Co2 flooding is an important EOR method that involves injecting supercritical CO2 into depleted oil reservoirs to displace oil. There are three main displacement mechanisms - miscible, partially miscible, and immiscible. Compositional simulation is needed to accurately model CO2 flooding since fluid properties depend on both pressure and composition. The SACROC unit in the Permian Basin was one of the first large-scale CO2 floods, and involved injecting CO2 from nearby gas plants to boost oil production from over 300 million barrels of original oil in place.

1. CO2 Flooding Simulation

2. Co2 Flooding Process :
One of the most important EOR methods.
Involves injection of supercritical CO2 to displace oil from a
depleted oil reservoir.

3. Supercritical Carbon Dioxide
CO2 above it’s critical
temperature and pressure.
Expand to fill its container like a
gas but with a density like that
of a liquid.

4. Mechanism of Co2 Flooding
Swelling crude oils (CO2 is very soluble in high-gravity oils).
Lowering oil viscosity.
Lowering the interfacial tension between the oil and CO2
phases in the near-miscible regions; Generating miscibility
between the oil and CO2 phases*.

5. Mechanism of Co2 Flooding
Displacement of oil bank occurs in three ways :
Completely miscible.
Partially miscible (Multiple contact miscible flooding).
Immiscible.

6. WAG Process.
Water Alternate Gas Process.
Improved sweep efficiency.
Cuts down on CO2 cost.
Less breakthroughs.

7. Miscible Displacement.
Two fluids are "first-contact miscible" if they form only one phase
when mixed in any proportions
Usually related to high reservoir pressure
(> MMP*) & high oil gravity.
A B A+B

8. Immiscible Displacement
Usually related to too low reservoir pressure (<MMP) and
low gravity oil.
Co2 injected remains in distinct phase from oil.
Improves recovery by causing oil to swell decreasing density
and increasing mobility.
A B A B

9. Partially miscible Co2 Flooding
Also called Multiple-Contact miscibility.
Reservoir pressure > MCMP.
Displacement processes may be described as:
Vaporizing Gas Drives
Condensing Gas Drives
Condensing/Vaporizing Gas Drives

10. Partially miscible Co2 Flooding
Cont’ d
Vaporizing gas drive mechanism:
Based on vaporization of intermediates from
reservoir oil.
CO2 can extract heavy components up to C30+.
Vaporizing gas drive occur at the front of the solvent
slug.

11. Partially miscible Co2 Flooding
Cont’ d
Condensing gas drive mechanism:
The injection gas is rich with the intermediate
components.
The light components are condensed in the crude oil to
create a mixture at the displacing front.
Combined vaporizing and condensing mechanism:
Or also called CO2 miscible displacement.

12. Introduction to Co2 Flooding
Simulation :
Black oil simulator models immiscible flow where
fluid properties can be described as a function of
pressure only or pressure and oil/gas saturations.
For modeling studies include mixing of fluids
having significantly different properties will it be
efficient enough?

13. Introduction to Co2 Flooding
Simulation :
Whenever compositional effects are important comes the
need for:

14. Compositional Simulation :
Vapor-liquid equilibrium is not only dependant on
pressure but also on composition.
Rigorous flash calculations must be made to determine
hydrocarbon phase composition after that viscosities
and densities can be calculated from phase
compositions

15. Compositional Simulation : Cont’d
Compositional reservoir flow equations presented by Collins :
Remark : Water equations is not changed from black oil
formulation.

16. Compositional Simulation : Cont’d
Large number of approaches for solving those equations are
presented in literature.
However some inconsistencies may occur in computation which
can lead to unstable model

17. Compositional Simulation : Cont’d
Recently this trend have been bypassed by using
EOS’s to correlate fluid properties even in
complex reservoir fluids where significant
amounts of non-hydrocarbon fluids exist by
calibrating correlations to laboratory experiments.

18. Co2 Flooding Simulation :
Modeling multiple contact miscible displacement is rather difficult.
There are troublesome vapor-liquid equilibrium calculation
specially near critical point where miscibility achieved.

19. Co2 Flooding Simulation : Cont’d
Accuracy problems
resulting from
numerical dispersion
errors.
This figure shows gas
saturations
generated during 1-D
condensing gas drive
calculation

20. Co2 Flooding Simulation : Cont’d
A common approach to solve such a problem is to
assume miscibility.
In such case only three components will be used ;
(IOIP, CO2 & drive fluid (if any)).
Resulting in a more simplified model in two ways :
Fewer components & vapor-Liquid calculations avoided.
Runs much faster than a fully compositional model making
it easier to use a finer grid.

21. Co2 Flooding Simulation : Cont’d
Limited application to model fluid flow (inj. &
production rates) but cannot be used to detect
whether miscibility obtained in reservoir or the
size of miscible bank.
Usually this sort of simplified calculation is made
by what is called a (Modified Black Oil Simulator).

22. Co2 Flooding Simulation : Cont’d
Todd & longstaff model
Assumes four components in two phases;
Wetting phase; water.
 Non-wetting phase (Oil ,gas & Solvent (CO2)).
A more modified model presented by Chase &
Todd is more applicable in our case as it accounts
for CO2 transport to the aqueous phase, water

23. Co2 Flooding Simulation : Cont’d
Input data required :
Depending on the approach to be considered
Fully compositional.
Phase equilibrium information, phase densities, phase
viscosities, compositions of reservoir hydrocarbons ,..etc
Modified black oil model.
Depending of assumptions taken
(Ex: immiscible displacement relative permeability curves &
MCMP)

24. • Methods used for determining MCMP:
1. Slim tube test:
used to:
1- determine minimum miscibility pressure
2- measure miscibility condition at reservoir pressure and temperature.
• The slim tube apparatus consists of:
 40 ft long, 0.25” diameter coiled stainless steel tube packed with 160-200
mesh sand.
 Positive displacement pump.
 Sight glass.
 Back pressure regulator.

25. • Procedure:
1- sand in the slim tube is saturated with oil at
reservoir temperature.
2- Inject 1.2 P.V of CO2 by the positive displacement
pump and observe the effluent through the sight glass
3- back pressure regulator will maintain constant
pressure through the apparatus.

26. 4- volumes of both gas & liquid are measured
using digital volume measuring detectors.
5- Oil recovery is plotted against pressure to
determine MCMP(pressure with maximum
recovery)

27. Levels of oil recovery and sharpness of
recovery curves depend on
1- Temperature
2- Oil and injection gas composition
3- Slim tube dimensions
The results from slim tube can be used for
simulating compositional changes, resulting
from continuous contacts between reservoir
fluids & injection gas.

28. 2. Rising bubble apparatus:
- used for determining MMP
- used only with vaporized gas drive

29. Principle
1- oil is confined in a slim glass tube inside a
double windowed pressure vessel
2- Gas is injected in the slim glass through
water below the oil
3- the shape of the bubbles is an indication of
MMP
•The gas bubbles have three possibilities:
1- At pressure below MMP
Bubbles formed in water will continue
upward through the oil

30. 2- At pressure close to MMP
The new bubbles released in water becomes too
large to be stable in oil, so disintegrates into lower
sized bubbles, the larger bubbles dissolve in oil and the
smallest bubbles rise on through the oil.
3- At pressure equal or grater than MMP
The bubble rises to the oil water contact and
immediately burst into several smaller bubbles, the
smallest bubbles continue for short distance up & then
disappear.

31. • Swelling test
1. Start with a certain volume of original
reservoir fluids at the saturation pressure.
2. Lean gas with specified composition
and volume is injected.
3. Change in pressure until reach to
saturation pressure and saturation volume.
4. Swelling factor, the new saturation
volume divided by the original saturation
volume can be determined.

32. Vaporization test
used to measure the extent of vaporization of intermediate
and heavy components from reservoir liquid by stripping
into injected gas stream.
Procedure
1. inject a specified amount of lean gas into specified
amount of reservoir fluid at some reservoir temp. and
pressure below saturation pressure.
2. The new composition is flashed at the same previous
pressure.
3. the composition of the removed enriched gas is
measured then the process is repeated with more lean gas.

33. Examples of CO2 flooding projects world
wide
 Permian Basin:
- The most prolific petroleum province of north
America.
- located in the west of texas & southest new
mexico.
- Compasses a surface area greater than 220000
km2.
- The basin is separated into eastern and western
halves.
- The western half contains a thicker sequence of
sedimentary rock.

35.  The SACROC unit in the Permian Basin:
- The first large scale CO2 flood in the world
- Cover an area of 205 km2 with in depleted kelly Snyder oil
field in eastern part of Permian basin in west texas.
- Oil is produced from lime stone reservoir.
- The reservoir holds approximately 336 million Sm3
OOIP.
 Production history:
1- primary oil production, since 1948.
2- Secondary recovery by water injection, since 1954.
3- CO2 immiscible flooding in 1972.
4- CO2 miscible flood in1993, still ongoing.

36. Sources of CO2:
1- Nearby natural gas processing plants, about 270 km
away from the oil field.
2- In 1996, the company had to convert transportation line
to natural gas pipeline & CO2 is supplied by Shell CO2
company.
3- In 1998, from val verd gas treatment plant.
Results
- The cumulative gross injected CO2 is 30 Billion Sm3 and
the recovered oil by EOR was 11 million Sm3
- In the early stages of CO2 injection rate was 5.1 million
Sm3/day and decreased to 1.7 million Sm3/day in 1995.

37. • The peak production was 31800 Sm3/day in 1975
• Production decreased rapidly to 1900 Sm3/day in
1995, due to the decrease of injected CO2
•There are plans to increase injected CO2 with
expected 3180 Sm3/day