Dry low NOx combustion technology is the cost-effective environmental solution for a plant retrofit in the increasingly restrictive Houston area.
A recent challenge that management at San Jose, CA–based Calpine Corp. faced when it needed to retrofit a natural gas–fired cogeneration plant in the Houston, TX, area was a familiar one: adhere to increasingly stringent environmental standards in the most cost-effective manner. Unique aspects of converting the first of three turbines at the 457-MW combined-cycle cogeneration Texas City power plant, however, were the local environmental standards—and an available technology for drastically reducing both NOx and carbon dioxide emissions that minimally impacted operations, not to mention the facility’s economic viability.
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Calpine had to reduce these emissions at the Texas City plant, which began operation in 1987 and produces steam for an adjacent Dow Chemical facility, in the wake of the Houston-Galveston area’s dubious capture of the title “Smog Capital of the US” during the past few years. NOx emissions, in particular, contribute to the development of smog—formation of environmentally harmful ground-level ozone when NOx combines with volatile organic compounds, such as gasoline vapors, and the pollutants get trapped near ground level by a combination of stagnant air and sunlight. The Houston-Galveston-Brazoria area—home to the nation’s largest concentration of chemical processing plants—is designated a “non-attainment area,” as it currently does not meet 1990 Clean Air Act standards for ozone, compelling the Texas Commission on Environmental Quality (TCEQ) to submit a plan for attainment of the federal one-hour ozone standard by 2007. In addition, the area must attain a more stringent federal eight-hour standard with further NOx reductions between 2010 and 2013.
Patrick Blanchard, director of safety, health, and environment for Calpine’s Electric Reliability Council of Texas (ERCOT), acknowledges that the TCEQ’s as-yet-undetermined strategy for adherence to the EPA’s more stringent eight-hour ozone standard added a complication to the plant’s retrofit. “Rather than go back and reinvent the wheel, we anticipate that they will be required to further limit the amount of allowances that are allocated to facilities,” he says. “We’re still a little ways out from being able to look into our crystal ball so we can see what our future allocation rights will be.”
Operations, such as the Texas City power plant, are allocated allowances for emission of NOx based on the area-attainment plan. (A ton of NOx equals one NOx allowance.) These operations can purchase additional allowances, or roll over or sell unused allowances on the open market at the end of a year, depending on the chosen strategy for managing the problem.
According to Ron Anselmo, P.E., a commercial manager for ERCOT, the market forces at play made purchasing credits not viable from a business standpoint. It would even be possible to purchase a “stream” of allowances allowing the emission of NOx in perpetuity, but this carried an unacceptably high cost of $40,000 per ton. A much better solution would be reducing NOx emissions. There was more than one way to achieve this, however.
The Choice of Technology
Anselmo notes that two technologies were available to reduce the NOx to an acceptable level. A proven technology is selective catalytic reduction (SCR), which involves the injection of ammonia into a plant’s exhaust gas. In the presence of a catalyst, the ammonia reacts with the gas to produce environmentally harmless nitrogen and water vapor. The other available technology was dry low NOx (DLN), which pre-mixes the plant fuel with air in a separate chamber prior to ignition, allowing for a lower burning temperature—producing less NOx.
SCR is a proven technology with which Calpine is familiar. DLN is a technology with which management was familiar enough; however, its superior cost-effectiveness began to emerge as Calpine began to compare the alternatives.
Anselmo notes that it quickly became clear that the SCR option would be considerably more complicated than the DLN alternative. Characteristic of capital planning, initial cost wasn’t the only issue. The biggest complications were site space restrictions and construction time. For one thing, the design of the existing heat recovery steam generators (HRSGs) wouldn’t allow for retrofitting with SCR equipment; entirely new HRSGs would have to be installed. While this upgrade would increase the plant output, it would further restrict the already limited floor space in the plant.
“For the HRSGs, we had to look at buying new equipment; you had to go out and construct that equipment, and you’ve got to have more space for that equipment,” Anselmo says. “One thing we don’t have is a lot of space on the property. With our timeline, we thought that with HRSG we could meet the timeline but we’d probably have more risk if we had a construction problem.
“The downsides we saw with HRSG were primarily space—it’s less cost compared to the DLN technology—and construction time. The biggest drivers were space and construction time. If we had done the HRSG project, we could have increased the capacity of the plant, but our main goal was to fix the environmental problem.”
Despite the fact that it requires a conversion of existing turbines, DLN technology carried a few concerns, too. “For DLN, the downside was that we didn’t know if we’d have the flexibility that we’d have with the HRSG,” he says. “We know how the turbines run now, but we didn’t know how they’d run with the LEC system.”
But a huge factor in Calpine’s decision to go with DLN was the experience its wholly owned Power Systems Mfg. LLC (PSM) subsidiary has with the technology. PSM engineers not only gas turbines but also military jet engines using an ISO 9001:2000–qualified design process.
A couple of years earlier, PSM had installed its patented low-emissions LEC-III combustion system at Dow’s Oyster Creek plant in Freeport, TX, and achieved a baseline 4.75-ppm NOx versus a required 5.0 ppm—a 62% reduction in addition to a 100% carbon dioxide reduction.
“I think, at the end of the day, PSM has proven to be a huge resource for Calpine,” says Anselmo. “Those guys definitely have the competence to build the hardware. They build airplane turbines, and we all know that they’re very efficient and very reliable. That gave us a lot of confidence internally.”
At Texas City, PSM installed its LEC-III system in a 501D5 combustion turbine generator designed by Siemens Westinghouse and manufactured by Mitsubishi. PSM’s Vice President of Commercial Operations Pat Conroy notes that the project team was entering new territory on this project in one respect. “That was our first 501D5,” he says. “The D5 has a different envelope from the GE 7A model we had retrofitted before, a different pressure boundary, and we had to make changes to that boundary and replace the pressure combustor case, and make a couple of other pressure components in order to accommodate our particular hardware. All in all, when Calpine and the Texas City folks evaluated the cost, it was still more cost-effective to put in a DLN system like the LEC-III than to go with an SCR.” It was estimated that the installed cost and operation of the DLN would save Calpine $36 million versus an SCR system.
Another plus in using DLN technology was that Calpine was able to reduce carbon dioxide emissions to single digits. Achieving reductions in both NOx and carbon dioxide can be an engineering challenge, however.
“You have to have sufficient time with the carbon monoxide at a high enough temperature so that it will oxidize the carbon dioxide,” says Conroy. “At the same time, this temperature can’t be so high as to promote excessive NOx formation. The engineering trick is that you can have different zones in the combustor to where if you haven’t mixed your fuel and air properly, you might have a streak, a pathway through that combustion system that may generate a lot of NOx. When you average that out in the exhaust, instead of having 5 parts per million of NOx, you might have 15 parts per million. At the same time in the same combustor, you could have a cold streak, where you’re letting a lot of unreacted carbon monoxide escape. So you could have the worst of both worlds if it weren’t devised, installed, and tuned properly. It’s engineering and attention to detail that has allowed these premix systems to evolve from 25 parts per million of NOx, and 20, 30, and 40 parts per million of carbon monoxide 10 years ago down to what we now have in service.”
Down to Business
The existing plant consisted of the three 501D5 combustion turbine generators (CTGs), three HRSGs, a condensing/extraction 141-MW Hitachi steam turbine generator (STG), a mechanical draft cooling tower, and other ancillary equipment. The facility interconnects to the ERCOT grid via 138-kV transmission lines. The facility’s CTGs were originally equipped with a steam-injection combustion system designed to maintain NOx emissions at 42 ppm when firing natural gas at base load and injecting 870,000 pounds per hour of steam into the CTGs. In order for the facility to achieve the required 80% NOx emissions reduction, it would have to achieve less than 9 ppm emissions.
PSM provided all of the “hot section” (fuel injection) and steam conversion hardware, as well as site engineers for technical direction and tuning/commissioning. The Texas City facility provided the overall construction management, including millwright support, and onsite control technicians and electricians to support the installation of the controls equipment for the outage. The facility also managed standard wiring, conduit and related electrical hardware for the controls installation, and the insulation for the engine cases and piping.
Conroy acknowledges some of the challenges that resulted from retrofitting the 501D5 compared with the General Electric turbines with which it had considerable previous experience retrofitting. Converting a turbine like the 501D5 “requires substantially more work replacing different components, adding fuel manifolds, fuel management skids—generally speaking, adding more horsepower and modernizing it. There are a lot of site specifics. There are also a lot of model-specific differences.
“There was a good amount of detail and precise preparation and engineering,” Conroy adds. “That occupied a considerable amount of time by our folks, plus the folks on the site, because all of these power plants are always one-of-a-kind installations—they’re always part of a larger integrated system. We worked closely with the plant staff to make sure that the physical stuff was all right, and then we did have to upgrade the control system because the control system on the machine was probably 20 years old. That had to be upgraded substantially in order to get the additional processing power that’s needed to manage a DLN-type combustion system; that combustion system is integrated into the control algorithms that control the gas turbines. It’s not a matter of digital pulses or voltage; it’s much more complex than that because you’ve got to start the machine up, you’ve got to transition between modes, so it was a substantial amount of work.”
Fine-Tuning Integration
“The control manufacturer, Emerson, which is a spin-off of Westinghouse, was the original control supplier,” notes Conroy. “They’re pretty familiar with those old-style Westinghouse controllers, so that helped. We provided the logic to them. Also, the plant people provided the required interactions for the control system between what’s called the balance of the plant, the rest of the power system, and the gas turbine control, so that was at least a three-way interaction. And then you’ve got to physically install it; you’ve got a lot of wires that have to be disconnected and reconnected, and the ones that have been in there for 20 years, you’ve got to make sure they’re not too corroded. All of this had to be done on a restricted space environment.”
However, in Conroy’s previous experience, as well as in the case of Texas City, the LEC technology has also had much less impact on the plant’s controls once it’s in operation versus SCR. “It’s pretty transparent to the operators,” he says. “That’s one of the reasons why people like our system over the SCR. When you go with SCR, you’re putting a chemical processing unit on the back of that machine, so you have to handle ammonia, and you’ve got a vaporization skid, blowers, hardware that you not only have to buy, but you’ve got to tune, test, et cetera. What we do to the gas turbine doesn’t add much to the part count, doesn’t make the operator’s control of the control panel any different. It doesn’t substantially increase the inspection and maintenance burden on the crew, either.”
An Industry First
Retrofit work on the first turbine began March 3, 2005, and its first firing was April 16, 2005. The plant ran at partial capacity during this time, which coincided with its off-peak season. In 2006, Calpine anticipates that retrofitting of the remaining two turbines will be complete, providing plenty of margin for meeting the 2007 requirements. By the conclusion of the project, PSM and Calpine had achieved an industry first by reducing NOx emissions from a natural gas–fired 501D5 turbine while reducing carbon dioxide emissions. The LEC technology lowered NOx emissions at normal operation at baseload beyond expectations, to less than 8 ppm. This more than met the 80% NOx reduction requirement.
An additional benefit resulting from the retrofit is water savings. The old system lost about 150 gpm of demineralized water per turbine up the exhaust stack at base load. Today, with the PSM LEC-III system in place, TCC is no longer losing that quantity of demineralized water to the atmosphere.
While DLN was the right solution for this project, Conroy points out that both DLN and SCR have respective advantages. In fact, Conroy maintains that SCR generally provides greater reductions in NOx and suits permits in areas with greater NOx emission restrictions than does DLN. “Given the limitations of both of those types of technologies, you’re not going to see one replace the other anytime soon,” he says. “SCR can get the tailpipe NOx coming out of the back end of a system lower than the DLN can. You’re talking about 3 parts per million in our best systems, and you see SCRs at 2 [parts per million]; you’re wringing the last bit of NOx out of the system. The costs of doing that tend to escalate, though.
“One of the things our customers really like to not have to deal with is the operation and maintenance of the SCR. Also, the fact that the type of SCR we’re talking about requires you to have a steam recovery boiler that needs gas in the 400 to 600--degree-Fahrenheit range, whereas the exhaust gas out of the turbine is more like 900 to 1,000 degrees Fahrenheit. You need to cool that gas off, and it takes a heat recovery steam generator that takes that heat and converts it into useful energy in the form of steam, or you can put in huge air dilution blowers that force ambient air into the exhaust steam to lower the temperature. You’re talking hundreds of horsepower just to blow this air into the exhaust to lower the temperature.”
In the case of Texas City, though, DLN was the clear choice from both an environmental and economic standpoint.
“It boiled down to a viable economic decision that would be cost-effective internally but also satisfy the NOx requirements going forward, such that it wouldn’t interrupt our business and keep our steam hosts and our market provider whole,” Blanchard concludes.