Commissioning seven gas-turbine (GT) control systems in seven weeks would probably be taxing under the best of conditions. In NV Energy’s case, there were some extenuating circumstances.
First, the seven systems are located at two generating facilities acquired by the utility in 2014. Second, it is challenging to test a retrofit, due to air permit emission limits. Third, NV Energy, like most utilities today, has limited central engineering staff for projects like this. Finally, the original estimates for the projects were established by the due-diligence team, but had to be carried out by engineering and operations. No field instrumentation was included in the scopes.
As background, three of the GTs, gas-fired (no backup fuel) GE 7EA peakers located at Sun Peak Generating Station (SPGS), have water injection for NOx control and minimum balance-of-plant (BOP) systems. The other four engines are at Las Vegas Generating Station (LVGS), which has three combined cycles powered by LM6000s equipped with water injection for NOx control and SPRINT compressor inlet water spray for power augmentation. Two of the combined cycles are in a 2 × 1 arrangement (installed in 2003), one is a 1 × 1 (installed in 1994). The latter was not included in the controls upgrade project.
The controls retrofit at SPGS was justified on the basis of adding remote operation; the LVGS retrofit was justified to improve and automate transitions in and out of SPRINT mode. Both projects were commissioned in seven weeks during October and November 2016, with no third-party owner’s engineer in the mix.
An interesting wrinkle, important to understanding how the projects unfolded, is that SPGS went first in the schedule. Because it required a Class A Nevada contractor’s license by NV Energy’s procurement group, the electrical contractor was lead, with Emerson, the DCS supplier, as sub. Due to a less restrictive project scope for LVGS, this requirement was relaxed such that a Nevada Class C contractor could lead, which allowed the DCS vendor to be lead, and the electrical contractor as sub. Nevertheless, this led to two separate engineering specifications for each plant.
As reported by Clint Vanderford at the Ovation Users Group Conference in July 2017 and during a follow-up call with CCJ editors, the experience offers valuable lessons—from the acquisitions phase through commissioning new equipment—for others undertaking such projects.
In reviewing the challenges explained below, it’s important to note that each plant had a different owner and both were IPPs, with design features that may not be considered “utility-grade.” Also, some of these are typical “gotchas” which occur with every project of this type and magnitude, but still suggest wise cautions for others contemplating similar work.
Carefully review all instrumentation relevant to the retrofit. Many project issues stemmed from a lack of instrumentation expertise on the acquisition due-diligence team which led to the controls retrofit project team being unaware of important instrumentation issues. All of the gas turbines here feature wet NOx control (water injection). Some of the instrumentation at SPGS is 1980s-vintage. LVGS had LM6000s equipped with newer instrumentation, but valve positioners in the Woodward control system posed problems. Plants often “live” with marginal instrumentation. The larger point here is that existing instruments will exhibit varying degrees of compatibility with a state-of-the-art DCS.
Clarify each participating group’s capabilities and experience. Each facility’s contract was managed differently. At SPGS, a local electrical contractor licensed in Nevada acted as the lead EPC contractor with Emerson as a subcontractor. At LVGS, Emerson was lead contractor with Dynalectric Nevada as sub. Lesson learned here is that the DCS supplier is a better EPC than an electrical contractor, in part because of the inherent understanding of the instrumentation. On the other hand, Emerson had little experience retrofitting LM6000 machines with Ovation; this inexperience surfaced in the areas of cabinet layouts and construction and diagnosing wiring circuits. Substantial new wiring had to be pulled to replace cabinets located at the turbine housing (the gas-turbine OEM’s design basis) to cabinets located outside the control room (the DCS vendor’s design basis).
Pay attention to the soft-hard interface. Vanderford noted that Emerson did a really good job delivering the “soft” product—that is, writing the logic and building the graphics. Wiring the existing plant components to the new DCS equipment was not so straightforward. At LVGS, there was no one who could actually install the new gear, so it had to be hired out. A third-party contractor had to make sure everything was properly wired. The project team found numerous instances of “duct tape” solutions with the existing equipment which had to be remedied to hook up the new controls. At SPGS, the ABB Bailey BOP controls and the GE gas-turbine controls were hard-wired—that is, no bus or data highway. “It was like peeling an onion,” Vanderford said, “it took a few iterations to achieve our objective of having minimum hard-wired stuff.” However, the protective circuits are still hard-wired. The project team also found numerous instances of electrical changes not properly documented.
Focus on the graphics. What the operators see on their screens helps determine how well they can run the equipment. Emerson’s Ovation team includes GT specialists, but they are typically not plant operators, and they build and deliver “standard” graphics packages. Those who specify and bid projects like these have to incorporate flexibility to modify the graphics so they work for GT plant operators, not GT engineers. Vanderford said the Ovation “standard” graphics were crowded and not well organized, and that boilers “don’t exist in the GT controls world.” “Many discussions were required with Emerson’s Clifton Park GT specialists,” he added.
Know your air permits before starting the project. It is challenging to test a retrofit like this because air quality permit limits cannot be violated. Not all of the post-installation testing that was required at SPGS would fit within the air permit emission limitations. As the regulatory agency does not issue variances, there was no way around this limitation. This made it difficult to commission the new turbine governor. This also necessitated postponing the voltage regulator replacement, because it requires one hour of operation at full speed and no load, even though the existing one is old and not easily maintained (though it is still deemed reliable). NV Energy is pursuing the permitting of a limited amount of operation at higher permit limits for the purposes of testing and tuning, which will allow the new voltage regulator to be commissioned.
Check out motor and other critical component specifications prior to testing. NV Energy experienced a starting-motor failure during the commissioning. An underrated motor had been installed before the project as a replacement, and it ended up running longer than it was designed for as part of the commissioning. The relays in the DCS were programmed to protect the load of the old motor, not the new one. An auxiliary lube-oil-pump motor also failed but Vanderford chalked this up to age: “Its time had come.”
Trust, but be in a position to verify. Because of the lack of central engineering resources and minimum plant staff, NV Energy had to place a great deal of trust in its contractors. For example, Vanderford notes, “we lacked experience in governor logic, and had to trust the DCS vendor, while holding some money back until verification that the controls would work as designed.” The electrical contractor was more of a “generalist,” though with abundant industrial facility experience, and required “coaching” by NV experts. Few on the plant staff had the requisite knowledge of the equipment to carry out a project like this. In the end, says Vanderford, success in construction relied heavily on good will and good working relationships among the team members. Each project was run by the plant, although up until 2016, such projects would have been handled by a central project management group.
Overall, Vanderford reports, there were no major failures and no major delays and the transition to normal operations went well. That’s quite an outcome when retrofitting seven gas turbines in seven weeks across two facilities with substantially different systems, equipment vintages, and former owner/operators.