turbo-expander (TE) itself.

Pipeline pressure dictates the TE discharge pressure. TE inlet pressure is dictated by the gas flow and the “swallowing capability” of the TE, i.e., the inlet flow area. The reservoir pressure is determined by the gas inventory, which will obviously diminish over time when the expansion process is active.

Consequently, the pressure-flow balance between the reservoir and the TE inlet is established by the flow-control valve. A second degree of freedom is provided by the TE inlet guide vanes (IGV). As shown in Figure 7 on page 34, IGVs act as stator nozzle vanes as well as inlet area adjusters.

The maximum variable inlet guide vane area is 125% of the required area at the design (typically, best efficiency) point. At low inlet pressures, the IGVs are fully open, and the flow is the maximum that will pass through at this fully open position. At high inlet pressures, IGVs are closed to keep the flow at the maximum 542 MMSCFD.

From basic gas-dynamic theory, expander inlet flow-pressure relationship is

where g is the specific heat ratio of the gas, PRexp is expander pressure ratio and Cq is a flow coefficient. For a TE with IGVs, Cq·Ain can be written as

where YIGV is the percent-open position of the IGVs. Thus, using Equations 10 and 11, OEM-provided TE characteristics can be translated into YIGV by assuming that the design point is 80% open and maximum opening is 100%, i.e., equivalent to 100% and 125% open, respectively. Thus, any desired flow-pressure combination for given Pin and Pout (i.e., PRexp), Tin (from the inlet heater) and YIGV can be determined via

Gas mass flow rate from Equation 12 along with Pin and Pres determines the flow control valve opening. Expander efficiency is also determined from OEM-provided data via a curve-fit (see Figure 9 on page 35). Equation 12 and Figure 9 curve-fit are implemented in Thermoflex gas expander module to evaluate the operating envelope of the CGES system, which is shown in Figure 10 on this page.

The CGES system in the photo on page 26 includes the following major equipment:

• High-pressure turboexpander with generator
• Preheater (shell-and-tube heat exchanger)
• Gas turbine with generator.
• Heat recovery steam generator (includes the SCR)

Interconnecting gas lines are run from the existing gas withdrawal process to the turbo-expander preheater, and from the outlet of turbo-expander back into the existing gas withdrawal process downstream of the pressure control valve and upstream of the existing dehydrators and then on to the existing pipeline (no new pipelines exits the site).

Existing utilities for air, water, and sewer in Gill Ranch are adequate to be extended to the CGES component.

One of the site’s redundant transformers is used for the step-up of the new generators’ output to the transmission voltage. Transformer redundancy is maintained as the compressors are not operated at the same time as the turboexpander.

In an effort to further increase the overall efficiency of the storage process, a discretionary investment to re-cylinder all five of the existing compressors is considered. This modification is expected to reduce the compressor load by approximately 22% or 5 MW when utilizing four compressors (one compressor held in reserve) at an additional cost of about $4.5 million. Thus, with the following assumptions

– Charging for 7.5 hours at 320 MMSCFD

– Discharging for ~4.5 hours at 542 MMSCFD based on the performance data in Figure 5 on page 33, a primary energy

efficiency of 42.4% is expected. Note that, in order to facilitate an “apples-to-apples” comparison to a competing storage technology with no fuel-burn, the roundtrip efficiency of the CGES system with re-cylindered compressors is

Turbo-expander Generation = 14,750 x 4.428 = 65,313 kWe

Compressor Consumption = 15,700 x 7.5 = 117,750 kWe

Roundtrip Efficiency = 65,313 / 117,750 = 55.5 percent

CONCLUSION

Gill Ranch is an existing 20 BCF gas storage operation that includes five electric-drive gas compressor units used to compress natural gas for injection into the existing natural gas storage reservoirs. The compressor station receives electricity from an electric power line that runs from PG&E’s Dairyland-Mendota 115 kV transmission line to the substation at the compressor site.

When needed, withdrawal of the gas is extracted from the reservoir at an average flow rate of 542 MMSCFD. During the withdrawal process, gas is heated, pressure is reduced over a set of valves, dehydrated and put in the pipeline at approximately 700 psig.

By incorporating a turboexpander generator train into the expansion part of the cycle, the natural gas storage facility will be transformed into an energy storage facility.

The proposed compressed gas energy storage system will produce electricity upon withdrawal of the high-pressure gas that was previously injected by the electric-drive compressors. The CGES system also includes an aero-derivative gas turbine for a nameplate rating of 35 MWe with a primary energy efficiency of 42.4 percent. Roundtrip efficiency based on turbo-expander only (i.e., excluding gas turbine) is 55.5%.

Noting that Gill Ranch is an active natural gas storage operation, one way to look at the power generation part of the thermal energy storage cycle is as a highly-efficient combined cycle power plant.

This is so because, whether CGES concept is realized or not, compression of gas into the storage reservoir is a given. The efficiency of the GT-TE combined cycle is 58%, which is at the same level as utility-scale F class technology.

Authors:

S. Can Gà¼len, Bechtel Infrastructure & Power Inc.; Sarah S. Adams and Roger M. Haley, Northwest Natural; and Charles Carlton, Project Consultant

BY MICHAEL DUCKER

Owners and developers of gas projects in the Northeast are faced with an increasing need to ensure reliable delivery of energy. As coal plants continue to retire and regions move to an ever-increasing reliance on natural gas, concerns on the dependence of this fuel source have surfaced. As such, new market rules in the PJM and the New England ISO are placing unprecedented value on ensuring reliability in gas turbine products and natural gas fuel delivery.

There are a wide range of fuel-delivery hedging mechanisms, including firm transport, back-up fuel, or even simply taking market risk. Each potential solution offers benefits and risks that need to be carefully weighed, and it’s important for customers to engage in a meaningful dialogue internally and with their OEM about options that exist.

Ultimately, this analysis points to first ensuring that reliable gas turbine products are selected. Thereafter, a hedging strategy for fuel delivery ought to be considered, and this analysis shows strong benefits of choosing a newly emerging business model of on-site LNG to comply with these new market rules.

Background

With an abundance of natural gas at historically low prices, environmental regulations targeting coal, and coal and nuclear plants struggling to remain profitable in competitive power markets, many regions are seeing a dramatic shift towards a greater reliance on natural gas generation. This shift is clear, particularly in the mid-atlantic region of PJM and northeast region of the New England ISO. In 2000, natural gas accounted for just 3% of generation in PJM and 24% of generation in ISO-NE. Today, natural gas comprises more than ¼ of PJM’s energy generation and more than ½ of ISO-NE’s energy generation.

Yet as regions experience a greater reliance on this clean and affordable energy resource, reliability issues have surfaced when delivery of that fuel source is unavailable. Although coal and nuclear plants may have several months to a near endless supply of fuel on-site, if a fuel supply disruption occurs to a natural gas plant, there is typically no natural gas stored on-site to continue operation. Natural gas power plants tend to be an “on demand” generator, meaning when the plant needs to operate then the fuel must be available. When that fuel is not available, and there is no back-up fuel to supply the plant, problems can arise. This was evident during the Polar Vortex in 2014 which saw record low temperatures across most of the U.S. and brought much of the Northeast to a near blackout condition. This grid “near miss” caused PJM and ISO-NE to issue tighter market rules to address reliability.

The Polar Vortex

The 2014 Polar Vortex was the kind of market event that causes a fundamental shift in regulatory oversight. This event became the center of attention for the new market rules in the Northeast due to its disruptive effects on the grid.

During the extremely cold weather of the Polar Vortex natural gas demand for residential heating competed with natural gas demand for power generation. Local distribution companies (LDCs) have a priority for natural gas for utilization within citygates, thus natural gas supplies for power plants are typically secondary and interruptible. The extremely cold weather strained these fuel supplies as natural gas was diverted almost entirely to LDCs, and many natural gas power plants simply could not operate because fuel was unavailable. At the same time the cold weather caused a multitude of other problems for power plants, including frozen stockpiles of coal, ice damage to equipment, combustion-related issues and other problems. What materialized in 2014 was more than 40,000 MW of forced outages, comprising nearly a quarter of PJM’s entire fleet. Nearly half of the outages were due to natural gas plant outages or natural gas fuel interruptions.

With such a large portion of the fleet in a forced outage and 50 percent natural gas-related, PJM moved towards implementing market rule changes to ensure such reliability issues would not occur again.

New Market Rule Overview

In 2014, PJM proposed restructuring their forward capacity market, known as the Reliability Pricing Model (RPM), to include a “Capacity Performance” (CP) component. CP requires generators to provide energy, if scheduled and dispatched by PJM, during Compliance Hours. Compliance Hours take place when PJM declares an emergency procedure event. All generators are obligated to provide their pro-rata share of energy during Compliance Hours. When a generator fails to deliver its pro-rata share of energy during a compliance event it is required to pay a Performance Payment. Performance Payments are collected as penalties from underperforming generators and delivered as bonuses to over-performing generators. Generators performing at their expected output can also earn a percentage of these bonuses, approximately 15 percent of their total capacity.

The performance payment is based on the generator’s committed output and is a function of the cost of new entry and PJM’s expected Compliance Hours.

When PJM promulgated its rule it estimated approximately 30 Compliance Hours per year, setting this baseline to calculate the performance payment. This number is currently under contention amongst PJM stakeholders because – aside from the Polar Vortex of 2014 – a historical look at trigger events yields only an annual average of 10-15 Compliance Hours. That would make the current PJM performance payment rate seemingly “too low.” For now the PJM’s projected annual 30 Compliance Hours sets the performance payment at approximately $3,400/MWh.

The performance payment means generators are exposed to a $3,400/MWh penalty or bonus during compliance events. To put it into perspective, if a combined cycle with 1,000 MW of output committed suffers a forced outage, and during the outage PJM declares a four-hour compliance event, this unit would face a penalty of $13.6 million. This is in addition to other losses the plant will incur, such as buying replacement power at real-time market prices, deviation charges assessed by PJM for not following day-ahead dispatch signals, and a higher assessed forced outage rating which will affect future capacity market payments. By any business standards, the performance payment represents a very severe penalty for a generator undergoing a four hour forced outage.

As such, the CP market rules mandate power producers focus on the reliability of gas turbine products and fuel deliverability. Failing to do so could have a crushing impact on profits.

Overview of Fuel Delivery Hedging Solutions

Mitsubishi Hitachi Power Systems (MHPS) conducted an analysis of four different hedging solutions: firm transport, fuel oil back-up, on-site LNG back-up and market risk. The analysis provides Northeast plant owners with an overview of each solution. While each solution will appeal to different plant owners for different reasons, we believe some options hold greater promise as hedging tools for most plant owners.

Firm Transportation

One of the biggest contributors to supply issues experienced during the Polar Vortex was interruptible service contracts for existing gas-fired power plants. In order to maintain competiveness in the markets, most existing gas-fired plants utilize interruptible service contracts which avoid costly reservation charges. Since peak demand for gas-fired generation typically occurs in the summer – when residential demand, local distribution companies and other firm transport holders are at their minimum usage – the need to pay a premium for firm transportation was not justified in most cases.

Moving forward, some market segments may consider firm transport and paying fixed reservation charges to guarantee the delivery of gas to the site. This is especially evident in the baseloaded, high efficiency NGCCs being developed today. By undertaking a firm transport service contract, gas-fired generators will alleviate the risks of having a fuel supply interruption during a critical grid event. This is a viable hedging strategy to avoid CP penalties.

The cost of firm transport contracts will vary greatly within regions, contracting entities, end-use customer needs, etc. While the viability and costs can differ significantly, there is public information on these reservation charges. From publically available sources, recent reservation charges have ranged from $0.30/MMBtu more than $1.00/MMBtu. We chose a lower of the average of $0.50/MMBtu for analysis purposes.

Fuel Oil

Fuel oil has been the defacto “back-up” fuel for most plants. Although not the most desirable back-up fuel, it has historically been the most cost effective. When discussing fuel oil with plant operators, there is often a litany of potential issues identified with this solution:

• Fouling of equipment
• O&M adders assessed by GT OEMs for utilizing the fuel source
• Reliability issues when running or starting on fuel oil
• A large majority of PJM issues during the Polar Vortex occurred with plants failing to start or switchover to fuel oil
• Even if a plant is backed with fuel oil, the fuel has a proven negative reliability record
• Emissions issues
• Local opposition to fuel oil operation
• Additional water usage during operation
• Maintenance of fuel oil storage tanks
• Turnover of tanks
• Quarterly/periodic testing requirements
• Fuel oil pricing spikes during cold weather events (in some cases cannot refill until end of winter)
• Spills/environmental concerns due to clogged lines

While many plant owners are considering adding fuel oil to new or existing gas-fired plants as a CP hedge, many express less than favorable interest in using fuel oil for the aforementioned reasons.

Still, when comparing fuel oil to firm transport cost, or other site conditions that necessitate a back-up fuel, it can be a cost effective option. For purposes of this analysis, we are assuming a 550 MW plant, greenfield site, with a 3-day fuel oil storage tank solution. We have assumed no duct firing and no derate on oil operation, which would net an initial capital cost of more than $26 million to go with fuel oil as the plant back-up fuel. See Table 1 on page 20 for fuel oil cost assumptions.

On-site LNG

On-site LNG often receives less consideration as a back-up fuel option. Historically, LNG has been an expensive commodity. Building the infrastructure to utilize it as an on-site back-up fuel added additional capital costs and permitting issues, while only achieving a moderate amount of back-up time before supplies would be depleted.

However, as owners look towards hedging CP compliance – which are likely short duration events – the notion of

on-site LNG as a back-up fuel immediately gains more credibility. Moreover, new companies are emerging offering full on-site LNG packaged solutions, including options such as a fixed long-term contract with a yearly demand fee, that includes the LNG provider handling the initial capital costs, construction, permitting and long-term O&M. These agreements can include guaranteed fuel delivery periods within PJM and ISO-NE, guarantee refill on grid “disaster days,” and fixed fuel costs. This is an attractive option for developers looking to reduce upfront capital costs, while still hedging for CP uncertainties.

Other benefits of on-site LNG include:

• Utilizing the primary fuel that gas turbines were designed for
• Emissions are the same as the site permit on pipeline natural gas
• Better emissions than fuel oil
• No GT/HRSG O&M impacts
• Less water usage
• Minimal footprint impact, including retrofitting this solution on existing plants

Two ancillary benefits worth stressing on the use of on-site LNG include:

1. The ability to blend LNG with pipeline gas to boost pressures in the event of a gas pipeline/gas compressor pressure anomaly, avoiding a costly gas turbine trip.
2. Compared to fuel oil as a back-up fuel, on-site LNG enables the plant owner to fully utilize their duct-fired capacity (if installed), thus maximizing bonus capabilities while minimizing risk exposure during CP events.

For purposes of this analysis, we are assuming a 550 MW plant, greenfield site, with a 32 hour storage tank solution (~100,000 decatherms). No duct firing is considered. This option results in a $2.1 million yearly cost for CP back-up. See Table 2 on page 21 for on-site LNG assumptions.

Fuel Delivery Risk

Owners certainly have the option of simply taking the market risk that fuel will be available when needed. PJM historical compliance events – with the exception of 2014 – all occurred in the summer months. Thus, some owners can certainly justify a limited risk of fuel interruption during summer months when competing needs for gas are minimal.

Of course if there is never a fuel interruption during a compliance event, this will be the cheapest option. But it also comes with the greatest potential risk. A single interruption during a compliance event could eradicate any savings from another solution.

Other Products

There is a growing interest in the insurance community to offer products to protect against CP events. However, as with any insurance product, there are vast amounts of coverages that can be pursued as well as a wide range of premiums for the same products at different end-users. For that reason, and due to the limited information on these emerging products, these options were not included as part of our analysis.

Solution Analysis

For this analysis, MHPS based its review on an owner building a greenfield JAC combined cycle power plant. The

MHPS JAC turbine was recently launched and is the world’s most efficient gas turbine at over 63 percent efficiency. For competitive power markets like PJM and ISO-NE, the need to be efficient – even in a low cost gas environment – is critical in order to dispatch ahead of other units and increase operating hours. The MHPS JAC is a good proxy for the types of units that will be built in the future in these markets reflecting the move towards advanced class, high efficiency gas turbines. The key performance specifications of the JAC combined cycle utilized in this analysis are listed in Table 3 on page 21.

In compiling key market assumptions for the fuel-hedging analysis, four scenarios were specifically chosen for several reasons. (1) historically, total compliance events have averaged ~10 hours per year with the exception of 2014; (2) compliance events have typically been in the summer when fuel is available and interruptions are less likely; (3) the maximum single duration event occurred during the Polar Vortex in 2014 and we believe this would be representative of a “worst case” single loss of fuel contingency event. The key assumptions for this analysis is outlined in Table 4 on page 22.

The results in Figure 3 on page 22 illustrate the total cost in net present value for the four solutions. A NPV analysis is necessary since some solutions require upfront capital costs while others require ongoing yearly fees. To provide a true comparison, a simple yearly review of costs would not be accurate.

In reviewing the results, with the exception of once case, the on-site LNG solution results in the lowest cost option of all four solutions. It represents nearly half the cost of the fuel oil option and one sixth the cost of firm transport. Although the storage limits back-up fuel available to 32 hours, it would seem for CP applications that this amount of storage is very reasonable and would even hedge against a “worst case” Polar Vortex-type of event. Moreover, it comes with ancillary benefits without additional environmental, maintenance, or reliability concerns.

Sensitivity

As a final review of the options, it is prudent to consider under what conditions firm transport or fuel oil will be the most economical solution. Figure 4 on page 24 shows a sensitivity study of the total cost of the firm transport solution under varying reservation fees and the sensitivity of the total cost of fuel oil under varying initial capital costs. Holding the other assumptions constant, firm transport becomes an economically viable solution when reservation fees are in the range of $0.10-0.15/MMBtu. Meanwhile, fuel oil becomes economically viable – assuming a scenario of a 4 hour/year event – when initial capital costs are <$15M.

As for the viability of these scenarios occurring, for firm transport it will be contingent on owners leveraging conditions that enable firm transport costs at such levels. For fuel oil, the scenario of <$15M initial capital cost could certainly materialize if an existing site already has fuel oil storage.

Some brownfield sites have tanks or a new site may be in close enough proximity to other projects that have fuel oil storage on-site. Under these conditions, initial capital costs would be minimal and likely would be <$15M thus making fuel oil an economically viable solution.

Conclusions

As a first line of defense against potential CP issues, owners and developers of gas projects in the Northeast must select reliable gas turbine products. Using the most reliable gas turbine products will help power producers reap the benefits of bonuses during contingency events and mitigate major losses due to forced outages. The reliable delivery of fuel to the site is a critical factor and, if fuel cannot be delivered, owners and developers must consider a wide range of hedging mechanisms.

This analysis seems to make it clear that on-site LNG is an economically viable solution in the context of new market rules in PJM and ISO-NE. Given the short-term nature of these events, but critical need to be hedged, on-site LNG appears to have strong merit. Further, the minimal impacts this solution has on emissions, O&M costs and plant integration, along with the ancillary benefits LNG provides in the event of pipeline/gas compressor pressure fluctuations, make it a very attractive solution.

The emphasis on Capacity Performance is likely to increase and there is a potential for the rules to expand into other regions as natural gas becomes a primary feedstock for power generation throughout the United States. Energy producers need strategies to be fully hedged through a combination of reliable gas turbine equipment and selecting a back-up fuel solution that best meets their needs.

Author: Michael Ducker is the director of Market Analysis at Mitsubishi Hitachi Power Systems Americas based in Orlando, FL.

BY JASON ROWELL AND INDRAJIT JASWAL

Combined cycle plants, even those built with state-of-the-art technologies at the time of commissioning, drop in dispatch order with age. Aging plants suffer the adverse effects of performance degradation and are surpassed by newer plants utilizing the latest technologies. These plants can recover performance lost to degradation and, in many cases, even surpass their original plant performance through major upgrades to their installed equipment. Gas turbine performance upgrade packages are available for most common models, and their use is one of the best means of breathing new life into an aging plant.

Gas turbine upgrade packages are available to address equipment robustness, output, heat rate, fuel and operating flexibility, or any combination of these factors. For some plants, the impact on steam cycle equipment may be negligible, and the plant can fully realize the advertised performance improvements. For many plants, however, the impact on steam cycle equipment is significant enough to limit actual performance gains. In rare cases, upgrades can even result in worse overall plant performance. An extreme example of this is unaddressed plant steam cycle limitations that prevent the upgraded gas turbine from reaching baseload.

Plant operators should consider a number of equipment and critical system evaluations prior to implementing a gas turbine performance upgrade to better ensure the end result. This pre-upgrade evaluation will allow the operator to not only avoid preventable pitfalls but also realize potentially beneficial concurrent upgrades to other systems.

Gas turbine upgrade performance impacts

The two most important combined cycle plant performance variables are electrical output and heat rate. Electrical output is the electricity generated and exported to the end users. Heat rate is a measure of the efficiency of the plant at the generating electrical output. Heat rate is defined as the energy (i.e., fuel) required to generate one kilowatt-hour of electrical output.

Gas turbines contribute to combined cycle plant performance through the following four separate variables:

• Electrical output.
• Heat rate.
• Exhaust flow.
• Exhaust temperature.

Improvements to gas turbine electrical output and heat rate directly translate into improvements in combined cycle performance, but these variables cannot be changed without impacting gas turbine exhaust flow and exhaust temperature.

Many times gas turbine exhaust flow and exhaust temperature are combined into a single variable known as gas turbine exhaust energy. When installed in an open cycle (i.e., simple cycle) configuration, gas turbine exhaust energy is merely wasted to the atmosphere via the stack; however, when installed in a combined cycle configuration, gas turbine exhaust energy may contribute more than one-third of the total plant electrical output. In a combined cycle configuration, exhaust energy is recovered in the heat recovery steam generator (HRSG) to produce steam, which is then converted to electrical output through the use of one or more steam turbine generators.

Most performance upgrades meant to improve gas turbine output and heat rate also impact the gas turbine exhaust energy available to generate power; these include compressor upgrades to increase airflow through the turbine (and subsequently the exhaust flow into the HRSG), increasing gas turbine firing temperature (and subsequently the exhaust temperature in the HRSG) or installing more efficient components (which may lower available exhaust energy). Each of these upgrades directly impacts the steam cycle performance and thus the overall plant performance, equipment and system design margins.

Older combined cycle power plants can regain SSperformance lost to degradation and, in some cases, exceed the results they were originally built to achieve. Photo courtesy: Siemens

Plant system and Equipment considerations

Heat Recovery Steam Generator Gas Side Impacts

Significant change to the HRSG gas side temperatures in the reheater, superheater, evaporator and economizer areas can occur when exhaust energy increases from the gas turbine upgrades. Typically the materials used in the HRSG can accommodate such temperature changes, but adverse effects such as increased tube and baffle vibration, tube and fin erosion, expansion joint damage and excessive hot spots may result from the upgrade. It should be noted that gas side temperature redistribution can also negatively affect HRSG carbon monoxide catalyst and selective catalytic reduction system operation.

Higher exhaust stack flow rates may exceed the combined cycle plant’s air permit emissions limits. Additionally, the higher flow rates leaving the HRSG stack could increase the noise levels, although substantial increases that would require plant modifications (e.g., stack silencers) are unlikely.

HRSG Steam Cycle Operability and Safety Valves

Increased steam flow rates resulting from higher gas turbine exhaust energy reduce the holding time of the HRSG drums, which thereby reduces the HRSGs (i.e., drum level control) ability to operate through transient events. This reduction in holding times should be evaluated to ensure that the drum levels and pressure excursions can be adequately managed by the existing hardware.

Reduced operating margins may cause safety valves to lift or simmer during plant transients such as a steam turbine trip or runback event. HRSG drum, superheater and reheater safety valve capacities should be verified for adequacy if steam flow rates increase.

Steam Turbine

The steam turbine governs the performance of the overall steam cycle. Steam turbines are volumetric flow limited machines. The volumetric flow capability of the steam turbine, known as the swallowing capacity, sets the steam cycle operating pressure for a given steam mass flow rate. As the steam mass flow rate increases, the steam cycle pressure must increase to allow the steam turbine to swallow more steam.

Combined cycle plants are generally designed so that the maximum steam cycle operating pressure is equivalent to the steam turbine maximum allowable operating pressure (i.e., rated pressure). Steam turbine manufacturers allow their units to operate above the maximum allowable operating pressure only for short durations.

If the steam flow increase is beyond the rated swallowing capacity of the steam turbine, the steam turbine must either be bypassed or the turbine steam blade path must be modified to increase the swallowing capacity and maintain the operating pressure below allowable limits. It should be noted that a continuous partial steam turbine bypass will result in a significant plant heat rate impact and increased bypass valve maintenance. Some plants have chosen to part load the gas turbines to avoid exceeding the steam cycle design limits, but this tends to defeat the purpose of the gas turbine upgrade.

Although the pressure can be maintained at the steam turbine inlet by implementing any of these modifications, higher steam flows will result in higher operating pressures in the HRSG, condensate, feedwater and steam systems.

The M501J Gas Turbine. Photo courtesy: Grand River Energy Center

Condensate, Feedwater and Steam Systems

The higher gas turbine exhaust energy yielded by many gas turbine upgrades increases the HRSG evaporator steaming rates and the heat absorption in the superheater and reheater sections. This produces an elevated demand on the boiler feedwater and condensate systems because an equivalent amount of water must be supplied to the HRSG drums and attemperators. The pumps and control valves are the most impacted components in these systems.

The condensate and boiler feed pumps are typically designed with no more than 5 percent to 10 percent margin on either flow or pressure. Any margins beyond this are unwarranted for plants designed using modern analytical tools because large margins will result in excessive pressure drops across the HRSG drum level control valves. In some cases, the condensate and boiler feed pumps may require larger impellers and potentially larger motors to accommodate the increased flow and pressure requirements.

Increased water flow can reduce pump net positive suction head available (NPSHA) margins during transient events. Low NPSHA can cause elevated vibration, increased maintenance and equipment failure. Low NPSHA can be addressed by optimizing storage tank (i.e., hotwell or drum) water levels or be addressed directly through various pump modifications.

The drum level, gland steam condenser bypass and attemperator control valves may require modifications to increase their trim flow coefficients (Cv). Control valve manufacturers typically recommend a minimum pressure drop across the valve for best performance, but this may not be possible under the uprated conditions. The original manufacturer should be consulted for available valve trim replacement options to restore the loss of control valve authority. In some circumstances, a control valve body may be too small to allow a larger trim to be installed, and a valve replacement may be the most economical option.

Steam turbine generator bypass valve capacities and operating speed verification are critical to ensure that the valves are suitable for the uprated plant requirements. Valve operating speeds may need to be upgraded to prevent safety valve popping during large transients.

Heat Rejection Systems

Increased steam generation increases condenser heat duty and, likely, steam turbine back pressure. Rupture disk capacities may need to be upgraded because of the higher steam flow into the condenser. Although condensers are typically designed to accommodate the higher heat duty and steam flow of steam turbine bypass operation, the ability of the condenser to operate properly with the higher steam turbine exhaust flow and under the steam turbine bypassed conditions should be verified by the condenser manufacturer. Potential issues include condenser internals erosion caused by higher velocities, tube flutter and vibration; decreased deaerating capability; and transient issues with hotwell level control.Downstream heat rejection equipment, such as cooling towers and once-through systems, should be confirmed to operate sufficiently at the higher heat rejection requirements.

It should be noted that higher heat rejection requirements result in increased evaporation and makeup water requirements in plant cooling towers. Cooling tower drift losses will rise as evaporation increases and may exceed the plant’s emission limits. Cooling tower performance and fill replacement options should be investigated with the original equipment manufacturer (OEM) to ensure reliable cooling tower performance.

Generators and Electrical Systems

Gas turbine generators and associated generator step-up transformers are normally provided margins to accommodate future performance uprates, but steam turbines and their associated electrical equipment are not. The capacity of the gas and steam turbine generators and the downstream power evacuation equipment and transformers should be confirmed for the higher generation capacity. In the event this equipment is found to be undersized, an adjustment to the operating power factor may be considered. When this option is not sufficient, the OEM should be consulted for potential re-ratings to the equipment.

Where Upgrades Make Sense

Gas turbine upgrades are most easily accommodated in plants where gas turbine performance is supplemented so that the steam cycle is oversized compared to the base gas turbine capability. Supplemental performance may be gained through gas turbine inlet conditioning or supplemental duct firing in the HRSG. For such installations, the maximum steam cycle operating pressure is likely set by an operating case with the gas turbine performance supplemented. The installation of a gas turbine upgrade allows for offsetting this supplemental output with improved performance from the gas turbine.

For installations without any means of gas turbine supplemental performance, the steam turbine will likely be the limiting component. Steam cycle limitation may prevent the owner from realizing the full gas turbine uprate potential without first implementing steam cycle upgrades.

Conclusions

Gas turbine uprates can recover performance lost to degradation and, in many cases, even result in surpassing the original plant performance. Plants that were originally designed with supplemental duct firing are the best candidates for gas turbine uprates, because the duct firing can be offset by the improved gas turbine performance. Even in these plants, however, the cycle must be evaluated to confirm the gas turbine uprate is not limited by the steam cycle. Plants without duct firing may still be candidates for substantial gas turbine uprates, but they need to be evaluated on a case-by-case basis.

A screening-level evaluation completed prior to committing to a gas turbine upgrade can quickly assess the feasibility, total plant cost and schedule requirements to complete this major project. Thoroughly assessing potential impacts identified in the screening study will mitigate the risk of a gas turbine upgrade yielding disappointing performance or operability on an overall plant level.

Authors

Jason Rowell is associate vice president and Gas Power Technologies manager at Black & Veatch. Indrajit Jaswal is a thermal performance engineer at Black & Veatch.

Much has been made about President Trump’s June 1 decision to back the United States out of the Paris climate change agreement. While the overriding objective of the Paris agreement – to limit global average temperatures to well below 2°C above pre-industrial levels – is certainly friendly to the nuclear power industry, I’m not convinced the self-set targets and uncertain enforcement mechanisms would have provided substantial support for the beleaguered U.S. nuclear fleet.

Don’t get me wrong. I would have preferred the United States had stayed in the agreement; I just don’t think the continued commercial viability of Beaver Valley or Three Mile Island or Millstone hinges on a document signed in France in 2015. Survival depends on difficult decisions and actions closer to home and nearer in time. And in a high-stakes game of nuclear-survival poker, the industry in increasingly calling everyone’s bluff.

It’s interesting to review studies addressing the challenges faced by the nuclear power industry. In almost all cases, the recommendations are sound and reflect a thorough understanding of the technological, economic, and political forces at play. Where they fall short – understandably in my opinion – is in their lack of attention to psychological and human factors. Barrage me with all the facts and figures you can muster, but there’s nothing like the fear of loss to focus my attention and compel me to act.

Over the past year or so, the Global Nexus Initiative (a collaboration between the Partnership for Global Security and the Nuclear Energy Institute) has released a number of policy memos highlighting changes needed to ensure nuclear energy can maintain a strong role in combating climate change. The reports identify key findings and recommendations in a number of areas, ranging from the role and responsibility of nuclear in addressing climate challenges, to the impact of nuclear suppliers on geopolitics, to the need for stronger nuclear governance structures and innovative policy constructs that “break the mold” and support nuclear power’s ability to achieve a significant reduction in greenhouse gas emissions. The GNI findings also note that institutional and cultural changes may be required in how the next generation of nuclear power is developed, tested, regulated, deployed and managed.

A June report titled Energy Technology Perspectives 2017 from the International Energy Agency strikes a similar tone, contending that existing government policies are not sufficient to meet climate goals. “Policies to support energy technology innovation at all stages, from research to deployment will be critical to reap energy security, environmental and economic benefits of energy system transformations” and to limit the rise in global temperatures to no more than 2°C. The report calls for clear and consistent policy support that includes nuclear power in clean energy incentive schemes and that encourages its development in addition to other clean forms of energy.

I don’t take issue with the findings from GNI and IEA, particularly over the longer term. My issue is that they sound a lot like what we’ve heard in recent years regarding nuclear power.

This is where the bluff calling comes into play.

The U.S. nuclear industry has seen the renewable energy industry skyrocket over the past decade, capitalizing on technological innovation, economies of scale, hard work, and clean energy policies that provide favorable economic treatment. Coupled with the low price of natural gas, nuclear plant owners in certain markets have swung from highly profitable to significantly unprofitable. Most asset owners were willing to absorb such losses for a few years in anticipation of a market turnaround or climate legislation (or some combination of the two), but the red ink is getting a bit thick for corporate boards and shareholders to continue accepting such a strategy.

The industry is now pushing back. Senior executives from Exelon, FirstEnergy, Dominion, PSEG, and elsewhere have all made comments – and taken actions in some cases – about closing their plants absent policy support recognizing (and compensating) their product for its clean energy attributes and ability to create thousands of jobs.

There have already been some winning hands. New York and Illinois passed legislation granting clean energy status to nuclear-produced electricity, thereby saving some nuclear plants in these states for the time being. Not every hand will be a winner, of course. Earlier this year, Connecticut and Pennsylvania postponed legislation, or diluted legislation, that would have provided economic support to their nuclear plants.

A losing hand, however, does not mean you’re out of the game. As demonstrated in New York and Illinois, it may be necessary to call a bluff multiple times to prompt action.

So ante up…and start studying those poker faces.

The air quality modeling community breathed a collective sigh of relief when a critical U.S. Environmental Protection Agency’s (EPA) modeling guidance finally became effective this year. The Guideline on Air Quality Models: Enhancements to the AERMOD Dispersion Modeling System and Incorporation of Approaches to Address Ozone and Fine Particulate Matter (Guideline) is akin to a user’s manual for determining how large power plants affect air quality. The significant revision to the Guideline, sometimes referred to as Appendix W, has been over a year and a half in the making. It has survived two extensions to the effective date because of a change in administration and numerous public comments. At times, the modeling community wondered if the updates to the Guideline would ever become a reality.

Why are the updates a big deal and what is the purpose of the Guideline? The Clean Air Act regulates emissions, but the Guideline details the modeling procedures and is therefore used by the EPA, state agencies, Native American tribes, and industry to prepare and review permits for new sources of air pollution. The Guideline was initially published in 1978, a year after the Clean Air Act was established, to provide direction on model applications and methodology. Since then, new sections and topics have been incorporated into the Guideline over the years, with the last update occurring back in November 2005.

Since science and technology are always evolving, it was time for a significant update to the Guidance to capture the advances in modeling technology and algorithms, to provide more flexibility for regulatory modeling and to incorporate new analytical techniques. Overall, the Guideline updates provide better guidance, increased clarity, and more certainty for the air quality modeling community and industry.

With better guidance for conducting National Ambient Air Quality Standards (NAAQS) and Prevention of Significant Deterioration (PSD) Increment modeling procedures, there is increased certainty for industry when applying for a permit. Procedures outlined in the Air Quality Analysis Chapter of the outdated 1990 Draft New Source Review Manual (NSR Manual) have led to overly conservative and unrealistic modeling practices. For example, when including neighboring sources in a modeling analysis, each of the neighboring source’s maximum potential to emit emissions are modeled along with the ambient background in the area and then compared to the NAAQS threshold, which leads to overly conservative modeled impacts. The Guideline outlines recommended modeling procedures for using actual emissions for neighboring sources. Modeling emission rates that are in-line with the actual operation for neighboring facilities results in modeled impacts that are realistic and not overly conservative.

The codification of the EPA’s Model Clearinghouse, developed in 1988, into the Guideline delivers increased clarity for the interpretation and approval of modeling guidance, as well as case-specific modeling issues. The Model Clearinghouse process helps resolve regulatory modeling issues and techniques, which streamlines procedures across EPA regional offices and simplifies approvals for the regulatory modeling community. The benefit to industry is that the Model Clearinghouse information is public and accessible in a searchable format to obtain the most up-to-date policy and procedures that can be applied to current projects.

To provide more certainty in modeling procedures, the Guideline stresses the appropriate development and vetting of modeling procedures for projects. The EPA has revised the Air Quality Analysis Checklist, which is essentially a 13-page document outlining important aspects of the air quality analysis – such as preconstruction modeling, which model is appropriate for the type of analysis being performed, and meteorological data. The checklist references EPA policies and guidance. When a project requires air dispersion modeling, it should be noted that a pre-application meeting with the state agency should be arranged and a modeling protocol should be prepared that outlines modeling procedures being used for the project. This streamlines the process so there are no surprises when the air permit application is submitted.

Improvements to the air quality models and methodology is a win for the industry since the air dispersion models will more accurately predict emissions from facilities.

In summary, you should be aware of how the Guideline updates will affect your facility or project and keep in mind that compliance is a moving target.