Shale Gas Reservoirs, Resource Estimation and Recoverable

Shale Gas Reservoirs, Resource Estimation and Recoverable Volumes What is Shale Gas? Shale gas is best described as rich in organic content and fine-grained (Bustin, 2006). Shale, is however a very broad term, and gas found in any reserve is trapped in the layers of sediment alternating between clastic and sandstone or carbonates.

Shale usually denotes fissile mudstone containing mm scale laminations of >50% silts and clays below 1/16mm (1% TOC, high Si%, low clay %, >40m thick, >1000km2, >1km deep, gas window thermal maturity levels, low expulsion potential and have a natural fracture network (Jarvie et al. 2007; Bouhlel and Bryant 2012). Shales, however are very heterogeneous and hence every play needs independent methodologies and estimations. That makes replication of one successful attempt to another play difficult (Khattab 2012).

The analysis of systemic variations in the mudstone architecture is measured on the parasequence scale using Sequence stratigraphy (Passey et al. 2010). Each parasequence corresponds to a 1-3m thick shale deposit strata depicting the organic and inorganic matter composition at the m-cm scale (Passey et al. 2010). The factors that play decisive role in formation of shale gas comprise organic production, their breakdown by bacteria and oxidization. This is accompanied by sediment dilution of the organic matter (Passey et al. 2010).

The factor that ultimately controls all these processes and factors is the amount of dissolved oxygen on the n-benthic activity, bioturbation, colour, pyrite and TOC% in the mudstone. The interface is called the 'reduction-oxidation front' (Potter et al. 2005). Extraction Methods The two basic methodologies in prevalence for estimation are: 1. GIP reserve estimates based on a geological strata studies, volume anlysis and gas contents ('bottom-up approach'), and 2. Well Estimates based on available technology, performance, density ('top-down approach').

(BGS 2013, p.10) Shale gas is extracted from organically-rich, marine transgressive to highstand mud-rocks layered composition of carbonate-clastic deposits. The GIP and transportability of gas in the deposits is determined by factors like adsorptive, Porosity, and permeability. Transportation properties help decide the course of exploration of the reserve. The measurements of porosity, permeability, inter-granular permeability, and specific surface area offer information about the level of extraction from a particular basin, reserve or play. One important method for allowing liquid petroleum to escape into the drills for extraction is the fracturing process.

This becomes a necessity as shale gas plays are found around thermal gas and liquid petroleum (Horsfield & Schulz 2012). Fracturing is done to improve the porosity of gas and is carried out in stages. The process is called hydraulic fracturing where about 99.5% water, and chemicals (0.5%>) are pumped into the plays at very high pressure fractures the shale gas layers increasing its porosity (U.S. Shale Gas Primer, 2009). The clay swells under certain chemicals and hence each reservoir may require a different chemical.

Clay is capable of standing higher pressures than silica which may crack under pressures where clay may only bend (Canadian National Energy Board 2009). Commercial drilling and fracturing process involves drilling up to sixteen horizontal wells from the same vertical drill as it reaches the shale gas deposit under the surface. The vertical shaft then turns at angles of 900. The drilling extends horizontally for about a couple of kilometers.

Thus, a larger cross sectional area can be fractured simultaneously which is seen to yield better results, commercially and in terms of technical efficiency (Bouhlel and Bryant 2012). This method is not applicable in case a shallow shale gas reservoir is encountered (Khattab 2012). The bottom-up methodology is applied to virgin locations for estimating oil reserves and resources in untapped topographical regions. this method estimates the OGIP. This is followed by applying the TRR estimates through percentage recovery factor estimate.

The various factors that contribute to these factors are the surface area or volume of shale rock, the organic composition (measured as a proportion of the total weight), the composition of the minerals (clay/quartz etc.) contained within the shale and the pressure at which gas is available. These measurements are done in staggered steps. Some subjective evaluation like risk factor and total convertibility is also required to assess the overall operability.

The recovery factor is a function of the mineralogy of the shale, the geological composition and other terrestrial factors. The usual recovery factors vary greatly from conventionally obtained 80% to a mid range value of 20-30%, though a variation is always employable depending on conditions and requirement (McGlade et al. 2013). References Advanced Resources International (ARI) (2011). World shale gas resources: an initial assessment of 14 regions outside the United States. Washington, DC: Advanced Resources International Inc. Aplin, A.C. Fleet, A.J. & Macquaker, J.H.S. (1999).

Muds and Mudstones: physical and fluid flow properties. Geol. Soc. Lon. Spec. Pub. Vol. 158, p.1-8. Bouhlel, A.M. & Bryant, I. (2012). An Effective Approach to Unconventional Resource Exploration in the Middle East. SPE152455. British Geographical Survey (BGS) (2013). The Carboniferous Bowland Shale gas study: geology and resource estimation. Department of Energy and Climate Change Bust, V.K. Majid, A.A. Oletu, J.U. & Worthington, P.F. (2013).The petrophysics of shale gas reservoirs: Technical challenges and pragmatic solutions. Petroleum Geoscience, v.19; p91-103. Bustin, M.R. (2006).

Geology report: where are the high-potential regions expected to be in Canada and the U.S. Capturing opportunities in Canadian shale gas; The Canadian Institute's 2nd Annual Shale Gas Conference, Calgary, January 31 -- February 1, 2006. Canadian National Energy Board.