Page 1 of 6 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460

OFFICE OF
AIR AND RADIATION

Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting Rule Docket: EPA-HQ-OAR-2009-0923

Title: Additional Analysis of Combustion Costs for Onshore Production

Summary: This memo presents the additional analysis conducted to assess the costs for the onshore production segment to estimate and report incremental combustion emissions.Page 2 of 6 A DDITIONAL A NALYSIS OF C OMBUSTION C OSTS FOR O NSHORE P RODUCTION

Overview and Purpose

This memo presents the additional analysis conducted to assess the costs for onshore production segment to estimate and report incremental combustion emissions. For the April 2010 proposed rule, the combustion cost estimates assumed that reporters would use the Subpart C Tier 1 methodology or its equivalent and therefore inco rporated labor assumptions that were not specific to a particular industry segment. In response to the comments and final rule changes, EPA used assumptions tailored to the onshore production segment to estimate the costs for them to determine fuel consumption at compressor engines and drilling rigs. As explained below, the tailored analysis demonstrates that estimates based on the Subpart C Tier 1 methodology are conservative high estimates of the costs for the onshore production segment to report incremental combustion emissions under Subpart W.

Specifically, the tailored analysis shows that the cost to report combustion emissions under the final Subpart W rule is lower than the estimates based on the Tier 1 methodology. Therefore, EPA decided to retain the higher estimate (based on Tier 1 methodology) in the Economic Impact Analysis (EIA) for the final rule in order to provide a more conservative estimate of combustion-related costs. Table 1 shows the combustion costs from this analysis compared to those in the Economic Impact Analysis (EIA) to the final Subpart W rule.

Table 1. Onshore Production Combustion Emissions Reporting Cost Comparison

Combustion Cost per Reporter Total Segment
Combustion Costs Final Subpart W
EIA Cost $2,200 $2.16 million

This Analysis $1,396 $1.36 million

Background

In the April 2010 Subpart W proposal, EPA used a cost of $2,200 to report combustion emissions from onshore production using the Subpart C Tier 1 methodology.1 The Tier 1 methodology bases estimates on a fuel-specific default CO 2 emission factor, a default high heating value of the fuel, and the annual fuel consumption from company records. EPA received comments regarding the scope and burden of the combustion requirements under Subpart W (e.g., EPA-HQ-OAR-2009- 0923-1151-104 and EPA-HQ-OAR-2009-0923-1151- 105). In response to the comments, EPA has provided an external combustion equipment

1 See EPA-HQ-OAR-2008-0508-0004, U.S. EP A, Technical Support Document for Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory Reporting of Gr eenhouse Gases, January 30, 2009, for more information about the IPCC Tier methodology (pgs 10-15).Page 3 of 6 threshold for onshore production. Any external combustion equipment below a 5 MMBtu per hour rated heat capacity threshold does not have to report emissions, but only provide a count by type of equipment. Furthermore, EPA conducted additional analysis (below) to estimate combustion costs tailored to the onshore production segment.

Additional Cost Analysis for Combustion in Onshore Production

EPA expects that onshore production reporters who combust fuels that are not listed in Table C1 (i.e., field gas and recovered products from vent s), and therefore not eligible for the Tier 1 methodology, to use the Subpart W combustion method (40 CFR 98.233(z)) to estimate and report emissions from combustion sources. The Subpart W combustion method is similar to the Tier 1 methodology and directs reporters to cal culate emissions based on fuel volume and composition. The final Subpart W rule allows reporters to use existing company information or conduct an engineering estimate based on best available data for operating hours and gas composition. The key data required to estimate combustion emissions from equipment using produced natural gas that is not pipeline quality are rated heat capacity of the equipment, operating hours, and gas composition of produced gas. EPA expects most of the time (and therefore cost) spent using the Subpart W methodology to involve determining the rated heat capacity for each piece of equipment. The key data element required to estimate combustion emissions from equipment using natural gas that is pipeline quality or liquid fuels is the volume of fuel used; the emissions are then estimated using an emissions factor.

The cost estimates from the detailed analysis are based on a labor cost per unit of combustion equipment and an estimate of the number of combustion equipment expected to report to the rule. EPA tailored its assumptions to the onshore production segment to estimate the labor hours and costs for reporters to determine fuel consumption at compressor engines and drilling rigs. EPA estimated labor hours for compressor engines and drilling rigs because they are the two largest sources of combustion emissions in the onshore production segment. Also, based on its analysis of annual emissions from onshore production operators, EPA assumed the external combustion equipment threshold would make reporting combustion emissions from fired separators, heaters, acid gas removal units and glycol dehydrator reboilers negligible. EPA discusses this combustion equipment threshold further in “Equipment Threshold for Small Combustion Units,” (EPA-HQ-OAR-2009-0923).

Labor Hour Estimates for Onshore Production Emission Sources

EPA assigned the labor hours to determine combustion emissions for compressors and drilling rigs based on its engineering knowledge of the industry obtained through its voluntary greenhouse gas programs. For these labor hours, EPA assumed a Junior Engineer labor rate of $71.03. Please see Table 4-10 in the EIA (EPA-HQ-OAR-2009-0923) for more details regarding labor rates.Page 4 of 6 Estimating the Number of Reporting Drilling Events

EPA estimated 28,800 well drilling events will be reported using the drilled well count from the U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2006 for Natural Gas Systems and Petroleum Systems

, the Baker Hughes’ drilling rig count by state, and HPDI® database. The U.S. Inventory estimates that in 2006, 35,600 natural gas wells were drilled and 13,907 petroleum gas wells were drilled, including dry wells in the United States. Baker Hughes provides drilling rig counts for each state, which ar e shown in Exhibit A. The HPDI® database provides real well property data such as well counts, oil or condensate throughput, and gas throughput by state, AAPG basin, and operator. EPA allocated the drilled events from the U.S. Inventory to each state using the percentage of drilling rigs in each state provided by Baker Hughes. EPA then determined the number of drilling events per well for each state using the
well counts from the HPDI ® oil and gas database. Finally, EPA determined the number of wells drilled for each reporting onshore production facility by multiplying the number of wells in that facility by the average number of drilling events for the state in which that facility is located. This calculation was done for each reporter using Equation 1 below.

S S US

R R well p d well d = Equation 1

where,

d

R = the number of wells drilled for reporter, R.
well R = the number of wells operated by reporter, R; provided by HPDI®
well S = the total wells in the state from which the reporter, R, is operating; provided by

HPDI®
d US = the total wells drilled in the U.S.; provided by the DOE Energy Information
Administration.

p S = the percentage of drilling rigs in the state that the reporter, R, is operating from; provided by Baker Hughes.

Estimating the Number of Reporting Compressors

EPA estimated that combustion emissions from 28,450 compressors in the onshore production segment will be reported using the U.S. Inventory of Greenhouse Gas Emissions and Sinks:
1990 – 2006 and the HPDI® database. EPA determined the compressors for each onshore production facility by apportioning the compressors from the U.S. Inventory by the gas throughputs (for natural gas systems compressors) and oil throughputs (for petroleum systems compressors) provided by the HPDI® database for each facility. EPA summed the compressors belonging to reporting onshore production facilities to determine the total compressors that will report combustion emissions.

Revised Onshore Production Total Cost to Report Combustion Emissions

EPA estimates onshore production reporters will incur labor costs of about $35.52 per drillingPage 5 of 6 event and $11.84 per compressor to determine the majority of combustion emissions from their facilities. EPA multiplied the labor costs by the number of reporting drilling events (28,800) and compressors (28,450) to yield $1.36 million, the total cost to report combustion emissions in the onshore production segment. EPA also divided the total combustion cost by the 981 reporting onshore production facilities to determine an average combustion emissions reporting cost of about $1,396. Given that the tailored onshore production combustion cost estimate is less than the estimate based on Tier 1 ($2,200 per reporter), EPA retained the higher estimate in the Economic Impact Analysis (EIA) for the final rule in order to provide a more conservative
estimate of combustion-related costs.

Table 2 presents the labor activities and costs for a junior engineer to report combustion emissions from drilling rigs and compressors.

Table 2. Responsibilities, Labor Hours, and Costs to Monitor Onshore Production
Combustion Emissions

Element Onshore Production Labor Activities and Cost

Labor Activities and Hours Cost per Event Events Reported to Subpart W Total Reporting Cost per Year

Onshore Production Drilling Rig Combustion Emissions

Junior Engineer ($71.03/hr) Gather data from drilling contractor that monitors rig fuel use (30 minutes / drilled well) $35.52 per drilled

well 28,800 petroleum and natural gas drilled wells in year 2006 $1.02 million

Onshore Production Compressor Combustion Emissions

Junior Engineer ($71.03/hr) Gather parameters to
estimate and calculated compressor fuel consumption (10 minutes / compressor) $11.84 per

compressor 28,450 compressors $337,000

Total

(entire onshore production segment) ­­­ ­­­ ­­­ $1.36 million

Average
combustion cost

per reporter $1,396Page 6 of 6 Exhibit A. Baker Hughes 2006 Drilling Rig Distribution by State

State Percentage Rig Breakdown

TX 49%

LA 8%

MS 1%

AR 2%

WY 7%
CO 6%

UT 3%

MT 1%

NM 6%
CA 2%

OK 12%

KS 1%

WV 2%

PA 1%

OH 1%