Page 23 - Fundamentals of Gas Shale Reservoirs

SHALE GAS OVERVIEW 3
The thickness of economic gas shales is one of many outlined in the following text for the purposes of providing a
considerations. However, as an example, in North America, clearer picture of what a shale gas development comprises,
the effective thicknesses of shale gas pay zones range from and how this differs to a conventional gas play.
6 m (Fayetteville) to 304 m (Marcellus) (Caineng et al., Shale gas is currently only viable onshore since it would
2010). Caineng et al. (2010) note a guidance thickness for be cost prohibitive to drill the large quantity of wells required
economic plays of 30–50 m, where development is contin­ in an offshore environment due the higher cost per offshore
uous and the TOC (wt%) is greater than 2%. well. For instance, the day rate for offshore drilling can be an
TOC is only an indication of shale gas potential. The order of magnitude higher than for onshore drilling.
actual accumulation of gas from the organic compounds Shale gas wells are generally drilled horizontally so as
within the shale requires the organic matter to first generate to maximize exposure to the “reservoir.” However,
the gas. The degree to which this has happened in a shale gas vertical wells may also be drilled where the shale interval is
play is a function of the thermal maturity of the shale very thick.
(Lu et al., 2012). Significant shale gas is typically only Extensive hydraulic fracturing (fracking) is undertaken
generated beyond vitrinite reflectance (Ro%) values of within the shale gas reservoir to further increase the perme­
approximately 0.7% (Type III kerogen) to 1.1% (Types I and ability and hence gas yield. Fracturing is generally under­
II kerogen), which corresponds to depths of between 3.5 and taken in multiple stages, with the fracturing treatment of
4.2 km (Gluyas and Swarbrick, 2009). However, the most each individual section being undertaken separately, so as to
favorable situation is when vitrinite reflectance values range maximize the control and effectiveness of the process. It is
from 1.1 to 1.4 (Staff, 2010). also not usually possible to maintain a downhole pressure
Mineralogy plays a central role when evaluating gas sufficient to stimulate the entire length of a well’s reservoir
shale, due to its impact on the performance of fracture intersection in a single stimulation/treatment event (US DOE,
treatment (also known as hydraulic fracturing and “frack­ 2009), and it would also probably result in the concentration
ing”). In terms of mineralogy, brittle minerals (i.e., siliceous of fractures in the most susceptible zones. Each treatment
and calcareous minerals) are favorable for the development stage involves a series of substages which involve using
of extensive fractures throughout the formation in response different volumes and compositions of fluids, depending
to fracture treatment. Caineng et al. (2010) note that a brittle on the design (US DOE, 2009). For example, the sequence
mineral content greater than 40% is considered necessary of substages may be as follows:
to enable sufficient fracture propagation. Alternatively,
Lu et al. (2012) notes that within the main shale‐gas‐ 1. Test phase—validating the integrity of the well casings
producing areas of the United States, the brittle mineral and cement,
content is generally greater than 50% and the clay content is 2. Acid treatment—pumping acid mix into the borehole
less than 50%. In more simplistic terms, high clay content to clean walls of “damage,”
results in a more ductile response to hydraulic fracturing, 3. Slickwater pad—pumping water‐based fracturing
with the shale deforming instead of shattering. Mineralogy fluid mixed with a friction‐reducing agent in the
and brittle mineral content can be linked to the depositional formation, which is essentially designed to improve
environment. For instance, marine‐deposited shales tend to the effectiveness of the subsequent substage,
have a lower clay content and, hence, a higher brittle mineral
content (EIA, 2011a). It should be noted that the fracture 4. Proppant stage—numerous sequential substages of
susceptibility of shale is also influenced by the stress regime injecting large volumes of fracture fluid mixed with
and the degree of overpressure in the formation, amongst fine‐grained mesh sand (proppant) into the formation,
other factors. with each subsequent substage gradually reducing the
Petrophysical considerations are beyond the scope of this water‐to‐sand ratio, and increasing the sand particle
review. However, it is worth noting that porosity is an impor­ size. The fracture fluid is typically 99.5% water and
tant petrophysical consideration, as it will influence the sand, with the remaining components being additives
amount of free gas that can be accumulated within the shales. to improve performance.
Staff (2010) note that it is preferable for porosity to be greater
than 5%. However, for the main producing gas shales in the A large number of wells are required to extract economic
United States porosity range from 2 to 10% (Staff, 2010). quantities of gas from shale. The approximate quantity of
wells required to produce 1 Tcf (trillion cubic feet) of gas
within various producing shale gas plays in the United States
1.2.2 Characteristics of a Producing Shale Gas Play
varies widely (Kennedy, 2010). The suggested typical
The general geological features of a gas shale determine quantity of wells per Tcf gas is 200–250. This equates to an
the general framework of a commercial‐scale shale gas estimated ultimate recovery per well (EUR/well) of 5 Bcf/
development. Some of these development features are well (billion cubic feet per well). However, other sources