American Oil and Gas Reporter - February 2015 - 80

SpecialReport: Improved Oil Recovery
FIGURE 3B
Oil versus Gas Recovery from Shale Matrix
45

Recovery (%)

0
1.0E+00

Recovery (%)

blocks in the saturation and pressure map at the early production
time represent kerogen randomly distributed in the inorganic frame.
As expected, pressure in the matrix begins to decrease as hydrocarbon production starts through the surrounding low-pressure
fracture network. While pressure in the matrix depletes, water saturation does not change considerably during the early stages of

FIGURE 4
Pressure and Water Saturation Distribution
In Shale Matrix at Four Times

0
1.0E+01

1.0E+02

1.0E+03
1.0E+04
1.0E+05
Dimensionless Time
Oil Recovery

1.0E+06

1.0E+07

Pressure Distribution

Water Saturation Distribution

Gas Recovery

Dimensionless Time = 1
Pressure (MPa)

Water Saturation

ture blocks with a lower pressure. In these connections, hydrocarbons always move from the higher-pressure kerogen to a lower-pressure fracture.
The second flow path correlates to connections where oil-wet
kerogen grid blocks are adjacent to the water-wet inorganic grids.
In these cases, capillary pressure in the shale matrix with a fairly small mean pore size plays an important role. This dual nature of oil transport in kerogen, along with gas phase movement
into/out of kerogen, controls pressure dynamics in the media.
Oil and gas saturations in inorganic matter decrease as a result of hydrocarbon production and water imbibition into the inorganics. Oil saturation in kerogen does not change considerably
during the course of simulation.
Similar to oil, gas saturation in kerogen does not change much
over simulation time. Although the results show considerable
changes in fluid pressure and saturation in the shale matrix during simulation time, the same order-of-magnitude change should
not be expected in real shale reservoirs within a short production
period. Similar changes may require tens to hundreds of years
in a field-scale shale model.
Compared with the oil phase, gas shows a higher ultimate recovery from the matrix (Figure 3B). Higher gas recovery is predictable, since the gas phase has a lower viscosity, and
molecule/wall interactions and slip phenomenon at pore walls improve permeability to the gas phase. Despite many shale reservoirs having considerable liquid hydrocarbon saturations, the extremely low permeability of the shale matrix and high capillary
pressures in kerogen hinder oil phase flow in porous media. This
problem sometimes can be severe enough to shut down the oil
production process in liquid-rich shales.

0.7

0.6

0.5

0.4

0.3

0.2

0.1

Dimensionless Time = 104
Pressure (MPa)

Water Saturation

0.7

0.6

0.5

0.4

0.3

0.2

0.1

Dimensionless Time = 105
Pressure (MPa)

Water Saturation

0.7

0.6

0.5

0.4

0.3

0.2

0.1

Dimensionless Time = 107
Pressure (MPa)

Water Saturation

Mass transfer dynamics are better understood using 3-D maps
of pressure and water saturation distribution in the shale matrix.
Figure 4 shows modeled results at four production times. The red
80 THE AMERICAN OIL & GAS REPORTER

0.7

0.6

0.5

0.4

0.3

Mass Transfer Dynamics

0.2

0.1

American Oil and Gas Reporter - February 2015

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