Boilers, Water Treatment

Riverside Repowering Project

Issue 3 and Volume 114.

 

Xcel Energy converted its Riverside plant from coal to natural gas.

 

By Paul Eiden, Timothy Rathsam and Dawn Buchel, Sargent & Lundy LLC, and Darin Schottler, Xcel Energy

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One of the two new HP steam bypass spargers inside the existing condenser. Photo, Timothy Rathsam, Sargent & Lundy

Xcel Energy initiated implementation of the Metropolitan Emissions Reduction Project (MERP) with the twofold goal of reducing emissions while increasing the amount of electricity produced at three Twin Cities coal-fired power plants.

MERP is a voluntary program created in 2003 and pursued by Xcel Energy to convert the Riverside and High Bridge coal-fired plants to natural gas combined cycle arrangements and to install modern emissions control equipment on the Allen S. King plant. This article focuses on repowering the Riverside plant as part of MERP, specifically discussing the new combined cycle arrangement, steam turbine upgrades and changes to the circulating water system.

 

Project Scope

 

The Riverside Plant is in Minneapolis, Minn., on the east bank of the Mississippi River. The facility is close to residences and light industry. Before the repowering project began, the Riverside plant consisted of two operating steam turbine generators (Units 7 and 8) supplied from three operating coal-fired boilers (Units 6, 7 and 8). Steam turbine 7 had a nominal capacity of 165 MW and received steam supplied from boilers 6 and 7.

Steam turbine 7 was installed in 1986 as a replacement for the original steam turbines 6 and 7. Boilers 6 and 7 went into service in 1949 and 1950, respectively. Unit 8 was placed into service in 1964 and had a nominal generating capacity of 221 MW. (Units 1 through 5 had been retired.) The existing plant had a total nominal generating capacity of 386 MW.

The Riverside Repowering Project consisted of retiring three existing coal burning boilers and repowering steam turbine 7 by adding two combustion turbine generators (CTGs), designated as Units 9 and 10, each with a heat recovery steam generator (HRSG). The new CTGs and HRSGs were constructed where the original Riverside Units 1-5 once stood.

Steam is piped from the HRSGs to the existing Unit 7 steam turbine. The repowered plant has a nominal summer day generating capacity of 486 MW. The facility is entirely within property contained in the existing Riverside Plant (approximately 77 acres), except for temporary construction facilities.

Xcel Energy managed the project using a multiple-contract approach. As the owner, Xcel Energy bought the major equipment and commodities, executed the construction management and performed a number of installation activities itself. Xcel Energy also designed the new plant switchyard and transmission lines connecting to the existing main substation. The remaining construction work was allocated into separate installation contracts.

Sargent & Lundy (S&L) performed engineering and design, developed procurement specifications and expedited equipment deliveries. Technical design was coordinated around S&L’s three-dimensional (3-D) computer model platform, including modeling existing equipment and buildings to the extent necessary to ensure proper interfaces with the new design.

 

Combined Cycle Benefits

 

The new CTGs are General Electric PG7241 (7FA) machines designed for burning natural gas in dry low NOX combustors. There are no plans to burn fuel oil or other alternate fuels.

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The steam turbine being reassembled with the new blades installed. Photo, Timothy Rathsam, Sargent & Lundy.

Gas is delivered to the site by a new high-pressure pipeline that does not require additional onsite gas compression. Inlet air evaporative coolers are used to increase combustion turbine output during warm weather. Fuel gas heaters using hot water from the HRSG increase fuel gas temperature prior to combustion to improve burner performance. Each CTG has a guaranteed net output of 168 MW at rated conditions.

The CTGs were also provided with “peak-firing” mode capability, which allows power output to be increased on hot days but at a less efficient heat rate and with an increased frequency of scheduled maintenance. At an ambient temperature of 97 F, peak firing can increase output by approximately 4 MW per CTG.

The HRSGs are from Nooter/Eriksen and are designed as two-pressure, non-reheat, unfired, natural circulation drum type, with integral deaerator and horizontal gas flow. The high pressure (HP) and low pressure (LP) sections both consist of an economizer, evaporator and superheater section. A selective catalytic reduction (SCR) system using 19 percent aqueous ammonia is used to control NOX emissions generated by the combustion turbines. A casing spool section is included for optional future installation of a catalyst capable of reducing CO emissions.

Fuel switching to natural gas from coal offers significant benefits for plant emissions.

Emissions of sulfur dioxide (SO2) are decreased 99 percent, NOX is decreased 96 percent and mercury is eliminated entirely.

The surrounding area will realize additional environmental benefits. By switching to natural gas, the coal trains were eliminated, ending dust issues caused by coal handling systems.

Several noise mitigation features were incorporated into the combined cycle design. The combustion turbines were equipped with inlet silencing. A new building enclosing the CTGs and HRSGs was furnished with sound-absorbing wall and roof materials. For building ventilation, acoustic air inlet louvers and low-noise exhaust fans were used. Steam vents were fitted with silencers.

To reduce the plant’s visual impact, the three coal-fired boiler chimneys will be removed, leaving the two shorter stacks from the HRSGs. The outdoor portions of the obsolete air quality control system and the coal handling equipment will be eliminated, along with abandoned railroad track and miscellaneous foundations. The property will be finished with asphalt paving for main roads and crushed aggregate for maintenance roads, with landscaping and surface vegetation added to prevent erosion and beautify the site.

Steam turbine 7 is in an existing building, along with several pieces of equipment that remain in service. The condenser and two circulating water pumps are positioned in the building basement and operate in a once-through cooling system sourced by the Mississippi River. The system continues to function with no change in flow rate. The condenser was modified to accommodate a full-flow steam turbine bypass system for both the HP steam and LP steam generated by the HRSGs. This mode can be used during startup, shutdown or while the steam turbine is out of service.

The steam is first routed through steam conditioning valves for pressure and temperature reduction with water from the condensate system used as the cooling medium. The steam then discharges into the condenser through new spargers designed for an additional pressure drop. (See Photo 1.) The previous arrangement included a much smaller sparger sized for boiler startup conditions.

Assessment of the Riverside plant equipment prior to repowering indicated that many existing components were sized adequately for the new plant arrangement. The demineralized water system, vacuum priming and condenser air removal systems and air compressors had sufficient capability to serve the modified plant.

The facility is expected to operate in intermediate load service with an annual capacity factor of around 30 percent. The plant is configured to operate over the range of maximum generation to the minimum output of a single combustion turbine operating at 45 percent load. During most periods of operation, the plant is expected to start five to seven times a week, primarily for load following on weekdays, shutting down on weekends and weeknights, with an occasional weekend start. A new gas-fired auxiliary boiler was installed that is capable of maintaining warm standby conditions indefinitely. On average, 150 starts a year are anticipated.

 

Steam Turbine Upgrades

 

The existing steam turbine was furnished by Westinghouse Electric Corp. in 1986 with a nameplate rating of 150.5 MW. The turbine is non-reheat, condensing, two-casing, doubleflow down-exhaust with 28.5-inch last stage blades. Rated conditions at the throttle valve inlet are 965 psia and 1,000 F. These values have not been changed as part of the repowering project.

The turbine design included three extractions from the HP casing and two extractions from each side of the LP casing for feedwater heating. The five stages of feedwater heaters were removed from service and were not included in the combined cycle configuration.

The HP extractions were cut and capped. Small bore drain lines were added at each extraction and routed to the condenser. A control valve, normally closed, was included in each line, which opens if condensate starts to collect in the drain. For the LP extractions, the lines were cut and capped inside the condenser neck. At the low point of each cap, a 1-inch hole was drilled that continuously drains steam above the condenser tubes to prevent condensate buildup in the remaining stub of extraction piping. Small holes were also added to the steam turbine LP casing to prevent water droplet buildup and aid in moisture removal.

At base load, the turbine operates with the throttle and governor valves wide open with sliding pressure. After repowering, design steam flow to the turbine has decreased from 1,255,000 lb./hr. to a maximum of 1,130,000 lb./hr. However, since the extraction lines were removed and no flow is leaving the turbine, the amount of flow exiting the HP section has increased by approximately 10 percent. As a result, the calculated pressure at the outlet of the HP casing increases. This would cause an overstress condition on the outer casing bolting along the horizontal joint, so changing the bolting or the flange was considered, but these options did not resolve the problem. Therefore, it was necessary to maintain the same HP casing exhaust pressure as originally designed. To achieve this, rows 1 and 2 in the LP section of the turbine were redesigned and replaced to enable an increased flow through the LP turbine at the same inlet pressure. This work was accomplished by Mitsubishi Power Systems. (See Photo 2.)

The remaining existing blades, the rotor and all other steam turbine components were determined to be acceptable in the repowered configuration. Leak-off lines from the steam chest and the HP section were altered. This piping formerly connected with the extraction steam lines but is now routed to the condenser. Temperature in the leak-off lines requires the use of alloy material (ASTM A335 Gr. P22).

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The new LP steam admission line connection into the crossover piping circulating water system. Photo, Timothy Rathsam, Sargent & Lundy.

Low-pressure steam generated by the HRSGs is routed to a new admission point on the steam turbine. Maximum operating conditions for the LP steam system are 115 psia and 505 F. The new admission connection is located on the 48-inch-diameter crossover pipe between the HP casing exhaust and the LP casing inlet. The new connection is 14 inches in diameter with 80,000 lb./hr. design flow rate. (See Photo 3.) Using one of the extraction nozzles as the new admission point was considered rather than installing a new connection. Mitsubishi advised against this arrangement, however, citing concerns over possible non-synchronous (or random) vibration with the steam entering the flow path in a nonsymmetrical fashion.

New LP steam stop and control valves were added near the steam turbine. Each valve has a fast-acting, air-operated, butterfly-style arrangement.

 

Circulating Water System

 

Repowering the plant requires the project to comply with the U.S. Environmental Protection Agency’s (EPA’s) Cooling Water Intake Structures Phase II regulation, under section 316(b) of the Clean Water Act. The Phase II rule sets national standards for cooling water withdrawals by large, existing power producing facilities.

The plant is permitted to reduce impingement by limiting the maximum through-screen design intake velocity to 0.5 ft./second or less, which could not be met by the existing traveling screens. A study was performed to evaluate the technical acceptability and economics of the available technologies for intake screening. The number of available intake screening options was limited by the short timeframe allowed for actual construction of the intake. Installing the new intake could not affect the operation of the plant until Unit 7 went into an extended outage starting in September 2008 and had to be completed by the time the repowered plant initiated startup activities in January 2009. Plus, all river work had to be completed before the river froze in November 2008.

Use of underwater wedge-wire screens was the best technically acceptable option. The versatility of the wedge-wire screens enabled them to be incorporated into the existing intake structure with relatively minor modifications. Five wedge-wire screens extend into the Mississippi River and are connected via an underwater pipe header to a new steel bulkhead installed at the existing Unit 7 intake screenhouse.

The river area in the vicinity of the Unit 7 intake was dredged and rip-rap was placed during a planned outage in the summer prior to installing the new intake. During installation of the new intake, piles were driven into the river bottom to support the wedge-wire screens and the piping header. The new bulkhead and all underwater piping were shop-prefabricated and modularized so that underwater installation only involved setting the pieces and bolting up the flanges (see Photo 4), minimizing the need for underwater welding.

Challenges associated with the design of the new circulating water intake included the shallow river water depths in the vicinity of the existing intake, periods of heavy river debris and silting, incorporation of the wedge-wire screens into the existing intake structure and avoiding the circulating water discharge pipe directly below the intake that extends to the middle of the river.

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One of the modular circulating water intake piping sections being lowered into the Mississippi River. Photo, Timothy Rathsam, Sargent & Lundy.

Air burst, silt sluicing and river warming systems were designed and installed to mitigate various types of screen fouling and to keep the screens operating at peak performance.

Air Burst: Periodically releases high-pressure air inside the intake screens to remove any debris accumulated on the screen surfaces.

Silt Sluicing: Periodically “jets” away any sediment buildup in the area below the screens. The operation of the sluicing system is anticipated only during times of heavy silt loading, typically during the fall and spring.

Warming: Redirects a portion of the water from the Unit 7 circulating water discharge tunnel to the area around each of the five screens to prevent the formation of frazil ice near the screens. Frazil ice is a collection of tiny waterborne ice crystals that resemble slush and form in supercooled, turbulent water, which can eventually block all or part of the wedge-wire screen surface. Under the right conditions, frazil ice can spread and adhere to objects in the water, especially when they are at a temperature below water’s freezing point. Managing surface ice is not the goal of the warming system, as the screens were placed below the maximum expected ice layer. An ice layer actually helps prevent frazil ice formation by insulating the water surface and preventing the large heat loss rates responsible for supercooled water.

Converting Riverside Plant to a combined-cycle station accomplished the goals of reducing emissions and increasing power output. Plant performance met predicted values for output and heat rate. The combined cycle plant was ready for operation in time for summer 2009.

Editor’s note: This article was condensed from a paper the authors presented at POWER-GEN International 2009. Additional topics covered in the paper include plant controls, foundation and building design, electrical integration and project schedule.

Authors: Paul Eiden is a manager at Sargent & Lundy LLC. Contributing to this article were Timothy Rathsam and Dawn Buchel, both members of S&L’s fossil power technology division based in Chicago, and Darin Schottler, manager for Xcel Energy in Minneapolis.

 

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