21
Unlike conventional reservoirs, these rocks don’t need any kind of special structural
or stratigraphic traps to contain oil and gas – the hydrocarbons are held within the
tiny pores and adsorbed onto organic particles. In fact, the USGS calls these “continuous reservoirs” because they will produce hydrocarbons from just about anywhere in the formation if the proper stimulation techniques are applied (Charpentier
and Cook 2011). It was recognized during the energy crisis that if a way could be
found to directly extract oil and gas economically from the huge volumes of shale
and other tight rocks in the U.S., they would represent a very large hydrocarbon
resource indeed (Schrider and Wise 1980). The key to shale gas production is that
the source rock is the reservoir rock.
The difficulty of extracting hydrocarbons from tight rocks like shale can be
understood by comparisons with the more permeable conventional reservoir rocks.
Measurements of the ability for a porous rock to transmit fluid were first defined in
1856 by Henry Darcy, a hydraulic engineer working on the municipal water system
for Dijon, France (Freeze and Cherry 1979). Darcy equated the flow of water
through the pore system of a rock or sediment with the flow of electrons through
metals. He developed an empirical relationship for what he called “hydraulic conductivity,” which is similar in structure to Ohm’s Law for electrical conductivity.
Darcy’s Law is written as:
q = kA(ΔP/μL)
Where q = flow in cubic cm per second, k = permeability (darcy or d), A = crosssectional area in square cm, ΔP = differential pressure in atmospheres per cm of
length, μ = fluid viscosity in centipoise (cP), and L = flowpath length in cm. To solve
for permeability (k) it can be rewritten as:
k = qμL/A(ΔP)
The basic unit of permeability is called the darcy. It is defined by a specific flow
rate when all the other variables are set to fixed values. Thus, a porous medium with
a permeability (k) of one darcy will discharge fluid that has a viscosity (μ) of 1 cP
(conveniently the viscosity of water at room temperature) from a cross sectional
area (A) of one square centimeter at a rate (q) of 1 cm
3
per second under a pressure
gradient (ΔP) of 1 atm per centimeter of length (L). This is illustrated graphically in
Fig. 2.2. The Standard International (SI) unit for permeability is the square meter, or
m
2
; one darcy is equal to about 10
−12
m
2
.
To obtain rock permeability in a lab, one needs to measure the dimensions of the
sample, the differential pressure across it, the fluid viscosity, and the discharge flow
rate. To determine gas permeability, a fixed ΔP is set for the measurement, q is measured and k is calculated. To determine permeability to water or another incompressible liquid, q is fixed for the measurement (a constant rate of liquid flow can be
obtained with a syringe pump) and ΔP is measured to calculate k.
Because Henry Darcy was performing experiments with water flowing through
columns of loose sand, the darcy is actually a fairly large unit, and conventional oil
and gas reservoir rocks like sandstone or limestone typically have permeabilities a
thousand times lower, in the range of 10
−3
d, or a millidarcy (md). Permeabilities in
tight sandstones or dense limestones are commonly a thousand times lower still,
around a microdarcy (μd) or 10
−6
darcy (Randolph 1983). Extremely tight rocks like
2.2 Why Frack?
Unlike conventional reservoirs, these rocks don’t need any kind of special structural
or stratigraphic traps to contain oil and gas – the hydrocarbons are held within the
tiny pores and adsorbed onto organic particles. In fact, the USGS calls these “continuous reservoirs” because they will produce hydrocarbons from just about anywhere in the formation if the proper stimulation techniques are applied (Charpentier
and Cook 2011). It was recognized during the energy crisis that if a way could be
found to directly extract oil and gas economically from the huge volumes of shale
and other tight rocks in the U.S., they would represent a very large hydrocarbon
resource indeed (Schrider and Wise 1980). The key to shale gas production is that
the source rock is the reservoir rock.
The difficulty of extracting hydrocarbons from tight rocks like shale can be
understood by comparisons with the more permeable conventional reservoir rocks.
Measurements of the ability for a porous rock to transmit fluid were first defined in
1856 by Henry Darcy, a hydraulic engineer working on the municipal water system
for Dijon, France (Freeze and Cherry 1979). Darcy equated the flow of water
through the pore system of a rock or sediment with the flow of electrons through
metals. He developed an empirical relationship for what he called “hydraulic conductivity,” which is similar in structure to Ohm’s Law for electrical conductivity.
Darcy’s Law is written as:
q = kA(ΔP/μL)
Where q = flow in cubic cm per second, k = permeability (darcy or d), A = crosssectional area in square cm, ΔP = differential pressure in atmospheres per cm of
length, μ = fluid viscosity in centipoise (cP), and L = flowpath length in cm. To solve
for permeability (k) it can be rewritten as:
k = qμL/A(ΔP)
The basic unit of permeability is called the darcy. It is defined by a specific flow
rate when all the other variables are set to fixed values. Thus, a porous medium with
a permeability (k) of one darcy will discharge fluid that has a viscosity (μ) of 1 cP
(conveniently the viscosity of water at room temperature) from a cross sectional
area (A) of one square centimeter at a rate (q) of 1 cm
3
per second under a pressure
gradient (ΔP) of 1 atm per centimeter of length (L). This is illustrated graphically in
Fig. 2.2. The Standard International (SI) unit for permeability is the square meter, or
m
2
; one darcy is equal to about 10
−12
m
2
.
To obtain rock permeability in a lab, one needs to measure the dimensions of the
sample, the differential pressure across it, the fluid viscosity, and the discharge flow
rate. To determine gas permeability, a fixed ΔP is set for the measurement, q is measured and k is calculated. To determine permeability to water or another incompressible liquid, q is fixed for the measurement (a constant rate of liquid flow can be
obtained with a syringe pump) and ΔP is measured to calculate k.
Because Henry Darcy was performing experiments with water flowing through
columns of loose sand, the darcy is actually a fairly large unit, and conventional oil
and gas reservoir rocks like sandstone or limestone typically have permeabilities a
thousand times lower, in the range of 10
−3
d, or a millidarcy (md). Permeabilities in
tight sandstones or dense limestones are commonly a thousand times lower still,
around a microdarcy (μd) or 10
−6
darcy (Randolph 1983). Extremely tight rocks like
2.2 Why Frack?