Parameter optimization of gas alternative water for CO2 flooding in low permeabilityhydrocarbon reservoirsPengcheng Liu, Xiaokun Zhang, Mingqiang Hao, Jiaqi Liu, and Zhe Yuan Citation: Journal of Renewable and Sustainable Energy 8, 035901 (2016); doi: 10.1063/1.4948483 View online: http://dx.doi.org/10.1063/1.4948483 View Table of Contents: http://scitation.aip.org/content/aip/journal/jrse/8/3?ver=pdfcov Published by the AIP Publishing Articles you may be interested in Particle-based simulation of hydraulic fracture and fluid/heat flow in geothermal reservoirs AIP Conf. Proc. 1542, 177 (2013); 10.1063/1.4811896 Magnetic resonance imaging study on near miscible supercritical CO2 flooding in porous media Phys. Fluids 25, 053301 (2013); 10.1063/1.4803663 Gas flow behavior in extremely low permeability rock AIP Conf. Proc. 1453, 251 (2012); 10.1063/1.4711184 Development of System and Method for Serial Measurement of Phase Permeability of Sandstone Core SamplesDuring Filtering of Water, Oil and Gas AIP Conf. Proc. 914, 275 (2007); 10.1063/1.2747442 Vibrate ‐Seismic Waves Can Change Oil‐Gas Reservoir State AIP Conf. Proc. 838, 157 (2006); 10.1063/1.2210339

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Parameter optimization of gas alternative water for CO2

flooding in low permeability hydrocarbon reservoirs

Pengcheng Liu,1,a) Xiaokun Zhang,1 Mingqiang Hao,2 Jiaqi Liu,1 andZhe Yuan1

1School of Energy Resources, China University of Geosciences, Beijing 100083, China2Research Institute of Petroleum Exploration and Development, PetroChina,Beijing 100082, China

(Received 4 December 2015; accepted 18 April 2016; published online 4 May 2016)

The parameters influencing gas alternative water (WAG) for CO2 flooding in the

low permeability block of the Jilin oil fields in China were investigated using the

numerical simulation software, Eclipse. The minimum miscibility pressure was

first determined based on slim tube tests. Comparisons were made between

continuous water flooding, continuous CO2 flooding, and WAG flooding methods.

The oil recovery ratio of “gas injection first method” was higher than that of “water

injection first method” and the mechanism of CO2 displacement was analyzed. The

optimum parameters for WAG flooding were 7 for the number of slugs, 0.3845 PV

for the total injection volume, approximately 0.5742 for the gas/water slug ratio,

and 120 days for the stewing time. The optimum injection timing of the switching

depletion development to the WAG injection was 0.25 years and the earlier

switching to the WAG injection after water flooding was more suitable for

enhanced oil recovery. The maximal cumulative water injection by water flooding

or by WAG flooding yielded the highest oil recovery ratio for homogeneous

reservoir. The results do not only play a very important role in optimizing different

development schemes but also provide theoretical basis for CO2 flooding in low

permeability hydrocarbon reservoirs. Published by AIP Publishing.

I. INTRODUCTION

The relationship between energy consumption, carbon dioxide (CO2) emissions, and global

warming has been increasingly investigated by many academic institutions.1,2 Meanwhile, CO2-

Enhanced Oil Recovery (CO2-EOR) has been in continuous operation and expansion in the oil

fields worldwide.3 A large number of CO2 emissions can bridge the gap between CO2 supply

and demand, and accordingly protect the environment against pollution.4 Both laboratory stud-

ies and field applications established that CO2 can be an efficient oil-displacing agent.5 If CO2

is introduced into a water flooded reservoir, it can substantially increase the oil recovery.6

Now, the CO2-EOR is widely accepted as a potential target and is considered as an effective

technique for EOR in oilfields.7–12

Since its first commercial application in the 1950s,7,13 CO2 flooding has been used as a

commercial process for EOR for several decades and is the second most applied EOR process

in both miscible and immiscible flooding in the world.14–17 More than 80% of the CO2 used for

EOR in the U.S. came from underground natural CO2 reservoirs.18 Through 2010, about 105

CO2 flooding projects exist in the U.S., providing nearly 250 000 barrels of oil per day by

injecting around 50 � 106 tons of CO2 per year. Over 1.3 � 109 barrels of oil were recovered,

and 1 � 109 barrels of proven reserves remain to be extracted.5,19 CO2 injection technology in

oil fields does not only play a key role to meet the energy demand in the coming years but is

also considered as a favorable option to reduce the accumulation of atmospheric CO2 and thus

a)Author to whom correspondence should be addressed. Electronic mail: pengchengliupcl@126.com. Tel.: þ8613522168398.

1941-7012/2016/8(3)/035901/12/$30.00 Published by AIP Publishing.1

JOURNAL OF RENEWABLE AND SUSTAINABLE ENERGY 8, 035901 (2016)

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mitigate greenhouse effects on climate.9 As a result, CO2 flooding projects have increased rap-

idly in China and worldwide.

Generally speaking, crude oil is produced using natural energy in the early stages of oil

field development. As the reservoir pressure rapidly drops, the oil recovery becomes very low.

Later, water flooding is implemented to supply the reservoir energy, which has higher oil-

recovery efficiency in medium- or high-permeability reservoirs.20,21 However, in low permeabil-

ity reservoirs, strong heterogeneity and numerous artificial and natural cracks exist, as well as

great differences in oil and water density and viscosity, which result in many developmental

problems such as water fingering, override, and channeling. Meanwhile, due to the presence of

capillary pressure and starting pressure gradient, it is extremely difficult to inject water, which

makes the reservoir energy difficult to supplement.4,22 CO2 is easily injected and reservoir

energy can be quickly replenished thereby making the oil recovery of CO2 flooding higher than

that of water flooding.23,24

Many studies showed that CO2 flooding is more suitable for low permeability hydrocarbon

reservoirs. Compared with general hydrocarbon gas, CO2 is easier to dissolve in water and its

solubility in oil is higher than in water. CO2 can reach the critical state faster. When tempera-

ture and pressure exceed 31.26 �C and 7.2 MPa, respectively, CO2 reaches the critical state and

becomes liquid-like density, gas-like viscosity, and high power diffusivity. Therefore, it has an

amazing dissolving ability and can be used to dissolve various substances. It is widely accepted

as the potential use of standard materials for the CO2-EOR.25,26 Consequently, it can reduce the

oil/water interfacial tension, decrease the viscosity of crude oil, extract or vaporize oil, cause

volume expansion, and then increase the oil displacement efficiency. This depends on the misci-

ble or immiscible CO2 flooding.27 At the same saturation, CO2 dissolves in oil easier than

CH4.28,29 The mechanisms of CO2 flooding include solution gas drive, immiscible CO2 drive,

hydrocarbon vaporization, direct miscible CO2 drive, and multiple-contact dynamic miscible

drive.30,31 In fact, the super-critical CO2 has the gas-like viscosity and thus leads to an unfavor-

able mobility ratio for the oil displacement. Viscosification of the injected gas phase by foam-

ing or nano-particle materials used could decrease the mobility of the injected gas and greatly

reduce the gas phase relative permeability; thereby, these can inhibit the gas onrush and expand

the volumetric displacement efficiency.32–34

There are two major types in CO2 flooding: continuous CO2 flooding and gas (CO2) alter-

native water (WAG) flooding. Both methods have their merits and demerits.4,29,31–37 The con-

tinuous CO2 flooding is not a foolproof and often displays high gas mobility, inadequate injec-

tivity, and/or poor sweep efficiency owing to CO2 fingering and gravity override in the vertical

and areal directions.38,39 In order to control the CO2 mobility and reduce its defects, WAG

flooding, as a method to improve sweep efficiency, has proved to be a sound flooding tech-

nique, which can reduce gravity segregation between water and CO2, stabilize the flooding

front, and delay the breakthrough time of water and gas, then enhance oil displacement effi-

ciency in the vertical direction.40 Many researchers reported this phenomenon.41–44

In the process of WAG, the size of the injection slugs and the number of the half cycle are

the major factors influencing the development results.24,45,46 However, previous researches

mainly focused on a simple experimental or simulation evaluation of WAG flooding. Few liter-

atures focused on the parameter optimization or the quantificational evaluation of WAG flood-

ing in low-permeability reservoirs. Some investigators have promoted that the smaller the cycle,

the better the development results, and the WAG ratios from 1:1 to 2:1 is recommended.45 In

fact, different geologic characteristics and different physical fluid properties decide different

half-cycle numbers and WAG ratios. Many prerequisites could be deeply considered, and a

number of injection parameters need to be optimized.46

In order to determine the technical feasibility of CO2 flooding in the low-permeability

block in Jilin oil fields, China, this paper compared water flooding and continuous CO2 flooding

with WAG flooding using a three-dimensional, three-phase compositional model by phase

matching based on its geologic characteristic and physical fluid property. The overall research

objective for this paper was to screen, optimize, and evaluate the different influencing factors

on oil recovery ratios of different flooding styles using the numerical simulation software

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Eclipse. The results do not only play a very important role in improving the reservoir sweep ef-

ficiency and reservoir performance in CO2 flooding applications but also provide theoretical ba-

sis for field implementation, to design and conduct CO2 flooding in low permeability hydrocar-

bon reservoirs.

II. IDEALIZED RESERVOIR DESCRIPTION

In 1992, water flooding was initiated in the block of Jilin oil fields in China which is a typ-

ical low permeability reservoir (initial pressure: 25.0 MPa; initial temperature: 98 �C; mean per-

meability: 10� 10�3 lm2). In 2005, some injector wells were shut down because of water cut

reaching the maximal economic limit. The oil recovery by water flooding was only 11.7% of

the original oil in place (OOIP). The estimated current mean reservoir pressure was 23.5 MPa

by well testing. There are rich CO2 resources in the Jilin oil field, which provides convenient

conditions for CO2 flooding. Since 2006, CO2 flooding pilot test has been conducted and

expanded to rigorously study the effective development technique in the low permeability

hydrocarbon reservoir and assess its commercial efficiency.

A. Fundamental assumptions

The temperature and pressure of a reservoir and the composition of its crude oil are the

main effects on CO2 flooding. To simplify, and in order to clearly document the influences of

displacement mechanisms, the reservoir conditions used in generating the base case model are

listed below. Some of these assumptions such as well spacing, well pattern, and other simula-

tion parameters are based on a commonly observed practice while others are to reduce

complexity.47

A quarter of an inverted 9-spot well pattern is commonly used with water flooding. The

hydrocarbon reservoir has three layers with different permeabilities. Each layer is homogeneous

and has equal thickness, which is penetrated completely by both wells and with vertical com-

munication. The fluids are oil, water, and CO2 with no aquifer support.

The grid blocks describing the X, Y, and Z directions are 44� 44� 3 and describe an area

of dimensions 220 m� 220 m� 20 m. The injector was placed in cell (1, 1) and the producer

was placed in cell (44, 44) with both perforated in all grid blocks in the vertical (Z) direction

to ensure direct contact with the entire thickness of the reservoir. Both wells are controlled by

the assigned liquid rates and/or bottom hole-pressure limits.

The above unit was selected for simulation and prediction by the compositional model of

the Eclipse software (E300), in which the fully implicit solution method was used in the simu-

lator to solve the governing equations.

B. Input parameters

Table I lists the input parameters of the reservoir rock and fluid properties in the numerical

simulation according to the data from the Jilin oilfield block in China.

Table II lists the compositional model construction (pseudo-components description of

crude oil). Although the ideal model used in the paper and the results obtained may be of nota-

ble difference compared with the actual situations, the conclusions drawn on the development

laws would also have important significance in field application.

C. Determine of minimum miscibility pressure (MMP)

The determination of minimum miscibility pressure (MMP) is one of the important

research contents, which determines the mechanism of CO2 flooding (miscible or immiscible

flooding), as well as affects the displacement efficiency. The determination of MMP takes a

long period of time although gas injection technology has been in use for long. Stalkup47 pro-

posed the method of the slim tube test which is widely recognized as the standard method of

determining MMP and minimum miscible composition.35,48–50 Compared with the theoretical

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calculation method, the experimental method is more accurate. However, its disadvantage is

that it takes long time, as well as higher cost to obtain an accurate data.

Fig. 1 shows the relationship between oil recovery factor and displacement pressure of six

experimental pressures in the slim tube test. The intersection of the two dashed lines gives the

minimum miscibility pressure as 22.80 MPa, which can achieve miscible flooding with CO2 in

the current mean reservoir pressure (23.5 MPa).

Meanwhile, the reservoir temperature (98 �C) and the current mean reservoir pressure (23.5

MPa) have reached the CO2 critical conditions (31.26 �C and 7.2 MPa), and CO2 can reach the

critical state.

III. RESULTS AND DISCUSSION

A. Optimization of different displacement patterns

To compare the continuous water flooding and continuous CO2 flooding with WAG flood-

ing, the oil recovery ratio of the three displacement methods must be defined. For WAG flood-

ing, the CO2 is first injected which has an injection timing of 180 days, and then switched to

TABLE I. Parameters of reservoir and fluid properties.

Reservoir property Fluid property

Effective porosity 0.12 Initial oil saturation 0.70

Depth to top of reservoir 2500 m Initial temperature 98 �C

Initial pressure 25.0 MPa Viscosity of degassed crude oil 2.1 mPa s (98 �C)

Current mean pressure 23.5 MPa Density 0.812 g/cm3 (20 �C)

Total reservoir thickness 5.0 m Gas-oil ratio (GOR) 31.4 m3/m3

Saturation pressure 9.43 MPa Mean permeability 10� 10�3 lm2

TABLE II. Pseudo-components description of crude oil.

Component Mole fraction (%) Component Mole fraction (%)

CO2 0.00 C5 to C14 27.18

C1 16.69 C15 to C30 27.52

C2 to C4 12.18 C31þ 16.43

FIG. 1. The relationship between oil recovery factors and displacement pressure in slim tube test.

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water injection which has an injection timing of 185 days. For the three flooding methods, the

maximum water cut was recorded as 98% and the gas-oil ratio (GOR) was 5000 m3/m3 in all

oil wells. Table III lists the oil recovery ratios by different injection patterns. From the table,

the result of the WAG injection is the best among the three flooding methods. The oil recovery

ratio of WAG injection is the highest when the gas injection velocity is 10 000 m3/d.

Generally, WAG flooding has two ways, one is injecting water followed by gas injection

and another is injecting gas followed by water injection. The simulated results of the two dis-

placement methods at different gas injection velocities are listed in Table IV. From the table,

the oil recovery ratio of the “gas injection first” is higher than that of the “water injection first.”

The oil recovery ratios of the two methods increase with the increasing injection velocity.

According to the mechanism of CO2 displacement, injecting CO2 first improves the oil vis-

cosity by reducing its viscosity because CO2 and oil have enough contact time. On the contrary,

when the water is first injected, the water limits the contact of the oil and gas, and decreases

the displacement efficiency. The simulation research shows that by injecting the gas earlier, the

displacement efficiency is higher. The earlier injection timing will result in the higher oil satu-

ration, which can increase the oil volume to contact the CO2.

B. Optimization of water and gas slugs

According to the above result, the gas is first injected which has an injection timing of 180

days, and then switched to water injection, whose injection timing is also 180 days. The results

of the different number of slugs are listed in Table V.

From Table V, the oil recovery ratios and the utility ratio (or called oil-draining ratio) are

increasing with the increasing number of slugs. The utility ratio refers to the ratio of the vol-

ume of cumulative injected gas to the volume of the cumulative oil production. The oil recov-

ery ratio differences slow down after the number of slugs exceeds 7. At this time, the total

injection volume is 0.3845 PV. After 14 cycles of slugs, all the wells are shut down until the

GOR of every oil well exceeds 5000 m3/m3.

If the number of injection slugs is 7, the injection velocity and the time of injected gas are

kept constant. The results of changing the time of water injection are listed in Table VI. From

TABLE III. Oil recovery ratio by different injection patterns.

Displacement patterns Water injection velocity (m3/d) Oil recovery ratio (%)

Natural energy … 20.32

Water injection … 47.73

Gas injection 50 000 64.63

20 000 61.22

10 000 58.20

5000 56.93

WAG injection 50 000 77.45

20 000 80.60

10 000 81.70

5000 78.84

TABLE IV. Comparison of two injection methods.

Displacement patterns

Gas injection velocity (m3/d)

50 000 20 000 10 000 5000

Gas injection first Oil recovery (%) 77.45 80.60 81.70 78.84

Water injection first 73.35 78.61 80.10 77.56

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the table, when the time of water injection is 150 days, the oil recovery ratio is the highest

(77.21%), which represents the gas and water slug ratio of about 0.5742.

C. Optimization of different injection timing

Different injection timing (refers to the injection time after depletion development) can

have different development results for the WAG injection. Two cases were studied by the nu-

merical simulation. Case-1 represented “depletion development first and then WAG injection.”

Case-2 represented “injection water first and then WAG injection.”

For case-1, six injection timings were researched (WAG injection were switched at 0.00,

0.25, 0.50, 1.00, 2.00, 4.00 years after depletion development). The oil recovery ratios for dif-

ferent injection timings after depletion development are shown in Fig. 2.

As shown in Fig. 2, when the injection timing was less than 0.25 years the oil recovery ra-

tio increased with the increasing injection timing. When the injection timing was above 0.25

years, the oil recovery ratio decreased rapidly with delaying injection timing. To sum up, the

optimum injection timing of switching depletion development to WAG injection is 0.25 years

for case-1.

For case-2, similarly, six injection timings were also researched (WAG injection were

switched at 0.00, 1.00, 2.00, 3.00, 5.00, 8.00 years after depletion development). The oil recov-

ery ratios for different injection timings after depletion development are shown in Fig. 3.

As shown in Fig. 3, when the injection timing was less than 2.00 years the oil recovery ra-

tio decreased with the increasing injection timing. When the injection timing was above 2.00

years, the oil recovery ratio increased slightly with the increasing injection timing. At higher

oil saturation, critical oil saturation is required to reach miscible conditions, and then oil dis-

placement efficiency can be optimized and a higher oil recovery can be obtained. To sum up,

TABLE V. Optimization of the number of slug.

Number of slugs Injection volume (PV) Oil recovery (%) Oil recovery difference (%) Utility ratio (m3/m3)

1 0.0519 53.26 … 47.98

2 0.1039 58.73 5.47 87.02

3 0.1558 68.02 9.29 112.70

4 0.2077 72.30 4.28 141.37

5 0.2597 74.47 2.17 171.56

6 0.3116 75.86 1.40 202.09

7 0.8745 77.05 1.18 232.15

8 0.4154 77.99 0.94 262.12

9 0.4674 78.81 0.83 291.79

10 0.5193 79.64 0.83 320.84

14 0.7270 81.70 2.06 437.86

TABLE VI. Optimization of the slug ratio.

Water injection timing (d) Oil recovery (%) Gas and water slug ratio

90 77.135 0.7511

120 77.155 0.6480

140 77.205 0.5980

150 77.207 0.5742

160 77.193 0.5511

185 77.049 0.5024

365 76.531 0.3112

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for case-2, the earlier switching to WAG injection after water flooding is more suitable for an

enhanced oil recovery.

The stewing time is defined as the time interval between the water injection and the WAG

injection. The different stewing time has a complicated influence on the result of the WAG

injection. In the numerical simulation, the time duration of the water injection is 8 years, the

water cut reaches 97.02%, and then all the wells are shut down.

After some stewing time interval was designed as (0, 10, 20, 30, 60, 90, 100, 110, 120,

130, 150, 180 days), the water injection is switched to the CO2 injection. The oil recovery

ratios of the different stewing times after water flooding are shown in Fig. 4.

As shown in Fig. 4, when the stewing time was less than 100 days the oil recovery ratio

decreased with the increasing stewing time. When the injection timing was above 100 days, the

oil recovery ratio increased sharply with increasing stewing time, and then it reached the maxi-

mum value when the stewing time was 120 days.

D. Optimization of different reservoirs by water or WAG flooding

There are five layers in different low-permeability hydrocarbon reservoirs by water flooding

or WAG flooding. The characteristic parameters of the five layers in numerical simulation are

listed in Table VII. The first, second, and third styles are, respectively, the homogeneous, posi-

tive, and inverted rhythm low-permeability reservoirs. The numerical simulation results by

water flooding and WAG flooding are listed in the table.

FIG. 2. Oil recovery ratio in different injection timings after depletion development.

FIG. 3. Oil recovery ratio for different injection timings after water flooding.

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As shown in Table VII, for water flooding, the simulated well group included five wells:

four production wells and one injection well. The production wells initially extracted oil at a

constant production rate, and then worked in a fixed bottom hole- pressure when the production

rate cannot be satisfied. The injection well initially injected water at a constant rate, and then

worked in a fixed bottom hole-pressure when the injection rate cannot be satisfied. The maxi-

mum water cut was recorded as 98% for all the production wells. For WAG flooding, CO2

slugs were initially injected at the rate of 10 000 m3/d and the injection timing was 180 days,

and then the water slugs were switched at the injection timing of 180 days, the injection slug

number was 7, and the total injection volume was 0.3845 PV. After an alternative flooding,

continuous water flooding continued until the production performance indicators reached the

above limits.

As shown in Table VIII, for water flooding, the highest oil recovery ratio and the longest

the production time were obtained which indicate the best oil displacement efficiency for the

homogeneous reservoir. The worst oil displacement efficiency was obtained for the positive

rhythm reservoir where the lowest oil recovery ratio and the shortest production time were real-

ized. The inverted rhythm reservoir lies between these two extremes. However, for WAG flood-

ing, the highest oil recovery ratio and the longest production time obtained were still the

FIG. 4. The relationship between recovery ratio and stew well time after water flooding.

TABLE VII. Characteristic parameters of the five layers.

Reservoir types Layers Kx (�10�3 lm2) Ky (�10�3 lm2) Kz (�10�3 lm2)

Homogeneous ‹ 10.0 10.0 1.0

› 10.0 10.0 1.0

fi 10.0 10.0 1.0

fl 10.0 10.0 1.0

� 10.0 10.0 1.0

Positive rhythm ‹ 2.5 2.5 1.0

› 5.0 5.0 1.0

fi 10.0 10.0 1.0

fl 20.0 20.0 1.0

� 40.0 40.0 1.0

Inverted rhythm ‹ 40.0 40.0 1.0

› 20.0 20.0 1.0

fi 10.0 10.0 1.0

fl 5.0 5.0 1.0

� 2.5 2.5 1.0

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homogeneous reservoir. The worst oil displacement efficiency was the inverted rhythm reservoir

where the lowest oil recovery ratio and the shortest production time were realized. The positive

rhythm reservoir lies between these two extremes.

The comparisons of the oil recovery ratio and water cut by water flooding in the different

type reservoirs are shown in Figs. 5 and 6. From these figures, the oil recovery ratios of the

positive rhythm and inverted rhythm reservoirs are higher in the early stage, as well as lower in

the later stage than those of the homogeneous reservoir. The water cut of the positive rhythm

and inverted rhythm hydrocarbon reservoirs were higher than those of the homogeneous hydro-

carbon reservoir. The water-free oil production period is longest in the homogeneous

TABLE VIII. Comparison of production performance in different reservoir types by water flooding.

Flooding type Reservoir type Production time (a) Recovery ratio (%) Cumulative water injection (104 m3)

Water flooding Homogeneous 10.156 47.73 11.54

Positive rhythm 7.807 45.28 13.75

Inverted rhythm 8.000 45.96 13.48

WAG flooding Homogeneous 12.055 76.15 16.49

Positive rhythm 8.640 65.84 15.98

Inverted rhythm 6.545 58.56 9.67

FIG. 5. Comparison of oil recovery ratio in the different reservoir types by water flooding.

FIG. 6. Comparison of water cut in the different reservoir types by water flooding.

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hydrocarbon reservoir, while the difference between positive rhythm reservoir and inverted

rhythm reservoir is negligible.

The comparisons of the oil recovery ratio and water cut by WAG flooding in the different

types reservoirs are shown in Figs. 7 and 8. From these figures, the oil recovery ratio of the ho-

mogeneous reservoirs is the highest with the lowest water cut and the longest water-free pro-

duction period among the three reservoir types. The oil recovery ratio of the inverted rhythm

hydrocarbon reservoir is the lowest.

Note, however, that the parameter optimization of WAG flooding is required to maximize

the oil recovery ratio from a specific low permeability hydrocarbon reservoir, and different res-

ervoirs behave differently.

IV. CONCLUSIONS

The following conclusions may be drawn based on the discussion above:

(1) Based on the slim tube tests, the minimum miscibility pressure (MMP) was determined, which

can achieve the miscible flooding in the initial formation pressure.

(2) The results of the WAG injection were the best among the three flooding methods, namely,

the continuous water flooding, continuous CO2 flooding, and WAG flooding.

FIG. 7. Comparison of oil recovery rate in the different reservoir types by WAG flooding.

FIG. 8. Comparison of water cut in the different reservoir types by WAG flooding.

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(3) For the two WAG flooding methods, the oil recovery ratios were both increasing with the

increasing injection velocity. The oil recovery ratio of the “gas injection first” was higher than

that of the “water injection first” and the mechanism of the CO2 displacement was that CO2

and oil had good contact, which could decrease the oil viscosity and improve the viscosity.

(4) The optimum slugs of WAG flooding were 7, the total injection volume was 0.3845 PV, gas/

water slug ratio was about 0.5742, and the stewing time was120 days.

(5) The optimum injection timing for switching depletion development to WAG injection was

0.25 years for the case of “depletion development first followed by WAG injection.” The ear-

lier switching to WAG injection after water flooding was more suitable for the enhanced oil

recovery for the case of “injection water first and followed by WAG injection.”

(6) For both water flooding and WAG flooding, the highest oil recovery ratio and the longest pro-

duction time were obtained, which indicate the best oil displacement efficiency for the homo-

geneous hydrocarbon reservoir.

ACKNOWLEDGMENTS

This research is dedicated to the Science and Technology Special Funds of China

(2016ZX05016 and 2016ZX05015.) for their financial supports. The authors would like to thank

Professor Yongle Hu of Research Institute of Petroleum Exploration and Development, CNPC for

his assistance and advice. We also thank Dr. Adenutsi, Caspar Daniel for his grammar correction

and clarity during the manuscript’s preparation.

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