Early last year Tampa Electric Company (TECO) announced it was retiring two aging 445MW coal-fired steam plants at its Big Bend Station in Florida, Units 1 and 2, and replacing them with a state-of-the-art highly efficient 1,090MW HA-class combined cycle plant.
Rather than build a new “greenfield” combined cycle plant, however, TECO has opted to repurpose the existing Unit 1 steam turbine generator and associated infrastructure (condenser, cooling water intake and discharge, etc.).
This reduces capital expenditure and the overall time for obtaining permits for the project. Project highlights:
- Combined Cycle. Two-on-one configuration, powered by two 7HA.02 gas turbine/HRSG gensets and upgraded steam turbine, rated at 1,090MW net combined cycle plant output with 60.2% net plant efficiency.
- Project Cost. Estimated at $853 million (783 $/kW installed) for the gas turbine generators and balance-of-plant equipment, modernization of the existing steam turbine generator, and refurbished infrastructure.
- Timetable. Pending expected mid-2019 permit approval to begin construction, schedule calls for simple cycle gas turbine operation by June 2021 and commercial combined cycle operation in early 2023.
- Emissions. Gas-fired combined cycle project is expected to reduce all site regulated emissions and cut CO2 emissions by more than 2 million tons per year, on top of a 25 percent reduction in cooling water and discharge flow.
Unit 1 is one of four coal-fired units installed between 1970 and 1985 at the nominally rated 1800MW Big Bend power station located near Apollo Beach, FL (photo).
In May 2018 TECO reported on plans registered with the Florida Department of Environmental Protection (FDEP) to shut down and repower Unit 1 for combined cycle operation, and to retire Unit 2 a twin 445MW plant in service since 1973.
Net result is that the utility will end up retiring 890MW of coal-fired power generation and replace it with 1090MW of more efficient and cleaner gas-fired combined cycle capacity.
Meanwhile, the newer Units 3 and 4 (445MW and 486MW respectively) would, for the time being, remain operating on coal.
Repowered combined cycle
The repowered 2×1 combined cycle plant is designed around two new GE advance-class 7HA.02 gas turbine gensets, each equipped with a bypass stack (for simple cycle operation), two unfired 3-pressure reheat heat recovery steam generators (HRSG). and modernized Unit 1 steam turbine generator.
During combined cycle operation, the steam output of both HRSGs is directed through a new over-head pipe-rack system to the 1970s-vintage steam turbine , which will have been modified to incorporate state-of-the-art steam technology.
General Electric ISO rates its simple cycle 7HA.02 gas turbine genset at 384MW gross output (without losses) and 8030 Btu/kWh LHV heat rate (42.5% efficiency).
TECO’s genset performance evaluations, however, are based on a calculated net output rating of 375MW per genset, which takes into account design and installation losses.
Similarly, GE rates its 2×1 7HA.02 combined cycle plant at 1148MW net plant output and 5377 Btu/kWh net plant heat rate (63.5% efficiency) for a standardized reference plant operating at ISO (59F) ambient conditions and designed around an optimized gas and steam turbine match.
Again, TECO’s performance evaluations are based on a calculated net combined cycle plant output of 1090MW and 60.2% efficiency which assumes a 70F average ambient temperature. It also takes into account a less-than-optimized steam turbine as well as installation losses and some limitations of the existing infrastructure.
Steam turbine changes
The $853 million project budget includes modernizing the existing Westinghouse-built Unit 1 steam turbine generator, plus refurbishing its associated steam-cycle infrastructure, including the once-through cooling system, condenser and intake/discharge structures.
“Reuse of the existing steam turbine in a combined cycle requires reoptimization of various parts of the unit for the changes in steam conditions and flows”, says Project Manager Kris Stryker.
“Our evaluations led us to the decision to replace the main (HP) steam and hot reheat (IP) steam control and stop valves, As well as redesign the HP/IP module for 1050F steam temperatures possible with the advanced 7HA gas turbines.”
This will allow us to achieve improved HP/IP turbine efficiency, he explains, since the original design steam temperatures were limited to 1000F. Throttle pressure remains at 2400 psia.
To accommodate changes in HP and IP flows that go with the change in the steam power cycle, says Stryker, a new and more optimized HP/IP module will be installed to replace the existing unit.
And to accommodate higher LP steam flows, he adds, the LP turbine will be retrofitted with a new steam path and rotor.
This will enable engineering to inorporate the latest 40-inch last row blade design. The original 1970s-era LP design featured the then state-of-art 31-inch last row blade.
TECO reports that GE has been selected to perform the steam turbine modernization work, while the HRSGs will be supplied by Vogt Power. Sargent & Lundy has been selected as the A/E for the project.
Expecting over 60% efficiency
Data filed with the FDEP indicates that the repowered combined cycle efficiency will be just over 60 percent (LHV) at an average site temperature of 70F.
Given the age of the Unit 1 steam turbine, this compares rather well with a new “greenfield” 2×1 7HA-02 plant designed around an optimized steam power cycle, ISO rated at 1148MW and 63.5 percent (LHV) per GE published data.
In the new Big Bend combined cycle plant, the modernized steam turbine will produce approximately 350MW (net) vs. about 410MW in GE’s idealized reference plant.
This difference may indicate that power output from that the redesigned steam turbine will be restricted somewhat due to limitations in the original design and/or in existing plant infrastructure, primarily the cooling system capacity and permits.
Targeted for 2023 completion
TECO officials expect the FDEP to approve their project permit application by mid-2019, when construction activities at the site would begin.
Under a phased construction approach, simple cycle operation could begin as early as June 2021. Project completion and commercial operation of the combined cycle is slated for early 2023.
Overall, says Stryker, the total project timeline from project permit application to commercial combined cycle plant operation,will span about 5 years. That’s a relatively short permitting time for a project of this size.
This is credited to the fact that repowering a steam turbine at an existing permitted site, and making use of existing cooling water (intake/discharge) infrastructure, effectively qualifies the new plant as a “existing unit” in the eyes of the regulators.
The new 1090MW combined cycle will not only replace the combined 890MW power generating capacity of coal-fired Unit 1 and Unit 2, but increase it by 200MW.
At the same time however, and critically for the regulators, the amount of steam turbine power generation which requires cooling water intake and discharge, will be reduced by 540MW (from 2x445MW, or 890MW to 350MW).
“The nearly 60 percent reduction in Unit 1 and 2 steam power will result in a substantial reduction – about 25 percent – in the current flow of cooling water intake and discharge for the 4-unit site”, says Stryker. So too will be the very substantial reduction in emissions of regulated pollutants and greenhouse gases with the retirement of the two oldest coal-fired boilers at the site, and replacing them with two gas-fired gas turbines equipped with DLN burners, and SCR technology installed in the HRSGs.
Reducing coal’s share
According to TECO, a key driving force behind the Big Bend repowering project is continued reduction in the share of coal in the utility’s overall fuel mix.
In 2017, the mix was 67% gas, 24% coal, and 9% from other sources. In 2023, taking into account the Big Bend project, the projected fuel mix will be 75% gas, 12% coal, 7% solar and 6% other.
TECO has already announced plans to invest in 600MW of solar power, in the period from 2018 through 2021, involving the installation of some 6 million solar panels.
Moreover, TECO’s coal-fired units, like most of the aging coal-fleet still operating in the US, are in need of major investments to maintain reliable operation, as well as making them viable in an increasingly competitive power market.
So, as in many similar cases in the US, retirement and conversion to natural gas was the economic choice for the utility in the case of Big Bend Units 1 and 2.
As for Big Bend Units 3 and 4, the other two 450MW-class coal-fired steam units at the site (in service since 1976 and 1985, respectively) they are dual-fuel units with capability to burn natural gas as an alternative to coal.
“There are no current plans to fully eliminate coal at the site”, says Stryker. For the foreseeable future, TECO expects that Units 3 and 4 will continue to operate on either coal or gas, depending on economics.
They have also been fitted with improved combustion systems and selective catalytic reduction (SCR) systems in recent years.
“Cleaner and greener”
The Big Bend project continues TECO’s efforts to reduce emissions and its corporate carbon footprint that started in 2003 with the repowering of two coal-fired steam units at the Gannon Power station (now known as H.L. Culbreath Bayside Power Station).
The result was an 1800MW F-class natural gas combined cycle plant comprised of two units: Unit 1 in a 3-on-1 configuration (~770MW) and Unit 2, a 4-on-1 plant (~1,030MW).
More recently, the TECO’s Polk Power Station’s four (4) F-class simple cycle units were converted to combined cycle operation. The Polk Power Station is also the site of a 250MW integrated coal gasification combined cycle (IGCC) unit, built with DOE support in the mid-1990s, which was recently equipped with carbon capture capability.
This continuing program is consistent with the announced strategic focus of TECO’s new parent company, Emera Energy, of transitioning power generation to technologies with lower carbon intensity.
“The Big Bend repowering project will improve the land and water use, and air emissions, at the site”, said Nancy Tower, President and CEO of Tampa Electric. “This project, coupled with our significant increase in solar power, will make Tampa Electric substantially cleaner and greener than it is today”, she added.
Slashing site emissions
TECO’s filing with the FDEP states that the gas turbines will burn pipeline natural gas, and be equipped with dry low NOx combustion technology to limit exhaust NOx levels to 25 ppmvd (at 15 percent O2). The unfired HRSGs will be equipped with SCR technology to further reduce final exhaust NOx levels to 15 ppmvd (at 15 percent O2).
The data filed show major reductions in all regulated pollutants, compared to Units 1 and 2 burning low-sulfur coal. Calculated totals are based on baseload operation, assuming 100 percent capacity factor (i.e., 8,760 hours of operation per year).
In addition, the company explains that the repowering project, including retirement of Unit 2, will greatly reduce greenhouse gas emissions (measured as CO2) through the use of natural gas, along with the highly efficient combined-cycle generation technology.
On an absolute basis, despite a 200MW increase in generating capacity, the operation of the gas-fired combined cycle unit in place of less efficient coal-fired generation will reduce site CO2 emissions by more than 2 million tons per year.
Adding operating flexibility
As mentioned, the Big Bend combined cycle will feature the use of bypass exhaust stacks installed upstream of the HRSGs.
This enables the gas turbines to operate in simple cycle mode by thermally uncoupling them from the bottoming cycle, thereby providing the repowered plant with a wide range of operating flexibility.
With new gas turbine models typically featuring fast start and steep load ramping capability, this means the plant can quickly be dispatched in simple cycle mode (one gas turbine unit at a time, if desired).
Gas turbine exhaust gas is then gradually fed to the HRSGs to meet the start-up characteristics of the bottoming cycle. This is usually determined by the design and the condition (e.g., cold vs. hot standby) of the HRSG and steam turbine.
The 2×1 combined cycle configuration also enables a wide range of power settings in the event that part-load power is called for. This covers power-set points from minimum load output of one gas turbine (usually set to meet emissions limits) all the way to fully loaded steam turbine.
Lowering cost of electricity
The chief hurdle for any new investment in power generation is the need to show economic benefit reflected as lowering the cost of generation.
In the case of replacing old coal-fired generation, the evaluation usually involves the future costs of upgrading the existing plant in light of changing environmental and safety regulations, as well as changing power markets.
In the case of repowering Big Bend Unit 1 and retiring Unit 2, despite the fact that the lifetime cost of natural gas is substantially higher than that of coal, TECO’s evaluations showed multiple economic benefits.
These included improved generation economics (higher output at lower heat rate), lower O&M costs, an extension of useful plant life at a strategic site location, improved environmental performance and improved operating flexibility to meet market demands.
The form of heat recovery repowering selected for Big Bend, being similar to that employed by TECO at the Bayside Station 15 years earlier, was also helpful in reaching the decision to proceed with the project.
By retaining as much existing plant equipment and infrastructure as reasonably possible, the capital investment proved to be substantially lower vs. a totally new “greenfield” plant.
Streamlining permitting process
Avoiding the cost of land acquisition and eliminating the time consuming process of permitting a brand new site were also important factors in TECO’s decision to repower Unit 1.
With most of the plant power being generated by the new gas turbines and 60 percent reduction in steam electric generating capacity (vs. existing Units 1 and 2 steam plants), the combined cycle project will not require submitting a Certificate of Need with the Florida Public Service Commission, according to TECO.
In addition, environmental permitting will be greatly streamlined. Not only will TECO be greatly lowering air emissions at the site, but the project will also benefit environmentally by utilizing existing Unit 1 steam cycle infrastructure, including the once-through cooling water intake and discharge structures.
Along with the retirement of Unit 2, the Unit 1 repowering project will actually reduce the cooling water intake and discharge from the Big Bend station site by some 25%.
With this approach, TECO is able to qualify the repowered plant as an “existing unit” under a 2014 ruling on the Clean Water Act Amendments of 1972.
Taking all of this into account, TECO expects that the gas turbines will be available for simple cycle operation, in mid-2021, and that the plant will be running as a full combined cycle unit early in 2023 – less than 5 years after filing the permit application.