Mandatory GHG reporting nears for onshore US production

Sept. 5, 2011
By Mar. 31, 2012, owners of onshore petroleum and natural gas production operations must report their greenhouse gas (GHG) emissions for calendar year 2011, under the US Environmental Protection Agency's mandatory reporting of greenhouse gases rule.

Daniel Pring
Kleinfelder
Littleton, Colo.

By Mar. 31, 2012, owners of onshore petroleum and natural gas production operations must report their greenhouse gas (GHG) emissions for calendar year 2011, under the US Environmental Protection Agency's mandatory reporting of greenhouse gases rule.

The final mandatory reporting rule (74 FR 5620), signed Nov. 8, 2010, is in 40 CFR Part 98.

At first glance, the reporting requirements seem extensive and costly. Yet with a few steps, an operator can track, reduce, certify, and report its GHG emissions to the EPA and prepare for emerging legal requirements that are likely on their way.

This article outlines the new federal GHG requirements for source types, the implementation of a data-tracking collection system, and quality-control procedures.

Blurred boundaries

Part 98 forms the regulatory framework of the Greenhouse Gas Reporting Program (GHGRP). It covers suppliers of certain products that would result in GHG emissions if released, combusted, or oxidized; direct emitting source categories; and facilities that inject carbon dioxide underground for geologic sequestration or other purposes (Fig 1).

GHG source types for onshore production cover everything from natural gas-powered pneumatic devices to backflow venting from hydraulic fracturing operations (Fig. 1).

Part 98 includes several subparts for specific industries that range from electricity generation to lead production (http://www.epa.gov/climatechange/emissions/subpart.html).

The requirements for petroleum and natural gas system are in Subpart W.

Subpart W says petroleum and natural gas operations that emit 25,000 tonnes/year or more of CO2 equivalent must report annual methane and CO2 emissions from equipment leaks and venting, and emissions of CO2, CH4, and nitrous oxide (N2O) from gas flaring and from onshore petroleum and natural gas production stationary and portable combustion emissions, and combustion emissions from stationary equipment involved in natural gas distribution.

Owners must monitor and report all greenhouse gas emissions to the EPA by Mar. 31 for the previous calendar year.

EPA estimates that GHG reporting required under Subpart W will cover 85% of GHG emissions from the US petroleum and natural gas industry (Fig. 1). EPA further anticipates that about 2,800 facilities will report under Subpart W.

The first step for every owner or operator is to determine if its production operation is subjected to the new reporting requirements.

In short, an oil and gas production facility consists of all production and portable nonself-propelled equipment on or associated with a well pad, located within a single hydrogeologic basin. The EPA identifies these areas using the AAPG Geologic Province Code map that maps the underground formations to the nearest county lines.

Therefore, emissions reports must assess emissions from production fields and associated equipment, even if, for instance, the production field consists of a network of wellsites that cross state lines.

Emissions source categories

The EPA has defined a series of emissions source categories, outlining specific reporting requirements for various types of production equipment and facility operations (http://www.epa.gov/climatechange/emissions/data-reporting-system.html).

The first step in performing the initial assessment is the documentation of the amount and type of production equipment used and the extent of the facility's operations that are regulated. This asset inventory provides the basis for estimating emissions and determining if the facility is subject to reporting requirements.

According to the EPA, GHG source types for onshore production cover everything from natural gas-powered pneumatic devices to backflow venting from hydraulic fracturing. A current and comprehensive asset inventory assessment outlines all surface sites, including well pads and ancillary production facilities.

The EPA has outlined specific data requirements for the following source types:

• Natural gas pneumatic device and pump venting.

• Acid-gas removal process venting.

• Dehydrator unit venting.

• Well venting from liquids unloading operations.

• Gas well venting from hydraulic fracturing activities.

• Gas well venting from completions and workovers.

• Production storage tanks (Fig. 2).

• Well testing venting.

• Associated gas venting.

• Flare stack emissions.

• Centrifugal compressor venting.

• Reciprocating compressor rod packing venting.

• Stationary internal and external combustion sources.

• Fugitive emissions from production equipment.

• Enhanced oil recovery operations emissions.

The GHG reporting requirements include emissions from production tanks (Fig. 2).

The time and cost required to prepare this inventory depend on the accuracy and currency of the existing facility's documentation. If the documentation is readily available, then the inventory process and emission estimates could take a month or so. If site inventory requires visits to the site to gather asset information, then the process could take longer.

For most onshore systems, the type and quantity of service equipment and engineering estimates or direct measurements relating to specific sources will determine the GHG assessment.

If emission estimates from inventory analysis indicate that a facility falls under Subpart W requirements, an owner or operator must put in place the necessary mechanisms to collect, analyze, track, and report emissions. The EPA defines the required methods used for emissions calculations.

Emissions calculations, data requirements

Production facilities must report annual CO2, CH4, and N2O from applicable source categories outlined previously if total GHG emissions meet or exceed the 25,000-tonne threshold.

Owners must track and report GHG emissions under the specific governing source categories that EPA has outlined. Also they must maintain and make available at the request of the EPA records from all measurements, calibration reports, and calculation inputs and outputs. This includes all estimated and measured parameters used for obtaining the final GHG emissions figures submitted to the EPA.

Specific quality assurance-quality control (QA-QC) procedures outline how owners should collect certain measurements and maintain and operate associated equipment.

Examples of QA-QC procedures include the requirements for operating and calibrating a flowmeter or procedures for how missing data may be estimated. EPA has outlined these procedures to ensure that the data collected represent the field conditions and to standardize practices for data collection.

Emissions data tracking

Because of the volume of data that reporting facilities will need to collect and maintain, a data-collection system is an important step and can be organized with either spreadsheets or a database program (Fig. 3).

A GHG data-collection system should track the type and quantity of in-service production equipment and various facility operations for specific locations in a field (Fig. 3).

A database is typically the most efficient tracking mechanism because the data volume required to meet the reporting requirements for some operations can become overly burdensome to maintain with a spreadsheet.

The data-collection system should track the type and quantity of in-service production equipment and various facility operations for specific locations in a field. Each location is associated with a particular hydrogeologic basin, and once the data entry is complete, the emissions can be calculated for the facility.

GHG monitoring plan

A location must maintain a GHG monitoring plan that is subjected to the monitoring requirements. This plan must outline the methodologies and procedures for measuring, collecting, and recording data used to meet the reporting requirements. This includes any procedures for estimating missing data, and any best-available monitoring methods (BAMM) that are used when a particular monitoring method is not yet feasible for the reporting facility.

The EPA has designated the temporary use of BAMM to give the industry time to obtain the necessary monitoring equipment and to put procedures in place to meet the monitoring requirements For more information about BAMM see http://www.epa.gov/climatechange/emissions/downloads11/documents/Subpart-W-BAMM-factsheet.pdf.

Originally, facilities only could use BAMM until June 30, 2011.

On June 20, 2011, EPA proposed an amendment to the rule that would allow reporting facilities to use BAMM during the entire 2011 reporting year without submitting a request for approval to the EPA. This proposal would also allow operators additional time to file for the use of BAMM beyond the 2011 reporting year. This proposal was published in the Federal Register on June 27, 2011. OGJ

Oil & Gas Journal | Sept. 5, 2011

The author

([email protected]) is a principal professional with Kleinfelder in Littleton, Colo. He has 20 years of experience providing environmental consulting in areas ranging from air quality to pollution prevention. Pring holds a BS in environmental engineering from the University of Florida.

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