Shale has such low matrix permeability that it releases gas very slowly and this is why shale is the last major source of natural gas to be developed.  However the upside is that shales can store an enormous amount of natural gas.  Shale is a fissile, very fine grained sedimentary rock comprising clay minerals, very fine grained sand (quartz, feldspar or carbonate) and may contain organic material (kerogen = hydrocarbon source).  Shale has been regarded as an impermeable seal (cap rock) for more porous and permeable sandstone and carbonate hydrocarbon reservoirs.  However, in a shale gas play, it forms both the source rock and a low permeability reservoir.  Shale gas plays are not dependent on structural closure, hence can extend over large areas – the challenge is to find sweet spots that will produce commercially.  The necessary elements for a shale gas play are (Curtis, 2009):

  • laterally extensive, realtively undeformed shale
  • thickness >30m
  • total organic carbon content >3%
  • thermal maturity in gas window (VR = 1.1 to 1.4)
  • good gas content >100scf/ton
  • moderate clay content <40%
  • brittle composition

In gas shales, the gas is generated in place and the shale is both the source rock and the reservoir. The gas can be stored as free gas within pore spaces in both the inorganic sediment component and the organic carbon component of the rock, as free gas in fractures, and as gas adsorbed to the surface of organic components (kerogen).  In-situ generation and storage of hydrocarbons results in volume and pressure changes, and some overpressure is therefore characteristic of gas shales. Shale gas is produced from continuous gas accumulations that are regionally extensive, lack an obvious seal and trap, and have no defined gas-water contact.

As shale matrix permeabilities are very low, operators generally seek to maximise the shale surface area exposed to production. This is achieved by “gas farming” whereby multiple horizontal wells are drilled perpendicular to the direction of maximum horizontal stress and stimulated with multiple hydraulic fracture stages to access the largest volume of reservoir and to intersect the maximum number of (typically) sub-vertical fractures. Microseismic monitoring can be used to identify fracture points in the reservoir during fraccing, to optimally orient follow up drilling, again as per geothermal reservoir stimulation. Natural fractures are beneficial, but usually don’t provide permeability pathways sufficient to support commercial production.  Larger scale faults are generally identified using 3D seismic and avoided as these complicate horizontal drilling (if the target shale bed is offset), inhibit hydraulic fracturing and can be water conduits.

The gas in natural (or induced) fractures, or gas which has migrated into thin sandstone interbeds is produced first. After the initial flush, gas production declines exponentially. Production rates typically flatten out after 3-4 years, as the adsorbed gas is slowly produced and can continue at relatively low rates for decades. Ultimate recoveries are much lower than for conventional gas fields, but completion and production technology advances are increasing recovery factors. Many US shale gas splays are ‘dry’ and water is not produced with the gas. Water is a problem as it will dissolve adsorbed gas which may be lost to the shale reservoir.

In the US, exploration and development of shale gas plays has accelerated over the past decade, and shale gas now provides in excess of 2 TCF gas per annum to the US domestic gas market. It is estimated that shale gas production will overtake coal seam gas production by 2025 (US Energy Information Administration) aided by improvements in exploration, completion and production technologies; gas price increases and emerging plays. No commercial shale-gas projects currently exist outside of the US, exploration is most advanced in Canada and Europe.

In Australia, explorers are in the early stages of identifying shale gas play fairways within prospective basins, and much of the basic data required to assess prospectivity has not yet been acquired.

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