We evaluated process modifications and tail gas treatment options when we proposed 40 CFR part 60, subpart LLL. 49 FR 2656, 2659-2660 (1984). As we explained in the preamble to the proposed subpart LLL, control through sulfur recovery with tail gas treatment may not always be cost effective, depending on sulfur feed rate and inlet H2S concentrations. Therefore, other methods of increasing sulfur recovery via process modifications were evaluated. As shown in the original evaluation, the performance capabilities and costs of each of these technologies are highly dependent on the ratio of H2S and CO2 in the gas stream and the total quantity of sulfur in the gas stream being treated. The most effective means of control was selected as BSER for the different stream characteristics. As a result, separate emissions limitations were developed in the form of equations that calculate the required initial and continuous emission reduction efficiency for each plant. The equations were based on the design performance capabilities of the technologies selected as BSER relative to the gas stream characteristics. 49 FR 2656, 2663-2664 (1984). The emission limit for sulfur feed rates at or below 5 long tons per day, regardless of H2S content, was 79 percent. For facilities with sulfur feed rates above 5 long tons per day, the emission limits ranged from 79 percent at an H2S content below 10 percent to 99.8 percent for H2S contents at or above 50 percent.
	To review these emission limitations, we performed a search of the RBLC database and state regulations. No state regulations identified had emission limitations more stringent than 40 CFR part 60, subpart LLL. However, the RBLC database search identified two entries with SO2 emission reductions of 99.9 percent. One entry is for a facility in Bakersfield, California, with a 90 long ton per day sulfur recovery unit followed by an amine-based tail-gas treating unit. The second entry is for a facility in Coden, Alabama, with a sulfur recovery unit with a sulfur feed rate of 280 long tons per day, followed by selective catalytic reduction and a tail gas incinerator. However, neither of these entries contained information regarding the H2S contents of the feed stream. Because the sulfur recovery efficiency of these large sized plants was greater than 99.8 percent, we reevaluated the original data. Based on the available cost information, it appears that a 99.9- percent efficiency is cost effective for facilities with a sulfur feed rate greater than 5 long tons per day and H2S content equal to or greater than 50 percent. Based on our review, we are proposing that the maximum initial and continuous efficiency for facilities with a sulfur feed rate greater than 5 long tons per day and a H2S content equal to or greater than 50 percent be raised to 99.9 percent. We are not proposing to make changes to the equations.
      Our search of the RBLC database did not uncover information regarding costs and achievable emission reductions to suggest that the emission limitations for facilities with a sulfur feed rate less than 5 long tons per day or H2S content less than 50 percent should be modified. Therefore, we are not proposing any changes to the emissions limitations for facilities with sulfur feed rate and H2S content less than 5 long tons per day and 50 percent, respectively.
2. What pollutants are being evaluated in this Oil and Natural Gas NSPS package?
	The two current NSPS for the Oil and Natural Gas source category address emissions of VOC and SO2. In addition to these pollutants, sources in this source category also emit a variety of other pollutants, most notably, air toxics. As discussed elsewhere in this notice, there are NESHAP that address air toxics from the oil and natural gas sector.
	In addition, processes in the Oil and Natural Gas source category emit significant amounts of methane. The 1990 - 2009 U.S. GHG Inventory estimates 2009 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries) to be 251.55 MMtCO2e (million metric tons of CO2-equivalents (CO2e)). The emissions estimated from well completions and recompletions exclude a significant number of wells completed in tight sand plays, such as the Marcellus, due to availability of data when the 2009 Inventory was developed. The estimate in this proposal includes an adjustment for tight sand plays (being considered as a planned improvement in development of the 2010 Inventory). This adjustment would increase the 2009 Inventory estimate by 76.74 MMtCO2e. The total methane emissions from Petroleum and Natural Gas Systems, based on the 2009 Inventory, adjusted for tight sand plays and the Marcellus, is 328.29 MMtCO2e. Although this proposed rule does not include standards for regulating the GHG emissions discussed above, we continue to assess these significant emissions and evaluate appropriate actions for addressing these concerns. Because many of the proposed requirements for control of VOC emissions also control methane emissions as a co-benefit, the proposed VOC standards would also achieve significant reduction of methane emissions.
	Significant emissions of oxides of nitrogen (NOx) also occur at oil and natural gas sites due to the combustion of natural gas in reciprocating engines and combustion turbines used to drive the compressors that move natural gas through the system, and from combustion of natural gas in heaters and boilers. While these engines, turbines, heaters and boilers are co-located with processes in the oil and natural gas sector, they are not in the Oil and Natural Gas source category and are not being addressed in this action. The NOx emissions from engines and turbines are covered by the Standards of Performance for Stationary Spark Internal Combustion Engines (40 CFR part 60, subpart JJJJ) and Standards of Performance for Stationary Combustion Turbines (40 CFR part 60, subpart KKKK), respectively.
	An additional source of NOx emissions would be pit flaring of VOC emissions from well completions during periods where REC is not feasible, as would be required under our proposed operational standards for wellhead affected facilities. As discussed below in section VI.B.4 (well completion), pit flaring is the only way we identified of controlling VOC emissions during these periods. Because there is no way of directly measuring the NOx produced, nor is there any way of applying controls other than minimizing flaring, we propose to allow flaring only when REC is not feasible. We have included our estimates of NOx formation from pit flaring in our discussion of secondary impacts in section VI.B.4.
3. What emission sources are being evaluated in this Oil and Natural Gas NSPS package?
	The current NSPS only cover emissions of VOC and SO2 from one type of facility in the oil and natural gas sector, which is the natural gas processing plant. This is the only type of facility in the Oil and Natural Gas source category where we would expect SO2 to be emitted directly, although H2S contained in sour gas, when oxidized in the atmosphere or combusted in boilers and heaters in the field, forms SO2 as a product of oxidation. These field boilers and heaters are not part of the Oil and Natural Gas source category and are generally too small to be regulated by the NSPS covering boilers (i.e., they have a heat input of less than 10 million British Thermal Units per hour). However, we may consider addressing them as part of a future sector-based strategy for the oil and natural gas sector.
	In addition to VOC emissions from gas processing plants, there are numerous sources of VOC throughout the oil and natural gas sector that are not addressed by the current NSPS. As explained above in section V.A, pursuant to CAA section 111(b), to the extent necessary, we are modifying the listed category to include all segments of the oil and natural gas industry for regulation. We are also proposing VOC standards to cover additional processes at oil and natural gas operations. These include NSPS for VOC from gas well completions, pneumatic controllers, compressors and storage vessels.
	We believe that produced water ponds are also a potentially significant source of emissions, but we have only limited information. We, therefore, solicit comments on produced water ponds, particularly in the following subject areas:
	(a) We are requesting comments pertaining to methods for calculating emissions. The State of Colorado currently uses a mass balance that assumes 100 percent of the VOC content is emitted to the atmosphere. Water9, an air emissions model, is another option that has some limitations, including poor methanol estimation.
	(b) We are requesting additional information on typical VOC content in produced water and any available chemical analyses, including data that could help clarify seasonal variations or differences among gas fields. Additionally, we request data that increase our understanding of how changing process variables or age of wells affect produced water output and VOC content.
	(c) We solicit information on the size and throughput capacity of typical evaporation pond facilities and request suggestions on parameters that could be used to define affected facilities or affected sources. We also seek information on impacts of smaller evaporation pits that are co-located with drilling operations, whether those warrant control and, if so, how controls should be developed.
	(d) An important factor is cost of emission reduction technologies, including recovery credits or cost savings realized from recovered salable product. We are seeking information on these considerations as well.
	(e) We are also seeking information on any limitations for emission reduction technologies such as availability of electricity, waste generation and disposal and throughput and concentration constraints.
	(f) Finally, we solicit information on separator technologies that are able to improve the oil-water separation efficiency.
4. What are the rationales for the proposed NSPS?
	We have provided below our rationales for the proposed BSER determinations and performance standards for a number of VOC emission sources in the Oil and Natural Gas source category that are not covered by the existing NSPS. Our general process for evaluating systems of emission reduction for the emission sources discussed below included: (1) Identification of available control measures; (2) evaluation of these measures to determine emission reductions achieved, associated costs, nonair environmental impacts, energy impacts and any limitations to their application; and (3) selection of the control techniques that represent BSER based on the information we considered.
	We identified the control options discussed in this package through our review of relevant state and local requirements and mitigation measures developed and reported by the EPA's Natural Gas STAR program. The EPA's Natural Gas STAR program has worked with industry partners since 1993 to identify cost effective measures to reduce emissions of methane and other pollutants from natural gas operations. We relied heavily on this wealth of information in conducting this review. We also identified state regulations, primarily in Colorado and Wyoming, which require mitigation measures for some emission sources in the Oil and Natural Gas source category.
a. NSPS for Well Completions
	Well completion activities are a significant source of VOC emissions, which occur when natural gas and non-methane hydrocarbons are vented to the atmosphere during flowback of a hydraulically fractured gas well. Flowback emissions are short-term in nature and occur over a period of several days following fracturing of a new well or refracturing of an existing well. Well completions include multiple steps after the well bore hole has reached the target depth. These steps include inserting and cementing-in well casing, perforating the casing at one or more producing horizons, and often hydraulically fracturing one or more zones in the reservoir to stimulate production. Well recompletions may also include hydraulic fracturing. Hydraulic fracturing is one technique for improving gas production where the reservoir rock is fractured with very high pressure fluid, typically water emulsion with a proppant (generally sand) that "props open" the fractures after fluid pressure is reduced. Emissions are a result of the backflow of the fracture fluids and reservoir gas at high volume and velocity necessary to lift excess proppant and fluids to the surface. This multi-phase mixture is often directed to a surface impoundment where natural gas and VOC vapors escape to the atmosphere during the collection of water, sand and hydrocarbon liquids. As the fracture fluids are depleted, the backflow eventually contains more volume of natural gas from the formation. Wells that are fractured generally have great amounts of emissions because of the extended length of the flowback period required to purge the well of the fluids and sand that are associated with the fracturing operation. Along with the fluids and sand from the fracturing operation, the 3 to 10-day flowback period also results in emissions of natural gas and VOC that would not occur in large quantities at oil wells or at natural gas wells that are not fractured. Thus, we estimate that gas well completions involving hydraulic fracturing vent substantially more VOC, approximately 200 times more, than completions not involving hydraulic fracturing. Specifically, we estimate that uncontrolled well completion emissions for a hydraulically fractured gas well are approximately 23 tons of VOC, where emissions for a conventional gas well completion are around 0.12 tons VOC. These estimates are explained in detail in the TSD available in the docket. Based on our review, we believe that emissions from recompletions of previously completed wells that are fractured or refractured to stimulate production or to begin production from a new production horizon are of similar magnitude and composition as emissions from completions of new wells that have been hydraulically fractured.
      EPA has based the NSPS impacts analysis on best available emission data. However, we recognize that there is uncertainty associated with our estimates. For both new completions and recompletions, there are a variety of factors that will determine the length of the flowback period and actual volume of emissions such as the number of zones, depth, pressure of the reservoir, gas composition, etc. This variability means there will be some wells which emit more than the estimated emission factor and some wells that emit less.
	During our review, we examined information from the Natural Gas STAR program and the Colorado and Wyoming state rules covering well completions. We identified two subcategories of fractured gas wells: (1) Non-exploratory and non-delineation wells; and (2) exploratory and delineation wells. An exploratory well is the first well drilled to determine the presence of a producing reservoir and the well's commercial viability. A delineation well is a well drilled to determine the boundary of a field or producing reservoir. Because exploratory and delineation wells are generally isolated from existing producing wells, there are no gathering lines available for collection of gas recovered during completion operations. In contrast, non-exploratory and non-delineation wells are located where existing, producing wells are connected to gathering lines and are, therefore, able to be connected to a gathering line to collect recovered salable natural gas product that would otherwise be vented to the atmosphere or combusted.
      For subcategory 1, we identified "green" completion, which we refer to as REC, as an option for reducing VOC emissions during well completions. REC are performed by separating the flowback water, sand, hydrocarbon condensate and natural gas to reduce the portion of natural gas and VOC vented to the atmosphere, while maximizing recovery of salable natural gas and VOC condensate. In some cases, for a portion of the completion operation, such as when CO2 or nitrogen is injected with the fracture water, initial gas produced is not of suitable quality to introduce into the gathering line due to CO2 or nitrogen content or other undesirable characteristic. In such cases, for a portion of the flowback period, gas cannot be recovered, but must be either vented or combusted. In practice, REC are often combined with combustion to minimize the amount of gas and condensate being vented. This combustion process is rather crude, consisting of a horizontal pipe downstream of the REC equipment, fitted with a continuous ignition source and discharging over a pit near the wellhead. Because of the nature of the flowback (i.e., with periods of water, condensate, and gas in slug flow), conveying the entire portion of this stream to a traditional flare control device or other control device, such as a vapor recovery unit, is not feasible. These control devices are not designed to accommodate the multiphase flow consisting of water, sand and hydrocarbon liquids, along with the gas and vapor being controlled. Although "pit flaring" does not employ a traditional flare control device, and is not capable of being tested or monitored for efficiency due to the multiphase slug flow and intermittent nature of the discharge of gas, water and sand over the pit, it does provide a means of minimizing vented gas and is preferable to venting. Because of the rather large exposed flame, open pit flaring can present a fire hazard or other undesirable impacts in some situations (e.g., dry, windy conditions, proximity to residences, etc.). As a result, we are aware that owners and operators may not be able to pit flare unrecoverable gas safely in every case. In some cases, pit flaring may be prohibited by local ordinance.
	Equipment required to conduct REC may include tankage, special gas-liquid-sand separator traps and gas dehydration. Equipment costs associated with REC will vary from well to well. Typical well completions last between 3 and 10 days and costs of performing REC are projected to be between $700 and $6,500 per day, including a cost of approximately $3,523 per completion event for the pit flaring equipment. However, there are savings associated with the use of REC because the gas recovered can be incorporated into the production stream and sold. In fact, we estimate that REC will result in an overall net cost savings in many cases.
      The emission reductions for a hydraulically fractured well are estimated to be around 22 tons of VOC. Based on an average incremental cost of $33,237 per completion, the cost effectiveness of REC, without considering any cost savings, is around $1,516 per ton of VOC (which we have previously found to be cost effective on average). When the value of the gas recovered (approximately 150 tons of methane per completion) is considered, the cost effectiveness is estimated as an average net savings of $99 per ton VOC reduced, using standard discount rates. We believe that these costs are very reasonable, given the emission reduction that would be achieved. Aside from the potential hazards associated with pit flaring, in some cases, we did not identify any nonair environmental impacts, health or energy impacts associated with REC combined with combustion. However, pit flaring would produce NOx emissions. Because we believe that these emissions cannot be controlled or measured directly due to the open combustion process characteristic of pit flaring, we used published emission factors (EPA Emission Guidelines AP-42)to estimate the NOx emissions for purposes of assessing secondary impacts. For category 1 well completions, we estimated that 0.02 tons of NOx are produced per event. This is based on the assumption that 5 percent of the flowback gas is combusted by the combustion device. The 1.2 tons of VOC controlled during the pit flaring portion of category 1 well completions is approximately 57 times greater than the NOx produced by pit flaring.  Thus, we believe that the benefit of the VOC reduction far outweighs the secondary impact of NOx formation during pit flaring.
      We believe that, based on the analysis above, REC in combination with combustion is BSER for subcategory 1 wells. We considered setting a numerical performance standard for subcategory 1 wells. However, it is not practicable to measure the emissions during pit flaring or venting because the gas is discharged over the pit along with water and sand in multiphase slug flow. Therefore, we believe it is not feasible to set a numerical performance standard. Pursuant to section 111(h)(2) of the CAA, we are proposing an operational standard for subcategory 1 wells that would require a combination of REC and pit flaring to minimize venting of gas and condensate vapors to the atmosphere, with provisions for venting in lieu of pit flaring for situations in which pit flaring would present safety hazards or for periods when the flowback gas is noncombustible due to high concentrations of nitrogen or CO2. The proposed operational standard would be accompanied by requirements for documentation of the overall duration of the completion event, duration of recovery using REC, duration of combustion, duration of venting, and specific reasons for venting in lieu of combustion.
      We recognize that there is heterogeneity in well operations and costs, and that while RECs may be cost-effective on average, they may not be for all operators.  Nonetheless, EPA is proposing to require an operational standard rather than a performance-based standard (e.g., requiring that some percentage of emissions be flared or captured), because we believe there are no feasible ways for operators to measure emissions with enough certainty to demonstrate compliance with a performance-based standard for REC in combination with pit flaring. The EPA requests comment on this and seeks input on whether alternative approaches to requiring REC for all operators with access to pipelines may exist that would allow operators to meet a performance-based standard if they can demonstrate that an REC is not cost effective.
      We have discussed above certain situations where unrecoverable gas would be vented because pit flaring would present a fire hazard or is infeasible because gas is noncombustible due to high concentrations of nitrogen or CO2. We solicit comment on whether there are other such situations where flaring would be unsafe or infeasible, and potential criteria that would support venting in lieu of pit flaring.  In addition, we learned that coalbed methane reservoirs may have low pressure, which would present a technical barrier for performing a REC because the well pressure may not be substantial enough to overcome gathering line pressure. In addition, we identified that coalbed methane wells often have low to almost no VOC emissions, even following the hydraulic fracturing process. We solicit comment on criteria and thresholds that could be used to exempt some well completion operations occurring in coalbed methane reservoirs from the requirements for subcategory 1 wells.
	Of the 25,000 new and modified fractured gas wells completed each year, we estimate that approximately 3,000 to 4,000 currently employ reduced emission completion. We expect this number to increase to over 21,000 REC annually as operators comply with the proposed NSPS. We estimate that approximately 9,300 new wells and 12,000 existing wells will be fractured or refractured annually that would be subject to subcategory 1 requirements under the NSPS. We believe that there will be a sufficient supply of REC equipment available by the time the NSPS becomes effective. However, energy availability could be affected if a shortage of REC equipment was allowed to cause delays in well completions. We request comment on whether sufficient supply of this equipment and personnel to operate it will be available to accommodate the increased number of REC by the effective date of the NSPS. We also request specific estimates of how much time would be required to get enough equipment in operation to accommodate the full number of REC performed annually.
	In the event that public comments indicate that available equipment would likely be insufficient to accommodate the increase in number of REC performed, we are considering phasing in requirements for well completions that would achieve an overall comparable level of environmental benefit. For example, operators performing completions of fractured or refractured existing wells (i.e., modified wells) could be allowed to control emissions through pit flaring instead of REC for some period of time. After some date certain, all modified wells would be subject to REC. We solicit comment on the phasing of requirements for REC along with suggestions for other ways to address a potential short-term REC equipment shortage that may hinder operators' compliance with the proposed NSPS, while also achieving a comparable level of reduced emissions to the air.
	Although we have determined that, on average, reduced emission completions are cost effective, well and reservoir characteristics could vary, such that some REC are more cost effective than others. Unlike most stationary source controls, REC equipment is used only for a 3 to 10 day period. Our review found that most operators contract with service companies to perform REC rather than purchase the equipment themselves, which was reflected in our economic analysis. It is also possible that the contracting costs of supplying and operating REC equipment may rise in the short term with the increased demand for those services. We request comment and any available technical information to judge whether our assumption of $33,237 per well completion for this service given the projected number of wells in 2015 subject to this requirement is accurate.
	We believe that the proposed rule regulates only significant emission sources for which controls are cost-effective. Nevertheless, we solicit comment and supporting data on appropriate thresholds (e.g., pressure, flowrate) that we should consider in specifying which well completions are subject to the REC requirements for subcategory 1 wells. Comments specifying thresholds should include an analysis of why sources below these thresholds are not cost effective to control.
      In addition, there may be economic, technical or other opportunities or barriers associated with performing cost effective REC that we have not identified in our review. For example, some small regulated entities may have an increased source of revenue due to the captured product. On the other hand, some small regulated entities may have less access to REC than larger regulated entities might have. We request information on such opportunities and barriers that we should consider and suggestions for how we may take them into account in structuring the NSPS.
      The second subcategory of fractured gas wells includes exploratory wells or delineation wells. Because these types of wells generally are not in proximity to existing gathering lines, REC is not an option, since there is no infrastructure in place to get the recovered gas to market or further processing. For these wells, the only potential control option we were able to identify is pit flaring, described above. As explained above, because of the slug flow nature of the flowback gas, water and sand, control by a traditional flare control device or other control devices, such as vapor recovery units, is infeasible, which leaves pit flaring as the only practicable control system for subcategory 2 wells. As also discussed above, open pit flaring can present a fire hazard or other undesirable impacts in some situations. Aside from the potential hazards associated with pit flaring, in some cases, we did not identify any nonair environmental impacts, health or energy impacts associated with pit flaring. However, pit flaring would produce NOx emissions. As in the case of category 1 wells, we believe that these emissions cannot be controlled or measured directly due to the open combustion process characteristic of pit flaring.  We again used published emission factors to estimate the NOx emissions for purposes of assessing secondary impacts. For category 2 well completions, we estimated that 0.32 tons of NOx are produced as secondary emissions per completion event. This is based on the assumption that 95 percent of flowback gas is combusted by the combustion device. The 22 tons of VOC reduced during the pit flaring used to control category 2 well completions is approximately 69 times greater than the NOx produced.  Thus, we believe that the benefit of the VOC reduction far outweighs the secondary impact of NOx formation during pit flaring.
      In light of the above, we propose to determine that BSER for subcategory 2 wells would be pit flaring. As we explained above, it is not practicable to measure the emissions during pit flaring or venting because the gas is discharged during flowback mixed with water and sand in multiphase slug flow. It is, therefore, not feasible to set a numerical performance standard.
      Pursuant to CAA section 111(h)(2), we are proposing an operational standard for subcategory 2 wells that requires minimization of venting of gas and hydrocarbon vapors during the completion operation through the use of pit flaring, with provisions for venting in lieu of pit flaring for situations in which flaring would present safety hazards or for periods when the flowback gas is noncombustible due to high concentrations of nitrogen or carbon dioxide.
      Consistent with requirements for subcategory 1 wells, owners or operators of subcategory 2 wells would be required to document completions and provide justification for periods when gas was vented in lieu of combustion. We solicit comment on whether there are other such situations where flaring would be unsafe or infeasible and potential criteria that would support venting in lieu of pit flaring.
	For controlling completion emissions at oil wells and conventional (non-fractured) gas wells, we have identified and evaluated the following control options: REC in conjunction with pit flaring and pit flaring alone. Due to the low uncontrolled VOC emissions of approximately 0.007 ton per completion and, therefore, low potential emission reductions from these events, the cost per ton of reduction based on REC would be extremely high (over $700,000 per ton of VOC reduced). We evaluated the use of pit flaring alone as a system for controlling emissions from oil wells and conventional gas wells and determined that the cost cost-effectiveness would be approximately $520,000 per ton for oil wells and approximately $32,000 per ton for conventional gas wells. In light of the high cost per ton of VOC reduction, we do not consider either of these control options to be BSER for oil wells and conventional wells.
      We propose that fracturing (or refracturing) and completion of an existing well (i.e., a well existing prior to (INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER)) is considered a modification under CAA section 111(a), because physical change occurs to the existing well, which includes the wellbore, casing and tubing, resulting in an emissions increase during the completion operation. The physical change, in this case, would be caused by the reperforation of the casing and tubing, along with the refracturing of the wellbore. The increased VOC emissions would occur during the flowback period following the fracturing or refracturing operation. Therefore, the proposed standards for category 1 and category 2 wells would apply to completions at existing fractured or refractured wells.
      EPA seeks comment on the 10 percent per year rate of refracturing for natural gas wells assumed in the impacts analysis found in the TSD. EPA has received anecdotal information suggesting that refracturing could be occurring much less frequently, while others suggest that the percent of wells refractured in a given year could be greater. We seek comment and comprehensive data and information on the rate of refracturing and key factors that influence or determine refracturing frequency.
      In addition to well completions, we considered VOC emissions occurring at the wellhead affected facility during subsequent day-to-day operations during well production. As discussed below in section VI.B.1.e, VOC emissions from wellheads are very small during production and account for about 2.6 tons VOC per year. We are not aware of any cost effective controls that can be used to address these relatively small emissions.
b. NSPS for Pneumatic Controllers
	Pneumatic controllers are automated instruments used for maintaining a process condition, such as liquid level, pressure, pressure differential and temperature. Pneumatic controllers are widely used in the oil and natural gas sector. In many situations across all segments of the oil and gas industry, pneumatic controllers make use of the available high-pressure natural gas to operate. In these "gas-driven" pneumatic controllers, natural gas may be released with every valve movement or continuously from the valve control pilot. The rate at which this release occurs is referred to as the device bleed rate. Bleed rates are dependent on the design of the device. Similar designs will have similar steady-state rates when operated under similar conditions. Gas-driven pneumatic controllers are typically characterized as "high-bleed" or "low-bleed," where a high-bleed device releases more than 6 standard cubic feet per hour (scfh) of gas, with 18 scfh bleed rate being what we used in our analyses below. There are three basic designs: (1) Continuous bleed devices (high or low-bleed) are used to modulate flow, liquid level or pressure and gas is vented at a steady-state rate; (2) actuating/intermittent devices (high or low-bleed) perform quick control movements and only release gas when they open or close a valve or as they throttle the gas flow; and (3) self-contained devices release gas to a downstream pipeline instead of to the atmosphere. We are not aware of any add-on controls that are or can be used to reduce VOC emissions from gas-driven pneumatic devices.
	For an average high-bleed pneumatic controller located in production (where the content of VOC in the raw product stream is relatively high), the difference in VOC emissions between a high-bleed controller and a low-bleed controller is around 1.8 tpy. For the transmission and storage segment (where the content of VOC in the pipeline quality gas is relatively low), the difference in VOC emissions between a high-bleed controller and a low-bleed controller is around 0.89 tpy. We have developed projections that estimate that approximately 13,600 new gas-driven units in the production segment and 67 new gas-driven units in the transmission and storage segment will be installed each year, including replacement of old units. Not all pneumatic controllers are gas driven. These "non-gas driven" pneumatic controllers use sources of power other than pressurized natural gas, such as compressed "instrument air." Because these devices are not gas driven, they do not release natural gas or VOC emissions, but they do have energy impacts because electrical power is required to drive the instrument air compressor system. Electrical service of at least 13.3 kilowatts (kW) is required to power a 10 horsepower (hp) instrument air compressor, which is a relatively small capacity compressor. At sites without available electrical service sufficient to power an instrument air compressor, only gas driven pneumatic devices can be used. During our review, we determined that gas processing plants are the only facilities in the oil and natural gas sector highly likely to have electrical service sufficient to power an instrument air system, and that approximately half of existing gas processing plants are using non-gas driven devices.
      For devices at gas processing plants, we evaluated the use of non-gas driven controllers and low-bleed controllers as options for reducing VOC emissions, with high-bleed controllers being the baseline. As mentioned above, non-gas driven devices themselves have zero emissions, but they do have energy impacts because electrical power is required to drive the instrument air compressor system. In our cost analysis, we determined that the annualized cost of installing and operating a fully redundant 10 hp (13.3 kW) instrument air system (systems generally are designed with redundancy to allow for system maintenance and failure without loss of air pressure), including duplicate compressors, air tanks and dryers, would be $11,090. A system of this size is capable of serving 15 control loops and reducing VOC emissions by 4.2 tpy, for a cost effectiveness of $2,659 per ton of VOC reduced. If the savings of the salable natural gas that would have been emitted is considered, the value of the gas not emitted would help offset the cost for this control, bringing the cost per ton of VOC down to $1,824.
      We also evaluated the use of low-bleed controllers in place of high-bleed controllers at processing plants. We evaluated the impact of bleeding 6 standard cubic feet of natural gas per hour, which is the maximum bleed rate from low-bleed controllers, according to manufacturers of these devices. We chose natural gas as a surrogate for VOC, because manufacturers' technical specifications for pneumatic controllers are stated in terms of natural gas bleed rate rather than VOC. The capital cost difference between a new high-bleed controller and a new low-bleed controller is estimated to be $165. Without taking into account the savings due to the natural gas losses avoided, the annual costs are estimated to be around $23 per year, which is a cost of $13 per ton of VOC reduced for the production segment. If the savings of the salable natural gas that would have been emitted is considered, there is a net savings of $1,519 per ton of VOC reduced.
      Although the non-gas-driven controller system is more expensive than the low-bleed controller system, it is still reasonably cost-effective. Furthermore, the non-gas-driven controller system achieves a 100-percent VOC reduction in contrast to a 66-percent reduction achieved by a low-bleed controller. Moreover, we believe the collateral emissions from electrical power generation needed to run the compressor are very low. Finally, non-gas-driven pneumatic controllers avoid potentially explosive concentrations of natural gas which can occur as a result of normal bleeding from groups of gas-driven pneumatic controllers located in close proximity, as they often are at gas processing plants. Based on our review described above, we believe that a non-gas-driven controller is BSER for reducing VOC emissions from pneumatic devices at gas processing plants. Accordingly, the proposed standard for pneumatic devices at gas processing plants is a zero VOC emission limit.
      For the production (other than processing plants) and transmission and storage segments, where electrical service sufficient to power an instrument air system is likely unavailable and, therefore, only gas-driven devices can be used, we evaluated the use of low-bleed controllers in place of high-bleed controllers. Just as in our analysis of low-bleed controllers as an option for gas processing plants, we evaluated the impact of bleeding 6 standard cubic feet per minute (scfm) of natural gas per hour contrasted with 18 scfm from a high-bleed unit. Again, the capital cost difference between a new high-bleed controller and a new low-bleed controller is estimated to be $165. Without taking into account the savings due to the natural gas losses avoided, the annual costs are estimated to be around $23 per year, which is a cost of $13 per ton of VOC reduced for the production segment. If the savings of the salable natural gas that would have been emitted is considered, there is a net savings for this control. In the transmission and storage segment, where the VOC content of the vented gas is much lower than in the production segment, the cost effectiveness of a low-bleed pneumatic device is estimated to be around $262 per ton of VOC reduced. However, there are no potential offsetting savings to be realized in the transmission and storage segment, since the operators of transmission and storage stations typically do not own the gas they are handling. Based on our evaluation of the emissions and costs, we believe that low-bleed controllers represent BSER for pneumatic controllers in the production (other than processing plants) and transmission and storage segments. Therefore, for pneumatic devices at these locations, we propose a natural gas bleed rate limit of 6.0 scfh to reflect the VOC limit with the use of a low-bleed controller.
There may be situations where high-bleed controllers and the attendant gas bleed rate greater than 6 cubic feet per hour, are necessary due to functional requirements, such as positive actuation or rapid actuation. An example would be controllers used on large emergency shutdown valves on pipelines entering or exiting compression stations. For such situations, we have provided in the proposed rule an exemption where pneumatic controllers meeting the emission standards discussed above would pose a functional limitation due to their actuation response time or other operating characteristics. We are requesting comments on whether there are other situations that should be considered for this exemption. If you provide such comment, please specify the criteria for such situations that would help assure that only appropriate exemptions are claimed.
The proposed standards would apply to installation of a new pneumatic device (including replacing an existing device with a new device). We consider that a pneumatic device, an apparatus, is an affected facility and each installation is construction subject to the proposed NSPS.  See definitions of "affected facility" and "construction" at 40 CFR 60.2.
c. NSPS for Compressors
	There are many locations throughout the oil and natural gas sector where compression of natural gas is required to move it along the pipeline. This is accomplished by compressors powered by combustion turbines, reciprocating internal combustion engines or electric motors. Turbine-powered compressors use a small portion of the natural gas that they compress to fuel the turbine. The turbine operates a centrifugal compressor, which compresses the natural gas for transit through the pipeline. Sometimes an electric motor is used to turn a centrifugal compressor. This type of compressor does not require the use of any of the natural gas from the pipeline, but it does require a substantial source of electricity. Reciprocating spark ignition engines are also used to power many compressors, referred to as reciprocating compressors, since they compress gas using pistons that are driven by the engine. Like combustion turbines, these engines are fueled by natural gas from the pipeline. Both centrifugal and reciprocating compressors are sources of VOC emissions and were evaluated for coverage under the NSPS.
      Centrifugal Compressors. Centrifugal compressors require seals around the rotating shaft to minimize gas leakage and fugitive VOC emissions from where the shaft exits the compressor casing. There are two types of seal systems: Wet seal systems and mechanical dry seal systems.
      Wet seal systems use oil, which is circulated under high pressure between three or more rings around the compressor shaft, forming a barrier to minimize compressed gas leakage. Very little gas escapes through the oil barrier, but considerable gas is absorbed by the oil. The amount of gas absorbed and entrained by the oil barrier is affected by the operating pressure of the gas being handled; higher operating pressures result in higher absorption of gas into the oil. Seal oil is purged of the absorbed and entrained gas (using heaters, flash tanks and degassing techniques) and recirculated to the seal area for reuse. Gas that is purged from the seal oil is commonly vented to the atmosphere. Degassing of the seal oil emits an average of 47.7 scfm of gas, depending on the operating pressure of the compressor. An uncontrolled wet seal system can emit, on average, approximately 20.5 tpy of VOC during the venting process (production segment) or about 3.5 tpy (transmission and storage segment). We identified two potential control techniques for reducing emissions from degassing of wet seal systems: (1) Routing the gas back to a low pressure fuel stream to be combusted as fuel gas and (2) routing the gas to a flare. We know only of anecdotal, undocumented information on routing of the gas back to a fuel stream and, therefore, were unable to assess costs and cost effectiveness of the first option. Although we do not have specific examples of routing emissions from wet seal degassing to a flare, we were able to estimate the cost, emission reductions and cost effectiveness of the second option using uncontrolled wet seals as a baseline.
      Based on the average uncontrolled emissions of wet seal systems discussed above and a flare efficiency of 95 percent, we determined that VOC emission reductions from a wet seal system would be an average of 19.5 tpy (production segment) or 3.3 tpy (transmission and storage segment). Using an annualized cost of flare installation and operation of $103,373, we estimated the incremental cost effectiveness of this option (from uncontrolled wet seals to controlled wet seals using a flare) to be approximately $5,300/ton and $31,000/ton for the production segment and transmission and storage segment, respectively. With this option, there would be secondary air impacts from combustion. However we did not identify any nonair quality or energy impacts associated with this control technique.
      Dry seal systems do not use any circulating seal oil. Dry seals operate mechanically under the opposing force created by hydrodynamic grooves and springs. Fugitive emissions occur from dry seals around the compressor shaft. Based on manufacturer studies and engineering design estimates, fugitive emissions from dry seal systems are approximately 6 scfm of gas, depending on the operating pressure of the compressor. A dry seal system can have fugitive emissions of, on average, approximately 2.6 tpy of VOC (production segment) or about 0.4 tpy (transmission and storage segment). We did not identify any control device suitable to capture and control the fugitive emissions from dry seals around the compressor shaft.
      Using uncontrolled wet seals as a baseline, we evaluated the reductions and incremental cost effectiveness of dry seal systems. Based on the average fugitive emissions, we determined that VOC emission reductions achieved by dry seal systems compared to uncontrolled wet seal systems would be 18 tpy (production segment) and 3.1 tpy (transmission and storage segment). Combined with an annualized cost of dry seal systems of $10,678, the incremental cost effectiveness compared to uncontrolled wet seal systems would be $595/ton and $3,495/ton for the production segment and transmission and storage segment, respectively. We identified neither nonair quality nor any energy impacts associated with this option.
      In performing our analysis, we estimated the incremental cost of a dry seal compressor over that of an equivalent wet seal compressor to be $75,000. This value was obtained from a vendor who represents a large share of the market for centrifugal compressors. However, this number likely represents a conservatively high value because wet seal units have a significant amount of ancillary equipment, namely the seal oil system and, thus, additional capital expenses. Dry seal systems have some ancillary equipment (the seal gas filtration system), but the costs are less than the wet seal oil system. We were not able to directly confirm this assumption with the vendor, however, a search of product literature showed that seal oil systems and seal gas filtration systems are typically listed separate from the basic compressor package. Using available data on the cost of this equipment, it is very likely that the cost of purchasing a dry seal compressor may actually be lower that a wet seal compressor. We seek comment on available cost data of a dry seal versus wet seal compressor, including all ancillary equipment costs.
      In light of the above analyses, we propose to determine that dry seal systems are BSER for reducing VOC emissions from centrifugal compressors. We evaluated the possibility of setting a performance standard that reflects the emission limitation achievable through the use of a dry seal system. However, as mentioned above, VOC from centrifugal compressors with dry seals are fugitive emissions from around the compressor shafts. There is no device to capture and control these fugitive emissions, nor can reliable measurement of these emissions be conducted due to difficulty in accessing the leakage area and danger of contacting the shaft rotating at approximately 30,000 revolutions per minute. This not only poses a likely hazard that would destroy test equipment on contact, it poses a safety hazard to personnel, as well. Therefore, pursuant to section 111(h)(2) of the CAA, we are proposing an equipment standard that would require the use of dry seals to limit the VOC emissions from new centrifugal compressors. We consider that a centrifugal compressor, an apparatus, is an affected facility and each installation is construction subject to the proposed NSPS. See definitions of "affected facility" and "construction" at 40 CFR 60.2. Accordingly, the proposed standard would apply to installation of new centrifugal compressors at new locations, as well as replacement of old compressors.
      Although we are proposing to determine dry seal systems to be BSER for centrifugal compressors, we are soliciting comments on the emission reduction potential, cost and any limitations for the option of routing the gas back to a low pressure fuel stream to be combusted as fuel gas. In addition, we solicit comments on whether there are situations or applications where wet seal is the only option, because a dry seal system is infeasible or otherwise inappropriate.
	Reciprocating Compressors. Reciprocating compressors in the natural gas industry leak natural gas fugitive VOC during normal operation. The highest volumes of gas loss and fugitive VOC emissions are associated with piston rod packing systems. Packing systems are used to maintain a tight seal around the piston rod, preventing the high pressure gas in the compressor cylinder from leaking, while allowing the rod to move freely. This leakage rate is dependent on a variety of factors, including physical size of the compressor piston rod, operating speed and operating pressure. Under the best conditions, new packing systems properly installed on a smooth, well-aligned shaft can be expected to leak a minimum of 11.5 scfh. Higher leak rates are a consequence of fit, alignment of the packing parts and wear.
      We evaluated the possibility of reducing VOC emissions from reciprocal compressors through a control device. However, VOC from reciprocating compressors are fugitive emissions from around the compressor shafts. Although it is possible to construct an enclosure around the rod packing area and vent the emissions outside for safety purposes, connection to a closed vent system and control device would create back pressure on the leaking gas. This back pressure would cause the leaked gas instead to be forced inside the crankcase of the engine, which would dilute lubricating oil, causing premature failure of engine bearings, pose an explosion hazard and eventually be vented from the crankcase breather, defeating the purpose of a control device.
      As mentioned above, as packing wears and deteriorates, leak rates can increase. We, therefore, evaluate replacement of compressor rod packing systems as an option for reducing VOC emissions. Conventional bronze-metallic packing rings wear out and need to be replaced every 3 to 5 years, depending on the compressor's rate of usage (i.e., the percentage of time that a compressor is in pressurized mode).
      Based on industry experience in the Natural Gas STAR program and other sources, we evaluated the rod packing replacement costs for reciprocating compressors at different segments of this industry. Usage rates vary by segment. Usage rates for compressors at wellheads, gathering/boosting stations, processing plants, transmission stations and storage facilities are 100, 79, 90, 79 and 68 percent, respectively. Reciprocating compressors at wellheads are small and operate at lower pressures, which limit VOC emissions from these sources. Due to the low VOC emissions from these compressors, about 0.044 tpy, combined with an annual cost of approximately $3,700, the cost per ton of VOC reduction is rather high. We estimated that the cost effectiveness of controlling wellhead compressors is over $84,000 per ton of VOC reduced, which we believe to be too high and, therefore, not reasonable. Because the cost effectiveness of replacing packing wellhead compressor rod systems is not reasonable, and absent other emission reduction measures, we did not find a BSER for reducing VOC emissions from reciprocal compressors at wellheads.
      For reciprocating compressors located at other oil and gas operations, we estimated that the cost effectiveness of controlling compressor VOC emissions by rod packing replacement would be $870 per ton of VOC for reciprocating compressors at gathering and boosting stations, $270 per ton of VOC for reciprocating compressors at processing stations, $2,800 per ton of VOC for reciprocating compressors at transmission stations and $3,700 per ton of VOC for reciprocating compressors at underground storage facilities. We consider these costs to be reasonable. We did not identify any nonair quality health or environmental impacts or energy impacts associated with rod packing replacement. In light of the above, we propose to determine that such control is the BSER for reducing VOC emission from compressors at these other oil and gas operations.
 Because VOC emitted from reciprocal compressors are fugitive emissions, there is no device to capture and control the emissions. Therefore, pursuant to section 111(h) of the CAA, we are proposing an operational standard. Based on industry experience reported to the Natural Gas STAR program, we determined that packing rods should be replaced every 3 years of operation. However, to account for segments of the industry in which reciprocating compressors operate in pressurized mode a fraction of the calendar year (ranging from approximately 68 percent up to approximately 90 percent), the proposed rule expresses the replacement requirement in terms of hours of operation rather than on a calendar year basis.  One year of continuous operation would be 8,760 hours. Three years of continuous operation would be 26,280 hours, or rounded to the nearest thousand, 26,000 hours. Accordingly, the proposed rule would require the replacement of the rod packing every 26,000 hours of operation. The owner or operator would be required to monitor the hours of operation beginning with the installation of the reciprocating compressor affected facility. Cumulative hours of operation would be reported each year in the facility's annual report. Once the hours of operation reached 26,000 hours, the owner or operator would be required to change the rod packing immediately, although unexpected shutdowns could be avoided by tracking hours of operation and planning for packing replacement at scheduled maintenance shutdowns before the hours of operation reached 26,000.
      Some industry partners of the Natural Gas STAR program currently conduct periodic testing to determine the leakage rates that would identify economically beneficial replacement of rod packing based on natural gas savings. Therefore, we are soliciting comments on incorporating a method similar to that in the Natural Gas STAR's Lessons Learned document entitled, Reducing Methane Emissions from Compressor Rod Packing Systems (http://www.epa.gov/gasstar/documents/ll_rodpack.pdf), to be incorporated in the NSPS. We are soliciting comments on how to determine a suitable leak threshold above which rod packing replacement would be cost effective for VOC emission reduction. We are also soliciting comment on the appropriate replacement frequency and other considerations that would be associated with regular replacement periods.
d. NSPS for Storage Vessels
	Crude oil, condensate and produced water are typically stored in fixed-roof storage vessels. Some vessels used for storing produced water may be open-top tanks. These vessels, which are operated at or near atmospheric pressure conditions, are typically located as part of a tank battery. A tank battery refers to the collection of process equipment used to separate, treat and store crude oil, condensate, natural gas and produced water. The extracted products from productions wells enter the tank battery through the production header, which may collect product from many wells.
	Emissions from storage vessels are a result of working, breathing and flash losses. Working losses occur due to the emptying and filling of storage tanks. Breathing losses are the release of gas associated with daily temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid with dissolved gases is transferred from a vessel with higher pressure to a vessel with lower pressure, thus, allowing dissolved gases and a portion of the liquid to vaporize or flash. In the oil and natural gas production segment, flashing losses occur when live crude oils or condensates flow into a storage tank from a processing vessel operated at a higher pressure. Typically, the larger the pressure drop, the more flash emissions will occur in the storage stage. Temperature of the liquid also influences the amount of flash emissions.  The amount of liquid entering the tank during a given time, commonly known as throughput, also affects the emission rate, with higher throughput tanks having higher annual emissions, given that other parameters are the same.
      In analyzing controls for storage vessels, we reviewed control techniques identified in the Natural Gas STAR program and state regulations. We identified two ways of controlling storage vessel emissions, both of which can reduce VOC emissions by 95 percent. One option would be to install a vapor recovery unit (VRU) and recover all the vapors from the tanks. The other option would be to route the emissions from the tanks to a flare control device.  These devices could be "candlestick" flares that are found at gas processing plants or other larger facilities or enclosed combustors which are commonly found at smaller field facilities. We estimated the total annual cost for a VRU to be approximately $18,900/yr and for a flare to be approximately $8,900/yr. Cost effectiveness of these control options depend on the amount of vapor produced by the storage vessels being controlled. A VRU has a potential advantage over flaring, in that it recovers hydrocarbon vapors that potentially can be used as supplemental burner fuel, or the vapors can be condensed and collected as condensate that can be sold. If natural gas is recovered, it can be sold, as well, as long as a gathering line is available to convey the recovered salable gas product to market or to further processing. A VRU also does not have secondary air impacts that flaring does, as described below. However, a VRU cannot be used in all instances. Some conditions that affect the feasibility of VRU are: Availability of electrical service sufficient to power the VRU; fluctuations in vapor loading caused by surges in throughput and flash emissions from the tank; potential for drawing air into condensate tanks causing an explosion hazard; and lack of appropriate destination or use for the vapor recovered.
      Like a VRU, a flare control device can also achieve a control efficiency of 95 percent. There are no technical limitations on the use of flares to control vapors from condensate and crude oil tanks. However, flaring has a secondary impact from emissions of NOx and other pollutants. In light of the technical limitations with the use of a VRU, we are unable to conclude that a VRU is better than flaring. We, therefore, propose to determine that both a VRU and flare are BSER for reducing VOC emission from storage vessels. We propose an NSPS of 95-percent reduction for storage vessels to reflect the level of emission reduction achievable by VRU and flares.
      VOC emissions from storage vessels vary significantly, depending on the rate of liquid entering and passing through the vessel (i.e., its throughput), the pressure of the liquid as it enters the atmospheric pressure storage vessel, the liquid's volatility and temperature of the liquid. Some storage vessels have negligible emissions, such as those with very little throughput and/or handling heavy liquids entering at atmospheric pressure. We do not believe that it is cost effective to control these vessels.  We believe it is important to control tanks with significant VOC emissions under the proposed NSPS.
      In our analysis, we evaluated storage tanks with varying condensate or crude oil throughput. We used emission factors developed for the Texas Environmental Research Consortium in a study that evaluated VOC emissions from crude oil and condensate storage tanks by performing direct measurements. The study found that the average VOC emission factor for crude oil storage tanks was 1.6 pounds (lb) VOC per barrel of crude oil throughput. The average VOC emission factor for condensate tanks was determined to be 33.3 lb VOC per barrel of condensate throughput. Applying these emission factors and evaluating condensate throughput rates of 0.5, 1, 2 and 5 barrels per day (bpd), we determined that VOC emissions at these condensate throughput rates would be approximately 3, 6, 12 and 30 tpy, respectively. Similarly, we evaluated crude oil throughput rates of 1, 5, 20 and 50 bpd. Based on the Texas study, these crude oil throughput rates would result in VOC emissions of 0.3, 1.5, 5.8 and 14.6 tpy, respectively. We believe that it is important to control tanks with significant VOC emissions. Furthermore, we believe it would be easier and less costly for owners and operators to determine applicability by using a throughput threshold instead of an emissions threshold. As a result of the above analyses, we believe that storage vessels with at least 1 bpd of condensate or 20 bpd of crude oil should be controlled. These throughput rates are equivalent to VOC emissions of approximately 6 tpy. Based on an estimated annual cost of $18,900 for the control device, controlling storage vessels with these condensate or crude oil throughputs would result in a cost effectiveness of $3,150 per ton of VOC reduced.
      Based on our evaluation, we propose to determine that both a VRU and flare are BSER for reducing VOC emission from storage vessels with throughput of at least 1 barrel of condensate per day or 20 barrels of crude oil per day.  We propose an NSPS of 95-percent reduction for these storage vessels to reflect the level of emission reduction achievable by VRU and flare control devices.
	For storage vessels below the throughput levels described above ("small throughput tanks"), for which we do not consider flares or VRU to be cost effective controls, we evaluated other measures to reduce VOC emissions. Standard practices for such tanks include requiring a cover that is well designed, maintained in good condition and kept closed. Crude oil and condensate storage tanks in the oil and natural gas sector are designed to operate at or just slightly above or below atmospheric pressure. Accordingly, they are provided with vents to prevent tank destruction under rapid pressure increases due to flash emissions conditions. Studies by the Natural Gas STAR program and by others have shown that working losses (i.e., those emissions absent flash emission conditions) are very low, approaching zero. During times of flash emissions, tanks are designed such that the flash emissions are released through a vent on the fixed roof of the tank when pressure reaches just a few ounces to prevent pressure buildup and resulting tank damage. At those times, vapor readily escapes through the vent to protect the tank. Tests have shown that open hatches or leaking hatch gaskets have little effect on emissions from uncontrolled tanks due to the functioning roof vent. However, in the case of controlled tanks, the control requirements include provisions for maintaining integrity of the closed vent system that conveys emissions to the control device, including hatches and other tank openings. As a result, hatches are required to be kept closed and gaskets kept in good repair to meet control requirements of controlled storage vessels. Because the measures we evaluated, including maintenance of hatch integrity, do not provide appreciable emission reductions for storage vessels with throughputs under 1 barrel of condensate per day and 21 barrels of crude oil per day, we believe that the control options we evaluated do not reflect BSER for the small throughput tanks and we are not proposing standards for these tanks.
      As discussed in section VII of this package, we are proposing to amend the NESHAP for oil and natural gas production facilities at 40 CFR part 63, subpart HH to require that all storage vessels at production facilities reduce HAP emissions by 95 percent. Because the controls used to achieve the 95-percent HAP reduction are the same as the proposed BSER for VOC reduction for storage vessels (i.e., VRU and flare), sources that are achieving the 95- percent HAP reduction would also be meeting the proposed NSPS of 95-percent VOC reduction. In light of the above, and to avoid duplicate monitoring, recordkeeping and reporting, we propose that storage vessels subject to the requirements of subpart HH are exempt from the proposed NSPS for storage vessel in 40 CFR part 60, subpart OOOO.
e. NSPS for VOC Equipment Leaks
      Equipment leaks are fugitive emissions emanating from valves, pump seals, flanges, compressor seals, pressure relief valves, open-ended lines and other process and operation components. There are several potential reasons for equipment leak emissions. Components such as pumps, valves, pressure relief valves, flanges, agitators and compressors are potential sources that can leak due to seal failure. Other sources, such as open-ended lines and sampling connections may leak for reasons other than faulty seals. In addition, corrosion of welded connections, flanges, and valves may also be a cause of equipment leak emissions. Because of the large number of valves, pumps and other components within an oil and gas production, processing and transmission facility, equipment leak volatile emissions from these components can be significant. Natural gas processing plants, especially those using refrigerated absorption and transmission stations tend to have a large number of components. Equipment leaks from processing plants are addressed in our review of 40 CFR part 60, subpart KKK, which is discussed above in section VI.B.1.
      In addition to gas processing plants, these types of equipment also exist at oil and gas production sites and gas transmission and storage facilities. While the number of components at individual transmission and storage facilities is relatively smaller than at processing plants, collectively, there are many components that can result in significant emissions.
      Therefore, we evaluated applying NSPS for equipment leaks to facilities in the production segment of the industry, which includes everything from the wellhead to the point that the gas enters the processing plant, transmission pipeline or distribution pipeline. Production facilities can vary significantly in the operations performed and the processes, all of which impact the number of components and potential emissions from leaking equipment and, thus, impact the annual costs related to implementing a LDAR program. We used data collected by the Gas Research Institute to develop model production facilities. Baseline emissions, along with emission reductions and costs of regulatory alternatives, were estimated using these model production facilities. We considered production facilities where separation, storage, compression and other processes occur. These facilities may not have a wellhead on-site, but would be associated with a wellhead. We also evaluated gathering and boosting facilities, where gas and/or oil are collected from a number of wells, then processed and transported downstream to processing plants or transmission stations. We evaluated the impacts at these production facilities with varying number of operations and equipment. We also developed a model plant for the transmission and storage segment using data from the Gas Research Institute. Details of these evaluations may be found in the TSD in the docket.
      For an average production site at or associated with a wellhead, we estimated annual VOC emissions from equipment leaks of around 2.6 tpy. For an average gathering/boosting facility, we estimated the annual VOC emissions from equipment leaks to be around 9.8 tpy. The average transmission and storage facility emits 2.7 tpy of VOC.
      For facilities in each non-gas processing plant segment, we evaluated the same four options as we did for gas processing plants in section VI.B.1 above.  These four options are as follows: (1) 40 CFR part 60, subpart VVa-level LDAR (which is based on conducting Method 21 monthly, defining "leak" at 500 ppm threshold, and adding connectors to the VV list of components to be monitored); (2) monthly optical gas imaging with annual Method 21 check (the alternative work practice for monitoring equipment for leaks at 40 CFR 60.18(g)); (3) monthly optical gas imaging alone; and (4) annual optical gas imaging alone.
      For option 1, we evaluated subpart VVa-LDAR as a whole.  We also analyzed separately the individual types of components (valves, connectors, pressure relief devices and open-ended lines). Detailed discussions of these component by component analyses are included in the TSD in the docket.
      Based on our evaluation, subpart VVa-level LDAR (Option 1) results in more VOC reduction than the subpart VV-level LDAR currently required for gas processing plants, because more leaks are found based on the lower definition of "leak" under subpart VVa(10,000 ppm for subpart VV and 500 ppm for subpart VVa).  In addition, our evaluation shows that the cost per ton of VOC reduced for subpart VVa level controls is less than the cost per ton of VOC reduced for the less stringent subpart VV level of control. Although the cost of repairing more leaks is higher, the increased VOC control afforded by subpart VVa level controls more than offsets the increased costs.
       For the subpart VVa level of control at the average production site associated with a wellhead, average facility-wide cost-effectiveness would be $16,084 per ton of VOC.  Component-specific cost-effectiveness ranged from $15,063 per ton of VOC (for valves) to $211,992 per ton of VOC (for pressure relief devices), with connectors and open-ended lines being $74,283 and $180,537 per ton of VOC, respectively.  We also looked at component costs for a modified subpart VVa level of control with less frequent monitoring for valves and connectors at production sites associated with a wellhead. The cost-effectiveness for valves was calculated to be $17,828 per ton of VOC by reducing the monitoring frequency from monthly to annually. The cost-effectiveness for connectors was calculated to be $87,277 per ton of VOC by reducing the monitoring frequency from every 4 years to every 8 years after the initial compliance period.
      We performed a similar facility-wide and component-specific analysis of option 1 LDAR for gathering and boosting stations. For the subpart VVa level of control at the average gathering and boosting station, facility-wide cost-effectiveness was estimated to be $9,344 per ton of VOC.  Component-specific cost-effectiveness ranged from $6,079 per ton of VOC (for valves) to $77,310 per ton of VOC (for open-ended lines), with connectors and pressure relief devices being $23,603 and $72,523 per ton, respectively.  For the modified subpart VVa level of control at gathering and boosting stations, cost-effectiveness ranged from $5,221 per ton of VOC (for valves) to $77,310 per ton of VOC (for open-ended lines), with connectors and pressure relief devices being $27,274 and $72,523 per ton, respectively. The modified subpart VVa level controls were more cost-effective than the subpart VVa level controls for valves, but not for connectors.  This is due to the low cost of monitoring connectors and the low VOC emissions from leaking connectors.
      We also performed a similar analysis of option 1 subpart VVa-level LDAR for gas transmission and storage facilities. For the subpart VVa level of control at the average transmission and storage facility, facility-wide cost-effectiveness was $20,215. Component-specific cost-effectiveness ranged from $24,762 per ton of VOC (for open-ended lines) to $243,525 per ton of VOC (for pressure relief devices), with connectors and valves being $36,527 and $43,111 per ton of VOC, respectively. For the modified subpart VVa level of control at transmission and storage facilities, cost-effectiveness ranged from $24,762 per ton of VOC (for open-ended lines) to $243,525 per ton of VOC (for pressure relief devices), with connectors and valves being $42,140 and $40,593 per ton of VOC, respectively. Again, the modified subpart VVa level controls were more cost-effective for valves and less cost effective for connectors than the subpart VVa level controls. This is due to the low cost of monitoring connectors and the low VOC emissions from leaking connectors.
      For each of the non-gas processing segments, we also evaluated monthly optical gas imaging with annual Method 21 check (Option 2).  As discussed in secton VI.B.1, we had previously determined that the VOC reductions achieved under this option would be the same as for option 1 subpart VVa-level LDAR. In our evaluation of Option 2, we estimated that a single optical imaging instrument could be used for 160 well sites and 13 gathering and boosting stations, which means that the cost of the purchase or rental of the camera would be spread across 173 facilities.
      For production sites, gathering and boosting stations, and transmission and storage facilities, we estimated that option 2 monthly optical gas imaging with annual Method 21 check would have cost-effectiveness of $16,123, $10,095, and $19,715 per ton of VOC, respectively.
      The annual costs for option 1 and option 2 leak detection and repair programs for production sites associated with a wellhead, gathering and boosting stations and transmission and storage facilities were higher than those estimated for natural gas processing plants because natural gas processing plant annual costs are based on the incremental cost of implementing subpart VVa-level standards, whereas the other facilities are not currently regulated under an LDAR program. The currently unregulated sites would be required to set up a new LDAR program; perform initial monitoring, tagging, logging and repairing of components; as well as planning and training personnel to implement the new LDAR program.
	In addition to options 1 and 2, we evaluated a third option that consisted of monthly optical gas imaging without an annual Method 21 check. Because we were unable to estimate the VOC emissions achieved by an optical imaging program alone, we were unable to estimate the cost-effectiveness of this option. However, we estimated the annual cost of the monthly optical gas imaging LDAR program at production sites, gathering and boosting stations, and transmission and storage facilities to be $37,049, $86,135, and $45,080, respectively, based on camera purchase, or $32,693, $81,780, and $40,629, respectively, based on camera rental.
	Finally, we evaluated a fourth option similar to the third option except that the optical gas imaging would be performed annually rather than monthly. For this option, we estimated the annual cost for production sites, gathering and boosting stations, and transmission and storage facilities to be $30,740, $64,416, and $24,031, respectively, based on camera purchase, or $26,341, $60,017, and $19,493, respectively, based on camera rental.
        We request comment on the applicability of a leak detection and repair program based solely on the use of optical imaging or other technologies. Of most use to us would be information on the effectiveness of advanced measurement technologies to detect and repair small leaks on the same order or smaller as specified in the VVa equipment leak requirements and the effects of increased frequency of and associated leak detection, recording, and repair practices.
         Based on the evaluation described above, we believe that neither option 1 nor option 2 is cost effective for reducing fugitive VOC emissions from equipment leaks at sites, gathering and boosting stations, and transmission and storage facilities. For options 3 and 4, we were unable to estimate their cost effectiveness and, therefore, could not identify either of these two options as BSER for addressing equipment leak of VOC at production facilities associated with wellheads, at gathering and boosting stations or at gas transmission and storage facilities. We are, therefore, not proposing NSPS for addressing VOC emissions from equipment leaks at these facilities.
5. What are the SSM provisions?
      The EPA is proposing standards in this rule that apply at all times, including during periods of startup or shutdown, and periods of malfunction. In proposing the standards in this rule, the EPA has taken into account startup and shutdown periods.
      The General Provisions in 40 CFR part 60 require facilities to keep records of the occurrence and duration of any startup, shutdown or malfunction (40 CFR 60.7(b)) and either report to the EPA any period of excess emissions that occurs during periods of SSM (40 CFR 60.7(c)(2)) or report that no excess emissions occurred (40 CFR 60.7(c)(4)). Thus, any comments that contend that sources cannot meet the proposed standard during startup and shutdown periods should provide data and other specifics supporting their claim.
      Periods of startup, normal operations and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as a "sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner..." (40 CFR 60.2.) The EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 111 standards. Further, nothing in CAA section 111 or in case law requires that the EPA anticipate and account for the innumerable types of potential malfunction events in setting emission standards. See, Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) ("In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by `uncontrollable acts of third parties,' such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation."), and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 111 standards.
      Further, it is reasonable to interpret CAA section 111 as not requiring the EPA to account for malfunctions in setting emissions standards. For example, we note that CAA section 111 provides that the EPA set standards of performance which reflect the degree of emission limitation achievable through "the application of the best system of emission reduction" that the EPA determines is adequately demonstrated. Applying the concept of "the application of the best system of emission reduction" to periods during which a source is malfunctioning presents difficulties. The "application of the best system of emission reduction" is more appropriately understood to include operating units in such a way as to avoid malfunctions.
      Moreover, even if malfunctions were considered a distinct operating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 111 standards for affected facilities under 40 CFR part 60, subpart OOOO. As noted above, by definition, malfunctions are sudden and unexpected events and it would be difficult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources in the category. Moreover, malfunctions can vary in frequency, degree and duration, further complicating standard setting.
      In the event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 111 standard was, in fact, "sudden, infrequent, not reasonably preventable" and was not instead "caused in part by poor maintenance or careless operation." 40 CFR 60.2 (definition of malfunction).
      Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail. Such failure can sometimes cause an exceedance of the relevant emission standard (See, e.g., State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown (September 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (February 15, 1983)). The EPA is, therefore, proposing to add an affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions. See 40 CFR 60.41Da (defining "affirmative defense" to mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding). We also are proposing other regulatory provisions to specify the elements that are necessary to establish this affirmative defense; the source must prove by a preponderance of the evidence that it has met all of the elements set forth in 40 CFR 60.46Da. (See 40 CFR 22.24). These criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 60.2 (sudden, infrequent, not reasonably preventable and not caused by poor maintenance and or careless operation). For example, to successfully assert the affirmative defense, the source must prove by a preponderance of the evidence that excess emissions "[w]ere caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner..." The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance with 40 CFR 60.40Da and to prevent future malfunctions. For example, the source would have to prove by a preponderance of the evidence that "[r]epairs were made as expeditiously as possible when the applicable emission limitations were being exceeded..." and that "[a]ll possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health..." In any judicial or administrative proceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met the burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with CAA section 113 (see also 40 CFR part 22.77).
VII.	Rationale for Proposed Action for NESHAP
A. What data were used for the NESHAP analyses?
	To perform the technology review and residual risk analysis for the two NESHAP, we created a comprehensive dataset (i.e., the MACT dataset). This dataset was based on the EPA's 2005 National Emissions Inventory (NEI). The NEI database contains information about sources that emit criteria air pollutants and their precursors and HAP. The database includes estimates of annual air pollutant emissions from point, nonpoint and mobile sources in the 50 states, the District of Columbia, Puerto Rico and the Virgin Islands. The EPA collects information about sources and releases an updated version of the NEI database every 3 years.
	The NEI database is compiled from these primary sources:
   * Emissions inventories compiled by state and local environmental agencies
   * Databases related to the EPA's MACT programs
   * Toxics Release Inventory data
   * For electric generating units, the EPA's Emission Tracking System/CEM data and United States Department of Energy (DOE) fuel use data
   * For onroad sources, the United States Federal Highway Administration's estimate of vehicle miles traveled and emission factors from the EPA's MOBILE computer model
   * For nonroad sources, the EPA's NONROAD computer model
   * Emissions inventories from previous years, if states do not submit current data
	To concentrate on only records pertaining to the oil and natural gas industry sector, data were extracted using two criteria. First, we specified that all facilities containing codes identifying the Oil and Natural Gas Production and the Natural Gas Transmission and Storage MACT source categories (MACT codes 0501 and 0504, respectively). Second, we extracted facilities identified with the following NAICS codes: 211*** (Oil and Gas Extraction), 221210 (Natural Gas Distribution), 4861** (Pipeline Transportation of Crude Oil), and 4862** (Pipeline Transportation of Natural Gas). Once the data were extracted, we reviewed the Source Classification Codes (SCC) to assess whether there were any records included in the dataset that were clearly not a part of the oil and natural gas sector. Our review of the SCC also included assigning each SCC to an "Emission Process Group" that represents emission point types within the oil and natural gas sector.
	Since these MACT standards only apply to major sources, only facilities designated as major sources in the NEI were extracted. In the NEI, sources are identified as major if the facility-wide emissions are greater than 10 tpy for any single HAP or 25 tpy for any combination of HAP. We believe that this may overestimate the number of major sources in the oil and natural gas sector because it does not take into account the limitations set forth in the CAA regarding aggregation of emissions from wells and associated equipment in determining major source status.
	The final dataset contained a total of 1,311 major sources in the oil and natural gas sector; 990 in Oil and Natural Gas Production, and 321 in Natural Gas Transmission and Storage. To assess how representative this number of facilities was, we obtained information on the number of subject facilities for both MACT standards from the Enforcement and Compliance History Online (ECHO) database. The ECHO database is a web-based tool (http://www.epa-echo.gov/echo/index.html) that provides public access to compliance and enforcement information for approximately 800,000 EPA-regulated facilities. The ECHO database allows users to find permit, inspection, violation, enforcement action and penalty information covering the past 3 years. The site includes facilities regulated as CAA stationary sources, as well as Clean Water Act direct dischargers, and Resource Conservation and Recovery Act hazardous waste generators/handlers. The data in the ECHO database are updated monthly.
	We performed a query on the ECHO database requesting records for major sources, with NAICS codes 211*, 221210, 4861* and 4862*, with information for MACT. The ECHO database query identified records for a total of 555 facilities, 269 in the Oil and Natural Gas Production source category (NAICS 211* and 221210) and 286 in the Natural Gas Transmission and Storage source category (NAICS 4861* and 4862*). This comparison leads us to conclude that, for the Natural Gas Transmission and Storage segment, the NEI database is representative of the number of sources subject to the rule. For the Oil and Natural Gas Production source category, it confirms our assumption that the NEI dataset contains more facilities than are subject to the rule. However, this provides a conservative overestimate of the number of sources, which we believe is appropriate for our risk analyses.
	We are requesting that the public provide a detailed review of the information in this dataset and provide comments and updated information where appropriate. Section X of this preamble provides an explanation of how to provide updated information for these datasets.
B. What are the proposed decisions regarding certain unregulated emissions sources?
	In addition to actions relative to the technology review and risk reviews discussed below, we are proposing, pursuant to CAA sections 112(d)(2) and (3), MACT standards for glycol dehydrators and storage vessels for which standards were not previously developed. We are also proposing changes that affect the definition of "associated equipment" which could apply these MACT standards to previously unregulated sources.
1. Glycol Dehydrators
	Once natural gas has been separated from any liquid materials or products (e.g., crude oil, condensate or produced water), residual entrained water is removed from the natural gas by dehydration. Dehydration is necessary because water vapor may form hydrates, which are ice-like structures, and can cause corrosion in or plug equipment lines. The most widely used natural gas dehydration processes are glycol dehydration and solid desiccant dehydration. Solid desiccant dehydration, which is typically only used for lower throughputs, uses adsorption to remove water and is not a source of HAP emissions.
	Glycol dehydration is an absorption process in which a liquid absorbent, glycol, directly contacts the natural gas stream and absorbs any entrained water vapor in a contact tower or absorption column. The majority of glycol dehydration units use triethylene glycol as the absorbent, but ethylene glycol and diethylene glycol are also used. The rich glycol, which has absorbed water vapor from the natural gas stream, leaves the bottom of the absorption column and is directed either to (1) a gas condensate glycol (GCG) separator (flash tank) and then a reboiler or (2) directly to a reboiler where the water is boiled off of the rich glycol. The regenerated glycol (lean glycol) is circulated, by pump, into the absorption tower. The vapor generated in the reboiler is directed to the reboiler vent.
	The reboiler vent is a source of HAP emissions. In the glycol contact tower, glycol not only absorbs water, but also absorbs selected hydrocarbons, including BTEX and n-hexane. The hydrocarbons are boiled off along with the water in the reboiler and vented to the atmosphere or to a control device. The most commonly used control device is a condenser. Condensers not only reduce emissions, but also recover condensable hydrocarbon vapors that can be recovered and sold. In addition, the dry non-condensable off-gas from the condenser may be used as fuel or recycled into the production process or directed to a flare, incinerator or other combustion device.
	If present, the GCG separator (flash tank) is also a potential source of HAP emissions. Some glycol dehydration units use flash tanks prior to the reboiler to separate entrained gases, primarily methane and ethane from the glycol. The flash tank off-gases are typically recovered as fuel or recycled to the natural gas production header. However, the flash tank may also be vented directly to the atmosphere. Flash tanks typically enhance the reboiler condenser's emission reduction efficiency by reducing the concentration of non-condensable gases present in the stream prior to being introduced into the condenser.
 In the development of the MACT standards for the two oil and natural gas source categories, the EPA created two subcategories of glycol dehydrators based on actual annual average natural gas flowrate and actual average benzene emissions. Under 40 CFR part 63, subpart HH, (the Oil and Natural Gas Production NESHAP), the EPA established MACT standards for glycol dehydration units with an actual annual average natural gas flowrate greater than or equal to 85,000 scmd and actual average benzene emissions greater than or equal to 0.90 Mg/yr (40 CFR 63.765(a)). The EPA did not establish standards for the other subcategory, which consists of glycol dehydration units that are below the flowrate and emission thresholds specified in subpart HH. Similarly, under 40 CFR part 63, subpart HHH (the Natural Gas Transmission and Storage NESHAP), the EPA established MACT standards for the subcategory of glycol dehydration units with an actual annual average natural gas flowrate greater than or equal to 283,000 scmd and actual average benzene emissions greater than or equal to 0.90 Mg/yr, but did not establish standards for the other subcategory, which consists of glycol dehydration units that are below the flowrate and emission thresholds specified in subpart HHH. As mentioned above, we refer to these unregulated dehydration units in both subparts HH and HHH as "small dehydrators" in this proposed rule.
	The EPA is proposing emission standards for these subcategories of small dehydrators (i.e., those dehydrators with an actual annual average natural gas flowrate less than 85,000 scmd at production sites or 283,000 scmd at natural gas transmission and storage sites, or actual average benzene emissions less than 0.9 Mg/yr). Because we do not have any new emissions data concerning these emission points, we evaluated the dataset collected from industry during the development of the original MACT standards (legacy docket A-94-04, item II-B-01, disk 1 for oil and natural gas production facilities; and items IV-G-24, 26, 27, 30 and 31 for natural gas transmission and storage facilities). We believe this dataset is representative of currently operating glycol dehydrators because it contains information for a varied group of sources (i.e., units owned by different companies, located in different states, representing a range of gas compositions and emission controls) and that the processes have not changed significantly since the data were collected.
	In the Oil and Natural Gas Production source category, there were 91 glycol dehydration units with throughput and emissions data identified that would be classified as small glycol dehydration units. We evaluated the possibility of establishing a MACT floor as a Mg/yr limit. However, due to variability of gas throughput and inlet gas composition, we could not properly identify the best performing units by only considering emissions. To allow us to normalize the emissions for a more accurate determination of the best performing sources, we created an emission factor in terms of grams BTEX/scm-ppmv for each facility. The emission factor reflects the facility's emission level, taking into consideration its natural gas throughput and inlet natural gas BTEX concentration. To determine the MACT floor for the existing dehydrators, we ranked each unit from lowest to highest, based on their emission factor, to determine the facilities in the top 12 percent of the dataset. The MACT floor was an emission factor of 1.10x10[-][4] grams BTEX/scm-ppmv. To meet this level of emissions, we anticipate that sources will use a variety of options, including, but not limited to, routing emissions to a condenser or to a combustion device.
	We also considered beyond-the-floor options for the existing sources, as required by section 112 (d)(2) of the CAA. To achieve further reductions beyond the MACT floor level of control, sources would have to install an additional add-on control device, most likely a combustion device. Assuming the MACT floor control device is a combustion device, which generally achieves at least a 95- percent HAP reduction, then less than 5 percent of the initial HAP emissions remain. Installing a second device would involve the same costs as the first control, but would only achieve 1/20 of the reduction (i.e., reducing the remaining 5 percent by another 95 percent represents a 4.49-percent reduction of the initial, uncontrolled emissions, which is 1/20 of the 95-percent reduction achieved with the first control). Based on the $8,360/Mg cost effectiveness of the floor level of control, we estimate that the incremental cost effectiveness of the second control to be $167,200/Mg. We do not believe this cost to be reasonable given the level of emission reduction. We are, therefore, proposing an emission standard for existing small dehydrators that reflects the MACT floor.
	For new small glycol dehydrators in the Oil and Natural Gas Production source category, based on our performance ranking, the best performing source has an emission factor of 4.66x10[-][6] grams BTEX/scm-ppmv. To meet this level of emissions, we anticipate that sources will use a variety of options, including, but not limited to, routing emissions to a condenser or to a combustion device. The consideration of beyond-the-floor options for new small dehydrators would be the same as for existing small dehydrators, and, as stated above, we do not believe a cost of $167,200/Mg to be reasonable given the level of emission reduction. We are, therefore, proposing a MACT standard for new small dehydrators that reflects the MACT floor level of control.
      Under our proposal, a small dehydrator's actual MACT emission limit would be determined by multiplying the MACT floor emission factor in g BTEX/scm-ppmv by its unit-specific incoming natural gas throughput and BTEX concentration for the dehydrator. A formula is provided in 40 CFR 63.765(b)(1)(iii) to calculate the MACT limit as an annual value.
      In the Natural Gas Transmission and Storage source category, there were 16 facilities for which throughput and emissions data were available that would be classified as small glycol dehydration units. Since the number of units was less than 30, the MACT floor for existing sources was based on the top five performing units. Using the same emission factor concept, we determined that the MACT floor for existing sources is an emission factor equal to 6.42x10[-][5] grams BTEX/scm-ppmv. To meet this level of emissions, we anticipate that sources will use a variety of options, including, but not limited to, routing emissions to a condenser or to a combustion device.
      We also considered beyond-the-floor options for the existing small dehydrators as required by section 112 (d)(2) of the CAA. To achieve further reductions beyond the MACT floor level of control, sources would have to install an additional add-on control device, most likely a combustion device. Assuming the MACT floor control device is a combustion device, which generally achieves at least a 95-percent HAP reduction, then less than 5 percent of the initial HAP emissions remain. Installing a second device would involve the same costs as the first control device, but would only achieve 1/20 of the reduction (i.e., reducing the remaining 5 percent by another 95 percent represents a 4.49-percent reduction of the initial, uncontrolled emissions, which is 1/20 of the 95-percent reduction achieved with the first control). Based on the $1,650/Mg cost effectiveness of the floor level of control, we estimate that the incremental cost effectiveness of the second control to be $33,000/Mg. We do not believe this cost to be reasonable given the level of emission reduction. We are, therefore, proposing an emission standard for existing small dehydrators that reflects the MACT floor.
	For new small glycol dehydrators, based on our performance ranking, the best performing source has an emission factor of 1.10x10[-][5] grams BTEX/scm-ppmv. To meet this level of emissions, we anticipate that sources will use a variety of options, including, but not limited to, routing emissions to a condenser or to a combustion device. The consideration of beyond-the-floor options for new small dehydrators would be the same as for existing small dehydrators, and, as stated above, we do not believe a cost of $33,000/Mg to be reasonable given the level of emission reduction. We are, therefore, proposing an emission standard for new sources that reflects the MACT floor level of control.
      Under our proposal, a source's actual MACT emissions limit would be determined by multiplying this emission factor by their unit-specific incoming natural gas throughput and BTEX concentration for the dehydrator. A formula is provided in 40 CFR 63.1275(b)(1)(iii) to calculate the limit as an annual value.
      As discussed below, we are proposing that, with the removal of the 1-ton alternative compliance option from the existing standards for glycol dehydrators, the MACT for these two source categories would provide an ample margin of safety to protect public health. We, therefore, maintain that, after the implementation of the small dehydrator standards discussed above, these MACT will continue to provide an ample margin of safety to protect public health. Consequently, we do not believe it will be necessary to conduct another residual risk review under CAA section 112(f) for these two source categories 8 years following promulgation of the small dehydrator standards merely due to the addition of these new MACT requirements.
2. Storage Vessels
	Crude oil, condensate and produced water are typically stored in fixed-roof storage vessels. Some vessels used for storing produced water may be open-top tanks. These vessels, which are operated at or near atmospheric pressure conditions, are typically located at tank batteries. A tank battery refers to the collection of process components used to separate, treat and store crude oil, condensate, natural gas and produced water. The extracted products from productions wells enter the tank battery through the production header, which may collect product from many wells.
	 Emissions from storage vessels are a result of working, breathing and flash losses. Working losses occur due to the emptying and filling of storage tanks. Breathing losses are the release of gas associated with daily temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is transferred from a vessel with higher pressure to a vessel with lower pressure, thus, allowing entrained gases or a portion of the liquid to vaporize or flash. In the oil and natural gas production segment, flashing losses occur when live crude oils or condensates flow into a storage tank from a processing vessel operated at a higher pressure. Typically, the larger the pressure drop, the more flashing emission will occur in the storage stage. Temperature of the liquid may also influence the amount of flash emissions.
	In the Oil and Natural Gas Production NESHAP (40 CFR part 63, subpart HH), the MACT standards for storage vessels apply only to those with the PFE. Storage vessels with the PFE are defined as storage vessels that contain hydrocarbon liquids that meet the following criteria:
         * A stock tank gas to oil ratio (GOR) greater than or equal to 0.31 cubic meters per liter (m[3]/liter); and
         * An American Petroleum Institute (API) gravity greater than or equal to 40 degrees; and
         * An actual annual average hydrocarbon liquid throughput greater than or equal to 79,500 liters per day (liter/day).
      Accordingly, there is no emission limit in the existing MACT for storage vessels without the PFE. However, the MACT analysis performed at the time indicates that the MACT floor was based on all storage vessels, not just those vessels with flash emissions. See, Recommendation of MACT Floor Levels for HAP Emission Points at Major Sources in the Oil and Natural Gas Production Source Category, (September 23, 1997, Docket A-94-04, Item II-A-07). We, therefore, propose to apply the existing MACT for storage vessels with PFE to all storage vessels (i.e., storage vessels with the PFE, as well as those without the PFE).
3. Definition of Associated Equipment
CAA section 112(n)(4)(A) provides:
      "Notwithstanding the provisions of subsection (a), emissions from any oil or gas exploration or production well (with its associated equipment) and emission from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not such units are in contiguous area or under common control, to determine whether such units or stations are major sources."
      As stated above, the CAA prevents aggregation of HAP emissions from wells and associated equipment in making major source determinations. In the absence of clear guidance in the statute on what constitutes "associated equipment," the EPA sought to define "associated equipment" in a way that recognizes the need to implement relief for this industry as Congress intended and that also allow for the appropriate regulation of significant emission points. 64 FR at 32619. Accordingly, in the existing Oil and Natural Gas Production NESHAP (1998 and 1999 NESHAP), the EPA defined "associated equipment" to exclude glycol dehydration units and storage vessels with PFE (thus allowing their emissions to be included in determining major source status) because EPA identified these sources as substantial contributors to HAP emissions. Id. EPA explained in that NESHAP that, because a single storage vessel with flash emissions may emit several Mg of HAP per year and individual glycol dehydrators may emit above the major source level, storage vessels with PFE and glycol dehydrators are large individual sources of HAP, 63 FR 6288, 6301 (1998). The EPA therefore considered these emission sources substantial contributors to HAP emissions and excluded them from the definition of "associated equipment." 64 FR at 32619. We have recently examined HAP emissions from storage vessels without flash emissions and found that these emissions are significant and comparable to those vessels with flash emissions. For example, one storage vessel with an API gravity of 30 degrees and a GOR of 2.09x10-[3] m[3]/liter with a throughput of 79,500 liter/day had HAP emissions of 9.91 Mg/yr, including 9.45 Mg/yr of n-hexane.
	Because storage vessels without the PFE can have significant emissions at levels that are comparable to emissions from storage vessels with the PFE, there is no appreciable difference between storage vessels with the PFE and those without the PFE for purposes of defining "associated equipment." We are, therefore, proposing to amend the associated equipment definition to exclude all storage vessels and not just storage vessels with the PFE.
C. How did we perform the risk assessment and what are the results and proposed decisions?
1. How did we estimate risks posed by the source categories?
	The EPA conducted risk assessments that provided estimates for each source in a category of the MIR posed by the HAP emissions, the HI for chronic exposures to HAP with the potential to cause noncancer health effects, and the hazard quotient (HQ) for acute exposures to HAP with the potential to cause noncancer health effects. The assessments also provided estimates of the distribution of cancer risks within the exposed populations, cancer incidence and an evaluation of the potential for adverse environmental effects for each source category. The risk assessments consisted of seven primary steps, as discussed below. The docket for this rulemaking contains the following document which provides more information on the risk assessment inputs and models: Draft Residual Risk Assessment for the Oil and Gas Production and Natural Gas Transmission and Storage Source Categories. The methods used to assess risks (as described in the seven primary steps below) are consistent with those peer-reviewed by a panel of the EPA's Science Advisory Board (SAB) in 2009 and described in their peer review report issued in 2010; they are also consistent with the key recommendations contained in that report.
a. Establishing the Nature and Magnitude of Actual Emissions and Identifying the Emissions Release Characteristics
	As discussed in section VII.A of this preamble, we used a dataset based on the 2005 NEI as the basis for the risk assessment. In addition to the quality assurance (QA) of the facilities contained in the dataset, we also checked the coordinates of every facility in the dataset through visual observations using tools such as GoogleEarth and ArcView. Where coordinates were found to be incorrect, we identified and corrected them to the extent possible. We also performed QA of the emissions data and release characteristics to ensure there were no outliers.
b. Establishing the Relationship Between Actual Emissions and MACT-Allowable Emissions Levels
      The available emissions data in the MACT dataset represent the estimates of mass of emissions actually emitted during the specified annual time period. These "actual" emission levels are often lower than the emission levels that a facility might be allowed to emit and still comply with the MACT standards. The emissions level allowed to be emitted by the MACT standards is referred to as the "MACT-allowable" emissions level. This represents the highest emissions level that could be emitted by the facility without violating the MACT standards.
      We discussed the use of both MACT-allowable and actual emissions in the final Coke Oven Batteries residual risk rule (70 FR 19998 - 19999, April 15, 2005) and in the proposed and final Hazardous Organic NESHAP residual risk rules (71 FR 34428, June 14, 2006, and 71 FR 76609, December 21, 2006, respectively). In those previous actions, we noted that assessing the risks at the MACT-allowable level is inherently reasonable since these risks reflect the maximum level sources could emit and still comply with national emission standards. But we also explained that it is reasonable to consider actual emissions, where such data are available, in both steps of the risk analysis, in accordance with the Benzene NESHAP. (54 FR 38044, September 14, 1989.)
      To estimate emissions at the MACT-allowable level, we developed a ratio of MACT-allowable to actual emissions for each emissions source type in each source category, based on the level of control required by the MACT standards compared to the level of reported actual emissions and available information on the level of control achieved by the emissions controls in use.
c. Conducting Dispersion Modeling, Determining Inhalation Exposures and Estimating Individual and Population Inhalation Risks
      Both long-term and short-term inhalation exposure concentrations and health risks from each source in the source categories addressed in this proposal were estimated using the Human Exposure Model (HEM) (Community and Sector HEM - 3 version 1.1.0). The HEM - 3 performs three primary risk assessment activities: (1) Conducting dispersion modeling to estimate the concentrations of HAP in ambient air, (2) estimating long-term and short-term inhalation exposures to individuals residing within 50 km of the modeled sources and (3) estimating individual and population-level inhalation risks using the exposure estimates and quantitative dose-response information.
      The dispersion model used by HEM - 3 is AERMOD, which is one of the EPA's preferred models for assessing pollutant concentrations from industrial facilities. To perform the dispersion modeling and to develop the preliminary risk estimates, HEM - 3 draws on three data libraries. The first is a library of meteorological data, which is used for dispersion calculations. This library includes 1 year of hourly surface and upper air observations for more than 158 meteorological stations, selected to provide coverage of the United States and Puerto Rico. A second library of
United States Census Bureau census block internal point locations and populations provides the basis of human exposure calculations (Census, 2000). In addition, for each census block, the census library includes the elevation and controlling hill height, which are also used in dispersion calculations. A third library of pollutant unit risk factors and other health benchmarks is used to estimate health risks. These risk factors and health benchmarks are the latest values recommended by the EPA for HAP and other toxic air pollutants. These values are available at http://www.epa.gov/ttn/atw/toxsource/summary.html and are discussed in more detail later in this section.
      In developing the risk assessment for chronic exposures, we used the estimated annual average ambient air concentration of each of the HAP emitted by each source for which we have emissions data in the source category. The air concentrations at each nearby census block centroid were used as a surrogate for the chronic inhalation exposure concentration for all the people who reside in that census block. We calculated the MIR for each facility as the cancer risk associated with a continuous lifetime (24 hours per day, 7 days per week, and 52 weeks per year for a 70-year period) exposure to the maximum concentration at the centroid of an inhabited census block. Individual cancer risks were calculated by multiplying the estimated lifetime exposure to the ambient concentration of each of the HAP (in micrograms per cubic meter) by its unit risk estimate (URE), which is an upper bound estimate of an individual's probability of contracting cancer over a lifetime of exposure to a concentration of 1 microgram of the pollutant per cubic meter of air. For residual risk assessments, we generally use URE values from the EPA's Integrated Risk Information System (IRIS). For carcinogenic pollutants without the EPA IRIS values, we look to other reputable sources of cancer dose-response values, often using California EPA (CalEPA) URE values, where available. In cases where new, scientifically credible dose-response values have been developed in a manner consistent with the EPA guidelines and have undergone a peer review process similar to that used by the EPA, we may use such dose-response values in place of or in addition to other values, if appropriate.
	Formaldehyde is a unique case. In 2004, the EPA determined that the Chemical Industry Institute of Toxicology (CIIT) cancer dose-response value for formaldehyde (5.5 x 10-9 per μg/m3) was based on better science than the IRIS cancer dose-response value (1.3 x 10-5 per μg/m3) and we switched from using the IRIS value to the CIIT value in risk assessments supporting regulatory actions. However, subsequent research published by the EPA suggests that the CIIT model was not appropriate and in 2010 the EPA returned to using the 1991 IRIS value, which is more health protective. The EPA has been working on revising the formaldehyde IRIS assessment and the National Academy of Sciences (NAS) completed its review of the EPA's draft in May of 2011. EPA is reviewing the public comments and the NAS independent scientific peer review, and the draft IRIS assessment will be revised and the final assessment will be posted on the IRIS database.  In the interim, we will present findings using the 1991 IRIS value as a primary estimate, and may also consider other information as the science evolves.
	In the case of benzene, the high end of the reported cancer URE range was used in our assessments to provide a conservative estimate of potential cancer risks. Use of the high end of the range provides risk estimates that are approximately 3.5 times higher than use of the equally-plausible low end value. We also evaluated the impact of using the low end of the URE range on our risk results.
	We also note that polycyclic organic matter (POM), a carcinogenic HAP with a mutagenic mode of action, is emitted by some of the facilities in these two categories. For this compound group, the age-dependent adjustment factors (ADAF) described in the EPA's Supplemental Guidance for Assessing Susceptibility from Early-Life Exposure to Carcinogens were applied. This adjustment has the effect of increasing the estimated lifetime risks for POM by a factor of 1.6. In addition, although only a small fraction of the total POM emissions were not reported as individual compounds, the EPA expresses carcinogenic potency for compounds in this group in terms of benzo[a]pyrene equivalence, based on evidence that carcinogenic POM has the same mutagenic mechanism of action as benzo[a]pyrene. For this reason, the EPA's Science
Policy Council recommends applying the Supplemental Guidance to all carcinogenic polycyclic aromatic hydrocarbons for which risk estimates are based on relative potency. Accordingly, we have applied the ADAF to the benzo[a]pyrene equivalent portion of all POM mixtures.
      Incremental individual lifetime cancer risks associated with emissions from the source category were estimated as the sum of the risks for each of the carcinogenic HAP (including those classified as carcinogenic to humans, likely to be carcinogenic to humans and suggestive evidence of carcinogenic potential) emitted by the modeled source. Cancer incidence and the distribution of individual cancer risks for the population within 50 km of any source were also estimated for the source category as part of these assessments by summing individual risks. A distance of 50 km is consistent with both the analysis supporting the 1989 Benzene NESHAP (54 FR 38044) and the limitations of Gaussian dispersion models, including AERMOD.
      To assess risk of noncancer health effects from chronic exposures, we summed the HQ for each of the HAP that affects a common target organ system to obtain the HI for that target organ system (or target organ-specific HI, TOSHI). The HQ for chronic exposures is the estimated chronic exposure divided by the chronic reference level, which is either the EPA reference concentration (RfC), defined as "an estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime," or, in cases where an RfC from the EPA's IRIS database is not available, the EPA will utilize the following prioritized sources for our chronic dose-response values: (1) The Agency for Toxic Substances and Disease Registry Minimum Risk Level, which is defined as "an estimate of daily human exposure to a substance that is likely to be without an appreciable risk of adverse effects (other than cancer) over a specified duration of exposure"; (2) the CalEPA Chronic Reference Exposure Level (REL), which is defined as "the concentration level at or below which no adverse health effects are anticipated for a specified exposure duration"; and (3), as noted above, in cases where scientifically credible dose-response values have been developed in a manner consistent with the EPA guidelines and have undergone a peer review process similar to that used by the EPA, we may use those dose-response values in place of or in concert with other values.
      Screening estimates of acute exposures and risks were also evaluated for each of the HAP at the point of highest off-site exposure for each facility (i.e., not just the census block centroids), assuming that a person is located at this spot at a time when both the peak (hourly) emission rate and worst-case dispersion conditions (1991 calendar year data) occur. The acute HQ is the estimated acute exposure divided by the acute dose-response value. In each case, acute HQ values were calculated using best available, short-term dose-response values. These acute dose-response values, which are described below, include the acute REL, acute exposure guideline levels (AEGL) and emergency response planning guidelines (ERPG) for 1-hour exposure durations. As discussed below, we used conservative assumptions for emission rates, meteorology and exposure location for our acute analysis.
      As described in the CalEPA's Air Toxics Hot Spots Program Risk Assessment Guidelines, Part I, The Determination of Acute Reference Exposure Levels for Airborne Toxicants, an acute REL value (http://www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined as "the concentration level at or below which no adverse health effects are anticipated for a specified exposure duration." Acute REL values are based on the most sensitive, relevant, adverse health effect reported in the medical and toxicological literature. Acute REL values are designed to protect the most sensitive individuals in the population by the inclusion of margins of safety. Since margins of safety are incorporated to address data gaps and uncertainties, exceeding the acute REL does not automatically indicate an adverse health impact.
      AEGL values were derived in response to recommendations from the National Research Council (NRC). As described in Standing Operating Procedures (SOP) of the National Advisory Committee on Acute Exposure Guideline Levels for Hazardous Substances (http://www.epa.gov/opptintr/aegl/pubs/sop.pdf), "the NRC's previous name for acute exposure levels -- community emergency exposure levels -- was replaced by the term AEGL to reflect the broad application of these values to planning, response, and prevention in the community, the workplace, transportation, the military, and the remediation of Superfund sites." This document also states that AEGL values "represent threshold exposure limits for the general public and are applicable to emergency exposures ranging from 10 minutes to eight hours." The document lays out the purpose and objectives of AEGL by stating (page 21) that "the primary purpose of the AEGL program and the National Advisory Committee for Acute Exposure Guideline Levels for Hazardous Substances is to develop guideline levels for once-in-a-lifetime, short-term exposures to airborne concentrations of acutely toxic, high-priority chemicals." In detailing the intended application of AEGL values, the document states (page 31) that "[i]t is anticipated that the AEGL values will be used for regulatory and nonregulatory purposes by U.S. Federal and state agencies and possibly the international community in conjunction with chemical emergency response, planning, and prevention programs. More specifically, the AEGL values will be used for conducting various risk assessments to aid in the development of emergency preparedness and prevention plans, as well as real-time emergency response actions, for accidental chemical releases at fixed facilities and from transport carriers."
      The AEGL - 1 value is then specifically defined as "the airborne concentration of a substance above which it is predicted that the general population, including susceptible individuals, could experience notable discomfort, irritation, or certain asymptomatic nonsensory effects. However, the effects are not disabling and are transient and reversible upon cessation of exposure." The document also notes (page 3) that, "Airborne concentrations below AEGL - 1 represent exposure levels that can produce mild and progressively increasing but transient and nondisabling odor, taste, and sensory irritation or certain asymptomatic, nonsensory effects." Similarly, the document defines AEGL - 2 values as "the airborne concentration (expressed as ppm or mg/m3) of a substance above which it is predicted that the general population, including susceptible individuals, could experience irreversible or other serious, long-lasting adverse health effects or an impaired ability to escape."
      ERPG values are derived for use in emergency response, as described in the American Industrial Hygiene Association's document entitled, Emergency Response Planning Guidelines (ERPG) Procedures and Responsibilities (http://www.aiha.org/1documents/committees/ERPSOPs2006.pdf)             which states that, "Emergency Response Planning Guidelines were developed for emergency planning and are intended as health based guideline concentrations for single exposures to chemicals." The ERPG - 1 value is defined as "the maximum airborne concentration below which it is believed that nearly all individuals could be exposed for up to 1 hour without experiencing other than mild transient adverse health effects or without perceiving a clearly defined, objectionable odor." Similarly, the ERPG - 2 value is defined as "the maximum airborne concentration below which it is believed that nearly all individuals could be exposed for up to 1 hour without experiencing or developing irreversible or other serious health effects or symptoms which could impair an individual's ability to take protective action."
      As can be seen from the definitions above, the AEGL and ERPG values include the similarly-defined severity levels 1 and 2. For many chemicals, a severity level 1 value AEGL or ERPG has not been developed; in these instances, higher severity level AEGL - 2 or ERPG - 2 values are compared to our modeled exposure levels to screen for potential acute concerns.
      Acute REL values for 1-hour exposure durations are typically lower than their corresponding AEGL - 1 and ERPG - 1 values. Even though their definitions are slightly different, AEGL - 1 values are often the same as the corresponding ERPG - 1 values, and AEGL - 2 values are often equal to ERPG - 2 values. Maximum HQ values from our acute screening risk assessments typically result when basing them on the acute REL value for a particular pollutant. In cases where our maximum acute HQ value exceeds 1, we also report the HQ value based on the next highest acute dose-response value (usually the AEGL - 1 and/or the ERPG - 1 value).