1. Research Paper
Performance of Different Gas Injections for a Better Recovery of Heavy Oil
M. Yusuf Hashim, Saleem Qadir Tunio, University of Technology Petronas
Copyright 2010, University of Technology Petronas
This paper was prepared following the research in Final Year
Project of author in the university. The research was presented in
front of the lecturers in Geosciences and Petroleum Department in
the university, the supervisors of the project, and the
representatives from oil and gas company for the purpose of
further evaluation. Electronic reproduction, distribution or storage
of any part of this paper for commercial purposes without the
written consent of the University of Technology Petronas is
prohibited. Permission to reproduce in print is restricted to an
abstract of not more than acknowledgement of where and by
whom the paper was presented. Write to Saleem Qadir Tunio,
Geosciences and Petroleum Department, University of Technology
PETRONAS, Bandar Seri Iskandar, 31750 Tronoh, Perak, Malaysia.
Abstract
In this paper, the author is attempting to prove which
type of gas is better in recovering heavy oil (i.e. carbon
dioxide and nitrogen). Following couples of papers and
journals and consultations, the author will test the
performance of each gas using two different methods;
namely, through the lab experiments and ECLIPSE
simulation software.
Throughout this final report, the author begins
with some background of study followed by literature
review of the theory behind the concept of study. After
that, the author will discuss the methodology used, both
the experimental procedures and also the simulation
settings in ECLIPSE.
Next, the results of both the experiments and
ECLIPSE simulation are displayed in tables and graphs
followed by discussions and conclusions or summary. At
the end, the author cited lists of references and few
appendixes for further explanations.
Introduction
Heavy crude oil provides interesting facts for the
petroleum industry. Its resources in the world that are
more than twice those of conventional light crude oil has
opened the oil players’ eyes to seek new technology to
develop them. A lot of researches are currently going on,
to how this promising crude could be recovered. Among
them is gas injection method. The gas injection has
becoming the major technique to recover heavy oil, in
order to improve sweep efficiency or to mobilize the
irreducible fluid.
Heavy crude oil is defined as any type of crude
oil which has a very high viscosity thus does not flow
easily. It is referred to as "heavy" because of its density
or specific gravity is higher than that of light crude oil.
Heavy crude oil has been defined as any liquid
petroleum with an API gravity less than 20°, meaning
that its specific gravity is greater than 0.933. This mostly
results from crude oil getting degraded by being exposed
to bacteria, water or air resulting in the loss of its lighter
fractions while leaving behind its heavier fractions.
Mark Klins (2006) wrote in his paper that the
deposits of heavy oil total over one-half trillion cubic
meters in the U.S., Venezuela and Canada. In the U.S.
alone, there are over 2,000 heavy oil reservoirs occurring
in 1500 fields in 26 states. The total resource is
estimated at 17 billion cubic meters, of which some 9.7
billion cubic meters occur in fields which do not offer
favorable conditions for thermal methods (1)
.
Methodology
The author starts the project by collecting and
analysis current studies and research papers first,
then planned an experimental procedures and
simulation settings in ECLIPSE afterwards. At the
end, the author discuss about the results obtained,
and made some conclusions.
Experimental Set-up & Procedures
In the POROPERM® machine, the experiments taken
using the RPS machine could only take place after the
author have taken a couple of measurements below. Two
cleaned core plugs were taken the dimensions like
diameter and length and weight were measured. Using
the POROPERM® device, the core plugs were put in the
core holder vertically in the machine, confining pressure
is applied of up to 1000 psi. The system in the computer
would automatically display the graphs and
characteristics of the core plug. The porosity and
permeability readings in the results section were
recorded. Next, the core plugs were saturated with
distilled water in a manual pump sucker for at least 6
hours. In the author’s experiment, he saturated it for one
whole day.

2. Using the Relative Permeability System (RPS) Machine,
all the tubings were cleaned thoroughly by air gun shot it
was made sure to free from foreign fluid. The core
holder equipments were prepared, the core plug was put
inside a confining latex tube just about 1 inch deep on
one side. The core holder closure was plugged close on
one end, while putting all of them inside the metal core
holder main enclosure. Using the other end core holder
closure was locked thigh using the C-wrench. Brine was
prepared for 30,000 ppm poured into the external pump
and was locked close. The air vent is pressured to pump
the brine into the accumulator B. Heavy oil that was
heated in the oven at 60degree C prior to the experiment
was slowly poured into the accumulator A, and was
closed and locked to its place with half inch wrench. As
for the accumulator C, CO2 will be injected later, just
before we proceed with EOR process. Before that, the
accumulator was just left it empty first. In the computer
interface software for RPS®, the following steps were
done:
1. Inject brine solution until the permeability reading
stabilizes. This step is taken for the purpose of
determining the initial permeability or absolute
permeability.
2. Inject Crude Black Oil.
To measure how much volume of oil that has been
saturated. Also this is to measure the irreducible
water saturation, Swir. Oil is pumped into the core to
displace the water. As more oil is pumped,
3. Inject Brine solution.
This is done to determine how much volume of oil
that has been produced, and how much oil that
remains. This is the residual oil saturation, Sor.
4. Inject carbon dioxide, CO2 gas.
This step is the Enhanced Oil Recovery process,
where we inject gas into the core, to recover the crude
heavy oil.
5. Measure the recovery of crude oil manually.
6. The experiment would be repeated by using Nitrogen
gas.
ECLIPSE Simulation Procedure
There were two runs, first using CO2 and the seconds
using N2. In the data file, we are using the well
dimension of 18 by 3 by 36 so it would give a total of
1944 cells. The heavy oil properties like bubble point,
density, viscosity are set in the data file, and shown in
Table 2. In the gas section of the data file, we use the
density of CO2 as 0.12342 lb/ft3
while the density of
nitrogen, N2 gas used was 0.2888 lb/ft3
.
Results & Discussions
a) Experimental Result Analysis
In the POROPERM ® machine, the following data was
obtained:
Core plug 1 Core plug 2
Name: K-4
Length:
(73.12+73.08+73.12)/3 =
73.107mm
Diameter:
(38.04+38.01+38)/3 =
38.017mm
Weight:(174.452+174.454
+174.453)/3 = 174.453g
Name: BR-7
Length:
(76.38+76.39+76.41)/3 =
76.393mm
Diameter:
(37.53+37.63+37.57)/3 =
37.577mm
Weight:(177.660+177.662
+177.660)/3 = 177.661g
PoroPerm System Computer Calculation Results
Vp (cc) = 16.116
Kair (mD) = 232.774
Φ (%) = 19.426
V bulk (cc) = 82.964
Vp (cc) = 16.367
Kair (mD) = 366.776
Φ (%) = 19.353
V bulk (cc) = 84.572
Putting all the information above (such as Viscosity,
Length and Diameter) into the RPS machine, the
experiment was run to show the heavy oil recovery
process using computer control.
Graph 2: The volume of 30,000ppm brine displaced over time.
Graph 3: The volume of heavy oil displaced over time.
0
10
20
30
40
5 10 15 20 25 30 35 40 45 50 55 60
VolumeofBrine(cc)
Time, min
Volume of Brine (cc) displaced over time
100° C 70° C
0
1
2
3
4
5 10 15 20 25 30 35 40 45 50 55 60
VolumeofHeavyOil(cc)
Time, min
Volume of Heavy Oil (cc) displaced over time
100° C 70° C

3. Graph 2 shows the difference in the increment of
accumulation of brine collected with regards to the
increase in temperature from 70°C to 100°C, where we
could clearly see, the higher the temperature used, the
more fluid we could displaced.
Graph 3 shows the constant volume of heavy oil
being recovered at the end of the experiment on both
runs, 70°C and 100°C. This, which resulted from the
plugging of the outer tubing of RPS, has made the outlet
to go beyond 5000 psi. This excessive pressure would
not me a suitable pressure to inject gas into the core
holder. In other words, the author failed to do research
on EOR process experiment.
Remarks: Since both of the experiment at 70°C
and 100°C is not quite satisfied, as the author cannot
proceed with the CO2 injection, the author decided to
simulate the whole behavior of heavy oil being displaced
by gas injection using ECLIPSE, a Schlumberger
developed software. The following section will show the
results from the ECLIPSE simulation works.
b) ECLIPSE Simulation Result Analysis
Graph 4: Field Oil Production Total (STB) versus time using
CO2 injection
Graph 4 shows the cumulative of oil production
as the time proceeds in days. As we can see, starting
from the origin, the oil starts to be produced in
increasingly behavior up to a point, the maximum point
(at 500 days) of our experiment, which should not be
the real time in the well, of course.
Observing on the graph alone, we could not
determine precisely how much of heavy oil have been
recovered. Thus, the author managed to find a function
in Eclipse to give the result of the production in Excel
format file, which could be seen in Table 7. In the table,
we will see that the cumulative of production would
give 37.092 stb.
Graph 5: Field Oil Production Total (STB) versus time using
N2 injection
In this Graph 5, we could see the same behavior
happened, which is as the time proceeds, the cumulative
oil production of heavy oil also increases up to a certain
points maximum at 500days (the time we use for both
runs of the experiments).
Table 8 tabulates the reading of the graph of
cumulative oil production versus time. In this table, you
could see more accurately on each specific point of
time, how much has been produced by our well using
Nitrogen gas injection. As you could see, the total field
oil production is 37.084 stb.
At first glance we would conclude that both the
graphs of Run 1 and Run 2 are relatively the same,
seeing at the graph alone. However, after further
research on the table reading, the author would say it is
not the same, differ by 37.092-37.084 = 0.008 stb.
From this small figure, the author predicted that
it would yield a bigger and more significant difference
if the well is to be produced for a longer time, say 100
years. This shows that carbon dioxide has yielded a
greater recovery of heavy oil as compared to the
nitrogen gas. An example of the recovery for 100 years
is shown as follows.
Injection gas Recovery after 100 years
CO2
37.092 ‫ܾݐݏ‬
496 ݀ܽ‫ݏݕ‬
ൌ 0.0747822 ‫ݕܽ݀/ܾݐݏ‬
For the next 100 years,
0.074782*100*365 = 2,729.55 stb
N2
37.084 ‫ܾݐݏ‬
496 ݀ܽ‫ݏݕ‬
ൌ 0.07476613 ‫ݕܽ݀/ܾݐݏ‬
For the next 100 years,
0.07476613*100 *365 = 2,728.96 stb

4. Risks and Opportunity on using CO2
The author has agreed to several researches done on
using CO2 to recover heavy oil, among them is T. M.
Doscher of University of Southern Carolina, said in a
non-stabilized system, the efficiency of carbon dioxide
would be maintained, whereas the efficiency of
nitrogen would be very low. This is because N2 is far
less compressible than CO2. As a result, N2 is far less
viscous and far less dense than the CO2. Doscher shows
that gravity override and viscous fingering will be much
more prominent in non-stabilized N2 flood than in
corresponding CO2 flood18
.
Mark A. Klins. Mark says in his study that in
any means, be it carbon dioxide, nitrogen flooding or
even natural depletion, the recovery of heavy oil is
much dependent on the oil viscosity14
.
The author also studied on the risks or
challenges involved in utilizing carbon dioxide. Among
them is the leakage problem, which Michael A. Celia
et. al. was quoted as saying, that hundreds of wells
drilled may require CO2 storage. While this approach
appears to be technically feasible, a comprehensive risk
assessment is required to determine the overall
effectiveness and possible environmental consequences
of this approach. One important part of such a risk
assessment is an analysis of potential leakage of
injected CO
2
from the formation into which is injected,
to other permeable formations or to the atmosphere.
Such leakage is a concern because it may contaminate
existing energy, mineral, and/or groundwater resources,
it may pose a hazard at the ground surface, and it will
contribute to increased concentrations of CO2
in the
atmosphere.15
Conclusions
The injection of gas into the reservoir has been proven
as feasible means of recovering heavy oil, especially
with the right concentration of the particular gas
injected. It is very important to; however, know the
most feasible type of gas to be injected, as at the end of
the day, the production capacity is not our main goals
after the high cost paid for the expenses of the gas
injection.
At this phase of the project, the author has concluded
the following:
a) Carbon dioxide is a better means of gas injection as
compared to Nitrogen gas for to recover heavy oil
reservoir
b) The reasons that are prominent are that the CO2 is
more viscous, denser and compressible as compared to
N2, even though the nitrogen is abundantly available
from the air.
c) Heavy oil in Field A in Sudan has the pour point of
70 °C, the threshold temperature at which it will starts
to flow. .
d) Despite the better performance of carbon dioxide in
pushing the heavy oil towards the producing well, the
supply CO2 is relatively scarce and more expensive
than N2 gas. Nitrogen is easier to be found as it
constitute about 78.01% of the air.
Recommendations
As the author have undergone many challenges and
process throughout this study of heavy oil recovery
using gas injections, the author has learnt and would
like to recommend the following for future studies, so
that the oncoming studies implemented could be
improved better and not repeating the same mistakes.
There are:
a) The RPS machine used in the experimental
phase should be chosen well, as there are two
types of this machine in the lab currently in
UTP, one with smaller fluid channel, the other
one with a bigger size, which normally be used
for the drilling mud testing. The author have not
tried using this bigger machine for the limitation
of time frame allocated for study, and the author
recommend this machine to be used for future
studies.
b) The crude heavy oil sample used in this study
has an API of 18.5°, which could be
considerably pretty heavy. The author suggests
to start with an API of 20° first, as the higher the
API, the more likely for the heavy oil to flow
with minimum viscosity possible.
c) In the simulation phase, the author has used
ECLIPSE 100 software. As the current practice
of industry, ECLIPSE 300 is being used for the
simulation of heavy oil, therefore, the author
recommends this software to be used next time
in future studies.
References
1. Mark A. Klins (2006) “Heavy Oil Production by
Carbon Dioxide Injection” JCPT presented for
Journal of Canadian Petroleum Technology,
Alberta, Canada.
2. I. Chatzis S. Ayatollahi, “The Effect of Gas
Injection Rate on the Recovery of Waterflood
Residual Oil Under Gravity Assisted Inert Gas
Injection”, Petroleum Society of CIM No.
SS9332, 5th
Petroleum Conference of the
Saskatchewan Section, Canada, October 18-20,
1993.
3. R. Foulser, P Naylor and C. Seale (1990),
“Relative Permeabilities for Gravity Stable
Displacements of Waterflood Residual Oil by
Gas”. Trans IChemE, 68 Part A, pp 307 – 315.

5. 4. P.E. Oren and W.V. Pinczewski (1991), “The
Effect of Wettability and Spreading Coefficient
on the Recovery of Waterflood Residual Oil by
Immiscible Gas Flooding”. SPE 24881, 67th
Annual SPE Technical Conference, Washington
DC, October 04-07, 1992.
5. Vizika, O. (1993) “Effect of the Spreading
Coefficient on the Efficiency of Oil Recovery
with Gravity Drainage”. Symposium on EOR,
Division of Petroleum Chemistry Onc., 205th
National Meeting, American Chemical Society,
Denver, Colorado, March 28-April 02, 1993.
6. Rolf Wuensche, “Nitrogen Injection for
Enhanced Oil Recovery”, Petroleum Society of
CIM No. 78-29-44 paper, 29th
Annual Technical
Meeting of Petroleum Society of CIM, Calgary,
Canada, June 13-16, 1978.
7. Namit J. Jaiswal (2007) “Distillation Effect in
Heavy Oil Recoveyr Under Steam Injection with
Hydrocarbon Additives” SPE 110712, 2007 SPE
Annual Technical Conference and Exhibition
held in Analheim, California, U.S.A., 11-14
November 2007.
8. Shubao Tian and Shunli He (2006)
“Investigating the Effect of Steam, CO2 , and
Surfactant on the Recovery of Heavy Oil
Reservoirs”. SPE/PS/CHOA 117394,
International Thermal Operations and Heavy Oil
Symposium, Calgary, Alberta, Canada, 20-23
October 2008.
9. Rafael Sandrea and Ralph F. Nielsen,
“Dynamics of Petroleum Reservoirs Under Gas
Injection” , from the National Research Council
of Venezuela, Gulf Publishing Company Book
Divisio, Houston, Texas, 1974.
10. Shedid A. Shedid, “Simulation Investigation of
the Feasibility of Simultaneous Hydrogen
Sulfide-Water Injection to Improve Oil
Recovery”, SPE88503 paper, SPE Asia Pasific
and Gas Conference, Perth, Australia, 18-20
October 2004.
11. R.E. Sweatman, M.E. Parker, S.L. Crookshank,
“Industry Experience With CO2-Enhanced Oil
Recovery Technology, SPE 126446 paper, SPE
International Conference, San Diego, California,
USA, 2-4 November 2009.
12. Laroche, C. (1998) “Secondary and Tertiary
Gas Injection Experiments in Heterogeneous
Wettability Micromodels”. European Petroleum
Conference, The Hague, The Netherland, 20-22
October 1998.
13. Brian Clark et al. (2007) “Heavy Oil” Topic
Paper #22, Schlumberger Limited, National
Petroleum Council Heavy Oil Subgroup Of The
Technology Task Group Of The NPC
Committee On Global Oil And Gas, February
2007.
14. Mark A. Klins, (1982) “Heavy Oil Production
by Carbon Dioxide Injection” The Journal of
Canadian Petroleum, Montreal, Paris.
15. Michael A. Celia et. al.“Quantitative Estimation
Of Co2 Leakage From Geological Storage:
Analytical Models, Numerical Models, And
Data Needs”, Alberta Energy and Utilities
Board, Edmonton, T6B 2X3, Canada.
16. Car Curtis and Robert Kopper (2002) “Heavy
Oil Reservoir” Oilfield Review Magazine,
Puerto La Cruz, Anzoategui, Venezuela.
17. Eclipse Simulation Software Manual 2009.1 by
Schlumberger.
18. T. M. Doscher et. al. (1984), SPE University of
Southern California, SPE California Regional
Meeting, Ventura, March 23-25, 1984.