Western Australia is becoming more popular in the unconventional gas space, with the State potentially containing an estimated 280 trillion cubic feet of shale and tight gas.1 Most of this gas can be found in the Canning basin (in the Kimberley and East Pilbara regions) and the Northern Perth basin (Midwest region).
The increasing popularity of this resource, and the unconventional methods of retrieving the underlying hydrocarbons that include hydraulic fracture stimulation (known as 'fraccing'), has prompted the Department of Mines and Petroleum (DMP) to engage with a range of stakeholders and introduce new draft regulations governing exploration and production of petroleum and geothermal energy resources in onshore WA (Regulations)2. These Regulations have been released for public comment until 5.00pm (Perth time) on 30 May 2014 with a consolidated regulatory framework document expected to be released by mid-year.
This article summarises the key aspects of the new Regulations and highlights important operational and timing considerations that operators and titleholders should be aware of when planning their onshore activities.
The Petroleum and Geothermal Energy Resources Act 1967 (WA) (the Act) is the main legislation that governs onshore petroleum and gas activities. The Act is complemented by the associated Schedule of Onshore Exploration and Production Requirements - 1991, known as 'the Schedule', as well as other environmental and safety regulations.
DMP is responsible for assessing all drilling applications and associated safety, environment and resource management plans. The assessment of these plans determines whether an application is approved or declined. Onshore activities must further comply with other legislation that protects public health, the environment and water resources.
The WA Government stated that it is committed to a regulatory regime that ensures responsible development of the unconventional gas resource, while protecting the environment, groundwater resources and public health3. Onshore regulation is also evolving in the Eastern States with Queensland and South Australia taking proactive steps towards unconventional gas development. However, regimes in New South Wales and Victoria are seen to have a more restrictive effect on the development of these projects due to delays in approving activities and a shifting moratorium on the CSG industry in those states.4
The new Regulations provide a risk-based management scheme for onshore activities and require (among other things) that well management plans for drilling activities (including in respect of shale and tight gas), field development plans for the recovery of petroleum and approval for the rate of recovery of petroleum, are all approved by the Minister/DMP.
The key objectives of the Regulations include ensuring that operations are carried out in a proper and workmanlike manner, in accordance with good oilfield practices and are compatible with the optimum long-term recovery of petroleum. Set out below are the key aspects of the Regulations.
A petroleum title holder must have an approved well management plan (WMP) in force before undertaking any 'well activity' in its title area, and must carry out a 'well activity' in accordance with the WMP (except in an emergency situation). 'Well activity' means any activity relating to a well that is carried out during the life of the well - including fraccing, drilling, workovers, production or plugging and abandonment.
The requirement to have an approved WMP for all onshore wells is a new requirement introduced by the Regulations although currently, a titleholder does require an approval to drill before any wells are drilled. This requirement was introduced to model the requirements of the Commonwealth resource management regulations relating to offshore wells, which require that a 'Well Operations Management Plan' or 'WOMP' is submitted to NOPSEMA for approval prior to commencing an offshore drilling campaign.
A WMP must be submitted to DMP at least 30 days before undertaking a proposed well activity. However, DMP recommends that a WMP be submitted as early as possible - at least 90 days prior to drilling operations and at least 6 months in advance for larger scale projects. The content requirements of a WMP are set out in regulation 17 and Schedule 1. The DMP has also published guidelines to assist petroleum title holders in the preparation and submission of a WMP5.
Within 30 days after receiving an application, the Minister must either approve the whole (or part of) the WMP, provide notification that further assessment of the WMP is required or reject the WMP. As soon as practicable after making a decision, the Minister must give the petroleum title holder a written notice specifying the terms of the decision, including the date on which the plan takes effect (if applicable). Once approved, the WMP becomes a legally binding agreement between DMP and the title holder which will set out performance objectives, standards and criteria which the title holder will be assessed against.
An approved WMP can be amended by application to DMP. Any approved amended program is appended to the original WMP and will become the current activity program until superseded by any further activity program.
A WMP remains in force for 5 years from the date of approval, whether or not it has been amended since initial approval.
Prior to developing an oil or gas field, a titleholder is required to submit a field development plan (FDP) for assessment by DMP. Only a production licence holder (or applicant for a production licence) can apply to DMP for approval of a FDP.
A FDP is a description of how a petroleum licensee will manage and develop the petroleum resources for the lifecycle of the field within their title area in accordance with good oil-field practice. The content requirements for a FDP are set out in regulation 48 and detailed in Schedule 3 (for petroleum) and Schedule 4 (for geothermal energy). The DMP has also published guidelines to assist petroleum title holders in the preparation and submission of a FDP6.
The requirement to have an approved FDP prior to developing an oil or gas field is currently a requirement of the existing regulations. However, the new Regulations will also introduce requirements for petroleum companies to have baseline water monitoring for their groundwater management strategies for field development. Baseline groundwater monitoring may also be required at the exploration phase of a project depending on the nature and location of the proposal.
The approval of a FDP under the Regulations is in two stages - submission of a preliminary FDP which outlines the proposed petroleum development and reservoir management, followed by submission of a final FDP.
After the preliminary FDP is submitted, DMP will prepare a technical paper which will be given to the proponent to assist in the preparation of the final FDP. The technical paper is essentially DMP's opportunity to comment on the preliminary FDP and once it has been received by the proponent, a final FDP can be submitted. The final FDP should address any issues raised by DMP in the technical paper and also incorporate the concepts described in the preliminary FDP to the extend they continue to be relevant. DMP may still seek further information after submission of the final FDP.
The recommended practice by DMP is to begin the FDP phase first through submission of a preliminary FDP, followed by submission of the production license application, and the final FDP (once the technical paper has been received).
Operators and title holders should allow for a period of approximately 5 months into their operations timetable to make provision for having a final FDP approved. Once a FDP has been approved, every 'well activity' must be carried out in a manner that is consistent with the FDP.
A variation of an approved FDP will be required if a 'major change' occurs - such as changing the development or management strategy of the field or a petroleum pool in the field, changing the plan for the development of additional petroleum pools in the field or introducing new methods for the recovery of petroleum from the field. A licensee must apply to the Minister for a variation at least 90 days before one of the above events occurs.
1 Source: Department of Mines and Petroleum and U.S Department of Energy 2013 (IEA).
2 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations 2014 (WA).
3 See Department of Mines and Petroleum Response to Report: 'Regulation of Shale, Cole Seam and Tight Gas Activities in Western Australia' dated 31 October 2011.
4 See Eastern Australian Domestic Gas Market Study - Australian Government Department of Industry.
5 WA Department of Mines and Petroleum, 'Guidelines for the Petroleum and Geothermal Energy Resource (Resource Management and Administration) Regulations 2014'(February 2014).
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