Coal seam gas (CSG) or coal bed methane production has grown exponentially in Australia over the last two decades with currently nearly 7000 productive wells and another 18,750 wells planned over the next five to ten years. To address concerns over environmental contamination by hydraulic fracture fluids (HFF) attributed to (i) incidents involving poor surface handling of HFF and other fluids with potential migration pathways in soil and shallow groundwater, and (ii) leakage pathways arising from HFF injection into coal seams and unintended migration of these chemicals, the National assessment of chemicals associated with coal seam gas extraction in Australia (the Assessment) was undertaken. The Assessment included a review of international studies on unconventional gas migration pathways to provide prior knowledge and comparison for use in the Australian study. The international literature highlighted that accidents with HFF were mainly due to surface operations and included leaking equipment and spills. Contamination risks of groundwater from hydraulic fracturing itself were found to be very small based on analysis of micro-seismic and groundwater hydrochemistry data; geologic modelling of vertical fracture growth further reveals a low risk of leakage pathways developing in aquifers confined by deep shale formations. This is due to limitations on the fracture growth vertically across aquitards often hundreds of meters thick, retention within the shale of limited amounts of injected fluid, and preferential fracture growth at shallow depths in the horizontal direction. These arguments are broadly applicable to Australian CSG basins. However, important differences exist, such as the reduced thickness in Australia of the aquitards that separate the targeted gas resource from groundwater. Also, hydraulic fracturing in Australian coal seams is practised only when permeabilities are too low for gas extraction to be economical without stimulation. From the nearly 10,000 CSG wells drilled in the Bowen and Surat Basins in Queensland, only 6% have received hydraulic fracturing to date. The reduced risk of leakage pathways developing during CSG production in Australian basins is further corroborated by geologic criteria based on modelling and observations. Criteria include encountering certain favourable conditions during drilling/injection, i.e. (i) interfaces, such as natural fractures, faults, and bedding planes, which promote offsetting and branching, or rock layers with higher fracture toughness causing the cessation or reduction in fracture growth, (ii) narrow fractures due to a relatively higher elastic modulus, leading to higher viscous flow loss, (iii) high permeability layers, and (iv) overlying layer(s) with a higher confining stress. In addition to the leakage pathways considered in North American shale gas basins involving (i) pre-existing fractures and faults, or (ii) flow up the production well due to poor casing or cementing, plausible chemical migration pathways in Australian CSG basins are due to (iii) connectivity via a fracture in or extended out of the coal seam formation between CSG wells and water bores co-located in the same formation, and (iv) poor integrity water bores enhancing inter-aquifer connectivity. These plausible pathways are described and used in subsequent work as the basis of risk assessments for contamination at the local- and regional scale.
