Country
Assessment
In New South Wales, under the Petroleum (Onshore) Act, 1991 , the beneficial use of gas may be permitted under a petroleum operations title only if that gas would otherwise have been flared or vented as part of licensed operations (Section 28B).
Similar language was not found in the laws and regulations of the other jurisdictions consulted. However, there are frequent references to good or sound oilfield practices and optimum recovery of resources.
At the national level, GHG emissions, including those associated with flaring and venting, and fugitive emissions from oil and gas operations, are measured according to NGER (Measurement) Determination, 2008, which the CER administers. Emissions measurement follows four general principles: transparency, comparability, accuracy, and completeness (Section 1.13). Several methods are described; those applicable to oil and gas operations are discussed in section 15 of this case study.
The environment plan required by the OPGGS (Environment) Regulations, 2009 , must provide for “appropriate environmental performance outcomes, environmental performance standards, and measurement criteria” (Regulation 10A[d]) and include “an appropriate implementation strategy and monitoring, recording and reporting arrangements” (Regulation 10A[e]). Regulation 14 states that the titleholder must report to NOPSEMA on its environmental performance at least annually according to the accepted environment plan. Part 3 details reporting and recordkeeping requirements and noncompliance penalties.
According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , emissions associated with flaring and venting during flowback and workovers must be measured—using methods consistent with NGER (Measurement) Determination, 2008—and reported. Part D.4 of the Code of Practice requires three types of regional methane monitoring programs. The first of these are baseline methane assessments, which are required to identify major methane sources before a proposed upstream oil and gas activity. These baseline studies should include measurement of carbon dioxide, oxides of nitrogen, and particulate matter before and after gas production starts. During the baseline study, fixed monitoring stations may be installed for routine monitoring after gas production begins.
The second type are regional methane assessment programs, which are required to characterize the existing natural and anthropogenic sources of methane emissions in a license area and in adjacent areas before exploration activity begins and immediately after full-scale production starts. Three assessments are required for exploration or production with hydraulic fracturing. The emissions may be estimated or directly measured.
The third type are routine periodic atmospheric monitoring programs, which are required every five years to detect any changes in methane emissions during the life of a producing asset. Fixed atmospheric monitoring stations must be established at least a year before gas production begins. According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019, “The number and location of monitoring sites must be sufficient to demonstrate shale production activities have not resulted in a regional enrichment of methane (and where relevant other GHG and particulate matter) above the background.” If significantly higher methane levels are detected, operators are required to identify the source and repair any leaks. A report must be submitted within a month of detection.
In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , a producer must measure volumes flared or vented (Section 801). The measurement must be with a meter—chapter 8 of the act details petroleum and fuel gas measurement schemes and meter criteria. The contents of a measurement scheme for metering include identifying each meter (by type), applicable Australian or other standards, testing methods and frequency, maintenance procedures, and other specifications (Section 637). Annual measurement reports are required (Section 650).
The Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022 , requires operators in Queensland to conduct routine visits to well sites, gathering systems, and processing facilities to inspect for leaks and ensure compliance with a leak management plan. Leaks from the surface equipment at a petroleum well and in gathering systems must be reported to the Petroleum and Gas Inspectorate within five days of detection.
According to Petroleum Regulations, 2021 , operators in Victoria must submit an annual report, which should include “a summary of actions taken to monitor, measure, eliminate or minimize” emissions from leaks, flaring, or venting during petroleum operations based on the ALARP criteria.
In Western Australia, as per the Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations, 2015 , companies must submit to DMIRS daily drilling reports, monthly production reports, and reports upon well completion. Volumes of gaseous petroleum (flared or vented) should be included in annual assessment reports (Schedule 2) and monthly production reports (Schedule 17). Regulation 34 of the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012 , requires operators to monitor and report emissions and discharges every three months.
In New South Wales, all petroleum operations require an environmental protection license, which mandates reporting land, noise, air, and water monitoring data as specified in each license. In South Australia, the Environment Protection Act, 1993 , mandates regularly reporting environmental quality and compliance with statutory requirements. No specific instructions on flaring, venting, or methane emissions were found in the legal and regulatory documents consulted for either state.
In Tasmania, the Mineral Exploration Code of Practice, 2012, requires licensees to ensure systems are implemented to control environmental, health, and safety hazards, and detect and respond to emergencies. Systems must be continuously improved via regular audits and reviews.
At the national level, no evidence specific to flaring, venting, or methane methods and measurement frequency could be found in the sources consulted. Regulation 14 of the OPGGS (Environment) Regulations, 2009 , requires that the environment plan implementation strategy “provide for sufficient monitoring, recording, audit, management of nonconformance and review of the titleholder’s environmental performance.”
Part D.5.1 of the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , requires routine inspections for the detection of fugitive methane emissions by “properly trained and competency-assured” personnel using calibrated gas detectors. Compressor stations and pneumatic devices must be inspected every quarter, well pad equipment biannually, and all other facilities annually. Inspection after major maintenance must be conducted within 48 hours of restart. If optical gas imaging equipment is used, an annual inspection as per the United States Environmental Protection Agency (US EPA) Method 21 must be performed.
In Queensland, the Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022 , requires operators to conduct leak surveys at least every five years. Still, the frequency depends on multiple factors, including age of the facility or equipment, characteristics of petroleum, facilities’ design, and proximity to other infrastructure. Surveys must be “conducted by trained personnel using industry-accepted gas detection instruments calibrated in accordance with the manufacturer’s requirements.”
In Western Australia, according to Regulation 34 of the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012 , emissions and discharges can be monitored and reported either continuously or at specific intervals as outlined in the environment plan. Operators are responsible for testing the monitoring equipment to ensure accuracy.
NGER (Measurement) Determination, 2008, establishes calculation methods and prescribes specific methods for various sources of GHG emissions, including those associated with flaring and venting, and fugitive emissions at oil and gas facilities. Engineering formulas are based on emission factors, fuel composition shares, destruction efficiency of fuel type, and other inputs. For oil or gas exploration and development, Subdivision 3.3.2.2 provides three emission estimation methods (formulas)—one with a variant, for emissions from flaring, depending on whether carbon dioxide, methane, or nitrous oxide is released. Subdivision 3.3.2.3 provides methods for estimating fugitive emissions from process vents, system upsets, and accidents. Similarly, Division 3.3.3 provides a detailed assignment of different methods for estimating emissions from flaring and fugitive methane emissions during crude oil production; Division 3.3.4 provides the same for crude oil transport; Division 3.3.5 provides the same for crude oil refining; and several other divisions provide methods for estimating fugitive emissions from the natural gas supply chain.
Regulation 14 of the OPGGS (Environment) Regulations, 2009 , requires titleholders to maintain “a quantitative record of emissions and discharges (whether occurring during normal operations or otherwise).” This record is used to assess whether the environmental performance outcomes and standards outlined in the environment plan are achieved and met. According to Regulation 27 (Storage of Records), a titleholder must store the environment plan and associated reports (monitoring, audit, review), and records (detailing emissions and discharges, calibration and maintenance of monitoring devices) “in a way that makes retrieval of the environment plan reasonably practicable.” Regulation 28 outlines the titleholder’s responsibility for making records available when requested by NOPSEMA or its inspectors.
The Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , follows the requirements of the Petroleum (Environment) Regulations, 2016 , on recording, monitoring, and reporting (Schedule 1, clause 11). In particular, the code requires maintaining inspection reports and keeping maintenance records, besides recording the volumes associated with leaks and vents and including them in mandatory reports (see section 13 of this chapter).
In Queensland, measurement schemes required by the Petroleum and Gas (Production and Safety) Act, 2004 , must include a description of the records to be maintained and the minimum period for which they will be kept. Such records may include anomalies, complaints, and actions to be rectified. Records associated with the safety management system are kept for seven years (Section 678A).
In New South Wales, the POEO Act, 1997 , empowers regulators to require records (Part 7.3) as part of their investigation powers. These requirements apply to all regulated activities and are not specific to flaring, venting, or methane emissions.
In Victoria, operations must maintain “quantitative records of emissions and discharges into the air… that can be monitored and audited against environmental performance standards” (Section 33 of Petroleum Regulations, 2021; see footnote 22).
In South Australia, the Environment Protection Act, 1993 , requires “the maintenance of a record of trends in environmental quality,” which can be used to ensure compliance with environmental requirements.
In Tasmania, the Mineral Exploration Code of Practice, 2012, requires licensees to document their systems for controlling or detecting environmental, health, and safety hazards. These documents must be retained for inspection purposes.
GHG emissions data collected under the NGER are used to develop Australia’s national GHG inventory and comply with the UNFCCC’s reporting requirements.
The results from the fixed monitoring stations for routine periodic atmospheric monitoring programs (see section 13 of this chapter) must be made publicly available via the Northern Territory Government portal.
In New South Wales, the Environment Protection Authority’s public register has all data required by environmental protection licenses.
There are civil penalties for noncompliance with the requirements of the OPGGS Act and the associated regulations. For example, a titleholder undertaking an activity without an environment plan is fined 80 penalty units. Similarly, 30- to 80-penalty-unit fines are imposed for not complying with the environment plan, not reporting incidents, not storing records per regulations, and other violations of the OPGGS (Environment) Regulations, 2009 . Violations of the field development plan provisions of the OPGGS (Resource Management and Administration) Regulations, 2011, can attract a 60- to 80-penalty-unit fine.
These penalties are enforceable under Part 4 of the Regulator Powers (Standard Provisions) Act, 2014. A penalty unit is currently set at $A 275 in the latest version of the Crimes Act, 1914. (Please note that Australia’s jurisdictions have assigned penalty units at different amounts.)
In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , operators are fined 500 penalty units for noncompliance with measurement obligations, including the measurement of any flared or vented petroleum (Section 801). In chapter 8, specific penalties ranging from 100 to 500 penalty units are assigned for noncompliance with various measurement requirements and regulatory notices. The penalty unit is set based on the Penalties and Sentences Act, 1992, and was increased to $A 154.80 as of July 2023.
In Western Australia, the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012 , specifies a penalty of $A 10,000 for noncompliance with the environmental plan requirements (Part 2) and $A 5,500 for noncompliance with monitoring and reporting requirements (Regulation 34).
In New South Wales, penalties can be imposed under various legislation governing the petroleum sector. These are referenced in Schedule 2A of the POEO Act . According to Section 78A of the Petroleum (Onshore) Act, 1991 , breach of environmental requirements can attract a 10,000-penalty-unit fine for corporations and a 2,000-penalty-unit fine for natural persons, with a 10 percent additional penalty for each day of continuing offense. In the latest edition of New South Wales’ Crimes (Sentencing Procedure) Act, 1999, the penalty unit is $A 110.
In Victoria, noncompliance with various requirements of the petroleum production development plan attracts a 240-penalty-unit fine, according to Division 6 of the Petroleum Act, 1998 . As of July 2023, the penalty unit is $A 192.31.
In South Australia, Part 11 of the Environment Protection Act, 1993 , allows the Environment Protection Authority to impose civil penalties. Under Part 12 (Environment Protection) of the Petroleum and Geothermal Energy Act, 2000 , a penalty of $A 120,000 is imposed for noncompliance with environmental requirements.
No evidence of nonmonetary penalties for violating flaring-, venting-, or methane-emission-related requirements were found in the sources consulted. However, many Australian regulators pursue a gradual compliance enforcement program, which includes prosecution for severe offenses. For examples, see the links for New South Wales’ and South Australia’s regulatory approaches in section 8 of this case study.
No evidence of specific performance requirements for flaring, venting, and methane emissions was found in the sources consulted. Most regulators, including NOPSEMA, the Northern Territory’s DEPWS, Victoria’s DEECA, and Western Australia’s DMIRS, require an environment plan for each proposed petroleum activity, the plan necessarily demonstrating reduction of emissions or environmental impacts and risks to levels that are ALARP or acceptable.
According to Section 10 of the Offshore Petroleum (Royalty) Act, 2006, royalty is not payable if the Western Australia state minister “is satisfied that the petroleum has been flared or vented in connection with operations for the recovery of petroleum” and flaring and venting did not contravene the OPGGS Act, 2006 , and associated regulations.
In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , an operator is exempt from paying petroleum royalty if the revenue commissioner is satisfied that the volumes flared or vented were part of exploration drilling (Section 591). The exemption applies to gas flared or vented during the production testing period but only up to 3 million cubic meters (Section 591A). As per Section 926, petroleum royalty is not payable for volumes flared or vented if approval was given under the Petroleum Act, 1923, before December 31, 2004.
In Western Australia, according to the Petroleum and Geothermal Energy Resources Act, 1967, and the Petroleum (Submerged Lands) Act, 1982 , operators may apply to the DMIRS for exemption from royalty payment for petroleum that—with the minister’s approval—is flared or vented in connection with petroleum recovery operations.
Under New South Wales’ Petroleum (Onshore) Act, 1991 , royalty is not payable if the minister approves gas flaring or venting (including of gas or other forms) for operations connected with petroleum recovery (Section 87).
In South Australia, according to the Petroleum and Geothermal Energy Act, 2000 , royalty is not payable if petroleum or any associated substance is “destroyed or dissipated in accordance with sound production practice” (Part 7).
In Tasmania, security deposits are required and must be high enough to cover environmental liability.