### From: Mike Eisenfeld <meisenfeld@frontier.net>

To: Bruce Moor e/RTP/USEPA/US@EPA, Nick Parsons/RTP/USEPA/US@EPA

Date: 08/10/2010 04:50 PM

Subject: Four Corners Air Quality Task Miti gation Options

- Oil and Gas

Mr. Moore and Mr. Parsons:

First off, thanks to both of you for your presence at the EPA hearing in Denver August 3. I am
confident that those who spoke shed constructive light on the complexities of oil and gas
development in our part of the country.

I certainly believe that there are creative solutions t o reducing air quality emissions from the O &
G Industry. In 2003, when the BLM here approved 10,000 new well pads and 10,000 new
compressors, a Task Force called the Four Corners Ozone Task Force was created. This Task
Force was formed to develop mitiga tion measures to keep the region in attainment on ozone.
The Task Force was renamed the Four Corners Air Quality Task Force and included a broad
spectrum of agency, industry, NGOs and citizens. A Final Report of the Task Force came out in

2007 and includ ed a document on Mitigation Options the Oil and Gas Industry and regulating
agencies could implement to reduce air pollution in the region. To date, these mitigation options
have been deemed "voluntary."

Given our precarious balancing act with ozone and t he very real fact that we may be out of
attainment August 31, 2010, these mitigation measures may have real applicability as mandatory
enforceable control measures. Please enter this report into the docket for Review of Air
Regulations Affecting Natural G as Industry.

Thanks,

Mike Eisenfeld New Mexico Energy Coordinator

San Juan Citizens Alliance 108 North Behrend, Suite I Farmington, New Mexico 87401

### office 505 325

- 6724

cell 505 360

- 8994 meisenfeld@frontier.net(See attached file: 4CAQTF_Report_FINAL_OilandGas.pdf)

# OIL AND GAS SECTION



# Four Corners Air Quality Task Force Report of Mitigation Options

November 1, 2007

The report is a compilation of mitigation options drafted by members of the Four Co rners Air Quality Task Force.

This is not a document to be endorsed by the agencies involved, but rather, a compendium of options for consideration following completion of the Task Force’s work in November 2007.Oil & Gas

11/01/07 1 

## Oil & Gas Section

Table of Contents

Preface ........................................................................................................................ ...............................................3

ENGINES........................................................................................................................ ..........................................4

STATIONARY RICE................................................................................................................ ............................4

Industry Co llabora tion......................................................................................................... ..............................4

Install Electri c Compression................................................................................................... ...........................6 Install Electric Compression (Alte rnative-Onsite Generators) ................................................................... .......9 Optimization/Ce ntralization.................................................................................................... .........................12

Follow EPA New Source Perfo rmance Standa rds (NSPS)............................................................................. .15 Adherence to Manufacturers’ Opera tion and Maintenanc e Requirements ......................................................17 Use of SCR for NOx control on lean burn engines................................................................................ ..........19 Use of NSCR / 3-way Catalysts and Air/Fuel Ratio Cont rollers on Rich Burn St oichiometric Engines.........21 Use of Oxidation Catalysts and Air/Fuel Ra tio Controllers on Lean Burn Engines........................................26

Install Lean Bu rn Engines ...................................................................................................... .........................28

Interim Emissions Recommenda tions for Sta tionary RICE.......................................................................... ...30 Next Generation Stationary RICE Control Technologies – Coopera tive Technology Partnerships................33

MOBILE/NON-ROAD................................................................................................................ ........................42 Fugitive Dust Control Plans for Dir t/Gravel Road and Land Clear ing............................................................4 2

Use Produced Water fo r Dust Reduction.......................................................................................... ...............44

Pave Roads to Mitigate Dust .................................................................................................... .......................47

Automation of Wells to Reduce Truck Traffic .................................................................................... ............48

Reduced Vehicular Dust Productio n by Enforcing Speed Limits.................................................................... 49 Reduced Truck Traffic by Centralizing Produced Water St orage Fac ilities ....................................................51 Reduced Vehicular Dust Production by Coveri ng Lease Roads with Rock or Gravel ....................................53 Reduced Truck Traffic by Efficiently R outing Produced Water Disposal Trucks ..........................................54

Use Alternative Fuels and Maximize Fuel Efficien cy to Control Combustion Engine Emissions..................55

Utilize Exhaust Emission Control Devices for Combustion Engine Em ission Controls .................................57 Exhaust Engine Testing for Combus tion Engine Emi ssion Controls ..............................................................58 Reduce Trucking Traffic in the Four Corn ers Region ............................................................................. ........59

RIG ENGINES .................................................................................................................... ................................60

Diesel Fuel Emulsions .......................................................................................................... ...........................60

Natural Gas Fire d Rig Engines .................................................................................................. ......................62 Selective Catalytic Reductio n (SCR)............................................................................................ ...................64 Selective Non-Catalyti c Reducti on (SNCR)....................................................................................... .............66 Implementation of EPA’s Non Road Diesel Engine Rule – Tier 2 - 4 Standards............................................68

Interim Emissions Recomm endations fo r Drill Rigs ............................................................................... ........75

Various Diesel Controls........................................................................................................ ...........................76

TURBINES....................................................................................................................... ...................................79

Upgrade Existing Turbines to Improved Combustion Controls (Emulating Dry LoNOx Technology) ..........79

EXPLORATION & PRODUCTION....................................................................................................... ................80

TANKS.......................................................................................................................... ......................................80 Best Management Practices (BMPs) for Operating Ta nk Batteries.................................................................8 0 Installing Vapor Reco very Units (VRU) .......................................................................................... ...............81 Installing Gas Bla nkets Capability ............................................................................................. .....................83 Installing Floati ng Roof Tanks ................................................................................................. .......................85

DEHYDRATORS/SEPARATORS/HEATERS ................................................................................................. .86 Replace Glycol Dehydrators w ith Desiccant De hydrators.......................................................................... .....86

Installation of Insula tion on Separators ....................................................................................... ....................89

Portable Desiccan t Dehydrators................................................................................................. ......................90 Zero Emissions (a.k.a. Qu antum Leap) Dehydrator ................................................................................ ........92 Venting versus Flaring of Natu ral Gas during Well Completions.................................................................. .95

Co-location/Centraliza tion for New Sources ..................................................................................... ............102 Control Glycol Pump Rates ...................................................................................................... .....................104Oil & Gas

11/01/07 2 Combustors fo r Still Ve nts ..................................................................................................... .......................106

WELLS.......................................................................................................................... ....................................107 Installation and/or Optimizatio n of a Plunger Lift Sy stem ...................................................................... ......107 Implementation of Reduced Emission Completions................................................................................. .....110 Convert High-Bleed to Low or no Bleed Gas Pneumatic Controls ...............................................................112 Utilizing Electric Ch emical Pumps.............................................................................................. ..................114

Solar Power Driven Wells ites and Tank Batte ries................................................................................ .........115

PNEUMATICS / CONTRO LLERS / FUGITIVES........................................................................................... 117 Optical Imaging to Detect Gas Leaks ............................................................................................ ................117

Convert Gas Pneumatic Contro ls to Instrument Air ............................................................................... .......119

MIDSTREAM OPERATIONS........................................................................................................... ...............121 Application of NSPS and MACT Requirements for Existing Sources at Midstream Facilities ....................121 Specific Direction for How to Meet NSPS and MACT Standards ................................................................123

OVERARCHING .................................................................................................................... ..............................125 Lease and Permit Incentives for Improving Air Quality on Pu blic Lands.....................................................125

Economic Incentives-Based Emissi on Trading System (EBETS).................................................................130 Tax or Economic Development Incentiv es for Environmenta l Mitigatio n....................................................133Voluntary Partnerships and Pay-back Incentives: Four Corners Innovation Technology and Best EnergyEnvironment Management Practices (IBEMP)....................................................................................... .......136 Voluntary Programs............................................................................................................. ..........................139 Cumulative Inventory of Emissions a nd Required Contro l Technology .......................................................141 Mitigation of Hydr ogen Sulfide................................................................................................. ....................143 Encourage States Importing San Juan Basin Natural Ga s to Require Pollution Control at the Source .........144

PUBLIC COMMENTS ................................................................................................................ .........................146Oil & Gas

11/01/07 3 

### Oil and Gas: Preface

Overview

The Oil & Gas Work Group of the Four Corners Ai r Quality Task Force was tasked with analyzing emission mitigation strategies for this industrial sector . For each Mitigation Strategy, and to the extent practicable, the Work Group documented the descrip tion of each strategy as well as implementation and feasibility considerations.

Participation in the Oil and Gas Work Group involved st ate, local and tribal air quality agencies, federal land management agencies, industry representatives, pub lic citizens, and representatives of environmental organizations. Over six working sessions and many m onthly conference calls, the work group identified more than 75 potential mitigation strategies. These mi tigation strategies were then discussed and either drafted as a mitigation option paper, or eliminated from further analysis where a rationale to do so existed (see Table at the end of this document). The vast majo rity of the options discussed are represented herein by mitigation option papers for a total of 51.

Organization

The Oil and Gas industry is generally divided into sub-sections according to process. The Work Group used this progression in process to address each stag e of the industry, with the exception of exploring Mitigation Options for Engines as a unique section that applies across the processes in the industry. For the purposes of organization and analysis of availabl e Mitigation Strategies, the Oil and Gas portion of the TF Draft Report follows the sequence of definitions as identified below:

1. Engines: The work group addressed engines as a separate category in its analysis attributable to all processes in the oil and gas industry. Th e mitigation strategies were created to address the subcategories of stationary or mobile/non-ro ad engines, drill rig engines, and turbines.

2. Exploration & Production (E & P): the work group defined E & P as the upstream sector of the oil and gas industry, including all activities associated with drilling, completion, and putting the well on-line. The work group iden tified and developed mitigation strategies for specific equipment in E&P, including oil/conde nsate tanks, dehydrators/separators/heaters, fugitive emissions associated with pneuma tic operations, comple tions, and wellhead

considerations.

3. Midstream: the work group defined Midstream Op erations as occurring after custody transfer, including facilities such as compr essor stations, gas processing plants, and transmission or storage of natural gas. Where appropriate, the work group devised mitigation strategies that avoided general overlap with E & P options, and concentrated primarily on options unique to the “midstream operations” that were not otherwise examined in the context of E&P operations.

The Work Group also identified and deve loped mitigation strategies that address Overarching and Energy Efficiency and Renewable Energy appropriate for consideration of application to the oil and gas industry.Oil & Gas: Engines – Stationary RICE

11/01/07 4 

### ENGINES: STATIONARY RICE

Mitigation Option: Industry Collaboration

I. Description of the mitigation option

Overview

• This option explores the possibility of industry collaboration with engine manufacturers to achieve and reliably maintain emissions at or below prescribed levels for upcoming emission standards (i.e., NSPS for engines) on new engines. Such technologies could include but are not limited to lean burn or non-selective catalytic converters (NSCR) with air-to-fuel ratio

controllers. The focus on such an effort would be on natural gas fired engines site rated at less than 300 hp.

Air Quality and Environmental Benefits

• This option would result in air quality improvement since all new engines built would meet lowest achievable emission controls at that time for criteria pollutants.

• Differing opinion : Reasonably available control technolo gy is the accepted term used by EPA, industry, and regulatory entities versus lowest achi evable emission controls that have a different

connotation.

Economic New Engines:

• Depending on the final emission levels established through this effort, operators might have to spend resources ensuring that prescribed emis sions limits are being maintained.

• If through this option emission levels are set at levels lower than upcoming federal standards, then detailed engineering/economic analyses s hould be conducted to examine the incremental cost to control (over the federal regulatory baselin e) and to determine if such additional controls are consistent with other programs. Existing Engines:

• If such a program were expanded to include the retrofitting of all existing engines with current emission control technology, this would require a large capital investme nt from companies to achieve this result. This would result in replace ment of older compressor engines, particularly those less than 200 hp,

• Differing Opinion: new engines would be a significant cost to the oil and gas industry. The salvage value of older compressors is a fraction of the cost of a new compressor engine.

• It would require companies to commit to ordering new engines over a prescribed time, likely ahead of when older units would have been replaced.

• The manufacturers would need confirmed orders to justify re-tooling their plants to meet the

demand.

Trade-offs

• The use of given emission control technology coul d result in other emissions. For example, the use of lean-burn technology on a large scale would result in incremental emissions of formaldehyde. If NSCR is used on a large scale, it is believed ammonia emissions would result. However, it is not known if these emissions would be significant.

• Some engine manufacturers that cannot meet the demand and/or re-tool their factories could lose

their market share in the San Juan Basin. Need to ensure this does not create any restraint of

trade concerns.Oil & Gas: Engines – Stationary RICE

11/01/07 5 II. Description of how to implement A. Mandatory or voluntary: It could be both. The companies could begin a process of placing new orders voluntarily or the agencies, through regulatory/rules, could require emission levels that necessitate ordering new compressor engines. Differing opinion: If this is industry collaboration with engine manufacturers, then the regulatory agencies should not expand to rule making that has requirements more stringent than NSPS.

B. Indicate the most appropriate agency(ies) to implement: State Environmental Agencies. Differing opinion: Not appropriate. If this is industry co llaboration with engine manufacturers, then the regulatory agencies should not expand to rule making that has requirements more stringent than NSPS.

III. Feasibility of the option A. Technical: None identified although some field trials and bench scale tests are probably necessary to assess actual emissions on the new engines. Differing opinion : EPA has assessed the technological feasi bility of controlling these types of engines (See NSPS Mitigation Option Paper below.)

B. Environmental: Yes, from the Cumulative Effects group depending upon what type of emission control technology is preferred. The cont rol technology that will be used will be based on the emission level selected, the lowest cost method of achieving the desired level of emission reduction and the reliability of maintaining emissi ons at the desired level. Ultimate decisions regarding control options should be based on measurable improvements in ambient air quality.

C. Economic: Economic burdens associated with e ngine replacement and manufacturer re-tooling are likely to be substantial.

IV. Background data and assumptions used Emission inventories compiled for the Farmington, NM BLM Resource Management Plan (2003) and

Southern Ute Indian Reservation Oil and G as Environmental Impact Statement (2002).

• Preliminary discussions with companies and engine manufacturer representatives.

• Will need to integrate any more recent emissions inventory data from the Cumulative Effects Group.

V. Any uncertainty associated with the option (Low, Medium, High) High, especially pertaining to economic feasibility and availability of field proven engines. High due to economics of replacing a large fleet of existing compr essor engines and the timing that would be required to begin manufacturing a number of small horsepower engines.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups (please describe the issue and which groups)

May need to verify with other work groups if ma nufacturing a large number of new compressor engines, particularly in the smaller horsepower range, coul d conflict with other new engine initiatives such as building Tier II and Tier III diesel engines and meeting requirements for additional NSPS general regulations.Oil & Gas: Engines – Stationary RICE

11/01/07 6 

### Mitigation Option: Install Electric Compression

I. Description of the mitigation option

Overview

• Electric Driven Compression would involve the re placement or retrofit of existing internal combustion engines or proposed new engines with electric motors. Retrofit of internal combustion engines with electric drivers is not generally feasible. Not all compressors can be fitted with an electric motor. This normally requir es either a complete package change or, at very least, gear modifications. Electric motors would be designed to deliver equal horsepower to that of internal combustion engines. However, the electric grid capacity in any given area may limit the size/number of electric engines potentially supportable. The reliability of the grid and the

easements also must be considered.

Air Quality/Environmental

• Elimination of local emissions of criteria pollutants that occur with the combustion of hydrocarbon fuels (natural gas, diesel, gasoline). Displacement of emissions to power generating sources (utilities) primarily from coal fired power pl ants (with higher emissions than natural gas fired engines) or natural gas fired peaking units.

• The “emissions balance” for switching to 4-corner s grid electricity is illustrated in the table directly below. As apparent, the switch is not necessarily positive when compared with “modern” gas-fired reciprocating engines. The actual “b alance” would depend on the particular engine model being compared to an electrical option.

4 Corners Grid Average Emissions

lbs/MWh (From NRDC Database) (Average of PNM, Xcel, and Tri-State)

SO2 3.4

NOx 3.8
CO2 2,473 Caterpillar 3608 LE Average Emissions lbs/MWh (equivalent)

SO2 0

NOx 2.9
CO2 1,138 Cat. 3608 Assumptions:

9815 Btu/kw-hr

"Sweet" Natural Gas NOx - 1 g/hp-hr 1 cu ft gas = 1,000 btu

See also Cumulative Effects Analysis for th is option for further emissions analysis.

Economics

• The costs to replace natural gas fired compressor engines with electric motors would be costly. Not all natural gas fired compressors can be fitted directly with an electric motor. This normally requires a complete package change or at very least, gear modifications.Oil & Gas: Engines – Stationary RICE

11/01/07 7 • The costs of getting electrical power to the sites would be extremely high in most cases. It could require a grid pattern upgrade, which could co sts millions of dollars for a given area. Maintenance and repair costs associated with the electrical power source are not included.

• A routine connection to a grid with adequate cap acity for a small electric motor can be $18K to $25K/site on the Colorado side of the San Juan Basin.

• A scaled down substation for electrification of a central compression site can range between $250K and $400K.

• Suppliers/Manufacturers would have to be poi sed to meet the demand of providing a large number of electrical motors, large and small.

Tradeoffs

• While the sites where the electrical motors would be placed would not be sources of emissions, indirect emissions from the facilities generating th e electricity would still occur such as coal-fired power plants.

• Additional co-generation facilities would likely ha ve to be built in the region to supply the amount of electrical power needed for this option. This would result in additional emissions of criteria pollutants from the combustion of natural g as for turbines typically used for co-generation facilities. Co-generation produces both power and stea m; as there is not a market for the steam, this might just be a need for additional power pl ants or combined cycle plants. Lead time and cost for permitting and new base load gene rating facilities could be substantial.

• There would need to be possible upgrades in th e electrical distribution system. However, the limitation of doing so is predicated by the elect rical grid that would exist in a given area to provide the necessary capacity to support electrical compression.

• When comparing emissions from electric generati ng facilities used to power electric compressors versus natural gas fired compressors, differenc es in emission rates as well as overall energy efficiency must be examined.

Burdens

• The cost to replace natural gas fired engines with electrical motors would be borne by the oil and gas industry. Extensive capital investments coul d be required if new generating facilities are needed to meet the electrical demand of this option.

II. Description of how to implement A. Mandatory or voluntary: Voluntary based on economics of meeting emission reduction requirements and/or initiatives a nd feasibility of implementation. B. Indicate the most appropriate agency(ies) to implement: No agency action needed to implement a voluntary program.

III. Feasibility of the option A. Technical: Feasible depending upon the electrica l grid in a given geographic area and overall available electrical power for large-scal e conversion in a given geographic area.

B. Environmental: Factors such as federal land use restrictions or landowner cooperation could restrict the ability to obtain easements to the s ite. The degree to which converting to electrical motors for oil and gas related compression is necessary should be a consideration of the Cumulative Effects and Monitoring Groups. Indi rect emission implications for grid suppliers should be considered (e.g., coal-fired plants). C. Economic: The economics of implementing this option are much larger than stated above. Considerations such as (but not limited to): 1) cost of energy; 2) electrical demand; 3)reliability; and 4) efficiency need to be included in such an analysis. Costs to control calculations are needed to determine if they are consistent with other options being considered. Modeling needs to beOil & Gas: Engines – Stationary RICE

11/01/07 8 conducted to evaluate if potentially shifting emis sions from natural gas to coal would result in ambient air quality benefits.

IV. Background data and assumptions used The background data was acquired from practical appli cation of using electrical motors in the northern San Juan Basin based upon interviews with company engineering and technical staff.

V. Any uncertainty associated with the option (Low, Medium, High): HIGH to MEDIUM based on land accessibility (easements), electric source availability and reliability of uninterrupted supply, advancing GHG le gislation/regulation, and economics.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups (please describe the issue and which groups: Possibly the Cumulative Effects Group due to indirect emission increases from coal-fired plants. See also Cumulative Effects Analysis for this option for further emissions analysis.Oil & Gas: Engines – Stationary RICE

11/01/07 9 

### Mitigation Option: Install Electric Compre ssion (Alternative - Onsite Generators)

I. Description of the mitigation option

Overview As an alternative to grid power dedicated on-site na tural gas-fired electrical generators can be used to supply power to electric motors that replace the selected RICE compression engines. The electric motors would be rated at an equivalent horsepower to that of RICE engines currently used for gas compression. The power sources for the electric compression could cons ist of a network of on-site gas-fired electrical power generators. The alternative c ould be expanded to include consid eration of replacement of other engines, such as, gas-fired pump-jack engines used as "prime-movers."

The currently available gas electric generator run on va riety of fuels including low fuel landfill gas or biogas, pipeline natural and field gases. The gas electric generators are available in the power rating from 11 kW to 4,900 kW. Decisions on the use of on-site ge nerators to replace natural gas-fired engines and the number of generators requi red would depend on a number of factors, including the proximity, spacing and size of existing engines. As a simple example usi ng the conversion factor of 1 MW = 1,341 HP, adding a 1 MW natural gas-fired generator could replace an i nventory of approximately 33 small (40 hp) internal combustion engines if these were reasonably close proxim ity, say spaced within a one or two mile radius. However, in "real world" operations, there will be se veral factors involved in determining the number of required gas-fired electrical generators; such as tran smission loss, ambient operating temperature, load operating conditions, pattering of applied loads, etc.

Air Quality/Environmental Benefits

The emissions from gas electrical generators are rela tively low compare to smaller internal combustion engines because of new technology and ability of c ontrolling emission from big engines. For example a Caterpillar G3612 gas electrical generator with power rating of 2275 kW emits 0.7 gram/hp-hr NOx at 900 rpm, which is equivalent to 0. 0009387 g/W-hr. For comparative illust ration with alternative 1, if you assume .... As stated in the mitigation option; "Control Technology Options for Four Corners Power Plant" (FCPP), the NOx emission from FCPP is approximately 0.54 g/mmBtu. Based on the assumption that efficiency of FCPP is 40%, the NOx emission from FCPP is approximately 0.002099 g/W-hr. This comparison shows that the gas electrical generator is more environmentally friendly then using power from a coal based power plant. Th e baseline average emission for the Western Grid should be used to

calculate the real emission difference between in stalling a lean burn electric generator to replace combustion engines.

The noise from continuously running internal combus tion engines can be an issue for the nearby

residents. The switch to electric motors will also he lp cut down the noise in the oil and gas operation.

The need for less maintenance of electric motors and lean burn electric generator will result in fewer maintenance trips for the oil and gas workers whic h will help in controlling dust as well minimize the impact on wild area in the four corners region.

Economics

The initial capitol cost of installing gas electrical gene rator and electrical motor would be relatively high. As an example, a generator of 1 MW capacity can approximately support 33 combustion engine of 40 HP. A general purpose 40 HP engines costs about $ 1200.00 which results in capital cost of $39,600 forreplacing 33 internal combustion engine with electric motors. The approximate cost of a 1.2 MW gasfired generator is $430,000. The total capital cost fo r replacing 33 engines with a gas fired generator willOil & Gas: Engines – Stationary RICE

11/01/07 10 be about $470,000. However in long term the be nefit in terms of emission reduction and saving in maintenance cost should help in recovering the initial capital cost.

The maintenance cost of one big generator is ch eaper than maintenance of many smaller internal combustion engines.

The cost of running electrical wires to connect elect ric motors will much less than currently installed pipelines to carry natural gas for the small rich burn combustion engines.

Tradeoffs

In case of gas electric generators, there will be shif t of emission from many internal combustion engines to one or several big internal combustion engine(s). There would be a net reduction in emissions which will depend on degree of conversion that each producer deems economically feasible.

The cost and affects of running transmission lines fro m generator(s) to power electrical motors for gas compression needs to be evaluated.

Burdens

The cost to replace natural gas fired engines with el ectrical motors would be borne by the oil and gas industry.

II. Description of how to implement

A. Mandatory or voluntary: Voluntary, depending upon the results of monitoring data over time. B. Indicate the most appropriate agency(ies) to implement: State Air Quality agencies.

III. Feasibility of the option

A. Technical: The feasibility mainly depends on the close proximity of replaceable internal combustion engines and operating conditions of internal combusti ons engines in order of selection of gas electrical generator. The power, transmission line and substa tion requirements for on-site lean-burn generator system would need to be carefully considered in deciding the feasibility of this option.

B. Environmental: Factors such as federal land use restrictions or landowner cooperation could restrict the ability to obtain easements to the site. The degree to which converting to electrical motors for oil and gas related compression is necessary should be a cons ideration of the Cumulative Effects and Monitoring Groups. Emissions from on-site electric generators would more than off- set the natural gas-fired engines that could be targeted for replacement (e.g., uncont rolled compressor engines or small rich burn pump jack engines). C. Economic: Depends upon economics of ordering electrical motors, the ability of the grid system to supply the needed capacity and the cost to obtain right of way to drop a line to a potential site. Suppliers/Manufacturers would have to be poised to meet the demand of providing a large number of electrical motors, large and small.

IV. Background data and assumptions used

The background data was acquired from practical appli cation of using electrical motors in the northern San Juan Basin based upon interviews with company engineering and technical staff.Oil & Gas: Engines – Stationary RICE

11/01/07 11 Gas electrical generator information wa s obtained from Caterpillar's Website.

V. Any uncertainty associated with the option (Low, Medium, High):

Medium based upon uncertainties of obtaining el ectrical easements from landowners and/or land management agencies.

VI. Level of agreement within the work group for this mitigation option : TBD

VII. Cross-over issues to the other source groupsOil & Gas: Engines – Stationary RICE

11/01/07 12 

### Mitigation Option: Optimization/Centralization

I. Description of the mitigation option

Overview

• This option outlines the deployment of intern al combustion engines used as the source to power various oil and gas related operations w ith the appropriate horsepower rated to the need of the activity being conducted. The a dvantages of this approach would be reducing the cumulative amount of horsepower deployed, which may reduce emissions through elimination of compression and optimization of compressor fleets. This may also be accomplished by using larger central compr ession in lieu of deploying numerous smaller compressor engines at a number of individual locations such as well sites.

• Overall fleets of engines in the San Juan b asin are currently believed to be loaded at about 50% available hp. This is determined by looking at installed hp, volume of gas being moved, and pressure differentials in the field. These load factors are dynamic and constantly changing.

• Differing opinion: Emissions from compressor engines are based on the amount of fuel used (a function of capacity and load). Assuming that emission factors do not change with load (this may or may not be true), as the load is reduced emissions will decrease. If it is assumed that all engines have the same rate of emissions, simply reducing the number of engines and operating them at higher capacity will likely result in the same amount of fuel usage and the same amount of emissions. The assumption that all engines

have the same emissions is not true and thus this option is based on a flawed premise. In reality, analysis of engine utilization in the region indicates that larger engines have lower emissions than smaller engines.

Air Quality and Environmental Benefits

• The benefits could be lower emissions cal culated against horsepower assuming smaller horsepower engines would be deployed to replace larger engines. This would be accomplished by either design or as field conditions changed at individual sites or by centralizing compression horsepower at central site. While efficiency may improve, application of smaller engines working at or near full load may increase NOx emissions relative to an oversized unit operating at reduced load.

• Differing opinion : Needs to be framed for applicability to engine type, size, etc.

Economics

• Optimization:

o The economics of replacing individual site compression with properly sized horsepower could be difficult. Some co mpanies bought individual site compression based upon technical considerations at that time. Unfortunately, due to changing field conditions, which could not be contem plated when the original engine was bought, the existing engine may not be si zed properly. To require the purchase of new compressors for changing field conditions over the life of a natural gas field will be an economic strain on the operators.

o The salvage value of the compressor being replaced is a fraction of a new one.

o Replacing engine compression several times during the life of well would not be economic. Purchasing new compression with operating conditions in a given field could jeopardize the economics of a well(s).

o If the engines are rentals, the situation is much more flexible depending upon the

lease/contract with the vendor. In the San Juan Basin most smaller well siteOil & Gas: Engines – Stationary RICE

11/01/07 13 compression is a combination of purchased and leased, both of which depend upon the individual operator’s preferences.

• Centralization

o As with optimization, field conditions cha nge and to size equipment properly on a horsepower basis may require numerous iterations of replacement.

o As above with optimization, the economics of replacing units to fit ever changing

field conditions in the cases where the equipment has been purchased will create economic challenges for the operators.

o For leased units, flexibility would be greater, but woul d depend upon the

lease/contract with the vendor.

o Use of larger centralized engines increas es the opportunity to use low emission lean burn engines.

• Lines and gathering system would probably need to be redesigned and replaced for efficiency, otherwise line losses and bottleneck ing could create operation issues. Besides causing increased surface disturbance the econom ics of line redesign and replacement are probably beyond the economic feasibility limits of the fields in the area.

Tradeoffs

• The tradeoffs for centralization appear to have the most concern.

• There could be an air quality benefit by centr alizing, but there would be more long-term surface disturbance involved and dust generation from construction. For instance, a central compressor serving multiple sites would likely need to be built at a new site making it more equitable from an operational perspective to serve its purpose. A new central site would then require surface disturbance for a new site and, whether an existing site could be used or not, underground piping from the central site to multip le sites would be necessary. This could result in permanent new disturbance (if a new site had to be built) and short-term disturbance for the pipeline to multiple sites until this was reclaimed.

• While above ground pipelines are a possibility, for safety reasons these have not been generally used in the San Juan Basin.

• Emissions tradeoffs based on relative opera ting loads would need to be considered.

• There is potential for increased noise for those living close to these centralized facilities.

• Potential for increased permitting.

• It is possible that centralized compressor stati ons would become Part 70 or 71 facilities (Title V under the CAA) and would require substantial testing and record keeping on the part of operators and agencies.

Burdens

• The burden for optimization and/or centralization would fall to industry. The cost of pursuing this approach should be carefully cons idered due to the impact it could have on the economic viability of a given well.

• Increased permitting places burden on regulatory agencies and industry.

II. Description of how to implement A. Mandatory or voluntary. This option shoul d be voluntary given the economic impacts. B. Indicate the most appropriate agency(ies) to im plement. NA; would be voluntary by the companies since they must assess the technical and economic feasibility.

III. Feasibility of the option

A. Technical: Technical concerns would include trying to size compression properly either with optimization or centralization considering the unknow ns associated with changing field conditions.Oil & Gas: Engines – Stationary RICE

11/01/07 14 B. Environmental: Potential environmental benefit w ould need to be more cl osely reviewed depending upon the specific scenario. At best, little or marg inal benefits are likely to be realized. C. Economic: While some centralized options coul d be considered, well-le vel optimization is not economically feasible considering all the vari ables that exist with field operations. .

IV. Background data and assumptions used Discussions with company field and engineering staff

• Input from engine manufacturer s and engine consultants

V. Any uncertainty associated with the option (Low, Medium, High) High. For optimization: The sizing of engines is based on the maximum flow from a well. As wells decline through time the initial hp needs are no longer appropriate. Replacement of this existing hp would be cost prohibitive. For centralization: collection systems are already in place and centralizing would require retrofitting, which is cost prohibitive. Furt her, in NM, well sites and gathering systems have different owners. Competitors would need to colla borate to centralize, which would be unlikely.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source gro ups (please describe the issue and which groups

None identified at this time. See also Cumulative Ef fects Analysis for this opt ion for further emissions analysis.Oil & Gas: Engines – Stationary RICE

11/01/07 15 

### Mitigation Option: Follow EPA New So urce Performance Standards (NSPS)

I. Description of the mitigation option EPA is in the process of developing the first nationa l requirements for the control of criteria pollutants from stationary engines. Separate rulemakings are in process for compression-ignition (CI) and sparkignition (SI) engines. These NSPS will serve as the national requirements, leaving states with the authority to regulate more stringently as might be required in unique situations.

CI NSPS: The final NSPS for stationary CI (diesel) engines was published in the Federal Register on July 11, 2006. It requires that new CI engines bu ilt from April 1, 2006, through December 31, 2006, for stationary use meet EPA’s nonroad Tier 1 emission re quirements. From January 1, 2007, all new CI engines built for stationary use must be certified to the prevailing nonroad standards. (Minor exceptions are beyond the scope of this discussion.)

SI NSPS: The NSPS proposal for stationary SI engines, including those operating on gaseous fuels, was published in the Federal Register on June 12, 2006. Per court order, the rule is to be finalized by December 20, 2007. Like the CI NSPS, certain elem ents of the SI NSPS will be retroactively effective once finalized. The following summarizes the proposed requirements:

All new stationary engines in the Four Corners re gion will have to meet the new EPA requirements. Deferring to the EPA NSPS will provide the most co st-effective emissions control because manufacturers will have compliant products for sale across much of the country. Compliance with the EPA NSPS will provide a level of emissions control that is federa lly mandated and will impose a certain financial burden that is not elective. The premise for this mitiga tion option is that additio nal control beyond the EPA NSPS would not be needed for new engines.

II. Description of how to implement A. Mandatory: Compliance with the EPA NSPS will be mandatory. This would apply to all newly manufactured, modified and reconstructed engines afte r the NSPS effective dates. ‘Modified’ engines are those undergoing a change that would result in an in crease in emissions, while ‘reconstructed’ engines are those undergoing rebuild work that costs at least 50% of the cost of a new unit. See 40 CFR 60.2 for

further definitional details.

Differing Opinion: Voluntary: Applicability of the NSPS requi rements could be considered for existing engines. Because a large number of existing engin es would require extensive rework or replacement to achieve the NSPS levels, any such approach should be a voluntary, incentive-based program.

B. Indicate the most appropriate agency(ies) to implement : No additional work would be needed other than what EPA is mandating. Any permitting would c ontinue to be at the State’s discretion. TheOil & Gas: Engines – Stationary RICE

11/01/07 16 appropriate agencies for any incentive based applic ability to existing engin es would need to be

determined.

III. Feasibility of the option

A. Technical: EPA has spent the past year working with engine manufacturers during its development of the CI and SI NSPS. The requirements have been shown to be technologically feasible.

B. Environmental: EPA’s regulatory documents do/will provide details of the expected environmental

benefits and the conclusion that this level of control is appropriate fo r areas not in advanced levels of nonattainment.

C. Economic: EPA’s Regulatory Impact Analyses (RIA) for the two rulemakings will provide explanations of the expected costs of compliance.

IV. Background data and assumptions used None beyond material in EPA’s rulemakings.

V. Any uncertainty associated with the option (Low, Medium, High) Essentially no uncertainty that the NSPS will soon pr ovide new, emissions-controlled stationary engines in the Four Corners region.

VI. Level of agreement within the work group for this mitigation option The RICE subgroup anticipates Oil & Gas Workgroup consensus that EPA’s mandatory compliance with its new NSPS will provide appropriate short- and long-term emissions control that is commensurate with the needs of the Four Corners region.

VII. Cross-over issues to the other source groups Assistance from Cumulative Effects Work Group needed to assess air quality benefits in the Four Corners area. See also Cumulative Effects Analysis fo r this option for further emissions analysis.Oil & Gas: Engines – Stationary RICE

11/01/07 17 

### Mitigation Option: Adherence to Manuf acturers’ Operation and Maintenance Requirements

I. Description of the mitigation option Engine manufacturers provide to end-users recommended procedures for the initial installation and adjustment of spark-ignition (SI) engines, in addition to on-going preventative maintenance

recommendations. Adherence to these recommendati ons provides long-term, intended performance, emission levels, durability, etc. Please see EPA SI NSPS proposal update below under Section V.

II. Description of how to implement A. Mandatory or voluntary: While adherence to engine manuf acturers’ ‘recommended’ procedures is generally voluntary from a regulatory perspective, this mitigation option instead proposes that such adherence be mandatory. This c ould be considered for existing engines as well as for new engines.

Please see Section V below for further discussion.

B. Indicate the most appropriate agency(ies) to implement: EPA’s proposed New Source Performance Standards (NSPS) for, in particular, SI engines, includes several related aspects that will likely be mandatory. Those aspects of engine manufacturers’ recommended procedures that are not included in the NSPS could be implemented by the states.

1. 40 CFR 60.4234: “Owners and operators of stationary SI ICE must operate and maintain stationary SI ICE that achieve the emis sion standards as required in 60.4233 according to the manufacturer’s written instructions or procedu res developed by the owner or operator that are approved by the engine manufacturer, over the entire life of the engine.”

2. 40 CFR 60.4241(f): “Manufacturers may certify their engines for operation using gaseous fuels in addition to pipeline-quality natural gas; howev er, the manufacturer must specify the properties of that fuel and provide testing in formation showing that the engine will meet the emission standards specified in 60.4231(d) when operating on that fuel. The manufacturer must also provide instructions for configuring the stationary engine to meet the emission standards on fuels that do not meet the pipeline-quality natural gas definition. The manufacturer must also provide information to the owner and operator of the certified stationary SI engine regarding the configur ation that is most conducive to reduced emissions where the engine will be operated on particular fuels to which the engine is not

certified.”

3. 60.4243: “ If you are an owner or operator, you must operate and maintain the stationary SI internal combustion engine a nd control device according to the manufacturer’s

written instructions or procedures developed by the owner or operator that are approved by the engine manufacturer. In addition, owners and operators of certified engines may only change those settings that are allowed by the manufacturer to ensure compliance with the applicable emission standards. ...The engine must be installed and c onfigured according to the manufacturer’s specifications to ensure compliance with the applicable standards.”

4. 60.4245(a): “Owners and operators of all statio nary SI ICE must keep records of...maintenance conducted on the engine.”

III. Feasibility of the option

A. Technical: Prudent operators follow manufacturers’ r ecommended procedures. Properly maintained engines operate more efficiently and at lower total co st. Ignition maintenance, in particular, can have significant impact on the performance and life of catalysts.Oil & Gas: Engines – Stationary RICE

11/01/07 18 B. Environmental: Properly maintained engines produce lower emissions. Instead of a fix-as-fail mentality, proper maintenance can avoid or detect failed O 2 sensors or spark plugs, thus avoiding an

increase in HC and CO.

C. Economic: The overall, long-term cost of a properly ma intained engine is lower than that of a neglected engine.

IV. Background data and assumptions used

V. Any uncertainty associated with the option Medium. EPA NSPS Upda te: Mandatory requirement to follow engine manufacturers’ recommendations is included in the proposal for optionally certified engines. For engines not certified by engine ma nufacturers, the owner/operator would have compliance responsibility and would not be required to follo w the engine manufacturers’ recommendations. Owner/operators are raising concern with EPA over the proposed requirement to follow engine manufacturer recommendations for certified engines or follow the proposed option to seek engine manufacturer approval for alternativ e operational procedures. Many ow ner/operators believe their own time-proven procedures are appropriate. Because EPA’s final rule will have carefully considered the implications of operational and main tenance practices, the Agency’s fi nal outcome should be appropriate for new engines used in the Four Corners area. Any consideration of those requirements for existing engines would need to assess the potential benefits achievable through altering current field practices.

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to the other source groupsOil & Gas: Engines – Stationary RICE

11/01/07 19 

### Mitigation Option: Use of SCR for NOx control on lean burn engines

I. Description of the mitigation option NOx emissions from lean burn engines (natural gas and diesel fueled) can be reduced by chemically converting NOx into inert compounds. The most effe ctive equipment to achieve NOx reductions is an SCR (selective catalytic reduction) system. Differing opinion: SCR is one effective equipment option to achieve NOx reductions. Reactant injection of industrial grade urea, anhydrous ammonia, or aqueous ammonia is required to

facilitate the chemical conversion. Th e overall catalyst reaction is as follows:

NH3 + NO + NO2 > N2 + H2O

The SCR systems utilize programmable logic contro ller (PLC) based control software for engine mapping/reactant injection requirements. Sampling ce lls are utilized for closed loop feedback of dosing requirements depending on the amount of NO measured downstream of the catalyst bed.

SCR system components include catalyst housing, h ousing insulation, contro l/dosing panel, exhaust dosing/mixing section, and reactant injector. Depending on the reactant medium, a storage tank will be required with a potential minimum temperature requirement of 40°F. Differing opinion: Heated reactant storage may drive limited applicability. Description should be expanded to address handling, associated regulations with monitoring and testing for the system slip and RMPs if applicable. Electrical supply to run the SCR system and instrumentation is required.

SCR systems can be constructed with the additi on of oxidation catalysts, for the added conversion requirements of CO, VOCs and Formaldehyde. This oxidation catalyst is a dry reaction and is not dependant on injection of a reactant. See the mitig ation option on the use of oxidation catalysts for reduction levels achieved for the pollutants. Differing opinion: Mitigation Option is ‘Use of SCR for NOx control on lean burn engines’; therefore, this paragraph may be out of context.

II. Description of how to implement A. Mandatory or voluntary Voluntary: May be enhanced by the state supplementing a percentage of the cost. B. Indicate the most appropriate agency(ies) to implement

III. Feasibility of the option

A. Technical : Dependent on site readiness, installati on and start-up would require 7-10 days. Differing opinion: Heated reactant storage may drive limited app licability, especially if power is unavailable. Concerns include security risk, handling, safety sta ndards, applicability of RMPs and other associated regulations for monitoring and testing of the system sl ip. There have been no known applications of this technology for remote unattended o il and gas operations. At the present time there is insufficient information to quantify achievable em ission reductions in unattended fac ilities. The incremental cost to control on lean burn technology is likely to be ve ry high because of the small incremental additional mass reductions as a result of tertiary add on controls. Because SCR uses a dilute aqueous solution, RMP hazards are typically not a concern. Excessive ammonia slip within a coherent NOx plume may lead to increased NO3 formation. This could result in degradation of visibility even though NOx emissions are reduced.

B. Environmental : Post catalyst NOx levels of <0.15g/bhp-hr. Differing opinion: <0.15 g/bhp-hr depends on the start point but could imply 95% or greater control. Catalysts optimally start at 90-95% capability but drop over time. Control is sensitive and if it moves offOil & Gas: Engines – Stationary RICE

11/01/07 20 set point, result is ‘no’ control (vs. reduced control). What is the origin of the stated NOx levels? On what type of engine in what type of service? Th is appears to be simply an assertion with no backup or

verification.

C. Economic : Cost of SCR system and maintenance are an in creased cost to the packager and end user. The five-year cost for SCR on a 3-engine rig in the Jonah/Pinedale area of Wyoming was estimated at $5 MM in a demonstration pilot conducte d by Shell. This information is available from the Wyoming DEQ. Differing opinion: Costs of heated storage, additional regulatory compliance, added manpower and increased site security would be the burden of the operato r. In addition, the engine must be highly stable for this control to be effective (see environmental note). See also Cumulative Effects Analysis for th is option for further emissions analysis.

IV. Background data and assumptions used

V. Any uncertainty associated with the option (Low, Medium, High) Medium. Negative perception of reactant handling a nd injection, though the technology has proven itself to be very user friendly. Differing opinion: HIGH: The assertion that this is “user friendly” technology is not aligned with the experiences documented as part of the pilots noted above. In these pilots, the systems required both a vendor representative and consultant on site to keep them operating correctly. Concerns include heating reactant, security risk, handling, safety standards, applicability of RMPs and other associated regulations for monitoring and testing of the system slip. Modeling needs to be conducted to evaluate the potential improvement in ambient air quality (ozone, deposition and visibility).

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to the other source groups (please describe the issue and which groups) None.

Differing opinion: The CE group needs to offer an opinion on the effect of additional ammonia emissions at plume height.

See also Cumulative Effects Analysis for th is option for further emissions analysis.Oil & Gas: Engines – Stationary RICE

11/01/07 21 

### Mitigation Option: Use of NSCR / 3-Way Catalyst s and Air/Fuel Ratio Controllers on Rich Burn Stoichiometric Engines

I. Description of the mitigation option, including benefits (air quality, environmental, economic, other) and burdens (on whom, what)

NO X , CO, HC, and Formaldehyde emissions from a stoich iometric engine can be reduced by chemically converting these pollutants into harmless, naturally occurring compounds of nitr ogen, carbon dioxide and water vapor. The most common method for achieving this is through the use of a catalytic converter. In a catalytic converter, the catalyst will either oxidize ( oxidation catalyst) a CO or fuel molecule or reduce (reduction catalyst) a NO X molecule. The general catalyst reactions are as follows:

NO + CO = N 2 + CO 2 NO X + CH 4 = N 2 + CO 2 +H 2 O

NO X + H 2 = N 2 + H 2 O

These reactions are reducing the NO X to nitrogen and oxidizing the fuel and CO molecules. These reactions oxidize some of the CO and NMHC molecules, however further conversion is accomplished with and oxidizing catalyst. The oxidizing reactions are shown below:

CO + O 2 = CO 2 CH 4 + O 2 = CO 2 + H 2 0

CnHm + O 2 = CO 2 + H 2 0

H 2 + O 2 = H 2 O

A 3-way catalyst contains both reduction and ox idation catalyst materials and will convert NO X , CO, and

NMHCs to N 2 , CO 2 , and H 2 O. A process which causes reaction of several pollutant components is referred to as a Non Selective Catalyst Reduction (NS CR). NSCR is applicable only on stoichiometric engines. A very narrow air/fuel ratio operating range is necessary to maintain the catalyst efficiency. This can only be consistently maintained by utilizing electronic air/fuel ratio controls.

Maintaining low emissions in a stoichiometric comb ustion engine using exhaust gas treatment requires a very closely regulated air/fuel ratio. Without an air/fuel ratio controller, emission reduction efficiencies vary through the catalyst. Many Air/Fuel Ratio Cont rollers (AFRCs) are available on the market today. AFRCs are available from both the engine manufact ure or can be purchased from an after-market supplier. Most controllers utilize closed loop contro l based on the readings of an exhaust gas oxygen

sensor to determine the air/fuel ratio.

Air/Fuel Ratio Control will only maintain an operator-de termined set point. For this set point to be at the lowest possible emissions setting an exhaust gas an alyzer must be utilized. Operators should utilize quarterly emission tests to ensure units are maintaining compliance.

Differing opinion: This mitigation option is distinct from the mitigation option on using oxidation catalysts on lean burn engines because NSCR controllers are applied only to rich burn engines. Only applies to true rich burn engines, not effective for 1-2% rated rich-burns. 3-way catalysts are only applicable to stoichiometric (true rich burn) engin es, potential is to drive the exhaust temperature up. Oxygen, oil slip past engine rings, and p oor fuel quality may destroy the catalysts.

II. Description of how to implement A. Mandatory or voluntary: Voluntary: May be enhanced by state funding a percentage of the cost.Oil & Gas: Engines – Stationary RICE

11/01/07 22 Mandatory: Mandatory enforcement would give the state the power to eliminate, at the minimum, 90% of

NO X , CO, HC, and Formaldehyde emis sions from stationary elements. Differing Opinion: This option should be mandatory, impl emented and enforced by the states. Differing Opinion: 90% is a reasonable not minimum control for NOx and CO, but HC and Formaldehyde are not straightforward to measure or to define. Catalysts are in a constant state of decline during operation and require periodic cleaning or repl acement. 90% control is contingent on closely monitored and regulated air/fuel ratio. A more lik ely/achievable reduction of NOx is in the 80% range and can only be achieved with well ope rated and maintained engines/AFR’s where the load is stable in

nature. Variable loads result in less than optimum air/fuel ratios and less reduction.

B. Indicate the most appropriate agency(ies) to implement : States, Tribes and/or BLM, due to the fact that they are already involved in air quality regulations. Differing opinion: Mandatory implementation of this requirement would only be feasible in a wellcrafted permit program administered by the agency having jurisdiction for air quality. BLM does not have regulatory authority for air quality. Although Tribes may have air quality administration authority, very few functional Tribal programs currently exist.

III. Feasibility of the option

A. Technical : Engines can be retrofitted in the field 1⁄2 a da y or less. Catalysts do have a life span and will lose their efficiencies. However, under ideal ope rating parameters and w ith consistent engine maintenance, the life span of a catalyst can easily be up to 5 years. Catalysts can be washed to increase the lifespan in the case of oil spray or ashing. AFRC oxygen sensors should be replaced quarterly to assure constant compliance. Fuel quality limitations are notable, i.e. field gas, biofuel, etc. may damage catalysts. Differing Opinion: The previous statement is inaccurate; if an engine can be retrofitted, the exhaust system has to be dismantled and rebuilt. Not all engi nes will accept an after-market add on of AFRC. Usually, the added controls require a new base, piping and if applicable, tear down and modification of protective building/fencing. If the engine is por table/skid mounted, this may prohibit it remaining portable. Retrofit installation of catalyst housings and units typically require additional support structure.

B. Environmental : Minimum of 90% NO X , CO, HC, and Formaldehyde emission reduction. Some increase in ammonia emissions would result, however , it is not known if this increase would be significant. Differing opinion: 90% is a reasonable not minimum control for NOx and CO, but HC and Formaldehyde are not straightforward to measure or to define. Catalysts are in a constant state of decline during operation and require periodic cleaning or repl acement. 90% control is contingent on closely monitored and regulated air/fuel ratio. A more lik ely/achievable reduction of NOx is in the 80% range and can only be achieved with well ope rated and maintained engines/AFR’s where the load is stable in

nature. Variable loads result in less than optimum air/fuel ratios and less reduction. Issues Associated With the Use of NSCR on Existing Small Engines:

•Engines Operate at Reduced Loads and There is a Problem Maintaining Sufficient Stack Temperature for Catalyst to Work •On Engines with Carburetors, Difficulty Having the AFR Maintain a Proper Setting •On Older Engines the Linkage and Fuel Control May not Provide “Fine Enough” Control •If the AFR Drifts Low, NH 3 Will be Formed in Roughly Equal Amounts to NOx Reduced

C. Economic : The cost of catalyst and AFRC are an added cost to both packager and end user, however, as technologies have advanced, producers have a number of cost effective options. The fact of the matter is the cost to the producer to maintain compliance is mu ch greater than the cost of a catalyst or AFRC. In order to maintain compliance of any kind, the producer is forced to have mo re manpower, more thoroughOil & Gas: Engines – Stationary RICE

11/01/07 23 engine maintenance programs, and adequate testing of their units to assure that they are in constant compliance. Caterpillar recommends monthly testing with portable analyzer. See approximate control cost analysis as of January 2007 for an example of the cost of NSCR control.

NSCR Retrofit Costs Compressco

Ford 460 Wauk.
220/330 Comments Catalyst Housing Purchase $2,120 $1,600 Catalyst Housing Purchase w/Silencer $2,650 $1,950 Average Housing Purchase $2,385 $1,775 Catalyst Element Purchase $1,000 $800

Air Fuel Ratio Controller Purchase $2,950 $2,950

"Rebuild" of Fuel and Air Control System on Older Engines Electricity for Air Fuel Ratio
Controller - Purchase of solar power unit $350 $350 Alternator and Battery or Solar and Battery Installation of Housing and Catalyst $1,080 $1,080 Assumes one welder and one helper for one full day
Installation/Modification of Support for Housing and Exhaust $300 $300 Estimate of materials - Labor

in item above

Installation of Electricity $540 $540 Electrician or Mechanic for 1/2 day - includes travel to and
from

Installation and Set-up of Air
Fuel Ratio Controller $2,160 $2,160 Electrician or Mechanic and
Instrument Technician for one day - includes travel time to
and from
Incremental Skid Cost for New Engine $1,000 $1,000 Taxes, Freight, Etc. (From EPA Manual) $1,077 $1,077

Total Purchase and Installation - Retrofit $11,842 $11,032

Total Purchase and Installation -

New $8,225 $7,415

Maintenance Cost Quarterly Change of O2 Sensor + Emissions Monitoring - annual

cost $320 $320

Labor/Travel for Above $540 $540 Technician for 1/2 day -

includes travel to and from Annualized Catalyst Replacement (5 yr life) $160 $160

Total Annual Cost $1,020 $1,020Oil & Gas: Engines – Stationary RICE

11/01/07 24 IV. Background data and assumptions used 1. G. Sorge “Update on Emissions” Differing opinion: Insufficient information to locate reference.

V. Any uncertainty associated with the option (Low, Medium, High)

LOW, this is a proven technology with years of resu lts. One issue of merit is the production of ammonia through a 3-way catalyst. This issue has been thoroughly researched and the following are the generalized results: Differing Opinion: MEDIUM: HC is difficult to measure. Drift of control and narrow applicability to only ‘true’ rich burn engines are significant issues.

The problem of NH3 formation across catalyst equipped rich burn CNG engines is associated with problems of the A/F controllers. If the A/F ratio is allo wed to drift rich, considerable NH3 can be formed. This is shown in the following graph:

Differing opinion: Reference is needed for the Graph credentials.

For a variety of reasons the A/F controllers have failed to control at the desired set point, 0 2 sensors failing, a not particularly sophisticated controller, et c. Today’s AFRCs are very exact machines with the ability to easily maintain a precise set point. If a rich burn engine is operated w ith a properly functioningOil & Gas: Engines – Stationary RICE

11/01/07 25 air/fuel ratio controller plus 3-way catalyst, it will meet emissions requirements without producing a

noticeable amount of ammonia.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups None at this time. Differing Opinion: The CE group needs to offer an opinion regarding the impact of increased ammonia emissions in the region. See also Cumulative Effect s Analysis for this option for further emissions analysis.Oil & Gas: Engines – Stationary RICE

11/01/07 26 

### Mitigation Option: Use of Oxidation Catalyst s and Air/Fuel Ratio Controllers on Lean Burn Engines

I. Description of the mitigation option CO, HC, and Formaldehyde emissions from a lean bur n engine can be reduced by chemically converting these pollutants into harmless, naturally occurring compounds, such as carbon dioxide and water vapor. Lean Burn Engines already have low uncontrolled NO X emission values (Lean burn engines are a form of NOx control and therefore do not have uncontrolled emissions)

. The most common method for achieving this is through the use of a catalytic converter. In a catalytic converter, the oxidation catalyst will oxidize (oxidation catalyst) a CO or fuel molecule. The most common method for achieving CO, HC and formaldehyde control this is through the use of an oxidation catalytic converter. The general oxidizing

reactions are shown below:

CO + O 2 = CO 2 CH 4 + O 2 = CO 2 + H 2 0

CnHm + O 2 = CO 2 + H 2 0

H 2 + O 2 = H 2 O

Air/fuel ratio control helps to maintain the catalyst efficiency. This can only be consistently maintained by utilizing electronic air/fuel ratio controls. Howeve r, most air/fuel ratio controllers are utilized to maintain engine performance due to ambient conditions . While it is true that lean burn engines perform better with AFRC units they are not needed for oxid ation catalyst performance – the exhaust stream in a lean burn engine has sufficient oxygen under all conditions where the engine will run. Differing opinion: An electronic air/fuel ratio controller is recommended to help maintain the catalyst efficiency.

Maintaining low emissions in a lean combustion engi ne using exhaust gas treatment is enhanced by the use of an Air/Fuel Ratio Controller, however, not n ecessary. Many Air/Fuel Ratio Controllers (AFRCs) are available on the market today, from both the e ngine manufacture in certain cases and after-market suppliers. Most controllers utilize closed loop cont rol based on the readings of an exhaust gas oxygen

sensor to determine the air/fuel ratio.

Air/Fuel Ratio Control will only maintain an operator-de termined set point. For this set point to be at the lowest possible emissions setting an exhaust gas an alyzer must be utilized. Operators should utilize quarterly emission tests to ensure units are maintaining compliance.

Differing opinion : The preceding two paragraphs seem out of place in the context of oxidation catalyst.

II. Description of how to implement A. Mandatory or voluntary : Voluntary: May be enhanced by state funding a percentage of the cost. Mandatory: Mandatory enforcement would require give th e state the power to eliminate, at the minimum, 90% of CO, HC, and Formaldehyde emissions from st ationary elements. Lean Burn Engines already

have low uncontrolled NO X emission values. Differing Opinion: This option should be mandatory, implemented and enforced by the states

. Differing Opinion: 80% CO destruction is a more likely/ sustainable reduction for CO and HC’s. Formaldehyde destruction/control is less certain but is lower than CO or HC’s. Differing Opinion: 90% is a reasonable not minimum control for CO; but HC and Formaldehyde are not straightforward to measure or to define. Catalysts are in a constant state of decline during operation and require periodic cleaning or replacement. 90% contro l is contingent on closely monitored and regulated

air/fuel ratio.Oil & Gas: Engines – Stationary RICE

11/01/07 27 B. Indicate the most appropriate agency(ies) to implement : States, Tribes and/or BLM, due to the fact that they are already involved in air quality regulations. Differing Opinion: BLM is not appropriate since they are not charged with air quality management. This is the role and responsibility of the States or Tribes.

III. Feasibility of the option

A. Technical : Engines can be retrofitted in the field 1⁄2 a da y or less. Catalysts do have a life span and will lose their efficiencies. However, under ideal ope rating parameters and w ith consistent engine maintenance, the life span of a catalyst can easily be up to 5 years. Catalysts can be washed to increase the lifespan in the case of oil spray or ashing. AFRC oxygen sensors should be replaced quarterly to assure constant compliance. Differing Opinion: The previous sentence should be deleted – it is not applicable to oxidation catalyst. Differing Opinion: The previous statement is inaccurate; if an engine can be retrofitted, the exhaust system has to be dismantled and rebuilt. Not all e ngines will accept an after-market add-on of AFRC. Usually, the added controls require a new base, piping and if applicable, tear down and modification of protective building/fencing. If the engine is por table/skid mounted, this may prohibit it remaining portable. Typically, retrofit will require additional support structure for the

B. Environmental : Minimum of 90% CO, HC, and Fo rmaldehyde emission reduction. Differing Opinion: 90% is a reasonable not minimum control for CO; but HC and Formaldehyde are not straightforward to measure or to define. Catalysts are in a constant state of decline during operation and require periodic cleaning or replacement. 90% contro l is contingent on closely monitored and regulated

air/fuel ratio.

According to the EPA speciate database, the major ity of HC emissions from RICE are methane (C1), which is not a regulated pollutant under the Clean Air Act. Methane is unregulated because it does not enter into photochemical reactions that form ozone. Therefore, from a THC or more importantly a VOC perspective, such controls will do little to improve am bient air quality. Realistic modeling analyses that focus on population exposure should be performed to evaluate exposure to formaldehyde. 80% CO and HC reduction is more likely in an operational mode. HCHO destruction is not completely understood but

is lower than CO or HC.

C. Economic : The cost of catalyst and AFRC are an added cost to both packager and end user, however, as technologies have advanced, producers have a number of cost effective options. The fact of the matter is the cost to the producer to maintain compliance is mu ch greater than the cost of a catalyst or AFRC. In order to maintain compliance of any kind, the producer is forced to have mo re manpower, more thorough engine maintenance programs, and adequate testing of their units to assure that they are in constant compliance.

IV. Background data and assumptions used 1. G. Sorge “Update on Emissions” Differing opinion: Insufficient informati on to locate reference

V. Any uncertainty associated with the option (Low, Medium, High) LOW, this is a proven technology with years of results. Differing Opinion: The uncertainty is not in the emission reduction technology. The uncertainty is in the ambient air quality benefits that would be achieve d as a result of implementation of this option.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups None at this time. See also Cumulative Effects Analysis for this option for further emissions analysis.Oil & Gas: Engines – Stationary RICE

11/01/07 28 

### Mitigation Option: Install Lean Burn Engines

I. Description of the mitigation option Using gas fueled (reciprocating) Lean Burn Engines as the main prime mover in gas compression and generator set applications in the Four Corners area.

Gas engines are the predominant prime mover used to power gas compressor packages. Gas engines are

classified as either Rich Burn or Lean Burn. The industry acknowledges a lean burn engine to have an oxygen level measured at the exhaus t outlet of about 7-8%. This typically translates into a NOx emissions rating of 2 g/bhp-hr or less. This will be federa lly mandated through NSPS regulations requiring performance at this rating for both Lean Burn and Rich Burn engines. Currently, a large percentage of engines operating in the Four Corners Area that have a capacity of greater than 500 hp use lean burn technology and achieve, on average, a NOx emission rating of less than 2 g/hp-hr.

Lean burn engines have this lower NOx rating withou t using a catalyst or any other form of emissions after-treatment. Some lean burn engine incorporate an Air Fuel Ratio Control installed at the engine manufacturing plant.

Typically lean burn engines have a HP rating a bove 300 HP. This reflects today’s manufacturing emphasis.

The main advantage of using a lean burn is in its cap ability to offer low emissions without after-treatment. In addition, lean burn engines opera te at cooler temperatures and ma y offer longer life between major repairs.

II. Description of how to implement A. Voluntary – lower emissions should be the goal. How the operator gets there is his selection and responsibility. In other words, allow an operator to either use a lean burn engine without emissions aftertreatment or a rich burn engine with emissions after-tre atment to achieve the emissions level needed. It is important to note that the majority of engines greater than 500 hp located on the Southern Ute Reservation where there is no minor source permitting program are lean burn or are low emitting engines as a result of post catalyst treatment. This h as been a voluntary effort from the operators. B. Most appropriate agency to implement: EPA and state air boards.

III. Feasibility of the option

A. Technical : Some states have shown preference to accep t engines with lean burn technology over rich burn engines using after-treatment. But as of mid- 2006 no engine manufacturers offer the lean burn engine at less than 300 HP. So manufacturers woul d have to develop a new engine to meet this requirement.

B. Environmental : Study the effect of HAPs formation in lean burn emission and whether further reduction is necessary. There has been extensive t esting on HAP emissions from lean burn engines and EPA has established MACT standards for major HAP s ources that pertain to RICE. Realistic modeling analyses that focus on population exposure should be performed to evaluate exposure to formaldehyde. The consolidated engine rule for SI engines will require HCHO control.

C. Economic : This is the best economic solution when the power rating is available and the total emissions for all pollutants meet the requirement. T ypically this is a more economically viable solution than having a rich burn engine with added c ontrols, catalysts and air to fuel ratio.

IV. Background data and assumptions used Since there are no known lean burn engines under 300 hp, engine manufacturers may be interested in developing them. The development of these engines may be the most acceptable solution to users, EPA,Oil & Gas: Engines – Stationary RICE

11/01/07 29 and states. The forthcoming NSPS will encourage e ngine manufacturers to develop lean burn engines under 300 hp.

V. Any uncertainty associated with the option (Low, Medium, High) The uncertainty is not in the lean burn technology bu t in the ability to meet the air emission requirement across all hp ratings (from 25 - 425 hp) and the accepta nce of the final composition of the exhaust gases (including HAPs).

Manufacturers are not unwilling to create new technologies but there is a risk associated with the types of investment returns on technologies developed for small engines.

VI. Level of agreement within the work group for this mitigation option Some believe that after-treatment is the best option. This is acceptable to an engine manufacturer but this option adds cost related to the additional equipm ent needed, permitting and monitoring process. In addition, there is the suspicion that engines with af ter-treatment may be working out of compliance at any one point.

VII. Cross-over issues to the other source groups (please describe the issue and which groups) A study should be conducted on what would achieve the lowest emissions:

• lean burns with no after-treatment

• lean burns with oxidation catalysts and AFRs

• or rich burns with catalysts and AFRs. From the results, select the option th at produces the lowest emissions.Oil & Gas: Engines – Stationary RICE

11/01/07 30 

### Mitigation Option: Interim Emissions Recommendations for Stationary RICE

I. Description of the mitigation option The following mitigation option paper is one of three that were written based on interim recommendations that were developed prior to the conve ning of the Four Corners Air Quality Task Force.

Since the Task Force's work would take 18-24 mont hs to finalize, and during this time oil and gas development could occur at a rapid pace, an Interi m Emissions Workgroup made up of state and federal air quality representatives was formed to develop recommendations for emissions control options associated with oil and gas production and tr ansportation. The Task Force includes these recommendations as part of its compre hensive list of mitigation options.

Require a 2 g/bhp-hr limit on engines less than 300 HP:

• May lead to 60 to 80 percent reduction in NOx.

• Help with visibility impairment in Class I areas in four corners region. Monitoring data at Mesa Verde and Weminuche Class I Areas clearly show s that NOx (NO3) is responsible for a very small fraction of visibility impairment. M odeling studies using the EPA CALPUFF model suggest that NO3 is responsible for visibilit y impairment in the Class I Areas. There are numerous examples that demonstrate that CALPU FF significantly over estimates NO3 visibility impairment compared to monitoring data.

• Several manufacturers offer engines that meet this specification, commercially available in two stroke engines only. Four stroke Lean burn engines capable of meeting 2 g/bhp-hr are not yet commercially available in sizes < 300hp.

• NSCR catalytic reduction can be added at reasonabl e cost. Potential engine durability concerns associated with elevated exhaust temperatures must be addressed when considering reasonable

costs of installation of NSCR.

• Ammonia emissions may increase from use of NSCR catalyst.

• Increased ammonia may or may not affect visibility in the region.

• Without implementation, air quality standards may be exceeded.

Require a 1 g/bhp-hr limit on engines larger than 300 HP:

• Lean burn technology is widely available from manufacturers.

• The lean burn technology will help protect visibility in the region.

• The NAAQS and PSD increments will be less affected.

• Deposition of NOx and related compounds would be reduced Differing Opinion: Analysis of engine quarterly flue gas testing results indicates that, on average, it is possible to achieve an emission lim it of 1 g/hp-hr, however, it may not be possible

to achieve this emission level on a continuous basis.

II. Description of how to implement

These limits should be mandatory for all new and relo cated engines and potentially for existing engines as well. The most appropriate agencies to implem ent this would be the FLMs and the New Mexico, Colorado and Southern Ute environment departments.

Existing fleet has limited compressors that meet these performance criteria. Based on NMAQ Letter of Instruction dated August 2005, <300 hp compressors mu st meet 2g/hp-hr. It should be noted that BLM does not have air quality authority to require any pa rticular emissions performance from engines. This should be implemented through a well crafted minor source permit program administered by the air quality agencies.Oil & Gas: Engines – Stationary RICE

11/01/07 31 Implementation Status for this Mitigation Option BLM in New Mexico is currently requiring compress or engines 300 horsepower or less to have NOx emissions limited to 2 grams per horsepower hour as a Condition of Approval for their Applications for Permit to Drill. Effective August 1, 2005, BLM New Mexico, Farmington Field Office (FFO) started adding to each APD issued on and after this date a Condition of Approval (COA) requiring a limit on NOx emissions if operator placed a compressor on the location. The specific condition language states the following:

This permit is contingent on compliance with the New Mexico Environmental Department, Air Quality Bureau’s directive that compressor engi nes 300 horsepower or less have NOx emissions limited to 2 grams per horsepower hour.

This was based on correspondence received by the NM Air Quality Bureau dated June 3, 2005 and June 5, 2005. The FFO developed the language for the COA, which was reviewed by the NM Air Quality Bureau. The operators are required to comply with this COA regardless of whether it is a newly built compressor or a compressor that they bring in from an other location or their ware yard and regardless of when the operators places the compressor on the location (i.e. six months later or two years later etc.).

BLM and USFS permits in the Northern San Juan Ba sin in Colorado involving new and replacement stationary internal combustion gas field engines requi re the following emission limits, on an interim basis:

• Emission Control (small gas field engines) : All new and replacement internal combustion gas field engines of less than or equal to 300 design-rated horsepower must not emit more than 2 grams of nitrogen oxides (NOx) per horsepower-hour . This requirement does not apply to gas field engines of less than or equal to 40 design-rated horsepower.

• Emission Control (large gas field engines) : All new and replacement internal combustion gas field engines greater than 300 design-rated horsepow er must not emit more than 1.5 gram of NOx per horsepower-hour.

Interim NOx emission requirements for permits on other BLM and USFS lands in southwestern Colorado

have not been established at this time. It is expected that NOx emission requirements will be implemented for these areas in the near future, either as a result of several ongoing planning efforts, or on an interim basis until these planning documents are completed.

Interim NOx emission requirements have not been est ablished for gas field engines on the Southern Ute

Indian Reservation at this time. Discussions between the Southern Ute Indian Tribe, State of Colorado Environmental Commission, US EPA Region 8, BLM and BIA are ongoing, and it is expected that NOx emission requirements will be implemente d for this area in the near future.

III. Feasibility of the Option The feasibility of a 2 g/bhp-hr limit has been demonstr ated and equipment is commercially available. The economic feasibility is acceptable for new engines sin ce the equipment is somewhat more expensive. Economic feasibility is acceptable for many new engines since the equipment is somewhat more expensive. Differing Opinion: A number of new and existing engines cannot accept NSCR due to potential durability concerns associated with elevated exha ust temperatures during the needed stoichiometric operation, especially at low or varying loads. The technical feasibility of a 1 g/bhp-hr limit has b een demonstrated in commercial applications. The environmental benefits are significant. New lean bur n engines can achieve this emission limit with no add-on controls, and rich burn engines can utilize add- on controls to achieve this limit. The cost isOil & Gas: Engines – Stationary RICE

11/01/07 32 acceptable given the large amounts of gas being compressed by these engines. Differing Opinion: The previous statement is subjective a nd unsubstantiated without supporting da ta. Need cost benefit analysis to determine acceptable levels. Only the new generation of lean burn engines are capable of meeting a 1 gram performance and then only with AFRC units and near full load.

IV. Background data and assumptions used The 2 g/bhp-hr limit is based on existing engine tech nology in conjunction with an NSCR catalyst. The assumptions are that these engines are more than 40 HP and less than 300 HP and that they are natural gas fueled. Further, these engines would be operated with an air fuel ratio controller. The technology for the 1 g/bhp-hr engines larger than 300 HP in natural g as is well established. Although the technology is well established, it will not be commercially available for all engines until 2010. There are large engines available that have a vendor guarantee of emissi ons approaching 1 g/hp-hr, however, the issue is maintaining emissions at this level on a continuous basis. The new generation lean burn engines in larger sizes will meet 1 g/bhp-hr performance if equippe d with AFRC units and operated near full load.

V. Any uncertainty associated with the option The uncertainty associated with this option is the potential formation of ammonia emissions as a result of

add-on controls. Ammonia emissions could worsen the air quality in the region. (See ammonia monitoring mitigation option paper.]

VI. Level of agreement within the work group for this mitigation option TBD. Differing Opinion: EPA has proposed a 1.0 g/bhp-hr NOx limit for new SI engines, > 500 hp, built on or after July 1, 2010, and for new SI engines, 26-499 hp, built on or af ter January 1, 2011. While these potential requirements are not expected to be fina lized until December 20, 2007, engine manufacturers have already had to initiate engineering work in an ticipation of this 1.0 gram requirement. Although a number of lean-burn engines can meet this require ment now, EPA chose the effective dates based upon the fact that other lean-burn engines need the add itional time to meet the standards. Cummins has initiated significant work requiring significant res ources to modify those engines to achieve the forthcoming 2.0 g/bhp-hr NOx standard. Cummins be lieves that the incremental benefit offered by a potential pull-ahead of the 1.0 gram standard for larg er engines versus the EPA requirement for 2.0 grams NOx soon to be effective followed by the 1.0 gram sta ndard three years later would likely be difficult to justify. Such a pull-ahead, without sound justifica tion, would undermine the substantial work being done by EPA and engine manufacturers in moving toward a national requirement that is to avoid similar, yet different, requirements.

VII. Cross-over issues to the other source groups The cumulative effects and monitoring groups need to address the concerns with ammonia emissions.Oil & Gas: Engines – Stationary RICE

11/01/07 33 

### Mitigation Option: Next Genera tion Stationary RICE Contro l Technologies – Cooperative Technology Partnerships

This option paper investigates the status of fi ve (1-5) new and/or evolving emissions-control technologies. They are: laser ignition, air-separa tion membranes, rich-burn engine with three-way catalyst, lean-burn NOx catalyst, and Homogeneous-Charge Compression-Ignition (HCCI) Engine.

Laser ignition is under development in the laboratory, but it has not reached a point where technology transfer viability can be determined.

Air separation membranes have been demonstrated in the laboratory, but have not been commercially

available because the membrane ma nufacturers do not have the production capacity for the heavy-duty trucking industry. Since stationary engines are a smaller market, there is a high probability that the membrane manufacturers could ramp up production in this area.

Rich-burn engines with three-way catalysts borrow fro m the well-developed automobile industry. It is applicable to smaller engines for which lean-burn technology is not available.

There are several variations of lean-burn NOx catalysts , but the one of most interest is the NOx trap. NOx traps are being used primarily in European on- road diesel engines, but are expected to become

common in the U.S. as low-sulfur fuel becomes availa ble. Applicability to lean-burn natural-gas engines is possible but it will require a fuel reformer to make use of the natural gas as a reductant.

1. Laser Ignition

I. Description of the mitigation option

Overview Laser ignition replaces the conventional spark plugs with a laser beam that is focused to a point in the combustion chamber. There, the focused, coherent light ionizes the fuel-air mixture to initiate combustion. Applicability is primarily to lean burn engines, although laser ignition could be applied to rich burn engines. Compared to rich-burn engin es, lean burn engines, which are significantly more efficient, require much higher ignition voltage with spark plugs, whereas it takes lower ignition energy with laser system.

Advantages of laser ignition compared to spark plug s include: 1. Longer intervals between shutdowns for

maintenance because wear of the electr odes is eliminated, 2. More cons istent ignition with less misfiring because higher energy is imparted to the ignition kern el, 3. The ability to operate at leaner air-fuel mixtures because higher energy is imparted to the ignition kernel, 4. The ability to operate at higher turbocharger pressure ratio or compression ratio because the laser is not subject to the insulating effect of high-pressure air - air at higher pressure requires a higher voltage to make the spark jump the gap, and, 5. Greater freedom of combustion chamber design because the laser can be focused at the geometric center of the combustion chamber, whereas the spark plug gene rally ignites the mixture near the boundary of the

combustion chamber.

However, laser ignition has some unresolved research i ssues that must be resolved before it can become commercially available. These include: 1. Lasers are into lerant of vibration that is found in the engine's environment. 2. Some means of transmitting the laser light to each combustion chamber should be developed while accommodating relative motion between th e engine and the laser. This might be done with mirrors or with fiber optics. Fiber optics genera lly lead to a simpler solution to the problem. 3. Current fiber optics is limited in the energy flux th ey can transmit. This leads to a less-than-optimum energy density at the focal point. 4. Wear of the fibe r optic due to vibration may limit its lifetime. 5. TheOil & Gas: Engines – Stationary RICE

11/01/07 34 cost of a laser is such that multiple lasers per engine are too expensive. Therefore, a means of distributing the light beam with the correct timing to each cylinder must be developed.

Air Quality and Environmental Benefits Although laser ignition could be applied to rich bur n engines, environmental benefits would accrue to lean burn engines. Air quality and environmental benef its are difficult to quantify at the current state of development. The more consistent ignition compar ed to spark ignition can be expected to decrease emissions of unburned hydrocarbons. The ability to op erate at leaner air-fuel ratios and at higher turbocharging pressure is expected to decre ase emissions of NOx because of lower combustion temperatures. Laser ignition systems have not been developed to the point where the effect of improved combustion chamber design can be measured. It is reasonable to expect that a better combustion chamber design would further decrease emissions of unbur ned hydrocarbons, carbon monoxide, and NOx. In actual operation of the engine, misfiring of one or mo re cylinders contributes to loss in efficiency and increase in emissions. With the laser ignition system, misfiring can be virtually eliminated. It is estimated that with laser ignited lean burn engines, the regulated levels of California Air Resources Board

NOx levels can be met.

Economic The primary advantage of laser ignition is its potentia l to eliminate downtime due to the need to change spark plugs. This advantage would accrue to both rich burn engines and lean burn engines. Higher efficiency due to near elimination of cyli nder misfirings is an additional benefit.

Trade-offs A tradeoff for engine manufacturers, assuming that laser ignition can be developed to the point of commercial feasibility, is whether or not to develop re trofit kits. Retrofits would be expected to take away sales of new engines.

A tradeoff for engine users is whether to continue us ing spark ignition or to pur chase a laser ignition that is initially more expensive but has a future economic benefit.

Another tradeoff for engine users is whether to retrofit laser ignition to an existing engi ne or to spend more money for a new engine in return for future benefits.

II. Description of how to implement

A. Mandatory or voluntary: Implementation should be voluntary because the primary incentive for implementation is economic.

B. Indicate the most appropriate agency(ies) to impl ement: At the current state of development, a research organization is the best agency to develo p laser ignition. After its feasibility is shown, an engine manufacturer, working with an ignition system supplier, is best equipped to carry the development through from product research to a commercial product.

III. Feasibility of the option

A. Technical: The primary technical risks are whethe r sufficiently high light flux can be carried through the fiber optic and whether the fiber optic is sufficiently durable. Laser ignition can be retrofitted to engines that use 18-mm spark plugs.

B. Environmental: If the technical barriers can be overcom e, there is little environmental risk to laser ignition.

C. Economic: If the technical barriers can be overcom e, the economic incentive for its adoption will depend on whether the engine must operate con tinuously or whether downtime can be scheduled to change spark plugs. The requirement for c ontinuous operation favors laser ignition, which is expected to have a higher initial cost than spar k ignition, but which can eliminate most of theOil & Gas: Engines – Stationary RICE

11/01/07 35 downtime for changing spark plugs.

IV. Background data and assumptions used TBD

.

V. Any uncertainty associated with the option (Low, Medium, High) Medium to High

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups (please describe the issue and which groups) TBD

2. Air-Separation Membranes

I. Description of the mitigation option

Overview The purpose of air-separation membranes is to change the proportion of nitrogen to oxygen in air. A membrane can be optimized to either enrich the oxyge n content or to enrich the nitrogen content. Both the oxygen enrichment mode and the nitrogen enrichment mode have been tested in the laboratory with diesel engines. The nitrogen enrichment mode has be en tested in the laboratory with Natural Gas Fuel as well. The oxygen enrichment mode and the nitr ogen enrichment mode are mutually exclusive.

Oxygen enrichment produces a dramatic reduction in pa rticulate emissions at the expense of increased NOx emissions. However, Poola [***ref Poola paper ***] has shown that the effects are non linear such that a small enrichment (1 percentage point or less) produces a significant reduction in particulate emissions with only a small increase in NOx emissions . By retarding the injection timing, one can achieve a reduction in both NOx and particulate emis sions. The overall benefits of oxygen enrichment are relatively small, so it will not be considered further. Nitrogen enrichment produces the same effect on emissions as exhaust-gas recirculation; NOx decreases while particulate emissions increase. Unlike diesel e xhaust, the nitrogen enriched air does not contain particulate matter. Manufacturers of heavy-duty diesel engines are concerned that introducing particulate matter from EGR into the engine may cause excessive w ear of the piston rings and cylinder liner. Thus, nitrogen enriched air is seen as an alternative to EGR. The published data in natural-gas engines show engine-out NOx reductions of 70% are possible with nitrogen-enriched combustion air. [Biruduganti, et al.]

Air Quality and Environmental Benefits Oxygen-enriched air has only been demonstrated in the laboratory to be beneficial with one type of engine that is considered obsolete. Although the r esults are encouraging, further testing with a more modern engine would be necessary to confirm th e decrease in both NOx and particulate emissions.

The development of oxygen-depleted air is furthe r along and has been demons trated as an effective

alternative to EGR.

Economic Use of oxygen-depletion membranes might have a hi gher initial cost than EGR, but would facilitate a longer interval between overhauls. It will have no ad verse impact on engine wear or durability; however, EGR at high levels will have reduced engine durability.

Trade-offs Engine manufacturers are concerned about the abrasive effects of particulate matter on piston rings and cylinder liners and other deleterious effects of EG R [830.pdf]. For the manufacturer the tradeoff isOil & Gas: Engines – Stationary RICE

11/01/07 36 between the initial cost of an oxygen depletion membrane versus the higher frequency of overhauls required with EGR.

II. Description of how to implement

A. Mandatory or voluntary: Implementation should be voluntary because the primary incentive for implementation is economic.

B. Indicate the most appropriate agency(ies) to implement: The engine manufacturer is the appropriate agency to implement air separation membranes because the primary issue is initial cost versus frequency of overhauls.

III. Feasibility of the option A. Technical: The technical feasibility of oxygen-de pletion membranes has been demonstrated as an alternative to EGR. The technical feasibility of oxygen-enrichment membranes has only been shown in the laboratory for one type of engine. The t echnical advantages of nitrogen enrichment with

membranes have been demonstrated in the la boratory for natural gas and diesel engines. B. Environmental: The environmental benefits of oxygen-depletion membranes are the same as

EGR. C. Economic: Membrane manufacturers are presently unable to produce enough membranes for widespread implementation of the technology in truc k engines. However, the oil and gas industry is a smaller market, which might allow the memb rane manufacturers to ramp up their production

levels. Because of this situati on, the economic feasibility of air-separation membranes is difficult to

assess.

IV. Background data and assumptions used www.enginemanufacturers.org/admin/library/upload/830.pdf

Published technical papers by Argon ne National Laboratory and others.

V. Any uncertainty associated with the option (Low, Medium, High) Low to medium. The technology would receive a "l ow" uncertainty rating if the availability issue

were more settled.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups (please describe the issue and which groups) TBD

3. Rich-Burn Engine with Three-Way Catalyst

I. Description of the mitigation option

Overview Rich-burn engines with a three-way catalyst borro w from the well developed automobile technology using the same type of catalyst. Key to efficient opera tion of the catalyst is maintenance of slightly lean of stoichiometric operation of the engine. Typically the exhaust oxygen content is maintained in a narrow range not exceeding 0.5% by means of an oxygen senso r in the exhaust stream and closed-loop feedback control of the fuel flow. The oxygen content is enough to catalytically oxidize carbon monoxide and unburned hydrocarbons as it chemically reduces NOx to mo lecular nitrogen and water. If the engine is operated lean of its desired operating point, NOx reduc tion efficiency drops off dramatically. If operation is rich, emissions of carbon monoxide and unburned hydrocarbons increase.Oil & Gas: Engines – Stationary RICE

11/01/07 37 It is commercially available as a retrofit for smaller en gines. Larger engines are usually operated in the

lean-burn mode.

Air Quality and Environmental Benefits Air quality benefits would be similar to automobiles, where catalytic converters are universally used with rich burn engines.

Economic Cost of three-way catalyst systems is considered high , but less than that of SCR with a lean-burn engine.

Trade-offs For small engines (that is, less than 200 BHP) lean bur n technology may not be available. Where there is a choice of rich-burn or lean-burn engines, the l ean-burn engines offer better fuel economy and more effective, albeit more expensive, overall emi ssions control via SCR and oxidation catalysts.

II. Description of how to implement

A. Mandatory or voluntary: The use of three-way catalysts will be dictated by the stringency of emissions regulations. Three-way catalysts are suffi ciently expensive that they are not likely to be adopted voluntarily.

B. Indicate the most appropriate agency(ies) to implement: U.S. EPA and state agencies

III. Feasibility of the option

A. Technical: The technology is commercially availabl e and has been proven effective. Rich-burn engines have higher engine-out NOx emissions , typically about 10-20 g/BHP-hr [830.pdf and reportoct31.doc], than lean-burn engine have. Th is requires the removal of at least 95% of the

NOx if overall emissions are to be relia bly reduced to less than 1 g/BHP-hr.

B. Environmental: The State of Colorado estimates that a 3-way catalyst can remove 75% of the NOx, unburned hydrocarbons, and carbon monoxide [reportoct31.doc, although manufacturers of equipment claim that 98-99% of these pollutants are removed.

C. Economic: The State of Colorado estimates that the cost of retrofitting a three-way catalyst system to a rich-burn engine over 250 BHP is $35,000 with annual operating costs of $6,000 [reportoct31.doc].

IV. Background data and assumptions used

http://apcd.state.co.us/documents/eac/cd2/reportoct31.doc

www.enginemanufacturers.org/admin/library/upload/830.pdf

V. Any uncertainty associated with the option (Low, Medium, High) Low

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups TBDOil & Gas: Engines – Stationary RICE

11/01/07 38 4. Lean-Burn NOx Catalyst, Including NOx Trap

I. Description of the mitigation option

Overview Lean-burn NOx catalysts have been under development for at least two decades in the laboratory with the intent of producing a lower cost alternative to SCR.

Several variants of lean-burn NOx catalysts have been studied: (1) Passive lean-burn NOx catalysts simply pass the exhaust over a catalyst. The diffi culty has been low NOx c onversion efficiency because the oxygen content of a lean-burn exhaust works against chemical reduction of NOx. Conversion efficiencies of the order of 10% are typical [park.doc.

(2) Active lean-burn NOx catalysts use a fuel as a re ductant. The catalyst d ecomposes the fuel, and the resulting fuel fragments either react with the NOx or oxidize. Methane is much more difficult to decompose than heavier fuels, such as diesel [aardahl.pdf. A wide range of NOx reduction efficiencies from 40% to more than 80% have been published [park. doc and icengine.pdf]. Variants of active leanburn catalyst systems may use plasma or a fuel reformer to produce a more effective reductant than neat fuel [aardahl.pdf, 2003_deer_aardahl.pdf, and 80905199.htm].

(3) NOx trap catalysts are a more recent developm ent that has seen some laboratory success. Operation is a two-step cyclic process. In the first stage th e NOx trap adsorbs NOx while the engine operates in a lean-burn mode. In the second stage, the engine opera tes with excess fuel in the exhaust. The fuel decomposes on the catalyst and reduces the NOx to mol ecular nitrogen and water. When the supply of trapped NOx is exhausted, the system reverts back to first-stage operation. NOx reduction efficiencies in excess of 90% have been published [parks01.pdf. A sophis ticated engine control is required to make this system work.

Air Quality and Environmental Benefits NOx traps have been proven to be effective and have seen some limited commercial success in Europe. NOx traps are one of the reasons for the dramatic reduc tion in sulfur content of diesel fuel in the U.S. Fuel-borne sulfur causes permanent poisoning of NOx-trap catalysts. There are doubts regarding the NOx conversion efficiency levels after 1,000 hours or l onger use. This should be evaluated, as well as the durability of the equipment.

Active lean-NOx catalysts have seen limited commercia l success because they are le ss effective than NOx traps and are not being considered for on-road diesel engines. Some instances of formation of nitrous oxide (N2O) rather than complete re duction of NOx have been reported.

Passive Lean-NOx catalysts do not provide e nough NOx reduction to be considered viable.

Economic Costs of retrofitting a lean-burn NOx catalyst are estimated at $6,500 to $10,000 per engine [retropotentialtech.htm], $15,000-$20,000 including a diesel particulate filter [V2-S4_Final_11-18- 05.pdf] for off-road trucks. Estimates are $10-$2 0/BHP for stationary engines [icengine.pdf].

Little information on the cost of NOx-trap cataly tic systems was found. The overall complexity of a NOx-trap system is only slightly more than that of a lean-burn NOx catalyst, so costs can be expected to be slightly higher. With methane-burning engines, both active lean-burn NOx catalysts and NOx-trap catalysts require a fuel reformer or other means of dissociating methane. This will add an increment of

cost.Oil & Gas: Engines – Stationary RICE

11/01/07 39 Both active lean-NOx technology and NOx-trap technology impose a fuel penalty of 3-7%.

Trade-offs NOx-trap systems compete with SCR systems. For meth ane-burning engines, a fuel reformer is required for NOx-trap systems. Fuel reformers are less well developed.

If emissions regulations can tolerate higher NOx em issions, an active lean-burn NOx catalyst might be

considered.

I. Description of how to implement

A. Mandatory or voluntary: The costs of lean-bur n NOx catalysts and NOx traps are such than voluntary compliance is unlikely. However, depe nding on the strictness of the regulations, the user may have a choice of systems.

B. Indicate the most appropriate agency(ies) to implement: U.S. EPA and state agencies.

II. Feasibility of the option

A. Technical: NOx-trap systems are proven and commercially available for diesel engines. However, they require low-sulfur diesel fuel (less than 15 ppm) to minimize sulfur poisoning of the catalyst. Active lean-burn catalysts are av ailable, but they have a lower NOx reduction efficiency than NOx-trap systems have. Both the lean-burn NOx catalyst and the NOx trap requires a fuel reformer (which can be a catalyst stage upstream of the NOx catalyst) to operate at full efficiency with natural-gas fueled engine.

B. Environmental: Lean-burn NOx catalysts and NOx-trap catalysts do not have the ammonia slip issue that SCR systems have, but lean-burn NOx catalysts may only partially reduce some of the NOx to nitrous oxide (N2O). The NOx reduction e fficiency of NOx traps is similar to that of SCR systems (>90%), but active lean-burn NOx catalysts have a lower efficiency (40-80%).

C. Economic: Lean-burn NOx catalysts and NOx traps have lower costs than SCR and they avoid the need to purchase and maintain a separate re ductant. However, both lean-burn NOx catalysts and NOx traps impose a fuel consumption penalty of 3-7%.

III. Background data and assumptions used Abstract of Caterpillar paper found at www.emsl.pnl.gov/new/emsl2002/abstracts/park.doc

. www.meca.org.galleries/default-file/icengine.pdf

www.energetics.com/meetings/recip05/pdfs/presentations/aardahl.pdf

www.eere.energy.gov/vehiclesandfuels/pdf s/deer_2003/session10/2003_deer_aardahl.pdf

www.swri.org/epubs/IRD1999/08905199.htm

www.feerc.ornl.gov/publications/parks01.shtml

www.epa.gov/oms/retrofit/retropotentialtech.htm

www.wrapair.org/forums/msf/projects/offroad_diesel_retrofit/V2-S4_Final_11-18-05.pdf

IV. Background data and assumptions used None

V. Any uncertainty associated with the option (Low, Medium, High) NOx traps have a low uncertainty if they are used with low sulfur diesel fuel. They have a medium uncertainty when used with natural gas because of the need to reform the fuel.

Lean-burn NOx catalysts have a medium uncertainty because they may not be able to meet future emissions regulations.Oil & Gas: Engines – Stationary RICE

11/01/07 40 VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups To be determined. The issue of incomplete NOx re duction that leaves some nitrous oxide (N2O) may be moot if active lean-burn NOx catalysts cannot meet future emissions regulations.

5. Homogeneous-Charge Compression-Ignition (HCCI) Engine

I. Description of the mitigation option

Overview

Homogeneous charge compression ignition (HCCI) engines are under development at several laboratories. In these engines a fully mixed charge of air and fuel is compressed until the heat of compression ignites it. The HCCI combustion process is unique since it proceeds uniformly throughout the entire cylinder rather than having a discreet high-temperature flame front as is the case with spark ignition or diesel engines. The low-temperature co mbustion of HCCI produces extremely low levels of NOx. The challenge of HCCI is in achieving the corr ect ignition timing, although progress is being made

in the laboratories. 1

Only a few experimental measurements of NOx from (HCCI) engines have been reported. The measurements are typically reported as a raw NOx me ter measurement in parts per million rather than being converted to grams per horsepower-hour. Dibb le reported a baseline measurement of 5 ppm when operated on natural gas. 2 Green reported NOx emissions from HCCI-like (not true HCCI) combustion of 0.25 g/hp-hr. 3 The achievable NOx emission levels are yet to be determined. It is not currently known if HCCI technology can be applied to all engine types an d sizes. However, if all reciprocating engines could be converted to HCCI so that the engines produ ce no more than 0.25 g/hp-hr, then the overall NOx

emissions reduction would be 80% in both Colorado and New Mexico using the calculation methodology of the SCR mitigation option.

II. Description of how to implement

A. Mandatory or voluntary: It is too early to de termine whether implementation of this technology will be voluntary or mandatory. B. Indicate the most appropriate agencies to implement

III. Feasibility of the option

A. Technical: HCCI is in the laboratory stage of development.

B. Environmental: HCCI has the potential of extremely low NOx levels.

C. Economic: HCCI is not sufficiently deve loped to have proven economic feasibility.

IV. Background data and assumptions used

1. Bengt Johansson, "Homogeneous-C harge Compression-Ignition: The Future of IC Engines," Lund Institute of Technology at Lund University, undated manuscript.

2. Robert Dibble, et al, "Landfill Gas Fueled HCCI Demonstration System," CA CEC Grant No: PIR-02- 003, Markel Engineering Inc.Oil & Gas: Engines – Stationary RICE

11/01/07 41 3. Johney Green, Jr., "Novel Combustion Regimes fo r Higher Efficiency and Lower Emissions," Oak Ridge National Laboratory, "Brown Bag" Luncheon Series, December 16, 2002.

V. Any uncertainty associated with the option (Low, Medium, or High)

HCCI has high uncertainty.

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to the other source groups (Please describe the issue and which group.)

Summary Five technologies are reported: laser ignition, air-sep aration membranes, rich-burn engine with three-way catalyst, lean-burn NOx catalyst, and Homogeneous-Charge Compression-Ignition (HCCI) Engine.

Laser ignition is not presently a commercial product. Th e impetus for investigating it is the potential to eliminate the need for changing spark plugs. It will also allow operation at leaner air-fuel ratios, higher compression ratios, and higher turbocharging pressure. Leaner air-fuel ratios imply lower engine-out

NOx emissions so the after treatment can be sma ller or can give lower overall emissions. Higher compression ratios and turbocharging ratios imply higher engine efficiency.

Air-separation membranes used to deplete oxygen from the combustion air can serve as a clean replacement for EGR. That is, an engine using oxy gen-depleted air would not be ingesting combustion products. Engine manufacturers are concerned that EGR will shorten the life of their engines and lead to premature overhauls and warranty repairs. The technol ogy has been demonstrated in the laboratory, but has not been used for heavy-duty trucks because membrane manufactu rers do not have enough production capacity for the market. Stationary engines are a sm aller market, so the membrane manufacturers may be able to ramp up their capacity with stationary engine s. Applicability is to diesel engines and rich-burn natural-gas engines. Oxygen-depletion membranes ha ve not been tested with lean-burn natural-gas engines.

A rich-burn engine with a three-way catalyst is a mature technology that is borrowed from automobile engines. The three-way catalyst effectively control NOx, unburned hydrocarbon, and carbon monoxide emissions. It requires an exhaust oxygen sensor with a closed-loop control of the fuel so that exhaust oxygen is maintained in a narrow range not exceeding 0.5%. It can be retrofitted to existing engines and is primarily applicable to small engines for which lean-burn combustion is not available. Its primary disadvantages are cost and the inherently lower effici ency of rich-burn engines compared to lean-burn engines.

Lean-burn NOx catalysts have several forms, but the one that is of most interest is the NOx-trap catalyst. Unlike SCR, lean-burn NOx catalysts use the engine's fuel as a reductant and do not require a separate supply of reductant. It is a well proven in the la boratory and is commercially available in Europe for diesel engines, but it requires a fuel reformer if na tural gas is used as the reductant. A sophisticated control system is required to cycle the engine between its two modes of operation. Ammonia slippage is not an issue with NOx traps, and if there is any s lippage of unburned fuel it can be removed with an oxidation catalyst. Cost is high but less than that of SCR systems. A disadvantage of NOx traps is that they are intolerant of fuel-borne sulfur. For diesel fuel, the sulfur content must be less than 15 ppm. Fuel-borne sulfur permanently poisons the catalyst. Since fuel is used as a reductant, there is a fuel consumption penalty of 3-7%.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 42 

### ENGINES: MOBILE/NON-ROAD

Mitigation Option: Fugitive Du st Control Plans for Dirt/Gravel Road and Land Clearing

I. Description of the mitigation option Fugitive dust emissions from traffic on dirt roads a nd construction sites are a nuisance and cause frequent complaints. Health concerns related to PM 10 (par ticulate matter less than 10 microns in size) exposure to high concentrations are breathing, aggravated existing respiratory and cardiovascular disease, lung damage, asthma, chronic bronchitis, and other health problems. Adequate measures could include wind breaks and barriers, water or chemical applications, control of vehicle access, vehicle speed restrictions, gravel or surfacing material use, and work stoppa ge when winds exceed 20 miles per hour. Activities occurring near sensitive and/or populated areas should receive a higher level of preventive planning. Sensitive receptors would include schools, housing, and business areas.

Economic burdens include increase business costs associat ed with increased road maintenance, loss of time and productivity associated with work stoppage during high wind days, and increased travel times due to speed restrictions. However, reduced w ear on roads and vehicles may be recognized through vehicle speed restrictions.

II. Description of how to implement A. Mandatory or voluntary: Speed restrictions, regular road maintenance, and construction activity restrictions during high wind days would be mandato ry. Road surfacing, wind breaks and barriers and vehicle access control would be voluntary. B. Indicate the most appropriate agency (ies) to implement: The states, tribal governments, BLM, FS, County, and Industry.

III. Feasibility of the option

A. Technical: The current BLM Road committee is a functi onal working group with 13 road maintenance units. An industry representative is assigned to each unit to oversee road construction and maintenance activities through a cost-sharing program. BLM law enforcement along with county and state law enforcement could enforce speed restrictions. In dustry could make observing speed limits a company policy. Conditions of approval c ould be added to permitted activities to restrict surface disturbing activities during high wind days. However, industry would prefer the use of other mitigation measures such as road surface treatments (e.g. fresh water or special emulsion) during high wind days.

B. Environmental: The environmental benefits from regul ar and proper road maintenance, speed restrictions, and surface disturbing activities during high wind days are well documented.

C. Economic: Cost sharing is an important purpose of the current roads committee that is very active and functional work group with regularly scheduled meeti ngs. Funding for speed enforcement is an intricate part and regularly funded operation of BL M, county and state law enforcement.

IV. Background data and assumptions used 1. BLM Gold Book-Surface Operating Standards fo r Oil and Gas Exploration and Development.

2. Numerous studies on road related erosion issues and standards exist. 3. Studies on excessive road speed and dust development.

V. Any uncertainty associated with the option (Low, Medium, High) LowOil & Gas: Engines – Mobile/Non-Road

11/01/07 43 VI. Level of agreement within the work group for this mitigation option Four member drafting team support this option

VII. Cross-over issues to the other source groups None at this time.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 44 

### Mitigation Option: Use Produ ced Water for Dust Reduction

I. Description of the mitigation option

This option involves using produced water on roads for dust suppression. Large volumes of water are often produced in conjunction with natural gas production, especially coal bed methane (CBM) production. Wells often produce up to 100-400 barrels/day. CBM produced water quality ranges from nearly fresh water to well above 10,000 ppm total di ssolved solids (TDS) and is readily available as an option for road dust suppression. The produced water used for dust mitigation would have to have low

TDS and low sodium levels that meet BLM and county standards. Some CBM water meets these

standards but not all of it.

Economic benefits could be realized by oil and gas ope rators in reduced trucking and disposal costs. Likewise, there are associated environmental benefits to this reduced trucking as is outlined in another mitigation strategy. However, the use would be as needed and seasonal (during prolonged dry periods or drought).

Environmental concerns and issues would arise concer ning 1) salt build up along roadways, 2) migration of water and associated pollutants off the roadway, 3) impacts to vegetations, 4) salt loading to river

systems.

Differing Opinion: Produced water in the Four Corners regi on contains toxins and therefore should not be used for dust mitigation. The potential environm ental concerns include more than just salt-related impacts. Produced waters are of variable quality. Depending on the source, the water may contain high

concentrations of constituents other than salts. Data on produced wate r quality is not widely available to the public. One example of produced water quality, ho wever, was published in a recent report prepared with support from the U.S. Department of Energy. The data show that in the New Mexico portion of the San Juan Basin, there can be elevated concentrations of various metals and othe r constituents in produced water (in addition to elevated salts – those data not shown). 1

McGrath

SWD 2 Four CBM injection wells 3
All values in mg/L Max Min Max Min

Barium 8.0 0.72 23.9 1.86

Boron 3.0 1.0 2.87 1.6

Bromium 21.8 7.1 15.2 2.4 Copper 0.019 ND

Chromium 0.035 ND 0.005 Iron (dissolved) 4 187 1.1 0.843 0

Selenium 0.080 ND 0.0171 ND

1 DiFilippo, Michael N. August, 2004. Use of Produc ed Water in Recirculating Cooling Systems at Power Generating Facilities. Semi-Annual Technical Progress Re port October 1, 2003 to March 31, 2004. Report produced with support from U.S. Department of Energy, Award No. DE-FC26-03NT41906. pp. 12-3.

2 McGrath Saltwater Disposal Well (SWD): data were from a 30 day random sampling of the SWD well), which was operated by Burlington (now, presumably Conoco).

3 CBM SWD wells operated by Dugan (Salty Dog 2 and 3 Injection Wells) and Richardson (Turk’s Toast and Locke Taber Injection Wells).

4 According to DiFilippo (page 10), mo st of the iron comes from aboveground carbon steel pipe used to convey produced water. So, presumably, if water were applied from trucks getting water from the well site, itself, this would not be a concern. If it were water being loaded at the SWD facility, then the iron would be present.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 45

Silver 0.20 ND

Strontium 55 7.2 34.5 1.73

Lead 0.031 ND 0.1

Total Petroleum Hydrocarbons (TPH) 520 23 17 ND

Zinc 0.298 ND

* ND is non-detected

Produced water may also contain chemical additiv es put downhole during the drilling, stimulation or

workover of the wells. Some of these treatment chemical s, such as biocides, can be lethal to aquatic life at levels as low as 0.1 part per million. 5 It is very difficult to obtain information on the concentrations of treatment chemicals and additives in produced water.

Environmental Justice Issues: Only with the permi ssion of surface owners, municipalities, counties, etc. should produced water be applied to roads. And these entities should be provided with produced water quality information prior to road spreading.

Wyoming requires landowner consent prior to road spread ing, which is an important provision to ensure that surface owners have a say in the application of large quantities of water that could affect their property. In Pennsylvania, other jurisdictions, such as municipalities, also have a say with respect to whether or not road spreading is allowed. 6

II. Description of how to implement

A. Mandatory or voluntary: The use of produced water would be voluntary; however, ultimate approval to do so would be up to the state authority that has primacy over the disposal and use of produced water. B. Indicate the most appropriate agency(ies) to implement: OCD, BLM, FS.

It may also be necessary to include the states in the implementation of any permitting process related to road spreading since these agencies ha ve the expertise and develop the e nvironmental standards related to surface and groundwater pollution. There is a preceden t for involving environment departments. In Wyoming, although the Oil Conservation Commissi on is responsible for permitting road spreading applications, the operations must also be approve d by their Department of Environmental Quality. 7

III. Feasibility of option

A. Technical: This option is technically feasible, but w ould require strict controls and monitoring. “Because of the potential for contaminants from the brine to leach into surface or ground waters, the Department of Environmental Protection (DEP) has developed guidelines that must be followed when spreading brine on unpaved roads.” 8 It would be advisable for the responsible agencies to develop their

5 Argonne National Laboratory. January, 2004. A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas and Coalbed Methane. Prepared for U.S. Department of Energy. Contract No. W-31-109- Eng-38.

6 http://www.dep.state.pa.us/dep/d eputate/minres/oilgas/fs1801.htm

7 Rules and Regulations of the Wyoming Oil and Gas Conservation Commission Chapter 4, Section 1 http ://www.cbmcc.vcn.com/dust.htm “(nn) Landfarming and landspreading must be approved by the DEQ. Jurisdiction over roadspreading or road application is shared by DEQ and the Commission. . .”

8 http://www.dep.state.pa.us/dep/d eputate/minres/oilgas/fs1801.htmOil & Gas: Engines – Mobile/Non-Road

11/01/07 46 own guidelines or policies to ensure that road spread ing practices are carried out in an environmentally

sound manner.

B. Environmental: Would require constraints on the allowabl e TDS and/or SAR content of the water and volumes applied. Baseline field testing for migrati on/movement would be requi red to determine if salt build-up is occurring. The use of boom type sprayer (i.e. spreader bars) to prevent pooling and washing off of roadway needs to be highly considered. A r esponsible party on site dur ing application would be necessary and signage indicating road maintenance being conducted.

Most jurisdictions that allow road spreading do not require chemical data on anything but the salts or dissolved solids (TDS). While TDS includes constitu ents such as dissolved metals, it does not provide any specific information as to the concentrations of the various metals. Basing the acceptability of using produced water for road spreading on salt content or TDS overlooks the potential impacts from other produced water constituents like metals, hydrocar bons, treatment chemicals and radionuclides (e.g., strontium).

Prior to application of produced water for road sp reading purposes, it would be prudent to analyze the water for all potentially harmful constituents. In 20 00, there was a case in Garfield County, CO, where a company illegally spread flowback fluids from a wo rkover operation. Samples of the produced water subsequently showed that TDS levels and B TEX were above state drinking water standards. 9

Prohibit spreading of flowback water. In Pennsylvani a, operators are not allowed to spread produced

water that main contain treatment chemicals. “Onl y production or treated brines may be used. The use of drilling, fracing, or plugging fluids or production br ines mixed with well servicing or treatment fluids, except surfactants, is prohibited. Free oil must be se parated from the brine before spreading.” Essentially, this would mean that the operator would have to wait a certain period of time to allow the majority of the

treatment chemicals to flow out of the well before using the produced water for road spreading purposes.

C. Economic: Some operators may see a reduction in ha uling and trucking cost associated using produced water for dust control.

IV. Background data and assumptions used 1. Currently produced water is used in some areas fo r road reconstruction and maintenance, but not for

dust reduction. Current levels allowed are 5,000 TDS for maintenance and 18,000 TDS for

reconstruction. 2. Could consider higher TDS levels of use with ti ght restriction on applications methods and timing. 3. Assume applications would be seasonal (during summer dry months)

4. Restricted to main collector road or on all roads with high traffic flow. 5. Need to protect operator’s invest ment for roadwork already completed.

V. Any uncertainty associated with the option (Low, Medium, High) Medium uncertainty to environmen t (water quality and vegetation).

VI. Level of agreement within the work group for this mitigation option. All members of drafting team support this option.

VII. Cross-over issues to other source groups None at this time.

9 Colorado Oil and Gas Information System. 7/6/2000. Notice of Alleged Violation Report. Barrett Resourced Corp. Document No. 850224. http://oil-gas.state.co.us/cogis/NOAVReport.asp?doc_num=850224Oil & Gas: Engines – Mobile/Non-Road

11/01/07 47 

### Mitigation Option: Pave Roads to Mitigate Dust

I. Description of the mitigation option This option involves paving roads that service the vast amounts of oil and gas locations in the four corners region. The benefits to air quality would be a significant reduction in dust generated by traffic in the San Juan Basin. Consideration should be given to paving only those collector roads that are located near populated areas and those that received heavy tr affic and excessive dust because of high cost of paving. Currently a pilot project is being propo sed to use hot emulsified asphalt on reconstructed collector roads. The hot asphalt would be incorpora ting it into the sandstone caps material using a road re-claimer or blade in an effort to create a durable driving surface.

Economic burdens would be extreme costs to oil and gas operators, federal, state and local governments associated with paving and maintaining a vast network of roads in the San Juan Basin. There would be

an immediate increase in traffic accidents associated with an eminent increase in speed associated with paved roads.

II. Description of how to implement A. Mandatory or voluntary: The construction and road base prepara tion necessary to properly pave a road would be voluntary B. Indicate the most appropriate agency(ies) to implement: Industry, OCD, BLM, FS, County, State.

III. Feasibility of option

A. Technical: This option is technically feasible but not prac tical to pave all roads. Consideration needs to be given to highly travel collector roads and road near heavily populated areas. Portions of heavily travel roads could be considered for paving.

B. Environmental: Would reduce long term dust emissions from vehicle traffic throughout the San Juan

Basin but there would be some shorter term incre ases in emissions associated with asphalt production, paving, and the construction equipment paving the road itself. However, increase accidents and speeding

could be drawbacks. Additional law enforcement would be required or re-prioritized workload to curtail speeding.

C. Economic: The cost to prepare, pave, and maintain roads throughout the San Juan Basin are not practical on all roads. Furthermore, the cost to r eclaim “paved roads” as part of the restoration process upon well abandonment would be substa ntial. Consideration could be give to paving only portions of main collector roads, especially in p opulated areas with heavy traffic.

IV. Background data and assumptions used 1. Pilot project currently proposed. Need to evaluate the effectiveness of using hot emulsified asphalt. Not practical to pave all roads in the San Juan Basin.

2. Restricted to main collector road with h eavy traffic, dust problems, and populated areas. 3. Would require addition capital outlay and cost sharing.

V. Any uncertainty associated with the option (Low, Medium, High) High, due to cost and feasibility.

VI. Level of agreement within the work group for this mitigation option. Members agree that this option has some merit but in limited areas. Not practical to consider the entire

San Juan Basin.

VII. Cross-over issues to other source groups None at this time.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 48 

### Mitigation Option: Automation of Wells to Reduce Truck Traffic

I. Description of the mitigation option This mitigation option would involve equipping wells with a variety of technology for the ultimate purpose of being able to decrease traffic to well sites when everything is operating normally. The potential air quality benefits include reduced dust an d tailpipe emissions from vehicle traffic. Other potential environmental benefits incl ude reduced vehicular fuel consumption (and therefore the need for crude oil feedstocks). Economically, the energy co mpanies could benefit by reducing their workforces and the expenses paid for contractors. As this automation may require the electrification of the equipment, the air quality benefits may be offset by emissions elsewhere and of a different nature. Costs for implementing this option may entail the installation of massive electrification systems to power the sensors, radios, and automated valves (vista issues). Additionally, should every well not be checked on a daily basis, there is believed to be a high likelihoo d that leaks small enough to be undetectable by the automation sensors could go on unabated until the next time the well was visited. This would represent a real tradeoff of risk (air quality vs. soil / water im pact). Significant burden would fall on the operator in such a situation. An additional benefit of this opti on is that once electricity is available at the site, it would increase the feasibility of the electric comp ressor option included under Stationary RICE.

II. Description of how to implement The oil & gas industry already uses automation technol ogy where technically and economically feasible. Therefore, this mitigation option would best be im plemented in a voluntary manner. As such, agency involvement would not be required.

III. Feasibility of the option

A. Technical : The technology exists today to implement this mitigation option.

B. Environmental : A study would need to be made to determin e the relative benefit of reducing emissions at the well site but increasing emissions during electri fication and offsite power generation. (Cumulative Effects Work Group task?)

C. Economic : In some cases the implementation of this t echnology is economically feasible. In many others it is not. Forced implemen tation could very well hasten the uneconomic status of a well resulting in the premature abandonment of the well and its hydrocarbon products.

IV. Background data and assumptions used

While EPA does have AP-42 emission factor data available for unpaved roads (13.2.2), no input

information was available in the time frame desired to make any calculations / determinations, hence the high-level and qualitative analysis. (C umulative Effects Work Group task?)

V. Any uncertainty associated with the option High. The feasibility of implementing this option is very situation specific. It is believed that widespread implementation (75% of wells) is probably not feasible.

VI. Level of agreement within the work group for this mitigation option Subgroup is in agreement with this option.

Cross-over issues to the other source groups

None at this time.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 49 

### Mitigation Option: Reduced Vehicular Dust Production by Enforcing Speed Limits

I. Description of the mitigation option

This mitigation option would involve enforcing speed limits on unpaved roads in an attempt to reduce dust emissions. The potential air quality benefits include reduced dust emissions from slowed vehicle traffic. Another potential environmental benefit (alb eit marginal) is reduced vehicular fuel consumption (and therefore the need for crude oil feedstocks). Economically, although theoretically less work would be accomplished in the same time period, this imp act would be insignificant since the degree of excess over the speed limit is probably not such that implem entation of this mitigation strategy would make a significant difference.

A. Public Roads : Enforcement on public roads would be most easily accomplished using local law enforcement agencies. Costs for stepping up enfo rcement of the speed limits on public roads might

include additional funds for increased staff for the local law enforcement agencies.

B. Private Roads : To the extent the unpaved roads are priv ate, the setting and enforcing of speed limits would have to take place in a cooperative agreement between local landowners and energy companies. Since energy companies are not staffed, trained or equipped to be law enforcement agents, this would represent a significant cost shift to the energy compan ies. Costs for implementing this option on private roads would entail legal review to understand on what basis such” private law enforcement” could take place, the negotiating of agreements with landowners, the posting of signs, and the staffing, training, and equipping of workers to fulfill this function.

C. Assistance : Cumulative Effects work group would be n eeded to understand the relative benefit of reduced speed on dust production.

II. Description of how to implement

A. On public unpaved roads, enforcem ent of existing speed limits could be seen as mandatory. The most appropriate agencies to implement are the existing local law enforcement agencies.

B. On private roads, implementation would have to be voluntary as no agency can force a landowner to undertake such a proposition. It is not appropriate for any agencies to get involved in the implementation of this mitigation option. It would be most a ppropriate for the environmental agencies to simply recognize this as a bona fide emission reduction strate gy, and then let the energy company determine where and when to implement such a strategy.

III. Feasibility of the option

A. Technical – Greater enforcement of speed limits on public unpaved roads would be feasible. Establishing and enforcing speed limits on priv ate unpaved roads is feasible but less so.

B. Environmental - Assistance from the Cumulative Effects work group would be needed to understand the relative benefit of reduced speed on dust production (how much reduction in speed is needed to have a significant reduction of dust?).

C. Economic - Assistance from the Cumulative Effects work group would be needed to understand the relative economic benefit of reduced speed on dust production.

D. Public Perception – This could be an issue based on the assumption that most people would want any additional funding for police activities to go toward safety/crime issues.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 50 IV. Background data and assumptions used

While EPA does have AP-42 emission factor data available for unpaved roads (13.2.2), no input

information was available in the time frame desired to make any calculations / determinations. Hence the high-level and qualitative analysis in this option pa per. The governing equations do however include speed as a component.

V. Any uncertainty associated with the option High. Assistance from the Cumulative Effects work group would be needed to understand the relative economic benefit of reduced speed on dust production. Once that is understood, an analysis could be made to reduce the economic and regulatory un certainty associated with this option.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups It is believed that this issue will cross-over to the Other Sources group.

Could the issue described in IV above be addr essed by the Cumulative E ffects work group?Oil & Gas: Engines – Mobile/Non-Road

11/01/07 51 

### Mitigation Option: Reduced Truck Traffic by Centralizing Produced Water Storage

Facilities

I. Description of the mitigation option

This mitigation option would involve reducing ve hicular traffic on unpaved roads (and hence dust production) by centralizing produced water storage fa cilities and pumping water to them. Much of the large truck traffic on unpaved lease roads is water hauler s. Therefore, one strategy to reduce dust is to reduce water hauler traffic. However, unless the produ ced water could be piped directly to the disposal (injection well) location, the same volume of truck tra ffic would exist. Therefore, to reap the benefits from this strategy, it would be necessary to either pipe th e water directly to the disposal location, or to site the centralized produced water storage facility along a paved road such that the water transporters would not be driving on unpaved roads and creating dust.

Benefits from this strategy include dust reduction, vehicle tailpipe exhaust emission reduction (potential), reduced road maintenance, and marginally safer ro ads. Burdens would fall exclusively on the energy companies. These burdens would include obtaining right s-of-way to lay the need ed pipelines, securing the pipe, securing trenching and installation services, and pa ying crews to make the necessary tie-ins. As much of the produced water in southern Colorado is essentially fresh in nature, heat tracing may be needed to prevent the freezing and bursting of pipes.

Tradeoffs would include the pollutants emitted at the source of the power used to drive the transfer pumps. This power production could be either at the we ll location (natural gas fired) or at the power plant (electric). Additionally, the dust emissions are current ly dispersed over a large area. Centralizing storage would greatly increase tailpipe emissions locally and potentially produce local air quality, noise, and traffic safety issues. Additionally, aggregating produc ed water in one location increases the potential for a catastrophic release. This would represent a real tradeoff of risk (air quality vs. soil / water impact). Additional tradeoffs include the emissions produced at the point of pipe manufacture and the emissions from the trenching operations. Assistance is needed from the Cumulative Effects work group to estimate the net air quality gain from centralizin g produced water storage facilities.

II. Description of how to implement

A. This mitigation option should be implemented on a voluntary basis. Forced implementation could hasten the uneconomic status of groups of wells r esulting in premature abandonment of the wells and their hydrocarbon products.

B. The most appropriate agency to implement would be the environmental agency through permitting incentives/offsets. It would be necessary to first u nderstand the relative benef it of reducing emissions from lease road traffic but increasing emissions el sewhere (Cumulative Effects Work Group task).

III. Feasibility of the option

A. Technical : The technology exists today to implement this mitigation option.

B. Environmental : A study would need to be made to determin e the relative benefit of reducing emissions from lease road traffic but increasing emissions el sewhere (Cumulative Effects Work Group task).

C. Economic : In some cases the implementation of this technology will be economically feasible. In many others it will not be.

IV. Background data and assumptions used : While EPA does have AP-42 emission factor data available for unpaved roads (13.2.2), no input

information was available in the time frame desired to make any calculations / determinations. Hence the high-level and qualitative analysis. This coul d be a Cumulative Effects Work Group task.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 52 V. Any uncertainty associated with the option (Low, Medium, High): High. Assistance from the Cumulative Effects work group would be needed to understand the relative

economic benefit of reduced truck tr affic vs. laying miles of pipelines and setting many pumps. Once that is understood, an analysis could be made to redu ce the economic and regulatory uncertainty associated with this option.

VI. Level of agreement within the work group for this mitigation option

V. Cross-over issues to the other source groups

It is believed that this issue will not cross-over to any other source work group. Assistance from the Cumulative Effects work group on the issue in V. above would be helpful.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 53 

### Mitigation Option: Reduced Vehicular Dust Pr oduction by Covering Lease Roads with

Rock or Gravel

I. Description of the mitigation option This mitigation option would involve reducing vehicu lar dust production by covering unpaved roads with rock or gravel. Benefits from this strategy includ e only dust reduction. Burdens would fall exclusively on the energy companies. These burdens would include obtaining the road material and paying crews to install it. Additionally, the presence of rock on the ro ads makes snow removal more difficult, and is hard on snow removal equipment. Therefore, road main tenance costs may increase during the winter months. Tradeoffs would include the pollutants emitted during the trucking and installation of the road material.

Assistance is needed from the Cumulative Effects wo rk group to estimate the net air quality gain from centralizing produced water storage facilities.

II. Description of how to implement A. This mitigation option should be implemented on a voluntary basis. Forced implementation could hasten the uneconomic status of groups of wells r esulting in premature abandonment of the wells and their hydrocarbon products.

B. The most appropriate agency to implement w ould be the environmental agency through permitting incentives/offsets. It would be necessary to first understand the relative e nvironmental benefit of covering roads with rock (Cumulative Effects Work Group task).

III. Feasibility of the option Technical – The technology exists today to implement this mitigation option.

Environmental – A study would need to be made to determine the relative em ission reductions due to covering the roads with rock (Cumulative Effects Work Group task).

Economic – In some cases the implementation of this t echnology will be economically feasible. In others

it will not be.

IV. Background data and assumptions used

While EPA does have AP-42 emission factor data available for unpaved roads (13.2.2), no input

information was available in the time frame desired to make any calculations / determinations. Hence the high-level and qualitative analysis. (C umulative Effects Work Group task?)

V. Any uncertainty associated with the option (Low, Medium, High) High. Assistance from the Cumulative Effects work group would be needed to understand the relative emission reduction benefit from covering lease roads with rock. Once that is understood, an analysis could be made to reduce the economic and regulat ory uncertainty associated with this option.

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to the other source gro ups (please describe the issue and which groups It is believed that this issue may cross-over to the Other Sources work group.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 54 

### Mitigation Option: Reduced Truck Traffic by Efficiently Routing Produced Water Disposal Trucks

I. Description of the mitigation option This mitigation option would involve setting up a produ ced water hauler coordinating / dispatch service to route water haulers as efficiently as possible in orde r to reducing vehicular tr affic on unpaved roads (and hence dust production). Much of the large truck tr affic on unpaved lease roads is water haulers. Therefore, one strategy to reduce dust is to minimize water hauler traffic. To accomplish this goal, it would be necessary institute a central dispatch concept among all of the water haulers in the area such that (a) only full truckloads are hauled from a given area a nd (b) the water is hauled to the closest disposal facility possible. Benefits from this strategy incl ude dust reduction, vehicle tailpipe exhaust emission reduction, and reduced vehicular fuel consumption (a nd therefore the need for crude oil feedstocks). Burdens would fall both on the water hauling service co mpanies and on the water disposal companies. These burdens would include agreements to cooperate (which would include the setting of prices), the purchase of compatible radio equipment, and the impl ementation of a central dispatch facility. There would be no tradeoffs associated with this strategy . Assistance is needed from the Cumulative Effects work group to estimate the net air quality gain from optimizing produced water hauling routes.

II. Description of how to implement This mitigation option could be implemented on a mandatory basis. In order to set fair prices on water hauling and disposal (like taxi cabs), it would be necessary to involve other agencies and potentially special legislation.

The most appropriate agency to implement would be the states’ regulatory entity for the oil and gas industry

. It would be necessary to first understand the relative benefit of reducing emissions from lease road traffic due to optimization (Cumulative Effects Work Group task).

III. Feasibility of the option Technical – The technology exists today to implement this mitigation option.

Environmental – A study would need to be made to determine the relative bene fit of reducing emissions from lease road traffic due to optimizati on (Cumulative Effects Work Group task).

Economic – Implementation of this technolog y should be economically feasible.

IV. Background data and assumptions used No input information was available in the time frame desired to make any calculations / determinations. Hence the high-level and qualitative analysis. This could be a Cumulative Effects Work Group task.

V. Any uncertainty associated with the option (Low, Medium, High)

Low. Assistance from the Cumulative Effects work group would be needed to understand the relative environmental benefit of optimized truck traffic. On ce that is understood, an analysis could be made to reduce the economic and regulatory uncerta inty associated with this option.

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to the other source gro ups (please describe the issue and which groups

It is believed that this issue will not cr oss-over to any other source work group.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 55 

### Mitigation Option: Use Alternative Fuels a nd Maximize Fuel Efficiency to Control Combustion Engine Emissions

I. Description of the mitigation option This option involves the implementation of alterna tive fuels, ultra low sulfur diesel (15 ppm) and improved fuel efficiency for heavy-duty trucks (Class 7 – GVW 26,001 to 33,001). The air quality benefits include potential reduction of sulfur, gr eenhouse gases and aromatic compounds throughout the region. Other environmental impacts include a reduc tion in petroleum consumption and conservation of

natural resources.

Economic burdens include the cost of the new alte rnative fuel/fuel efficient vehicle and cost and availability of the fuel.

There would not be adverse environmental justi ce issues associated with the implementation of alternative fuels. There is potential for air quality improvements from travels through socio-economically disadvantaged communities with improved fuel efficiency.

Low sulfur diesel can continue to be used in 2 006 and older highway vehicles until 2010. Any new 2007 model year highway diesel vehicle will be required to use ultra low sulfur diesel (ULSD). ULSD must be available at retail by October 15, 2006. Terminals sh ould be turned over to ULSD by the end of July. They could consider using ULSD for the non-road eq uipment too and get even more reductions in PM as

well.

II. Description of how to implement A. Mandatory or voluntary: There may be some mandatory upgrades for new heavy-duty trucks purchased after a set date. The immediate move to alternative fuel vehicles should be a voluntary program and could be incorporated into the San Juan Vistas or similar program. Likewise the states could adopt tax advantaged strategies under a voluntary progra m to encourage the adoption of alternative fuels. B. Indicate the most appropriate agency(ies) to implement : NM Dept. of Transportation, Colorado Dept. of Transportation, Federal Highway Administration.

III. Feasibility of the option

A. Technical: Oil and gas industry have developed a di esel fuel made from natural gas through the Fischer-Tropsch (F-T) process, there are other synthe tic liquid fuels and major heavy-duty diesel engine companies are working on engines with reduced NOx and particulate emissions.

B. Environmental: The environmental benefits would primar ily be associated with reduced consumption of petroleum resources.

C. Economic: The market will have to drive economically vi able alternatives. According to referenced studies, Class 7 Heavy Duty Vehicles use a smaller pe rcentage of fuel than Class 8 trucks (long-haul tractor- trailers), Class 2b vehicles (light trucks) or Class 6 vehicles (delivery vans).

IV. Background data and assumptions used 1. Life Cycle Analysis for Heavy Vehicles by Ar gonne National Laboratory Transportation Technology

R&D Center. 2. Heavy Vehicle Technology and Fuels September 2004 – Argonne National Laboratories Transportation Technology R&D Center. 3. Green Machines facts and figures associated with fu el type, consumption rates, and emissions factors (reference)

V. Any uncertainty associated with the option High.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 56 VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to other source groups None at this time.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 57 

### Mitigation Option: Utilize Exhaust Emission Control Devices for Combustion Engine

Emission Controls

I. Description of the mitigation option This option involves the implementation of exhaust emission control devices for heavy-duty trucks (Class 7 – GVW 26,001 to 33,001) such as diesel oxidation cat alysts (DOC), diesel particulate filters and/or traps. The air quality benefits include potential re duction of particulate matter and NOx throughout the region.

Economic burdens include the cost associated with the installation and maintenance of the exhaust

emission control devices.

There would not be environmental justice issues associat ed with the implementation of emission controls.

II. Description of how to implement A. Mandatory or voluntary: There may be some mandatory upgrades for new heavy-duty trucks purchased after a set date. The immediate move to emission controls should be a voluntary program and could be incorporated into the San Juan Vistas or similar program. B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: Technology exists.

B. Environmental: The environmental benefits would primarily be associated with reduced particulates

and NOx.

Most devices are also effective at reducing VOCs, and therefore air toxics and ozone. In fact, the most common, inexpensive, and most demonstrated technologies are oxidation catalysts, which are more effective at removing VOCs than PM and NOx. After treatment technologies for reducing NOx (especially on mobile engines) are still evolving, and so strategies for reducing NOx typically rely on fuel emulsifiers, engine modifications/repair, and engine replacements.

C. Economic: The market will have to drive economically vi able alternatives. According to referenced studies, Class 7 Heavy Duty Vehicles use a smaller pe rcentage of fuel than Class 8 trucks (long-haul tractor- trailers), Class 2b vehicles (light trucks) or Class 6 vehicles (delivery vans).

IV. Background data and assumptions used 1. Life Cycle Analysis for Heavy Vehicles by Ar gonne National Laboratory Transportation Technology

R&D Center. 2. Heavy Vehicle Technology and Fuels September 2004 – Argonne National Laboratories Transportation Technology R&D Center.

3. US EPA Clean Diesel and Trucks Rule 4. Green Machines facts and figures associated with fu el type, consumption rates, and emissions factors (reference)

V. Any uncertainty associated with the option (Low, Medium, High) High

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to other source groupsOil & Gas: Engines – Mobile/Non-Road

11/01/07 58 

### Mitigation Option: Exhaust Engine Testing fo r Combustion Engine Emission Controls

I. Description of the mitigation option This option involves the implementation of an insp ection and maintenance program to determine if emission controls and engines are functioning proper ly resulting in reduced emissions. Compliance with the standards set in the 2000 Heavy Duty Highway Cl ean Diesel Trucks and Buses Rule can be tested with an inspections and maintenance testing program . Environmental benefits include potential reduction of sulfur, NOx and particulates throughout the region.

Economic burdens include the cost of the inspecti on program, equipment, inspectors, and mobile or stationary inspection facilities.

There would not be environmental justice issues asso ciated with the implementation of exhaust engine testing.

II. Description of how to implement A. Mandatory or voluntary: Mandatory participa tion would be required. B. Indicate the most appropriate agency(ies) to implement : NM Dept. of Transportation, Colorado Dept. of Transportation, Federal Highway Administration.

III. Feasibility of the option

A. Technical: Numerous states currently use exhaust emi ssion testing. Details on mobile inspection programs are widely available.

B. Environmental: The environmental benefits would prim arily be associated with reduced sulfur, particulates and compliance with Clean Diesel Trucks Rule.

Most devices are also effective at reducing VOCs, and therefore air toxics and ozone. In fact, the most common, inexpensive, and most demonstrated technologies are oxidation catalysts, which are more effective at removing VOCs than PM and NOx. After treatment technologies for reducing NOx (especially on mobile engines) are still evolving, and so strategies for reducing NOx typically rely on fuel emulsifiers, engine modifications/repair, and engine replacements.

C. Economic: The market will have to drive economically vi able alternatives. According to referenced studies, Class 7 Heavy Duty Vehicles use a smaller pe rcentage of fuel than Class 8 trucks (long-haul tractor- trailers), Class 2b vehicles (light trucks) or Class 6 vehicles (delivery vans).

IV. Background data and assumptions used 1. Life Cycle Analysis for Heavy Vehicles by Ar gonne National Laboratory Transportation Technology

R&D Center. 2. Heavy Vehicle Technology and Fuels September 2004 – Argonne National Laboratories Transportation Technology R&D Center.

3. US EPA Clean Diesel and Trucks Rule 4. Green Machines facts and figures associated with fu el type, consumption rates, and emissions factors (reference)

V. Any uncertainty associated with the option (Low, Medium, High) Medium

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to other source groups None at this time.Oil & Gas: Engines – Mobile/Non-Road

11/01/07 59 

### Mitigation Option: Reduce Trucking Tr affic in the Four Corners Region

I. Description of the mitigation option This option involves implementing various measures to reduce the mileage required to truck fluids or equipment for oil and gas exploration, production, or treating operations. The air quality benefits include increased operating efficiency by 10% which will equate to 10% reduced fuel usage, which results in a net reduction of emissions of NOx by [ ] tons pe r day, SOx by [ ] tons per day, a reduction in greenhouse gas emissions of [ ] and PM2.5 emissions by [ ] tons per day. Other environmental impacts

include reduced dust and noise from the trucks and road s at nearby residences, and reduced unintentional killing of wildlife and livestock that may be killed truck traffic.

Economic burdens include the cost of centralized facilities and systems designed to maximize routing efficiency, which may be partially offset by the be nefits to human health of improved air quality and reduction of highway traffic (and traffic accidents) in the region.

There should not be any environmental justice issues associated with the placeme nt of the centralized tank batteries (including produced water tanks, condensate tanks and/ or crude oil tanks) in socioeconomically disadvantaged communities. Differing opinion: There are potential health hazards associated with crude oil and condensate tank emissions. Concentrating these facilities in socio-econom ically disadvantaged communities is an example of environmental injustice.

II. Description of how to implement A. Mandatory or voluntary: The implementation of measures to ma ximize routing efficiency and reduce truck trips are envisioned as a “voluntary” measures to enhance operating efficiency and could be easily incorporated as a BMP in voluntary programs su ch as the NMED San Juan VISTAs program. Furthermore, the state could adopt tax advantages stra tegies to allow companies to reduce their taxes by showing reduced emissions from adop ting improved routing or operating efficiency. There are currently no mechanisms or rules to require mandatory effi ciency standards and this seems implausible as a mandatory approach. B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: The use of centralized facilities is technically feasible as is software to maximize routing efficiency.

B. Environmental: The environmental benefits of redu ced vehicle mileage are well documented.

C. Economic: These options need to be explored by indi vidual companies as to their economic viability.

IV. Background data and assumptions used 1. Water hauling is necessary in NM due to the lack of pipeline infrastructure to pipe the fluids directly to SWD facilities; Colorado has a greater use of pipelines. 2. Trucking companies will not react adversel y to reduced economics from less vehicle miles.

V. Any uncertainty associated with the option Medium.

VI. Level of agreement within the work group for this mitigation option General agreement among drafting team members that this is viable and probable.

VII. Cross-over issues to other source groups None at this time. Differing opinion: Some indication by the Cumulative Effects group of the potential emissions reduced would be helpful.Oil & Gas: Engines – Rig Engines

11/01//07 60 

### ENGINES: RIG ENGINES

Mitigation Option: Dies el Fuel Emulsions

I. Description of the mitigation option

Diesel Fuel Emulsions:

• This option, which is an EPA verified retr ofit technology, reduces peak engine combustion temperatures and increases fuel atomization and combustion efficiency. Differing opinion: The EPA study only looked at the “summer” blend of diesel emulsion. There

is no data available to evaluate neither the compatibility with winter temperatures nor the emissions effects at winter temperatures.

• It is accomplished by using surfactant additives to encapsulate water droplets in diesel fuel to form a stable mixture while ensuring that th e water does not contact metal engine parts.

• Air quality benefit:

% Reductions 2, 3

Non-Road 1 PM CO NOx HC 0-100 hp 23 (35) 19 (99) 100-175 hp 17 13 17 (80) 175-300 hp 17 13 19 (73) >300 hp 17 13 20 (30)

1. Estimate using 2D fuel, <500 ppm sulfur.

2. (##) indicates an increase

3. Based on verification results supplied to EPA by Lubrizol for PuriNOx emulsion. Differing Opinion: CARB’s verified NOx reductions were lower (14%) than EPA’s as shown in the above table. This suggests a need for a more extensive review prior to finalizing this option.

• Can be used in conjunction with a diesel oxida tion catalyst to reduce HC and CO emissions and

further reduce PM.

• Emission control performance is better in lower load/lower speed applications.

• Emulsions have about a 12-month shelf life.

• Typically experience a 20% power loss when operating at maximum engine horsepower. The power loss is potentially a fatal flaw in this method. Most rig engines are sized for the maximum load expected and would have to be refitted with larger engines to handle the equivalent maximum loads.

• Will expect a 15% increase in fuel consum ption for equipment operating on fuel with emulsion additive. [This will increase SO2 emissi ons by 15%. The mass will depend on the

sulfur content of the fuel. It will also increase fuel delivery truck emissions by 15% along with road dust emissions due to fuel hauling by 15%.

• Not compatible with optical or conductivity -type fuel sensors, water absorbing water separators, water absorbing fuel filters, or centrifugal style water separators.

• Engine must be run for at least 15 minutes every 30 days.

• Incremental cost increase of $0.10 to 0.20 per gallon. Differing opinion: The increased fuel cost on top of the 15% increase in fuel consumption makes this a very expensive option. For a “typical” 16 day Wyoming Green River Basin well using 19,816 gallons of diesel, the 15% fuel penalty w ould represent about $6,000 additional fuel cost and the average premium ($0.15/gal) would represen t about $3,400 additional fuel cost for a NOx

benefit of about 1 ton reduction – or a cost of about $9,400 per ton of NOx. This seems very

excessive and does not include the additional cost s required for separate mixing and storage of the emulsified fuel. There may also be incremen tal labor costs for the technicians to operate the system. The incremental cost per gallon needs to be updated and verified – the cost quoted datesOil & Gas: Engines – Rig Engines

11/01//07 61 to the original study date. Installation of oxidation catalyst to control hydrocarbon and CO emissions would add additional cost and complexity to an already cost prohibitive option.

• Requires mixing of fuel with emulsion and a storage unit for the emulsion and or mixed fuel. Some burden on technicians to properly ope rate and mix some simple equipment.

II. Description of how to implement This voluntary option would be relatively simple using EPA verified retrofit technology. Some analysis is required to ensure that duty cycle (how long will e ngine and fuel be idle) and ambient temperatures are compatible with the emulsion product. Storage tanks and some training and capable technicians will be required to put into operation the re latively simple mixing equipment. Differing opinion: The power penalties, incremental mixi ng and storage equipment, and increased technical knowledge necessary make this option do-able, but not necessarily simple.

III. Feasibility of the option A. Technical: Technically this is one of the simplest options available. B. Environmental: Fuel emulsion has potential for increased carbon monoxide and hydrocarbon emissions, but this downside could be overcome by use of a diesel oxidation catalyst. One additional issue with the emulsion option is that if the emulsion is no longer purchased or used the emission benefit goes away, in comparison to permanent exhaust treatments or improved engines or hardware. C. Economic: There would be capital cost for emulsi on and/or mixture storage and ongoing incremental cost per gallon. Differing opinion: This option should be characterized as an expensive one. Using a “typical” 16 day Wyoming Green River Basin well using 19,816 gallons of diesel the 15% fuel penalty would represent about $6,000 additional fuel cost and the averag e premium ($0.15/gal) would represent about $3,400

additional fuel cost for a NOx benefit of about 1 ton reduction – or a cost of about $9,400 per ton of NOx. This seems very excessive and does not include th e additional costs required for separate mixing and storage of the emulsified fuel. There may also be incremental labor costs for the technicians to operate the system.

IV. Background data and assumptions used As an EPA verified retrofit, the data and assump tions associated with this option have been well

evaluated and considered. Differing opinion: The evaluation of applicability in cold weather needs to be done.

V. Any uncertainty associated with the option (Low, Medium, High) Low uncertainty as this is a verified, simple retrofit. Differing opinion: Given the high apparent cost, no evaluati on in cold weather, different reduction percentages from separate evalua tions, and complexity, this option should not be considered low uncertainty.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups (please describe the issue and which groups

None at this time.Oil & Gas: Engines – Rig Engines

11/01//07 62 

### Mitigation Option: Natural Gas Fired Rig Engines

I. Description of the mitigation option

Install natural gas fired engines on rigs in the Four Corners region. Benefits



### • Air Quality - Natural gas engines emit less and NOx,

– ~ 85% reduction of NOx vs. Tier I engines. Differing opinion: Given the variable load (and often low load) on drilling rig engines, the “best” lean burn natural gas engine performance expected would be in the range of 2 to 3 grams per hp-hr. This represents about a 65- 75% reduction from Tier 1 diesel engines. Please note this would require lean burn engines.

– ~ 91% reduction of NOx vs. Tier 0 engines Differing opinion: Given the variable load (and often low load) on drilling rig engines, the “best” lean burn natural gas engine performance expected would be in the range of 2 to 3 grams per hp-hr. This represents about a 65- 75% reduction from Tier 1 diesel engines. Please note this would require lean burn engines.

- Natural gas engines emit less particulate matter (PM) on a larger percent reduction basis than the NOx percentages above.



### • Cost Savings?

– If the natural gas fuel source is in close proximity and little piping is required, its use may be less expensive than diesel, which is currently hauled to the rig. Differing opinion: On a purely fuel basis this may be true without considering the retrofit

costs.

– Savings in fuel cost is dependent on product price. Tradeoffs



### • CO levels increase with natural gas usage, ~ 175%

Burdens



### • Fuel Source

– A natural gas fuel source sufficient to power th e rig engines may not be readily available at every site.

– Installation of piping to transport the natu ral gas may increase safety risks for workers and may potentially require right-of-way that can significantly delay projects (months to years).

– Natural gas usage may require mineral owner approval, metering and appropriate allocation potentially resulting in permitting delays and increased administrative support

– Fuel supply needs careful tuning and monitori ng due to varying amounts of produced water that may be present. Also impacted by varia tions in fuel quality in the different areas and formations of a field. Could also require the in stallation of a dehydrator if gas is wet and the field uses a central dehydration system.

– Engine size must increase to achieve an equivalent horsepower yield. For example a Cat 3512 diesel would have to be replaced with a Cat 3516 natural gas engine to get approximately the same horsepower.



### • Rig Operations

– Slower power response and less torque requires learning curve on rigs

– Not well suited for Mechanical Rigs – Electric rigs are preferred. Information from natural gas fueled engine rigs in Wyoming indicates that a “load bank” is required due to the slower response of the engines to power demand.



### • Cost

– Initial Capital Investment – up to 1.2 MM$ / Rig for retrofitOil & Gas: Engines – Rig Engines

11/01//07 63 – If the natural gas fuel source is distant or not available for other reasons, the associated piping or use of LNG may be significantly more expensive than diesel. Differing opinion: LNG is not a viable fuel – it is not readily available, requires refrigerated storage, and requires “re-gas” equipment. Conve rsion to natural gas fuels essentially limits the utility of a particular rig to just those instances where gas is available.



### • Availability

– Engine availability is limited

II. Description of how to implement A. Mandatory or voluntary: Voluntary B. Indicate the most appropriate agency(ies) to implement : None

III. Feasibility of the option

A. Technical: A natural gas fired rig engine is currently being utilized in Wyoming in the Jonah Field indicating that the technology works. However, th e Jonah field is significantly different from the San Juan Basin enabling easier access to natural gas as a fuel source. The wells in the Jonah Field are more closely spaced (10 acre vs. 80 acre) and deeper allowi ng for the directional drilling of several wells from a single well pad and close proximity to currently producing wells.

B. Environmental: Installation of natural gas fired engines on new rigs will significantly reduce NOx emissions for those rigs, but may result in other environmental impacts, including an increase in CO emissions and potential land disturbance related to inst allation of natural gas pipelines to deliver the fuel.

C. Economic: In some cases where a natural gas fuel sour ce is nearby, fuel costs may be lower than for diesel. In other cases, where access to natural gas can only be obtained by installing a large amount of pipe that potentially requires a right-of-way or by using LNG, the costs may be significantly higher. Conversion to natural gas fired engines essentially limits the use of a rig to only those instances where gas is available. The conversion/retrofit costs are high. Differing opinion: See LNG comments above.

IV. Background data and assumptions used Utilized Encana data obtained from Ensign 88 – Na tural Gas Rig (2 3516 LE Natural Gas Engines on 1200 KW Generators)

V. Any uncertainty associated with the option (Low, Medium, High) High

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to other source groupsOil & Gas: Engines – Rig Engines

11/01//07 64 

### Mitigation Option: Selective Catalytic Reduction (SCR)

I. Description of the mitigation option

Selective Catalytic Reduction (SCR) Description Selective catalytic reduction (SCR) is the process where a reductant (typically ammonia or urea) is added to the flue gas stream and is absorbed onto the catalyst (typically vanadium or zeolite) enabling the chemical reduction of NOx to molecular nitrogen and water. Diesel engines typically have unconsumed oxygen in the exhaust, which inhibits removal of oxygen from the NOx molecules. To remove the unconsumed oxygen, the catalyst decomposes the reduc tant causing the release of hydrogen, which reacts with the oxygen. This creates local oxygen depletion n ear the catalyst allowing the hydrogen to also react with the NOx molecules to form nitrogen and water.

Benefits

• NOx emission reductions of 80-90% are achieved. NOx emission reductions of up to 80-90% are

achievable.

• Potential to reduce hydrocarbon, hazardous air pollu tant, and condensable particulate matter (PM)

emissions based on emissions tests.

• Technology is available currently.

• SCR systems designed primarily to reduce NOx ha ve been designed with PM filtering capabilities.

Tradeoffs

• Ammonia Slip

The SCR process requires precise control of the ammoni a injection rate. An insufficient injection may result in unacceptably low NO

x conversions. An injection rate that is too high results in release of undesirable ammonia to the atmosphere. These a mmonia emissions from SCR systems are known as ammonia slip . Ammonia slip will also occur when exhaus t gas temperatures are too cold for the SCR Reaction to occur. Ammonia slip can potentiall y be controlled by an oxidation catalyst installed downstream of the SCR catalyst. Diesel oxidation catalysts are often used downstream of NOx catalysts

for ammonia reduction.

Burdens



### • Minimum and maximum temperature ranges limit the effectiveness of the SCR system.

– The SCR system requires a minimum exhaust temperature of 572°F (300°C) and maximum of 986°F (530°C) for NOx reduction to occur (optimal range).



### • The SCR systems had faults and system errors that can shut the urea injection system off.

– ENSR testing had problems with the NO2 me asuring cells that had multiple high and low pressure and measurement alarms.



### • The SCR system needs operator attention.

– The SCR system needs to be tuned to the engine operating cycle. This requires running the engine through a simulation of the operating cycl e of the machine it will be fitted to (engine mapping).

– Typically SCR catalysts require frequent cleaning even with pure reductants, as the reductant can cake the inlet surface of the catalyst while th e exhaust gas stream temperature is too low for the SCR reaction to take place.



### • Potential for ammonia slip



### • Cost (Retrofit)

– Capital Expenditure Costs - ~$130,000 / new SCR unitOil & Gas: Engines – Rig Engines

11/01//07 65 – Operating Expenditure Costs - ~$143,000 / year / unit 1

– Costs extrapolated out over a 10-year period would equate to $1.56 MM / engine equipped.

– Need for reductant (NH3) adds to the engine operating cost (in the range of 4% of the equipment operating fuel cost).

Non-Selective Catalytic Reduction (NSCR) NSCR is not applicable to diesel engines.

II. Description of how to implement A. Mandatory or voluntary : The workgroup believes that more information is required on the contribution of rig emissions to the total NOx emissi ons and the potential ammonia emissions impact to visibility prior to determining whether this m itigation should be mandatory or voluntary.

. B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: The technology is available and effective in reducing NOx emissions.

B. Environmental: Proven reduction of NOx emissions, however the potential increase of ammonia emissions and subsequent impact to visibility is not well understood.

C. Economic: Capital costs associated with a new engine with SCR or installation of retrofit SCR are feasible. Additional costs associated with operation and maintenance may not be feasible for some rig

operators.

IV. Background data and assumptions used

Utilized information from ENSR Presentation - Technology Demonstration – Selective Catalytic Reduction (SCR) and Bi-Fuels Impl ementation on Drill Rig Engines

V. Any uncertainty associated with the option (Low, Medium, High)

Medium – It is clear that SCR is effective in re ducing NOx emissions, however an understanding of the potential increase of ammonia emissions and the resulti ng impacts to visibility need to be understood.

VI. Level of agreement within the work group for this mitigation option The workgroup agrees that this is a potential mitigat ion option, but requires mo re information regarding

ammonia emissions and the overall cont ribution of NOx emissions from rigs. EPA has SCR listed as a Potential Retrofit Technology for diesel engines.

VII. Cross-over issues to the other source gro ups (please describe the issue and which groups Cumulative Effects Workgroup – The Rig Engines Drafting Workgroup requires information on the estimated contribution of NOx emissions from rig e ngines and on the impact of ammonia emissions on visibility (what are local levels currently, how w ill increasing ammonia emissions impact visibility?).Oil & Gas: Engines – Rig Engines

11/01//07 66 

### Mitigation Option: Selective No n-Catalytic Reduction (SNCR)

I. Description of the mitigation option Selective Non-Catalytic Reduction (SNCR) is a post-co mbustion treatment in which ammonia is injected into the flue gas stream. The ammonia reacts with the NOx compounds, forming nitrogen and water. In order for this technique to be effective, the amm onia must be injected at a proper temperature range within the stack and must be in the proper ratio to the amount of NOx present. The reduction reaction at temperatures ranging from 925 – 1125oC does not requir e catalysis and can achieve 40% NOx control.

More modest NOx reductions are re ported in the 725 - 925oC range. Differing Opinion: These are very high temperatures and much greater than the temperatures in diesel engine exhaust. For example, the data sheet for a Cat 3512 diesel rig engine shows a “highest” exhaust temperature of ~792 degrees F. Based on the degr adation in performance reported in the 725 – 925 degrees C it probably would have very little effect at the exhaust temperatures from rig engines. This technology is really tested for very high temperature boilers only – not engines.

Benefits

• NOx emission reductions of ~40% (range 20-55%) are achieved in optimal temperature range.

• Avoids the expense of a catalyst.

• Technology is available currently.

Tradeoffs

• Ammonia Slip – 10 ppm ammonia slip is consider ed reasonable for SNCR. 10 ppm represents about 16 tons/yr of ammonia from a single fully loaded Cat 3512 engine. Given that most rigs have two or more engines it is not much of a stretch to have very significant ammonia emissions with the number of rigs running in the basin. This amount of ammonia may enhance secondary particulate formation with consequent effects on PM 2.5 (health based) and visibility (perception based).

Burdens SNCR tends to have high operating costs - cost is estimated at $600 - $1300/ton Mobile source engines (rig engines) are usually not a good candidate for SNCR because typical operating temperatures are below the levels needed for effective operation.

II. Description of how to implement A. Mandatory or voluntary : The workgroup believes that more information is required on the contribution of rig emissions to the total NOx emissi ons and the potential ammonia emissions impact to visibility prior to determining whether this m itigation should be mandatory or voluntary. B. Indicate the most appropriate agency(ies) to implement : Colorado Department of Public Health and Environment (CDPHE), New Mexico Environment Department (NMED).

III. Feasibility of the option

A. Technical: The technology is available and e ffective in reducing NOx emissions. Differing Opinion: There is no available data indicating app licability to engines or much lower temp operation. This option should be considered as non-feasible.

B. Environmental: Proven reduction of NOx emissions, however the potential increase of ammonia emissions and subsequent impact to visibility is not well understood.

C. Economic: Costs associated with operation and maintenance may not be feasible for some rig

operators.Oil & Gas: Engines – Rig Engines

11/01//07 67 IV. Background data and assumptions used State of the Art (SOTA) Manual for Reciprocating Internal Combustion Engines – State of New Jersey, Department of Environmental Protection, Division of Air Quality

V. Any uncertainty associated with the option Medium – SNCR is effective in reducing NOx emi ssions, however an understanding of the potential increase of ammonia emissions and the resulting im pacts to visibility need to be understood.

VI. Level of agreement within the work group for this mitigation option The workgroup agrees that this is a potential mitigat ion option, but requires mo re information regarding

ammonia emissions and the overall cont ribution of NOx emissions from rigs.

VII. Cross-over issues to the other source groups Cumulative Effects Workgroup – The Rig Engines Drafting Workgroup requires information on the estimated contribution of NOx emissions from rig e ngines and on the impact of ammonia emissions on visibility (what are local levels currently, how w ill increasing ammonia emissions impact visibility?).Oil & Gas: Engines – Rig Engines

11/01//07 68 

### Mitigation Option: Implementa tion of EPA’s Non Road Di esel Engine Rule – Tier 2 through Tier 4 Standards

I. Description of the mitigation option

In short this option would require the use of engines that at minimum meet EPA Tier 2 non-road on a fleet average basis and that all newly installed engin es would meet the most current EPA standard (Tier 2 through 4).

In 1998, EPA adopted more stringent emission standa rds ("Tier 2" and "Tier 3") for NOx, hydrocarbons (HC), and PM from new nonroad diesel engines. This program includes the first set of standards for nonroad diesel engines less than 50 hp (phasing in between 1999 and 2000), phases in more stringent

"Tier 2" emission standards from 2001 to 2006 for all engine sizes, and adds more stringent "Tier 3" standards for engines between 50 hp and 750 hp from 2006 to 2008.

In June 2004, EPA adopted additional nonroad diesel engines emission standards. These standards are known as “Tier 4.” This comprehensive national pr ogram regulates nonroad diesel engines and diesel fuel as a system. New engine standards will begin to take effect in the 2008 model year, phasing in over a number of years.

The pertinent regulations are as follows:

Clean Air Nonroad Diesel - Tier 4 Final Rule: Control of Emissions of Air Pollution from Nonroad Diesel Engines and Fuel, 69 FR 38957, June 29, 2004

Tier 2 and Tier 3 Emission Standards - Final Rule: Control of Emissions of Air Pollution from Nonroad Diesel Engines, 63 FR 56967, October 23, 1998

Drill rig engines would be considered "non-road engines" because of the definition of non-road engine in 40 CFR 1068.30 (1)(iii) and (2)(iii) – assuming the rig moves more often than every 12 months.

These non-road diesel standards do not apply to existi ng non-road equipment. Only equipment built after the start date for an engine category (1999- 2006, depending on the category) is affected by the rule.Oil & Gas: Engines – Rig Engines

11/01//07 69 The Tier 2, 3, and 4 Emission Standards for large (> 300 hp) are as follows: [AP42 (Tier 0) and Tier 1 shown for comparison purposes]

OR

The Tier 2, 3, and 4 Emission Standards for large (> 300 hp) are as follows: [AP42 (Tier 0) and Tier 1 shown for comparison purposes] NO x Factors for Large Nonroad Diesel Engines

0 2 4 6 8 10 12 14 16

300 to 600 hp 600 to 750 hp > 750 hp Gen sets 750 to 1200 hp Gen sets > 1200 hpg/hp-hr AP-42

Tier 1

Tier 2

Tier 3

Tier 4 transitional

Tier 4 finalOil & Gas: Engines – Rig Engines

11/01//07 70

Effective Dates of Tier Standards, No nroad Diesel Engines, by Horsepower

1 2 3 4

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 

## Tier

Up to 25 hp

25 -- 50 hp

50 -- 75 hp

75 -- 100 hp

100 -- 175 hp

175 -- 300 hp

300 -- 600 hp

600 -- 750 hp

Over 750 hp 4 TransOil & Gas: Engines – Rig Engines

11/01//07 71Oil & Gas: Engines – Rig Engines

11/01//07 72 II. Description of how to implement

A. Mandatory or voluntary Compliance with these regulations is required for new and rebuilt engines after the specified deadlines. The Four Corners Task Force is studying the potentia l for quicker implementation of the standards based on a voluntary agreement to either retrofit existing engines to meet the Tier 2 through Tier 4 standards or use of new Tier 2 through Tier 4 compliant engines.

B. Indicate the most appropriate agency(ies) to implementOil & Gas: Engines – Rig Engines

11/01//07 73 EPA implements the non-road engine regulations nationally by certifying engine manufacture test results, but state regulatory agencies would be involved in any agreements for accelerated implementation of the

standards in the Four Corners area.

III. Feasibility of the option

A. Technical Some engine industry authorities indicate anecdotally th at the supply of the new, cleaner engines may fall short of the demand for them particularly in the oil and gas industry.

In 1998, EPA adopted more stringent emissions standa rds for nonroad diesel engines. In that rulemaking, EPA indicated that in 2001 it would review the upcomi ng Tier 3 portion of those standards (and the Tier 2 emission standards for engines under 50 horsepower) to assess whether or not the new standards were technologically feasible. EPA drafted a technical paper with a preliminary assessment of the technological feasibility of the Tier 2 and Tier 3 emission standards - http://www.epa.gov/nonroaddiesel/r01052.pdf

In this assessment EPA determined that the standa rds were feasible with technologies such as the following:

Charge Air Cooling - Air-to-air or air-to-water cooli ng at intake manifold reduces peak temperature of combustion. (Controls NOx)

Fuel Injection Rate Shaping & Multiple Injections - Controls fuel injection rate, limiting rate of increase in temperature & pressure. (Controls NOx)

Ignition Timing Retard - Delays start of combustion, matching heat release with power stroke. (Controls NOx)

Exhaust Gas Recirculation - (1) Reduces peak cylinder temperature, (2) dilutes O2 with inert gases, (3) dissociates CO2 & H2O endothermic. (Controls NOx)

B. Environmental

The Tier 2 and 3 standards will reduce emissions from a typical nonroad diesel engine by up to two-thirds from the levels of previous standard s. By meeting these standards, manufacturers of new nonroad engines and equipment will ach ieve large reductions in the emissions (especially NOx and PM) that cause air pollution problems in many parts of the country. EPA estimates that by 2010, NOx emissions nationally will be reduced by about a m illion tons per year because of the Tier 2 and 3

standards.

When the full inventory of older nonroad engin es are replaced by Tier 4 engines, annual emission reductions nationally are estimated at 738,000 tons of NOx and 129,000 tons of PM. By 2030, 12,000 premature deaths would be prevented annually due to the implementation of the proposed standards. EPA estimates that NOx emissions from these engi nes will be reduced by 62 percent in 2030.

C. Economic EPA estimates the costs of meeting the Tier 2 and 3 emission standards are expected to add well under 1 percent to the purchase price of typical new non-road diesel equipment, although for some equipment the standards may cause price increases on the order of two or three percent. The program is expected to cost about $600 per ton of NOx reduced, which compar es very favorably with other emission control strategies.Oil & Gas: Engines – Rig Engines

11/01//07 74 The estimated costs for added emission controls for the vast majority of equipment was estimated at 1-3% as a fraction of total equipment price. For example, for a 175 hp bulldozer that costs approximately $230,000 it would cost up to $6,900 to add the advanced emission controls and to design the bulldozer to accommodate the modified engine.

EPA estimated that the average cost increase for 15 ppm sulfur diesel fuel will be seven cents per gallon. This figure would be reduced to four cents by anticip ated savings in maintenance costs due to low sulfur

diesel.

IV. Background data and assumptions used (indicate if assistance is needed from Cumulative Effects and/or Monitoring work groups)

The Cumulative Effects group could assess how much air quality improvement would be realized from implementation of the Tier 2 through Tier 4 standards by a specified percent of rig engines in the Four Corners area, by timeframes specified in regulation or some accelerated schedule. The group could also address the number of days of visibility improveme nt, and the reduced flux of Nitrogen deposition.

V. Any uncertainty associated with the option (Low, Medium, High)

Low, these diesel engine standards must be met na tionally by the specified dates. The primary uncertainty raised so far is related to supply of ne w engines sufficient to meet demand. EPA has studied the technological feasibility of the Tier 2 and Tier 3 emission standards and has determined that they are feasibility [see http://www.epa.gov/nonroad-diesel/r01052.pdf]

VI. Level of agreement within the work group for this mitigation option N.A. for complying with national regulations.

VII. Cross-over issues to the other source groups (please describe the issue and which groups All new “non-road” diesel engines used in the Four Corners area will have to comply with these regulations.Oil & Gas: Engines – Rig Engines

11/01//07 75 

### Mitigation Option: Interim Emission s Recommendations for Drill Rigs

I. Description of the mitigation option The following mitigation option paper is one of three that were written based on interim recommendations that were developed prior to the conve ning of the Four Corners Air Quality Task Force.

Since the Task Force's work would take 18-24 mont hs to finalize, and during this time oil and gas development could occur at a rapid pace, an Interi m Emissions Workgroup made up of state and federal air quality representatives was formed to develop recommendations for emissions control options associated with oil and gas production and tr ansportation. The Task Force includes these recommendations as part of its compre hensive list of mitigation options.

NOx emissions from drill rigs are significant on a y ear round basis and should be reduced by a requirement that rig engines meet Tier 2 standards.

• NOx emissions from rigs contribute to visibility degradation

• This recommendation is consistent with EPA Region 8’s oil and gas initiative and recent Wyoming DEQ recommendations

• The requirement may be impractical for BLM to enforce States should analyze potential initiatives to achieve emissions reductions from these sources to reduce deposition, the cumulative impacts to visibility, an d to ensure compliance with the NAAQS and PSD

increments.

II. Description of how to implement NOx emission limits determined by Tier 2 would be mandatory for new rigs and voluntary for existing equipment. The agencies to enforce this would be BLM and the New Mexico and Colorado departments of environmental quality.

III. Feasibility of the Option

The feasibility of Tier 2 requirements for new ri g engines has been demonstrated in commercial applications. The environmental benefits include PM and NOx reductions. The economic feasibility depends on using the technology with new rigs. The co st for replacement of an existing engine would be high since there might be no market for the used engine.

IV. Background data and assumptions used

The technology for rig engine upgrade to Tier 2 stan dards is based on the requirement to use Tier 2 certified diesel engines on new rigs. Under certain circumstances, upgrades might be required on older rigs as well.

V. Any uncertainty associated with the option Tier 2 engines are currently being manufactured, but some uncertainty exists about the effectiveness of

add-on controls to meet Tier 2 levels for existing rig engines.

VI. Level of agreement within the work group for this mitigation option

TBD.

VII. Cross-over issues to the other source groups

None.Oil & Gas: Engines – Rig Engines

11/01//07 76 

### Mitigation Options: Various Diesel Controls
Duel Fuel (or Bi-fuel) Diesel and Na tural Gas; Biodiesel; PM Traps; Free Gas Recirculation; Fuel Additives; Liquid Combustion Catalyst; Lean NOx Catalyst; Low NOx ECM - Engine Electronic Control Module (ECM) Reprogram; Exhaust Gas Recirculation (EGR)

I. Description of the mitigation options

Duel fuel (or Bi-fuel) diesel and natural gas This system allows engines to run on a blend of diesel and natural gas fuels. The systems consist of an air to fuel (AFR) controller and a fuel mixing chamber. The AFR constantly adjusts the fuel to air mixture being delivered to the piston chambers and optimizes the stoichiometric relationship in order to balance the NOx and CO emissions. The mixing chamber establis hes the diesel to natural gas mixing ratio. This system is being tested on drill rig diesel engines in the Pinedale, WY area. There are preliminary results based on tests of three engines (Cat 398 & 399) Pros: Operators reported that rig engine fuel costs were reduced by ~ $700 per day, requires minimal engine m odification, and has a small footprint. Cons: Does not conclusively reduce NOx, increases CO and HC em issions, and the system needs frequent oversight to ensure operation.

Biodiesel Biodiesel fuel stock comes from vegetable oil, anim al fats, and waste cooking oils. Biodiesel can be blended at different percentages up to100% (typical ly 5 – 20%). Biodiesel at a 20% blend can reduce PM mass emissions by up to 10%, reduce HC and CO up to 20%, and may slightly increase NOx emissions. Use of biodiesel requires little or no modification to fu el system or engine. Cold temperatures require special fuel handling such as additives or heating fuel system. EPA listed “verified retrofit technology.”

PM Traps Diesel particulate filters (DPFs) collect or trap PM in the exhaust. DPFs consist of a filter encased in a steel canister positioned in the exhaust system. DPFs need a mechanism to remove the PM (regeneration or cleaning) and to monitor for engine backpressure . DPFs types have different reduction capabilities and applications. DPFs can be used in conjunction with catalysts (catalyst based (CB) DPFs) to obtain the most effective PM control for a retrofit technology. CB-DPFs can have over 90% PM mass reduction and

over 99% carbon based PM reduction. CB-DPFs can also control CO and HC resulting in near

elimination of diesel smoke and odor.

Flow through filters (FTFs), or partial flow filters, u se a variety of media and regeneration strategies. The

filter media can be either wire mesh or pertubated path metal foil. FTFs are a relatively new technology. FTF can be catalyzed or used in combination with Diesel Oxidation Catalysts (DOCs) or Fuels Borne Catalysts (FBCs). PM reduction efficiencies range from 25 to over 60% depending on the type of technology and duty/test cycle. FTFs have the potentia l for greater application than conventional DPFs. Some designs can be used on engines fueled with < 500 ppm sulfur fuel but efficiency decreases. Has the potential for use on older engines, but high PM leve ls can overwhelm even a FTF system. Adequate exhaust temperatures are needed to support filter regeneration.

Diesel exhaust PM traps are EPA listed “verified retrofit technology.”

Free Gas Recirculation Crankcase emissions from diesel engines can be subs tantial. To control these emissions, some diesel engine manufacturers make closed crankcase ventila tion (CCV) systems, which return the crankcase blow-by gases to engine for combustion. CCV syst ems prevent crankcase emissions from entering the atmosphere. Aftermarket open crankcase ventilations (OCV) are available which provide incremental improvements over engines with no crankcase controls , but they still allow crankcase emissions to beOil & Gas: Engines – Rig Engines

11/01//07 77 released into the atmosphere. A retrofit CCV cr ankcase emission control (CCV) system has been introduced and verified for on-road applications by both the U.S EPA and CARB. Crankcase emissions range from 10% to 25% of the total engine emissions , depending on the engine and the operating duty cycle. Crankcase emissions typically contribute to a higher percentage (up to 50%) of total engine emissions when the engine is idling. The combined CCV/DOC system controls PM emissions by up to 33%, CO emissions by up to 23% and HC emissions by up to 66%.

Fuel Additives

Fuel additives are chemical added to the fuel in sm all amounts to improve one or more properties of the base fuel and/or to improve the performance of retr ofit emission control technologies. Several cetane enhancers have been verified by EPA that re duce NOx 0 to 5%. Other additives are undergoing

verification. There thousands of fuel additives on th e market that have no emission or fuel efficiency benefit so it is important to verify the manufacturer ’s claims regarding benefits. EPA listed “verified retrofit technology.”

Liquid Combustion Catalyst Fuels borne catalyst systems (FBCs) are marketed as a stand-alone product or as part of a system combined with DPFs, FTFs, or DOCs. FBCs ha ve included cerium, cerium/platinum copper, iron/strontium, manganese and sodium . A DPF must be used to collect the catalyst additive so it cannot be emitted to the air. A FBC/DOC system has been verified by EPA to reduce PM 25 – 50%, NOx 0 – 5%, and HC 40 – 50%. A FBC/FTF system has been verified by EPA to reduce PM 55 – 76%, CO 50 – 66%, and HC 75 – 89%. The estimated cost of the veri fied FBC is approximately $.05 per gallon. Premixed fuel is recommended for retrofit applications. F BCs do not require ultra low sulfur diesel and work with a wide range of engine sizes and ages. EPA listed “verified retrofit technology.”

Lean NOx Catalyst Lean NOx catalyst (LNC) is a flow through catalyst technology similar to diesel oxidation catalyst that is formulated for NOx control. It ty pically uses diesel fuel injection ah ead of the catalyst to serve as NOx reduction. Lean NOx catalyst can achieve a 10% to ov er 25% NOx reduction. It can be combined with diesel oxidation catalyst (DOC) or diesel particulate filter (DPF). Over 3500 vehicles and equipment have been retrofitted with Lean NOx catalyst and CB-DPF filter systems in United States. The sulfur lever level of the fuel has to be less than 15 ppm. Verified LNC systems use injected diesel fuel as the NOx reducing agent and as a result a fuel economy penalty of up to 3% has been reported

. EPA listed “potential retrofit technology.”

Low NOx ECM - Engine electronic control module (ECM) reprogram Some engine manufacturers used ECM on 1993 thro ugh 1996 heavy-duty diesel engines that caused the engine to switch to a more fuel-efficient but higher NOx mode during off cycle engine highway cruising. As part of the manufacturers’ requirements to rebuild or reprogram older engines (1993-1998) to cleaner levels, companies developed a heavy-duty diesel engine software upgrade (known as an ECM “reprogram”, “reflash” or “low NOx” software) that m odifies the fuel control strategy in the engine’s

ECM to reduce the excess NOx emissions. Low NOx EC M is available as a retrofit strategy to reduce NOx emissions from certain diesel engines. Emissions control performance is engine specific. A system verified for a Cummins engine by CARB provided 85 % particulate and 25% oxidation reductions. Over 60,000 heavy-duty diesel engines have received ECM reprograms. CARB plans to require ECM reprogramming on approximately 300,000 to 400,000 engi nes. ECM application is limited to heavy-duty diesel engines with electronic controls. Most off-road engines are not equipped with electronic controls. ECM is available throughout the U.S. through engine dealers and distributors. The software can be installed on-site and the reprogram ta kes approximately 15 to 30 minutes.

Exhaust Gas Recirculation (EGR)Oil & Gas: Engines – Rig Engines

11/01//07 78 The EGR system used in retrofit applications empl oys low-pressure. Original Equipment EGR systems typically employ high-pressure. EGR as a retrofit st rategy is a relatively new development but has been proven durable and effective over the last few years. In the U.S. retrofit low-pressure EGR systems is combined with a CB-DPF to allow the proper func tioning of the EGR component. EGR can reduce the NOx formed by the CB-DPF. EGR/DPF systems have been verified by CARB. Over 3000 and exhaust gas recirculation diesel particular filter systems have been retrofitted onto on road vehicles worldwide. EGR/DPF systems can be applied to off-road engines. However, experience is limited and the off-road market not the primary target application in the U.S. Current experience with EGR/DPF systems has been a range of 190 horsepower to 445 horsepower. The fuel economy penalty from EGR component ranges from 1% to 5% based on technology designed to particular engine and the test/duty cycle. EPA listed “potential retrofit technology.”

II. Description of how to implement These controls would be voluntary retrofits for existing engines. Some of these controls may be used by engine manufacturers to meet EPA’s diesel standards for new engines.

III. Feasibility of the option

A. Technical

B. Environmental

C. Economic

See the individual control summary descriptions above . For more detailed information consult Volume 2

of the WRAP Off-road Diesel Retrof it Guidance Document, to be found at: http://www.wrapair.org/forums/msf/projects/offro ad_diesel_retrofit/Offroad_Diesel_Retrofit_V2.pdf

IV. Background data and assumptions used As EPA verified retrofits or potential retrofits (with the exception of the bi-fuel option), the data and assumptions associated with this option have been evaluated and considered . See EPA’s Voluntary Diesel Retrofit Program web pages ( http://www.epa.gov/otaq/retrofit/retroverifiedlist.htm and http://www.epa.gov/otaq/retrofit/retropotentialtech.htm ) and Volume 2 of the WRAP Off-road Diesel Retrofit Guidance Document, located at: http://www.wrapair.org/forums/msf/projects/offro ad_diesel_retrofit/Offroad_Diesel_Retrofit_V2.pdf for more information on these verified and potential retrofit controls.

V. Any uncertainty associated with the option Low to high uncertainty depending on the applica tion, engine, operating conditions. These are EPA verified or potential retrofits for diesel engines (with the exception of the bi-fuel option), but some controls are limited to specific applications.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups (please describe the issue and which groups) All existing or newly introduced diesel engines (on-ro ad, non-road, and stationary) used in the 4 Corners area could utilize these control options with the limitations noted above.Oil & Gas: Engines – Turbines

11/01/07 79 

### ENGINES: TURBINES

Mitigation Option: Upgrade Existing Turb ines to Improved Combustion Controls (Emulating Dry LoNOx Technology)

I. Description of the mitigation option This option involves upgrading older units with im proved electronic combustion control technology that approaches or meets Dry LoNOx for existing turbines and requires Dry LoNOx technology on all new turbines. The benefits of this mitigation option ar e lower NOx emissions, but it is an expensive option that may take several years to implement and may be difficult to achieve with some engine models. The tradeoffs is that a few people may spend a lot of money and not significantly impact overall nitrogen oxide emissions to meet the region’s emission control objectives.

II. Description of how to implement A. Mandatory or voluntary: Implementation should be assumed as voluntary until the existing turbine population is better understood.

Differing Opinion: The best technology should be mandatory.

B. Indicate the most appropriate agency(ies) to implement Federal, state, and tribal agencies responsible for air emissions compliance.

III. Feasibility of the option

A. Technical Individual turbine assessment will be need ed to confirm appropriate size or design limitations (not all turbines can be retrofitted).

B. Environmental The benefits of a dry LoNOx emissions control technology on air emissions has been proven repeatedly for many large turbines.

C. Economic The economic impact cannot be understood without an inventory of installed turbines.

IV. Background data and assumptions used No assumptions have been made at this time on the im pact of emissions reductions due to the uncertainty of the existing turbine population.

V. Any uncertainty associated with the option High.

VI. Level of agreement within the work group for this mitigation option High.

VII. Cross-over issues to the other source groups The impact of implementing this option may be further evaluated by the Cumulative Effects or Monitoring groups.Oil & Gas: Exploration & Production – Tanks

11/01/07 80 

### EXPLORATION & PRODUCTION: TANKS

Mitigation Option: Best Man agement Practices (BMPs) for Operating Tank Batteries

I. Description of the mitigation option This option involves implementing and/or adoption of various Best Management Practices (BMPs) for operating tanks that contain crude oil and condensate. The specific BMPs include the use of Enardo valves, closing thief and other tank hatches, maintaining valves in leak -free condition, closing valves, etc. so as to minimize VOC losses to the atmosphere.

Economic burdens are minimal since these practices are largely followed and considered a normal cost of doing business as part of responsible operations.

There should not be any environmental justice issues associated with following these practices in socioeconomically disadvantaged communities. Differing opinion: This conclusion requires adequate suppor t that is not included in this option.

II. Description of how to implement A. Mandatory or voluntary: The implementation of measures to implement BMPs for operating tank batteries are envisioned as “voluntary” measures to enhance operating efficiency and could be easily incorporated as a BMP in voluntary programs such as the NMED San Juan VISTAS program and EPA’s Natural Gas STAR Program. There are currently no mech anisms or rules to require BMPs as standards, and this seems implausible as a mandatory approach . Many companies have BMPs in place already.

B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: The use of BMPs for operating tank batteries is technically feasible as is software to maximize routing efficiency.

B. Environmental: The environmental benefits of redu ced VOC pollution are well documented. Differing opinion : Quantification of emission reductions from implementation of this mitigation option is not possible.

C. Economic: These BMPs need to be explored by indi vidual companies as to their economic viability.

IV. Background data and assumptions used 1. Tank batteries containing crude oil and condensate are necessary in NM and Co lorado due to the lack of pipeline infrastructure to pipe the fluids directly to refineries. 2. Oil and gas producing companies will need to e ducate their workforce on the validity and importance

of these BMPs. 3. Employees will not react adversely to following these practices as a normal course of being a lease

operator.

V. Any uncertainty associated with the option Low.

VI. Level of agreement within the work group for this mitigation option General agreement within working group memb ers that this is viable and probable.Oil & Gas: Exploration & Production – Tanks

11/01/07 81 

### Mitigation Option: Installing Vapor Recovery Units (VRU)

I. Description of the mitigation option This option involves using Vapor Recover Units (V RUs) on crude oil and condensate tanks so as to capture the flash emissions that result when crude oil or condensate is dumped into the tank from the production separator. The air quality benefits would be to minimize VOC losses to the atmosphere and if sufficient flash gas were present, ther e would be economic benefits as well.

Economic burdens are substantial since these un its are costly to install and maintain.

There should not be any environmental justice issues associated with installing and operating these units in socio-economically disadvantaged communities. Differing opinion: This conclusion requires adequate support that is not included in this option.

II. Description of how to implement A. Mandatory or voluntary: The implementation of measures to implement VRUs for operating tank batteries are envisioned as “voluntary” measures since the feasibility of VRUs in the Four Corners area is negative. In certain areas of the country where ozone non-attainment areas exist, VRUs are commonly mandated by the respective Air Quality Control agency as Best Available Control Technology (BACT) or Lowest Achievable Emission Rate (LAER). Since the Four Corners area is not in ozone non-attainment and the costs economics will not generally justify inst allation of VRUs for econom ic benefit, a voluntary approach is recommended. B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: The use of VRUs for operating tank batteries is technically feasible. Differing opinion: However, installation of a VRU to most existing tank installations is not likely feasible without a complete redesign and new installati on. Most tanks are pressure rated at 3-5 psig and would need to be replaced with tanks designed w ith higher pressure rating to handle pressure surges during separator dumps. Additional pressure relief va lving, pressure regulators and other safety devices would need to be included with these systems. Re design and system replacement would need to be evaluated to determine the economic feasibility of this type of system. As these tanks are under pressure there would be additional operational and safety issues related to proper product transfer and handling. Most transporters are not equipped to handle pressurized product transfers at present. Due to the small amount of condensate produced in 4-Corners wells, the periodic “dumping” from the separators to the tanks, and the consequent uneven flash of gas from th e condensate the use of VRU’s is technically very challenging and may not be technically feasible. VRU’s start from atmospheric pressure and boost gas to low pressure that may not be sufficient to flow into the collection system lines. In this case, they are either not feasible or would require additional compression. The lack of electricity in the fields effectively precludes any opera tionally feasible VRU use.

B. Environmental: The environmental benefits of reduced VOC pollution are well documented. Benefits are relative to production throughputs. VOC emission s from flashing emissions are a function of well pressure and condensate production. The amount of emission reduction will be proportional to the

amount of uncontrolled VOC emissions. Even if VRU’s can be made to work in the 4-corners area, the

amount of VOC emission reduction per tank will be low due to th e low condensate production rate.

C. Economic: The use of VRUs for recovering the flash emissions from produced crude oil/condensate are economically feasible where the Gas Oil Ratio (GOR) from produced crude oil/condensate is high and the daily production volume is at least 50 barrels/day or greater. Most wells in the Four Corners area typically produce less than 1 bbl/day of crude oil or condensate so VRUs are not economically feasible.Oil & Gas: Exploration & Production – Tanks

11/01/07 82 Flares or combustors could be considered an altern ative control technology if sufficient VOC emissions exist. At 1 bbl/day and low pressure drop the flash gas volume and VOC content will not justify control

systems.

IV. Background data and assumptions used 1. Tank batteries containing crude oil and condensate are necessary in NM and Co lorado due to the lack of pipeline infrastructure to pipe the fluids directly to refineries. 2. The minimal production levels for most wells make the use of VRU economically infeasible.

V. Any uncertainty associated with the option Low. Differing opinion: MEDIUM based on availability of power , high maintenance requirements and reliability/performance. Differing opinion: This would rank a high level of uncertainty in actually achieving meaningful and cost

effective emission reductions using this technology.

VI. Level of agreement within the work group for this mitigation option General agreement within working group members that the use of VRUs in the Four Corners areas is economically infeasible and an unlikely source for voluntary adoption.Oil & Gas: Exploration & Production – Tanks

11/01/07 83 

### Mitigation Option: Installing Gas Blankets Capability

I. Description of the mitigation option This option involves modifying existing and installing new designed crude oil and condensate tanks that would be capable of placing an inert gas blanket ove r these tanks to minimize vapor loss. The inert gas would fill the space above the condensate/crude oil to minimize volatilization and vapor loss. The air quality benefits would be to minimize VOC losses to the atmosphere and if sufficient flash gas if present,

there would be economic benefits as well.

Economic burdens are substantial since these un its are costly to install and maintain.

There should not be any environmental justice issues associated with installing and operating these units in socio-economically disadvantaged communities. Differing opinion: This conclusion requires adequate suppor t that is not included in this option.

II. Description of how to implement A. Mandatory or voluntary: The implementation of measures to implement gas blankets for operating tank batteries are envisioned as “voluntary” measures sin ce the feasibility of gas bl anket technology in the Four Corners area is negative. In certain areas of th e country where ozone non-attainment areas exist, gas blanket technology is one of several measures comm only mandated by the respective Air Quality Control agency as Best Available Control Technology (BACT) or Lowest Achievable Emission Rate (LAER).

Since the Four Corners area is not in ozone non-a ttainment and the cost economics will not generally justify installation of gas blankets for economic benefit, a voluntary approach is recommended. B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: The use of gas blankets for operating tank ba tteries is technically feasible but requires the tanks to be designed to handle the increased pressur es that will result when crude oil/condensate enters the tank, thereby pressurizing the gas blanket. Currently crude oil/condensate tanks are designed as atmospheric tanks and are designed only to withstand 5 psig of internal pressure. API 12F specifies 16 oz of pressure for normal operation and no greater than 24 oz for emergency operati ons. Using gas blanket technology requires such tanks to withstand abou t 100 psig, which increases the costs for tanks substantially. As these tanks are under pressure ther e would be additional operational and safety issues related to proper product transfer and handling. Most transporters are not equipped to handle pressurized product transfers at present.

B. Environmental: The environmental benefits of re duced VOC pollution are well documented. Differing opinion : If this is considered a candidate cont rol technology, the detailed engineering and economic analyses are needed to evaluate the cost to c ontrol relative to other potential control measures.

C. Economic: The use of gas blanket technology for preven ting the release of flash and vapor emissions from produced crude oil/condensate are economically f easible for large, centrally located tank batteries where the crude oil/condensate can be piped from numerous wells to a centralized facility. Most wells in the Four Corners area typically produce less than 1 bb l/day of crude oil or condensate so the use of pipelines to transport the crude oil/condensat e to a centralized facility is uneconomic.

IV. Background data and assumptions used 1. Individual tank batteries rather than large, cen tralized tank batteries containing crude oil and condensate are necessary in NM and Colorado due to the minimal daily production volumes (i.e., less than 1 barrel/day).

V. Any uncertainty associated with the option Low.Oil & Gas: Exploration & Production – Tanks

11/01/07 84 Differing opinion: HIGH based on feasibility comments above and additional regulatory requirements for pressurized vessels, transport of pressurized product, and added safety processes.

VI. Level of agreement within the work group for this mitigation option General agreement within working group members that the use of gas blanket technology in the Four Corners areas is economically unfeasible and an unlikely source for voluntary adoption.Oil & Gas: Exploration & Production – Tanks

11/01/07 85 

### Mitigation Option: Installing Fl oating Roof Tanks on Tanks in the Four Corners Region

I. Description of the mitigation option This option involves using floating roof tanks on crud e oil and condensate tanks so as to prevent the loss

of emissions that result from crude oil or condensate st ored in the tank. The air quality benefits would be to minimize VOC losses to the atmosphere and if sufficient gas were present, there would be minimal economic benefits. However, the use of floating roof tanks on smaller tanks instead of fixed roof tanks do not reduce the emissions. The emissions actually increase.

Economic burdens are substantial since these un its are costly to install and maintain.

There should not be any environmental justice issues associated with installing and operating these units in socio-economically disadvantaged communities.

II. Description of how to implement A. Mandatory or voluntary: The implementation of measures to implement floating roof tanks on tank batteries are envisioned as “voluntary” measures since th e feasibility of floating roof tanks in the Four Corners area is negative. At certain facilities in th e country where tanks are considerably larger are commonly mandated by the respective Air Quality Control agency as BACT or LAER. The common

sizes of tanks in the Four Corners area will not bene fit economically or in em ission reductions through installation of floating roof tanks. Generally , emissions will increase if floating roofs are installed on these small tanks. Therefore, this mitig ation does not have merit for the Four Corners area and is recommended not to be implemente d either voluntary or mandatory. B. Indicate the most appropriate agency (ies) to implement : NMED, Colorado Air Pollution Control

Division.

III. Feasibility of the option

A. Technical: The use of floating roof tanks on tank ba tteries is technically feasible, however, not currently available for smaller sized tanks.

B. Environmental: The environmental benefits of reduced VOC pollution are well documented for larger tanks; however the documentation on smaller tanks with fixed roofs indicates an increase in emissions.

C. Economic: The use of floating tank roofs for preven ting the working loss emissions from produced crude oil/condensate is not economically feasible.

IV. Background data and assumptions used 1. Tank batteries containing crude oil and condensate are necessary in NM and Co lorado due to the lack of pipeline infrastructure to pipe the fluids directly to refineries. 2. The minimal production levels for most wells make the use of floating rank roofs economically

infeasible.

V. Any uncertainty associated with the option (Low, Medium, High) Low

VI. Level of agreement within the work group for this mitigation option

. General agreement within working group members is that the use of floating tank roofs in the Four Corners areas is economically infeasible a nd an unlikely source for voluntary adoption.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 86 

### EXPLORATION & PRODUCTION: DE HYDRATORS/SEPARATORS/HEATERS

Mitigation Option: Replace Glycol Dehydrators with Desiccant Dehydrators

I. Description of the mitigation option Desiccant dehydrators utilize moisture-absorbing salts to remove water from natural gas. Desiccants can be a cost-effective alternative to glycol dehydrators. Additionally, there are only minor air emissions from desiccant systems.

Desiccant dehydrators are very simple systems. Wet gas passes through a “drying” bed of desiccant tablets (e.g., salts such as calcium, potassium or lith ium chlorides). The tablets pull moisture from the gas, and gradually dissolve to form a brine solutio n. Maintenance is minimal - the brine must be periodically drained to a storage tank, and the desiccant vessel must be refilled from time to time. Often, operators will utilize two vessels so that one can be u sed to dry the gas when the other is being refilled

with salt.

Desiccant dehydrators have the benefit of grea tly reducing air emissions. Conventional glycol dehydrators continuously release methane, vol atile organic compounds (VOC) and hazardous air pollutants (HAP) from reboiler vents; methane from pneumatic controllers; CO 2 from reboiler fuel; and

CO 2 from wet gas heaters. The only air emissions from desiccant systems o ccur when the desiccantholding vessel is depressurized and re-fille d – typically, one vessel volume per week. 1 Some operators have experienced a 99% decrease in CH 4 /VOC/HAP emissions when switching over to a desiccant

system. 2

Other potential benefits of desiccant dehydrators in clude: reduced ground contamination; reduced fire hazard; low maintenance requirements (because ther e are no moveable parts to be replaced and maintained); and the elimination of an external power supply. 3

Solid desiccants are commonly used at centralized natural gas plants, but glycol dehydrators are still the most popular form of dehydration used in the field. 4 Most probably this is because there are particular conditions under which desiccant dehydrators work best:

• The volume of gas to be dr ied is 5 MMcf/day or less. Many wells in the San Juan Basin average less than 5 MMcf/day, 5 so this should not be a constraint to using desiccant systems.

• Wellhead gas temperature is low (< 59o F for CaCl and < 70o for LiCl) . If the inlet temperature of the gas is too high, desiccants can form hydrates that precipitate from the solution and cause caking and brine drainage problems. It is possible to cool or compress gas to the appropriate temperatures, but this increases the cost of the desiccant system.

• Wellhead gas pressure is high (> 250 psig for CaCl and >100 psig for LiCl).

II. Description of how to implement A. Mandatory or voluntary Where feasible, it should be mandatory, since it is both cost effective and virtually eliminates air emissions from field dehydrators. Differing opinion: Cost is prohibitive for replacement of existing systems but applicable for new installations as determined on a case-by-case evaluation. B. Indicate the most appropriate agency(ies) to implement Dehydration is not a down-hole issue, therefore, is not the sole purview of the oil and gas commissions. Furthermore, this option relates specifically to mi nimizing air emissions. Thus, the most appropriate agencies to implement this option would be the envi ronment/health agencies in the different states.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 87 Differing opinion: The Federal area source MACT rules address glycol dehydrators a nd require controls for those whose size and throughputs justify control. This regulation was carefully considered and evaluated by EPA prior to finalization and should not be exceeded without careful analysis and justification.

III. Feasibility of the option

A. Technical Desiccant dehydration is currently feasible under certain operating conditions (i.e., temperature and pressure of inlet gas). It may be possible to expand the applicability with add-on technologies (e.g., autorefrigeration units to chill the inlet gas). 6
Differing opinion: On March 20, 2007 at the NMOCD Greenhouse Gas meeting held in Santa Fe, NM, an operator stated during his presentation that based on their company’s experience with salt dehydration in Wyoming, they are removing all salt dehydrators from service. Although the economics and technical feasibility initially looked very favorable, they have found salt slippage and ot her operational concerns very problematic with no technical solutions to date. Thus this method of dehydration is currently not as viable for their operations. This technology needs to be thoroughly considered before adoption – although it looks good initially, long-term use has not proven to be sustainable.

B. Environmental

Under some environmental conditions (e.g., high temperatures) this option becomes less feasible. Wastewater by product would need to handled, dispo sed of or re-injected. In the CBM areas of Colorado the gas is predominately methane and the gas is relati vely dry and requires little dehydration. In this case

VOC emissions are minimal. Conventio nal production in New Mexico also has very little moisture in the gas and little dehydration is required. As a result of th e type of production in this region it is likely that dehydration emissions are not significant and the use of such alternative technology may not be

warranted.

C. Economic For new dehydration systems, desiccant systems have b een shown to be a lower cost alternative (both for capital and operating costs) than glycol dehydrators. 7 The payback period to replace an existing glycol dehydrator with a desiccant system has been shown to be less than 3 years. 8 The economics stated are only valid for a small range of temperature, pressu re, and water content combinations. Desiccant dehydration for hot, low pressure, or high water content gas streams is not cost effective when compared to glycol dehydration. Differing opinion : Increased operational costs for the desiccan t, storage, and handling/disposal of

wastewater should be factored in to the economics.

IV. Background data and assumptions used See endnotes.

V. Any uncertainty associated with the option Low. Differing opinion: MEDIUM-HIGH based above comments regarding generation of wastewater, disposal, and recent operational experiences in Wyoming.

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to the other Task Force work groups

Notes: 1. U.S. Environmental Protection Agency. Natura l Gas STAR Program. “Lessons Learned - Replacing Glycol Dehydrators with Desiccant Dehydrators.” p. 5. http://epa.gov/gasstar/pdf/lessons/ll_desde.pdfOil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 88 2. U.S. Environmental Protection Agency. Natura l Gas STAR Program. “Lessons Learned - Replacing Glycol Dehydrators with Desiccant Dehydrators.” p. 1. http://epa.gov/gasstar/pdf/lessons/ll_desde.pdf 3. Acor, L. Design Enhancements to Eliminat e Sump Recrystalization in Zero-Emissions NonRegenerative Desiccant Dryer. In: The Tenth In ternational Petroleum Environmental Conference, Houston, TX. November 11-14, 2003 http://ipec. utulsa.edu/Conf2003/Pa pers/acor_78.pdf 4. Smith, Glenda, American Petroleum Institute, written comments to Dan Chadwick, USEPA/OECA, September 22, 1999. In. EPA Office of Compliance. Oct. 2000. Sector Notebook Project - Profile of the Oil and Gas Extraction Industry. EPA/310-R-99-006. p. 31 5. Lippman Consulting. May 16, 2005. “Productio n levels increase in San Juan Basin,” Energy Quarterly. http://www.businessjournals.com/ artman/publish/article_898.shtml 6. U.S. EPA. Natural Gas Star. Replace Glycol Deh ydrator with Separators and In-Line Heaters. PRO

Fact Sheet No. 204. http://www.epa.gov/gasstar/pdf/pro_pdfs_eng/re placeglycoldehydratorwithseparators.pdf Auto-refrigeration has been used in other oilfield applications, such as chilling gas to enhance water condensation and separation. 7. U.S. Environmental Protection Agency. Natura l Gas STAR Program. “Lessons Learned - Replacing Glycol Dehydrators with Desiccant Dehydrators.” p. 16. http://epa.gov/gasstar/pdf/lessons/ll_desde.pdf For a system processing 1 MMcf/day natural gas, operating at 450 psig and 47 F: Total implementation (capital plus installati on): $22,750 (desiccant) vs. $35,000 (glycol) Total annual operating costs: $3,63 3 (desiccant) vs. $4,847 (glycol) 8. U.S. Environmental Protection Agency. Natura l Gas STAR Program. “Lessons Learned - Replacing Glycol Dehydrators with Desiccant Dehydrators.” p. 17. http://epa.gov/gasstar/pdf/lessons/ll_desde.pdf This payback period was reported fo r a glycol dehydrator system that was replaced with a two-vessel desiccant dehydration system.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 89 

### Mitigation Option: Installation of Insulation on Separators

I. Description of the mitigation option This option involves modifying existing and installing new separators that are in sulated so as to reduce fuel usage. The air quality benefits would be to minimize combustion emissions to the atmosphere (NOx, CO, NMHC).

Economic burdens are significant but not insurmountable if the cost recovery factor from reduced fuel usage over the anticipated life of the uni t shows a positive return on investment.

There should not be any environmental justice issues associated with installing and operating these units in socio-economically disadvantaged communities. Differing opinion: This conclusion requires adequate suppor t that is not included in this option.

II. Description of how to implement A. Mandatory or voluntary: The implementation of measures to implement insulated separators and vessels are envisioned as “voluntary” measures since th e feasibility of installing insulation on new units or retrofitting existing units must be evaluated fo r a positive Net Present Value (NPV) or Return on Investment (ROI) in the Four Corners area. If the NPV or ROI meets a company’s investment targets, then utilization of this technology should be enc ouraged as a best practice. There are no existing mandates by the respective Air Quality Control agenci es to require insulated vessels as BACT. Since the

Four Corners area is not in ozone non-attainment and the cost economics will not always justify

installation of insulation for economic benef it, a voluntary approach is recommended. B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: The application of insulation to separators, tanks, or other heated vessels is technically feasible. Currently some companies are insulating newly installed on production separators and larger produced water tanks on a case-by-case basis.

B. Environmental: The environmental benefits of redu ced NOx, CO, and NMHC pollution are well

documented. Differing opinion: It is unclear how much insulation woul d cut fuel consumption and consequently

reduce emissions. The emissi ons from well-site production units are very small (the units are very small) and not a significant component of the regional NOx budget. Insulation of these units would make a small reduction in a very small number.

C. Economic: The application of insulation to separators, tanks, or other heated vessels for reducing fuel usage and minimizing combustion emissions from separators, tanks, or other heated vessels are economically feasible where the there is payback that meets the respective companies targets for investments (i.e., ROI or NPV). For older units or vessels where the remaining life of the equipment is limited, the economics may not justify the applicati on of insulation. Costs basis and frequency of maintenance and ultimate replacement of both blow n and wrapped insulation should be identified.

IV. Background data and assumptions used

Most fired units in the Four Corners area are u tilized during the time period from November through March to achieve their objective.

V. Any uncertainty associated with the option (Low, Medium, High) Low. Differing opinion: High in terms of emission reductions.

VI. Level of agreement within the work group for this mitigation option TBD.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 90 

### Mitigation Option: Portable Desiccant Dehydrators

I. Description of the mitigation option Desiccant dehydrators utilize moisture-absorbing salts (e.g., calcium, potassium or lithium chlorides) to remove the water from natural gas.

Glycol dehydrators may be more suitable than desicc ant systems in some field gas dehydration situations (e.g., when inlet gas has a high temperature and low pr essure). But glycol dehydrators require regulator maintenance for optimal performance. During maintena nce periods production wells are either shut-in or vented to the atmosphere (rather th an running wet gas into the pipeline ). Venting is especially popular for low-pressure wells, because it can be difficult to resume gas flow once they are shut in.

Portable desiccant dehydrators can be brought on-site during glycol dehydrator maintenance (or breakdown) periods. This allows the gas to be processed and sent to the pipeline, rather than requiring the well to be shut-in, or the gas to be vented. These por table dehydrators can also be used to capture and dehydrate gas during “green completion” operations.

The benefits of utilizing portable desiccant dehydr ators are: the ability to continue producing a well during glycol dehydrator maintenance; the eliminati on of methane, VOCs and HAPs that would otherwise be vented while glycol dehydrators are being serviced.

II. Description of how to implement A. Mandatory or voluntary Voluntary at this point in time. There are technologies that would result in much more significant air

emissions reductions that should ha ve higher regulatory priority. Differing opinion: On March 20, 2007 at the NMOCD Greenhouse Gas meeting held in Santa Fe, NM, an operator stated during his presentation that based on their company’s experience with salt dehydration in Wyoming, they are removing all salt dehydrators from service. Although the economics and technical feasibility initially looked very favorable, they have found salt slippage and ot her operational concerns very problematic with no technical solutions to date. Thus this method of dehydration is currently not as viable for their operations. B. Indicate the most appropriate agency(ies) to implement Environment/Health Departments, which have the responsibility for the regulation of air quality.

III. Feasibility of the option

A. Technical A portable desiccant dehydrator requires a truck that has been modified to house the dehydrator; and ancillary equipment (e.g., piping) to re-route gas flow from the glycol to the desiccant dehydrator. See the discussion of technical feasibility in the desiccan t dehydration option paper – the same comments and issues apply here.

B. Environmental Desiccant dehydration systems wo rk best under certain gas temperature and pressure conditions. Wastewater by product would need to handled, dispo sed of or re-injected. In the CBM areas of Colorado the gas is predominately methane and the gas is relative ly dry gas and requires little dehydration. In this case VOC emissions are minimal. Conventional producti on in New Mexico also has very little moisture in the gas and little dehydration is required. As a result of the type of production in this region it is likely that dehydration emissions are not significant and th e use of such alternative technology may not be

warranted.

C. Economic Capital cost of a 10-inch portable desiccant dehydrator is estimated to be greater than $4,000. Operating costs (e.g., labor, transportation, set-up and decommissioning) are on the order of $5,000/yr.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 91 Differing opinion: Cost is prohibitive for replacement of existing systems but applicable for new installations as determined on a case-by-case evaluation. Increased operational costs for the desiccant, storage, and handling/disposal of wastewater should be factored in to the economics.

One operator reports that portable desiccant dehydr ators are economical when used on gas wells that produced more than 15.6 Mcf/day.

Obviously, a company would get the most economic be nefit from owning this equipment if the equipment was kept in continual operation – i.e., move d from one site immediately to another.

IV. Background data and assumptions used All information in this mitigation option comes from: U.S. EPA. Portable Desiccant Dehydrators. PRO

Fact Sheet No. 207. Available at: http://www.epa.gov/gasstar/pdf/pro_pdfs_eng/portabledehy.pdf

V. Any uncertainty associated with the option TBD. Differing opinion: MEDIUM-HIGH based above comments regarding generation of wastewater, disposal, and recent operational experiences in Wyoming.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other Task Force work groups None at this time.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 92 

### Mitigation Option: Zero Emission s (a.k.a. Quantum Leap) Dehydrator

I. Description of the mitigation option Conventional glycol dehydrators route natural gas through a contactor vessel containing glycol, which absorbs water (and VOCs, HAPs) from the gas. Typica lly, gas-driven pumps are then used to circulate glycol through a reboiler/stripper colu mn, where it is regenerated, then sent back to the contactor vessel. Distillation and reboiling removes VOCs, HAPs and ab sorbed water from the glycol, and releases these compounds through the “still column” vent as vapor. C onventional glycol dehydrators vent directly to the atmosphere. Add-on technologies, such as therma l oxidizers, can reduce the amount of methane and VOCs that are vented, but result in increased NO

x , particulate matter and CO emissions. 1

Natural gas dehydration is the third largest source of methane emissions and causes more than 80% of the natural gas industry’s annual HAP and VOC emissions. 2 In the CBM areas of Colorado the gas is predominately methane and the gas is relatively dry gas and requires little dehydration. In this case VOC emissions are minimal. Conventional production in New Me xico also has very little moisture in the gas and little dehydration is required. As a result of the type of production in this region it is likely that dehydration emissions are not significant and the use of such alternative technology may not be

warranted.

The zero emissions dehydrator combines several te chnologies that lower emissions. These technologies eliminate emissions from glycol circulation pumps, gas strippers and the majority of the still column

effluent.

• Rather than being released as vapor, the water and hydrocarbons are collected from the glycol still column, and the condensable and non-condensable co mponents are separated from each other. The two primary condensable products are wastewater, which can be disposed of with treatment; and hydrocarbon condensate, which can be sold. The non-condensable products (m ethane and ethane) are used as fuel for the glycol reboiler, inst ead of releasing them to the atmosphere.

• A water exhauster is used to produce high glycol co ncentrations without the use of a gas stripper.

• Methane emissions are further reduced by using el ectric instead of gas-driven glycol circulation

pumps.

Benefits of this technology include:

• Elimination of methane emissions. 3

• Elimination of virtually all VOCs (reduction fro m multiple tons per year to pounds per year. 4

• Has a HAP destruction efficiency of greater than 99%. 5

• Reduces emissions of particulate matter, sulfur dioxide, NO

x or CO emissions (these compounds are emitted when thermal oxidation, a competing method of reducing glycol dehydrator VOC emissions, is used).

• Eliminates the Kimray pump, which is typically u sed to circulate glycol. Kimray pumps require extra gas (which is eventually vent ed to the atmosphere) for pump power. 6

• Significantly reduces fuel requirements for glycol reboiler. Natural gas that was used for this purpose can now be sent to market.

• Results in collection of conden sate, which can be sold.

II. Description of how to implement A. Mandatory or voluntary The zero emissions dehydrator system offers incredible reductions in emissions. States that are experiencing air quality problems could make this a mandatory technology, and achieve large reductions in VOC, HAP and methane emissions.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 93 Differing opinion: Previous statement requires supporting do cumentation and quantification of ‘tradeoff’ pollutants. B. Indicate the most appropriate agency(ies) to implement Dehydration is not a down-hole issue, therefore, is not the sole purview of the oil and gas commissions. Furthermore, this option relates specifically to mi nimizing air emissions. Thus, the most appropriate agencies to implement this option would be the e nvironment/health agencies in the different states.

III. Feasibility of the option

A. Technical The operation of the glycol circulation pump requires electric utilities or an engine generator set. The use of electric pumps (rather than fossil fuel driven pumps) will minimize NO

x , CO, CO 2 , SO 2 emissions at the wellhead, but will result in some emissions at electrical generation source (e.g., coal-fired power plant).

Zero emissions dehydrators can be newly installe d, and existing dehydrators can be retrofitted by modifying the gas stream piping and using a 5 kW engine-generator for electricity needs. 7 This requires a fuel or power source, for which associated emissions need to be quantified.

B. Environmental Environmental benefit for this mitig ation option needs to be defined.

C. Economic 8
Capital costs of a zero emissions dehydrator are similar to the costs of installing a conventional dehydrator equipped with a thermal oxidizer (>$10,00 0). Operating and Maintenance costs are greater than $1,000 per year, but lower than the maintenance costs for conventional glycol dehydrators.

If operators were to install zero emissions dehydrator s, EPA estimates that the payback to occur in less than a year. Differing opinion : This presumes the ability to recover the hydrocarbons for sales – which is not without significant challenges and technical difficulties.

IV. Background data and assumptions used

The calculations of methane, VOC and HAP emissions from the zero emissions dehydrator were based on a dehydrator that processed 28 MMcf/day. 9 Other assumptions are contained in the endnotes.

If we had emissions data for glycol dehydrators from th e San Juan Basin, we could provide a more accurate (and basin-specific) comparison of me thane, VOC and HAP emissions from conventional dehydrators versus emissions from zero emissions dehydrators.

V. Any uncertainty associated with the option TBD.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other Task Force work groups None at this time.

Notes: 1. Permit renewal application by Centerpoint Ener gy Gas Transmission Co. to Louisiana Department of Environmental Quality. AI# 26802. March, 2005. Available at: http://www.deq.louisiana.gov/apps/pubNotice/s how.asp?qPostID=2335&SearchText=centerpoint&s

tartDate=1/1/2005&endD ate=7/6/2006&category=Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 94 The application includes estimated emissions scenario s for controlling glycol dehydrator still column

vent emissions with or without thermal oxidation. 2. McKinnon, H.W. and Piccot, S.D. 2003. “Emi ssions control of criteria pollutants, hazardous pollutants, and greenhouse gases, Natural Gas De hydration, Quantum Leap Dehydrator.” Environmental Technology Verification Program, Jo int Verification Statement. U.S. EPA and

Southern Research Institute. Available at: http://www.epa.gov/etv/pdfs/vrvs/03_vs_quantum.pdf

3. ibid. 4. Rueter, C.O., Reif, D.L. and Myers, D.B. 19 95. Glycol dehydrator BTEX and VOC emissions testing results at two units in Texas and Louisian a. U.S. EPA Air and Energy Engineering Research Laboratory. Project No. EPA/600/SR-95/046. A study of two glycol dehydrators, processing 3.6 an d 4.9 million standard cubic feet of gas per day, were found to have VOC emissions of approxima tely 19 and 37 tons of VOC/year, respectively. Tests run on the Zero Emissions Dehydrator, processing 28 million standard cubic feet of gas per day, resulted in average emissions of 0.0003 lb/h (2.6 lbs/yr). This is a dramatically lower amount of VOC emissions than conventional glycol dehydrators. 5. McKinnon, H.W. and Piccot, S.D. 2003. (See Note 2) 6. Fernandez, R., Petrusak, R., Robins, D. and Zavodil, D. June, 2005. “Cost-effective methane

emissions reductions for small and midsize na tural gas producers,” Journal of Petroleum Technology. Available at: http://www.icfi.com/Markets/Environment/doc_files/methaneemissions.pdf 7. U.S. EPA. “Zero emissions dehydrators, ” PRO Fact Sheet No. 206. Available at: http://www.epa.gov/gasstar/pdf/pro_pdfs_eng/zeroemissionsdehy.pdf 8. All of the economic information comes from: U.S. EPA. (see Note 7) 9. McKinnon, H.W. and Piccot, S.D. 2003. (See Note 2)Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 95 

### Mitigation Option: Venting versus Flarin g of Natural Gas during Well Completions

I. Description of the mitigation option Both venting and flaring of natural gas result in the release of greenhouse gases, hazardous air pollutants (HAPs) and others.

The venting of natural gas primarily releases methan e, a greenhouse gas. Depending on the composition of the gas, venting will release other hydrocarbons su ch as ethane, propane, buta ne, pentane and hexane. In some locations, natural gas contains the EPA-d esignated HAPs benzene, toluene, ethyl benzene and xylenes (BTEX). Both hexane (also a HAP) and the BTEX compounds are present in San Juan Basin natural gas, typically accounting for 0.3 - 0.6 % of the natural gas composition. 1
Differing opinion : This is only true for the conventional pr oduction. Coal bed methane does not contain appreciable amounts of VOCs or HAPs. Depending on the formation, natural gas may also contain nitrogen, carbon dioxide or sulfur compounds, such as hydrogen sulfide (H 2 S), which is a highly toxic gas. In the New Mexico portion of the San Juan Basin, there are at least 375 gas wells, from at least five different producing formations, that contain hydrogen sulfide. 2

Flaring is used as a means of converting natural gas constituents into less hazardous and atmospherically reactive compounds. The main purpose for flaring is fo r process safety reasons. Flaring is required when completing a well for two reasons: (1) the initial gas a nd liquids produced by most wells does not meet the gas gatherer’s (pipeline’s) quality requirements, and (2) the flare is the primary safety device in the event of an overpressure or equipment failure. The objective for both industry and the public is to minimize flaring where possible for bot h environmental and economic reasons

. The assumption is that combustion processes associated with flares efficiently converts hydro carbons and sulfur compounds to relatively innocuous gases such as CO 2 , SO 2 , and H 2 O.

While industrial flares associated with processes such as refineries have the potential to be highly efficient (e.g., 98-99%), the few studies that have been conducted on oil and gas “field flares” have found much lower efficiencies (62-84%). 3 Fields flares without combus tion enhancements (e.g., knockout drums to collect liquids prior to entering the flare; flame retention devices; pilots) have a much lower efficiency compared to properly designed and operated industrial flares. 4 Other factors, such as improper liquids removal, 5 low heating value of the fuel, 6 flow rate of gas, 7 and high wind speeds, 8 also decrease the combustion efficiency of flares. Differing opinion : The one study cited is the only flare study that found low destruction efficiencies when burning production type gas streams. A number of other studies have confirmed destruction efficiencies >98% - which is the EPA guidance. A cooperative study, known as the international flare consortium study, is underway now and is testing d estruction efficiencies across a wide range of gas types, flare types, and conditions.

There is a dearth of information on combustion effi ciencies for flares used during well completion events, but given the fact that these flares are more rudiment ary than industrial or even solution gas flares, it is highly possible that they have even lower combustion efficiencies. Differing opinion: There are a number of very well done flare studies published.

When flares burn inefficiently, a host of hydrocar bon by-products that include highly reactive VOCs and polycyclic aromatic hydrocarbons, may be formed. 9 Leahey et al. (2001) found more than 60 hydrocarbon by-products, including known carcinogens such as benzene, anthracene and benzo(a)pyrene, downwind of a natural gas flare estimated to be operating at 65% combustion efficiency. 10 The inefficient burning of hydrocarbons also produces soot (particulate matter). 11 Additionally, nitrogen oxides are formed during the combustion process, even if the flare gas does not contain nitrogen. 12Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 96 Differing opinion: The one study cited is the only flare study that found low destruction efficiencies when burning production type gas streams. A number of other studies have confirmed destruction efficiencies >98% - which is the EPA guidance. A cooperative study, known as the international flare consortium study, is underway now and is testing d estruction efficiencies across a wide range of gas types, flare types, and conditions.

See the Endnotes for a table that summarizes the poten tial health and environmen tal effects related to compounds released during flaring and venting. 13
Differing opinion: Not having access to the original table(s), it appears that errors may have occurred when it was adapted given the unwarranted combinat ion of gas constituents and combustion products in one table and some obvious flaws (i.e., VOCs, SO2 an d NOx contributing to particulate pollution but not aggravating respiratory conditions).

Flares operated during well completion activities handle e normous volumes of gas, which is either vented or flared over a short period of time. The amounts of HAPs and VOCs produced during a typical well completion in Wyoming have been calculated. It h as been estimated that a single well completion event, which lasts an average of 10 days, releases:

• 115 tons of VOCs, and 4 tons of HAPs (assumption: 100% venting); or

• 86 tons VOCs, and 3 ton HAPs (assumption: half of the gas is flared per completion, and the flare operates at 50% efficiency). 14
Differing opinion: Many completions in Wyoming – particularly those with gas flow rates in the 4 MMSCF/day range suggested above – are complete d using flareless completion techniques which significantly reduces volume flared (75 to 90% reduction) . However, use of these techniques is limited to those areas where the reservoir pressure is high enough to clean up the well and get the gas into the pipeline.

While it is clear that flaring reduces the volume (mas s) of VOCs and HAPs, questions remain, such as: what are the particular VOC and HAP compounds rel eased during both venting and flaring; what are the concentrations of these compounds in ambient air; 15 and can well completion flares somehow be designed (e.g., better liquid removal, lower gas flow ra tes going to the flare) to more effectively destroy hazardous compounds.

For a true assessment of the relative benefits of fl aring vs. venting (especially with respect to human health), there is a need for a better assessment of venting/flaring emissions from well completions in the

San Juan Basin. This assessment should determ ine both volumes of emissions, and provide a characterization of VOCs, HAPs and other com pounds emitted (volumes and species) during well completion venting and flaring.

II. Description of how to implement Using methods similar to those used in Wyoming, ca lculations could be perform ed to estimate the amount of VOCs and HAPs released from flaring and ventin g during well completion events in the San Juan Basin. Information requirements include:

• volume of gas released (vented or flared) per well completion

• VOC and HAP weight % of the natural gas

• estimates of combustion efficiency of flares

• estimates of how often flares are extinguished (resulting in venting of gas)

Monitoring downwind of sites that are flaring a nd/or venting is needed, to better characterize concentrations and species of VOCs and HAPs, as well as other flaring by-products.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 97 A. Mandatory or voluntary Initially, it could be a voluntary initiative, but if that does not produce data or results there may need to be mandatory reporting and monitoring requirements.

B. Indicate the most appropriate agency(ies) to implement State oil and gas commissions could require the reporting of well completion emissions volumes; and environment/health departments woul d be the appropriate agencies to require monitoring of venting and flaring emissions.

III. Feasibility of the option

A. Technical Emissions volumes from well completions have been determined for Wyoming, so presumably it is technically feasible to determine volumes for the San Juan Basin. If the data do not exist, perhaps the monitoring work group could work with industry to calculate or develop estimates of these volumes specific to the San Juan Basin.

Researches in Alberta have been able to determ ine combustion by-products using on-site analytical equipment or through absorbent samplers fo r confirmatory analyses by combined gas chromatography/mass spect rometry. Flare combustion efficiency were then calculated using a carbon mass balance of combustion products identified in the emissions. See Strosher (1996), Endnote 4.

B. Environmental

None.

C. Economic Emissions volumes from well completions: low cost. The identification of compounds emitted during venting and combustion: unknown.

IV. Background data and assumptions used See Endnotes Section.

V. Any uncertainty associated with the option High uncertainty: depends on willingness of industry and regulators to undertake the necessary data

collection.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups None.

Notes: 1. Proportions calculated based on data from: Mans ell, G.E. and Dinh, T. (ENVIRON International). September 2003. Emission Inventory Report - Air Qu ality Modeling Analysis For The Denver Early Action Ozone Compact: Development of the 2002 Base Case Modeling Inve ntory. p. 3-5. http://apcd.state.co.us/documen ts/eac/2002%20Modeling%20EI.pdfOil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 98 Table 3-5. Average gas profiles (% compositi on) by formation for the San Juan Basin

Mesa

Verde Dakota Pictures

Cliffs Gallup

Nitrogen 0.212 1.603 0 0.965

Carbon Dioxide 1.388 1.034 1.403 0.639

Methane 84.372 74.979 87.736 76.944

Ethane 8.221 12.163 6.373 10.823 Propane 3.19 6.488 2.651 6.552
Butanes 1.432 2,532 1,148 2.551

Pentanes 0.727 0.765 0.418 0.948

Hexanes 0.459 0.437 0.270 0.578

Benzene 0.0145 0.016 0.003

Toluene 0.00706 0.003 0.0014 Ethyl Benzene 0.00037 0.0001 0.0002 Xylene 0.002 0.0006 0.001 Calculated VOC and HAP content (not in original chart) Average

for all

formations HAPS (BTEX + hexane) 0.483 0.457 0.276 0.578 0.4483 VOCs (C1-C4) 97.94 96.93 98.33 97.82 97.753

2. Hewitt, J. (Bureau of Land Management). 2005. “H2S Occurrences San Juan Basin,” a presentation at Hydrogen Sulfide: Issues and Answers Workshop. http://octane.nmt.edu/swpttc/proceedings/H2S_05/BLM_H2S_SanJuanBasin.pdf 3. Strosher, M. 1996. Investigations of Flare G as Emissions in Alberta. Alberta Research Council,

November 1996. Strosher (1996) found flaring efficiencies of 62-71% and 82-84% for sweet and sour gas flares, respectively. The sweet gas had a higher liquid hydrocarbon content than the sour gas being flared. Leahy et al. (2001, citation in Endnote 9) observed fl are efficiencies of 68 ±7 % at sweet and sour gas

flares in Alberta. 4. Seebold, J., Davis, B., Gogolek, P., Kostiuk, L., Pohl, J., Schwartz, B., Soelberg, N., Strosher, M., and Walsh, P. 2003. “Reaction Efficiency of Industrial Flares: the perspective of the past.” International Flare Consortium, Combustion Canada ‘03 Paper. http://www.nrcan.gc.ca/es/etb/cetc/ifc/id4_e.html 5. Russell, J. and Pollack, A. (ENVIRON Interna tional). 2005. Final Project Report: Oil And Gas Emission Inventories For The Western States. Report prepared for the Western Governors’ Association. Appendix A, Wyoming Emission Factor Documentation. p. A-2. http://www.wrapair.org/forums/ssjf/documents/e ictts/OilGas/WRAP_Oil&Ga s_Final_Report.122805.pdf When liquid content is too high, flares don’t or won’t ignite. 6. Kostiuk, L.W., M.R. Johnson & R.A. Pr ybysh. 2000 “Recent Research on the Emission from Continuous Flares,” Paper presented at CPANS/PNWIS–A&WMA Conference (Banff, Alberta, April 10- 12). Cited in: Seebold et al. (2003). 7. Strosher, M. 1996. Investigations of Flare G as Emissions in Alberta. Alberta Research Council, November 1996. p. 85. Combustion efficiencies decreased from 70.6% (flow rate of 1 m3/min) to 67.2 % (flow rate of 5-6 m3/min) for sweet gas being flared at an oil tank battery in Alberta. Increasing the flow increased the volatile hydrocarbo ns by about 33%, and the non-volatiles by three

times the concentrations found in the lower volume flow. 8. Leahey, Douglas M., Preston, Katherine and Strosher, Mel. 2001. Theoretical and Observational Assessments of Flare Efficiencies,” Journal of the Ai r & Waste Management Association. Volume 51. p.

1615Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 99 "It has been shown, as well, that flaring can be e fficient only at low wind speeds because the size of the flare flame, which is an indicator of flame effi ciency, decreases with increasing wind speed. Therefore, the flaring process could routinely r esult, during periods of moderate to high wind speeds, in appreciable quantities of products of incomplete combustion such as anthracene and benzo(a) pyrene, which can have adverse implications with respect to air quality." 9. Seebold, J., Gogolek, P., Pohl, J., and Schwartz, R. 2004. “Practical implications of prior research on today’s outstanding flare emissions questions and a r esearch program to answer them,” Paper presented at the AFRC-JFRC 20004 Joint International Combustion Symposium, Environmental Control of Combustion Processes: Innovative Technology for the 21st Century. (Oct. 10-13, 2004; Maui, Hawaii). http://www.nrcan.gc.ca/es/etb/cetc/ifc/id12_e.html For example, during the 1990s, research conducted as part of the Petroleum Environmental Research Forum’s project 92-19 “The Origin and Fate of T oxic Combustion By-Products in Refinery Heaters” showed that even when burning laboratory grade methane “pure as the drifted snow” traces of higher molecular weight compounds not originally present in the fuel are found in the flue gas (e.g., ethylene, propylene, butadiene, formaldehyde , benzene, benzo(a)pyrene and other hydrocarbons in the gas phase up through coronene). Seebold, et al. also report that, “the external combustion of hydrocarbon gas mixtures by any means, including flaring, literally manufactures and subsequen tly emits to the atmosphere traces of all possible molecular combinations of the elemental constituents pr esent either in the fuel or in the air including the ozone precursor highly reactive volatile organi c compounds (HRVOCs) and the carcinogenic hazardous air pollutants (HAPs). 10. Leahey, Douglas M., Preston, Katherine and Strosh er, Mel. 2001. Theoretical and Observational Assessments of Flare Efficiencies,” Journal of the Air & Waste Management Association. Volume 51. p.1614. http://www.awma.org/journal/pdfs/2001/12/Leahey.pdf

Speciated data for combustion products observed downwind of the sweet gas flare using solvent

extraction methods.

Product Volume (mg/m3) Product Volume (mg/m3) Nonane 0.41 9h-fluorene, 3-methyl- 3.05 Benzaldehyde (acn)(dot) 0.53 Phenanthrene 10.01 Benzene, 1-ethyl-2-methyl- 0.13 Benzo(c)cinnoline 2.06 1h-indene, 2,3-dihydro- 0. 34 Anthracene 42.11
Decane 1.72 1h-indene, 1- (phenylmethylene)- 1.94

Benzene, 1-ethynyl-4-methyl- 9.83 9h-fluorene, 9-ethylidene- 0.89 Benzene, 1,3-diethenyl- 1.27 1h-phenalen-1-one 1.861h-indene, 1-methylene- 0.28 4hcyclopenta[def]phenanthrene 3.50

Azulene 21.20 Naphthalene, 2-phenyl- 1.98 Benzene, (1-methyl-2- cyclopropen-1-yl)- 11.47 Naphthalene, 1-phenyl- 1.82

1h-indene, 1-methyl- 1.66 9,10-anthracenedione 0.94 Naphthalene (can)(dot) 99.39 5h-dibenzo[a,d]cycloheptene, 5-methylene- 0.75

Benzaldehyde, o-methyloxime 0.27 Naphthalene, 1,8-di-1- propynyl- 1.14

1-h-inden-1-one, 2,3-dihydro- 0.74 Fluoranthene 51.35 Benzene, 1,1'-(1,3-butadiyne-1,4- diyl)bis- 2.07Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 100 Naphthalene, 2-methyl- 9.25 Pyrene 32.37 Naphthalene, 1-methyl- 6.18 11h-benzo[a]fluorene 2.25 1h-indene, 1-ethylidene- 1.22 Pyrene, 4-methyl- 9.13 1,1'-biphenyl 58.70 Pyrene, 1-methyl- 8.38 Naphthalene, 2-ethyl- 1.87 Benzo[ghi]fluoranthene 10.16 Biphenylene 42.81 Cyclopenta[cd]pyrene 29.77 Naphthalene, 2-ethenyl- 7.32 Benz[a]anthracene 17.33 Acenaphthylene 7.15 Chrysene 2.12 Acenaphthene 2.93 Benzene, 1,2-diphenoxy- 1.94 Dibenzofuran 0.88 Methanone, (6-methyl-1,3- benzodioxol-5-yl)phenyl- 0.95

1,1'-biphenyl, 3-methyl- 0.31 Benzo[e]pyrene 0.71 1h-phenalene 21.01 Benzo[a]pyrene 1.03 9h-fluorene 41.09 Perylene 0.62 9h-fluorene, 9-methyl- 1.07 Indeno[1,2,3-cd]pyrene 0.15 Benzaldehyde, 4,6-dihydroxy-2,3- dimethyl 1.16 Benzo[ghi]perylene 0.26

9h-fluorene, 9-methylene- 1.07 Dibenzo[def,mno]chrysene 0.15

Coronene 0.08

11. U.S. Environmental Protection Agency. 2000. Office of Air Quality Planning and Standards. “Industrial Flares,” AP-42 Fifth Edition. Vol. 1: Stationary Point and Area Sources. p. 13.5-3. Tendency to smoke or make soot is influenced by fuel characteristics and by amount and distribution of oxygen in the combustion zone. All hydrocarbons above methane tend to soot. Soot from industrial flares is eliminated by adding steam or air. Soot emissions factors developed by EPA for industrial flares are: non-smoking flares, 0 micrograms per liter (μg/L); lightly smoking flares, 40 μg/L; average smoking flares, 177 μg/L; and heavily smoking flares, 274 μg/L. 12. K.D. Siegel. 1980l. Degree of Conversion of Flare Gas in Refinery High Flares. Dissertation. University of Karlsruhe, Germany. Cited in: USEPA Office of Air Quality Planning and Standards. 2000. “Industrial Flares,”AP-42 Fifth Edition. Volume 1: Stationary Point and Area Sources. p.13.5-5. Even waste gas that does not contain nitrogen compounds form NO. It is formed either by fixation of atmospheric nitrogen with oxygen, or by the reac tion between hydrocarbon radicals and atmospheric N by way of intermediate states, HCN, CN and OCN.

13. Health and Environmental Effects of Chem icals Released During Venting and Flaring.

VOCs SO2 NOx CO PAHs H2S HAPs SMO

KE/

SOOT

Contributes to particulate pollution

that can cause respiratory illness, aggravation of heart conditions and asthma, permanent lung damage and premature death. FLAR

ING FLAR

ING FLAR

ING FLAR

ING

VENT

ING Aggravates respiratory

conditions

FLAR

INGOil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 101 VOCs SO2 NOx CO PAHs H2S HAPs SMO

KE/

SOOT

VENT

ING VENT

ING Can cause health problems such as

cancer FLAR

ING FLAR

ING FLAR

ING

VENT

ING Can cause reproductive, neurological, developmental, respiratory, immune system, and other health problems. FLAR

ING

VENT

ING Reacts with other chemicals leading to ground-level ozone and smog, which can trigger respiratory problems FLAR

ING FLAR

ING

Reacts with common organic chemicals forming toxins that may

cause bio-mutations FLAR

ING

VENT

ING Affects cardiovascular system and can cause problems within the central nervous system

VENT

ING Causes haze that can migrate to sensitive

areas such as National

Parks FLAR

ING FLAR

ING FLAR

ING FLAR

ING FLAR

ING Contributes to global warming VENT

ING Adapted from: EPA Office of Inspector General. 2004. EPA Needs to Improve Tracking of National Petroleum Refinery Program Progress and Impacts. Appendix D. 14. Russell, J. and Pollack, A. (ENVIRON Interna tional). 2005. Final Project Report: Oil And Gas Emission Inventories For The Western States. Report prepared for the Western Governors’ Association. Appendix A, Wyoming Emission Factor Documentation. p. A-2. http://www.wrapair.org/forums/ssjf/documents/e ictts/OilGas/WRAP_Oil&Ga s_Final_Report.122805.pdf 15. Strosher, M. 1996. Investigations of Flare G as Emissions in Alberta. Alberta Research Council, November 1996. p. 28. Strosher measured concentrations of hydrocarbon compounds emitted from sweet and sour solution gas flares in Alberta, and then predicted ground-level co ncentrations of HAPs at various locations around the well location. Predicted values of some polycyclic ar omatic hydrocarbons in the vicinity of sweet and sour gas flares were comparable to concentrations found in large industrial c ities, while predicted values of hazardous VOCs released during flaring we re below ambient air quality standards.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 102 

### Mitigation Option: Co-location/Ce ntralization for New Sources

I. Description of the mitigation option This mitigation option would involve co-locating and/or centralizing new oil/gas field facilities, including roads, well pads, utilities, pipelines, compressors, power sources and fluid storage tanks, wherever possible, to reduce surface impacts, fugitive dust, engine emissions and gas field traffic.

In general, co-location and/or centralization of ne w facilities would result in overall reductions in surface disturbance, vehicular traffic, and number of facilitie s. Potential benefits from this strategy include fugitive dust reduction (due to decreased traffi c and less overall new surface disturbance), vehicle emission reductions, reduced road maintenance, safer roads as a result of decreased traffic, and oil/gas field engine emission reductions. The potential for redu ced engine emissions is due in part to lowering cumulative horsepower requirements by using larger, more efficient engines, and in part to groups of smaller engines with relatively high emission rates pe r hp/hr being replaced by fewer, larger engines with relatively low emission rates per hp/hr. Implementa tion costs for this mitigation option would fall exclusively on the energy companies, but such costs could be partially offset by the economic benefits of having fewer facilities to construct, maintain and ultimately reclaim.

Tradeoffs include increased impacts at co-located/cen tralized sites. Co-locating well bores on a single pad results in larger pad sizes that may not fit well w ith pre-existing conditions. Centralizing facilities would increase vehicle emissions locally and potentially produ ce local air quality, noise, visual and traffic safety issues. Additionally, aggregating produced water in one location increases the potential for a catastrophic

release.

II. Description of how to implement A. This mitigation option should be implemented on a voluntary basis, with the approach emphasized by the appropriate regulatory agency during the pla nning and permitting processes for oil/gas field facilities and utility corridors (pipelines, power lines, etc.). Consideration should be given to economic and environmental impacts, as well as current and future land management activities. Ideally, oil/gas field operators and regulatory agencies would coordinate on a regular basis to identify development plans that

minimize new construction and maxi mize efficiencies. Cooperation between operators in the same development area would make this option even more effective, but multiple economic and regulatory

constraints exist that make such coordination difficult.

B. State and Federal lands and mine rals management agencies would be able to emphasize this approach at various stages of the planning and permitting pro cess. In addition, State and Federal air regulatory agencies could emphasize this approach if multip le air quality permit applications are submitted concurrently for the same general area.

III. Feasibility of the option

A. Technical : The technology exists today to implement this mitigation option. This option is best suited for areas of known or high potential for economic oil/gas field production. This option can be implemented most effectively when planning for oil/g as field- or lease-wide development activities, such

as in-fill drilling and plans of development for multiple wells.

B. Environmental : Co-location and/or centralization of ne w facilities would generally have numerous

environmental benefits.

C. Economic : Economic feasibility of this option will vary on a project-level basis. Higher initial costs may be offset by overall cost reductions due to fewer facilities to construct, operate and reclaim. Additional cost savings may result because co-located/ centralized facilities can be more efficient than dispersed facilities.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 103 IV. Background data and assumptions used This option is best suited for areas with existing or high potential for economic gas/oil field production.

V. Any uncertainty associated with the option Low. While implementation of this option may cause greater noise, emission, and visual impacts at fewer, co-located/centralized locations, the ove rall effect would be a reduction in oil/gas field environmental impacts.

VI. Level of agreement within the work group for this mitigation option Unknown at this time

VII. Cross-over issues to the other source groups Road-related impacts are an element of this mitig ation option being looked at by the Other Sources Workgroup. Two other mitigation strategies (Optimiz ation/Centralization and Reduced Truck Traffic by Centralizing Produced Water Storage Facilities) look at the compression and produced water facets of this mitigation option in greater detail a nd are presented in the Oil and Gas section of this Task Force Report. Assistance from the Cumulative Effects work group to quantify potential dust, vehicle traffic and overall emission reductions resulting from co-location and/or centralization would be helpful.

VIII. References

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html

http://www.westgov.org/wga/initiatives/coalbed/

http://bogc.dnrc.state.mt.us/website/mtcbm/webmapper_cbm_info_res.htmOil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 104 

### Mitigation Option: Control Glycol Pump Rates

I. Description of the mitigation option Most dehydration systems use triethylene glycol (TEG) as the absorbent fluid to remove water from natural gas. As TEG absorbs water, it also absorb s methane, other volatile organic compounds (VOCs), and hazardous air pollutants (HAPs). As TEG is rege nerated through heating in a reboiler, absorbed methane, VOCs, and HAPs are vented to the atmosphe re with the water, wasting gas and money. The amount of methane absorbed, and used as assist gas for Kimray type pumps, and vented is directly of the TEG Dehydrator, but conti nue to circulate TEG at rates two or three times higher than necessary, resulting in little improvement in gas moisture quality but much higher methane emissions and fuel use. Reducing TEG circulation rates reduce me thane emissions at negligible cost.

Economic burdens are minimal since this practice simply requires the pump rate to be manually adjusted.

II. Description of how to implement A. Mandatory or voluntary: The implementation of lower TEG ci rculation rates should be “voluntary” since the measure would enhance recovery of natu ral gas and reduce emissions. Companies should be receptive to voluntarily implement this measure. B. Indicate the most appropriate agency(ies) to implement : The state Air Quality Divisions should

communicate this information.

III. Feasibility of the option

A. Technical: Controlling TEG circulation rates are technically feasible since it can be achieved by manually setting the pump rate.

B. Environmental: The environmental benefits of reduced VOC pollution are well documented. The reduction of methane, a greenhouse gas, can also be documented. Quantification of emission reductions can be achieved through the use of the GLYCALC model. Due to the low field pressures in the San Juan basin area, most field dehydrators have been removed and dehydration is done at central facilities rather than di spersed locations. Due to this, this option will have very limited applicability and emission reductions associated with it.

C. Economic: The benefits can be quantified by the amount of methane and VOC that is not emitted to the atmosphere and rather sold as product.

IV. Background data and assumptions used A. Gas production fields experience declining pr oduction as pressure is drawn-off the reservoir. Wellhead glycol dehydrators and their TEG circul ation rates are designed for the initial, highest production rate, and therefore, become over-sized as the well matures. It is common that the TEG circulation rate is much higher than necessary to meet the sales gas specification for moisture content. B. The methane emissions from a glycol dehydrator are directly proportional to the amount of TEG circulated through the system. The higher the circul ation rate, the more methane, is vented from the regenerator. Over-circulation results in more methane emissions without significant and necessary reduction in gas moisture content. C. Operators can reduce the TEG circulation rate and subsequently reduce the methane emissions rate, without affecting dehydration perform ance or adding any additional cost.

V. Any uncertainty associated with the option Low.

VI. Level of agreement within the work group for this mitigation option Although a general discussion of this option has not occurred between the working group members, it is doubtful a disagreement about controlling TEG circulation rates would occur.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 105 Source of Information: “ Optimize Glycol Circulation and Install of Flash Tank Separators in Dehydrators”, U.S. EPA Natural Gas Star Program.Oil & Gas: Exploration & Production – Dehydrators/Separators/Heaters

11/01/07 106 

### Mitigation Option: Combustors for Still Vents

I. Description of the mitigation option Most dehydration systems use triethylene glycol (TEG) as the absorbent fluid to remove water from natural gas. As TEG absorbs water, it also absorb s methane, other volatile organic compounds (VOCs), and hazardous air pollutants (HAPs). The TEG is th en distilled to strip water and consequently VOC from the TEG. Vapors and/or liquids in the still vent are typically greater than 90% volume water, with the balance being hydrocarbons alon g with small quantities of carbon dioxi de and nitrogen. The still vent column is typically released to the atmosphere that in cludes emissions of hydrocarbons. It is important to note that gas composition is an important consideration in determining the need to install flares. Some natural gas, such as coalbed methane gas contains little, if any VOC component, and would not result in

VOC emissions.

In order to reduce these emissions, combustion de vices can be installed to combust hydrocarbon emissions, including VOCs, instead of venting them to the atmosphere. The combustion technology typically consists of an enclosed “flare/burner.” It does require a condenser and separator upstream of the combustion device to avoid liquid hydrocarbons routed to the combustion device.

II. Description of how to implement A. Mandatory or voluntary: The requirement for control of emissions from glycol dehydrators is included

in the EPA’s area source Onshore Natural Gas Processing MACT rules that have been proposed/promulgated. After careful analysis, EPA set emission and throughput based criteria to trigger these control requirements. Any control at lower emission or throughput rates should be voluntary. B. Indicate the most appropriate agency(ies) to implement : The state Air Quality Divisions should develop the regulatory program to administer this program.

III. Feasibility of the option

A. Technical: Installing condensers and combustion devices to control emissions from dehydrator still vents is technically feasible since it is already being applied in various locations where controls of these

emissions have been mandated.

B. Environmental: The environmental benefits of reduced VOC emissions are well documented. The reduction of methane, a greenhouse gas, can also be documented. Actual bene fits are dependent on the amount and composition of the gas being dehydrated a nd are highly variable. Little benefit is expected for the San Juan basin due to the lack of field dehydration.

C. Economic: Costs are for a typical condenser and smokeless combustion chamber large enough to service a dehydrator in Wyoming are about $35,000 installed. There are no revenues from the gas as it is destroyed through combustion, and there is a fuel co st of about $1,800 per year for each pilot (at $3 per Mcf of gas).

IV. Background data and assumptions used Wyoming oil and gas presumptive BACT guidance.

V. Any uncertainty associated with the option Low where applicable.

VI. Level of agreement within the work group for this mitigation option Although a general discussion of this option has not occurred between the working group members, it is unknown about the degree of acceptance regarding the use of combustors for still vents.

Source of Information: “Install Flares”

, PRO Fact Sheet No. 905, U.S. EPA Natural Gas Star Program. Gas Research Institute, Control De vice Monitoring of Glycol Dehydrators; Condenser Efficiency Measurements and Modeling, 1997.Oil & Gas: Exploration & Production - Wells

11/01/07 107 

### EXPLORATION & PRODUCTION: WELLS

Mitigation Option: Installation and/or Op timization of a Plunger Lift System

I. Description of the mitigation option

Overview In mature gas wells, the accumulation of fluids in the well-bore can impede and sometimes halt gas production. Fluids are removed and gas flow mainta ined by removing accumulated fluids through the use of artificial lift (such as a beam pump) or enhanced fluid lift treatments or techniques, such as plunger lifts, velocity strings, swabbing, soap injection, or venting the well to atmospheric pressure (referred to as “blowing down” the well). Fluid removal operations , particularly well blow-downs, may result in substantial methane and associated VOC emissions to the atmosphere.

Installing a plunger lift system can be a cost-effective alternative for removing liquids on wells where the well-bore configuration, pressure profiles, and produc tion characteristics enable its application. Plunger lift systems have the additional benefit of potentially increasing production, as well as significantly reducing methane and associated VOC emissions asso ciated with blow-down operations. A plunger lift uses gas pressure buildup in a well to lift a column of accumulated fluid out of the well. The plunger lift system helps to maintain gas production and may reduce the need for other remedial operations.

Air Quality and Environmental Benefits

The installation of a plunger lift system serves as an interim well-bore deliquification methodology for the period between natural flowing lift and full artificia l lift and can yield environmental and production benefits while reducing well blow-dow ns and their associated emissions. The extent and nature of these benefits depend on the individual well characteristics a nd the method of plunger lift control and operation.

New automation systems and control capabilities can improve plunger lift system optimization, monitoring, and control. For example, technologies such as programmable logic controllers and remote transmitter units can allow operators to control pl unger lift systems thorough control algorithms or remotely, without regular field visits. These sy stems can offer enhanced plunger lift operation and effectiveness versus older plunger control systems.

By reducing the need for well-bore blow-down, pl unger lift systems can lower emissions. Reducing repetitive remedial treatments and well work-over ma y also reduce methane and associated emissions. Natural Gas STAR partners have reported annual gas savings averag ing 600 Mcf per well by avoiding blow-down and an average of 30 Mcf per year by eliminating or reducing well work-overs.

Economics Lower capital and operational cost ve rsus installing full artificial lift equipment (such as a beam pump). The costs of installing and maintaining a plunger lift are generally lower than the cost to install and maintain artificial lift equipment.

Lower well maintenance and fewer remedial treatments. Overall well maintenance costs are reduced because periodic remedial treatments such as swabbi ng or well blow-downs are reduced or no longer needed with plunger lift systems.

More effective well-bore deliquification and continuo us production may improve gas production rates and increase efficiency. With proper optimization and cont rol, plunger lift systems can also conserve the well’s lifting energy and increase gas production. Regul ar fluid removal allows the well to produce gasOil & Gas: Exploration & Production - Wells

11/01/07 108 continuously and helps prevent fluid loading that periodically halts gas production or “kills” the well. Often, the continuous removal of fluids results in daily gas production rates that are higher than the production rates prior to the plunger lift installation.

Reduced paraffin and scale buildup. In wells where para ffin or scale buildup is a problem, the mechanical action of the plunger running up and down the tubing ma y prevent particulate buildup inside the tubing. Thus, the need for chemical or swabbing treatments may be reduced or eliminated. Many different types of plungers are manufactured with “wobble-washers” to improve their “scraping” performance.

Other economic benefits. In calculating the economic benefits of plunger lifts, the savings from avoided emissions and enhanced production are only two factors to consider in the analysis. Additional savings may result from lower operational and well work costs.

Tradeoffs Plunger lift systems do fail and can require additional maintenance versus blowi ng wells down. If return velocity is not controlled they may also “launch” through the plunger receiver and cause wellhead failure. Also, dependent on the control systems, they may require regular operator intervention.

Burdens Installation of plunger lift systems can involve substa ntial costs particularly if changes to the well-bore tubulars are required. If adequate control systems and a means to power them are not available on a particular well, their installation will require additional expenditures.

II. Description of how to implement A. Mandatory or voluntary: This option should be voluntary given the restrictions on applicability posed by well-bore configuration, pressure and build-up pr ofile, and production characteristics. Each well must be evaluated for feasibility of plunger lift systems. A large number of wells in the Four Corners area already have artificial lift systems or other enhan ced deliquification techniques already installed. Requiring all wells in the basin to replace other means of enhanced or artificial lift would be logistically and operationally unreasonable. A large percentage of the producing wells in the 4-corners area are already equipped with plunger lift systems. Most operators have an ongoing well evaluation program to determine the appropriate deliquification tec hnology to apply to any particular well. B. Indicate the most appropriate agency(ies) to implement : Non-applicable – voluntary implementation. However, workshops on plunger lift applicability, co ntrol, and operation may enhance implementation.

III. Feasibility of the option A. Technical: The technical considerations necessary for plunger lift systems are well known and plunger lift systems are feasible where the well characteristics enable application. For very low pressure/flow environments, such as portions of the San Juan B asin, operation of plunger lifts may require periodic venting (blow-down) of well-bores to the atmosphere to generate enough differential energy to lift the plunger and associated fluids. Advanced control system s can significantly reduce the need for this type of blow-down but require robust automation capabilities.

B. Environmental: There are no known environmental issues w ith plunger lift implementation and they typically reduce emissions.

C. Economic: the economics of applying plunger lift technolog y to a particular well must be evaluated on a well-by-well basis. For wells where they are a pplicable, plunger lift systems are generally economic.

IV. Background data and assumptions used N/AOil & Gas: Exploration & Production - Wells

11/01/07 109 V. Any uncertainty associated with the option Assuming a well-by-well evaluation of applicabilit y the uncertainty associated with plunger lift implementation should be low. Due to the large num ber of wells already equipped with plunger lift or other enhanced or artificial lift systems the sc ope of available implementation may be limited.

VI. Level of agreement within the work group for this mitigation option Still being evaluated, but based upon info rmation to date it should be high.Oil & Gas: Exploration & Production - Wells

11/01/07 110 

### Mitigation Option: Implementation of Reduced Emission Completions (Green Completions)

I. Description of the mitigation option The “green completions” control method reduces me thane losses during gas well completions. During well completions it is necessary to clean out the we ll bore and the surrounding formation perforations. This is done both after new well completions and afte r well workovers. Operators produce the well to an open pit or tanks to collect sand, cuttings and reservoi r fluids for disposal. Normal practice during this process is to vent or flare the natural gas produced . Venting may lead to dangerous gas buildup, so flaring is preferred where there is no fire hazard or nuisance issue (concerns about smoke, light, noise, etc.). Green completions recover the natural g as and condensate produced during well completions or workovers. This is accomplished using portable e quipment to process the gas and condensate so it is suitable for sale. The additional equipment may in clude more tanks, special gas-liquid-sand separator traps, and portable gas dehydration. The recovered gas is directed through permanent dehydrators and meters to sales lines, reducing venting and flaring. “Green completion” techniques are only applicable where the reservoir pressure and flow is sufficient to clean-up a well bore after completion and still have sufficient pressure to enter the collec tion system/pipeline. With the de pleted status of the conventional

San Juan basin reservoirs and the characteristics of co al bed methane reservoirs; this is not an available option for the SJ basin area.

II. Description of how to implement A. Mandatory or voluntary This process can be mandatory or voluntary.

B. Indicate the most appropriate agency(ies) to implement For the 4 Corners area, State regulatory agencies coul d require green completions through regulation or policy. For example, in the Pinedale, WY area the St ate of Wyoming, BLM, and operators have agreed to minimize flaring operations through use of green co mpletions. FLMs could require this process through stipulations or conditions of approval in lease s and applications for permits to drill.

III. Feasibility of the option

A. Technical The green completion process can apply to the drilling of all natural gas wells, however, a sales line connection and sales agreements need to be arranged before the well drilling is completed. There are operational, access and other considerations that make this a case determination. Differing opinion: This technique is not feasible in the SJ basin – see above. The green completion process has been reviewed by EPA and is listed under “Recommended Technologies and Practices” on EPA’s Natu ral Gas Star Program web site: http://www.epa.gov/gasstar/techprac.htm Differing opinion: This technology may not be applicable in all cases, and needs careful consideration. Different formations typically require different completion techniques that this technology may not be suited to ha ndle. E.g. many operators use compressed air to fracture coal wells. Air mixed with natural gas cannot be shipped to a pipeline due to the high potential for spontaneous combustion under typical pipeline temperatures and pressures. Additionally, oxygen contamination of natural gas causes additional corrosi on risks to gathering lines. Separation of air from natural gas is presently not feasible or part of th e process equipment used in “green completions.”

B. Environmental Nationally EPA has estimated that 25.2 billion cubic f oot (Bcf) of natural gas can be recovered annually using Green Completions - 25,000 million cubic fo ot (MMcf) from high pressure wells, 181 MMcf from low pressure wells, and 27 MMcf from workovers. This reduces emissions of methane (a greenhouse gas), condensates (hazardous air pollutants), and nitr ogen oxides (precursor to ozone formation andOil & Gas: Exploration & Production - Wells

11/01/07 111 visibility degradation) formed when gas is flared. An EPA Gas Star Partner reported an estimated methane emissions reduction, as the total recovered from 63 wells, of 7.4 MMcf per year, which is 70 percent of the gas formerly vented to the atmosphere.

C. Economic A methane savings of 7 MMcf per year based on comp leting 60 wells per year at the average recovery reported by an EPA Gas Star partner. The partner also reported recovering a total of 156 barrels of condensate from the 63 wells, an average of 2.5 barrels per well. The capital costs include additional portable separators, sand traps, and tanks at a cost reported by the partner of $180,000. This equipment would be move d from well-to-well, so amortizing the cost over 10 years and doing 60 wells per year, the annual capita l charges would be under $10,000. Incremental operating costs are assumed to be over $1,000 per year. At a natural gas price of $3 per Mcf and condensate price of $19 per barrel, green completions will pay back the costs in about 1 year. This information is for green completions in the Green Ri ver Basin area of Wyoming and is for much higher rate wells with much higher pressures and energy than the SJ basin wells.

IV. Background data and assumptions used Information on Green Completions comes from EPA’s Natural Gas Star Program web site: http://www.epa.gov/gasstar/techprac.htm

V. Any uncertainty associated with the option Low, if the well is part of an in-fill and a sales line co nnection is available. Ot her situations may not be suitable for green completions. Differing opinion: Very High – this is not a viable option for the SJ basin area – see above.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups None.Oil & Gas: Exploration & Production - Wells

11/01/07 112 

### Mitigation Option: Convert High-Bleed to Low or No Bleed Gas Pneumatic Controls

I. Description of the mitigation option This option would encourage oil and gas producers and pipeline owners and operators to replace or retrofit high-bleed natural gas pneuma tic controls. This option should be considered when replacement of pneumatic controls with compressed instrument air sy stems is not practical or feasible (e.g. no electric power supply). It would enhance EPA’s current effort s in the Natural Gas Star Program and make them specific to the San Juan Basin. This would result in a significant reduction in methane emissions as well as achieve cost savings for the companies.

Pneumatic instrument systems powered by high-pressure natural gas are often used across the natural gas and petroleum industries for process control. Typi cal process control applications include pressure, temperature, liquid level, and flow ra te regulation. As part of normal operation, natural gas powered pneumatic devices release or bleeds gas to the atmosp here and, consequently, are a leading source of methane emissions from the natural gas industry. High–bleed pneumatic devices are defined as those with bleed rates of 6 standard cubic feet per hour ( scfh) or 50 thousand cubic feet (Mcf) per year. An EPA study in 2003 reported the cons tant bleed of natural gas from these controllers was collectively one of the largest sources of methane emissions in the natural gas industry, estimated at approximately 24 billion cubic feet (Bcf) per year in the production sector, 16 Bcf from processing and 14 Bcf per year in the transmission sector. Pneumatic control systems emit methane from tube joints, controls, and any number of points within the distribution tubing network.

Companies have found that the payback period can be less than a year for most retrofits from high-bleed to low-bleed pneumatic controllers. Recent experien ce indicates that up to 80 percent of all high-bleed devices can be replaced with low-bleed equipment or retrofitted. If electric power is available, conversion from natural gas-powered pneumatic control systems to compressed instrument air systems will result in greater methane emissions reductions. However, the investment payback period will likely be longer, and may not be cost effective in some cases.

In compressed instrument air systems, atmospheric ai r is compressed, stored in a volume tank, filtered and dried for instrument use. All other parts of a gas pneumatic system work the same way with air as they do with gas. Existing pneumatic gas supply piping, control instruments, and valve actuators of the gas pneumatic system can be reused in an instrument air system. Reducing methane emissions from pneumatic devices by converting to instrument air systems can yield significant economic and environmental benefits for natural gas companies including:

3⁄4 Financial Return From Reducing Gas Emission Loss es. In many cases, the cost of converting high-bleed to low-bleed pneumatic controllers can be recovered in less than a year.

3⁄4 Lower Methane Emissions

II. Description of how to implement A. Mandatory or voluntary: This program would be voluntary. Due to the fact that almost all high-bleed pneumatics have been replaced by the industry, the economic returns from implementing low bleed systems should motivate producers to implement them . State and Federal agencies can assist by advertising the benefits, as is currently done by EPA’s Natural Gas Star Program. B. Currently most operators have already re placed all high bleed with low bleed systems. C. Indicate the most appropriate agency(ies) to implement: EPA and the State environmental agencies

would extend and enhance EPA’s current efforts to make them specific to the San Juan Basin.Oil & Gas: Exploration & Production - Wells

11/01/07 113 III. Feasibility of the option

A. Technical: These systems are off-the-shelf and proven.

B. Environmental: The environmental benefits of repl acing high-bleed with low-bleed pneumatic controls, in terms of lower methane emissions, have been documented by EPA. Companies reporting to EPA have reduced emissions by 50-260 Mcf per year per controller.

C. Economic: EPA reports that replacing or retrofitting hi gh-bleed units with low-bleed units have a payback of five to 21 months.

IV. Background data and assumptions used See the website for EPA’s Natural Gas Star Program: http://www.epa.gov/gasstar/index.htm

In particular, the lessons learned summaries for low-bleed pneumatics: http://www.epa.gov/gasstar/pdf/lessons/ll_pneumatics.pdf

V. Any uncertainty associated with the option Low. This is proven techno logy with proven benefits.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups Cumulative effects should review oil and gas tasks a nd rank those most effective as priorities over those

less effective or cost effective.Oil & Gas: Exploration & Production - Wells

11/01/07 114 

### Mitigation Option: Utilizin g Electric Chemical Pumps

I. Description of the mitigation option This option involves replacing existing gas drive pump s with solar powered, electric-driven chemical pumps. The air quality benefits would be to minimi ze methane and VOC emissions to the atmosphere (Methane, VOC).

Economic burdens are significant but not insurmountable if the cost recovery factor from reduced fuel usage over the anticipated life of the uni t shows a positive return on investment.

There should not be any environmental justice issues associated with installing and operating these units in socio-economically disadvantaged communities.

Differing opinion: This conclusion requires adequate suppor t that is not included in this option.

II. Description of how to implement A. Mandatory or voluntary: The implementation of measures to install electric-driven, solar powered chemical pumps are envisioned as “voluntary” measures since the feasibility of installing insulation on new units or retrofitting existing units must be ev aluated for a positive Net Present Value (NPV) or Return on Investment (ROI) in the Four Corners area. If the NPV or ROI meets a company’s investment targets, then utilization of this technology should be encouraged as a best practice. There are no existing mandates by the respective Air Quality Control agenci es to require electric drive pumps as BACT. Since

the Four Corners area is not in ozone non-attainme nt and the cost economics will not always justify

installation of insulation for economic benef it, a voluntary approach is recommended. B. Indicate the most appropriate agency(ies) to implement : The states.

III. Feasibility of the option

A. Technical: The purchase and installation of electrically driven chemical pumps is technically feasible. Currently some companies are installing these pumps on a trial basis to assure performance during the

winter months.

B. Environmental: The environmental benefits of re duced Methane and VOC pollution are well

documented.

C. Economic: The use of electric-driven, solar powered chemical pumps is economically feasible where the there is payback that meets th e respective companies targets for i nvestments (i.e., ROI or NPV). For existing older pumps exist on wells that have a futu re limited life, the economics may not justify the application of insulation.

IV. Background data and assumptions used Most chemical pumps in the Four Corners area are utilized year round to achieve their objective.

V. Any uncertainty associated with the option Low.

VI. Level of agreement within the work group for this mitigation option There is general agreement among working group me mbers that the use of electrical chemical pump technology in the Four Corners areas is economically unfeasible and a likely source for voluntary adoption if the economics show a sufficient NPV.Oil & Gas: Exploration & Production - Wells

11/01/07 115 

### Mitigation Option: Solar Power Driven Wellsites and Tank Batteries

I. Description of the mitigation option This option comprises a system of production equi pment and controls powered by solar generated electricity (through Photovoltaic – PV - cells) at g as well production sites that are not served with grid power. In most cases solar power replaces pressurize d fuel gas, which is usually vented to the atmosphere after use. The power s upply consists of solar pa nels and batteries. The solar power is used for electric instruments, controllers, actuators for automatic valves and small additive (methanol) pumps. Optimization consists of selecting the best fit items of hardware, becoming familiar with the strengths and

limitations of all of the individual items as well as the overall system and making modifications to improve performance.

II. Description of how to implement A. Mandatory or voluntary: Mandatory on all new wellsites with gas-assisted chemical injection pumps. Mandatory where economic at existing wellsites. Propose to define a standardized calculation to determine if it is economic. An example borrowe d from the Alberta EUB – Energy & Utilities Board – Directive 60, agreed to by a multi-stakeholder gr oup including the oil & g as industry, includes the following: 1) Before tax basis 2) Point to an agreed upon specific gas forecast report 3) Must have remaining reserves calculation and production forecast (NPV calculated over life of well/production) 4) Only incremental capital costs related to the solar PV skid system may be included 5) Long term inflation based on CPI forecast 6) Discount rate = prime lending rate + 3% 7) Only revenue minus net royalties from incremen tal gas conservation only to be included 8) Economic if NPV before tax > $0

B. Indicate the most appropriate agency(ies) to implement : The States on State land or Federal/Tribe on Indian country.

III. Feasibility of the option

A. Technical: In the past two years an operator in Al berta has installed over 40 of these systems. Supported by operations managers, in strumentation personnel carried out trials with solar systems and electrical equipment to arrive at a “best fit” arrange ment. In summer 2006, this operator carried out a study with outside specialist consultants in energy c onsumption and emissions monitoring to evaluate the performance of the system. The results of the study were very positive, resulting in this operator making their solar PV system the company standard for gas well production. The primary reasons for this are to reduce fuel consumption in producing operations , increase sales gas revenues and reduce vent gas emissions. There are also operators in the US Rocky Mountain area using solar PV systems in comparable ways.

B. Environmental: Reduced VOC emissions and reduced methane emissions (with a global warming potential ~23 times greater than CO2). Quantity of reduction would be dependent on number and bleed rate of pneumatic controllers, a nd size and supply gas use rate of pneumatic pump equipment, being replaced with electrically-powered devices.

C. Economic: Reduced fuel gas consumption so increased gas conservation and saleable product. These solar PV systems also minimize the requirement for expensive fuel gas regulators, shutdown devices and repair kits and stainless steel in strument tubing and fittings.Oil & Gas: Exploration & Production - Wells

11/01/07 116 IV. Background data and assumptions used See the presentation, “BP Canada Energy Comp any Innovative Methods for Reducing Greenhouse Gas - Low Emissions Wellsite” by Milos Krnjaja, BP Cana da made at the “Energy Management Workshop for Upstream and Midstream Operations: Increasing Revenue through Process Optimization & Methane Emissions Reduction” in Calgary, Al berta Canada on 15-17 January 2007. ( http://www.methanetomarkets.org/events/2006/oil- gas/docs/15jan07-bp_canada_energy_company.pdf )

See the presentation, “Using Solar to Reduce F ugitive Gas Emissions” by Stuart Torr, Komex International made at the 2005 Energy Conservation and Air Emissions Technology Forum Wednesday, in Calgary, Alberta Canada on 19 October 2005. ( http://www.ptac.org/eet/dl/eetf0501p12.pdf )

See Database of State Incentives for Renewables and Efficiency (DSIRE) for a fast and convenient method to access comprehensive information on available state, local, utility, and federal financial

incentives that promote renewable energy and energy efficiency. ( http://www.dsireusa.org/ )

See Alberta Energy & Utilities Board – Directive 60 – Upstream Petroleum Industry Flaring, Incinerating, and Venting. ( http://www.eub.ca/docs/documents/ directives/Directive060.pdf )

See Ber-Mac Electrical and Instrumentation for an example of a supplier of solar PV systems for instrumentation use. They have been in business since 1980 supplying electrical power and instrumentation equipment and services, both domestica lly and to international markets, supplying the needs of oil and gas companies all over the world. Th eir “Green Machine” is an environmentally-friendly, solar-powered operating system for new and existing wellsites. ( http://www.ber-mac.com/greenmachine.htm )

V. Any uncertainty associated with the option Low – a fair amount of industry experience and vendor capacity to-date.

VI. Level of agreement within the work group for this mitigation option General agreement within working gr oup members that this is viable.Oil & Gas: Exploration & Productio n – Pneumatics/Controllers/Fugitives

11/01/07 117 

### EXPLORATION & PRODUCTION: PNEUMA TICS / CONTROLLERS / FUGITIVES

Mitigation Option: Optical Im aging to Detect Gas Leaks

I. Description of the mitigation option This option would encourage oil and gas producers and pipelines to use optical imaging to detect methane and other gaseous leaks from equipmen t, processing plants, and pipelines.

Optical imaging refers to a class of technologies that use principles of infrared light and optics to create an image of chemical emission plumes. They offer more cost-effective use of resources than traditional hand-held emissions analyzers, can screen hundreds of components or miles of pipeline relatively quickly and allow quicker identification and repair of leaks. The remote sensing a nd instantaneous detection capabilities of optical imaging technologies allow an ope rator to scan areas containing tens to hundreds of potential leaks, thus eliminating the need to vi sit and manually measure all potential leak sites.

Gas imaging can be either active or passive. Active gas imaging is accomplished by illuminating a viewing area with laser light tuned to a wavelength that is absorbed by the target gas to be detected. As the viewing area is illuminated, a camera sensitive to light at the laser wavelength images it. If a plume of the target gas is present in the im aged scene, it absorbs the laser illu mination and the gas appears in a video picture as a dark cloud. Because it relies on the detection of backscattered radiation from surfaces in the scene, the process is referred to as Ba ckscatter Absorption Gas Imaging (BAGI).

Passive gas imaging is based on a complex relati onship between emission, absorption, reflection, and scatter of electromagnetic radiation. VOCs in the vapor phase have unique spectral emission and absorption properties. By measuring these properties, the gas species can be uniquely identified. By tuning the instrument’s spectral response to the unique spectral region of the VOC, the camera can make an image of a gas plume.

There is a variety of technologies available and in different stages of development for imaging hydrocarbon gases. Plume imaging technologies include BAGI and Hyperspectral Imaging systems. Remote detection sensing instruments include Op en-path Fourier Transform Infrared (OP-FTIR), Differential Absorption Spectroscopy (DOAS), Li ght Detection and Ranging (LIDAR-DIAL), and Tunable Diode Laser Absorption Spectroscopy (TDL AS). These instruments can be hand held or shoulder mounted, van mounted, or operated from a he licopter or fixed wing aircraft, depending on the technology and the facility to be inspected.

As an example, the ANGEL service, which uses Di fferential Absorption Lidar (DIAL), can detect specific hydrocarbon gases with color video imaging from a fixed wing aircraft, quantify the plume concentration, encode GPS data on the image, and c over 1000 miles per day. This technology is most suited to a facility such as a pipeline or tank farm. For a gas processing plant, a hand held or shoulder mounted camera may be the technology of choice.

The benefits of using optical leak detection in an inspection and maintenance program include:
3⁄4 Reductions in hydrocarbon gas emissions, both greenhouse gases and hazardous air pollutants;
3⁄4 Improved safety; and
3⁄4 Typical payback of less than one year in reduced methane product losses.

II. Description of how to implement A. Mandatory or voluntary: This program would be a voluntary Best Management Practice. The economic returns from implementing optical leak detection should motivate producers to implementOil & Gas: Exploration & Productio n – Pneumatics/Controllers/Fugitives

11/01/07 118 them. State and Federal agencies can assist by adve rtising the benefits, as is currently done by EPA’s Natural Gas Star Program. B. Indicate the most appropriate agency(ies) to implement: EPA and the state environmental agencies

would extend and enhance EPA’s current efforts to make them specific to the San Juan Basin.

III. Feasibility of the option

A. Technical: Several of these systems are commercially available.

B. Environmental: The environmental benefits of using optical imaging to detect and repair leaks have been documented. Companies reporting to EPA ha ve reduced emissions significantly. Individual company results can be found on the EPA Natural Gas Star Program web site referenced below.

C. Economic: EPA reports that optical leak detection surv eys pay for themselves in less than a year. Differing opinion : Must be evaluated for each operation, may not be economic or applicable for all.

IV. Background data and assumptions used See the web site for EPA’s Natural Gas Star Program: http://www.epa.gov/gasstar/index.htm

Individual companies’ experience with optical imaging leak detection:

Dynergy: http://www.epa.gov/gasstar/pdf/ngstar_fall2005.pdf

Enbridge: http://www.epa.gov/gasstar/works hops/houston-oct 2005/dodson.pdf

Also see the agendas from the 2003 – 2005 Gas STAR Program annual implementation workshops: http://www.epa.gov/gasstar/workshops/imp_workshops.htm

Information on the ANGEL-DIAL technology: http://www.epa.gov/gasstar/workshops/kenai/itt_sstearns.pdf

http://www.epa.gov/gasstar/pdf/ngspartnerup_spring06.pdf

Texas Commission on Environmental Quality report that includes comparison of various imaging technologies: http://www.tceq.state.tx.us/impleme ntation/air/terp/Prop_02R04.html

V. Any uncertainty associated with the option Low. This is proven technology with proven benefits.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups None known.Oil & Gas: Exploration & Productio n – Pneumatics/Controllers/Fugitives

11/01/07 119 

### Mitigation Option: Convert Gas Pneuma tic Controls to Instrument Air

I. Description of the mitigation option This option would encourage oil and gas producers and pipelines to convert pneumatic controls from natural gas to compressed instrument air systems. It would enhance EPA’s current efforts in the Natural Gas Star Program and make them specific to the Sa n Juan Basin. This would result in a significant

reduction in methane emissions as well as ach ieve cost savings for the companies.

Pneumatic instrument systems powered by high-pressure natural gas are often used across the natural gas and petroleum industries for process control. Typi cal process control applications include pressure, temperature, liquid level, and flow ra te regulation. As part of normal operation, natural gas powered pneumatic devices release or bleed gas to the atmosp here and, consequently, are a major source of methane emissions from the natural gas industry. The constant bleed of natural gas from these controllers is collectively one of the largest sources of methane emissions in the natural gas industry, estimated at approximately 24 billion cubic feet (Bcf) per year in the production sector, 16 Bcf from processing and 14 Bcf per year in the transmission sector. Pneumatic control systems emit methane from tube joints, controls, and any number of points within the distribution tubing network.

Companies can achieve significant cost savings and methane emission reductions by converting natural gas-powered pneumatic control systems to compressed instrument air systems. Instrument air systems substitute compressed air for the pressurized natural gas, eliminating methane emissions and providing additional safety benefits. Cost effective applicati ons, however, are limited to those field sites with available electrical power.

In compressed instrument air systems, atmospheric ai r is compressed, stored in a volume tank, filtered and dried for instrument use. All other parts of a gas pneumatic system work the same way with air as they do with gas. Existing pneumatic gas supply piping, control instruments, and valve actuators of the gas pneumatic system can be reused in an instrument air system. Reducing methane emissions from pneumatic devices by converting to instrument air systems can yield significant economic and environmental benefits for natural gas companies including:
3⁄4 Financial Return from Reducing Gas Emission Losses. In many cases, the cost of converting to instrument air can be recovered in less than a year.
3⁄4 Increased Life of Control Devices and Improved Operational Efficiency
3⁄4 Avoided Use of Flammable Natural Gas. By eliminating the use of a flammable substance, operational safety is significantly increased.
3⁄4 Lower Methane Emissions
3⁄4 The conversion of natural gas pneumatics to instrument air system is applicable to all natural gas facilities and plants where an electric power supply is availa ble. For those sites that do not have electricity available, cost savings and methane emissions reduc tions can still be achieved by replacing high-bleed pneumatic devices with low bleed devices, retrofitti ng high-bleed devices, and improving maintenance practices. Experience has shown that these options often pay for themselves in less than a year.

II. Description of how to implement A. Mandatory or voluntary: This program would be voluntary. The economic returns from implementing instrument air or low bleed systems should motivat e producers to implement them. State and Federal agencies can assist by advertising the benefits, as is currently done by EPA’s Natural Gas Star Program. B. Indicate the most appropriate agency(ies) to implement: EPA and the state environmental agencies

would extend and enhance EPA’s current efforts to make them specific to the San Juan Basin.Oil & Gas: Exploration & Productio n – Pneumatics/Controllers/Fugitives

11/01/07 120 III. Feasibility of the option

A. Technical: These systems are off-the-shelf and proven. Best utilized at larger facilities.

B. Environmental: The environmental benefits of repl acing high-bleed pneumatic controls with instrument air, in terms of lower methane emis sions, have been documented by EPA. Companies reporting to EPA have reduced emissions by an average of 20 Bcf per year per facility.

C. Economic: EPA reports that instrument air systems pa y for themselves in less than a year. Replacing or retrofitting high-bleed units with low-bleed units have a payback of five months to one year. Differing opinion : May not be economically justifiable or operationally sound for small facilities and

well sites.

IV. Background data and assumptions used See the web site for EPA’s Natural Gas Star Program: http://www.epa.gov/gasstar/index.htm

In particular, the lessons learned summaries for instrument air: http://www.epa.gov/gasstar/pdf/lessons/ll_instrument_air.pdf

And for low-bleed pneumatics: http://www.epa.gov/gasstar/pdf/lessons/ll_pneumatics.pdf

V. Any uncertainty associated with the option Low: this is proven tec hnology with proven benefits.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups None known.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 121 

### EXPLORATION & PRODUCTION: MIDSTREAM OPERATIONS

Mitigation Option: Application of NSPS and M ACT Requirements for Existing Sources at

Midstream Facilities

I. Description of the mitigation option

Overview

• This mitigation option would involve filling in the gaps where the NSPS and MACT fail to adequately regulate sources at midstream facilitie s. Filing in the gaps could include lifting exemptions on existing sources and lowering appli cability thresholds. Specific examples include:

o Subjecting existing stationary combustion turb ines at midstream facilities to 40 CFR Part 63, Subpart YYYY;

o Requiring existing 2 stroke lean burn and 4 stroke lean burn reciprocating internal combustion engines to meet 40 CFR Part 63, Subpart ZZZZ MACT standards at midstream facilities;

o Requiring boilers, reboilers, or heaters with a design capacity of less than 10 mmBtu/hr to meet NSPS at 40 CFR Part 60, Subpart Dc at midstream facilities;

o Requiring all midstream facilities to meet the requirements to 40 CFR Part 60, Subpart KKK; and

o Requiring all amine sweetening units at midstream facilities to meet 40 CFR Part 60, Subpart LLL requirements.

This option would involve case-by-case assessments of midstream facilities to determine whether additional pieces of equipment should be regul ated under NSPS and MACT standards and to assess the feasibility of such regulation. The ove rall goal is to use NSPS and MACT standards as guides for further air pollution reductions at midstream facilities.

Air Quality/Environmental

• This mitigation option would lead to further reduc tions in hazardous air pollutants and criteria air pollutants by subjecting more units to regulation. By requiring more facilities and/or units to comply with NSPS and MACT, there may be an incentive to upgrade to cleaner equipment, which would provide additi onal air quality benefits.

Economics

• There would likely be additional costs associated with bringing previously unregulated facilities and/or units into compliance.

• The option may provide an incentive to replace olde r, less efficient equipment, which could lead to increased efficiency.

• There would be potential paybacks associated with methane recovery by complying with NSPS at Subpart KKK.

Tradeoffs

• None.

Burdens

• The burden would be on industry to bring faciliti es and/or units into compliance with the NSPS and MACT standard. Air quality impacts woul d be reduced, reducing burden on health and welfare. Regulatory agencies may have to revi se rules to implement this mitigation options.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 122 II. Description of how to implement A. Mandatory or voluntary : Mandatory. NSPS and MACT standards work best as mandatory requirements. B. Indicate the most appropriate agency(ies) to implement: State Air Quality agencies, EPA.

III. Feasibility of the option

A. Technical : There will need to be case-by-case assessments, but this appears to be a technically feasible option.

B. Environmental : No environmental feasibility issues are known.

C. Economic : There may be economic concerns that should be addressed, but this option is not infeasible based on economics. The goal is clean air and that may take an investment.

D. Other : There will likely need to be rule changes to implement this option that may present feasibility

issues.

IV. Background data and assumptions used Background data and assumptions used came from review of EPA NSPS and MACT standards.

V. Any uncertainty associated with the option (Low, Medium, High): Low uncertainty. The NSPS and MACT provide a solid basis for air pollution control options. However, further discussion and comments may reveal other mean s of using NSPS and MACT standards to keep air pollution in check.

VI. Level of agreement within the work group for this mitigation option: TBD

VII. Cross-over issues to the other source gro ups (please describe the issue and which groups : None.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 123 

### Mitigation Option: Specific Direction for Ho w to Meet NSPS and MACT Standards: Directed Inspection and Maintenance

I. Description of the mitigation option

Overview Meeting NSPS and MACT standards at Midstream fa cilities can often be achieved using a variety of methods, some of which may be better than others. Fo r example, the EPA is proposing to allow the use of infrared cameras to meet Leak Detection and Repair (LDAR) requirements set forth in several NSPS and MACT standards. 70 Fed. Reg. pp. 17401-17409. The EPA has indicated that infrared cameras can provide better data than Reference Method 21.

This mitigation option provides specific direction on how to meet NSPS and MACT standards so that the best methods of compliance are met. Specifically, it requires operators to use approved infrared cameras to meet LDAR requirements set forth at 40 CFR Part 60, Subpart KKK and 40 CFR Part 63, Subpart HH

and HHH.

It would also require operators to implement cost -effective options for reducing methane emissions, as outlined in Fernandez, et al. 2005, to meet appli cable NSPS and MACT standards. These cost-effective options would vary depending on the equipment, but would include using vapor recovery units on tanks and dehydrators, using desiccant dehydrators rather than glycol dehydrators, replacing compressor rod packing after three years, replacing gas starters on compressor engines with air starters, and converting gas pneumatics at facilities to instrument air.

Air Quality/Environmental

• Meeting LDAR requirements using infrared came ras promises to better keep volatile organic compound and hazardous air pollutant emissions from leaking equipment in check. Implementing cost-effective options for reduc ing methane emissions will further reduce emissions. In both cases, methane emissions w ould be reduced, preventing further greenhouse gas emissions.

Economics

• This mitigation option will most likely yield a payback due to the recovery of methane. According to one case study, BP recovered $2.4 million in 2 months simply by recovering over 123 MMcf/yr of that was lost due to equipment leaks (see, http://www.epa.gov/gasstar/workshops/hobbs72706/dim.pdf ).

Tradeoffs

• The use of some cost-effective me thane control options may require the use of electricity, such as vapor recovery units, which may be generated through coal or natural gas burning. Potential increases in emissions from electricity generation c ould be prevented through the use of solar or other renewable energy sources.

Burdens

• The only burden would be the restriction of flexibility for the operators and the investment cost.

II. Description of how to implement A. Mandatory or voluntary : Mandatory. Although infrared came ras and methane control options can provide paybacks and are proven cost-effective, they are not widely used. Despite potential paybacks, current incentives do not appear to be strong enough to encourage their use. Mandatory requirements would provide that incentive.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 124 B. Indicate the most appropriate agency(ies) to implement : State air quality agencies and EPA.

III. Feasibility of the option

A. Technical : Feasible, these technologies are already in use and are being implemented elsewhere.

B. Environmental : Vapor recovery units may require add itional space at midstream facilities and could pose additional environmental impacts. This seems to present a limited environmental feasibility issue.

C. Economic : Given the paybacks from methane recovery , there are no economic feasibility issues.

D. Other : The EPA has not yet finalized its proposal to a llow infrared cameras to be used solely to meet LDAR requirements in the NSPS and MACT.

IV. Background data and assumptions used Background data was obtained from information on the EPA’s Natural Gas Star Program website, www.epa.gov/gasstar , from the EPA’s proposal to allow infrare d cameras to be used to meet LDAR requirements at 70 Fed. Reg. 17401-17409, and from the Fernandez et al. 2005 paper, “Cost Effective

Methane Emissions Reductions for Small and Mids ize Natural Gas Producers,” available online at http://www.epa.gov/outreach/gasstar/pdf/CaseStudy.pdf

.

V. Any uncertainty associated with the option Low uncertainty, especially with regard s to the use of infrared cameras as effective tools to comply with NSPS and MACT LDAR requirements. Operators woul d still have to show that cost-effect methane control options would meet the applicab le requirements of the NSPS and MACT.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other source groups Possibly the Cumulative Effects Group due to indir ect emission increases from coal or natural gas burning plants that may accompany increased use of vapor recovery units or other methane control options requiring electricity.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 125 

### OIL & GAS OVERARCHING

Mitigation Option: Lease and Permit Incentiv es for Improving Air Quality on Public

Lands

I. Description of the mitigation option This option would provide incentives in the form of exceptions or waivers from lease stipulations or permit conditions of approvals (COAs) for oil and g as drilling on public lands in exchange for a program of environmental mitigation activities that would reduce air emissions along with other types of environmental and ecological impacts.

Differing Opinion: The proposed activities that would reduce air emissions and surface disturbance in this section should become standard practices but without the proposed exchange for the exceptions or

waivers from seasonal wildlife restrictions which wo uld negatively impact public lands wildlife.

This option could provide incentives in the form of expedited permit processing for operating permits in exchange for a program of environmental mitigati on activities that would requi re documented reductions in emissions from major and minor sources. This option is not intended to reduce protection for wildlife. Monitoring and adjustments in response to monitoring results would be used to assure that the package of mitigation activities and associated developm ent does not adversely affect wildlife.

Differing Opinion: Additionally these incentives would not incl ude the exception of waivers from lease stipulations or permit conditions of approval (“COAs”) for oil a nd gas drilling on public lands.

Expedited operating permit issuance from the appropri ate agency in exchange for additional emissions

reductions offers incentives for both industry and the agencies

Industry Incentives include:

• The streamlining of operating permits.

• Direct and prompt cooperation with permit issuing agency.

• Obtaining an operating permit at an accelerated ra te allows for an accelerated startup date, thus increased resource production (may be especially helpful for minor source operating permits).

Environmental Incentives include:

• The addition of emission control equipment such as a catalyst, Zero Emissions (a.k.a. Quantum Leap) Dehydrator, directional drilling, complying with emission limitations relating to hours of operation, lean burn engine, and/or implemen ting a program of environmental mitigation

activities that would reduce air emissions.

This option would work well in the areas that sma ller agencies, such as Tribes, oversee the operating permits. This option would be implemente d by the applicable permitting agencies.

It would be modeled after the experience in the Pi nedale Anticline and Jonah fields in Wyoming where producers face seasonal limitations on drilling due to c oncerns about wildlife impacts. As a result, drilling is prohibited for several months during the year, delaying development and increasing costs. Several producers have applied for a nd been granted permission to drill y ear round in exchange for efforts that mitigate environmental impacts. These effo rts combine improved technologies and innovative practices that together greatly reduce adverse impact s. They include: directional drilling to reduce the number of drilling pads, and thus the amount of surface disturbance, by half or more; using natural gasfired drilling rigs to reduce air emissions; transporting produced water by pipeline to eliminate truck trips;Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 126 using mat systems on drilling pads to reduce surface imp act; partial remediation of drilling pads after the drilling phase; eliminating flares during well testing and completion to reduce air emissions and noise; centralized fracturing and production facilities; low im pact road construction techniques; and produced water recycling. Producers and BLM will monitor wildlife impacts as part of the program. Year round drilling has the added benefits of re ducing the duration of drilling operations by one third-to one-half, and increasing stability of the local community as workers move in with their families, rather than commuting seasonally.

Differing Opinion: This suggestion of modeling after the e xperience in Wyoming's Pinedale Anticline and Jonah fields fails to address the widespread a nd significant concerns that have been expressed regarding current and future impacts of oil and gas activity on wildlife in these fields and the wildlife population declines that have been documented thro ugh scientific studies. The Pinedale Anticline and Jonah field experience has not prove n to be a model for wildlife, and recent proposals to increase drilling may even adversely impact a federally threatened species, the Bald Eagle, and further exacerbate problems for the sage grouse, a sp ecies which some believe should be listed as federally endangered because of recent population declines. Another report that helps put the Jonah field experience in perspective came in December 2006, stating that in places one well was being drilled per every five acres. Repeated concerns about the impact on wildlife in these areas of Wyoming have been expressed by numerous and diverse groups of pe ople ranging from private citizens, outfitters, hunters, environmental organizations, scientists, to government agency pe rsonnel including personnel from Wyoming's Game and Fish Department. Drilling exceptions granted in crucial big game winter range around Pinedale early winter 2006/2007 were granted in the face of oppos ition by Wyoming's Game and Fish Department.

Differing Opinion Continued: Monitoring has also not been a model experience in this area. According to reports of a May 2006, internal assessment Pine dale, Wyoming, Bureau of Land Management field office, the office neglected its commitment to m onitor and limit harm to wildlife and air quality from natural gas drilling in western Wyoming. A wildlife biol ogist who worked in that Pinedale office, Steve Belinda, is reported to have quit his job because he an d other wildlife specialists were required to spend nearly all their time in the office processing drilling re quests and were not able to go into the field to

monitor the effect of the thousands of wells on wildlife.

This option would involve tradeoffs between seasona l restrictions, which would be relaxed, and a comprehensive wildlife and environmental impact pl an which would use the kind of technologies and practices listed above. This plan would reduce impa cts on wildlife, as well as on air quality, land and water resources, and on the local communities. Ec ological and environmental monitoring would assess these impacts and allow for adjustment s in the plans as activities proceed. All of these elements would be contained in agreements between the land manage ment agencies and industry, with public input.

Differing Opinion: Exceptions or waivers from wildlife lease stipulations or pe rmit conditions of approvals (COAs) for oil and gas drilling on public lands likely would increase negative impacts of oil and gas activities on wildlife in the Four Corners. At least in Northwest New Mexico and likely in the other Four Corners states, it is important to rememb er that the seasonal closures in the Bureau of Land Management Farmington Field Office management area ex ist only for parts of the year with their length dependent upon the animal species and the reason for the restriction such as elk calving or antelope fawning. The restrictions are in place to protect speci es during times of the year when they are especially vulnerable such as nesting for raptors; wintering for deer, elk, and Bald Eagles; and birthing and caring for young for antelope and elk. Provisions for wa iving, excepting, or modifying the oil/gas lease stipulations already exist according to the Bureau of Land Management Farm ington Field Office's 2003 Record of Decision for Farmington's Proposed RMP and Final Environmental Impact . These restrictions should remain in place to protect wildlife, especially w ith the current and anticipated intensity of drilling.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 127 Differing Opinion Continued: An indication of the major potential for the impact of oil and gas activity on wildlife is found in the 2006 Annual Report of the Sublette Mule Deer Study conducted in the Pinedale Anticline Project Area. Study results that "suggest that mule deer abundance in the treatment area declined by 46 % in the first 4 years of gas development."

Differing Opinion Continued: In the summer, 2006, publication of the New Mexico Department of

Game and Fish titled New Mexico Wildlife under the regional outlook for Northwest New Mexico, wildlife biologists are reported to be "concerned a bout the effects the severely dry spring had on fawn

survival in the state's already depressed deer herds ." [Bolding is this author's.]

Differing Opinion Continued: Removal of the wintering restrictions for mule deer could create problems in New Mexico and in both this state and Colorado where migratory populations are shared. Another word of caution is found in the Upper San Basin Biological Assessment in the Comprehensive Wildlife Conservation Strategy (New Mexico's wildlif e action plan accepted by the US Fish and Wildlife Service in 2006), which places mule deer in its lis t of Species of Greatest Conservation Need in the Colorado Plateau Ecoregion. Under "Problems Affect ing Habitats or Species" in Chapter 5 of this document is this statement: "Of particular concer n are energy development..." along with invasive species and livestock grazing practices. The document st ates that "coal bed methane development in the San Juan Basin is currently a major land use...Depend ing on the scale, density, and arrangement of each well site in relation to other sites, habitat loss and fra gmentation in the portions of this habitat type [Big Sagebrush Shrubland] subjected to en ergy development are extensive. At this high level of development, effects may not be successfully mitigated."

Differing Opinion Continued: Pronghorn antelope numbers were so low at the time the Farmington Field Office's Draft Pronghorn Antelope Habitat Mana gement Plan was published in March 2004, that the populations were described as struggling to survive, a change from when this species was common in the 1950’s and 1960’s. The restriction of drilling and cons truction activity during antelope fawning period from May 1 through July 15 was proposed as one of the ways to bring the populations back to eventual self-sufficiency

.

These actions reduce air emissions from drilling rigs, fro m trucks (both diesel emissions and road dust), and from flaring. There are also benefits from reduced surface impacts and improved water management, as well as improved community stability.

Differing Opinion Continued: The actions that are offered that will reduce air pollution appear to be important ways to address our air quality problem and should become required practice because of the serious air pollution problems in the San Juan Basin. Th ey should not come at an expense to area wildlife, which is already negatively impacted by direct and functional habitat loss due to oil and gas activities, as delineated in the 2003 Bureau of Land Manage ment Farmington Field Office Draft Resource Management Plan and Environmental Impact Statement.

This option would work well in areas of the Four Corn ers region where new oil and gas projects are being proposed and where those projects face access limitations from wildlife stipulations or COAs. In these cases, the land management agencies (principally th e BLM and the Forest Service) would have the greatest opportunity to negotiate agreements for infrast ructure and operational changes from project start, in exchange for relaxing the access restrictions, along with monitoring for wildlife impacts. Monitoring of the air quality impacts, including documentation of reductions over similar projects without mitigation, would be required.

In New Mexico, this option could be integrated with the New Mexico Oil and Gas Association’s (NMOGA) Good Neighbor Initiative.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 128 Differing Opinion: Year round drilling will not improve air quality. The current drilling seasons are in place to protect the wildlife in the area. The im proved technologies and innova tive practices described above should be standard industry requirements and not be used in trade for expanded drill seasons.

Differing Opinion: BLM should not entertain compromising one environmental value in exchange for protecting another when industry is legally mandated to protect both. Year round drilling will only add to the stress wildlife currently experien ce in an already highly fragmented ha bitat. Even more, in the San Juan Basin industry has demonstrated their reluctance to routinely employ directional drilling as a means to avoid further habitat fragmentation. Since direc tional drilling “all wells” would be the cornerstone of the proposed mitigation option it seems that this options would not be favorably received by industry.

II. Description of how to implement A. Mandatory or voluntary : This program would be voluntary and would rely on the operators, the agencies, and any local communities obtaining benefits from the arrangements. B. Indicate the most appropriate agency(ies) to implement: BLM and the Forest Service on Federal land. State and tribal land management agencies may implement this option on state and tribal lands.

III. Feasibility of the option

A. Technical : The technological approaches to reducing impacts are already being implemented in Wyoming and other locations. Differing Opinion: Four Corners states should use the technological approaches without industry cost being a factor.

B. Environmental : The environmental benefits of the mitigation measures are currently being documented in Wyoming. Many of them seem appa rent. The impact of year round drilling (or other permit-related incentives) on wildlife woul d have to be closely monitored.

C. Economic : Many environmental mitigation measures tu rn out to be economically attractive as well (e.g., natural gas drilling rigs can reduce fuel costs by two-thirds). Year-round drilling can shorten the project length by one-third to one-half, improvi ng project economics. Producers would have to anticipate an economic benefit in order to enter into agreements.

IV. Background data and assumptions used Web sites and presentations from operators and BLM on the experience with this kind of agreement in Wyoming. The NMOGA web site has information on their Good Neighbor Initiative.

See the following web sites: BLM environmental assessment of year-round drilling in the Pinedale Anticline Field: http://www.wy.blm.gov/nepa/pfodocs/questar/01ea.pdf (See especially section 2.5 on Applicant-Committed Mitigation.)

Questar presentation on development in Pinedale: http://www.wy.blm.gov/fluidminerals04/presentations/NFMC/028RonHogan.pdf\

BLM assessment of year round drilling demonstration project in the Pinedale Anticline Field: http://www.wy.blm.gov/nepa/pfodocs/asu/01ea.pdf

Jonah Infill Project:

Encana release: http://www.encana.com/operations/upstream/us_jonah_blm.html BLM air quality discussion: http://www.wy.blm.gov/nepa/pfodocs/jonah/92FEISAirQualSuppleQ-As.pdf

BLM EIS and Record of Decision: http://www.wy.blm.gov/nepa/pfodocs/jonah/Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 129 NMOGA Good Neighbors Initiative: http://www.nmoga.org/nmoga/NMOGA %20Good%20Neighbor%20Initiative.pdf Wyoming Mule Deer Study Report (1 site) http://www.west-inc.com/reports/bi g_game/PAPA_deer_report_2006.pdf Wyoming wildlife, sage grouse http://stream.publicbroadcasting.net/pro duction/mp3/wpr/local-wpr-563699.mp3 http://gf.state.wy.us/downloads/pdf/sagegrouse/Holloran2005PhD.pdf Wyoming wildlife, Bald Eagle http://www.wy.blm.gov/nepa/pfodocs/anticline/seis/06chap3.pdf 3-97 http://www.wy.blm.gov/nepa/pfodocs/anticline/seis/07chap4.pdf 4-123 Wyoming Bureau of Land Management , wildlife monitoring (1site) http://www.washingtonpost.com/wp-dyn/cont ent/article/2006/08/3 1/AR2006083101482.html New Mexico: Comprehensive Wildlif e Conservation Strategy (CWCS) http://fws-nmcfwru.nmsu.edu/cwcs/New_Mexico_CWCS.htm New Mexico—2003 Bureau of Land Management R esource Management Plan/Environmental Impact Statement, Record of Decision http://www.nm.blm.gov/ffo/ffo_p_rmp_feis/docs/Farmington_ROD.pdf Appendix B

V. Any uncertainty associated with the option Medium: Depends on opportunities (proposed projec ts) for implementing incentives in exchange for mitigation activities, on producer willingness to partic ipate, and on BLM/FS state and regional office and tribal policy.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups Impacts from trucks and roads may overlap with the Other Sources work group.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 130 

### Mitigation Option: Economic Incentives-B ased Emission Trad ing System (EBETS)

I. Description of the mitigation option

The central idea of this option is that inherent economic incentives promote innovative ways to achieve emission reductions, including gains from efficiencies in operation and maintenance and in applications of new innovative engine and control technologies.

This option encourages the use of pollution markets through implementation of an emission trading system (ETS) along with cooperative partnerships to reduce air emissions with the aid of emission reduction incentives. Basically in an emission trad ing program, the governing authority (e.g., agency)

issues a limited number of allocations in the form of ce rtificates consistent with the desired or targeted level of emissions in an identified region or area. The sources of a particular air pollutant (e.g., NOx) are allotted certificates to release a specified number of tons of the pollutant. The certificate owners may choose either to continue to release the pollutant at current levels and use the certificates or to reduce their

emissions and sell the certificates. The fact that the cer tificates have value as an item to be sold or traded gives the owner an incentive to re duce the company’s emissions. Simply stated in an ETS, a producer who has low-emission engines could sell emissions cred its to a producer who has high-emission engines. Typically, 0.8 units of credit could be sold for each unit of reduction below the standard or reference level. The end result is a ratcheting down of ove rall emissions. This option does not contemplate multipollutant trading, but rather a separat e market for each individual pollutant.

Approximately 30 state and federal ETS programs existed or were being developed in the U.S. in the later part of the 1990s. Examples of ETS that have work ed reasonably well in achieving emission reductions and providing economic incentives to industry incl ude the Illinois EPA’s Emission Reduction Market System (ERMS), Indiana Department of Environmental Management’s credit registry trading system, U.S. EPA’s Acid Rain Program, and commercial an d non-commercial institutions like Chicago Climate Exchange (CCX). In addition, in 2002 the US EPA approved a plan submitted by the WRAP, which contained recommendations for implementing the regional haze rule. The plan included an SO 2 emissions allowance trading program for nine Western states and eligible Indian tribes. As an example, EPA’s program took about three years to plan and begin implementing.

The proposed economic incentives based emission trad ing system (EBETS) mitigation option can be developed or modeled after ETSs which have been su ccessful and tailored to issues specific to the Four Corner region. Emission credits can accrue through a variety of methods that are complementary to or independent of other mitigation options developed herein by the Task Force. For example, credits can be gained through use of partnerships that that pr ovide incentives for voluntary emission reductions, such as in the EPA’s Natural Gas STAR Program or New Me xico’s VISTAS program (see the IBEMP mitigation option paper, OOP4). Credits for use or sale (e.g., sal es within the ETS) can also be acquired through use of tax and/or lease incentives and through the in itiatives coming from Small and Large Engine Subgroup (e.g., advanced ignition systems, use of electric engin es, centralized large engine from many small engine mode of operations). In addition, opportunities exis t for collaboration between engine manufacturers and producers for field testing new engine technology through a swap out program, dirty old for cleaner new. Finally, use of voluntary laboratory testing of a sel ect group of existing engines (e.g. uncontrolled small, <300 hp, engines) could provide a means to identif y innovative cost-effective modifications to improve engine efficiency and reduce e ngine emissions (SERP, 2006).

Benefits : Joint participation by oil and gas, elect ric power production, and other source category stakeholders provides opportunities for multi-pollutant emission reductions that cover key criteria air pollutants such as NO

x , SO 2 , VOCs, PM 2.5 , and PM 10 . An added benefit could be realized by also including green house gases such as CO 2 and CH 4 , in the mix. Examples of the emission reductions thatOil & Gas: Exploration & Production – Midstream Operations

11/01/07 131 could be achieved by a well designed and implemen ted ETS are the 50% reduction from 1980 levels of SO2 emissions from utilities under the ETS within US EPA’s Acid Rain Program 1 and the 65% reduction

from 1990 levels achieved under the Ozone Trans port Commission NOx Program (SERP, 2006).

Tradeoffs : The ETS could be designed to provide for polluta nt emission allocation and/or credit tradeoffs (e.g., NOx for SO2 in NOx limited regions) and trades between source groups or categories (e.g., oil and gas NOx with power plant SO 2 ).

Burdens : The major burden would be administrative in na ture. Who would be responsible for designing, setting up and administering the proposed EB ETS program and how would it be funded?

II. Description of how to implement A. Mandatory or voluntary : Participation in the program would be voluntarily.

B. Indicate the most appropriate agency (ies) to implement : The states.

III. Feasibility of the option

A. Technical : The technical feasibility of ETS programs is well established and is in use around the

world.

Differing opinion: Accurately and reliably measuring th e emissions from oil and gas sources will prove challenging. EBETSs have had broad success because those that have been established rely heavily on good monitoring and reporting, and it is no t clear that such techniques are available for the oil and gas sources of interest. Parametric, as opposed to direct exhaust emissions monitoring is one option, but the less direct/accurate/reliable the measurement, the more likely it is that some offset/discount will be demanded to make up for th e uncertainty, e.g., if a source wanted to purchase credits as part of its compliance plan, it would have to purchase two instead of one. Alternatively, sources with relatively weaker emissions monitori ng would be allowed to purchase credits, but not sell them. This latter approach was take n in the WRAP SO2 Backstop Trading Program

.

B. Environmental : The feasibility in achieving significant emission reductions has been clearly demonstrated through use of well designed and im plemented ETS programs. Inclusion and addition of “Best Management Practices,” innovative technolog ies, improved maintenance and other pay-back incentives enhance the feasibility of achieving emissi on reductions required to meet air quality and visibility enhancement goals in the Four Corners Region.

C. Economic : This program is economically feasible because emission trading provides economic incentives through implementation of complement ary voluntary measures that reduce emissions, provide fuel savings, reduce operati on and maintenance cost by adoption of BMPs and installation of innovative technologies. One recent study of proj ected economic gain by 2010 from the continued implementation of the ETS within the Acid Rain Program estimated it would provide an annual economic benefit of $122 billion (in 2000 $) at an an nual cost of approximately $3 billion (or a 1 to 40 cost-benefit ratio).

_________________________________ 1 The success of the Acid Rain Program ETS is ev ident from emissions data, which shows that SO 2 emissions were reduced by over 5 million tons from 1990 levels or about 34 percent of total emissions from the power sector. When compared to 1980 levels, SO 2 emissions from power plants have reduced by 7 million tons or more than 40 percent.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 132 IV. Background data and assumption used

1. United States Environmental Protection Agency (USEPA) Acid Rain Program

< http://www.epa.gov/airmarkets/arp/index.html >
2. Illinois Environmental Protection Agency Emission Reduction Market System (ERMS)

< http://www.epa.state.il.us/air/erms/ >
3. Argonne National Laboratory, Strategic Emission Reduction Plan, Draft, 2006.

4. Chicago Climate Exchange < http://www.chicagoclimatex.com/ >

V. Any uncertainty associated with the option Medium to high.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups A key crossover issue to establishing and implem enting an effective EBETS is the facilitation of voluntary participation of electric utilities and ot her major source groups. This will provide the anticipated needed trade-offs in air pollutants (e.g., NOx and SO 2 ) that participation by one or a limited number of source groups may not be able to provide.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 133 

### Mitigation Option: Tax or Economic Deve lopment Incentives for Environmental Mitigation

I. Description of the mitigation option This option provides for regulatory agencies and industry working together to utilize various legislative (state/federal/tribal) processes to achieve real em issions reductions. Emi ssion reductions would be achieved by providing economic incentives that would encourage the industry to utilize lower emission internal combustion engines in various applications.

Emission reductions could be achieved th rough reducing the number of trucks in the field. This could be accomplished by providing incentives for companies to in stall underground piping in order to dispose of produced water. Criteria pollutants could be reduced by installing lower emissions compressor engines. Industry could be encouraged to install such engi nes by implementing tax incentives as described below.

Tax incentives provide economic relief to industry by reducing or eliminating taxes on certain equipment or activities. The equipment or activity must provi de a recognized environmental benefit to the taxing entity that grants the incentive. Some examples of tax incentives currently being utilized are: (1) allowing costs of retrofitting existing engines or installing new e ngines to be fully deducted in the year they are incurred rather than being capitalized (2) tax credit certificates issued to program participants, which can be redeemed over a specified period of time (3 ) income tax credits upon installation of approved equipment.

The air quality benefits include ne t reduction of emissions, primarily of nitrogen oxides. However, reductions in sulfur oxides, greenhouse gas emissions and particulate matter emissions can also be calculated. Only positive environmental impacts have been identified. It is not anticipated that this strategy would cause any negative impacts, other th an increased costs to in dustry. This strategy specifically provides for relief from such economic impacts.

Economic burdens include the cost to the oil and g as industry, engine manufacturers and other interest groups to develop and lobby legislative proposals. New technology would be more efficient, possibly resulting in increased production and reduced costs. The increased revenue would provide some offset to the initial costs of installation or retrofitting. Econom ic burden to the taxing entity would also occur. The taxpayers would, in effect, be subsidizing industry e fforts to install or retrofit equipment to achieve lower emissions. Achieving taxpayer approval for such a subsidy might prove difficult.

Assistance from the Cumulative Effects Work Group could be helpful in estimating the potential costbenefit of this option.

II. Description of how to implement A. Mandatory or voluntary: Participation by industry or othe r groups would be voluntary, both in working to establish tax/economic development incentiv es and in taking advantage of such incentives. B. Indicate the most appropriate agency(ies) to implement : States of Colorado and New Mexico. Counties of San Juan, NM; La Plata, CO; and other co unties in the Four Corners area of impact. Indian tribes, including Jicarilla, Ute Mountain Ute, Southern Ute, Navajo, and others. These groups would need to work with state legislatures and/or Congressional representatives in getting spon sors to help draft an energy bill that includes tax incentives for improving Four Corners air quality.

III. Feasibility of the option

A. Technical: Many models of tax and economic developmen t incentives are available. A list of some models follows, with more details contai ned in an Appendix to this document.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 134 i. Mineral Tax Incentives and the Wyoming Ec onomy, May 2001, is an economic model. http://legisweb.state.wy.us/2001/interim/ app/reports/mineraltaxincentives.htm ii. Brownfields Tax Incentive (1997 Taxpayer Relie f Act P.L. 105-34). This model allows costs to be fully deductible in the year they are incurred, rather than having to be capitalized. iii. New York State Green Building Initiative. This tax credit program was developed by New York State Department of Environmental Conservati on as per 6NYCRR Part 638. Tax credit certificates are issued and can be redeemed at any time over a designated period (i.e. 2006 – 2014). iv. Montana Incentives for Renewable Energy include property tax exemptions, industry tax credit, venture capital tax credits, and a low inter est revolving loan program, special revenue local government bonds, and streamlined permitting processes fo r participants, income tax credits for retrofitting equipment. v. State of Virginia House Bill 2141, July 1997 allows the local gove rning body of any county, city, or town, by ordinance, to exempt, or partia lly exempt property from local taxation annually for a period not to exceed five years. vi. US EPA’s Voluntary Diesel Retrofit Program is a non-regulatory, incentive-based, voluntary program designed to reduce emissions from existing diesel vehicles and equipment by encouraging equipment owners to install pollution reducing tech nology. This option would easily fit into the “partnership” mitigation option. However, it is also a model for the type of equipment that might qualify

for a tax incentive. vii. Philippines Department of Natural Resour ces developed a single document that consolidates all tax incentives for air pollution control devices. Not new incentives, but a compilation of existing

programs. viii. Western Regional Air Partnership diesel Retr ofit program for diesel engines could be used as a model for other internal combustion engines. Th e guidance document for developing a retrofit program is found on the WRAP website. See Appendix for info rmation. This option would easily fit into the “partnership” mitigation option. However, it operat es similar to a tax incentive program and gives an example of how to set up a workable program.

B. Environmental: The environmental benefits of pollutant emissions reductions are well documented.

C. Economic: The entire concept of this mitigation option is that it must be economically viable.

IV. Background data and assumptions used See Appendix for background studies. Cooperation between the regulated community; local, state and tribal governments; and equipment manufacturers would have to be garnered in order for this option to work.

V. Any uncertainty associated with the option Medium

VI. Level of agreement within the work group for this mitigation option The three member drafting team expressed no disagreement with this option.

VII. Cross-over issues to the other source groups These tax incentive programs could also apply to ot her sources, such as power plants or vehicles.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 135 APPENDIX

Mineral Tax Incentives and the Wyoming Econom y, May 2001, is an economic model. http://legisweb.state.wy.us/2001/interim/ app/reports/mineraltaxincentives.htm

This model can be used to show the effects of all tax incentives previously gran ted, as well as the effects of hypothetical tax incentives or tax relief that might be considered in the future. Impacts include reduction in taxes; increased production; effects on federal, state and local government revenues.

Brownfields Tax Incentive fact sheets (EPA 500-F- 03-223, June 2003) and incentive guidelines (EPA 500-F-01-338, August 2001) can be found on US EPA’s website at www.epa.gov/swerosps/bf/bftaxinc.htm There are also numerous case studies listed on this site as well as

federal resources.

New York State Green Building Initiative credit certificat es can be re-allocated to secondary users, if the initial recipient cannot utilize the entire credit amount. Information available at www.dec.state.ny.us/website/ppu/grnbldg/index.html or Pollution Prevention Unit (518) 402-9469; NY business tax hotline (518)862-1090 x 3311

Montana Incentives for Renewable Energy http://deq.mt.gov/Energy/Ren ewable/TaxIncentRenew.asp

Virginia property tax exemptions for the Voluntary Remediation Program http://www.deq.state.va.us/vrp/tax.html

US EPA’s Voluntary Diesel Retrofit Program information at http://www.epa.gov/otaq/retrofit/retroverifiedlist.htm Includes a list of approved retrofit technology.

Philippines Department of Natural Resources lists many tax incentive and economic incentives at http://www.cyberdyaryo.com/features/f2004_0624_03.htm Also included are numerous links to related

sites.

Western Regional Air Partnership guidance document for diesel retrof it programs can be found at http://www.wrapair.org/forums/msf/offroad_diesel.htmlOil & Gas: Exploration & Production – Midstream Operations

11/01/07 136 

### Mitigation Option: Voluntary Partnerships and Pay-back Incentives: Four Corners Innovation Technology and Best Energy-Envi ronment Management Practices (IBEMP)

I. Description of the mitigation option This option encourages establishment of partnerships be tween oil and gas producers and federal, state and local agencies and with engine manufacturers. Exampl es of such voluntary partnerships that have worked successfully in reducing emissions and providing cost be nefits to industry include the U.S. EPA’s Natural Gas STAR Program, the New Mexico’s Voluntary Innovative Strategies for Today's Air Standards (VISTAS) Program, Green Power and Combined Heat and Power Partnerships. The Natural Gas STAR Program is one of many voluntary programs established by the U.S. Environmental Protection Agency (EPA) to promote government/industry partnerships that encourage cost-effective technologies and market-based approaches to reducing air polluti on. There are seven San Juan Basin producers 1 that are currently active members of the Natural Gas STAR Program. The VISTA Program is modeled after

Natural Gas STAR.

This option involves establishing new partnerships or extending existing partnerships that encourage voluntary measures that reduce emissions and provide industry payback through improved operation and maintenance efficiencies. The IBEMP option is b ased on and is intended to extend upon the successes achieved in EPA’s Natural Gas STAR Program a nd to complement the newly established VISTAS Program.

The central ideas of this option

• Increasing efficiency will result in more productivity, less emission, and increased revenue.

• Complementing EPA’s Natural Gas STAR Program and VISTAS program to focus on the pollutants not covered in these programs

• Collection and use of the Best Management Practices (BMPs) from around the world, latest innovative technologies, and innovative solutions found by IBEMP members.

The air quality benefits include reductio n of criteria pollutants such as NOx, SO 2 , PM 2.5 , PM 10 as well as green house gases CO 2 and CH 4 . The success of the EPA’s Natural Gas STAR Program is well documented. According to the EPA’s Gas Program, “Since the Program’s launc h in 1993, Natural Gas

STAR Partners has eliminated more than 220 billion c ubic feet (Bcf) of methane emissions, resulting in approximately $660 million in increased revenues.” One Natural Gas STAR Partner has achieved the 18% to 24% fuel saving and reduction of 128 Mcf of methane emission per unit per year after installing an automated air to fuel ratio (AFR ) contro l system called REMVue. According to engine manufacturers, new generation engin es have benefits over older gene ration such as low operating cost, high thermal efficiency, low emissions, maintenance si mplicity, and low repair cost which will help in recovering the cost of investment faster. An exampl e of rapid improvement in the engine technology is the new Cummins-Westport engine, which is capable of peak thermal efficiency of close to 40% with 0.01 g/bhp-hr PM and 0.2 g/bhp-hr NOx emission. Even though Cummins-Westport engines and new generation engines from other engine manufacturers ar e geared towards transportation sector at present because of tighter emission standards, the improved engine technologies will help reduce the pollution in the other industrial sectors as the demand grows for efficient engines.

____________________________ 1 BP, Burlington Resources, ConocoPhillips, Devon Energy, Williams Production, Energen Resources, and XTO EnergyOil & Gas: Exploration & Production – Midstream Operations

11/01/07 137 Under this option, the time period to offset the cost of the replacing old engines with a new generation engines can be estimated through analysis of data fro m laboratory testing. Such data may be available from engine manufacturers or obtained through indepe ndent laboratory engine performance tests. The voluntary comparative laboratory performance a nd emissions testing (e.g., operating cost) and documentation would be performed by an independent t est laboratory. In addition, voluntary laboratory and field-testing of a select group of existing engin es (e.g., uncontrolled small, < 300 hp, engines) could provide a means to identify cost-effective modifications to improve engine efficiency and reduce engine emissions (Lazaro 2006, SERP).

Under this program the increased revenue from methan e mitigation and fuel and maintenance savings can

offset the cost of investment in the BMP and new technologies or equipment. In addition, under the proposed IBEMP option, partner members’ mitigation efforts will be fully recognized and promoted similar to the recognition of partner contributi ons under EPA’s Natural Gas STAR Program and New Mexico’s VISTAS Program. Mitigation efforts can be recognized through awarding of emission credits (which can be traded in an emission market system, OOT-3). These efforts will also provide benefits to members through improved public and investor relations.

Since the IBEMP option is a voluntary program, part icipating members will have control or choice on mitigation decisions that are made. This provid es opportunities for choices that provide a return on investments in best management practices and on ne w equipment and technology. As such, this option does not impose a burden on participating partners. Although, being a partner under this option would not relieve an operator from complying with non-voluntary measures or options, BMPs or other commitments made voluntarily under this option ma y facilitate compliance with other mandatory measures that may be adopted or come into play.

II. Description of how to implement A. Mandatory or voluntary : The participation in the program is voluntarily

B. Indicate the most appropriate agency(ies) to implement : Through the New Mexico Environment Department under or a part of its VISTAS Progr am and/or in partnership with the Colorado Department of Public Health and Environment. The USEPA Gas Program may also be interested in collaborative partnerships with the Four Corners Air Quality Task Force.

III. Feasibility of the option

A. Technical : The success of the EPA’s Natural Gas STAR Program is a clear indicator of the technical feasibility of this program.

B. Environmental : The Best Management Practices, includi ng equipment upgrades are well established in the oil and gas industry and adoption of these measures will provide opportunities for significant

and achievable emission reductions.

C. Economic : This program is economically feasible be cause innovative technologies and BMPs will result in increased productivity, fuel saving, and envi ronmental benefits, which in return offset the cost of investment. The previously referenced EPA Natural Gas STAR Program example illustrates that significant savings can be achieved in reduced fuel consumption (e.g., in one case that covered 51 engines reduction in excess of 2,900 MMcf or an average of 78 Mcf per day per engine, when adjusted for load, was achieved over a two-year pe riod). The final payout period was 1.4 years by taking into consideration of fuel saving of $4.35 million at a nominal value of $3/Mcf.

IV. Background data and assumptions used

1. United States Environmental Protection Agency (USEPA) Natural Gas STAR Program

< http://www.epa.gov/gas/ >Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 138 2. New Mexico San Juan Voluntary Innovative Strategies for Today's Air Standards (VISTAS)

< http://www.nmenv.state.nm.us/aqb/projects/SJV/index.html >
3. Engine Manufacturers: < www.cat.com >, < www.cummins.com >, < www.cumminswestport.com >.
4. Argonne National Laboratory, Strategi c Emission Reduction Plan, Draft, 2006

5. Near-term commercial availability of small clean efficient engines

6. Near-term commercial av ailability of advanced engine technology

V. Any uncertainty associated with the option Low to medium.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups Establishing and implementing an e ffective IBEMP is the facilitation of voluntary participation of San Juan oil and gas producers. There are no key crossover issues with other source groups.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 139 

### Mitigation Option: Voluntary Programs

I. Description of the mitigation option

Overview This option describes voluntary programs to implem ent mitigation strategies and achieve air quality benefits that are above and beyond the requirements of regulations and permits. This option is not meant to replace the Voluntary Partnerships and Pay-back Incentive mitigation option, nor is this option meant to indicate voluntary implementation should be applie d to existing or future requirements necessary for improvement of air quality. There are situations in which mandatory measures are the only system that will result in emissions reductions that are high-im pact, consistent, and necessary. There are also situations in which voluntary implementation of strategies may be a method to achieve emissions

reductions in a time- and cost-effective manner. Vol untary programs allow participants to demonstrate

their commitment to the issue and to local commun ities. Challenges to success with voluntary programs include publicizing a program to make it well-known, creating a list of strategies and technologies that may be implemented voluntarily, offering incentives sufficient to attract program participants, and quantifying emissions reductions adequately and consistently to estimate results.

Air Quality and Environmental Benefits

• Air quality improvement because voluntary measur es would achieve emissions reductions beyond regulatory and permitting requirements.

• Depending on strategy/technology, other environmental benefits may exist.

Economic

• Capital investment from participants for voluntary measures and reporting.

Trade-offs

• Air quality improvement

• Positive public relations

• Agency's costs for administration and tracking.

II. Description of how to implement

A. Mandatory or voluntary: Voluntary. The New Me xico Environment Department already administers a voluntary program called VISTAS (Voluntary Innovative Strategies for Today's Air Standards) that is modeled after EPA's Natural Gas STAR Program. To increase implementation, the agency could compile of list of mitigation options not otherwise require d by regulation or permit, as a list of "qualifying" voluntary measures for VISTAS. More information about VISTAS is available at: http://www.nmenv.state.nm.us/aqb/projects/SJV/index.html . Quantification of benefits and measurement

of other results is essential to ensure accountabilit y in a voluntary program and increase likelihood of success of the program. In addition, participants or the administrator of a voluntary program should describe voluntary actions by producing "Lessons Le arned" papers, which are short descriptions of practices and technologies employed, benefits and challe nges, feasibility, and implications for future use of the same voluntary actions. B. Indicate the most appropriate agency(ies) to implement: State Environmental Agencies

III. Feasibility of the option A. Technical: Good feasibility due to flexibility and choices regarding participation and specific technology(ies) implemented. Potential voluntary measures for the oil and gas industries may include, but are not limited to, the following:Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 140 • Plunger lift cycles for removal of liquid buildup and minimizing well blowdowns

.

• Device on tanks to control over-heati ng, such as bands of insulation.

• Electrification where possible.

• Centralization of tank batteries to decrease truck traffic.

B. Environmental: Excellent feasibility, however envi ronmental benefits depend on control strategies. Select control strategies may have other air or non- air environmental impacts, such as SCR's ammonia slip.

C. Economic: Feasibility depends on incentives. Ec onomic feasibility often increases in response to incentives. Participation in voluntary programs for companies is often based on a cost/benefit economic analysis, and incentives can provide a deciding factor. Potential incentives would be determined by the implementing agency and may include the following:

• “Good Citizen” marketing

• Alternative to regulation, if any exist

• Paybacks/savings

• Consideration for expedited permits, if possible

• Parametric monitoring less strict or other requirement leniency, if possible

• Tax credit/royalty rate reduction

• For Federal land, modification in standard stipulations, if possible.

• “Credit” given like an Environmental Ma nagement System on compliance history

IV. Background data and assumptions used Natural Gas STAR and San Juan VISTAS, both voluntary air programs in the Four Corners region.

V. Any uncertainty associated with the option High. Voluntary programs do not guarantee emissions reductions, nor are emissions reductions enforceable . Quantify of reductions through reporting may lessen uncertainty but do not guarantee or enforce reductions.

VI. Level of agreement within the work group for this mitigation option Medium. This option writeup stems from a discussion at the November 8, 2006 meeting of the Oil and Gas Work Group.

Some members of the work group expressed concern th at mandatory application of the strategies outlined in this document prior to analysis by a regulatory agency may preclude consideration of advantages and disadvantages from voluntary programs. There was also some discussion of the concept of criteria for establishing whether a mitigation strategy is applie d under voluntary or mandato ry conditions should be developed to enhance capability for implementation of the options. These crite ria would provide an important tool to agencies considering options by better defining feasibility. Additionally, voluntary application of the mitigation strategies would facilita te the development and efficient implementation of these options via a “lessons learned” approach where mandatory application may prematurely dictate the method of implementation.

VII. Cross-over issues to the other source groups If a voluntary program has a wide range of participan ts, there are many cross-over issues to other source groups in terms of what voluntary measures could be implemented by those sources.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 141 

### Mitigation Option: Cumulative Inventory of Emissions and Required Control Technology

I. Description of Mitigation Option The Four Corners Region is a hotbed of oil and gas activity. There are more than 20,000 oil and gas wells in the San Juan Basin and at least 12,500 additional ne w wells are proposed within the next 20 years. Oil and gas facilities are being located in remote are as and in neighborhoods and cities. The City of Bloomfield, NM, population of 7,200 people, has at least six major oil and gas processing facilities in very close proximity. A large elementary school near the cluster of these facilities north of Bloomfield

was evacuated in 2006 due to an accidental release of noxious emissions from one of these gas plants.

A cumulative inventory of total emissions from the large oil and gas facilities near densely populated areas should be conducted prior to the permitting of additio nal facilities. It has been reported that at least one new, large, petroleum processing facility is on the drawing board for the Bloomfield area.

All oil and gas facilities, large or small, should be required to report all emissions to appropriate governing agencies annually. A cumulative inventory of emissions is necessary.

Installation of best available technology emission control equipment on ALL oil and gas facilities should be MANDATORY to greatly reduce the release of pol lutants into the environment. All internal combustion engines should be required to be fitted with catalytic converters.

II. Description of how to implement A. Mandatory or voluntary : Mandatory.

B. Indicate the most appropriate agency (ies) to implement : States of New Mexico and Colorado.

III. Feasibility of the option

A. Technical : is not clear whether the intent was to have a yearly report of emissions output based on continuous emissions monitoring for all pollutants (ver y expensive), or if the intent was to have the operators estimate the amount of emissions based on what sources had been operational during the year. Option also needs to define what levels of the given pollutants would be acceptable to assess feasibility.

B. Environmental : None

C. Economic : None

IV. Background data and assumption used Bloomfield area ozone levels are already periodically high according to monitoring. Any consideration of permitting additional large oil and gas facilities near Bloomfield should include risk of increasing levels

of ozone.

An example: The North Crandall Compressor Station located within the City of Aztec is permitted by NMED Air Quality Bureau at 176.3 tons/yr (tpy) of Nitrogen Oxides (NOX), 39.4 tpy of Carbon Monoxide and 75.9 tpy of Volatile Organic Compounds (VOC's). There is a warning sign on the fence that states "Warning Hazardous B.T.E.X. emissions may be present." B.T.E.X. compounds are toxic to humans and wildlife. Several homes are located near this facility.

In comparison to the refineries and gas processing f acilities in the Bloomfield area, the Williams Crandall Compressor Station is small but it is permitted to em it about 292 tons of pollutants per year into the atmosphere. Cumulative permitted emissions from the very large Bloomfield facilities are unavailable at

this time.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 142 Oil and gas facilities are sources of many hazardous pollutants such as NOX, SOX, VOC's, methane, hydrogen sulfide, etc. Many of these pollutants contribute to respiratory diseases, cardiac diseases and some of them are carcinogens. Hydrogen sulfide is a deadly neurotoxin.

V. Any uncertainty associated with the option None.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups TBD.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 143 

### Mitigation Option: Mitigat ion of Hydrogen Sulfide

I. Description of Mitigation Option Hydrogen sulfide (H2S) is a deadly neurotoxin. Si nce H2S contamination is becoming more widespread, for the safety of the public and the oilfield empl oyees ALL wells should be tested for H2S by the well operators at least twice per year and the test results reported to appropriate agencies.

The companies provide H2S training and monitors fo r the employees. The employees are trained to be aware of H2S, but the general population is not. Th e typical rotten egg smell is a familiar warning to oilfield employees, but the general population who lives in close proximity to H2S wells are not informed about the dangers of an H2S release.

Public information programs on the dangers and toxic ity of oil and gas pollutants and most importantly H2S, must be made available to the people. Id eally, gas wells and refineries should be isolated away from the general population; however, oil and gas facilities are being estab lished in populated areas and vice versa. Houses are being built next to oil and g as sites. For the health of the public, exposure to H2S and other petroleum related toxics must be prevented.

II. Description of how to implement A. Mandatory or voluntary : Mandatory.

B. Indicate the most appropriate agency (ies) to implement : The companies and the States of New

Mexico and Colorado.

III. Feasibility of the option

Not considered.

IV. Background data and assumption used For H2S information, do a Google search on Dr. Kaye H. Kilburn MD, and Professor of Medicine at the University of Southern California. He is a leadi ng researcher on chemicals such as hydrogen sulfide and

diesel exhaust.

The Bureau of Land Management has been collecting data on the wells contaminated by hydrogen sulfide

in the San Juan Basin.

Quick statistics are as follows:

 More than 375 wells test positive for H2S

 H2S is present in at least 5 formations

 11 producers have reported H2S wells

 A lot of the small producers did not report, so these numbers are likely higher.

Sour gas (H2S) fields are common in Colorado and New Mexico. New Mexico has a State Regulation with an ambient air quality standard for H2S; how ever, it is reported that NMED does not have H2S measuring equipment. H2S must be closely monitore d and controlled by the companies and the State and Federal agencies. It can be deadly.

V. Any uncertainty associated with the option TBD.

VI. Level of agreement within the work group for this mitigation option TBD.

VII. Cross-over issues to the other source groups TBD.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 144 

### Mitigation Option: Encourage St ates Importing San Juan Basin Natural Gas to Require

Pollution Control at the Source

I. Description of the mitigation option States that import San Juan Basin natural gas should require the gas be produced and transmitted in an environmentally clean method. End users should have a responsibility for the sources of pollution generated from natural gas production.

Recent California legislation banning importation of power from sources that generate more greenhouse gases than in-state natural gas-fired plan ts leads to this related issue.

Much of the natural gas used in these plants as well as in the residential sector is imported from other states or other countries. One published article 1 states that 85% of the natural gas used in California is from out-of-state and that one-quarter of this comes fr om the San Juan Basin. Other states may also be using San Juan Basin natural gas. It is disingenuous for states to claim to be producing clean power or using clean gas for residential use when the produc tion of fuel for that “clean” power plant or clean burning appliance is creating serious air and water quality problems at the source of the fuel. If the user states are seriously concerned about improving ai r and water quality they should address out-of-state impacts as well as in-state impacts.

II. Description of how to implement

A. Mandatory or voluntary: Adoption of a “clean fuel import policy” by user states would necessarily have to be voluntary. However, the application of such a policy by a user state, once adopted, could and should be mandatory for fuel importers. B. Indicate the most appropriate agencies to implement: Implementation of the policy in user states coul d be by the regulatory agencies or commissions charged with oversight of investor-owned or p ublicly-owned electric utility systems. In some cases legislation may be necessary to implement this policy. There is a need to develop an inventory, stat e-by-state, of customers who are importing natural gas from wells in the San Juan Basin. The firs t step in implementation would involve contacting user states and urging adoption of policy or le gislation requiring importation of “clean” natural gas; a definition of “clean” must be developed.

III. Feasibility of the option

A. Technical: It may be difficult to devel op a good working definition of what constitutes acceptably “clean” natural gas. This is also a legal issue and one must work within the framework of the Federal

Clean Air Act and Clean Water Act as well as individual state statutes.

B. Environmental:

Should be feasible

C. Economic: Could eventually lead to higher costs for electricity in user states due to the rightful inclusion of environmental costs of fuel production.

D. Political: Could be very difficult to implement in some states

IV. Background data and assumptions used Assumption that most natural gas produced in the San Juan Basin is exported to other states. The figures

cited in Section I should be checked/verified.Oil & Gas: Exploration & Production – Midstream Operations

11/01/07 145 V. Any uncertainty associated with the option Yes; response of user states unknown.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other Task Force work groups Significant cross-over to the Power Plants and Oil & Gas Work Groups

________________________________ 1 High Country News , Dec. 25, 2006, p. 12.Oil & Gas: Public Comments

11/01/07 146 

### OIL & GAS: PUBLIC COMMENTS

Oil & Gas Exploration & Production Public Comments

Comment Mitigation Option If "many companies BMPs in place already," then why does a mandatory approach to BMPs seem implausible. This should be a cost of doing business in this area; a cost that is well-absorbed by most other companies. Best Management Practices (BMPs) for Operating Tank

Batteries

VRU's have one big technical problem no t addressed, the introduction of air in the gas. Air is made up of Nitrogen and Oxygen two contaminates that the gas pipeline companies refuse to take into their system. If one VRU allows air to enter the gas system, t hen the whole gas system must be shut down or flared in the field. The gas companies must be forced to take air in reasonable quantities into their system. The gas pipelines will argue that it is unsafe, if that is true then all t he gas supplying houses in the Colorado front range must be shutdown becaus e air is added to improve quality. Installing Vapor Recovery Units

In the 60's and 70's this type of water removal was tried in the northern Rockies. The amount of saltwater disposal was huge and the beds may only last a day or two before they must be changed. Dehydrators / Separators / Heaters

Glycol pumps are a critical item and any replacement system must have a high reliability. 5KW generators w ill had NOx, CO, CO2 and decrease reliability. Kimray pumps with flash gas separators redu ce emissions and keep the system reliable. the gases recovered from the pump gas separator can be used for fuel MOST of the time. In some cases where the gas stream is high in liquefiable hy drocarbons (those with molecular weights higher than 40) the pump gas separator vapors will not burn reliably or completely cause unreliable operators and increased emissions. In the case of gases with high liquefiable content, vent gases need to be flared (burned). Zero Emissions (a.k.a. Quantum Leap) Dehydrator

We strongly agree that an initial voluntary monitoring effort, followed by mandatory reporting and monitoring requirements, should be initiated by the operators to measure concentrations and species of VOCs and HAPs and other flaring by-products. Venting versus Flaring of Natural Gas during Well Completions

We strongly agree that co-location and centralization of new oil/gas field facilities should be voluntarily implem ented by operators. We also agree with the approach of state and fede ral agencies and mineral management agencies proactively integrating this approach into planning and permitting

processes. Co-location /
Centralization for New
Sources

The present laws will not allow this option. TEG (glycol) units must be permitted at a maximum rate. In the Rockies the maximum rate is only required for a few months during the year. Good operators adjust their pumps as needed to save fuel and lower emissions, but they get not credit for doing so because their permits are set. GLYCALC uses all kinds of default assumptions, this does not replace good engineering and the ability to make real life adjustments. Other design and simulation programs should be allowed without any legal ramifications. Control Glycol Pump

Rates

Mitigation option is both economically feasible and environmentally beneficial, as a result we strongly agree with their implementation. Control Glycol Pump

Rates

Mitigation option is both economically feasible and environmentally beneficial, as a result we strongly agree with their implementation. Convert High-Bleed to
Low or No Bleed Gas
Pneumatic Controls

Mitigation option is both economically feasible and environmentally beneficial, as a result we strongly agree with their implementation. Optical Imaging to
Detect Gas LeaksOil & Gas: Public Comments

11/01/07 147

Comment Mitigation Option Instrument gas or instrument air is used to control facilities. These controls maintain the emission control system, gas quality controls and safety shutdown systems. If the instruments air/gas system lacks sufficient quantity and quality, the controls will fa il and emissions, quality and safety
devices can fail with undesirable results. At small and remote sites air compressors will be unreliable and gas must be used. Convert Gas Pneumatic
Controls to Instrument

Air

Oil & Gas Stationary RICE Public Comments

Comment Mitigation Option The SUGF agrees that new air quality management strategies such as this option should be implemented to address cumulative air quality impacts. It is highly recommended that this option be considered by the regulatory agencies and be applied to both new and existing engines, particularly units of less than 300 horsepower. Although horsepower levels are lower and operating hours may be limited, emission rates of these smaller units are higher than larger units. As a single source, emissions may be minimal, but collectively with other area sources it may have a cumulative affect. Industry Collaboration

Comments below are specific to the mi tigation option as currently written, which assumes the power requirement would come from the power grid. A second alternative is also provided below as a sub option assuming the power comes from on-site generators. We recommend including both alternatives to this option. Comments are also provided on the analysis of this option under the cumulative effects section of the public draft report.

Install Electric Compression (re-label as Alternative 1 - Power Grid, see recommended Alternative 2 addition below after comment # 6)

1. The overview is not consistent with overviews written for other mitigation options covered in the Task Force Repor t. As written, the overview presents a rather biased view on the viability of this option. The overview should provide a description of the option wi thout any discussion about the option's
technical or economic feas ibility. Possible physical re striction or modification requirements on installation for specific compressors should be removed and discussed under Sec III. Feasibility of the option, A. Technical. The last two sentences on the electric grid shoul d also be moved to the feasibility

discussion or deleted.

Under the mitigation option overview, we recommend inserting the following:

The selection of combustion engines for electric compression should be on case-by-case basis which will allow t he flexibility of evaluating necessary compressor interface modifications such as re-gearing to accommodate

electric motors.

2. The discussion and emission table under Air Quality/Environment is

inconsistent with discussions cover ed in the other mitigation options and
should be deleted. Please see our comments on the Cumulative Effects section analysis of this option. T he nationwide averages of emissions from power plants operated by the three identified companies would not be representative of the power suppli ed from the Western Power Grid.

We recommend inserting the following under the mitigation option overview: Install Electric CompressionOil & Gas: Public Comments

11/01/07 148

Comment Mitigation Option

The noise from continuously running internal combustion engines can be an issue for the nearby residents. The switch to electric motors will also help cut down the noise in the oil and gas operation.

3. The economics as written only co vers the costs of the option if implemented. To provide a balance picture both costs and economic benefits should be covered. The following points should be included in the discussion:

a. In case of electric motors connected to power grid, there is virtually no

maintenance cost. b. The electric rates in the night are cheaper compared to peak times. This

will result in additional s aving for oil and gas industry.
c. The need for less maintenance of elec tric motors and localized electric grid will result in fewer maintenance trips for the oil and gas workers which will help in controlling dust as well as minimize impact on the wild a rea in the four corners region.

In the second bullet not sure what specific maintenance and repair costs we be borne by producers that are associated with the electric power source for electric compression. Maintenance and repair of substations and transmission lines, from the grid to subs tation, are typically borne by electric generators and i ncluded in rates to consumers.

The last bullet on suppliers/manufacturers is more an implementation issue than an economic issue. We recommend moving this discussion to description on how to implement.

4. Tradeoffs - We recommend striking any reference to new co-generation plants as means to supply power for electric compression, since the electric compression option requires no thermal pow er. As previously stated current plans for electric power generating within the western regional power grid should be adequate to meet even the most optimal electric compression demand that might develop.

5. Burdens - Since implementation of electric compression is voluntary the producers can evaluate which compress or conversions to electric are economically feasible. Economic burdens over the long term can be minimized and possibly turned into economic gain based on careful evaluation of return on capitol expenditures (e.g., lower electric motor vs. RICE engine maintenance costs). The assumed requirement for new electric power generation to support electric compression is speculative, since the degree of implementation of this option producer specific. We recommend deleting the sentence on capitol invest ment for new power plants. Also, existing plans for new generation may be sufficiently adequate to meet reasonably anticipated power requirements for implementing this option. We recommend consultation with the Power Plant Workgroup.

6. II. Description of how to implem ent and feasibility of option - See above

comments.

7. III. Feasibility of the option, C Ec onomics - On economics, we agree that costs need to be evaluated, including t he economic benefits, as previously mentioned. The need for modeling (air quality) to evaluate the air qualityOil & Gas: Public Comments

11/01/07 149

Comment Mitigation Option benefits is true about all of the options. Also, the planned modeling to address cumulative regional air quality im pacts is discussed elsewhere in the draft report. We recommend deleting the sentence.

ON-SITE ELECTRIC GENERATOR ALTERNATIVE TO GRID POWERED
ELECTRIC COMPRESSION

As written the current option identifies only one source of electric power, power from the grid. A second alternative to this option would be to supply power to the electric motors using local dedicated low-emission natural gas lean-burn electric generators. The elec tric compression using the lean-burn electric generator should be included as a second alternative for the "In stall Electric Compression" mitigation option.

We recommend that the Four Corners Air Quality Task Force add the following language to the Install Electric Compression mitigation option:

Mitigation Option: Install Electric Compression (Alternative - On-Site Generators)

I. Description of the mitigation option

Overview - As an alternative to grid po wer dedicated on-site natural gas-fired electrical generators can be used to supply power to electric motors that replace the selected RICE compression engines. The electric motors would be rated at an equivalent horsepower to that of RICE engines currently used for gas compression. The power sources for the electric compression could consist of a network of on-site gas-fi red electrical power generators. The alternative could be expanded to include consideration of replacement of other engines, such as, gas-fired pump-jack engines used as " prime-movers ."

The currently available gas electric ge nerator run on variety of fuels including low fuel landfill gas or bio-gas, pipeline natural and field gases. The gas electric generators are available in the power rating from 11 kW to 4,900 kW. Decisions on the use of on-site generators to replace natural gas-fired engines and the number of generators required would depend on a number of factors, including the proximity, spac ing and size of existing engines. As a simple example using the conversion fa ctor of 1 MW = 1,341 HP, adding a 1 MW natural gas-fired generator could replace an inventory of approximately 33 small (40 hp) internal combustion engines if these were reasonably close proximity, say spaced within a one or two mile radius. However, in "real world" operations, there will be several factors involved in determining the number of required gas-fired electrical generators; such as transmission loss, ambient operating temperature, load operating conditions, pattering of applied loads, etc.

Air Quality/Environmental Benefits

The emissions from gas electrical generators are relatively low compare to smaller internal combustion engines because of new technology and ability of controlling emission from big engines. For example a Caterpillar G3612 gas electrical generator with power rating of 2275 kW emits 0.7 gram/hp-hr NOx at 900 rpm which is equivalent to 0.0009387 g/W-hr. For comparative illustration with alternative 1, if you a ssume .... As stated in the mitigationOil & Gas: Public Comments

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Comment Mitigation Option option; "Control Technology Options for Four Corners Power Plant" (FCPP), the NOx emission from FCPP is approximately 0.54 g/mmBtu. Based on the assumption that efficiency of FCPP is 40%, the NOx emission from FCPP is approximately 0.002099 g/W-hr. This comparison shows that the gas electrical generator is more environme ntally friendly then using power from a coal based power plant. The baseline average emission for the Western Grid should be used to calculate the real emission difference between installing a lean burn electric generator to replace combustion engines.

The noise from continuously running internal combustion engines can be an issue for the nearby residents. The switch to electric motors will also help cut

down the noise in the oil and gas operation.

The need for less maintenance of elec tric motors and lean burn electric generator will result in fewer maintenance trips for the oil and gas workers which will help in controlling dust as well minimize the impact on wild area in the four corners region.

Economics

The initial capitol cost of installing gas electrical generator and electrical motor would be relatively high. As an example, a generator of 1 MW capacity can approximately support 33 combustion engine of 40 HP. A general purpose 40 HP engines costs about $1200.00 which re sults in capital cost of $39,600 for replacing 33 internal combustion engine with electric motors. The approximate cost of a 1.2 MW gas-fi red generator is $430,000. The total capital cost for replacing 33 engines with a gas fired generator will be about $470,000. However in long term the benefit in terms of emission reduction and saving in maintenance cost should help in recov ering the initial capital cost.

The maintenance cost of one big generat or is cheaper than maintenance of many smaller internal combustion engines.

The cost of running electric al wires to connect electr ic motors will much less than currently installed pipelines to ca rry natural gas for the small rich burn combustion engines.

Tradeoffs

In case of gas electric generators, there will be shi ft of emission from many internal combustion engines to one or several big internal combustion engine(s). There would be a net reduction in emissions which will depend on degree of conversion that each prod ucer deems economically feasible.

The cost and affects of running transmission lines from generator(s) to power electrical motors for gas compression needs to be evaluated.

Burdens

The cost to replace natural gas fired engines with electrical motors would be borne by the oil and gas industry.

II. Description of how to implementOil & Gas: Public Comments

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Comment Mitigation Option
A. Mandatory or voluntary: Volunt ary, depending upon the results of monitoring data over time.

B. Indicate the most appropriate agency (ies) to implement: State Air Quality agencies.

III. Feasibility of the option

A. Technical: The feasibility mainly depends on the close proximity of replaceable internal combustion engines and operating conditions of internal combustions engines in order of selection of gas electrical generator. The power, transmission line and substation requirements for on-site lean-burn generator system would need to be carefully considered in deciding the feasibility of this option.
B. Environmental: Factors such as f ederal land use restrictions or landowner cooperation could re strict the ability to obtain easements to the site. The degree to which converting to electrical motors for oil and gas related compression is necessary should be a consideration of the Cumulative Effects and Monitoring Groups. Emissions from on-site electric generators would more than off-set the natural ga s-fired engines that could be targeted for replacement (e.g., uncontrolled compressor engines or small rich burn pump jack engines). C. Economic: Depends upon economics of ordering electrical motors, the ability of the grid system to supply the needed capacity and the cost to obtain right of way to drop a line to a potential site. Suppliers/Manufacturers would have to be poised to meet the demand of providing a large number of electrical motors, large and small.

IV. Background data and assumptions used

The background data was acquired from practical application of using electrical motors in the northern San Juan Basin based upon interviews with company engineering an d technical staff.

Gas electrical generator information was obtained from Caterpillar's Website.

V. Any uncertainty associated with the option (Low, Medium, High):

Medium based upon uncertainties of obtaining electrical easements from

landowners a nd/or land management agencies.

VI. Level of agreement within the work group for this mitigation option TBD

VII. Cross-over issues to the other so urce groups (please describe the issue

and The SUGF agrees that implementation of this federally mandated level of emission control will minimize emissions from newly manufactured, modified and reconstructed engines after their respective effective dates. Follow EPA New
Source Performance Standards (NSPS)Oil & Gas: Public Comments

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Comment Mitigation Option The SUGF supports the control technology options listed above as the SUGF supports usage of Best Available Control Technologies on internal combustion engines located within the exterior boundaries of the Southern

Ute Indian Reservation. Use of SCR for NOx

control on lean burn engines Use of NSCR / 3-Way Catalysts and Air/Fuel
Ratio Controllers on

Rich Burn
Stoichiometric Engines
Use of Oxidation Catalysts and Air/Fuel
Ratio Controllers on Lean Burn Engines

Install Lean Burn Engines

As EPA commented on the Cumulative Effects Paper, it is unclear how the 4 Corners Task Force Interim Emissions Recommendations for Stationary RICE are being implemen ted.

The mitigation option Interim Emissions Recommendations for Stationary
RICE states that "BLM in New Mexico and Colorado are currently requiring
these emission limits as a Condition of Approval (COA) for their Applications for Permits to Drill (APD). These limits currently apply only to new and

relocated engines ... (compressors assigned to the well APD)..." However, we understand that BLM policy for a small engine COA as applied to an APD
is for new and replacement engines.

The Oil and Gas Workgroup should clarify how is the terms "relocated" and/or "replacement" are being defined by BLM and the USFS with respect to COAs for well located engines.

For comparison, EPA's NSPS for spark ignition engines will apply to new, modified, and reconstructed units starting in January 2008. The terms new, modified, and reconstructed are defined in Federal Regulation. Interim Emissions
Recommendations for Stationary RICE

We recommend adding the following next generation technology to the four currently included in this mitigation option:

Homogeneous-Charge Compression-Ignition (HCCI) technology was analyzed the by cumulative effects work group but was inadvertently omitted from the oil and gas work group mitigation option paper Next Generation RICE Stationary Technology. The following is a recommended text for inclusion in the Final Report:

Homogeneous-Charge Compression-Ignition (HCCI) Engine

I. Description of the mitigation option

Overview

Homogeneous charge compression ignition (HCCI) engines are under development at several laboratories. In these engines a fully mixed charge of air and fuel is compressed until the heat of compression ignites it. The HCCI combustion process is unique since it proceeds uniformly throughout the entire cylinder rather than having a discr eet high-temperature flame front as is Next Generation Stationary RICE Control Technologies – Cooperative Technology PartnershipsOil & Gas: Public Comments

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Comment Mitigation Option the case with spark ignition or di esel engines. The low-temperature combustion of HCCI produces extremely low levels of NOx. The challenge of HCCI is in achieving the correct i gnition timing, although progress is being

made in the laboratories. 1

Only a few experimental measurements of NOx from (HCCI) engines have been reported. The measurements are ty pically reported as a raw NOx meter measurement in parts per million rather than being converted to grams per horsepower-hour. Dibble reported a baseline measurement of 5 ppm when operated on natural gas. 2 Green reported NOx emissions from HCCI-like (not true HCCI) combustion of 0.25 g/hp-hr. 3 The achievable NOx emission levels are yet to be determined. It is not curr ently known if HCCI technology can be applied to all engine types and sizes. However, if all reciprocating engines
could be converted to HCCI so that the engines produce no more than 0.25 g/hp-hr, then the overall NOx emissions reduction would be 80% in both Colorado and New Mexico using the calculation methodology of the SCR mitigation option.

II. Description of how to implement

A. Mandatory or voluntary

It is too early to determine whether im plementation of this technology will be voluntary or mandatory.

B. Indicate the most appropriate agencies to implement

III. Feasibility of the option

A. Technical - HCCI is in t he laboratory stage of development.

B. Environmental - HCCI has the potential of extremely low NOx levels.

C. Economic - HCCI is not sufficiently developed to have proven economic feasibility.

IV. Background data and assumptions used

1. Bengt Johansson, "Homogeneous- Charge Compression-Ignition: The Future of IC Engines," Lund Institut e of Technology at Lund University, undated manuscript.

2. Robert Dibble, et al, "Landfill Gas Fueled HCCI Demonstration System," CA CEC Grant No: PIR-02-003, Markel Engineering Inc.

3. Johney Green, Jr., "Novel Combustion Regimes for Higher Efficiency and Lower Emissions," Oak Ridge National Laboratory, "Brown Bag" Luncheon Series, December 16, 2002.

V. Any uncertainty associated with the option (Low, Medium, or High)

HCCI has high uncertainty.Oil & Gas: Public Comments

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Comment Mitigation Option

VI. Level of agreement within the work group for this mitigation option

VII. Cross-over issues to the other so urce groups (Please describe the issue and which group.)

Oil & Gas Overarching Issues Public Comments

Comment Mitigation Option The Four Corners Air Quality Task Force (4CAQTF) is a noble way of beginning communication between our citizenry and the polluting industries. Hopefully some meaningful "common ground" can be reached that will produce measurable air quality improvements.

With a demonstrated failure of industry to "want to do their best" and when the "dollar gain" in a corporation's quarterl y report is the measuring stick for it's shareholders, the recommendations from the 4CAQTF is up against a mature lobby force very capable of stopping meaningful actions that will lead to measurable benefits to our air quality!

Therefore, spending serious time delib erating measurable benefits that could predictably occur if industry's su ggestion of "year round" drilling
EVERYWHERE as a means of ameliora ting their emissions to me, seems without merit. A simple catalytic conv erter on each of their established fossil fuel operated engines would be considered a "wonderful start" of industry wanting "to do their best".

Recommending to any state or federal land wildlife management agency to consider removing established seasonal habitat protection bans for the assumed benefit of distributing annual air quality pollutants should not be an option. Many years were spent by land management and wildlife management agencies formulating the habitats that need protection for identified species. The process to establish habi tat closures is elaborate.

Let us let this industry recommendation respectfully die and encourage installation of catalytic converters on indu stry's fossil fuel motors. This action does have measurable air quality results. As we drivers know, we are required by law to have catalytic converters on our vehicles as a way of demonstrating our contribution to improving air quality problems.

As a recommendation, I would only sugges t that if the oil and gas industry wants to recommend the lifting of this seas onal closure on identified lands, that THEY contact the state and federal agencies that have programming prerogatives over habitat and wildlife iss ues with their suggestion that lifting this ban would have beneficial measurable benefits for air quality concerns that outweigh wildlife concerns. The 4CAQTF should not be the "quarter back" for carrying the recommendation to state and federal habitat and wildlife agencies.

I make these comments as a degreed wildlife biologist with 27 years of experience. Respectfully, Warren J. McNall 900 Sabena, Aztec, NM Lease and Permit
Incentives for Improving Air Quality

on Public LandsOil & Gas: Public Comments

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Comment Mitigation Option Disagree - unlike Wyoming, Colorado ha s a shortage of state and federal specialists to monitor impacts from oil and gas development. As a result, monitoring of oil and gas impacts to wildlife would likely not happen. Streamlining the permit process would be beneficial to operators economically, but may be at the expense of area wildlife and habitat. Lease and Permit
Incentives for Improving Air Quality

on Public Lands

Regarding the paragraph:

"Monitoring has also not been a model experience in this area. According to reports of a May, 2006, internal assessment Pinedale, Wyoming, Bureau of Land Management field office, the office neglected its commitment to monitor and limit harm to wildlife and air quality from natural gas drilling in western Wyoming. A wildlife biologist who worked in that Pinedale office, Steve Belinda, is reported to have quit his job because he and other wildlife specialists were required to spend nearly all their time in the office processing drilling requests and were not able to go in to the field to monitor the effect of
the thousands of wells on wildlife."

Basically, I would suggest a more neutra l approach than the quoted paragraph. It is rather forceful, without sufficient fo llow-up. It would help our situation if we could see whether the Farmington offi ce is under similar pressures. Alternatively, examining the policies, rather than experiences, might make for a stronger position. For example, as the author seems to know a bit about BLM and permitting--she/he might instead look in to the use of categorical exclusions (CAX) which are currently used to ci rcumvent the environmental assessments (EA) that would normally be required to develop well fields on BLM land. (Sometimes this is also called streamlini ng.) How prevalent is this practice in the Four Corners, do CAX result in a lower standard of environmental review, and could this practice deleteriously impact 4C air quality? Lease and Permit
Incentives for Improving Air Quality

on Public Lands

In light of the current global climate conditions, lessening our overall impact on the environment is everyone's duty to the planet and its children's future. This task force should not be in the position of negotiating away wildlife habitat in exchange for mitigating measures that ought to be a duty of the oil and gas industry as a cost of doing business on this planet. Lease and Permit
Incentives for Improving Air Quality

on Public Lands

Mitigation option is both economically feasible and environmentally beneficial, as a result we strongly agree with their implementation. Economic-Incentives

Based Emission Trading System (EBETS)Oil & Gas: Public Comments

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Comment Mitigation Option

Economic-incentives ba sed emission trading syst ems (EBETS) have had varying levels of success nationa lly and have been less successful in geographic regions where pollutants are already causing harm to human health or the environment. It can also be argued that these systems lack incentives to improve environmental qu ality over economics. They can be more a function of market supply and demand driving the trades, not variations in regional human and environmental health "costs".

Multisectoral trading systems are comple x, increase challenges in emissions monitoring, and environmental just ice considerations become more complicated due to inequitable concentrations of source emissions and different pollutant mixing outcomes. (Regarding the federal Acid Rain Program, indeed, the nationwide level of emission s from electric utilities were halved since 1980, however, no geographic restrictions were imposed and many areas of higher pollution levels remained at higher levels.) As stated in the Task Force document, the major burden for the EBETS mitigation option would be administrative; however the full bur den must be assessed and coordinated among the state agencies. Not only would comparability and tracking of different types, sizes and ages of insta llations be extremely complicated, multipollutant emissions trading is challenging to monitor and enforce.

Although it would be impossible to hav e an emissions trading system that eliminates environmental injustice, a ca refully designed trading system that is rigorous, far-sighted, and includes geographic restrictions would have a much better chance of reducing localized injustices to human health and/or the

environment. Economic-Incentives

Based Emission Trading System (EBETS)

The proposed incentive to modify standard st ipulations for federal land if it is to be the relaxing or waiving of seasonal restrictions for wildlife while promoting year round drilling should not be a part of the voluntary program. Seasonal
restrictions have been written to benefit wildlife during times of the year when they are at increased risk due to weathe r, nesting, birthing, etc. The Wyoming experience has shown the potential negat ive impacts of intense drilling on wildlife, and how highly wildlife is val ued by a broad range of American people. With the pressures from the increase in drilling, wells, roads, and pipelines in the Four Corners area, we can ill afford to lose the wildlife protections from the stipulations that we currently have. Voluntary Programs

New Mexico and Colorado already have rules governing H2S, no need to add more rules that may conflict. Mitigation of Hydrogen
Sulfide

New Mexico Environment Department does have controls for H2S on paper,
but state environmental officials have validated that the state does not have H2S monitoring equipment. Mitigation of Hydrogen
Sulfide

Mitigation option is both economically feasible and environmentally beneficial, as a result we strongly agree with their implementation. Mitigation of Hydrogen
Sulfide

Rules that are capable of being enforced due to adequate staffing and necessary monitoring tools are what is needed to regulate this area. More rules that cloud the issue, or are effectively toothless due to lack of
enforcement infrastructure will not acco mplish the goals of this task force. Mitigation of Hydrogen
Sulfide