Upload
others
View
7
Download
0
Embed Size (px)
Citation preview
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
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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: [email protected]. 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)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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
035901-2 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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
035901-3 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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.
035901-4 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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
035901-5 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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
035901-6 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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.
035901-7 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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
035901-8 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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.
035901-9 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
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.
035901-10 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
(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.
1K. Farhat, “CO2 interim storage as a tool for CO2 market development: A comprehensive technical assessment,” Ph.D.dissertation, Stanford University, 2011, pp. 1–2.
2C. Yuan and V. V. Leonardo, “An efficient Bayesian formulation to history match and uncertainty assessment,” paperpresented (poster) at the SPE Workshop, History Matching: Improving Reservoir Management, Galveston, Texas, 2009.
3R. J. Watts, J. B. Gehr, and J. A. Wasson et al., “A single CO2 injection well mini test in a low-permeability carbonatereservoir,” J. Pet. Technol. 34(08), 1781–1788 (1982).
4P. Liu and X. Zhang, “Enhanced oil recovery by CO2–CH4 flooding in low permeability and rhythmic hydrocarbon reser-voir,” Int. J. Hydrogen Energy 40(37), 12849–12853 (2015).
5V. Alvarado and E. Manrique, “Enhanced oil recovery: An update review,” Energies 3(9), 1529–1575 (2010).6M. K. Roper, Jr., G. A. Pope, and K. Sepehrnoori, “Analysis of tertiary injectivity of carbon dioxide,” in Permian BasinOil and Gas Recovery Conference, 1992, Paper No. SPE23974-MS.
7C. P. Bardon, D. Karaoguz, and M. Tholance, “Well stimulation by CO2 in the heavy oil field of Camurlu in Turkey,” inSPE Enhanced Oil Recovery Symposium, 1986, Paper No. SPE/DOE14943-MS.
8N. Mungan, “An evaluation of carbon dioxide flooding,” in SPE Western Regional Meeting, 1991, Paper No. SPE-21762-MS.
9J. Bradshaw and P. Cook, “Geological sequestration of carbon dioxide,” Environ. Geosci. 8(3), 149–151 (2001).10S. Zheng, H. Li, and D. Yang, “Pressure maintenance and improving oil recovery with immiscible CO2 injection in thin
heavy oil reservoirs,” J. Pet. Sci. Eng. 112, 139–152 (2013).11H. Li and D. Yang, “Determination of individual diffusion coefficients of solvent-CO2 mixture in heavy oil using
pressure-decay method,” SPE J. 21, 131–143 (2015).12C. Yuan, Z. Zhang, and K. Liu, “Assessment of the recovery and front contrast of CO2 EOR and sequestration in a new
gas condensate reservoir by compositional simulation and seismic modeling,” Fuel 142, 81–86 (2015).13J. T. Patton, P. Sigmund, and B. Evans et al., “Design of a CO2 stimulation process for heavy oil reservoirs,” in SPE
Regional Meeting, Pasadena, 1980, Paper No. SPE 08897-MS.14A. L. Bunge and C. J. Radke, “CO2 flooding strategy in a communicating layered reservoir,” J. Pet. Technol. 34(12),
2746–2756 (1982).15J. B. Desch, W. K. Larsen, and R. F. Lindsay et al., “Enhanced oil recovery by CO2 miscible displacement in the Little
Knife field, Billings County, North Dakota,” J. Pet. Technol. 36(10), 1592–1602 (1984).16P. A. Jeschke, L. Schoeling, and J. Hemmings, “CO2 flood potential of California oil reservoirs and possible CO2
sources,” in SPE Annual Technical Conference and Exhibition, 2000, Paper No. SPE63305-MS.17P. M. Jarrell, Practical Aspects of CO2 Flooding (Henry L. Doherty Memorial Fund of AIME, Society of Petroleum
Engineers, Richardson, Texas, 2002).18M. Tanner, “Projecting the scale of the pipeline network for CO2-EOR and its implications for CCS infrastructure devel-
opment,” U.S. Energy Information Administration, Office of Petroleum, Gas & Bio-Fuels Analysis, 2010.19ARI, “Oil production potential from accelerated deployment of carbon capture and storage,” Advanced Resources
International, Arlington, VA, USA, 2010.20L. B. Gu, Z. P. Li, and J. Qu, “The existing state of enhanced oil recovery by utilizing carbon dioxide,” China Min. Mag.
16(10), 66–69 (2007).21B. Z. Li, X. F. Li, and K. Sepehrnoori et al., “Optimization of the injection and production schemes during CO2 flooding
for tight reservoir,” J. Southwest Pet. Univ. 2(23), 101–107 (2010).22P. Liu, Y. Wu, and X. Li, “Experimental study on the stability of the foamy oil in developing heavy oil reservoirs,” Fuel
111, 12–19 (2013).
035901-11 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04
23C. F. Du, P. C. Wu, and C. G. Shao, “Laboratory study on EOR by CO2 in extra-low permeability reservoirs, Changqingoilfield,” Pet. Geol. Recovery Effic. 117(4), 63–64 (2010).
24Y. F. He, H. M. Gao, and X. S. Zhou, “Study on method for improving displacement effect of CO2 drive in extra-low per-meability reservoir,” Fault-Block Oil Gas Field 18(4), 512–515 (2011).
25T. Holt, J. I. Jensen, and E. Lindeberg, “Underground storage of CO2 in aquifers and oil reservoirs,” Energy Convers.Manage. 36(6), 535–538 (1995).
26H. Li, S. Zheng, and D. T. Yang, “Enhanced swelling effect and viscosity reduction of solvent(s)/CO2/heavy-oil sys-tems,” SPE J. 18(4), 695–707 (2013).
27K. K. Dai and F. M. Orr, Jr., “Prediction of CO2 flood performance: Interaction of phase behavior with microscopic porestructure heterogeneity,” SPE Reservoir Eng. 2(04), 531–542 (1987).
28R. L. Christiansen and H. K. Haines, “Rapid measurement of minimum miscibility pressure with the rising-bubble appa-ratus,” SPE Reservoir Eng. 2(4), 523–527 (1987).
29P. Guo, S. L. Li, and Z. M. Du, “Evaluation on IOR by gas injection in low permeability oil reservoir,” J. Southwest Pet.Inst. 24(5), 46–50 (2002).
30L. W. Holm and V. A. Josendal, “Mechanisms of oil displacement by carbon dioxide,” J. Pet. Technol. 26(12),1427–1438 (1974).
31W. A. Flanders, W. A. Stanberry, and M. Martinez, “CO2 injection increases Hansford Marmaton production,” J. Pet.Technol. 42(1), 68–73 (1990).
32G. Cheraghian and L. Hendraningrat, “A review on applications of nanotechnology in the enhanced oil recovery part B:Effects of nanoparticles on flooding,” Int. Nano Lett. 6, 1–10 (2015).
33D. Denney, “Success of SAG foam processes in heterogeneous reservoirs,” J. Pet. Technol. 60(1), 43–46 (2008).34W. R. Rossen and C. J. Van Duijn, “Gravity segregation in steady-state horizontal flow in homogeneous reservoirs,”
J. Pet. Sci. Eng. 43(1), 99–111 (2004).35F. B. Thomas, X. L. Zhou, and D. B. Bennion et al., “A comparative study of RBA, Px, multi contact and slim tube
results,” J. Can. Pet. Technol. 33(2), 17–26 (1994).36R. B. Grigg and U. W. Siagian, “Understanding and exploiting four-phase flow in low-temperature CO2 floods,” in SPE
Permian Basin Oil and Gas Recovery Conference, 1998, Paper No. SPE39790-MS.37C. Yuan and G. A. Pope, “A new method to model relative permeability in compositional simulators to avoid discontinu-
ous changes caused by phase identification problems,” SPE J. 17(4), 1221–1230 (2011).38Z. W. Zeng, B. Bai, and Y. Liu et al., “Improving CO2 efficiency for recovering oil in heterogeneous reservoirs,” Report
No. DE-FG26-01BC15364, New Mexico Petroleum Recovery Research Center, New Mexico Institute of Mining andTechnology, 2005.
39D. Novosel, “Initial results of WAG CO2 IOR pilot project implementation in Croatia,” in SPE International ImprovedOil Recovery Conference, 2005, Paper No. SPE97639-MS.
40M. Sohrabi, D. H. Tehrani, A. Danesh, and G. D. Henderson, “Visualisation of oil recovery by water alternating gas(WAG) injection using high pressure micromodels-oil-wet & mixed-wet systems,” in SPE Annual Technical Conferenceand Exhibition, 2001, Paper No. SPE71494-MS.
41T. G. Monger and J. M. Coma, “A laboratory and field evaluation of the CO2 Huff ’n’ Puff process for light-oil recovery,”SPE Reservoir Eng. 3(4), 1168–1176 (1988).
42J. D. Rogers and R. B. Grigg, “A literature analysis of the WAG injectivity abnormalities in the CO2 process,” in SPE/DOE Improved Oil Recovery Symposium, 2000, Paper No. SPE59329-MS.
43M. D. Murray, S. M. Frailey, and A. S. Lawal, “New approach to CO2 flood: Soak alternating gas,” in SPE PermianBasin Oil and Gas Recovery Conference, 2001, Paper No. SPE70023-MS.
44E. M. Winter and P. D. Bergman, “Availability of depleted oil and gas reservoirs for disposal of carbon dioxide in theUnited States,” Energy Convers. Manage. 34(9), 1177–1187 (1993).
45V. Attanucci, K. S. Aslesen, and K. A. Hejl et al., “WAG process optimization in the rangely CO2 miscible flood,” inSPE Annual Technical Conference and Exhibition, 1993, Paper No. SPE26622-MS.
46T. Okeke and R. H. Lane, “Simulation and economic screening of improved-conformance oil recovery by polymer flood-ing and a thermally activated deep diverting gel,” in SPE Western Regional Meeting, 2012, Paper No. SPE153740-MS.
47F. I. Stalkup, “Displacement behavior of the condensing/vaporizing gas drives process,” in SPE Annual TechnicalConference and Exhibition, 1987, Paper No. SPE16715-MS.
48G. R. Jerauld, “A case study in scaleup for multi-contact miscible hydrocarbon gas injection,” in SPE/DOE Improved OilRecovery Symposium, 1998, Paper No. SPE39626-MS.
49F. P. Brinkman, T. V. Kane, and R. R. McCullough et al., “Use of full-field simulation to design a miscible CO2 flood,”in SPE/DOE Improved Oil Recovery Symposium, 1998, Paper No. SPE39629-MS.
50A. Y. Zekri, R. A. Almehaideb, and S. A. Shedid, “Displacement efficiency of supercritical CO2 flooding in tight carbon-ate rocks under immiscible and miscible conditions,” in SPE Europec/EAGE Annual Conference and Exhibition, 2006,Paper No. SPE98911-MS.
035901-12 Liu et al. J. Renewable Sustainable Energy 8, 035901 (2016)
Reuse of AIP Publishing content is subject to the terms: https://publishing.aip.org/authors/rights-and-permissions. Downloaded to IP: 202.101.194.206 On: Fri, 07 Oct 2016
11:59:04