PLANNING UPGRADES: Evaluate the regulatory impacts of upgrades before you buy

These are tough times for electric utilities. Many people seem to believe they know more about the business of producing and delivering electricity than company executives, who are challenged daily by demanding questions and opinions from regulators, politicians, customers, special-interest groups, and others about everything from species displaced by new infrastructure to the unfair price of electricity produced “free” from solar and wind resources.

Having both viable and politically correct answers to questions yet not thought of is part of the job. For the generation side of the business, this requires a living plan for producing power five, 10, and 15 or more years from now at competitive prices and consistent with unspecified regulatory requirements. Variables and unknowns should be evaluated independently and often to provide the most accurate and current information to executives on the front lines and for inclusion into integrated resource plans required by state authorities.

One ongoing study at NV Energy, and probably many other generators as well, involves identifying possible upgrades for existing assets capable of satisfying near-term increases in demand and delaying the need for new resources.

Staff Engineer Susan Hill provided users attending the respected Regulatory and Compliance Roundtable at CTOTF’s™ 38th annual Spring Turbine Users Conference (April 2013) a valuable methodology for doing this. Generation strategy is one of Hill’s responsibilities at NV Energy. The Georgia Tech chemical engineer has more than 15 years of experience in power-generation operations and process optimization in the utility, pulp-and-paper, and pharmaceutical industries.

Upgrade options now being considered by NV Energy include these:

• Cooling of compressor inlet air using absorption or mechanical chillers, or inlet fogging. Each of these enhancements boosts compressor mass flow, which increases power production. Adding thermal-storage capability to a chiller package can further improve performance by reducing chiller size and shifting power consumption to off-peak hours. The latter provides more power for sale during peak periods.

• Engine performance improvements offered by OEMs and third-party providers. Examples include:

1. A Siemens FD3 upgrade for the utility’s four 501FD2 gas turbines.

2. Replacing hot-gas-path (HGP) parts in NV Energy’s eight 7FAs to those provided in GE’s Dot-04 package.

3. Upgrading HGP parts on all F-class frames with a third-party supplier’s latest offerings.

4. Adding GE’s OpFlex to improve the operating flexibility and performance of the company’s 7FAs.

Using TurboPHASE™ to boost peak output and respond quickly to grid requirements.

• Power augmentation by injection of steam or water to increase compressor mass flow.

• Addition of PV capability where switchyard capacity is available.

• Replacement of seals and hardware on steam turbines to return the machines to as-new condition.

• Addition of wet cooling capability to plants served exclusively by air-cooled condensers, to reduce backpressure and increase generation when ambient temperatures are highest.

• Installation of a packaged boiler to take advantage of unused steam-turbine capacity.

Key steps in the process outlined by Hill and co-presenter Jonathon Bader, PE, of Sega Inc, an engineering firm, were the following:

• Identify possible upgrades.

• Identify any plant limitations.

• Perform high-level design of upgrades for applicable units.

• Determine potential capacity increase for each upgrade.

• Assess upgrades for complexity.

• Estimate lead times for projects.

• Evaluate environmental/permitting limitations.

• Determine controls upgrades required, if any.

The next level of investigation involved these tasks, among others:

• Evaluate the candidate facility’s balance-of-plant infrastructure for supporting the proposed upgrade.

• Use thermal engineering software to gauge performance.

• Estimate capital cost and the incremental increase in plant variable costs.

• Conduct an environmental assessment that evaluates the possible impacts of the following environmental statutes: PSD (Prevention of Significant Deterioration)/BACT (Best Available Control Technology), NSR (New Source Review), NSPS (New Source Performance Standards).

The environmental assessment portion of Hill’s presentation was of particular interest to attendees who had never participated in PSD, NSR, and/or NSPS evaluations. What quickly became apparent was that no particular upgrade could be applied across the utility’s fleet with equal success. One reason for this is the many locations of the company’s generation assets and the different rules that can apply to each. To illustrate: About three-quarters of NV Energy’s capacity is in southern Nevada, specifically Clark County; most of the remainder is in northern Nevada, relatively close to Reno. Some Clark County assets are in PM10 non-attainment areas; plus, ozone rules are not well defined for the county going forward. Northern plants are in an attainment area.

PSD analysis needed? One of the first questions you should ask when evaluating upgrade options is, “Will it trigger PSD analysis?” PSD rules, Hill pointed out, apply to both attainment and non-attainment areas and analysis is required if your project results in a significant increase in emissions. The next question likely is, “What is significant?” To determine that, compare the potential increases in emissions of criteria pollutants attributed to the upgrade with the “significant emission rate” (SER) in tons per year for each pollutant as specified in the PSD rules. These numbers are as follows: PM10, 15 tons/yr; PM2.5, 10; NOx, 40; VOC, 40; CO, 100; CO2e, 75,000.

In case you read through the list quickly, take note of the last entry. Greenhouse gases (GHG)—including CO2, CH4, N2O, SF6, and certain fluorocarbons—became regulated under the federal Clean Air Act in 2011. The CO2e designation stands for carbon-dioxide equivalency or the amount of CO2 that has the same global warming potential as the mixture of greenhouse gases.

The bottom line: If the emissions after the upgrade exceed the pre-upgrade emissions by more than the SER, PSD analysis is necessary, Hill said. The next question probably is, “What does PSD analysis involve?” According to Hill, it means (1) air dispersion modeling for NAAQS (National Ambient Air Quality Standards) and PSD, and possibly ambient-air modeling as well, and (2) BACT review and possibly installation. Even if the upgraded facility satisfies BACT, she said, the process adds time and expense to the project.

In sum, Hill stressed that if PSD analysis is required for upgrading a relatively new unit the best outcome is a longer permitting process, later project implementation, and higher cost; the worst, modification of existing controls. For older units, expect that you’ll have to install BACT, which probably means a sizeable investment.

NSR is another hurdle that must be cleared. It is applicable to construction or modification of a major stationary source. The obvious question from anyone considering an upgrade is, “What is meant by modification?” Colin Campbell of RTP Environmental Associates Inc, who presented on the challenges of NSR during the same session as Hill, said that “modification” as defined by Congress was, “Any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously.”

EPA’s “major modification” definition in NSR rules is narrower and more specific, he continued. Specifically, (1) It allows for exclusions for some types of changes—for example, routine maintenance/repair/replacement, (2) It establishes de minimis exemption levels for emissions, and (3) It clarifies that emissions increases are determined based on actual annual emissions.

But that’s not all. Campbell said that after much litigation, the current status is that (1) exclusions must be interpreted narrowly, consistent with Congressional intent, and (2) whether maintenance/repair/replacement is routine or not may be based on the nature, extent, purpose, frequency, and cost of the project. Apparently, upgraded replacement components—such as HGP parts—could be considered a “major modification,” in at least some cases. However, the deal breaker for many upgrade projects might well be GHG.

Next steps. Hill began wrapping up by asking, “Now we know the ‘triggers’ for additional permitting and possibly capital, how do we estimate without a full detailed emission analysis?” The answer, she said, it to make some simplifying assumptions and calculations, such as these:

• Assume emissions in pounds per million Btu of heat input will not change.

• Calculate the fuel increase required by upgrade under consideration.

• Assume a number of operating hours at the higher rate of fuel input.

• Calculate the increase in pollutant emissions and compare them with the SER and other “triggers.”

• Highlight those projects that come within 50% and 100% of SER.

Then rank projects based on cost and risk and decide which ones to take to the next level of evaluation, which involves the following:

• Detailed engineering.

• Detailed review of permitting implications—including potential changes in SCR performance.

• Develop performance curves for use in production cost modeling to quantify the benefit of each proposed project in the dispatch model. ccj