Hydraulic Fracture Stimulation
Technical Fact Sheet
Table of Contents
Introduction ...... 3
What is Hydraulic Fracturing? ...... 3
Why Does the Industry Use Hydraulic Fracturing? ...... 3
Hydraulic Fracture Design ...... 4
On-site Activities ...... 4
Site setup 4
Perforation 5
Injection of fluids 5
Flowback 7
Post-fracturing Activities ...... 8
Fracture growth measurements 8
Reporting 8
Monitoring for impacts 9
Issues and Environmental Concerns ...... 9
Subsurface contamination 9
Surface contamination 10
Induced seismicity 10
Water supply 10
APPENDIX - REGULATORY...... 11
Commonwealth Government 11
State and Territory Governments 11
Queensland 12
New South Wales 12
South Australia 13
Northern Territory 13
Western Australia 13
Victoria 14
Tasmania 14
References ...... 15
Hydraulic Fracture Stimulation Technical Fact Sheet Page 2 15 October 2015 Introduction Hydraulic Fracture Stimulation, commonly referred to as hydraulic fracturing, is currently performed in many basins around Australia. Santos has decades of experience using this technology in Queensland, the Northern Territory and South Australia. Hydraulic fracturing has been successfully used on wells in the Cooper Basin in South Australia for over 45 years (since 1969), and has consistently been used since the early 1980s to enhance oil and gas recovery. While ‘fracking’ (as it has become colloquially known) has been conducted in Australia for decades for conventional gas development, the transition to coal seam gas and shale gas has increased the attention on the technology. The first hydraulic fracturing experiment, which proved the possibility of increased productivity, was performed by Halliburton for Stanolind in Kansas, USA in 1947. The world’s first commercial hydraulic fracturing process took place on March 17, 1949 about 12 miles east of Duncan, Oklahoma, USA. The Society of Petroleum Engineers estimates that over 2.5 million hydraulic fracture stimulation treatments have been undertaken in oil and gas wells worldwide, with over 1.2 million in the United States.
In 60 years of exploration and production, Santos has drilled over 3,000 wells. Currently, Santos produces oil and gas from approximately 1,500 wells. To date, Santos has fracture stimulated over 1000 wells in South Australia, Queensland and the Northern Territory, with over 2,000 individual hydraulic fracture stimulation stages undertaken. According to the Australian Petroleum Production & Exploration Association (APPEA), the industry has fracture stimulated over 1,700 wells in Australia.
What is Hydraulic Fracturing? Hydraulic fracturing is a well stimulation process used to maximize the extraction of underground resources; including oil, natural gas, geothermal energy, and water. The oil and gas industry uses hydraulic fracturing to create and enhance or enlarge fractures in the rock to allow oil or natural gas to flow more effectively. Hydraulic fracturing typically involves injecting fluid made up of water, proppant and chemical additives under high pressure into the well to widen existing fractures or create new fractures (or pathways) within the target rock formation. Hydraulic fracturing is often performed sequentially at multiple depths, or stages, in a well corresponding with the location of the reservoir where the oil or gas is held. The number of fracture stimulation stages varies depending on the well and reservoir characteristics. Multistage fracturing operations are common in both vertical and directional wells. Why Does the Industry Use Hydraulic Fracturing? Hydraulic fracturing is a process used to enhance the productivity of a well. Hydraulic fracturing is a technology applied after the well is drilled and the drill rig has moved to another location. It is a process that is often used in circumstances where hydrocarbons (oil and gas) are tightly held in low permeability reservoir sands, coals and shales, to improve the productivity of the reservoir and enable economic production. Hydraulic fracturing is also sometimes repeated during the life of a well to boost declining oil or gas productivity. While not common in Santos operations, re-fracturing is used to create a “clean” fracture and drain parts of the reservoir not accessed previously.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 3 15 October 2015 What is Permeability? Permeability describes a rocks ability to allow gas or liquid to flow through it. High permeability means that gas and liquid can flow easily through a rock. Low permeability or ‘tight’ rock means that gas and liquid do not flow through the rock. This is when artificial stimulation is used to allow the flow of water, oil or gas through the rock formation. There are many factors that affect permeability, including but not limited to the rock type (e.g. sandstone is typically more permeable than shale), under-ground pressure and porosity.
The design and quality of the well construction is of paramount importance in managing and avoiding any potential environmental risks associated with hydraulic fracturing. Santos applies best practice in our drilling techniques and activities to ensure risks are managed appropriately. Refer to the drilling and well integrity technical fact sheet for additional information. Hydraulic Fracture Design The basis of well specific hydraulic fracture design is to produce hydrocarbons through an optimal number of hydraulic fracture stages, fracture length, fracture conductivity, and fracture height within the target rock formation. A number of considerations influence the final design for each hydraulic fracture stimulation design including: depth and thickness of the target zone lithology of target and bounding layers minimum horizontal stress across all layers thickness of the barriers above and below the target rock formation porosity and permeability of the reservoir and the barriers pore fluid saturations (percentage of pore volume occupied by each fluid, for example oil, gas or water) pore fluid properties (e.g. density, water salinity) well performance data, including flow rates, formation pressure and produced fluid properties formation boundaries (as identified from seismic data) bulk density, elastic properties and compressibility bedding planes, jointing and mineralisation natural fracture networks thickness of underlying formations and rock strength stress field analysis to determine the maximum principle stress direction and the minimum principle stress direction.
The hydraulic fracture design process accommodates detailed analysis of these parameters to specify a design that is contained within the target rock formation. The design models can model the fracture geometry; including fracture length and fracture height based on the geomechanical properties of the reservoir. On-site Activities The on-site activities include site setup, perforation of the well casing and cement into the target rock formation, injection of hydraulic fracturing fluid and ‘flowback’ of the injected fluid. Site setup Once the well is drilled, the drill rig moves away from the site and the hydraulic fracturing team moves onto location. Temporary storage facilities are established to contain the source
Hydraulic Fracture Stimulation Technical Fact Sheet Page 4 15 October 2015 water for fracturing and for the flowback water. Purpose-built mobile units are used onsite for storage of materials such as proppant and chemical additives and for blending of fracturing fluids. Perforation A perforation tool is lowered down the well and small holes (or perforations) - approximately 5 to 10 millimetres (~0.3 inches) in diameter - are made through the casing and cement at the depth of the target rock formation. There are two different ways to carry out this operation. Specially designed charges (casing guns) are lowered into the well to the target depth, and then from the surface the charges are initiated creating small holes in the casing and cement. Jet nozzles use abrasive hydro jetting technology with coiled tubing and proppant to create holes through the casing and cement. Once the perforations are created, then a mix of fluid and proppant is pumped into the well at high pressure.
Injection of fluids The next step is the injection of fluids into the well to initiate fracturing in the target rock formation and to keep the fractures open so that gas can flow to the well. Water makes up the majority of the fracturing fluid, with the next largest component being the proppant, which is transported into the fractures to prevent them from closing once the pressure is reduced. Hydraulic fracturing fluid typically consists of around 99% water and proppant, with the remaining volume consisting of a variety of chemical additives, however, this can vary by operation location. For example:
Hydraulic Fracture Stimulation Technical Fact Sheet Page 5 15 October 2015 In the Cooper Basin, the hydraulic fracturing fluid consists of a range of 93 to 95% water, 3 to 5% proppant and .5 to 2% chemical additives. In Santos’ Queensland coal seam gas operations, water accounts for approximately 90% of the hydraulic fracture fluid, proppant accounts for about 9% and the chemical additives account for the remaining 1% of the mixture. For Santos operations, depending on availability and applicable regulations, water used during hydraulic fracturing is either taken from: produced water from adjacent oil and gas production facilities, or local water bores which will draw the water from shallow or deep aquifers in full consultation with the land owner/occupier. With advances in fluid chemistry, fresh potable water is no longer necessary for hydraulic fracturing. The proppant - sand, ceramic pellets or other small incompressible particles - acts to keep the fracture open after injection of the fluid stops, and forms a conductive channel in the reservoir through which the oil or gas can travel back to the well. Typically, the chemical additives are used to improve the transportation of proppant, prevent the growth of bacteria, reduce mineral blockages and prevent well corrosion over time and may include acid, gelling agents, biocides and pH buffers. These chemical additives are used for many different household or industry functions and are not specific to the hydraulic fracturing process. Common uses include components of toothpaste, food additives, detergents, cosmetics and soap.
Chemicals are used in the hydraulic fracturing fluid for the following purposes:
Viscosity: gelling agents are added to the water to provide viscosity to enable the proppant material such as sand or ceramic beads to be transported down the well and into the created fractures. Friction reduction: to reduce the force required to pump the fluid, friction reducers are added, making the fluid more ‘slippery’ and easier to pump at the high pressures and rates required to create the fracture network. Biocide: biocides or disinfectants are added to ensure that no microbes or organisms present in the water will destroy the gelling agents and also to ensure they will not enter and contaminate the reservoir. Scale and corrosion: scale and corrosion inhibitors are added to prevent deposition of mineral scales and to prevent corrosion of the steel casing or tubing. Surface tension: surfactants or surface tension modifiers are added to assist the flowback of fluids from the target rock formation.
Chemical additives used in hydraulic fracturing fluids are required to be notified and assessed by National Industrial Chemicals Notification and Assessment Scheme (NICNAS), and listed on the Australian Inventory of Chemical Substances (AICS). The chemical additives that could be harmful in concentrated forms are greatly diluted by water when used in the fracturing process and are therefore present in relatively low concentrations. Even in low concentrations, Santos handles these chemical additives with care to avoid any potential impacts on human health or the environment. With operational controls and management, the overall or residual risk to the environment associated with the chemicals used in hydraulic fracturing is further minimised.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 6 15 October 2015 In Queensland, Santos conducts a comprehensive risk assessment on the chemicals used in hydraulic fracturing. The assessment is reviewed by multiple state and federal agencies including the Federal Department of the Environment and the Independent Expert Scientific Committee as part of the Environmental Impact Statement process. The Santos GLNG Upstream Hydraulic Fracturing Risk Assessment has been publically available on the Santos website since 2011.
Flowback Once the injection process is complete, the internal pressure of the rock formation causes fluid to return or “flowback” to the surface through the well. This fluid is also known as flowback or produced water and may contain the injected chemicals plus naturally occurring materials such as brines, metals, radionuclides and hydrocarbons. The produced water is typically stored on site in tanks or lined pits before recycling, treatment or disposal. Following completion of the hydraulic fracturing process, a considerable volume of the injected fluids are recovered upon flowback. Studies performed by the US EPA indicated that approximately 60% of the fluids are recovered in the first three weeks, and total recovery was estimated to be from 68–82% (US EPA). Most of the remaining fracturing fluid is likely to be extracted in the produced water over the life of the well; however, a proportion of injected fluid and chemicals retained in the target rock formation after production because some chemicals adsorb onto the surface of the rock. Some fractures also close shortly after being created and are cut off from the rest of the fracture network. It is possible that some chemicals will be retained in these isolated fractures.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 7 15 October 2015 Post-fracturing Activities After fracturing has been carried out, measurement, reporting and monitoring are conducted. Fracture growth measurements Fracture growth is measured after hydraulic fracturing, with the results then used to improve predictions for future fracturing. There are many methods for directly or indirectly measuring fracture growth. However, all have limitations in resolution, practical requirements and the range of measurable fracture properties. The type of measurement that may be used include: pressure monitoring to calibrate mechanical earth model and fracture model to predict fracture geometry (measures fracture length and height) detection of radioactive tracers, if they have been used, in the hydraulic fracturing fluid or proppant (measures height) temperature surveys to detect fracturing fluid which is typically a different temperature to the water in the well (measures height) production logs or down hole video to assess where most water is entering the well; and microseismic and tiltmeter mapping (measures length and height).
Sensitive seismic measuring equipment can detect the position of the microseismic activity by measuring the time taken for stress waves to travel between the activity and the receiver. Since the activity tends to occur at and behind the fracture tip, or growing edge, this gives an indication of the extent of fracture growth in three dimensions. Microseismic mapping involves measuring the very small tremors, termed microseismic activities that occur during fracturing. These activities result from the stress placed on the rock and adjacent rock from the injection of high pressure fluids and opening of hydraulic fractures. This should not be confused with ‘induced seismicity’, which is a term that refers to earthquake events of higher magnitude and is discussed further below. Reporting There are different reporting requirements by jurisdiction. A completion or post-fracturing report can include real-time data acquired during fracturing such as injected volumes and pressures. It can also include any post-fracturing down hole logging and results from microseismic or tiltmeter mapping. For example:
The South Australian Government regulates hydraulic fracturing through usual environmental approval processes, namely requirements for an approved Statement of Environment Objectives (SEO) based on an Environmental Impact Report (EIR). SEOs and EIRs are public documents available on the government’s website (DMITRE). In Queensland, coal seam gas companies are now required (under the April 2011 amendments to the Petroleum Regulation 2004 and Petroleum and Gas (Production and Safety) Act 2004) to notify the government and landholders prior to carrying out and after completing hydraulic fracturing. Companies must lodge a report with the Queensland Government, within two months of any hydraulic fracturing activity, detailing the composition of the fracturing fluid used at each well and its potential impact. Operators in New South Wales are required to submit a completion report, or a post fracturing report, to the regulator within 30 days of cessation of fracturing (NSW Trade & Investment). The NSW code of practice states that submission of fracture
Hydraulic Fracture Stimulation Technical Fact Sheet Page 8 15 October 2015 completion reports are a mandatory requirement and these may be published for public view on the relevant agency’s website (NSW Trade & Investment). In Western Australia, under the Petroleum and Geothermal Energy Resources Regulations and the Petroleum (Submerged Lands) (Environment) Regulations 2012, operators are required to provide the following information to the Department of Mines and Petroleum, which may be made available in the public domain: disclosure details including trade name, supplier name, purpose and ingredients; chemical abstracts service registry number; maximum ingredient concentration in product; maximum ingredient concentration in total fluid used; Material Safety Data Sheet; and ecotoxicity information. Monitoring for impacts Santos ensures well integrity and undertakes monitoring of the environment surrounding the well for any changes. Well integrity is tested through pressure tests and running cement bond logging equipment down the well to check that the cement is still intact. Refer to the drilling and well integrity fact sheet for additional information. Issues and Environmental Concerns The main environmental concerns associated with hydraulic fracturing can be broadly divided into: subsurface contamination and risks to groundwater resources, their quality and use surface contamination, including exposure risk and toxicity of chemical additives induced seismicity water use.
The significance of these ‘perceived’ risks is geographically and geologically specific. For example, the risk of hydraulic fracturing fluid migrating through several hundred metres of low-permeability layered rock is low. Similarly, the toxicity of the chemicals used is dependent on the initial concentration of the chemical within the hydraulic fracturing fluid, any mixing effects of the combined chemicals, any reactions with the surrounding rocks and groundwater, attenuation over time as the chemicals move through the rock formation and the nature of exposure risks to these chemical additives. Industry risk assessments indicate that the residual concentrations of a chemical of potential concern are unlikely to pose a risk in groundwater or at the surface. Appropriate regulation and good industry practice are key in minimising and managing risks to the environment. Subsurface contamination Subsurface contamination is minimised by limiting the use of toxic chemicals in hydraulic fracturing fluids, maximising the recovery of chemical additives via flowback, and preventing connection between the target rock formation and aquifers used for domestic or agricultural purposes. Light condensate, including naturally occurring hydrocarbon compounds such as benzene, toluene, ethylbenzene, and zylenes (BTEX), may be associated with oil and gas and therefore present in recovered fluids. Separators are used to separate water, condensate, and gas for separate handling and the produced fluids are directed into lined pits (e.g. lined with UV stabilised HDPE or equivalent) or tanks before recycling, treatment or disposal. Potential environmental risks are assessed regularly and managed through monitoring and containment. Water management ponds or containment facilities are constructed in accordance with regulatory standards and Santos policies and procedures.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 9 15 October 2015 Fracture growth is highly dependent on the conditions at the site, including the geology, in situ stress and injection pressure. Various methods can be used prior to and during hydraulic fracturing to design and control fracture growth. In addition, ensuring well integrity is important in protecting the environment. Surface contamination At the surface, flowback water is either stored in temporary storage tanks or ponds, or is transported by pipeline to a water treatment facility. There is potential for accidental releases, leaks and spills due to pond or pipeline failure. Another surface contamination source is the accidental release or spill of hydraulic fracturing fluid. Assessment and management of risks are undertaken by reviewing the existing site environment, assessing hazards to determine which chemicals are of most concern, assessing exposure pathways and then characterising and managing the risks appropriately. Induced seismicity Fracture stimulation can induce small microseismic activity that can only be detected by local monitoring and cannot be detected at the surface. The risk of large seismic events occurring is rare and minimised by appropriate site selection and understanding the local subsurface fault system and seismic history of a region. Water supply Hydraulic fracturing requires access to volumes of water that are generally not large compared to other uses, such as irrigation, and large industrial and town water supply. Water is commonly sourced from nearby groundwater systems. In regions where local, natural water sources are scarce or fully committed for other purposes, the use of water for hydraulic fracturing is managed in a variety of ways, including reuse or recycling of water from gas operations or the use of non-potable underground aquifers.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 10 15 October 2015 APPENDIX - REGULATORY
Regulatory Framework State and territory governments are mainly responsible for the legislative framework, licensing and decision making processes governing petroleum exploration and production activities. Responsibility for Australia's offshore areas, beyond three nautical miles from the territorial sea baseline (referred to as ‘coastal waters’), rests with the Commonwealth Government. Onshore and as far as three nautical miles seaward of the coastline, petroleum operations are the responsibility of the individual state and territory governments. The Commonwealth Government shares joint regulatory authority with the relevant state or territory in the adjacent areas of Commonwealth waters. Commonwealth Government The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) is charged with regulating health and safety, well integrity and environmental management for all offshore petroleum facilities and activities in Commonwealth waters and in coastal waters where state and territory functions have been conferred. The Environment Protection and Biodiversity Protection Act (EPBC Act) is the main piece of Commonwealth Government environmental legislation. It provides a legal framework to protect and manage impacts upon matters of national environmental significance which include water resources in relation to coal seam gas and large coal mining development. Under the EPBC Act, matters of national environmental significance include listed threatened species and communities, listed migratory species, wetlands of international importance, nuclear actions, Commonwealth marine areas, World Heritage properties and National Heritage places. The Commonwealth Government established the Independent Expert Scientific Committee on Coal Seam Gas and Large Coal Mining Development (IESC) as a statutory body under the EPBC Act. The IESC provides advice to Commonwealth and state government regulators on water-related impacts of coal seam gas and large coal mining development proposals. These arrangements are supported by a National Partnership Agreement on Coal Seam Gas and Large Coal Mining Development, a joint initiative of the Commonwealth Government and participating states (New South Wales, Victoria, Queensland and South Australia) (IESC). In 2013, the Council of Australian Governments’ (COAG) Standing Council on Energy and Resources published a national harmonised regulatory framework for coal seam gas to address concerns based on four key areas: water management and monitoring; well integrity and aquifer protection; hydraulic fracturing; and, chemical use (SCER). State and Territory Governments Generally the exploration and production of petroleum in Australia is governed by onshore petroleum acts. Each of the acts defines petroleum as one of the following: any naturally occurring hydrocarbon, whether in a gaseous, liquid or solid state. any naturally occurring mixture of hydrocarbons, whether in a gaseous, liquid or solid state. any naturally occurring mixture of one or more hydrocarbons, whether in a gaseous, liquid or solid state, and one or more of the following, hydrogen sulphide, nitrogen, helium and carbon dioxide. The exception is Tasmania which regulates gas through the Mineral Resources Development Act 1995. This act defines petroleum and coal seam gas separately:
Hydraulic Fracture Stimulation Technical Fact Sheet Page 11 15 October 2015 petroleum means naturally occurring hydrocarbon or mixture of hydrocarbons, whether in a gaseous, liquid or solid state; or mixture of one or more such hydrocarbons and gas – but does not include coal seam gas. coal seam gas also known as coal bed methane means the gas and includes any naturally occurring hydrocarbon, or mixture of hydrocarbons, that is within a deposit of coal or oil shale.
Queensland The main regulatory framework in Queensland is the Petroleum Act 1923 and Petroleum and Gas (Production and Safety) Act 2004 which is supported by a number of legislation, and codes of practice and policy. Petroleum activities in Queensland are licensed under the Environmental Protection Act 1994, which imposes strict operating conditions to reduce or avoid potential environmental impacts that must be complied with before any activity can begin. The Environmental Protection Act 1994 was amended in October 2010 to regulate the use of BTEX chemicals in hydraulic fracturing processes. As BTEX chemicals occur naturally in underground water sources, the government restricted the use of BTEX in hydraulic fracturing chemical additives to nationally set environmental and health standards. The amendments improved notice requirements of incidents that may cause serious material environmental harm to affected landholders. Although the exact Environmental Authority conditions applicable to hydraulic fracturing are project specific, some common conditions imposed on coal seam gas operations include: prohibiting the use of hydraulic fracturing fluids containing BTEX and Poly aromatic hydrocarbons (PAH) as additives. conducting a risk assessment to ensure that the hydraulic fracturing activity is managed to prevent environmental harm. providing a detailed hydraulic fracturing impact monitoring program that considers the findings of the risk assessment to the government for review, prior to carrying out hydraulic fracturing activities, to ensure any adverse impacts to water quality are detected. providing publically available details of the composition of the fracturing fluid to be used, and undertaking a hydraulic fracturing chemical risk assessment which must be submitted for review prior to carrying out hydraulic fracturing. undertaking baseline bore assessment to collect sufficient water quality data to accurately represent the water in the well prior to hydraulic fracturing. conducting long-term monitoring of wells that have been hydraulically fractured. monitoring groundwater and all active landholder bores within a two kilometre horizontal radius prior to and following hydraulic fracturing.
New South Wales
The extraction of petroleum in NSW is regulated under the Petroleum (Onshore) Act 1991, which is supported by legislation and codes of practice and policy. On 6 March 2012, NSW implemented a policy banning the use of BTEX compounds in coal seam gas drilling and hydraulic fracturing under the Petroleum (Onshore) Act 1991 (Department of Trade & Investment). This policy is part of the NSW Government’s Strategic Regional Land Use Policy and prohibits the adding of BTEX chemicals in coal seam gas drilling and hydraulic fracturing fluids. For the same reasons as in Queensland, it sets threshold levels for BTEX chemicals to ensure they are not at a level that will exceed the nationally set environmental and human health standards.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 12 15 October 2015 South Australia Petroleum exploration, development and production in South Australia are regulated under the Petroleum and Geothermal Energy Act 2000 and the associated Petroleum and Geothermal Energy Regulations 2000. The South Australian regulations are objective based rather than prescriptive and seek to ensure effective management of activities through compliance with performance standards developed cooperatively by industry, the regulator and the community. The South Australian Government regulates hydraulic fracturing through usual environmental approval processes, namely requirements for an approved Statement of Environment Objectives (SEO) based on an Environmental Impact Report (EIR). SEOs and EIRs are public documents available on the government’s website (DMITRE). While there are no regulatory or legislative requirements that prohibit the use of BTEX compounds, as with the other Australian jurisdictions, Santos does not introduce these constituents in hydraulic fracturing operations. Northern Territory The exploration and extraction of petroleum is regulated in the Northern Territory under the Petroleum Act 2013. This is supported by other legislation such as the Water Act 1992 and Environmental Assessment Act 2013. Water use is not subject to regulation under the Water Act 1992 when used for extracting petroleum resources. Hydraulic fracturing is used on deep shale wells, under regulation by the Northern Territory Department of Mines and Energy (DME). The Northern Territory Government requires an application to conduct hydraulic fracturing (Northern Territory Department of Mines & Energy) is provided to the DME and the relevant Land Council(s) for approval. The application must address: water management; type and quantities of chemicals used in the hydraulic fracturing; well integrity; communication and reporting. Chemical disclosure statements and summaries of environmental management plans are available on the government’s website. DME requires that the detailed well completion and stimulation work program is sent to Northern Territory Environment Protection Authority for comment prior to approval. Western Australia Petroleum exploration and development is regulated under the Petroleum and Geothermal Energy Resources Act 1967 and the associated Schedule of Onshore Exploration and Production Requirements 1991. These are supported by other legislation and regulations such as the Environmental Protection Act 1986. The following petroleum environment regulations came into force in August 2012: Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 Petroleum (Submerged Lands) (Environment) Regulations 2012 Petroleum Pipelines (Environment) Regulations 2012.
These regulations are administered by the Western Australia Department of Mines and Petroleum (DMP) and require all chemicals used in hydraulic fracturing to be disclosed in a Drilling Application and Environment Management Plan (Department of Mines and Petroleum). Full public disclosure is required for products, additives, chemicals and other substances that may be used in drilling, hydraulic fracturing or other ‘down-well’ petroleum related activities. The disclosure is made available on the DMP website. In addition to Western Australia’s chemical disclosure requirements, the Australian Petroleum Production and Exploration Association’s (APPEA) Western Australian Onshore Gas Code of Practice for Hydraulic Fracturing
Hydraulic Fracture Stimulation Technical Fact Sheet Page 13 15 October 2015 http://www.norwestenergy.com.au/assets/files/Industry%20News/2013%2007%2004%20AP PEA_Code_of_Practice.pdf suggests how operators should responsibly develop onshore gas reservoirs in Western Australia, including the use of chemicals in hydraulic fracturing. Specifically, Guideline 4 (on the use of chemicals) states that details of all fluids to be used during hydraulic fracturing operations, including information on actual usage and fluid recovery, will be provided to the WA Department of Mines and Petroleum and that operators will support the public release of this information. Victoria Petroleum exploration and development and mining in Victoria are regulated under the Mineral Resources (Sustainable Development) Act 1990. This is supported by other legislation such as the Environment Protection Act 1970 and Water Act 1989. No hydraulic fracturing activities have been approved in Victoria. On 24 August 2012, the Victorian Government announced regulatory reforms to provide more certainty for industry and regional communities in the lead up to the development of a national harmonised regulatory framework for the coal seam gas industry through the National Partnership Agreement. The reforms include a moratorium on hydraulic fracturing approvals related to onshore gas exploration and issuing of new exploration licenses for coal seam gas until the national harmonised regulatory framework has been considered. This involves banning the use of BTEX chemicals in hydraulic fracturing together with strengthening policy and legislation to ensure better consideration of multiple land use issues during coal seam gas exploration applications.
Tasmania Petroleum exploration and development activities in Tasmania are regulated under the Mineral Resources Development Act 1995 (MRDA) (including the Mineral exploration code of practice, and Schedule for onshore exploration for petroleum, shale gas, coal seam gas, or geothermal substances). This Act and the associated Code and Schedule provide the regulatory framework for all petroleum and gas exploration and development activities within the State. This is supported by the Environmental Management and Pollution Control Act 1994, and Land Use Planning and Approvals Act 1993. To date there has been no hydraulic fracturing undertaken in Tasmania. In 2014, the Government imposed a 12-month moratorium on hydraulic fracturing in Tasmania to enable a review into hydraulic fracturing in the State. On 26 February 2015, the Government released a policy statement detailing its intent to maintain the moratorium on the use of fracking for the purposes of hydrocarbon resource extraction, e.g. shale gas and petroleum for five years, until March 2020.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 14 15 October 2015 References Department for Manufacturing, Innovation, Trade, Resources and Energy (DMITRE). 2012. Primary Industries and Regions South Australia (2012) Available at: http://www.pir.sa.gov.au/petroleum/prospectivity/Basin_and_province_information/unconvent ional_gas/frequently_asked_questions#Has%20hydraulic%20fracturing.
Department of Mines and Petroleum. 2012. What controls are placed on the use of hydraulic stimulation chemicals in Western Australia? Government of Western Australia. Available at: http://www.dmp. wa.gov.au/12872 .aspx#12875.
Department of Trade and Investment, Regional Infrastructure and Services. 2012. Ban on use of BTEX compounds in CSG activities policy, New South Wales Government. Available at: http://www.trade.nsw.gov.au/policy/TI-O-120.
Independent Expert Scientific Committee on Coal Seam Gas and Large Coal Mining Development (IESC). 2013. Available at: http://www.environment.gov.au/coal-seam-gas- mining/.
National Industrial Chemicals Notification and Assessment Scheme (NICNAS). 2013. Information Sheet - National Assessment of Chemicals Associated with Coal Seam Gas Extraction in Australia Available at: http://www.nicnas.gov.au/communications/issues/fracking-hydraulic-fracturing-coal-seam- gas-extraction.
Northern Territory Department of Mines and Energy (2012) Regulation of hydraulic fracturing. Available at: http://www.nt.gov.au/d/Minerals_Energy/index.cfm?header=Regulation%20of%20Hydraulic %20Fracturing.
NSW Trade and Investment. 2012. NSW Code of Practice for Coal Seam Gas – Fracture Stimulation Activities. Available at: http://www.nsw.gov.au/strategicregionallanduse.
Standing Council on Energy and Resources (SCER). 2013. National Harmonised RegulatoryFramework for Natural Gas from Coal Seams Available at: http://www.scer.gov.au/workstreams/land-access/coal-seam-gas/. US EPA. “Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs”, EPA 816-R-04-003, June 2004.
Hydraulic Fracture Stimulation Technical Fact Sheet Page 15 15 October 2015