Technical Memorandum

To:		EPA

Title:	Techno-economic analysis of current technology for Fischer-Tropsch fuels production

Author:		Ryan Davis

Date:		August 14, 2009

Abstract
The purpose of this study is to evaluate the economics of a biomass-based Fischer Tropsch (FT) plant, based on publicly available literature and engineering data.  The focus for the plant is on maximum production of liquid fuels (specifically diesel) consistent with recent developments in FT synthesis.  The basis for the process was the 2007 NREL thermochemical ethanol design report [1], which utilized low pressure indirect steam gasification in a 2,000 dry tonne/day plant processing hybrid poplar wood chips, and serves as the same starting point for the FT model.  The design report established specific design targets thought to be achievable by the year 2015, while the FT modifications contain somewhat optimistic assumptions that would be reflective of a "best-case" type of scenario; thus, it was decided that this study would be appropriate for operation commencing in the year 2022.  Upon completing the base case scenario, the minimum required diesel selling price to achieve a target 10% IRR was found to be $2.06/gallon.  Of the various sensitivity parameters evaluated, the areas with the largest impact on diesel price are synthesis conversion extent, feed price, and coproduct values.

Keywords: 	Fischer Tropsch, state of technology, techno-economic, diesel, fuel

Introduction
As noted above, the basis for this study was the 2007 NREL thermochemical ethanol design report.  Based on previous NREL studies comparing the various gasification options, it was decided that the same gasification scheme would be used here, thus the design report model served as a starting point and was modified as appropriate for Fischer Tropsch fuels.  Modifications were made to the tar reformer, gas cleanup, and steam sections, while most of the synthesis and separation sections were replaced altogether as described below.  Very few changes were required in the front-end sections of the plant and the same base feedstock type and cost ($50.70/dry ton) was assumed.  Additionally the same plant capacity factor (96% = 8,406 operating hours/year) was assumed, and the original assumption of 100% equity financing was not changed.

The basic flow scheme for this process is as follows: the feed is delivered to the plant, dried and gasified in the same manner as described in the design report.  The dirty syngas is fed to the tar reformer which operates under the same conditions as the base model, with the exception that more steam is fed to the reformer to adjust the H2/CO ratio to that required for FT.  The syngas then passes through the quench section and compressors (which were left unchanged), before feeding to the amine scrubbing unit which removes H2S to a lower level (20 ppmv vs 50 ppmv previously).  H2S is then further removed to sub-ppm levels using a zinc oxide guard bed, and a small slip-stream is sent through a PSA to provide hydrogen for downstream hydroprocessing.  The majority of the material is fed to a slurry column synthesis reactor, which converts the syngas to a range of fuel-range hydrocarbons and wax.  The wax is sent to a hydrocracker to upgrade it to additional fuel-range material, while the lighter hydrocarbons are cooled and knocked out from the unconverted syngas, the latter of which is sent to an expander and recycled to the tar reformer area, as was done in the ethanol model.  The liquid hydrocarbons and hydrocracker products are sent to a fractionator to separate the products into light gases, naphtha, diesel and residual wax.  Each of these steps, as well as the underlying process and costing assumptions, are described in more detail in the following sections.

Process Descriptions and Major Assumptions for Model/Cost
As described previously, the front-end sections (feed preparation, gasification and char combustion) were left essentially unchanged, and their process descriptions can be found in the NREL thermochemical design report.  The feed is assumed to enter the plant at a cost of $50.70/dry ton, consistent with the updated price for the base model.  The following sections describe changes made to the downstream units of the model and their underlying assumptions.

Area 300: Conditioning
The assumptions made in A300 are summarized as follows and described in more detail below:
   * Tar reformer: Larger steam feed than necessary for reforming is not a problem for catalyst
   * Still meeting all steam/power requirements internally, even though steam demand is higher here and requires combustion of more syngas at the tar reformer regenerator
   * MEA is still preferred amine type; MEA CO2/H2S selectivity = 1
   * Increased amine unit cost associated with more acid gas removal was incorporated by scaling the original cost by the ratio of new/original total inlet flow (syngas + amine)
   * Steam methane reforming unit is not warranted (some studies include it to increase syngas yield, but CH4 is not present in substantial amounts here)
   * NH3 removal is sufficient in existing quench scrubber
   * No COS hydrolisation unit required
   * No dedicated CO2 removal step required

The "Conditioning" section includes the tar reformer, quench, acid gas removal, and sulfur removal.  The quench and sulfur removal sections were left unchanged, and any differences in those areas relative to the original model were a result of new inputs to either section.  The tar reformer operating conditions and specifications were also left unchanged, however the steam feed was increased substantially.  While the syngas into the tar reformer has a H - 2 - /CO ratio close to 0.6, cobalt-based FT synthesis requires a ratio of 2.1 [2].  This can be met by utilizing a water-gas shift (WGS) reactor to favor H2 production at the expense of CO via the reaction: CO + H2O <--> CO2 + H2 .  However, the tar reformer catalyst also maintains WGS activity, so it was decided it would be beneficial to save on the capital cost for a dedicated WGS reactor by utilizing the reformer catalyst's WGS capability to meet the synthesis composition requirements.  Thus a design specification was created to increase steam to a rate that shifts the equilibrium for this reaction to achieve the proper syngas ratio.  An implicit assumption here is that excess steam does not hinder the reactor's capacity to crack heavy components (tars), which should be valid as steam is also required to reform the hydrocarbon components.

The tar reformer catalyst regenerator was also left unchanged, but operates at a higher temperature to satisfy increased steam demands and close the heat balance; the assumption here is that the plant remains electricity-neutral and meets all internal power requirements by burning process material.  Thus since steam demands are higher in this model, more of the raw syngas as well as the recycled unconverted gas from the synthesis reactor must be diverted to the regenerator.  This ultimately results in lower product yields and decreased overall plant efficiency relative to the ethanol model.

The acid gas cleanup unit was also left mostly unchanged, but has higher internal traffic.  While the ethanol synthesis reactor had a sulfur limit of 50 ppmv H2S, the FT synthesis catalyst has a higher sulfur sensitivity and requires cleanup to ppb levels [3].  There are several options to achieve this, the most common being amine scrubbing followed by zinc oxide polishing, or physical absorption processes such as Selexol or Rectisol.  The amine/ZnO process was chosen here as Selexol has not been found to be favorable for H2S removal and Rectisol is too costly at the smaller scale of a biomass plant, compared to a larger coal-based FT plant [2].  A ZnO guard bed can readily remove H2S to the required level, but has an inlet sulfur limit of about 20 ppmv; thus the amine scrubbers must remove sulfur to this level first.

For consistency with previous NREL models, MEA was still assumed to be the chosen amine here.  MEA also removes the most CO - 2 of the conventional amines, which is useful here to minimize inerts (CO2) in the synthesis reactor, and thus reactor size.  Although MEA is slightly more selective for CO2 than H2S [4], selectivity was assumed to be 1 here as complete CO2 removal wouldn't be realistic.  As a result of a significantly larger H2S (and associated CO2) removal, the amine scrubber traffic and thus amine reboiler heating steam demand increased substantially over the base ethanol model.  Since the amine unit was originally costed as a total package, the associated increase in cost was calculated by scaling the original cost in the design report by new/original total traffic (inlet syngas + amine flow).

Additional cleanup considerations for selected components are shown in Table 1.  Although some studies include separate provisions for removing some of these components, it is assumed here that the existing units remove them sufficiently.

            Table 1: Considerations for additional FT contaminants
                                  Contaminant
                                FT requirement
                                  Discussion
                                  N (NH3/HCN)
                            <20 ppb total N [5]
Most other studies assume nitrogen compounds can be sufficiently removed in the existing quench scrubber; assuming the same here.
                                      COS
                            <10 ppb total S [5]
The NREL studies do not include a provision for COS formation, and it is assumed COS is not produced in significant amounts.  If trace amounts do form, COS can be removed to an extent in the ZnO bed [6].  If there were significant COS formation, the alternative would be to add a hydrolisation unit; it is assumed here that this is not necessary.
                                      CO2
                                      NA
CO2 is not a contaminant, but as an inert can increase reactor costs if it is present in large amounts.  Thus some studies have included provisions such as a Sulfinol unit to remove CO2.  However, CO2 removal may only be justified if over ~10% [5].  In this study, the concentration is only 1% due to co-removal with H2S in the MEA-based amine scrubber.

A400: Fuel Synthesis
The assumptions made in A400 are summarized as follows and described in more detail below:
   * No secondary compression required; compressors before amine section pressurize the syngas to an adequate pressure for proper FT performance
   * Zinc oxide beds: remove H2S to adequate levels, also remove any COS that may be present; equipment cost scaled from NREL H2 report (assuming two beds required); catalyst cost and amount also based on NREL H2 report
   * PSA unit: feed is set by H2 required for hydroprocessing, assuming 85% H2 recovery and >99.9% purity.  Cost is for total PSA "package" (assuming this accounts for total number of beds required as well as sorbent cost), and can be scaled from the NREL H2 study which was based on a much higher flowrate.  Since cost is on a flowrate basis, it is assumed that any periodic sorbent changeout (if required) is already included in the cost and is not costed separately.
   * FT synthesis reactor: 446F and ~27.5 bar operating conditions; conversion = 80% and selectivity α = 0.9, both set independent of reaction conditions but  based on "typical" performance that can be achieved in modern FT synthesis.  Reactor is cobalt-based slurry column reactor, and capital cost scaled from parameters given in other studies.  Catalyst cost was calculated using GHSV = 5800 std L/kg cat/hr, 3 year lifetime, $25/lb based on various sources.
   * Wax leaves synthesis reactor as a separate stream from the rest of the product and feeds to wax hydrocracker; hydrocracker cost was scaled from other studies and is assumed to include all equipment "inside battery limits" for the entire plant as well as associated catalyst costs.  Hydrocracker wax conversion = 90% with 70/30 wt% diesel/naphtha yield and 4% light ends.

The first A400 unit in the base model was a 2[nd] compression section to pressurize the clean syngas to 1,000 psia as required for alcohol synthesis.  However, modern slurry reactors for FT synthesis can operate as low as 20-25 bar (~300-350 psia) while still maintaining high selectivity and conversion [7].  Given that the first compression section in A300 pressurizes the syngas to 425 psia, the feed can already be delivered to the synthesis reactor at 400 psia after including pressure drop through the intermediate equipment; thus the second compressor section was eliminated.

The first new unit in A400 is the zinc oxide guard bed, which treats the residual H - 2S down to ppb levels according to the reaction  ZnO + H2S <--> ZnS + H2O .  The setup for this unit was based on the 2005 NREL H2 study [6], which set the inlet temperature to the reactor at 707 °F so that the reaction closely approaches equilibrium.  Thus the original reactor feed heat exchangers were used to increase the temperature to 707 °F before entering the guard bed.  Although there would still be traces of sulfur leaving the ZnO unit, complete removal was assumed for the purposes of the model.  Additionally, although COS is not expected to be present in significant amounts, the ZnO bed would remove small amounts of this species as well.  Cost for the ZnO reactor itself was scaled from the H2 study according to inlet rate, and it was assumed two beds would be required to allow for constant operation if one bed needs to be changed out.  The ZnO catalyst assumptions were also the same as in the H2 study, namely that the catalyst has a 5-year lifetime and costs $4.67/lb, and the required catalyst volume was calculated using GHSV=4000 hr[-1] based on standard flow conditions.

Following the ZnO beds, a small slipstream of clean syngas is diverted to a PSA unit to purify hydrogen for downstream hydroprocessing uses.  The PSA was also set up similar to the NREL H2 study, where the feed is first cooled to 110 °F and any water is knocked out, and H2 is produced at >99.9% purity (assumed 100% here) and 85% recovery.  Some of the purified hydrogen is recycled back to the PSA inlet given that typical PSA operation requires >70% hydrogen purity [6].  The PSA tail gas combines with the unconverted syngas from synthesis after the expander, and is recycled to the tar reformer section (this also sets the tail gas pressure).  The PSA cost was also determined by scaling the cost in the H2 study, which uses a $/scfd basis; it is assumed here that since the cost is already on a flow rate basis, any periodic sorbent changeout (if required) is already included in the overall cost, and there is not a separate provision for ongoing sorbent material expense.  Although the PSA section would contain several beds, this cost basis is for the total PSA "package."

The majority of the cleaned syngas leaving the ZnO unit feeds to the FT synthesis reactor.  The operating temperature of the synthesis reactor is set at 446 F based on various sources [5], and the operating pressure is 404 psia as discussed above.  It was decided to use a slurry reactor instead of a fixed-bed type due to its many advantages, such as much higher single-pass conversions (80% or more) in a relatively small reactor volume and superior control of the heat released from the exothermic reaction  CO + 2.1H2 --> -(CH2)- + H2O  [8].  Additionally, a cobalt-based catalyst was chosen over the iron-based alternative due to many advantages such as higher activity, higher diesel yields, and much longer catalyst life, which justifies its initial higher price [9].  As is done in most other FT studies, it is assumed that hydrocarbon component selectivity follows the Anderson-Schulz-Flory chain growth equation, which states that the molar yield of a given component with carbon number n is a function of α in the equation:
Cn=αn-11-α

The parameter α is dependent on the reactor conditions and type, and in modern cobalt-based slurry systems is around 0.9 or higher [7], where a higher value implies greater selectivity towards high carbon numbers (diesel and wax); for this study, a value for α = 0.9 was assumed.  The yields of C1-C4 were re-distributed to favor more methane and less of the others as is closer to reality [5].  The conversion was set to 80% which is also achievable in modern slurry reactor systems [8].  The operation of a slurry column reactor entails suspending fine catalyst particles in the product wax and bubbling syngas through the mixture, while removing heat through boiler feed water tubes running through the reactor to produce steam.  While the mechanism to separate product wax from the catalyst is not immediately clear, it is assumed that this operation is included in the "inside battery limits" cost for the FT reactor.  The cost was taken by scaling the size and cost based on parameters found in other studies, most of which reference a Bechtel analysis done for slurry-based FT systems [8].  The basis for cost scaling is described in the ethanol design report, and was also done here according to:

New Cost= Base CostNew SizeBase Sizef

As noted above, a cobalt-based catalyst was chosen for this study.  The required catalyst amount was calculated based on the report by Larson et al, which assumed a GHSV = 5800 std L/kg cat/hr for the FT reactor [8].  The cost for cobalt-based FT catalyst varied over a number of studies from $10-30/lb, with an industry source quoting $25-30/lb [10]; given this info, the cost assumed here was $25/lb.  Finally, the catalyst lifetime varied by source from 2.5-5 years; the lifetime assumed here was three years as this was the most common figure.

Following the fuel synthesis reactor, the wax material is sent to a wax hydrocracker while the rest of the product is cooled in a series of heat exchangers and knocked out to split the unconverted and light gases from the liquid product.  This is a similar scheme as the original base model, with the exception that the knockout drum is now three-phase as a result of large amounts of water produced from the FT reaction.  As this is a comparatively small cost, the new cost for a three-phase separator was estimated by adding 20% to the cost of a two-phase drum.  The water product is recycled back to the steam cycle, while the gas product is heated and expanded to recover electricity similar to the base model (the expander was left unchanged, but produces less electricity since the inlet pressure is lower than the ethanol case).  The PSA tail gas then joins this stream and the mixture is recycled back to the tar reformer and regenerator.  The liquid product is sent to a low-pressure flash drum prior to distillation, as was done before.

A400: Hydroprocessing
The wax produced from the synthesis reactor is sent to a wax hydrocracker, where it is upgraded to additional fuel-range material.  The hydrogen rate from the PSA was set such that the H2/liquid feed ratio was 1200:1 nm[3]/m[3], and the hydrocracker operates at relatively mild conditions, ~710F and 500 psia with a 90% wax conversion [11].  The product slate was set at 70/30 wt% diesel/naphtha with approximately 4% light ends [2, 11].  Although the hydrocracking plant was modeled in detail, there is insufficient literature data on an accurate cost for the individual hydrocracking reactor and catalyst; thus the unit as a whole was costed based on literature data for a hydrocracking plant as is done in other studies [8].  It is assumed that the hydrocracking catalyst expense is included in this "inside battery limits" cost, given that the cost is on an inlet flow rate basis.  The outlet streams from the hydrocracker are a heavy hydrocarbon liquid which feeds directly to distillation, a lighter liquid which combines with the synthesis liquid stream at the low pressure flash drum, a small flue gas stream produced as a result of the hydrocracker furnace (combines with the other flue gas streams), and a small purge offgas stream which is burned in the tar reformer regenerator.

A500: Product Separation
The assumptions made in A500 are summarized as follows and described in more detail below:
   * A single steam-stripped column will adequately separate the products into offgas, naphtha, diesel, and residual wax
   * Column specified to produce 95% purity diesel; naphtha purity not as important as it requires additional refining to be considered "gasoline" and wax is considered "low-grade" paraffinic wax
   * 28 actual stages required assuming 50% tray efficiency; column was costed in Aspen IPE
   * Total column feed is heated to 600F and heat is supplied by FT reactor feed cooler; this coupled heat exchanger was costed in Aspen IPE
   * Remaining heat exchangers scaled by duty based on another exchanger in similar service.  The pinch analysis was not re-evaluated as the time required is not justified based on the cost impact; even doubling the cost of every heat exchanger changes the diesel price by 3 cents.
   * For the diesel product to be considered "finished" (ready for use as transportation fuel), a diesel hydrotreater is required.  This was not modeled in detail, but was costed based on an "inside battery limits" estimate for a hydrotreating plant.

 The separation section consists mainly of a single distillation column to separate the various products, thus is simpler than the base model as the molecular sieve unit and 2[nd] distillation column are not necessary.  As mentioned previously, the liquid synthesis products as well as the light liquid from wax hydrocracking are flashed in a low-pressure drum and the offgas is recycled to the tar reformer.  The liquid product is preheated to 250F before mixing with the heavy liquid stream from wax hydrocracking, and the combined stream is heated to 600F and fed to the distillation column.  This column operates at higher temperature than the base model because the products have significantly higher boiling ranges; as such, a reboiled column would result in bottom temperatures in excess of what could be met by heat exchange with steam or most other process streams.  Thus the column was converted to a steam-stripped fractionator as is common in the petroleum industry; this resulted in a more reasonable temperature profile and good internal column traffic (the alternative would be to draw diesel+ material from a reboiled column and split diesel/wax in a 2[nd] vacuum column).  Since this is a more ideal mixture, the column decreased in diameter to 5 ft and number of trays required was 28 actual trays (assuming 50% tray efficiency).  This new column was costed in Aspen IPE based on the resulting dimensions.

The fractionator was specified to produce diesel at 95% purity, while the naphtha and wax material was closer to 90%.  It was assumed that the purity of these byproduct streams is not as important since the naphtha requires additional upgrading before it can be sold as "gasoline" and the wax does not have stringent component requirements, but would be sold as a "low-grade" paraffinic wax.  The offgas from the column (consisting mostly of C1-C4 components) was recycled to the tar reformer.  The product run-down lines were left unchanged, and the wax coolers and product tank were costed in the same manner as the existing equipment.

According to various studies, the diesel cannot be considered "finished" (ie, ready for use as transportation fuel) without final upgrading to improve various engine performance properties and to crack any residual wax [8].  Thus a diesel hydrotreater was included in the capital cost calculations, although it wasn't modeled in detail as the base cost for this unit was another "inside battery limits" package cost based on diesel flow rate.  It was assumed that the final product flowrate would be the same as that leaving the distillation column, which should be reasonable given that this would be fairly mild hydrotreating and the goal is not to break the material down into lighter fractions.

It should be noted that the pinch analysis was not re-evaluated from the base model as this would take an unreasonable amount of time to adjust the heat exchanger network, relative to the impact on the economics.  Thus, all heat exchangers were costed based on the same pinch network with updated duties, and were checked to ensure there would not be temperature crosses at the beginning or end of a heat exchanger series.  The new FT feed cooler/fractionator pre-heater was coupled and costed as a single unit in Aspen IPE, as well as new utility coolers.  Any other new exchangers were costed based on a similar exchanger that would have somewhat similar U and LMTD values.  This approximation to heat exchanger costing is reasonable in the scope of this study, given the fact that even doubling the cost of every heat exchanger would only change the diesel selling price by ~3 cents/gallon.

A600: Steam System
The assumptions made in A600 are summarized as follows and described in more detail below:
   * High-purity water produced as a result of FT synthesis is recovered and recycled to the steam cycle
   * A new medium-pressure steam loop was created to accommodate a lower FT synthesis operating temperature and thus steam quality (relative to the original ethanol synthesis reactor).  This included a new medium-pressure boiler feed water pump, preheater, and steam superheater, all of which were costed by scaling to the same piece of equipment in the high-pressure loop.
   * To accommodate the lower steam pressure generated at the FT synthesis reactor, the steam turbine was modified to accept the medium-pressure steam at the 2[nd] stage while still extracting low pressure steam at the 3[rd] stage for the various process and heat demands in the plant.  The anticipated higher cost for this turbine was estimated by assuming the total (HP+MP) steam rate is theoretically introduced at the 1[st] stage.

The steam system was slightly modified to include recycle streams from new water knockout sources added as a result of FT water production, as well as medium pressure steam produced from the FT synthesis reactor.  As noted previously, the pinch analysis was not re-evaluated in this study.  Since the pinch point was originally set by the alcohol synthesis reactor temperature, an adjustment to the steam heat balance was necessary to accommodate the lower operating temperature of the FT synthesis reactor.  Originally, steam was generated at 527F based on a 43F temperature approach to the 570F operating temperature of the ethanol synthesis reactor.  Assuming the same approach temperature with the 446F operating temperature in the FT model, steam is generated at 403F which results in a lower saturation pressure, and thus lower quality steam to drive the turbine generator.  As this would result in an unacceptably low pressure differential and thus power generation at the turbine, the turbine was modified to accept the same high-pressure steam generated elsewhere in the plant at the first stage, and the new medium-pressure steam generated from the synthesis reactor at the second stage.  Low-pressure steam is still extracted from the third stage to meet the various process and heat demands throughout the plant as described in the original design report.  Since steam is both injected and extracted at intermediate stages in the turbine, this modified configuration is called an "induction/extraction turbine."

The new medium-pressure steam cycle includes a separate boiler feed water pump, boiler feed water preheater, and medium pressure steam superheater to bring the steam to the proper 2[nd]-stage turbine injection temperature.  All of these units were costed by scaling the power (for a pump) or duty (for an exchanger) based on the same piece of equipment in the high-pressure steam loop.  The medium pressure steam is generated at saturation conditions via tubes immersed in the synthesis reactor shell, and this cost is assumed to be included in the overall reactor cost described above.  The cost for an "extraction/induction" turbine was not immediately available in literature, so the new cost was estimated by assuming the full flowrate into the first stage of the turbine and scaling based on the original estimate.  Although the first stage does not actually see this full flow, this is a reasonable way to reflect a higher turbine cost due to a more complex design, when the cost for such a design was not available.

Operating Costs
The assumptions made for operating costs are summarized here and described in more detail below:
   * ZnO and FT catalysts require a "disposal cost" at the point when they are replaced; cost was assumed to be the same as the tar reformer catalyst disposal cost
   * Naphtha coproduct credit = $3.27/gallon, estimated by discounting projected gasoline price in 2022 by $0.40/gal
   * FT wax coproduct credit = $0.49/lb, estimated by scaling the 2006 paraffin wax spot price by 2022 projected oil price and discounting by 50%.
   * All other operating cost estimates are assumed to be on the same basis as in the ethanol design report

For this study, zinc oxide and FT synthesis catalyst were both assumed to require a "disposal cost" at the point when they are replaced, similar to the tar reformer catalyst.  The cost was assumed to be the same as that for tar reformer catalyst disposal, and is based on a basic "solid waste disposal" rate; this does not account for any environmental or metal recovery premiums that could be associated with either of these catalysts.  However, this assumption has a negligible impact on overall economics, as it was determined that even at 100x this base cost, the minimum diesel selling price was the same rounded to the nearest cent.

The diesel price is much more dependent on assumed co-product credit for naphtha and residual wax.  Although some studies assume the naphtha price can be approximated by "gasoline", this is not valid unless the plant includes numerous naphtha upgrading units as the naphtha produced by FT synthesis is low-octane and generally low-quality [12].  Thus the coproduct credit for naphtha was based on an analysis by Reed et al which discounted the price of gasoline by $0.40/gallon, which in turn was based on an average estimated cost required to upgrade FT naphtha for blending in the gasoline pool [12].  The base gasoline selling price was taken from EIA projections for gasoline in year 2022, $3.67/gal in 2007 dollars [13].  Thus the net assumed naphtha coproduct credit was $3.27/gallon.  It should be noted that as expected, the gasoline price is projected to continue increasing into the future, thus if a shorter timeframe was chosen earlier than 2022, the required diesel selling price would be higher and vice-versa, but this is an artificial influence on economics as it only reflects fluctuating energy prices and not physical advances in the research and technology.

There is a small amount of residual wax leaving the plant as a result of <100% conversion at the wax hydrocracker.  The wax selling price was estimated by assuming a refinery "paraffin wax" price in 2022 and discounting by 50% [14].  The projected price for paraffin wax was estimated by first taking the paraffin wax spot price in 2006 [15] and dividing by the US imported oil average price in the same year [13].  This ratio was then applied to the EIA projected oil price for 2022 [13] to arrive at the projected paraffin wax value, given that this price is largely a function of base oil prices.  The resulting estimate is $0.49/lb of FT wax in 2007 dollars.

Sensitivity Analysis
As noted previously there were numerous assumptions made to reasonably define the system, both from a process and costing standpoint.  Given that each assumption has a different degree of impact on the bottom line economics, an analysis was run to determine the sensitivity of the diesel selling price on a particular variable, while all other factors were held constant.  The results are shown in Figure 1.

                               Financial/ Market
Process

                   Figure 1: Results of sensitivity analysis
Figure 1 is divided into two categories, process assumptions and financial/market assumptions, and each factor was varied over a reasonable range (either according to values used in similar studies or elsewhere in literature).  The synthesis conversion extent was the largest process-related assumption evaluated, from the base value of 80% (achievable in modern slurry reactors) down to 40% which was chosen as this is typical for fixed-bed FT systems [8].  Various alternatives for the gas cleanup section were evaluated, as this section varies widely between studies.  A rough estimate was made to determine the cost of removing H2S and CO2 using a Rectisol unit based on parameters from [8], and was compared to the more standard schematic of amine/ZnO cleanup.  Additionally, the use of DEA instead of MEA in the amine unit was evaluated, but both of these changes had a relatively small effect on diesel price.  A somewhat larger impact was realized by supplementing the increased steam heat demands with natural gas (up to 5 MMSCFD) instead of relying purely on burning process streams and thereby sacrificing product yields; this improves economics but hurts the overall plant sustainability and self-sufficiency.

The largest financial/market assumptions to have an impact on diesel price were feed cost and assumed coproduct credit.  Feed cost has been well-documented to have the single largest impact on product selling price in many studies, and the price range evaluated here covers the range typically assumed to be realistic.  The coproduct credit is also an important variable on bottom-line economics as discussed previously, and the range evaluated here was set to +25% to account for uncertainties in future oil prices.  Additionally, the stream factor (online production time) was varied over the range typically assumed in other studies to demonstrate the effect this factor has in artificially influencing diesel price.  Finally, FT catalyst cost was varied over the range cited by industry [16, 10], but diesel price was not affected over this range.

Concluding Remarks
This study essentially served as a "best-case" scenario for FT diesel production; underlying process assumptions for achievable conversion and yields were higher than some studies but equivalent to others, and are based on literature sources citing recent developments on both the research and industry-level scale.  Additionally, a 96% capacity factor (operating time of 8406 hours/year, chosen here for consistency with the ethanol model) is somewhat optimistic relative to other studies, and artificially improves economics relative to other studies with lower capacity factors.  It should be noted that this model was developed from NREL's thermochemical ethanol design report model, and all assumptions in the front-end section of the plant such as feedstock cost and gasifier performance are based on the same "future" design targets.  Additionally, the FT model was developed to maintain similarity with the ethanol model (same recycle scheme, cleanup using amine scrubbing with MEA, no net electricity production etc); this is by no means the only feasible approach, and some of the various alternatives are presented in the "Sensitivity Analysis."  Still other options exist as well, such as eliminating recycle and focusing on net power generation as some other studies have investigated.  Given this information, a comparison against similar biomass-based FT studies is shown below for reference [16], as well as a brief explanation of differences.

     Table 2: Comparison against other FT studies (other values from [16])
                                   Parameter
                               Larson et al [8]
                              Tijmensen et al [2]
                              Swanson et al [16]
                                 Present study
Feed rate (dry tons/day)
                                     5000
                                     1920
                                     2205
                                     2205
Operating time (hours/year)
                                     7000
                                     8000
                                     7446
                                     8406
Feed cost ($2007/dry ton)
                                     51.80
                                     39.54
                                     75.00
                                     50.70
Diesel yield (gal/dry ton)
                                      25
                                  45  [5][2]
                                    32-41
                            (LT-HT gasification)[3]
                                     43.3
Total fuel yield (GDE/dry ton[1])
                                     38.9
                                     55.7
                                     42.3
                                     62.7
Total Efficiency (%, LHV)
                                     57.3
                                     50.1
                                     42.7
                                     46.7
Product Value ($/GDE[1])
                                     2.32
                                     2.56
                                     5.40
                                     2.51
   1. GDE = Gallons Diesel Equivalent (all products normalized to diesel according to heating value)
   2. Specific diesel yield value from Hamelinck et al; this report expanded on the Tijmensen study and used similar parameters, but broke out fuel yield into individual products while Tijmensen did not (all other values in the column are from the Tijmensen study)
   3. This study looked at both low-temperature (LT) and HT gasification schemes, and the specific diesel yield is reported for both cases.  All other values in the column are for the LT case.

As evident in Table 2, the results of this study are reasonable compared to the others, keeping in mind that the results vary according to different production scenarios.  For example, the Larson et al study did not employ a recycle loop (thus lower normalized yields) but burned un-converted syngas in a turbine to generate extra electricity to sell (thus higher total efficiency values, which include electricity).  The economics may be slightly better in the Larson study due to a larger scale as well as inclusion of all refining units to upgrade the naphtha value.  The Tijmensen et al study is relatively similar to this case in that it focuses on maximum fuel production, and shows similar yield results after normalizing operating time.  The Swanson et al study is not quite the same, in that it employs a fixed-bed synthesis reactor and thus much lower per-pass conversion, which results in lower yields and less attractive economics.  Note that the $/GDE figure in the present study is provided to establish a common basis for comparison; it was calculated by normalizing the coproducts to diesel according to heating value and thus eliminates uncertainty associated with projected coproduct credit.  The key economic metric in this study is the minimum diesel selling price, which is $2.06/gallon of diesel fuel for the base case.

The intent of this report was to provide a snapshot analysis of FT technology and economic viability by applying the most recent developments in the FT industry (typically based on coal or gas feeds) to a biomass feedstock.  As such, the results have a higher degree of uncertainty given that a commercial-scale biomass-based FT facility does not yet exist.  There is room for further development of this study in the future, through means such as a more thorough reactor model that calculates specific selectivities and conversions, evaluation of alternative process layouts and gas cleanup options, validation of the larger capital equipment costs, and more individual costing for areas such as the hydrocracker plant.  However, the assumptions employed here regarding such parameters are standard across most studies, thus the reliability of these results are comparable.
References
[1]  Phillips, S. et al., "Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass" (2007), http://www.nrel.gov/docs/fy07osti/41168.pdf
[2]  Tijmensen, M. et al., "The Production of Fischer Tropsch Liquids and Power Through Biomass Gasification" (2000), Utrecht University, NWS-E-2000-29, ISBN 90-73958-62-8
[3]  Spath, P. et al., "Fischer Tropsch Synthesis Technology Brief" (2002), http://devafdc.nrel.gov/bcfcdoc/6985.pdf
[4]  Amine website, http://www.amines.com/mdea_comp.htm
[5]  Hamelinck, C. et al., "Production of FT Transportation Fuels from Biomass; Technical Options, Process Analysis and Optimization, and Development Potential (2003), Utrecht University, NWS-E-2003-08, ISBN 90-393-3342-4
[6]  Spath, P. et al., "Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Batelle Columbus  Laboratory Indirectly-Heated Gasifier" (2005), http://www.nrel.gov/docs/fy05osti/37408.pdf
[7]  Van Vliet, O. et al., "Fischer Tropsch Diesel Production in a Well-to-Wheel Perspective: A Carbon, Energy Flow and Cost Analysis."  Energy Conversion and Management 50 (2009) 855-876.
[8]  Larson, E. et al., "Large-Scale Gasification-Based Coproduction of Fuels and Electricity from Switchgrass."  Biofuels, Bioproducts and Biorefining 3 (2009) 174-194 (electronic version; contains report and supporting info).
[9]  "Fischer Tropsch Catalyst Test on Coal-Derived Synthesis Gas."  Syntroleum public document.
[10]  "Syntroleum Analyst Day" powerpoint (2006), http://www.syntroleum.com/Presentations/Analyst-Day-June-2006-Final.pdf
[11]  Leckel, Dieter.  "Low-Pressure Hydrocracking of Coal-Derived Fischer-Tropsch Waxes to Diesel."  Energy & Fuels 21 (2007) 1425-1431.
[12]  Reed, M. et al., "Baseline Technical and Economic Assessment of a Commercial Scale Fischer-Tropsch Liquids Facility" (2007).  DOE/NETL document 2007/1260.
[13]  Energy Information Administration price forecasts, http://www.eia.doe.gov/oiaf/forecasting.html
[14]  Personal communication with Rich Bain (NREL), 7/24/09.
[15]  From SRI report on US Paraffinic wax prices, http://www.sriconsulting.com/CEH/Public/Reports/595.5000/
[16]  Swanson, R. et al., "Techno-Economic Analysis of Biomass Gasification Scenarios" (2009), ConocoPhillips/Iowa State FT study.

FT model inlet/outlet heat and material balance summary

                            Energy Flow [MMBTU/hr]
                           Material Flowrate [lb/hr]
                              Major Energy Inlets
Biomass Feedstock (WET)
                                    -1699.4
                                    367437
Natural Gas
                                      0.0
                                       0
Air
                                     -78.3
                                    703501
Olivine
                                      0.0
                                      538
MgO
                                      0.0
                                       7
Water
                                    -1375.2
                                    199430
Tar Reforming Catalyst
                                      0.0
                                       1
Purchased Electricity
                                     -0.1
                                      NA
Other
                                      0.0
                                       3
Total
                                     -3153
                                    1270917
                             Major Energy Outlets
Diesel
                                     -21.9
                                     24550
Naphtha
                                     -9.6
                                     9885
Wax
                                     -1.3
                                     1620
Cooling Tower Evap.
                                    -591.6
                                    107139
Flue Gas
                                    -1938.3
                                    948007
Sulfur
                                      0.0
                                      133
CO2 Vent
                                    -313.0
                                     81664
Byproduct Electricity
                                      0.0
                                      NA
Air Coolers
                                     244.9
                                      NA
Compressor Heat
                                     135.1
                                      NA
Vent to Atmosphere
                                     -0.5
                                      331
Sand and Ash
                                     -2.2
                                     2428
Catalyst Purge
                                      0.0
                                       1
Wastewater
                                    -378.1
                                     55376
Ambient Heat and Work Losses
                                      3.1
                                      NA
Other
                                    -273.2
                                     39765
Total
                                     -3147
                                    1270900
% difference (Note 1)
                                     0.2%
                                     0.0%
   1.  Slight discrepancy due to thermodynamic property changes within model and overall convergence tolerance

FT model emission sources and flowrates [lb/h]


[Federal Register Volume 87, Number 235 (Thursday, December 8, 2022)]
[Proposed Rules]
[Pages 75181-75185]
[FR Doc No: 2022-26579]

-----------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 39

[Docket No. FAA-2022-1416; Project Identifier AD-2022-00725-E]
RIN 2120-AA64

Airworthiness Directives; General Electric Company Turbofan
Engines

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Notice of proposed rulemaking (NPRM).

-----------------------------------------------------------------------

SUMMARY: The FAA proposes to supersede Airworthiness Directive (AD)
2012-02-07, which applies to certain General Electric Company (GE) CF6-
45 and CF6-50 series model turbofan engines with a specified low-
pressure turbine (LPT) rotor stage 3 disk installed. AD 2012-02-07
requires inspections of high-pressure turbine (HPT) and LPT rotors,
engine checks, vibration surveys, an optional LPT rotor stage 3 disk
removal after a failed HPT blade borescope inspection (BSI) or a failed
engine core vibration survey, establishes a lower life limit for the
affected LPT rotor stage 3 disks, and requires removing these disks
from service at times determined by a drawdown plan. Since the FAA
issued AD 2012-02-07, four additional events of separation of the LPT
rotor assembly have been reported resulting in the LPT rotor assembly
departing the rear of the engine. The manufacturer has improved the
design of the LPT rotor stage 3 disk. This proposed AD would continue
to require inspections of HPT and LPT rotor stage 1 and stage 2 blades,
vibration surveys, and use of a lower life limit for the affected LPT
rotor stage 3 disks. As a terminating action to the inspections, engine
checks, and vibration surveys, this proposed AD would require removal
and replacement of the LPT rotor stage 3 disk with a redesigned LPT
rotor stage 3 disk. This proposed AD would also revise the compliance
time of the drawdown plan for the removal and replacement of the LPT
rotor stage 3 disk. This proposed AD would also prohibit the
installation

or reinstallation of certain LPT rotor stage 3 disks. The FAA is
proposing this AD to address the unsafe condition on these products.

DATES: The FAA must receive comments on this proposed AD by January 23,
2023.

ADDRESSES: You may send comments, using the procedures found in 14 CFR
11.43 and 11.45, by any of the following methods:
     Federal eRulemaking Portal: Go to regulations.gov. Follow
the instructions for submitting comments.
     Fax:<PHONE_NUMBER>.
     Mail: U.S. Department of Transportation, Docket
Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New
Jersey Avenue SE, Washington, DC 20590.
     Hand Delivery: Deliver to Mail address above between 9
a.m. and 5 p.m., Monday through Friday, except Federal holidays.
    AD Docket: You may examine the AD docket at regulations.gov by
searching for and locating Docket No. FAA-2022-1416; or in person at
Docket Operations between 9 a.m. and 5 p.m., Monday through Friday,
except Federal holidays. The AD docket contains this NPRM, any comments
received, and other information. The street address for Docket
Operations is listed above.

FOR FURTHER INFORMATION CONTACT: Sungmo Cho, Aviation Safety Engineer,
ECO Branch, FAA, 1200 District Avenue, Burlington, MA 01803; phone:
(781) 238-7241; email: [email protected].

SUPPLEMENTARY INFORMATION:

Comments Invited

    The FAA invites you to send any written relevant data, views, or
arguments about this proposal. Send your comments to an address listed
under ADDRESSES. Include ``Docket No. FAA-2022-1416; Project Identifier
AD-2022-00725-E'' at the beginning of your comments. The most helpful
comments reference a specific portion of the proposal, explain the
reason for any recommended change, and include supporting data. The FAA
will consider all comments received by the closing date and may amend
the proposal because of those comments.
    Except for Confidential Business Information (CBI) as described in
the following paragraph, and other information as described in 14 CFR
11.35, the FAA will post all comments received, without change, to
regulations.gov, including any personal information you provide. The
agency will also post a report summarizing each substantive verbal
contact received about this NPRM.

Confidential Business Information

    CBI is commercial or financial information that is both customarily
and actually treated as private by its owner. Under the Freedom of
Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public
disclosure. If your comments responsive to this NPRM contain commercial
or financial information that is customarily treated as private, that
you actually treat as private, and that is relevant or responsive to
this NPRM, it is important that you clearly designate the submitted
comments as CBI. Please mark each page of your submission containing
CBI as ``PROPIN.'' The FAA will treat such marked submissions as
confidential under the FOIA, and they will not be placed in the public
docket of this NPRM. Submissions containing CBI should be sent to
Sungmo Cho, Aviation Safety Engineer, ECO Branch, FAA, 1200 District
Avenue, Burlington, MA 01803. Any commentary that the FAA receives
which is not specifically designated as CBI will be placed in the
public docket for this rulemaking.

Background

    The FAA issued AD 2012-02-07, Amendment 39-16930 (77 FR 4650,
January 31, 2012) (AD 2012-02-07), for GE CF6-45A, CF6-45A2, CF6-50A,
CF6-50C, CF6-50CA, CF6-50C1, CF6-50C2, CF6-50C2B, CF6-50C2D, CF6-50E,
CF6-50E1, CF6-50E2, and CF6-50E2B model turbofan engines, including
engines marked on the engine data plate as CF6-50C2-F and CF6-50C2-R,
with a specified LPT rotor stage 3 disk, identified by part number (P/
N), installed. AD 2012-02-07 superseded AD 2011-02-07, Amendment 39-
16580 (76 FR 6323, February 4, 2011) and AD 2011-18-01, Amendment 39-
16783 (76 FR 52213, August 22, 2011). AD 2012-02-07 was prompted by the
determination that a new lower life limit for the affected LPT rotor
stage 3 disks was necessary. AD 2012-02-07 retained the requirements of
the two superseded ADs, which required inspections of HPT and LPT
rotors, ultrasonic inspection (UI) of the LPT rotor stage 3 disk
forward spacer arm, exhaust gas temperature (EGT) resistance check, EGT
thermocouple inspection, cleaning, fluorescent-penetrant inspection
(FPI) of the LPT rotor stage 3 disk, engine checks, and vibration
surveys. AD 2012-02-07 also added an optional LPT rotor stage 3 disk
removal after a failed HPT BSI or a failed engine core vibration
survey, established a new lower life limit for the affected LPT rotor
stage 3 disks, and required removing those disks from service at times
determined by a drawdown plan. The agency issued AD 2012-02-07 to
prevent critical life-limited rotating engine part failure, which could
result in an uncontained engine failure and damage to the airplane.

Actions Since AD 2012-02-07 Was Issued

    Since the FAA issued AD 2012-02-07, the FAA has received reports of
four additional events of separation of the LPT rotor assembly, which
resulted in the LPT rotor assembly departing the rear of the engine.
Following the most recent separation event, the FAA determined that due
to the complexity of AD 2012-02-07, the limitations of certain
operators to access required equipment and training needed to
accomplish the inspections, and the manufacturer's redesign of the LPT
rotor stage 3 disk, AD 2012-02-07 should be superseded. The redesigned
LPT rotor stage 3 disk, P/N 2453M80P01, has a thicker forward spacer
arm, which reduces stress on the forward arm area and increases its
high cycle fatigue alternating stress capability.
    Accordingly, the FAA is proposing to require the replacement of the
affected LPT rotor stage 3 disk with a redesigned LPT rotor stage 3
disk, P/N 2453M80P01, as a terminating action to the HPT blade
inspection, vibration survey, UI, EGT resistance check, EGT
thermocouple inspection, cleaning, and FPI. This proposed AD would also
revise the installation prohibition for affected LPT rotor stage 3
disks. AD 2012-02-07 prohibited the installation or reinstallation of
an affected LPT rotor stage 3 disk if it had exceeded 6,200 cycles
since new. This proposed AD would prohibit installing an affected LPT
rotor stage 3 disk onto any engine.

FAA's Determination

    The FAA is issuing this NPRM after determining that the unsafe
condition described previously is likely to exist or develop on other
products of the same type designs.

Proposed AD Requirements in This NPRM

    This proposed AD would retain certain requirements of AD 2012-02-
07. As a terminating action to the HPT blade inspection, vibration
survey, UI, EGT resistance check, EGT thermocouple inspection,
cleaning, and FPI of the LPT rotor stage 3 disk, this proposed AD would
require removal and replacement of the LPT rotor stage 3 disk with
improved design LPT rotor

stage 3 disk P/N 2453M80P01 within 18 months of the effective date of
the AD. This proposed AD would also prohibit the installation or
reinstallation of certain LPT rotor stage 3 disks on any engine.

Costs of Compliance

    The FAA estimates that this AD, if adopted as proposed, would
affect 26 engines installed on airplanes of U.S. registry.
    The FAA estimates the following costs to comply with this proposed
AD:

                                                 Estimated Costs
----------------------------------------------------------------------------------------------------------------
                                                                                Cost per      Cost on U.S.
                Action                         Labor cost           Parts cost        product        operators
----------------------------------------------------------------------------------------------------------------
HPT blade inspection, vibration         28 work-hours x $85 per               $0          $2,380         $61,880
 survey, UI, EGT resistance check, EGT   hour = $2,380.
 thermocouple inspection, cleaning and
 FPI of the LPT rotor stage 3 disk.
Remove and replace LPT rotor stage 3    620 work-hours x $85 per         276,300         329,000       8,554,000
 disk.                                   hour = $52,700.
----------------------------------------------------------------------------------------------------------------

Authority for This Rulemaking

    Title 49 of the United States Code specifies the FAA's authority to
issue rules on aviation safety. Subtitle I, Section 106, describes the
authority of the FAA Administrator. Subtitle VII, Aviation Programs,
describes in more detail the scope of the Agency's authority.
    The FAA is issuing this rulemaking under the authority described in
Subtitle VII, Part A, Subpart III, Section 44701, General requirements.
Under that section, Congress charges the FAA with promoting safe flight
of civil aircraft in air commerce by prescribing regulations for
practices, methods, and procedures the Administrator finds necessary
for safety in air commerce. This regulation is within the scope of that
authority because it addresses an unsafe condition that is likely to
exist or develop on products identified in this rulemaking action.

Regulatory Findings

    The FAA determined that this proposed AD would not have federalism
implications under Executive Order 13132. This proposed AD would not
have a substantial direct effect on the States, on the relationship
between the national Government and the States, or on the distribution
of power and responsibilities among the various levels of government.
    For the reasons discussed above, I certify that the proposed
regulation:
    (1) Is not a ``significant regulatory action'' under Executive
Order 12866,
    (2) Would not affect intrastate aviation in Alaska, and
    (3) Would not have a significant economic impact, positive or
negative, on a substantial number of small entities under the criteria
of the Regulatory Flexibility Act.

List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by
reference, Safety.

The Proposed Amendment

    Accordingly, under the authority delegated to me by the
Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

PART 39--AIRWORTHINESS DIRECTIVES

0
1. The authority citation for part 39 continues to read as follows:

    Authority:  49 U.S.C. 106(g), 40113, 44701.

Sec.  39.13  [Amended]

0
2. The FAA amends Sec.  39.13 by:
0
a. Removing Airworthiness Directive AD 2012-02-07, Amendment 39-16930
(77 FR 4650, January 31, 2012); and
0
b. Adding the following new airworthiness directive:

General Electric Company: Docket No. FAA-2022-1416; Project
Identifier AD-2022-00725-E.

(a) Comments Due Date

    The FAA must receive comments on this airworthiness directive
(AD) action by January 23, 2023.

(b) Affected ADs

    This AD replaces AD 2012-02-07, Amendment 39-16930 (77 FR 4650,
January 31, 2012) (AD 2012-02-07).

(c) Applicability

    This AD applies to General Electric Company (GE) CF6-45A, CF6-
45A2, CF6-50A, CF6-50C, CF6-50CA, CF6-50C1, CF6-50C2, CF6-50C2B,
CF6-50C2D, CF6-50E, CF6-50E1, CF6-50E2, and CF6-50E2B model turbofan
engines, including engines marked on the engine data plate as CF6-
50C2-F and CF6-50C2-R, with an installed low-pressure turbine (LPT)
rotor stage 3 disk having a part number listed in Table 1 to
paragraph (c) of this AD.

                                        Table 1 to Paragraph (c)--Applicable LPT Rotor Stage 3 Disk Part Numbers
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
                9061M23P06                     9061M23P07                     9061M23P08                     9061M23P09                    9224M75P01
                9061M23P10                     1473M90P01                     1473M90P02                     1473M90P03                    1473M90P04
                9061M23P12                     9061M23P14                     9061M23P15                     9061M23P16                    1479M75P01
                1479M75P02                     1479M75P03                     1479M75P04                     1479M75P05                    1479M75P06
                1479M75P07                     1479M75P08                     1479M75P09                     1479M75P11                    1479M75P13
                1479M75P14                            N/A                            N/A                            N/A                           N/A
--------------------------------------------------------------------------------------------------------------------------------------------------------

(d) Subject

    Joint Aircraft System Component (JASC) Code 7250, Turbine
Section.

(e) Unsafe Condition

    This AD was prompted by the occurrence of four events of
separation of the LPT rotor assembly, occurring after the effective
date of AD 2012-02-07, which resulted in the LPT rotor assembly
departing the rear of the engine. The FAA is issuing this AD to
prevent critical life-limited rotating engine part failure. The
unsafe condition, if not addressed, could result in an uncontained
engine failure and damage to the airplane.

(f) Compliance

    Comply with this AD within the compliance times specified,
unless already done.

(g) Required Actions

    (1) Borescope Inspections (BSI) of High-Pressure Turbine (HPT)
Rotor Stage 1 and Stage 2 Blades:
    For the BSIs required by paragraphs (g)(1)(i) through (iii) of
this AD, inspect the blades from the forward and aft directions.
Inspect all areas of the blade airfoil. The inspection must include
blade leading and trailing edges and their convex and concave
airfoil surfaces. Inspect for signs of impact, cracking, burning,
damage, and distress.
    (i) Within 75 cycles since last inspection (CSLI) or before
further flight, whichever occurs later, perform an initial BSI of
the HPT rotor stage 1 and stage 2 blades.
    (ii) Thereafter, within every 75 CSLI, repeat the BSI of the HPT
rotor stage 1 and stage 2 blades.
    (iii) Within the cycle limits after the engine has experienced
any of the events specified in Table 1 to paragraph (g)(1) of this
AD, borescope-inspect the HPT rotor stage 1 and stage 2 blades.
    (iv) If the engine fails any of the BSIs required by this AD,
before further flight, remove the engine from
service.[FEDREG][VOL]*[/VOL][NO]*[/NO][DATE]*[/
DATE][PRORULES][PRORULE][PREAMB][AGENCY]*[/AGENCY][SUBJECT]*[/
SUBJECT][/PREAMB][SUPLINF][HED]*[/HED][EXTRACT][P]*[/P]?>

          Table 2 to Paragraph (g)(1)--Conditional BSI Criteria
------------------------------------------------------------------------
                                                      Then borescope
         If the engine has experienced:                  inspect:
------------------------------------------------------------------------
(i) An exhaust gas temperature (EGT) above        Within 10 cycles.
 redline.
(ii) A shift in the smoothed EGT trending data    Within 10 cycles.
 that exceeds 18 [deg]F (10 [deg]C), but is less
 than or equal to 36 [deg]F (20 [deg]C).
(iii) A shift in the smoothed EGT trending data   Before further flight.
 that exceeds 36 [deg]F (20 [deg]C).
(iv) Two consecutive raw EGT trend data points    Within 10 cycles.
 that exceed 18 [deg]F (10 [deg]C), but are less
 than or equal to 36 [deg]F (20 [deg]C), above
 the smoothed average.
(v) Two consecutive raw EGT trend data points     Before further flight.
 that exceed 36 [deg]F (20 [deg]C) above the
 smoothed average.
------------------------------------------------------------------------

    (2) Engines with Damaged HPT Rotor Blades:
    For those engines that fail any BSI requirements of this AD,
before returning the engine to service, accomplish the actions
required by paragraph (g)(2)(i) or (ii) of this AD:
    (i) Remove the LPT rotor stage 3 disk from service; or
    (ii) Perform a fluorescent-penetrant inspection (FPI) of the
inner diameter surface forward cone body (forward spacer arm) of the
LPT rotor stage 3 disk as specified in paragraphs (g)(6)(i)(A)
through (C) of this AD.
    (3) EGT Thermocouple Probe Inspections.
    (i) Within 750 CSLI, or before further flight, whichever occurs
later, inspect the EGT thermocouple probe for damage.
    Note 1 to paragraph (g)(3)(i): Damage to the EGT thermocouple
probe may be indicated by wear through the thermocouple guide sleeve
or contact between the turbine mid-frame liner and the EGT
thermocouple probe.
    (ii) Thereafter, within every 750 CSLI, re-inspect the EGT
thermocouple probe for damage.
    (iii) If any EGT thermocouple probe shows wear through the
thermocouple guide sleeve or contact between the turbine mid-frame
liner and the EGT thermocouple probe, before further flight, remove
and replace the EGT thermocouple probe and ensure the turbine mid-
frame liner does not contact the EGT thermocouple probe.
    (4) EGT System Resistance Checks.
    (i) Within 750 cycles since the last resistance check on the EGT
system or before further flight, whichever occurs later, perform an
EGT system resistance check.
    (ii) Thereafter, within every 750 cycles since the last
resistance check, repeat the EGT system resistance check.
    (iii) If an EGT system component fails the resistance system
check, before further flight, remove and replace, or repair the EGT
system component.
    (5) Engine Core Vibration Survey.
    (i) Within 350 cycles since the last engine core vibration
survey or before further flight, whichever occurs later, perform an
initial engine core vibration survey.
    (ii) Use about a one-minute acceleration and a one-minute
deceleration of the engine between ground idle and 84% N2 (about
8,250 rpm) to perform the engine core vibration survey.
    (iii) Use a spectral/trim balance analyzer or equivalent to
measure the N2 rotor vibration.
    (iv) If the vibration level is above 5 mils Double Amplitude
then, before further flight, remove the engine from service.
    (v) For those engines that fail any engine core vibration survey
requirements of this AD, then before returning the engine to
service:
    (A) Remove the LPT rotor stage 3 disk from service; or
    (B) Perform an FPI of the inner diameter surface forward spacer
arm of the LPT rotor stage 3 disk as specified in paragraph
(g)(6)(i)(A) through (C) of this AD.
    (vi) Thereafter, within every 350 cycles since the last engine
core vibration survey, perform the engine core vibration survey as
required in paragraphs (g)(5)(i) through (v) of this AD.
    (vii) If the engine has experienced any vibration reported by
maintenance or flight crew that is suspected to be caused by the
engine core (N2), within 10 cycles after the report, perform the
engine core vibration survey as required in paragraphs (g)(5)(i)
through (v) of this AD.
    (viii) Vibration surveys carried out in an engine test cell as
part of an engine manual performance run fulfill the vibration
survey requirements of paragraphs (g)(5)(ii) and (iii) of this AD.
    (6) Initial and Repetitive FPI of LPT Rotor Stage 3 Disk.
    (i) At the next shop visit after accumulating 1,000 cycles since
the last FPI of the LPT rotor stage 3 disk forward spacer arm or
before further flight, whichever occurs later:
    (A) Clean the LPT rotor stage 3 disk forward spacer arm,
including the use of a wet-abrasive blast, to eliminate residual or
background fluorescence.
    (B) Perform an FPI of the LPT rotor stage 3 disk forward spacer
arm for cracks and for a band of fluorescence. Include all areas of
the disk forward spacer arm and the inner diameter surface forward
spacer arm of the LPT rotor stage 3 disk.
    (C) If a crack or a band of fluorescence is present, before
further flight, remove the disk from service.
    (ii) Thereafter, at each engine shop visit that occurs after
accumulating 1,000 cycles since the last FPI of the LPT rotor stage
3 disk forward spacer arm, clean and perform an FPI of the LPT rotor
stage 3 disk forward spacer arm, as specified in paragraph
(g)(6)(i)(A) through (C) of this AD.
    (7) Removal of LPT Rotor Stage 3 Disk.
    (i) For any installed LPT rotor stage 3 disk having a part
number listed in Table 1 to paragraph (c) of this AD, at the first
occurrence of any one of the conditions identified in paragraphs
(g)(7)(i)(A) through (C) of this AD, remove the LPT rotor stage 3
disk from service and replace with LPT rotor stage 3 disk part
number 2453M80P01.
    (A) For a disk that has accumulated fewer than 3,200 cycles
since new (CSN) as of March 6, 2012 (the effective date of AD 2012-
02-07), remove the disk from service before accumulating 6,200 CSN.
    (B) For a disk that accumulated 3,200 or more CSN as of March 6,
2012 (the effective date of AD 2012-02-07), do the actions required
by paragraphs (g)(7)(i)(B)(1) or (2) of this AD, as applicable to
your engine.
    (1) If the engine has a shop visit before the disk accumulates
6,200 CSN, remove the disk from service at that shop visit.
    (2) If the engine does not have a shop visit before the disk
accumulates 6,200 CSN, remove the disk from service at the next shop
visit after accumulating 6,200 CSN, not to exceed 3,000 cycles from
March 6, 2012 (the effective date of AD 2012-02-07).
    (C) Before exceeding 18 months from the effective date of this
AD.

(h) Terminating Action

    Replacement of the LPT rotor stage 3 disk in accordance with
paragraph (g)(7) of this AD constitutes terminating action for the
inspections, engine checks and vibration surveys required by
paragraphs (g)(1) through (6) of this AD.

(i) Installation Prohibition

    After the effective date of this AD, do not install or reinstall
onto any engine an LPT rotor stage 3 disk listed in Table 1 to
paragraph (c) of this AD that has accumulated 6,200 CSN or more.

(j) Definitions

    (1) For the purposes of this AD, an EGT above redline is a
confirmed over-temperature indication that is not a result of EGT
system error.
    (2) For the purposes of this AD, a shift in the smoothed EGT
trending data is a shift in a rolling average of EGT readings that
can be confirmed by a corresponding shift in the trending of fuel
flow or fan speed/core speed (N1/N2) relationship. You can find
further guidance about evaluating EGT trend data in GE Company
Service Rep Tip 373 ''Guidelines For Parameter Trend Monitoring.''
    (3) For the purposes of this AD, an engine shop visit is the
induction of an engine into the shop, where the separation of a
major engine flange occurs; except the following maintenance
actions, or any combination, are not considered engine shop visits:
    (i) Induction of an engine into a shop solely for removal of the
compressor top or bottom case for airfoil maintenance or variable
stator vane bushing replacement.
    (ii) Induction of an engine into a shop solely for removal or
replacement of the stage 1 fan disk.
    (iii) Induction of an engine into a shop solely for replacement
of the turbine rear frame.
    (iv) Induction of an engine into a shop solely for replacement
of the accessory gearbox or transfer gearbox, or both.
    (v) Induction of an engine into a shop solely for replacement of
the fan forward case.
    (4) For the purposes of this AD, a raw EGT trend data point
above the smoothed average is a confirmed temperature reading over
the rolling average of EGT readings that is not a result of EGT
system error.

(k) Credit for Previous Actions

    You may take credit for the actions required by paragraph (g) of
this AD if they were performed before the effective date of this AD
using GE Service Bulletin (SB) No. CF6-50 SB 72-1315, Initial Issue,
dated June 3, 2011, or GE SB No. CF6-50 SB 72-1315, Revision 1,
dated June 30, 2011.

(l) Alternative Methods of Compliance (AMOCs)

    (1) The Manager, ECO Branch, FAA, has the authority to approve
AMOCs for this AD, if requested using the procedures found in 14 CFR
39.19. In accordance with 14 CFR 39.19, send your request to your
principal inspector or local Flight Standards District Office, as
appropriate. If sending information directly to the manager of the
certification office, send it to the attention of the person
identified in paragraph (m) of this AD and email it to: [email protected].
    (2) Before using any approved AMOC, notify your appropriate
principal inspector, or lacking a principal inspector, the manager
of the local flight standards district office/certificate holding
district office.
    (3) AMOCs approved previously for AD 2010-12-10, Amendment 39-
16331 (75 FR 32649, June 9, 2010), AD 2011-02-07, Amendment 39-16580
(76 FR 6323, February 4, 2011), or AD 2011-18-01, Amendment 39-16783
(76 FR 52213, August 22, 2011) are approved as AMOCs for the
corresponding provisions of this AD.

(m) Related Information

    For more information about this AD, contact Sungmo Cho, Aviation
Safety Engineer, ECO Branch, FAA, 1200 District Avenue, Burlington,
MA 01803; phone:<PHONE_NUMBER>; email: [email protected].

(n) Material Incorporated by Reference

    None.

    Issued on November 3, 2022.
Christina Underwood,
Acting Director, Compliance & Airworthiness Division, Aircraft
Certification Service.
[FR Doc. 2022-26579 Filed 12-7-22; 8:45 am]
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[Federal Register: April 25, 2008 (Volume 73, Number 81)]
[Notices]
[Page 22458]
[DOCID:fr25ap08-140]

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DEPARTMENT OF TRANSPORTATION

Federal Motor Carrier Safety Administration

[Docket Nos. FMCSA-05-22727, FMCSA-05-23099]

Qualification of Drivers; Exemption Renewals; Vision

AGENCY: Federal Motor Carrier Safety Administration (FMCSA), DOT.

ACTION: Notice of final disposition.

-----------------------------------------------------------------------

SUMMARY: FMCSA previously announced its decision to renew the
exemptions from the vision requirement in the Federal Motor Carrier
Safety Regulations for 8 individuals. FMCSA has statutory authority to
exempt individuals from the vision requirement if the exemptions
granted will not compromise safety. The Agency has reviewed the
comments submitted in response to the previous announcement and
concluded that granting these exemptions will provide a level of safety
that will be equivalent to, or greater than, the level of safety
maintained without the exemptions for these commercial motor vehicle
(CMV) drivers.

FOR FURTHER INFORMATION CONTACT: Dr. Mary D. Gunnels, Director, Medical
Programs,<PHONE_NUMBER><EMAIL_ADDRESS>FMCSA, Department of
Transportation, 400 Seventh Street, SW., Room 8301, Washington, DC
20590-0001. Office hours are from 8:30 a.m. to 5 p.m., Monday through
Friday, except Federal holidays.

SUPPLEMENTARY INFORMATION:

Electronic Access

    You may see all the comments online through the Federal Document
Management System (FDMS) at http://www.regulations.gov.

Background

    Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption
for a 2-year period if it finds ``such exemption would likely achieve a
level of safety that is equivalent to, or greater than, the level that
would be achieved absent such exemption.'' The statute also allows the
Agency to renew exemptions at the end of the 2-year period. The comment
period ended on March 20, 2008.

Discussion of Comments

    FMCSA received one comment in this proceeding. The comment was
considered and discussed below.
    Advocates for Highway and Auto Safety (Advocates) expressed
opposition to FMCSA's policy to grant exemptions from the FMCSR,
including the driver qualification standards. Specifically, Advocates:
(1) Objects to the manner in which FMCSA presents driver information to
the public and makes safety determinations; (2) objects to the Agency's
reliance on conclusions drawn from the vision waiver program; (3)
claims the Agency has misinterpreted statutory language on the granting
of exemptions (49 U.S.C. 31136(e) and 31315); and finally (4) suggests
that a 1999 Supreme Court decision affects the legal validity of vision
exemptions.
    The issues raised by Advocates were addressed at length in 64 FR
51568 (September 23, 1999), 64 FR 66962 (November 30, 1999), 64 FR
69586 (December 13, 1999), 65 FR 159 (January 3, 2000), 65 FR 57230
(September 21, 2000), and 66 FR 13825 (March 7, 2001). We will not
address these points again here, but refer interested parties to those
earlier discussions.

Conclusion

    The Agency has not received any adverse evidence on any of these
drivers that indicates that safety is being compromised. Based upon its
evaluation of the 8 renewal applications, FMCSA renews the Federal
vision exemptions for John R. Alger, Gene Bartlett, Jr., Marland L.
Brassfield, Billy R. Jeffries, John P. Rodrigues, Robert V. Sloan, Gary
N. Wilson, and William B. Wilson.
    In accordance with 49 U.S.C. 31136(e) and 31315, each renewal
exemption will be valid for 2 years unless revoked earlier by FMCSA.
The exemption will be revoked if: (1) The person fails to comply with
the terms and conditions of the exemption; (2) the exemption has
resulted in a lower level of safety than was maintained before it was
granted; or (3) continuation of the exemption would not be consistent
with the goals and objectives of 49 U.S.C. 31136 and 31315.

    Issued on: April 17, 2008.
Larry W. Minor,
Associate Administrator for Policy and Program Development.
 [FR Doc. E8-8987 Filed 4-24-08; 8:45 am]

BILLING CODE 4910-EX-P


[Federal Register Volume 82, Number 155 (Monday, August 14, 2017)]
[Rules and Regulations]
[Pages 37822-37824]
[FR Doc No: 2017-17123]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2016-0382; FRL-9966-25-OAR]
RIN 2060-AT15

Revisions to Procedure 2--Quality Assurance Requirements for
Particulate Matter Continuous Emission Monitoring Systems at Stationary
Sources

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: The Environmental Protection Agency (EPA) is finalizing
revisions to Procedure 2 that were proposed in the Federal Register on
November 21, 2016. Procedure 2 includes quality assurance/quality
control (QA/QC) procedures for particulate matter (PM) continuous
emission monitoring systems (CEMS) used for compliance determination at
stationary sources. The QA procedures specify the minimum requirements
necessary for the control and assessment of the quality of PM CEMS data
submitted to the EPA and other regulatory authorities. This action
establishes consistent requirements for ensuring and assessing the
quality of PM data measured by CEMS that meet initial acceptance
requirements in Performance Specification (PS) 11 of appendix B to part
60.

DATES: This final rule is effective on September 13, 2017.

ADDRESSES: Docket: The EPA has established a docket for this rulemaking
under Docket ID No. EPA-HQ-OAR-2016-0382. All documents in the docket
are listed at https://www.regulations.gov. Although listed in the
index, some information is not publicly available, e.g., Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy form. Publicly available docket materials are
available either electronically through www.regulations.gov or in hard
copy at the EPA Docket Center, Room 3334, EPA WJC West Building, 1301
Constitution Avenue NW., Washington, DC 20004. The Public Reading Room
is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding
legal holidays. The telephone number for the Public Reading Room is
(202) 566-1744, and the telephone number for the EPA Docket Center is
(202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Ms. Kimberly Garnett, Office of Air
Quality Planning and Standards, Air Quality Assessment Division,
Measurement Technology Group (Mail Code: E143-02), U.S. Environmental
Protection Agency, Research Triangle Park, NC 27709; telephone number:
(919) 541-1158; fax number:<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:
    The information in this document is organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document and other related
information?
    C. Judicial Review
II. Background
III. Final Revisions to Procedure 2
IV. Summary of Major Comments and Responses
V. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act (NTTAA)
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
    K. Congressional Review Act (CRA)

I. General Information

A. Does this action apply to me?

    The entities potentially affected by this rule include any facility
that is required to install and operate a PM CEMS under any provision
of title 40 of the Code of Federal Regulations. If you have any
questions regarding the applicability of this action to a particular
entity, consult the person listed in the FOR FURTHER INFORMATION
CONTACT section of this document.

B. Where can I get a copy of this document and other related
information?

    In addition to being available in the docket, an electronic copy of
this action is available on the Internet through the EPA's Technology
Transfer Network (TTN) Web site, a forum for information and technology
exchange in various areas of air quality management, measurement
standards and implementation, etc. Following publication in the Federal
Register, the EPA will post the Federal Register version of the
promulgation and key technical documents on the TTN at http://www.epa.gov/ttn/emc/promulgated.html.

C. Judicial Review

    Under section 307(b)(1) of the Clean Air Act (CAA), judicial review
of this final rule is available only by filing a petition for review in
the U.S. Court of Appeals for the District of Columbia Circuit by
October 13, 2017. Under

section 307(d)(7)(B) of the CAA, only an objection to this final rule
that was raised with reasonable specificity during the period for
public comment can be raised during judicial review. Moreover, under
section 307(b)(2) of the CAA, the requirements established by this
final rule may not be challenged separately in any civil or criminal
proceedings brought by the EPA to enforce these requirements. Section
307(d)(7)(B) of the CAA further provides that ``[o]nly an objection to
a rule or procedure which was raised with reasonable specificity during
the period for public comment (including any public hearing) may be
raised during judicial review.'' This section also provides a mechanism
for the EPA to convene a proceeding for reconsideration, ``[i]f the
person raising an objection can demonstrate to the EPA that it was
impracticable to raise such objection within [the period for public
comment] or if the grounds for such objection arose after the period
for public comment (but within the time specified for judicial review)
and if such objection is of central relevance to the outcome of the
rule.'' Any person seeking to make such a demonstration to us should
submit a Petition for Reconsideration to the Office of the
Administrator, U.S. EPA, Room 3000, William Jefferson Clinton Building,
1200 Pennsylvania Avenue NW., Washington, DC 20460, with a copy to both
the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT
section, and the Associate General Counsel for the Air and Radiation
Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200
Pennsylvania Avenue NW., Washington, DC 20460. Filing a petition for
reconsideration by the Administrator of this final action does not
affect the finality of this action for the purposes of judicial review,
nor does it extend the time within which a petition for judicial review
must be filed, and shall not postpone the effectiveness of this action.

II. Background

    On January 12, 2004, the EPA promulgated Procedure 2--Quality
Assurance Requirements for Particulate Matter Continuous Emission
Monitoring Systems at Stationary Sources (69 FR 1786). Procedure 2,
sections 10.4 (5) and (6), contain a requirement for conducting the
annual Relative Correlation Audit (RCA) or Relative Response Audit
(RRA) QA/QC test procedures, in which a specified amount of the
required number of PM CEMS response values, or data points, must lie
within the PM CEMS response range used to develop the PM CEMS
correlation curve. In other words, when conducting the annual QA/QC
tests, the PM CEMS response values should not be higher or lower than
the values used to develop the correlation curve for that PM CEMS.
Recently, as PM emission limits have been reduced and facilities have
installed more robust PM emission control devices, a number of
facilities have found that their PM emissions are lower than their PM
CEMS correlation curve and, as a result, the facilities are now unable
to meet the criteria needed to pass the annual Procedure 2 QA/QC tests.
The EPA proposed to modify this language in Procedure 2 through a
direct final rule (81 FR 83160; November 21, 2016) and a parallel
proposed rule (81 FR 83189; November 21, 2016). In the direct final
rule, the EPA stated that if the agency received any significant and
relevant adverse comments to the direct final rule, it would withdraw
the direct final rule and address all public comments in a subsequent
final rule based on the proposed rule. The EPA stated it would not
institute a second comment period on the proposed rule (81 FR 83161,
November 21, 2016). The EPA received one significant and relevant
adverse comment and, therefore, published a withdrawal of the direct
final rule (81 FR 10711; February 15, 2017). With this action, the EPA
is responding to the adverse comment and finalizing revisions to
Procedure 2.

III. Final Revisions to Procedure 2

    This action finalizes the changes to Procedure 2 that were proposed
on November 21, 2016 (81 FR 83189), and responds to the adverse comment
received in response to that proposal by addressing conflicting
language in sections 10.4(5) and 10.4(6).

IV. Summary of Major Comments and Responses

    A commenter stated that the revisions to Procedure 2, as proposed
by the EPA on November 21, 2016, do not achieve the intended result. As
the commenter points out, sections 10.4(5) and 10.4(6) still contain
language which requires that a portion of the data points from the RRA
and RCA ``must lie within the PM CEMS output range used to develop your
correlation curve.'' The commenter suggested that language in sections
10.4(5)(ii) and 10.4(6)(ii) be removed. The EPA agrees with the
commenter and removed the language in sections 10.4(5)(ii) and
10.4(6)(ii). In addition, the language allowing the extension of the
correlation curve to accommodate points that are lower than the
original curve has been moved to make it clear that it is needed only
when determining if the RRA and RCA meet the  25 percent
criteria originally contained in sections 10.4(5)(iii) and
10.4(6)(iii).

V. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    This action is not a significant regulatory action and was,
therefore, not submitted to the Office of Management and Budget (OMB)
for review.

B. Paperwork Reduction Act (PRA)

    This action does not impose an information collection burden under
the PRA. This action provides performance criteria and QA/QC test
procedures for assessing the acceptability of PM CEMS performance and
data quality. These criteria and QA/QC test procedures do not add
information collection requirements beyond those currently required
under the applicable regulation.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. This
action will not impose any requirements on small entities. There are no
small entities in the regulated industry for which Procedure 2 applies.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain any unfunded mandate as described in
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect
small governments. This action imposes no enforceable duty on any
state, local or tribal governments or the private sector.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    This action does not have tribal implications, as specified in
Executive Order 13175. Procedure 2 is applicable to facility owners and
operators who are responsible for one or more PM CEMS used for
monitoring emissions. Thus, Executive Order 13175 does not apply to
this action.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it does not concern an environmental
health risk or safety risk.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211, because it is
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    The EPA believes that this action will not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it does not affect the level of
protection provided to human health or the environment. This action
will help to ensure that emission control devices are operated properly
and maintained as needed, thereby helping to ensure compliance with
emission standards, which would benefit all affected populations.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is not a ``major rule'' as defined by 5
U.S.C. 804(2).

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Continuous emission monitoring systems,
Particulate matter, Performance specifications, Test methods and
procedures.

    Dated: August 7, 2017.
E. Scott Pruitt,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I of the
Code of Federal Regulations is amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

0
2. In Appendix F, Procedure 2, in section 10.4, paragraphs (5) and (6)
are revised to read as follows:

Appendix F to Part 60--Quality Assurance Procedures

* * * * *

Procedure 2--Quality Assurance Requirements for Particulate Matter
Continuous Emission Monitoring Systems at Stationary Sources

* * * * *
    10.4 * * *
    (5) What are the criteria for passing a RCA? To pass a RCA, you
must meet the criteria specified in paragraphs (5)(i) and (ii) of
this section. If your PM CEMS fails to meet these RCA criteria, it
is out of control.
    (i) For all 12 data points, the PM CEMS response value can be no
greater than the greatest PM CEMS response value used to develop
your correlation curve.
    (ii) At least 75 percent of a minimum number of 12 sets of PM
CEMS and reference method measurements must fall within a specified
area on a graph of the correlation regression line. The specified
area on the graph of the correlation regression line is defined by
two lines parallel to the correlation regression line, offset at a
distance of 25 percent of the numerical emission limit
value from the correlation regression line. If any of the PM CEMS
response values resulting from your RCA are lower than the lowest PM
CEMS response value of your existing correlation curve, you may
extend your correlation regression line to the point corresponding
to the lowest PM CEMS response value obtained during the RCA. This
extended correlation regression line must then be used to determine
if the RCA data meets this criterion.
    (6) What are the criteria to pass a RRA? To pass a RRA, you must
meet the criteria specified in paragraphs (6)(i) and (ii) of this
section. If your PM CEMS fails to meet these RRA criteria, it is out
of control.
    (i) For all three data points, the PM CEMS response value can be
no greater than the greatest PM CEMS response value used to develop
your correlation curve.
    (ii) At least two of the three sets of PM CEMS and reference
method measurements must fall within the same specified area on a
graph of the correlation regression line as required for the RCA and
described in paragraph (5)(ii) of this section.
* * * * *
[FR Doc. 2017-17123 Filed 8-11-17; 8:45 am]
BILLING CODE 6560-50-P