Afton Generating Station: One plant, two stories

The general public typically does not appreciate how difficult it can be to install new generating plants. Like­wise, some owners don’t appreciate how much effort it can take to keep generator shafts turning. Yet both groups bark aloud when costs go up.

There are two stories in this arti­cle: One shows the torturous path for Afton Generating Station from conception to completion; the other, the people effort involved in meeting evolving expectations with existing infrastructure. If you have no inter­est in why it took six years to design, build, and commission a 1 × 1 com­bined cycle, turn to p 132 for the les­sons learned since startup (Fig 1).

Why developers need deep pockets

Flexibility, adaptability, and commit­ment to goals are attributes critical to the success of today’s generating companies—regulated or unregulat­ed. Afton is a case in point. In 2001, the project was purchased by Public Service Co of New Mexico (PNM) from developers who had invested several years trying to line up power-purchase contracts to support con­struction.

PNM’s plan was to build a 550-MW 2 × 1 7FA-powered, duct-fired combined cycle with an evaporative cooling system and it purchased gas and steam turbines from GE Energy. First step in the project’s develop­ment (designated Phase I) was to design, build, and commission one simple-cycle gas turbine (GT).

A few years later, a reassessment by the company of its generation mix revealed that a 225-MW 1 × 1 com­bined cycle was the optimal resource, not the 2 × 1, and work proceeded to develop that asset as Phase II. The reassessment also concluded that the steam turbine for the 2 × 1, already in inventory, was not suited for the proposed Phase II configuration. To meet the project schedule, grey-market replacement equipment was purchased in late 2005.

PNM implemented a demand­ing environmental sustainability policy in 2003. Its impact on Afton was a change from wet cooling to a hybrid system using an air-cooled condenser (ACC) and small wet tower operating in parallel. This reduced water consumption by 60% over the original plan with little, if any, per­formance impacts during periods of high ambient temperatures.

Afton achieved commercial opera­tion in October 2007. Today, the state-of-the-art plant is categorized a critical resource and is tied with PNM’s Luna Energy as the generat­ing facility with the lowest emissions rate in the state.

Ancient history. Development of the Afton site began in 1991 by Energy Southwest Inc, an in-state development and consulting firm. ESI saw two possibilities for a plant in New Mexico’s so-called southern industrial corridor relatively close to robust electric and gas transmission infrastructure:

  • Peak power for mining operations in southwestern New Mexico and southeastern Arizona.
  • Peak power for nearby Las Cru­ces, which was negotiating a sepa­ration from El Paso Electric Co. If the city were successful, it would become a wholesale purchaser.

Afton’s evolution is defined by five different design configurations devel­oped over the years, as described below. Configurations one and two came and went before PNM pur­chased the plant:

1. The first idea was to install a single gas-only peaker and link it electrically to a remote 1 × 1 com­bined cycle—equipped with a Model 7FA gas turbine and an A10 steam turbine—under development in Mor­enci, Ariz, to serve a large regional copper-mining concern. Goals: The two-element asset portfolio would supply most of the copper producer’s electrical needs and also provide peak power for Las Cruces.

2. The power sales contract with the mining concern was placed on indefinite hold and the state and federal governments were propos­ing a robust deregulated market for “exempt wholesale generators.” The Morenci plant was shelved and the focus shifted to Afton, which was reconfigured as a 1 × 1 7FA-based plant with a wet cooling tower.

Target market was El Paso Elec­tric’s wholesale loads which analysis suggested were served by old, gen­erally unreliable gas-fired steam/electric plants. Against these assets, Afton would have a significant com­petitive advantage.

3. PNM bought Afton because the utility thought it ideal to serve the expected merchant market. It ordered the turbines for the 2 × 1 combined cycle in the midst of a strong seller’s market. Then came the Enron fiasco and the virtual collapse of the fully competitive deregulated wholesale market. Afton was shelved and reassessed once again for a more appropriate configuration.

4. The fourth configuration, a simple-cycle 7FA peaker (again), became the first constructed phase of the project. Availability and operat­ing flexibility were critical. The dual-fuel unit was equipped with a bypass stack and damper to accommodate future plans.

The plant was engineered and constructed to allow expansion to a 1 × 1 combined cycle. The other equip­ment purchased for the 2 × 1 (Config­uration 3) and not used for Configu­ration 4 was assigned to other PNM projects or sold. The utility’s plan going forward was to have a smaller Afton as a non-merchant resource for jurisdictional load.

5. The final evolutionary step was to expand the peaker into a 1 × 1 combined cycle by adding a duct-fired heat-recovery steam genera­tor (HRSG) equipped with SCR and CO catalyst systems, and a GE A10 steam turbine. Both were purchased from Cogentrix Energy, which had them in storage. An upgraded tur­bine control system was purchased from the OEM.

The OEM’s fogging system was installed as well, to maximize sum­mertime generation. Dental molds are taken periodically as suggested by the manufacturer. No erosion of R0 com­pressor blades is evident to this point.

Cooling system experience

The wet/dry parallel cooling system was bid as an integrated system—including ACC and associated steam duct, surface condenser, and wet cool­ing tower—by the plant design engi­neer, POWER Engineers Inc, Boise (see equipment list and Fig 2). Design intent was to achieve a thermal duty split between the wet condenser and ACC of 40/60, respectively, when ambient air was 70F. This was based on heat balances run under assumed operating hours which maintained water consumption below the permit­ted 555 acre-ft/yr.

Reducing the environmental impact of power generation

PNM Resources Inc, parent of Public Service Co of New Mexico aka PNM, has as one of its goals a reduction in water use at generat­ing plants. In 2008, the company reported that it had consumed 6% less fresh water per megawatt-hour of electric production than it did five years earlier. Use of dry cooling to the degree practicable at new plants is one reason for this. Anoth­er is increased reliance on gas-turbine-based powerplants which require less water than conventional steam/electric stations.

The company also reported a 28% reduction in NOx intensity (pounds/MWh) from 2004 to 2008. That number also reflects the posi­tive influence of GT-based plants on emissions. During the 2004-2008 period, generation increased by 30% while absolute NOx emissions in tons dropped by more than 6%.

Afton’s cooling system has a (1) 10-cell (5 × 2 arrangement) ACC equipped with two-speed fans, (2) two-cell wet tower with two-speed fans, (3) deaerating surface condens­er with two 50% vertical circulating-water pumps with 4160-V single-speed motor drives, (4) steam-jet air removal system, and (5) hogging vacuum pump for startup.

The small wet tower also serves as the heat sink for the closed cool­ing-water system, so one circ pump always is on. In cool weather it oper­ates with one or no fans running to minimize evaporative loss; the ACC handles most of the condensing duty for the steam turbine. Water circu­lates through the surface condenser year-round to minimize both fouling and air inleakage.

The cooling system is con­trolled from the plant DCS and operation is automatic. The control-room operator inputs a backpressure setpoint and the DCS adjusts the number of ACC fans and their speed to maintain that pressure. The sur­face condenser supplements the ACC when the backpressure gets in the range of 3.5 to 4 in. Hg abs.

Fig 3 compares the steam-turbine backpressures for wet-, air-, and par­allel-cooled systems over a wide range of ambient temperatures. Design point for the parallel cooling system: Con­dense 594,981 lb/hr of steam using 98F ambient air (16% relative humidity) without turbine backpressure exceed­ing 5 in. Hg abs.

At higher ambients, duct firing typ­ically is cut back to reduce steam flow and keep backpressure from going over 5 in. Turbine is set to trip at 7.5 in. Plant Manager Greg Nugent said that he couldn’t recall going over 5 in. Hgabs—even on a 108F day. However, he remembers high 4s.

Nugent was hired late in the project—less than three months before first fire in June 2007. Most often, plant managers arrive at the site about the time the first shovel of dirt is scooped so they can par­ticipate in design decisions affecting operation and maintenance. Nugent really had to scramble to come up to speed; this was his first experience with ACCs—and the com­pany’s, too.

One of the first potholes Nugent encountered was insufficient vacu­um at loads less than rated capac­ity. Motive steam for the air ejectors comes off the cold reheat line and is supposed to be at 427 psig. But Nugent said they were seeing about 275 psig until the plant was oper­ating at base load. Only practical solution was to leave on the hogging vacuum pump until the plant was operating at full load.

But this was not as easy as you might assume. Pump was of the liquid-ring type and the plant had difficulty maintaining the water level required. So they had to put a hose in the water tank for the pump and leave it on, allowing the tank to over­flow to the wastewater treatment pond—certainly not a long-term fix, especially given the company’s com­mitment to water conservation.

Solution was to redesign the air-ejector nozzles for 275 psig. That worked fine. Whole problem could have been avoided, Nugent surmised, by pulling air-ejector motive steam from the main steam line rather than the cold reheat line. Lesson: Owners can save on personnel costs by hiring late, but then you don’t have access to the experience that can help avoid such oversights. It’s the old story, “You can pay me now, or pay me later.”

Learning how to balance the dry and wet cooling takes some expe­rience, continued Nugent. Although ACC operation is controlled by the DCS, he said, the CRO sometimes will switch to manual operation—such as when temperature changes rapidly, during high-wind condi­tions, when fans cycle excessively between low and high speeds because of changing ambient temperature. The plant hasn’t experienced loss of suction during high winds, which typically blow from the West. Both the dry and wet towers run in a north/south direction and are located south of the generating equipment; the wet tower is west of the ACC.

Early in the plant’s operating his­tory, Nugent said, the operators were running at least one fan in the wet tower about 40% of the time. This is a manual operation: Closed cooling water temperature reaches a certain level and the CRO turns on a fan. When CCW hits the target, fan is turned off.

Any experienced operator knows there are times of the year—like the shoulder months—when you might have to run the fan for 15 minutes, shut it off for an hour, then turn it on again. There were occasions when operators chose to just let the fans run for extended periods.

The only way to “take control,” Nugent added, is to program this into the DCS. But you need data to do this and you can’t get that information without a top-notch historian, which he hopes to have soon. Nugent said having ready access to all plant historical data also is critical for troubleshooting. He’s had more than his share of “mys­tery trips.”

ACC fan failures seem to be a growing concern. Several plants have experienced them. Afton’s came only three months after commercial operation was declared. Five of six blades on one fan failed. Inspection of the other nine fans revealed that 80% of the blades had cracks radiating out along the leading edge.

Corrective action: Replaced all six-blade fans with ones having seven blades; changed pitch angle of the blades from 12.8 to 12.3 deg; used a different manufacturing pro­cess. Strain gauges were installed on one fan to gather data for a possible root-cause analysis—for example, a given wind condition. There have been no failures since the fans were changed.

Get information first-hand on the industry’s experience with ACC fans by attending the inaugural meeting of the ACC Users Group, Nov 12-13, 2009. The users-only workshop will be held at NV Energy’s corporate headquarters in Las Vegas (see ad, p 84). Contact Staff Engineer Barbara Allen today at BAllen@nvenergy.com; seating is limited.

Principal equipment, Afton Generating Station

Commercial operating date: Octo­ber 2007
Architect/engineer: POWER Engi­neers Inc
Constructor: TIC The Industrial Co
Type of plant: Combined cycle

Key personnel

Plant manager: Greg Nugent
O&M manager: Pat Ryan
Planner: Chuck Arater
Plant chemist: Mary Schoenheider

Gas turbine

Manufacturer: GE Energy
Number of machines: 1
Model: 7FA
Control system: Mark VI
Combustion system: DLN 2.6
Fuels: Dual fuel (natural gas and distillate)
Water injection for NOx control? Yes (when firing oil)
Water injection for power augmen­tation? No
Generator, type: Hydrogen-cooled
Manufacturer: GE Energy
GSU: Waukesha Electric Systems
Air inlet house: Braden Manufactur­ing LLC
Inlet-air cooling system, type: Fog­ging
Manufacturer: GE Energy

HRSG

Manufacturer: CMI EPTI LLC
Control system: Invensys Process Systems/Foxboro
Attemperator(s): CCI-Control Com­ponents Inc
Duct burner: Forney Corp
SCR: Peerless Mfg Co
Catalyst supplier: Cormetech Inc
CO catalyst: Spool piece provided for future catalyst, if necessary
Steam-turbine bypass valve/desu­perheater: CCI-Control Compo­nents Inc

Water treatment

HRSG internal treatment, type: Amine, oxygen scavenger, phos­phate
Chemical supplier: Nalco Co
Reverse osmosis system: Eco-Tec Inc
Demineralizer: Eco-Tec Inc
Cooling-water treatment system: Nalco Co
Cooling-water chemicals: Nalco Co
Wastewater treatment system, type: ZLD
Supplier: Eco-Tec Inc

Steam turbine

Manufacturer: GE Energy
Model: A10
Generator, type: Hydrogen-cooled
Manufacturer: GE Energy
GSU: Waukesha Electric Systems

Balance of plant

DCS: Invensys Process Systems/Foxboro
Condenser, types: Air- and water-cooled
Manufacturers: GEA Power Cooling Inc (ACC); GEA Iberica S A (sur­face condenser)
Wet cooling tower: GEA Power Cooling Inc
Boiler-feed pumps: KSB Inc
Condensate pumps: Flowserve Corp
Circulating-water pumps: Flowserve Corp

Water treatment

Makeup water is sourced from onsite wells and treated conventionally as shown in Fig 4.

Wastewater treatment sys­tems typically present the biggest challenges to plant staffs, primar­ily because much of the information required for design is not known in sufficient detail until the plant has operated for a couple of years. To illustrate: In the case of Afton, cool­ing-tower blowdown varies signifi­cantly with wet-tower capacity factor and that certainly was not known at the design stage.

Also, several owners have expe­rienced dramatic changes in the quality of raw water used for make­up between the time the plant is designed and commissioned. If quali­ty is poorer than expected, the waste­water treatment system might not have sufficient flexibility to process waste streams generated during the production of process water.

Afton’s wastewater treatment sys­tem is designed primarily to process cooling-tower blowdown and reverse-osmosis (RO) reject water (Fig 5, upper left). As designed, water was pumped to three 32,000-gal waste­water tanks with an equalizing line. Nugent said the tanks were too small for the actual service conditions and were subject to stratification because no mixers were installed.

The solution for undersize waste­water tanks and stratification was simple: Pump all waste streams to a pond where they mix and become a homogeneous solution. Silverhawk Generating Station does this as well (see p 102).

Initially, RO permeate was pumped to the wet tower as makeup, but it doesn’t have storage capability, which can be a problem. Now perme­ate is sent to the raw water tank (as indicated in Fig 5) where it mixes with well water to produce a higher-quality water for demineralization.

Clarifier size also was called into question. The rapid-mix chamber as sized and configured doesn’t allow sufficient time for flocculation. Plant is installing a premix system to maintain near constant flow and water quality (including pH) to the clarifier. Another multimedia filter, arranged in parallel with the exist­ing filter, is required as well. Goal is to redesign/re-equip the waste­water treatment system for con­tinuous, rather than intermittent, operation. For more on wastewater treatment, see the article on the Frank A Tracy Generating Station (p 90). ccj