Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 1 COMBUSTION TURBINE POINT SO URCE CATEGORY 4-FACTOR ANALYSIS I. Source Description

Combustion turbines fueled by natural gas or oil are either co -located with coal-fired electric generating units or as stand-alone fac ilities. These units are primarily used to supplement power supply during peak demand perio ds when electricity use is highest. Combustion turbine units start quickly and usually operate only for a short time. However, they are capable of operating fo r extended periods. Combustion turbine units are also capable of operati ng together or independently.

Information regarding combustion turbine emissions is well recorded in the State’s air emissions inventory. Typical emissions for this source type may be significant for NOx, but pipeline quality natural gas is inher ently clean and low-emi tting for SO2 and PM10 emissions. Combustion turbines are subject to 40 CFR Part 60, Subpart GG – Standards of Performance for Stationary Gas Tu rbines, which limit sulfur content to 0.8 percent by weight, support ed by monitoring and testing. Subpart GG also limits nitrogen oxides to 117.8 percent by volu me at 15 percent oxygen on a dry basis (60.332(a)(1)), supported by monitoring and te sting. The majori ty of combustion turbines are installed with Continuous Emissions Monitoring Systems (CEMs).

Control strategies for th is source category are: NOx – Steam or water injection, adv anced dry low NOx co mbustion system, and selective catalytic reduction (SCR)

Cumulatively, this emissions source cat egory is projected to be a minimal single category of Colorado point source s with a total of 56 turbines. Of this total, turbines located as single sources at Reasonable Progr ess facilities are 18. Total state-wide NO x emissions (2007 inventory) are approxim ately 284,037 tons/year. This source category is about 0.7% of tota l statewide emissions; theref ore, the Division considers this source category to be nominal. Regardl ess, the Division eval uated all combustion turbines, regardless of fuel type, at Reasonable Progress fa cilities. The majority of combustion turbines (assumed 17 out of 18 based on inventory limit ations) are naturalgas fired.

II. Source Emissions

Pollutant Total 2006 – 2008 Averaged Annual

Emissions (tpy) Total RP Turbine 2006 – 2008 Averaged Annual

Emissions (tpy) RP Turbine Emissions compared to total state-wide turbine emissions (%)

NO 2 2,003 473 24%

The Division analyzed total stat e-wide combustion turbine emissions averaged over the 2006 – 2008 Reasonable Progress baseline period. There are 5 Reasonable Progress facilities with combustion turbines – PSCo Valmont Generating Stat ion, PSCo ArapahoeColorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 2 Generating Station, Colorado Sp rings Utilities Nixon Plant, Pl atte River Power Authority Rawhide Energy Station, and PSCo Pawnee Generating Station. Of these, only two emit over federal significanc e levels as depicted below.

For the purposes of evaluating RP, the Division has elected to set de minimis thresholds for any emission unit at a subject-to-RP s ource with actual base line emissions of NO x equal to or exceeding the f ederal Prevention of Signifi cant Deterioration (PSD) significance levels. The Division has established de minimis thresholds for SO 2 , NO x and PM 10 to focus the technical emission co ntrol analysis on significant emission sources where potential controls could provi de a meaningful improvem ent in visibility if emission controls are determi ned to be cost effective.

The de minimis levels are applicable to individual em ission units at a stationary source. The Division defines “emissions unit” as “any par t or activity of a stationary source that emits or has the potential to emit any air pollutant regulat ed under the state or Federal Acts. This term is not meant to alter or a ffect the definition of the term “unit” for purposes of Title IV (acid deposit ion control) of the federal act, or of the term “source” for purposes of the Air Pollut ant Emission Notice requirement s of Regulation Number 3, Part A, Section II.B.3. 1 .” These de minimis levels are as follows:

• NO x – 40 tons per year

• SO 2 – 40 tons per year

• PM 10 – 15 tons per year

Facility – Turbine Total 2006 – 2008 Averaged NOx Annual Emissions (tpy) Total 2006 – 2008 Averaged

SO2 Annual Emissions (tpy) Total 2006 – 2008 Averaged PM10 Annual

Emissions (tpy) Greater than de minimis levels?

Valmont – Turbine #6 12.6 0.4 0.1 No

Valmont – Turbine #7 27.4 0.2 2.8 No

Valmont – Turbine #8 1.5 0.0 0.1 No

Arapahoe – Turbine #5 25.5 0.4 5.0 No

Arapahoe – Turbine #6 15.3 0.4 5.0 No

Arapahoe –

Turbine 4.1 0.2 3.7 No

Nixon – Turbine #2 0.7 0.0 0.2 No

Nixon – Turbine #3 1.2 0.0 0.3 No

Nixon – Front Range Power 159.6 2.9 4.9 Yes – NOx only

1 Colorado Department of Public Health and Environm ent. Air Quality Control Commission Common Provisions Regulation 5 CCR 1001-2. Amended December 17, 2009. Effective January 30, 2010. Page 19.Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 3 Plant – Turbine #1 Nixon – Front Range Power Plant – Turbine #2 147.9 2.8 4.9 Yes – NOx only

Rawhide Turbine A 2.5 0.1 0.5 No

Rawhide Turbine B 4.0 0.1 0.8 No

Rawhide Turbine C 2.7 0.1 0.5 No

Rawhide Turbine D 2.9 0.1 0.5 No

Pawnee – Turbine #1 25.4 0.3 3.3 No

Pawnee – Turbine #2 25.0 0.2 2.7 No

Therefore, for the purposes of this RP planning period, the Division will evaluate the Nixon – Front Range Power Plant – Turbines #1 and #2 as they are the two combustion turbines emitting over de minimis levels.

III. Control Technology Evaluation

Step 1: Identify All Available Technologies

Four technologies have been identified to lo wer emissions from combustion turbines:

1. Wet controls using steam or water inje ction to reduce combustion temperatures for NOx control

2. Dry controls using advanced combustor design to suppress NOx formation and/or promote CO burnout

3. Adding post combustion technology – selective non-catalytic reduction (SNCR) or selective catalytic reduction (SCR)

Technology #2: This technology (retrofitting with lo w-NOx burners) was identified by the EPA and is documented in the AP-42 “Com pilation of Air Pollutant Emission Factors.” The following is from the 5 th Edition, Volume 1, Chapt er 1, Section 3.1.4.1: “Water or steam injection is a technology that has been demonstrated to effectively suppress NOx emissions from gas turbines. The effect of steam and wa ter injection is to increase the thermal mass by dilution and t hereby reduce peak temperatures in the flame zone. With water injection, there is an additional benefit of absorbing the latent heat of vaporization from the fl ame zone. Water or steam is typically injected at a waterto-fuel weight ratio of less than one.”

Technology #3: This technology was identified by the EPA and is documented in the AP-42 “Compilation of Air Pollutant Emission Factors.” The followi ng is from the 5 thColorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 4 Edition, Volume 1, Chapter 1, Section 3.1.4.2: “Since thermal NOX is a function of both temperature (exponentially) and time (linearly), the basis of dry cont rols are to either lower the combustor temperature using lean mi xtures of air and/or fuel staging, or decrease the residence time of the combusto r. A combination of methods may be used to reduce NOx emissions such as lean co mbustion and staged combustion (two stage lean/lean combustion or two st age rich/lean combustion).

Lean combustion involves increasing the air-to-fuel ratio of the mixture so that the peak and average temperatures within the co mbustor will be less t han that of the stoichiometric mixture, thus suppressing t hermal NOX formation. Introducing excess air not only creates a leaner mixture but it also can reduce residence time at peak temperatures.

Two-stage lean/lean combustors are essentially fuel-staged, premixed combustors in which each stage burns lean. The two-stage l ean/lean combustor allows the turbine to operate with an extremely l ean mixture while ensuring a stable flame. A small stoichiometric pilot flame ignites the premix ed gas and provides flame stability. The NOx emissions associated with the high temperature pilot flame are insignificant. Low NOx emission levels are achieved by this combustor design through cooler flame temperatures associated with lean combus tion and avoidance of localized "hot spots" by premixing the fuel and air.

Two stage rich/lean combustors are essentia lly air-staged, premixed combustors in which the primary zone is operated fuel ri ch and the secondary zone is operated fuel lean. The rich mixture produces lower tem peratures (compared to stoichiometric) and higher concentrations of CO and H2, because of incomplete combustion. The rich mixture also decreases the amount of ox ygen available for NOx generation. Before entering the secondary zone, the exhaus t of the primary zone is quenched (to extinguish the flame) by la rge amounts of air and a lean mi xture is created. The lean mixture is pre-ignited and the combustion completed in the secondary zone. NOx formation in the second stage are minimized through combustion in a fuel lean, lower temperature environment. Staged combustion is identified through a variety of names, including Dry-Low NOx (DLN), Dry-Low Emissions (DLE), or SoLoNOx.”

Technology #4 : This technology (adding SNCR or SCR) involves adding control equipment and reagent to treat turbine exhaust.

Step 2: Eliminate Techni cally Infeasible Options

Technology #1: This technology is technically feasible.

Technology #2: This technology is technically feasible.

Technology #3: This technology is technically feasib le and is already installed at the Nixon – Front Range Power Plant combustion turbines.

Technology #4: This technology is technically feasible, although a Division of the EPA’s RBLC database revealed SCR is t he predominant post-combustion control technology for combustion turbines and di d not find any examples of SNCR postcombustion technology applied to combustion turbines.Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 5 Step 3: Evaluate Control Effectiveness of Each Remaining Control Technology

Technology #1: Since this control technology is specific fuel type usage, control efficiency are not applicable.

Technology #2: EPA’s AP-42 factor database cites this technology as achieving control efficiencies of 60% or greater. However, this technology will not be evaluated in this analysis further since the dry low-NOx co mbustion systems already installed on the turbines at the Front Range Power Plant achieve greater than 85% control, which is greater than the 60% estimate achievable by wet controls.

Technology #3: The Division calculated that the controlled-uncontrolled ratio for advanced dry-low NOx combus tions using EPA’s AP-42 emission factors is approximately 70% and may be greater in site-s pecific cases. The combustion turbines at the Nixon – Front Range Power Plant we re installed with these systems, and based on 2006 – 2008 CEMs data and AP-42 emission factors, are achieving 89.4% and 90.1% NOx reductions (calculated usi ng the 2006 – 2008 RP baseline period), respectively.

Technology #4: EPA’s AP-42 emission factor descripti on indicates that a SCR in good working order can achieve removal efficienci es ranging from 65 – 90 percent from the NOx exhaust stream. AP-42 is silent on control efficienc ies regarding SNCR. During a research review, the Division could not find any instances of a commercial-scale SNCR applied at a natural-gas fired combusti on turbine. Therefore, SNCR will not be considered further in this analysis.

Step 4: Evaluate Impacts and Document Results

The Division reasons that SCR requires significant capital ex penditures and will result in minimal additional NOx reducti ons, if any. Regardless, the Division analyzed additional achievable NOx reductions if SCR was install ed at these two turbines. Applying SCR at 90% to both turbines would result in about 275 additional tons of NOx reduced annually. Using another Colorado SCR analysis from t he same utility (Colorado Springs Utilities), the Division estimates that annualized costs for installing SCR to both turbines will be approximately $8 million each, resulting in about $57,000 - $62,000 per ton of NOx reduced annually.

The time necessary for compliance will depend on the type of control implemented. Based on other Colorado facility submittals, the Division anticipates that the time necessary for completing design, permitting, procurement, pipeline installation, and system startup and shutdown, af ter SIP approval, it would take CSU approximately 3 – 5 years to implement any of the SCR cont rol option. This timeframe may vary somewhat due to regional demand for natural gas and to schedule the necessary major maintenance outage with other r egionally affected utilities.

There are no energy or non-air quality impacts for fuel usage of pipeline quality natural gas or for advanced dry low-NOx combustion systems. The energy and non-air quality impacts of SCR and SNCR ar e increased power needs, potential for ammonia slip, potential for visible emissions, haza rdous materials storage and handling.Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 6 There are no remaining useful life issues for the alternatives as the sources will remain in service for the 20-y ear amortization period.

Step 5: Select Reasonable Progress Control

The Division determines that any potential r eductions from this source category are minimal, if any. Pipeline quality natural gas is inherently clean for SO2 and PM10. For NOx, the majority of combustion turb ines already apply advanced dry-low NOx combustion systems, especially the larger turbines.

Based on its consideration of the four factors summarized her ein, the state has determined that NOx RP for combustion turb ines is existing controls and emission limits. Though other controls achieve better emission reductions, the expense of these options coupled with predicted minimal visi bility improvement were determined to be excessive.