The phrase, matrix organization, was popular a decade or two ago in management circles. It refers to an org chart where a staff worker or middle manager reports to multiple bosses and stakeholders, rather than a traditional binary “one worker, one boss” hierarchy.

One of the largest combined-cycle facilities in the country is a “matrixed” powerplant. It has multiple 2 × 1 power blocks equipped with GE 7FA gas turbine/generators (GT) and D11 steam turbine/generators (ST). Each 550-MW block is not only owned separately, but functions to serve each owner’s discrete objectives. More specifically, one block is governed by a tolling agreement with a solar-rich utility and primarily serves a large metro area. Another block is owned by a utility. Two more blocks are owned by a merchant power company.

Three separate operating budgets and operating schedules govern the facility. The common infrastructure—such as water treatment, fuel supply and delivery, fire and safety systems, control rooms, etc—are paid for equally by the three owners, regardless of output, operating hours, or other metric which might be used to apportion expenses. The operating staff is common to all three owners, too.

Like so many other combined cycles nationwide, performance objectives have changed considerably since the facility was commissioned in 2003.

It’s all about the peak. The common performance objective across the owners and power blocks is similar: It’s all about meeting peak demand. The GTs, all told, can experience more than 1200 starts annually. For example, the solar rich utility buys 230 MW of solar thermal, greatest between 10 am and 3 pm each day. On a typical sunny day, the associated power block will shut down during those hours, and the unit will experience a start/stop in the morning and another in the evening.

In other words, the block “follows the sun” much like a peaking gas turbine in terms of starts. On the other hand, a peaking GT would, in earlier times anyway, operate during the day to satisfy peak AC demand of the utility’s customers, and then shut down at night.

By contrast, the power block devoted to the other utility operates less like a peaking GT and more like an intermediate-duty machine. Last year, for example, the unit remained online all of September and October.

The merchant power blocks are experiencing few calls to start these days. As of the first week in January (2016), those blocks were expected to be in layup until sometime this month.

Flexibility toolkit. Water is at a premium at this site and the emissions envelope for different operating modes is tight. Thus, the plant has assembled the familiar toolkit to meet peak demand, minimize emissions during starts and stops, minimize raw water sourced from an aquifer, maintain combustion stability under dynamic conditions, and prevent as much wear and tear on the GTs as possible (none of the blocks are governed by an LTSA with a vendor). The toolkit includes:

• Software system to monitor and optimize loading of the turbines while keeping emissions in check

• Enhanced startup procedures through a plant-built startup sequence calculator

• Supplemental firing of the HRSGs for power augmentation

• GT inlet fogging systems for power augmentation during appropriate ambient conditions

In addition, the plant extensively modified its water treatment systems to accommodate the growing need for flexibility, changes in operating profile, and a restrictive permit that prohibits the discharge of process water from the site.

Simplified ZLD. Core problems with the original zero liquid discharge (ZLD) water system were the following:

• The plant was discharging too much wastewater to the evaporation ponds.

• The brine concentrators (BC), the heart of a ZLD system, were troublesome and required frequent servicing and offline cleaning. Average run time between BC unit cleanings was 3-4 months. The permit at the time did not allow pumping water somewhere else under any circumstances. When the “freeboard” elevation in the pond got below 4.5 ft. the plant risked a forced shutdown.

The first solution attempted was to eliminate the clarifiers, holding tanks, and other “front-end” equipment (such as multi-media filters), and install a third BC unit. That wasn’t enough.

Later, the facility was able to get the air permit modified to allow spray evaporators in the ponds and the water permit modified to allow floating pumps to return pond water to the ZLD for treatment.

Permit mods, plus the following process changes, allowed the plant to streamline the ZLD:

• Add spray evaporators and floating pumps to the ponds (three of them).

• Replace original single-pass reverse osmosis (RO) rental units, used when the ZLD system is offline, with permanent dual pass RO unit for processing raw makeup from the aquifer.

• Minimize cooling-tower blowdown by increasing cycles of concentration (from 150 ppm to 180 ppm) together with added monitoring capability.

• Improve BC performance by use of anti-scalant and anti-foaming additives.

One important consequence of the mods is that the plant is no longer dependent on expensive rental water treatment equipment and/or solely on the brine concentrator for HRSG boiler makeup. The revamped ZLD system has been operating well and saving hundreds of thousands of dollars annually, according to an account at a user event.

One lingering issue is corrosion at the top of the brine-concentrator tubesheets. Generally, brine-laden wastewater flows through the inside of the tubes in a BC, while steam condensing on the outside transfers heat across the tubes. Nozzles at the top distribute the brine through the tubes.

The primary cause of corrosion isn’t known but the thought is that brine “wicks” underneath and between the nozzle and titanium alloy tubes. Better control of chlorides is thought to be part of the solution.

Climbing the peak. HRSG duct burners add up to 25 MW additional capacity, the foggers up to 20 MW from each GT at full blast. Normally, the blocks run on an automatic generation control (AGC) signal from grid dispatch, but not during power augmentation. During these hours, the goal is to deliver as much capacity as possible, not cycle to meet fluctuating demand.

Variable-frequency drives (VFD) on the fogger water pumps help control flow to the GTs as ambient humidity fluctuates. Foggers typically run in the summer months when temperatures are above about 70F.

The plant has endured a prolonged learning curve with various fogging systems (Fig 1). All GTs came equipped with foggers supplied by the OEM, but they proved unreliable and also contributed to erosion of compressor blades. After attempts at correcting issues with the original foggers failed, a replacement system from Mee Industries was installed on one block. It apparently operated well and fogging water droplet size was controlled well enough to avoid blade erosion.

However, early in 2014, the facility contracted with Caldwell Energy to retrofit the remaining GE units with its equipment, using as much of the original equipment as possible. According to Caldwell’s Rodney Kohler, the original foggers relied on belt-driven plunger pumps. Not only were they prone to failure at this site, pieces of the pump seals would clog spray nozzles and other downstream components, especially during summer when they are frequently online.

The Caldwell foggers avoid belt-driven pumps, gearboxes, and lube oil systems, and instead incorporate high-pressure, positive-displacement pumps with VFD motors. Kohler said these pumps more accurately deliver the right amount of water to the nozzles, while minimizing valves and piping. They also require less frequent inspections.

Foggers are critical at this site to meet contractual output obligations when dispatched during peak demand periods. At a facility where every drop of water has value, precise control over water delivery to the fogger nozzles is important. Plant personnel reported no significant issues with the new foggers, although Kohler noted that some teething problems had to be worked out with thermal management in the VFD power electronics package.

Beat the fuel burn. Because of the high number of starts, one of the facility’s primary key performance indicators (KPI) is to minimize fuel consumption during startups. To this end, the plant developed a six-mode startup sequence automation package, which runs in the Ovation control system. In addition, there are automated procedures for hot, warm, and cold starts based on aggregated temperature decays from previous starts.

Essentially, the software benchmarks each start on megawatts, emissions, fuel burn, dispatch times, turbine ramp rates, etc, by comparing the current start sequence to an “expected” start based on actual operating conditions—such as ambient air conditions, equipment temperatures (for example, hot, warm, or cold start), and steam-temperature profiles. All the required data are collected in the DCS; the plant just puts it to good use in a convenient way that enhances operations.

Automation is important for reducing human error and making starts consistent, but also to give operators performance targets. The goal is to reduce the fuel burn and meet or exceed the dispatch times. Automating startup routines also adds flexibility. When the GTs are in extended turndown, the operating mode used to avoid a restart, a power block can be brought to full load in 17 minutes.

Another benefit of consistent startup sequences and predictable fuel burns is they help plant management arrange for more cost-efficient gas deliveries.