There are different definitions of the term shale and not all of them are found in unconventional reservoirs
I am increasingly being asked by clients and other organizations as to whether a reservoir is conventional or unconventional shale, and this raises an important question when it comes to planning and regulations within certain regions. The answer to this question is not as clear cut as it may seem.
While any reservoir that is deemed to be “shale” may seem to be firmly in the unconventional bucket, there are different definitions of the term shale – and it is important to know that not all shales are found in unconventional reservoirs; the vast majority are overburden and seals to our conventional reservoirs. A rock can be determined to be shale by a number of criteria, including grain size (below 2 microns), clay content (above 50 percent) or a very fine-grained rock deposited in a low-energy environment. A source rock reservoir (SRR), for instance, is shale (for want of a better word) with some special properties: it is organically rich, with total organic carbon greater than 2 percent. Also, the organic matter contained needs to be buried and thermally mature to have generated hydrocarbons.
For a world-class SRR, we like to see overpressure, as this indicates that hydrocarbons have been generated, but not significantly expelled from the organic source rock, migrated and filled traps as in a conventional hydrocarbon system. Mechanical properties of the SRR are key; it is well known that these systems need to be hydraulically stimulated for any type of flow to occur; therefore, mineralogy and brittleness need to be well understood.
The presence of natural fractures is another critical component for a SRR to be a commercial success. Due to the ultra-low permeability (measured in nano-darcy units) of a shale, the matrix flow of hydrocarbons is extremely slow and only possible by slip diffusion. Therefore, production comes from maximizing the stimulation of the natural fracture system, along with the induced hydraulic fractures that we place within the reservoir. These are just a few of the considerations that we need to study in order for a “shale” play to work.
When it comes to tight liquid and gas plays, the line between conventional and unconventional becomes much more blurred, whether they are clastics or carbonates, with different operators classifying them as either one or the other. Many of these tight zones are bypass zones within a conventional reservoir, which have been passed over as being difficult to produce. The permeability of these zones generally ranges from milli- to micro-darcy, where there may be limited conventional production, but sub-commercial without some type of stimulation. With the advent of unconventional shale plays, extended lateral drilling and multistage hydraulic fracturing are now common, leading to reductions within the technical difficulty and cost of such operations, many of these zones are now looking attractive as commercial prospects.
So how is a reservoir classified as unconventional? Is it purely a shale reservoir? A key question to consider is this: Does it have permeability cut-off? In other words, is it a sub-micro-darcy type of reservoir that requires some type of stimulation to achieve commercial flow?
This may appear to be a semantic question, but it certainly has large implications for planning and permitting. Consider, for example, a highly laminated marine fan consisting of very fine-grained sand, silt, and claystone. When would this be considered a shale reservoir, if the formation has more than 50 percent claystone or a micro-darcy conventional tight play if the flow is coming predominantly from the sands and silts?
Currently, it is individual regulators and geologists that are making these determinations, and these decisions ultimately affect many aspects of permitting and regulations. For this reason as an industry we should strive to agree to a set of guidelines on the criteria of what constitutes a conventional vs. an unconventional reservoir.