Chemical Engineering

Communication

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

ABSTRACT

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

injection.

KEY WORDS: MISCIBLE CO

INJECTION, WATER ALTERNATING GAS (WAG) INJECTION, ENHANCED OIL RECOVERY

184

ARTICLE INFORMATION:

*Corresponding Author: zrezaiek@yahoo.com

Received 27

Nov, 2016

Accepted after revision 17

March, 2017

BBRC Print ISSN: 0974-6455

Online ISSN: 2321-4007 CODEN: USA BBRCBA

Thomson Reuters ISI ESC and Crossref Indexed Journal

NAAS Journal Score 2017: 4.31 Cosmos IF : 4.006

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Online Contents Available at: http//www.bbrc.in/

Zohreh Rezaei Kavanrudi et al.

INTRODUCTION

Gas injection is done as miscible and immiscible meth-

ods. Natural gas is enriched with middle hydrocar-

bons like C

-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

gas.

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).

MATERIALS AND METHODS

RESERVOIR INTRODUCTION AND MODELING

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.

BIOSCIENCE BIOTECHNOLOGY RESEARCH COMMUNICATIONS EVALUATION OF DIFFERENT EFFECTIVE PARAMETERS 185

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.

HYPOTHESIS OF THE MODEL

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

include:

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

injection

RESULTS AND DISCUSSIONS

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

(Kx=Ky=10Kz).

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

GOR SCDF/STB 2400

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

186 EVALUATION OF DIFFERENT EFFECTIVE PARAMETERS BIOSCIENCE BIOTECHNOLOGY RESEARCH COMMUNICATIONS

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.,

2016).

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

recovery.

FIGURE 2. Effect of different CO

injection

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-

BIOSCIENCE BIOTECHNOLOGY RESEARCH COMMUNICATIONS EVALUATION OF DIFFERENT EFFECTIVE PARAMETERS 187

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

 ooding

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

188 EVALUATION OF DIFFERENT EFFECTIVE PARAMETERS BIOSCIENCE BIOTECHNOLOGY RESEARCH COMMUNICATIONS

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).

CONCLUSIONS

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

 ooding.

ACKNOWLEDGMENT

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

scenario

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

BIOSCIENCE BIOTECHNOLOGY RESEARCH COMMUNICATIONS EVALUATION OF DIFFERENT EFFECTIVE PARAMETERS 189

Zohreh Rezaei Kavanrudi et al.

Azad University, Firoozabad, Iran for the provision of

the laboratory facilities necessary for completing this

work.

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