Environmental Engineering Reference
In-Depth Information
which can introduce significant error in porosity determination if not taken
into account. Traditional petrophysical principles are used for water-satur-
ation calculation to determine the hydrocarbon content of the pore space.
50
For gas-shales, the volume of sorbed gas must be taken into account, cal-
culated from the Langmuir volume and pressure at reservoir temperature
and pressure conditions and added to the log-derived ''free'' gas.
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The
Langmuir volume and pressure are derived from the Langmuir isotherm
which is derived experimentally for shale reservoir sorption relationships
between TOC, maturity and pressure. In general, the Langmuir volume is a
function of organic richness and the thermal maturity of the shale, while the
Langmuir pressure relates gas adsorption on the organic matter to pressure.
The calculated resource values are typically presented in US ''oilfield''
units of million barrels of oil (mmbo) per section (square mile) or, in the gas
case, billion cubic feet (bcf) gas per section. For a shale gas reservoir, re-
sources of greater than 50-60 bcf section
1
currently represent a lower
economic cut-off for shale gas in the USA, viable economic reservoirs such as
the Marcellus Shale having values of 100-180 bcf section
1
.
In conventional reservoirs, hydrocarbon reserves are derived from resource
determinations by the application of a recovery factor derived from modelling
of reservoir-flow test data. Clearly, in shale reservoirs with no naturally per-
meable reservoir this is not possible as the permeability is created post-
logging by the stimulation process, which is an unknown until the well is put
on production. Potential reserves, known as Expected Ultimate Recovery
(EUR), are calculated from the initial production (IP) data and the production
decline over a period of time, giving a prediction of the amount of hydro-
carbons producible in a given well. This is dependent on the production
period and the accuracy increases with time: a problematic scenario, which is
solved by the use of standardised decline curves from different shale reser-
voirs which are related to IP rates and initial production decline rates to give
an EUR estimate (see Figure 4). Clearly, choice of analogue decline curve is
critical and is potentially the main weakness in resource determinations. Of
note is the potential production period of up to 30-40 years predicted by these
decline curves, dependent on the mechanical life and economics of the well.
Recovery factor is a key parameter to convert resource estimations into tech-
nically and economically reserves; this is commonly derived from a combin-
ation of shale reservoir parameters, such as mineralogy, and production
features such as lateral well length and well spacing. Therefore, not sur-
prisingly, quoted recovery factors show a wide range of 15 to 35% for shale
gas,
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with typical values of 20 to 30%. For example, estimates of recovery
factors for US gas and oil shales average 20% for gas with a range of 15-25%
and average 4-5% for shale oil with a range of 3-6%.
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4 Exploration and Exploitation of Shale Reservoirs
Successful exploration for shale resources, whether for shale oil or shale gas,
is dependent on the location of good quality organic-rich shale of large re-
gional extent and thickness, and suitable thermal maturity. Present-day
