By Mike Eddington, Mark Osmundsen, Indrajit Jaswal, Jason Rowell, and Brian Reinhart
Cane Run, a 640-MW natural gas combined cycle unit owned and operated by Louisville Gas & Electric, was completed in June 2015 and features two SGT6-5000Fee gas turbines from Siemens, a Siemens SST6 5000 steam turbine and a heat recovery steam generator from Vogt Power International. Photo courtesy: Black & Veatch
In recent years, the term “fast start” has become commonplace in the power generation industry. Specifically, many new combined cycle units being conceptualized or designed incorporate elements of fast start. However, this term can take on many meanings.
Various solutions exist to address specific requirements, depending on what is driving the need for faster startup times. Is the driver reduced emissions, improving plant dispatch, meeting ancillary services or a combination of factors? This article explores these drivers for fast-start plants and outlines the differences in plant design requirements, initial capital and operations and maintenance (O&M) costs for the various levels of fast-start capability.
Conventional Versus FAST
Generally, conventional start combined cycle units are restricted by heat recovery steam generator (HRSG), steam turbine generator (STG) and interconnecting balance-of-plant (BOP) equipment design. The combustion turbine generator (CTG) is required to follow a restricted load profile so that excessive exhaust energy is not provided to the HRSG and, subsequently, the STG. Fast-start combined cycle plants aim to disconnect (to various extents) the CTG loading from the STG.
In addition, HRSGs must adhere to manufacturer and design-specific temperature gradient limits (how fast the temperature can rise in the evaporator drums). Because of this, the amount of CTG exhaust energy (temperature and mass flow) needs to be controlled to prevent exceedance of this temperature gradient restriction.
In conventional start combined cycle facilities, the interconnecting BOP equipment, including major steam piping and steam turbine bypass systems, may restrict the rate at which steam can be introduced to the steam turbine. During cold start conditions (typically greater than 72 hours following plant shutdown), the major steam lines may reach a cold state. To prevent condensation carry-over to the steam turbine, the major steam lines need to be warmed. This can add significant time to the plant startup sequence.
The steam turbine is typically the most restrictive element of combined cycle startup because of the large thermal inertia. During startup, the steam turbine casing thermally expands at a slower rate than the rotor and blades. To prevent blade rubbing and turbine degradation, the rate at which steam energy is admitted is restricted. In conventional combined cycle plants, this restriction in steam temperature and mass flow is controlled by slowing down the load ramp rate of the combustion turbine.
The fast-start combined cycle unit is designed to remove these bottlenecks and allow the plant to load faster. The figure on this page provides a high-level schematic comparing a CTG load path for a 1×1 conventional combined cycle to that of a fast-start combined cycle.
To determine which elements of fast-start combined cycles should be applied to a facility, it is critical to understand what is driving the need. How fast does the facility need to be?
Typical drivers for fast-start combined cycle plants are as follows:
- Air permit constraints on emissions (nitrogen oxides [NOx], carbon monoxide [CO], particulate matter [PM], etc.) per start event.
- Carbon dioxide [CO2] emissions limitations (in pounds per megawatt-hour [lb/MWh]).
- Reduction in time to achieve stack emissions compliance (minimum emissions-compliant load).
- Reduction in the time to reach dispatched load.
- Startup fuel consumption reduction.
- Ancillary services for non-spinning reserve to increase revenue.
Conventional Versus Fast-Start CTG Load
Air Permit Compliance
Depending on the air permitting requirements of the facility, startup emissions (typically NOx, CO and PM) may be restricted on a pounds per event or annual basis. To reduce the amount of emissions generated during startup, it is beneficial to achieve stack emissions compliance as soon as possible following combustion turbine ignition.
Cane Run Unit 7 in western Louisville can achieve a quick startup and shutdown to meet emission limits. Photo courtesy: Black & Veatch
Fast-start combined cycle plants can improve dispatch characteristics, depending on the market. Many energy markets are now providing non-spinning reserve incentives. Dispatch calls are made every five minutes and require the unit to be on line within 10 minutes. The amount of time required for notification to serve load for a fast-start combined cycle is significantly less than the time required for a conventional start combined cycle or thermal plant. Because of this, if the plant operates in a market with significant load generation or demand volatility (e.g., significant renewable assets), fast-start attributes enable the facility to be called upon more frequently and at higher load, thereby increasing revenue.
Design Features OF FAST-START COMBINED CYCLE plants
Compared to conventional start plants, fast-start plant designs include specific measures to address equipment life expenditure resulting from the cycling operation and to improve reliability. In addition, there are also differences between fast-start plant designs depending on whether the intent is to minimize startup emissions or to generate load as quickly as possible. The following paragraphs address the differences in equipment caused by the additional design considerations for fast start.
To keep capital costs low, conventional start plants typical employ a single CTG starting system shared among multiple turbines. Fast-start plants designed to minimize startup emissions may use a similar approach. Plants designed for fast starts to rated CTG load, on the other hand, require individual start systems to support simultaneous starts (i.e., all CTG/HRSG trains starting together).
HRSGs designed for conventional start plants typically require holds at low combustion turbine loads to gradually warm thick-walled components (such as the high-pressure [HP] evaporator drum) prior to ramping. The unrestricted CTG startup in fast-start plants, on the other hand, can subject cold HRSG components such as superheaters and reheaters to rapid heating. Large thermal stresses can be produced by the differential expansion of the tubes within the HRSG. HRSG designs in such plants must be capable of accommodating the rapid change in temperature and flow of flue gas generated by the startup and load ramping of advanced class combustion turbines.
Stack Damper and Insulation
HRSGs can lose heat during shutdowns because of airflow from the natural draft created by the stack. Blocking the flow through the HRSG stack using a stack damper and insulating the stack up to the stack damper will minimize heat loss when the unit is offline. Maintaining the HRSG in a hot condition is critical for reducing startup time.
Natural Gas Purge Credits
Purging of the CTG and HRSG is required according to National Fire Protection Association (NFPA) 85 to ensure a safe light-off during startup. Conventional units typically include a CTG/HRSG purge as part of the startup sequence, which leads to a longer startup period. Fast-start plants avoid the startup purge through a purge credit. This method performs the purge during the CTG shutdown process and requires additional provisions to ensure isolation of fuel from the gas turbine and HRSG duct burners and ammonia from the selective catalytic reduction (SCR) system.
Multi-casing steam turbines with separate HP, intermediate-pressure (IP) and low-pressure (LP) sections can improve startup but can increase cost. STG designs for fast-start plants feature optimized casing designs to reduce the thermal stress during startup and rapid load changes. The use of higher grade material may be employed in the HP and IP casings and valves to reduce component thickness. Other features include a fully automated turbine startup and shutdown control system and integral rotor stress monitor. The rotor stress monitor is typically capable of limiting or reducing the steam turbine load or speed increase and is designed to trip the turbine when the calculated rotor stresses exceed allowable limits.
Steam turbine bypass systems in conventional start units are typically little used during startup after the STG is on load. CTG load ramping is low enough so that the STG can swallow all the additional steam generated in the HRSGs. In fast-start plants, the thermal energy released by the combustion turbine during startup is significantly higher, and excess steam must be managed. HRSGs with cascaded steam turbine bypass systems and condensers designed for 100 percent steam dump capability are required at a minimum. Fast-start plants designed for fast CTG loading may require an additional bypass system to dump HP steam directly into the condenser.
Conventional start plants which do not include an auxiliary boiler require additional time during the startup process to establish condenser vacuum. Fast-start plants may need an auxiliary boiler, but this need must be evaluated on a case-by-case basis. An auxiliary boiler provides sparging steam for the HRSG (to maintain warm drums) and condenser and seal steam for the steam turbine to maintain condenser vacuum while the unit is offline.
Terminal Steam Attemperators
Conventional start plants hold the CTG load during startup as needed to meet the STG startup steam temperature requirements. Fast-start plants decouple the CTG/HRSG startup from the STG startup by using terminal attemperators at the HRSG outlet for meeting STG startup steam temperature requirements, irrespective of CTG/HRSG load. This allows the STG to come on line independently from the CTG and HRSG. As a result, the plant can increase load more quickly.
Automated Startup Sequence
Compared to a manual or semi-automated startup control system used in a conventional start plant, fast-start plants typically utilize a fully automated control system. As a result, more plant instrumentation is required in automated plants to allow the plant control system to monitor system status, minimize times between sequential steps and provide consistent startups.
CAPITAL AND O&M COSTS
Capital costs are higher for fast-start plants than they are for plants designed for conventional starts. Additional costs that must be considered are requirements for a more flexible HRSG (e.g., header returns, tube to header connections, harps per header limits), terminal attemperators and associated systems; more flexible steam piping; improved steam piping drain systems, improved bypass system and controls integration, and requirements for auxiliary steam. Because of the range of possible additions, the capital cost increase must be evaluated on a case-by-case basis.
Various starting regimes require different levels of additional features. For example, a fast-start plant designed to minimize emissions will require fewer flexible design features than a fast-start plant designed for rated load. Because of the large variability in fast-start requirements and potential features, capital cost requirements should be evaluated on a case-by-case basis.
O&M costs are also higher for fast-start plants. However, other than the combustion turbine maintenance factors, the BOP maintenance cost increases are expected to be low relative to the capital cost increases, as long as the plant’s start regime is commensurate with its fast start design features.
While the definition of a fast-start combined cycle unit can be vague, it is important to understand the key drivers that may influence plant design. After the key drivers are known, a host of cycle design options that impact operations, reliability and cost should be considered. Since there are no one-size-fits-all solutions, it is recommended that fast-start capabilities be determined early in the conceptualization and design phases of a project.
Mike Eddington is a senior consultant at Black & Veatch. Mark Osmundsen is manager of Thermal Performance & Technologies, America’s, at Black & Veatch. Indrajit Jaswal is thermal performance engineer at Black & Veatch. Jason Rowell is turbine technologies manager at Black & Veatch. Brian Reinhart is manager of Technology Assessments & Technical Due Diligence at Black & Veatch.