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 (

There are interleaved layers of clay and limestone that trap the gas. The gas is formed and adsorbed from organic matter. Fine particles of clay mix with the Shale and the whole rock formation thus contains trapped hydrocarbons in what is called Shale gas. The TOC (Total organic Content) is a measure of the Shale gas content that could be recovered from the layers of Shale gas deposits. These formations take decades, often centuries to form during which time the porous structure gets hardened. The layers have low permeability that has to be loosened by gushing water jets; this makes a muddy mixture from where gas can easily escape into the drills. (BGS 2013, p.8).

Oil and gas are actually hydrocarbons made from centuries of compression of organic substances. The main structure is grainy clay. These get interleaved with limestone, sandstone etc. And the gas gets percolated into these traps. Physically, these traps are at an elevation of the boundaries of the two intervening layers of the shale gas basins (BGS 2013, p.7).

Estimation and Recovery of Shale Gas

Shale gas occurs in free state adsorbed and trapped within porous kerogen, between the microscopic space of shale (microfractures) or even in larger spaces between layers called macrofractures (Bust et al. 2013, p.95). The reserve estimate for Shale gas is the amount of gas possibly available in the reservoir under consideration. The extractable amount of shale gas is called the recovery estimate. The reserve is the approximate estimation and recovery estimate is the useful extractable quantity. That leads to the recovery fraction that is the proportion of the extractable, useful gas to the gross resource estimated in the reservoir (stated as a percentage value, determined by time, money and technical resources and constraints) (BGS 2013, p.5).

The degree of production uncertainty and the stage of exploration determine the reserve and resource figures for any reservoir. GIP OGIP GIIP respectively Gas in-place, original gas in-place and gas initially in-place are the alternative names for the estimations acquired even before the operation for extractions go underway. These are the rough estimates enabling investors and shareholders to help them with their decisions. TRR (technically recoverable resources) is a newly formed, revised estimate methodology designed and adopted by the USGS (U.S. Geological Survey) specifically for estimating coal bed methane and shale gas. These figures provide a much clearer method of recovery and reserve estimates of extractable gas from shale gas basins (BGS 2013, p.6).

With the integration of the TRR, the estimate figures offered by the U.S. Energy Information Administration (EIA) have improved as they take into account the actual exploration figures through the years. This is still an exercise in its infancy and different methods are being used by other agencies. With growing commercial awareness and technological advances in the field the estimates and extraction capabilities are poised for improvement (BGS 2013, p.6).

Hitherto used estimate measurements are based on the methodology deployed for coalbed methane. The shale gas basins vary significantly from such reservoirs causing improper estimates when same methods are employed to shale gas reservoirs. Secondly, shale gas is heterogeneous unlike coal-bed methane basins. Moreover, each shale gas reservoir may require specific methodology for the estimation and extraction to near accurate levels. Unlike in coal-bed methane basins there is a need to approximate the adsorption capacity of the kerogen that traps gas as also the inter-granular grain space that holds gas. (Bust et al. 2013, p.98). As such there are various parameters like local shale-play data, well-specific core and log data, or regional analogue information around which estimates will have to designed and formed. After such calculation and estimation using the constraints of 'fractured volume', alternatively the 'stimulated volume', the traditionally used equations for the GIP (gas-in-place) along with GRV can be used (Economides & Wang 2010).

Porosity

An estimation of porosity of the terrain of the basin is proving to be a very important factor in estimation and extraction technologies as the trapped gas within layers that are more porous have proven to yield shale gas ranging up to10x those of tighter and hence lesser porous layers. (Economides & Wang 2010).

Porosity is a function of the organic and inorganic composition of the reservoir and the thermal pressures it has sustained (diagenesis) (Jarvie et al. 2007; Katsube et al. 2000; Kuila and Prasad 2010). The original intergrain pores decrease in shale as diagenesis increases; the same process also results in formation of the intra-grain organic nanopores. Jarvie et al. (2007) proved that, the organic nano-pores are formed as shale matures into the level of oil window because of generation and expulsion of the hydrocarbon, resulting in further expansion of pore sizes which in turn yields larger volumes and the process continues improving extraction and recovery capabilities (Zhou et al. 2014).

The fundamental requirements of successful shale gas plays have >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).