GEL 1: Lecture 1: Origin of Earth & Early Earth
(5th Edition: Ch. 1, specifically p. 15-19, 27-34
& Ch. 13, p. 470-472)
Where did Earth come from? How do planets form?
Bottom line: Earth and the rest of the planets in our solar system formed from the remn

diffusion predominates in the lateral direction. This phenomenon is called the
Taylor effect (Figure 2.18).
Aris and Amundson^ modeled porous media as a series of mixing cells
where perfect mixing occured within each cell (Figure 2.19), which allowed the

where the concentration shifts abruptly at the earlier time but shifts more and
more gradually as time progresses. During a CO2 injection where the fluids are
moving, the concentration profile of the fluids will change with both time and
distance, as show

it ahead of the displaced fluid via the viscous fingers. Figure 2.14 shows the
effect that the reciprocal Peclet number, a dimensionless indicator of transverse
dispersion comprised of the ratio of the time, L/v^, for a particle of fluid to be
convected t

C02 processes yield higher recoveries than tertiary CO2 processes (i.e., following
a waterflood).
Stern^ investigated the effects of pore-level fluid distribution, flow rate,
core length, oil viscosity, wettability, WAG ratio, and initial water saturation

hydrocarbons present (Figure 2.11), the molecular weight of the C5+
hydrocarbons in the oil (Figure 2.12), and the molecular structure of
hydrocarbons (e.g., aromatic rings) present in the oil.^'
Metcalfe and Yarborough^ studied miscibility processes of C

2.3.1. Phase Behavior
Hutchinson and Braun' studied the condensing gas drive mechanism in a
methane/crude oil system and felt that it dominated the displacement process
once hydrocarbon components of the crude oil began to mix with the injected
methane. Z

lOOmmxIOOmm tube with a square constriction and used the following capillary
number that would correlate with the capillary number used by Gunn and
Slattery'^ for porous media:
N - ^
(2.13)
a
Here, Ap was the pressure drop across the capillary, and Xc was

Mungan'^ found that altering core conditions from oil-wet to water-wet
yielded an additional 2.6-3% oil recovery in a waterflood, but altering the
conditions from oil-wet to intermediate-wet did not increase the recovery factor.
Wagner and Leach' found th

coefficient, Do, and the formation electrical resistivity factor with porosity, 1/Fn.
The second term of each equation represents mechanical mixing by convection
as a function of the average longitudinal interstitial velocity, v, the molecular
diameter of

Craig et al. studied the effect of gravity segregation on miscible gas drive
systems, concluding that up to 80% bypassing could occur in a linear system and
that the amount of segregation was influenced more by the average injection rate
than by variation

Although bypassing by CO2 can occur whenever there is interfacial
tension between the oil, water and CO2 phases, hydrocarbon mobilization may
still be possible. Within an individual pore that is water-wet, immiscible (i.e.,
physical) displacement will no

behavior, and dispersion influence the displacement efficiency of a CO2 flood,
and that bypassing can occur on both the microscopic scale and the macroscopic
scale.
2.4.1. Microscopic Displacement Efficiency
Within a swept volume, microscopic displacement

various test that could be performed before a field performance be carried out.
These tests include a comparison of filtering residue from a representative crude
oil with that of a C02-contacted crude oil, conducting a PVT analysis on a
C02/crude oil mixt

the amount of fluid injected, while the remaining curves show the areal sweep
efficiency at a set number of PVs injected as functions of the mobility ratio.
2.3.7. Water Injectivity
Shelton and Yarborough"^ studied phase behavior in MCM processes to
addre

The K-factor is in turn a product of the reservoir heterogeneity factor, H, and the
viscosity ratio factor, E. Where the reservoir heterogeneity is equal to 1, the Kfactor is expressed using the quarter-power mixing rule as follows:
K=[0.7% + 0.22(Mjiu,f'

was greater than in water-wet rock. They concluded that the transition zone
between crude oil and a displacing solvent phase in an MCM process was very
short and that an increase in the displacement rate decreases oil recovery within
the swept region. In

proposed an alternate differential capacitance model to arrive at a more accurate
dispersion coefficient. BakeP^ later modified this capacitance model and
developed a method of rapidly matching this model to experimental data to
model the unit-viscosity r

recovery and to determine the extent of macroscopic bypassing. Since the
viscous/gravity ratio can be controlled to an extent by the flow rate, such an
analysis could also determine to what extent the operator can influence the
recovery by adjusting the f

it applies to two different liquids or a liquid and a solid.^ Wettability acts at
fluid/solid interfaces and is defined as the tendency of one fluid to spread on or
adhere to a solid surface in the presence of a second fluid^ (Figure 2.7).
Amyx, Bass, and

line to the fractional water flow of one. Further plots based on the BuckleyLeverett model include those of Figures 2.5 and 2.6. Figure 2.5 is a plot of
dimensionless distance versus dimensionless time at various water saturations,
where it can be seen ho

viscosity ratio and the density difference. In addition, he provided correlations of
recoveries of residual oil as a function of the capillary number, a dimensionless
variation of the Taber number (Figure 2.8). Stegemeier" also developed a
method of predi

NOMENCLATURE
A
cross-sectional area normal to the direction of flow. In Equation
2.14, this also denotes fluid A.
B
In Equation 2.14, this denotes fluid B.
Ce
concentration of fluid B
D
apparent diffusion coefficient
Do
molecular diffusion coefficient
DBA

2.35
2.36
Production rates before and after CO2 injection in a WAG process
(Seventeen-Pattern Area)
76
Utilization of CO2 with incremental oil production and CO2 production
in a WAG process (Seventeen-Pattern Area)
76
2.37
Comparison between cumulative re

Greek Letters
a
an empirical constant proportional to the amount of water blocking
or water shielding during a CO2 flood
^
porosity of the formation
X
fluid mobility, the ratio of its permeability to its viscosity
XD
fluid mobility of the displacing phase

2.17
Concentration profiles for the injection of a slug of Fluid B to
displace Fluid A
65
2.18
Dispersion resulting from laminar flow in a straight capillary
66
2.19
Dispersion based on porous media being viewed as a series of
mixing tanks
Dispersion resu

SD
average saturation of the displacing phase, i.e., behind the flood
front
Sj
average saturation of the displaced phase, i.e., ahead of the flood
front
t
time
to
dimensionless time, as a fraction of the time needed to fill the entire
pore volume with the

LIST OF FIGURES
2.1
Relative permeability characteristics of porous media
in (a) strongly water-wet rock, and (b) strongly oil-wet rock
57
2.2
Theoretical fractional water flow of water versus water saturation
57
2.3
Actual fractional water flow versus wa

Ki
longitudinal dispersion coefficient
Kt
transverse dispersion coefficient
k
absolute permeability of a porous medium to a given fluid
l<ri
relative permeability of a porous medium to fluid i with respect to its
absolute permeability
km
relative permeabi

In this work, a new concept in CO2 flooding is introduced as "soakalternating-gas," or SAG, which incorporates the soak period of a CO2 hufTn'puff
into the continuous CO2 flood to provide additional mobility control and a viable
alternative to a WAG proce