Chemical Engineering
Biosci. Biotech. Res. Comm. 10(1): 184-191 (2017)
Evaluation of different effective parameters during
continual gas and water alternating gas (WAG)
injections in oil reservoirs
Zohreh Rezaei Kavanrudi
*, Mohammad Afkhami Karaei
and Amin Azdarpour
Department of Petroleum Engineering, Firoozabad Branch, Islamic Azad University, Firoozabad, Iran
Department of Petroleum Engineering, Marvdasht Branch, Islamic Azad University, Marvdasht, Iran
Oil recovery from the reserevoirs is devided into three stage of primary, secondary and tertiary stage. Primary recov-
ery is done using the antural energy of the reservoir, while the secondary recovery occures after the primary recov-
ery. It ususlly consists of water and gas injection into the reservoirs for improving the oil recovery. Finally, tertiary
ecovery takes in place, which is consists of different methods that are after the secondary recovery. The purpose of
this paper is to investigate and compare different gas injection scenarios in an Iranian oil reservoir using Eclipse
300 software. It models recovery factor, cumulative recovery, and the effective parameters of gas injection during
different procedures of CO
gas injection and Water Alternating gas (WAG) injection. Recovery factor, cumulative
recovery, remaining oil saturation, and reservoir pressure are studied and compared during different CO
gas injection
and WAG injection scenarios to specify an optimized pattern of injection process for EOR purpose. Laboratory data
of reservoir rock and  uid are matched by using PVTi software and the results imported into Eclipse for modeling
miscible CO
injection and WAG injection. The results showed that oil recovery and remaining oil saturation during
WAG injection in reservoir are 31.8 and 56.6% and during miscible CO
injection are 25.8 and 60.4% respectively. In
case if WAG injection is highly suggested instead of miscible CO
*Corresponding Author:
Received 27
Nov, 2016
Accepted after revision 17
March, 2017
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Zohreh Rezaei Kavanrudi et al.
Gas injection is done as miscible and immiscible meth-
ods. Natural gas is enriched with middle hydrocar-
bons like C
at miscible injection method. Recovery
increase rate is the maximum at this method and nit can
cause a recovery of about 65-75% of residual oil, if res-
ervoir rock has homogeneous characteristics and good
permeability.At CO
injection lots of this gas is injected
into reservoir along with some fraction of light hydro-
carbons for miscible sweeping. This method usually is
used for the reservoirs that reservoir initial pressure is
decreased during initial production or water ooding.
In this method, water is injected into reservoir until
pressure reaches to an acceptable amount. Then, CO
injected through injection wells. During this injection an
miscible area of CO
and light hydrocarbons is created
which is soluble in oil and speeds its movement toward
production wells (Kulkarni and Rao, 2005; Qin et al.,
2015; Hao et al., 2016; Feng et al., 2016).
Another injection method is Water Alternating Gas
(WAG) injection which is done in large scales in oil
elds for controlling oil mobility.WAG injection was
rst attempted at 1957 in Alberta and the results were
reported as successful.After this and because of its
numerous privileges comparing to water or gas injec-
tion separately it has been applied around the worldwide
like USA, Canada, North sea, Russia, Turkey, and Ven-
ezuela. The mentioned privileges include high capability
for controlling mobility ratio of displaced and displac-
ing phases, preventing immature  ngering in produc-
tion wells, capability of recovery of un-swept oil during
water or gas injection, creating a controllable and stable
front, and capability to use operational tools of water
and gas injection for different oil  elds. During these
years researchers investigated different aspects of WAG
injection for better understanding of the facts and the
changes of reservoir properties during injection period
(Quijada, 2005; Ahmadi et al., 2015; Teklu et al., 2016;
Chen and Reynolds, 2017).
Cobanoglu (2001) investigated immiscible gas and
WAG injection in BatyKozulca in Turkey with designing
and comparing different scenarios of injection rates,
cycles, and number of producing and injecting wells
using Eclipse 100. The results of their showed that
immiscible WAG injection led to more oil recovery com-
paring to immiscible gas injection. Kulkarni and Rao
(2004) investigated WAG injection and compared its
results to injection of gas and water separately in high
permeability layers of North Sea  eld. They claimed that
ngering of gas and water at high permeability layers
and immobility at low permeability layers causes a low
recovery during these methods. Their studies showed
that WAG injection prevents the movement of gas in
high permeability layers and creating a 3 phase area and
stability of mobility front. Therefore, this method shows
a higher recovery comparing to injection of water or
Jaturakhanawanit and Wannakomol (2012) studied
gas and WAG injection in Phitanulok  eld at north of
Thailand. They claimed that with an optimum injection
rate of 700 bbl/day of water and 700 Mf
/day of gas,
with a 12 month cycle of water and 1 month gas, the
achieved recovery would be 65% and 28% for WAG and
gas injection respectively. Christensen et al. (2001) inves-
tigated a 30 years period of seelington  eld at Texas.
They introduced an immiscible simultaneous injection
of water and gas as an optimum method for the men-
tioned reservoir. Maracaibo (2002)  eld was studied by
Manrique. The results showed that WAG injection will
increase oil recovery about 17% at that  eld.
Shi et al. (2008) investigated kuparuk  eld at North
of Alaska by using data from a 20 years period of WAG
injection. They claimed that although gas injection is
used as EOR method in this  eld, but because of imma-
ture  ngering and GOR increase, WAG injection was
suggested and replaced with that method to prevent
those problems. That also increased oil recovery. Instef-
jord and Todnem (2002) studied a 10 years period of
WAG injection in Gullfaks  eld. Their studies showed
that during injection in this  eld, oil production was
almost 2 MMSTB more than natural production. They
claimed that WAG injection in this  led led to increase
of recovery, sweep ef ciency, and water cut. Other than
these mentioned reports, there are so many successful
reports published about WAG injection and its privileges
comparing to EOR other methods (Rogers and Griggs,
2000; Rehman, 2008; Salehi et al., 2014; Batruny and
Babadagli, 2015; Yu and Sheng, 2017).
This  eld has been discovered at 1978 and developed by
drilling 9 wells until 1990. Initial oil in place for this  eld
was estimated to be about 440 MMbbl. Initial waster satu-
ration (Sw) of the reservoir, initial reservoir pressure (Pi),
reservoir temeprature, bubble point pressure (Pb), water
oil contact (WOC), and gas oil contact (GOC) of the reser-
voir were, 15%, 4335 psi, 302 F, 2673 psi, 6849 psi, and
2000 psi, respectively. For the simulation, the studied  eld
should be converted to a model for importing to Eclipse
300 simulator. A cubical model was created for this pur-
pose. After analyzing the effect of grid numbers on simu-
lation result, 21, 24, and 4 grid numbers were chosen at
direction x, y, and z, respectively.
Zohreh Rezaei Kavanrudi et al.
The relative  le for  eld grids is GRID.GRDECL that
was created by FloGrid software. The PERMX.GRDECL
was the  le for permeability information at x direction,
and as the same, PERMY.GRDECL was for permeability
at y direction.
For prediction of reservoir operation for simulator it is
necessary to de ne some limitations and conditions.
These limitations for economical production andof
probable limitations of wellhead facilities and prevent-
ing their damages are considered during simulation and
applied for all scenarios. The minimum economic pro-
duction from each well was assumed to be 100000 bbl,
the maximum GOR of each well was 3000 SCF/STB, the
maximum water cut was 50%, and the abondanment
pressure was 1500 psi.
The production was from 9 producing wells at the
start. EOR process and  eld development will not take
place until 10 years and during this time the only pro-
duction mechanism is natural production. For continu-
ing  eld development 1 well will be drilled each 2 years
until 20 years; one well as producing well and one as
injection well.
The second 10 years period is divides to 4 scenarios
that 3 of them are investigated in this paper. The second
step will be studied in future works. These for scenarios
A. Continuing natural production
B. Continuing production with drilling new wells
C. Continuing production with drilling new wells and CO
gas injection
D. Continuing production with drilling new wells and WAG
Table 1 shows petrophysical characteristics and the
information obtained from PVT test in simulator. The
layer has a low thickness of 100 ft that shows the res-
ervoir has several layer. The permeability in x and y
direction is 10 times of the permeability of z direction
Production as natural depletion mechanism, without
drilling new wells and EOR operation was investigated.
As mention earlier economical production from each
well is 100000 bbl per day. According to data all the
wells produce more than this amount. Bottomhole pres-
sure is set to 1500 psi for ensuring that oil reaches to
wellhead facilities and average production rate of each
well is set as controlling rate. The results for 50 years of
production with this mechanism (no new well and EOR
operation) are summarized in Table 2. The primary dirve
mechanism of the reservoir is by natural pressure of the
reservoir. The reservoir pressure transmits the  uid from
the reservoir to the wellbore and from wellbore to the
surface. In cases where reservoir pressure is high enough
through the prodcution life of the reservoir, natural  ow
of the reservoir continues without any restrictions. Oth-
erwise, in ll drilling and EOR methods should be applied
to maintain the natural pressure of the reservoir and
thus, increasing the amount of recoverable oil from the
reservoir (da Silva et al., 2013; Hu et al., 2014; Longxin
et al., 2015).
Production as natural depletion mechanism, with
drilling new wells and EOR operation was investigated.
During this simulation process it is assumed that after
10 years of production, each 2 years 1 new producing
well is drilled. Parameters such as layer thickness, layer
permeability, and reservoir oil saturation are affecting
parameters for determining where the well should be
drilled.Positions of the wells show that no well is drilled
at the left-down side of the reservoir. All wells that are
drilled in this area are shut because they didn’t reach
to economical production limit.The results of running
the simulation for 50 years are summarized in Table 3.
These results show that drilling new producing wells
won’t affect the production too much. The position of
wells and incapability of reservoir for production under
natural depletion mechanism can be the reason for it.
Table 1. Information of the studied reservoir
Parameter Unit Amount
Reservoir Depth ft 6167.1
Reservoir Length ft 13500
Reservoir Width ft 15000
Reservoir Thickness ft 100
Permeability of x and y direction mD 179.23
Permeability of z direction mD 17.943
Porosity Percent 25.56
Lightness API 46
Bo Rb/STB 2.9
Table 2. Summary of 50 years of production from
reservoir by natural depletion
Parameter Unit Amount
IOIP MMbbl 438.16
Oil Recovered MMbbl 47.61
Oil Recovery Factor Percent 10.86
Remaining Oil saturation Percent 76.31
Reservoir Pressure psi 2513.7
Zohreh Rezaei Kavanrudi et al.
In ll drilling is one of the improved oil recovery tech-
niques in petroleum industry. Some fraction of the oil in
place is bypassed through the movement from reservoir
to the wellbore and can not be recovered to the surface.
In  ll drilling in areas where sifni cant amount of oil
is trapped can be successful method of recovering these
amounts of oil from the reservoir (Aslanyan et al., 2014;
Awaad et al., 2015; Urban et al., 2016; Parihar et al.,
Recovery with CO
gas injection was investigated.
Gas injection is a common method of EOR operations.
Displacement factor highly depends on minimum misci-
ble pressure; a pressure that less than this pressure, the
injected  uid is not miscible with oil. In this paper, mis-
cibility or immiscibility of operation is determined using
PVTi software and reservoir data. Minimum miscibility
pressure is determined via slim tube method of Eclipse
software and this pressure is compared with maximum
injection pressure that is determined by formation break
pressure and it is 2420 psi for this case. Also, according
Table 3. Summary of 50 years of production from
reservoir with drilling new wells
Parameter Unit Amount
IOIP MMbbl 438.16
Oil Recovered MMbbl 47.61
Oil Recovery Factor Percent 10.86
Remaining Oil saturation Percent 72.94
Reservoir Pressure psi 2434.8
FIGURE 1. Effect of different CO
injection rates on oil
FIGURE 2. Effect of different CO
rates on GOR.
FIGURE 3. Effect of different CO
injection rates on res-
ervoir pressure.
to empirical equations from well loggings of layers show
that formation break pressure gradient is about 0.75 psi/
ft for this formation. So, it would be about 4625 psi.
Therefore, injection operation should be done in pres-
sures lower than this amount.
Another effecting parameter is gas injection rate and
in Figure 1 it is shown that with increasing injection rate
from 1000 to 4000 MMcuft/day the recovery will increase
from 26 to 33%. Figures 2 and 3 show the changes of
GOR and reservoir pressure according to injection rate
changes respectively. It can be seen that during high
injection rates, GOR crosses the maximum operational
limit. Also pressure increase trend during high injection
rates shows that continuing injection will increase the
reservoir pressure even more that reservoir initial pres-
sure. According to these explanations the injection rate
of 1000 cuft/day is considered as an optimum opera-
Zohreh Rezaei Kavanrudi et al.
tional rate. Table 4 shows the summarized results of CO
gas injection scenario in reservoir.
One of the major problems associated in water o-
oding is that capillary forces will trap the oil during
water ooding. Injection of miscible  uids was pro-
posed to overcome the capillary forces because in the
case of miscible  ooding there is no interfacial tension
and capillary force doesn’t exist to trap the oil. Carbon
dioxide was proposed as a miscible  uid; however it is
not miscible with oil at the  rst contact. CO
can improve oil recovery by generating miscibility,
swelling crude oil, lowering oil viscosity and lowering
interfacial tension between oil and CO
. However this
method has some advantages, the most disadvantages of
this method refer to the low viscosity of this gas. Not all
the oil is contacted with the gas due to the low viscosity
of the CO
and the ef ciency in oil recovery is not as
high as expected. High mobility of the CO
compare with
reservoir  uids can cause poor sweep ef ciency; there-
fore gravity override would be the result in which due
to low density of the injected gas, they move through
the top of the reservoir and try to  nd highly permeable
layers to move in. Early breakthrough of the injected gas
due to unfavourable mobility ratio is the major problem
in any CO
gas  ooding. Thus, controling the mobility
of the injected gas by water alternating gas could be a
more successful remedy form recovering additional oil
(Wang et al., 2015; Zhou et al., 2015; Zhang et al., 2015;
Hao et al., 2016; Li et al., 2016).
Production during WAG injection Scenario was
investigated in details. The effect of each parameter isn’t
known very well in WAG injection operation. In this sec-
FIGURE 4. Effect of water/gas ratio on oil recovery.
FIGURE 5. Effect of water/gas ratio oil saturation.
FIGURE 6. Effect of water/gas ratio on water cut.
tion several parameters such as water/gas ratio, injection
rate, and types of injection are investigated.
Water/Gas ratio means the ratio of total injected vol-
ume of water and gas and its optimum amount depends
on rock wettability. However, 1:1 ratio is the most com-
mon ratio that is used. High amounts of this parameter
have a great effect on recovery from water wet reservoirs.
Its optimum amount during WAG injection depends to
injected gas slug volume. With injection of slugs with
a volume of 60% of pore space (0.6 PV) the recovery
Zohreh Rezaei Kavanrudi et al.
would be great. However, injection slug with a volume
of 0.2PV will be more economical. For oil wetting rocks
the suggested ratio is 0:1 (continual gas injection) and
for water wet rocks is 1:1 WAG injection.
For investigating the effect of water/gas ratio injec-
tion rate of 4000 MSCF/day is selected and the diagram
of oil recovery changes for water/gas ratios of 0.5, 1,
and 1.5 (water injection rates are 2000, 4000, and 6000
bbl/day respectively) are calculated. Figure 4 shows the
effect of water/gas ratio on oil recovery.This can be
seen that by increasing this ratio from 0.5 to 1.5 the
production increases from 28 to 37%. Figure 5 and 6
show remaining oil saturation and water cut for differ-
ent water/gas ratios respectively.It can be seen for ratio
of 1.5 the wells produce too much water that can dam-
age wellhead facilities. Therefore, 1:1 ratio is selected as
optimum amount.
Effect of Types of Injection on overall recovery was
investigated. According to reservoir rock properties, two
type’s injection can be applied. For the  rst method, gas
injected into reservoir earlier than water and for the
second method it is water earlier than gas. When water
injected  rstly (second method) oil would be trapped in
pores if the reservoir is water wet and it will decrease
recovered oil. Figure 7 shows oil recovery in case that
gas is injected earlier that water ( rst method). The rea-
son for this can be because of water wetting behavior of
reservoir rock.
Low viscosity of the injected gas can cause bre-
akthrough and consequently poor sweep ef ciency. In
order to reduce the mobility of the injected gas, WAG
can be proposed as a way to improve sweep ef ciency
of the gas by controlling the mobility of the injected
gas and stabilizing the front. Reducing mobility of the
injected gas causes that the larger portion of oil contacts
with gas and then the amount of oil that will be reco-
vered is much more in compare to the conventional gas
injection. Although mobility control is the major advan-
tage of using WAG, compositional exchange is the other
mechanism that affects  uid densities and viscosities
and results on improving oil recovery. WAG injection
can be done either in miscible or immiscible depending
on the reservoir characteristics and  uid properties and
for the majority of all WAG injection projects results
show in a signi cant incremental oil recovery, generally
about 5 to 10 percent (Laochamroonvorapongse et al.,
2014; Ahmadi et al., 2015; Majidaie et al., 2015; Memon
et al., 2016; Bataee et al., 2016).
In this study, oil recovery scenarios in one of the Iranian
oil  elds was studied. The simualtion results showed that
natural depletion of the reservoir provides only 12%
recovery factor, which is very low. In addition, in ll
drilling also did not improve oil recovery signicantly. On
the other hand, oil recovery was improved signincatly
with CO
ooding and water alternating gas  ooding.
However, water alternating gas  ooding showed better
results compared to CO
The authors would like to appreciate the Department
of Petroleum Engineering, Firoozabad Branch, Islamic
FIGURE 7. Effect of injection type on oil recovery.
Table 4. Summary of results of CO
gas injection
Parameter Unit Amount
IOIP MMbbl 438.16
Oil Recovered MMbbl 109.37
Oil Recovery Factor Percent 25.84
Remaining Oil Saturation Percent 60.38
Reservoir Pressure psi 2551.5
Table 5. Results of WAG injection scenario
Parameter Unit Amount
IOIP MM bbl 438.16
Recovered Oil MM bbl 136.72
Oil Recovery factor Percent 31.8
Remaining oil Saturation percent 56.61
Reservoir Pressure Psi 2578.1
Zohreh Rezaei Kavanrudi et al.
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