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Research Report on CO2 EOR
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COMPARISON OF CO2- EOR SIMULATION STUDIES USING CO2 – SURFACTANT CO-
INJECTION, SURFACTANT ALTERNATING CO2 GAS (SAG), AND CONTINUOUS CO2 INJECTION
IN FIELD T
Prof. Dr. Ir. HP. Septoratno Siregar, OGRINDO RC ITB, Billal Maydika Aslam, OGRINDO RC ITB
Abstract
Miscible and immiscible CO2 Flooding projects are respectively proven and potential EOR methods.
Environmental initiative such as Kyoto Protocol also encourage CO2 injection into reservoir due to potential reduction
of greenhouse gas volume. However conventional CO2 EOR methods have suffered from limited recovery efficiency
due to gravity segregation, gas override, viscous fingering and channeling through high permeability streaks.
Numerous theoretical and experimental studies as well as field applications have indicated that foaming of CO2 reduces
its mobility, thereby helping to control the above negative effects.
The objective of this study is to compare the recovery efficiency of foam methods using co-injection and
surfactant alternating CO2 gas (SAG) to conventional CO2 flooding in field-scale simulation. Simple (quasi-
equilibrium) foam model is used as incorporated in CMG-STARSTM simulator. Immiscible injection method is
preferred due to high Minimum Miscibility Pressure (MMP) and fracture pressure limitation of the selected reservoir.
The study highlight the effect of varying injection rate to oil recovery for each methods. Pattern optimization by
altering insignificant producer to injector is done as it prove higher recovery factor. Field injection parameter is also
calculated to ensure feasibility of injection in real condition. The study also suggest some aspects to increase accuracy
of the field-scale simulation.
Keywords: CO2-EOR, Foam, Co-injection, SAG, Mobility Control
Introduction
Favorable mobility ratio between oil bank and gas slug is necessary for mobilization and displacement of oil in
CO2 EOR methods. Lower mobility ratio ensure more stable displacement of slug, which prevent channeling and
segregation. Hence the purpose of foam application in CO2 EOR is to improve the control of gas mobility by altering
gas effective permeability (Fig.1). The use of foam also improve microscopic displacement efficiency by reducing
capillary forces via reducing the interfacial tensions due to the presence of surfactant.
Foam can be placed in a reservoir in four ways:
1. In co-injection, gas and aqueous surfactant solution are injected simultaneously from a single well.
Foam forms in the surface facilities where the fluids meet, in the tubing, or shortly after the fluids
enter the formation.
2. In surfactant-alternating-gas or SAG injection, gas and surfactant solution are injected in separate
slugs from a single well. Foam forms in the formation where gas meets previously injected surfactant
solution, or when surfactant solution meets previously injected gas.
3. It is possible to dissolve some surfactants directly into supercritical CO2 (Lee et al.,2008; Ashoori et
al., 2010) Then there is no need to inject aqueous surfactant solution; injected CO2 with dissolved
surfactant forms foam as it meets water in the formation.
4. Surfactant solution and gas can be injected simultaneously, but from different sections of a vertical
well (gas injected below the surfactant solution), or from parallel horizontal wells (gas injected from
the lower well) (Stone, 2004; Rossen et al., 2010).
The study will be focused on co-injection method and SAG method which are proved by laboratory experiment
to have better injectivity than preformed foam. Based on published field result, for low pressure and high permeability,
the co-injection foam is effective at normal surfactant concentration, and it can be considered for long term injection.
For high pressure and low permeability, SAG at medium or even low surfactant concentration can be considered.
For foam application to be successful, surfactant concentration used have to create ultra-low IFT so that pseudo
emulsion between oil and foam would occur (Talebian et al., 2013). Another important parameter to be considered is
Figure 1. Relative Permeability function before and after foam is added
foam quality. Based on laboratory experiment, 1:4 volume ratio of surfactant and CO2 would generate 70% - 90%
foam quality which will be suitable for foam EOR application (Brioletty et al., 2005).
Objectives
The objectives of this study are described as follows:
1. Determine and compare areal sweep efficiency (Ea), vertical sweep efficiency (Ev) and microscopic
displacement efficiency (Ed) by simulation from reservoir section
2. Determine and compare field-scale recovery factor increment of each methods from simulation
3. Optimize injection pattern based on existing producer and injector wells
4. Determine limitation of injection parameters
Reservoir Model and Properties
For better understand the effect of EOR methods, depleted brownfield reservoir model is used. Secondary
recovery mechanism (waterflood) has already applied in the field before the start of simulation. Selected reservoir
model is a four-way dip closure separated by sealing fault. The reservoir is a heterogeneous reservoir comprised of 10
rock types. The reservoir is divided into 7 sectors based on fault boundary. NCE sector will be used for simulation
study since it has the biggest reserve compared to other sectors (Fig 2). Selected reservoir model contains 2698 active
grid block with gross bulk volume of 517530000 ft3.
Figure 2. Aerial View of Reservoir Model and Reserves for each sector
From NCE sector, only middle part of the sector will be used in EOR simulation since it has the highest residual
oil. The oil saturation profile at the start of simulation shows that residual oil is collected in upper part of the reservoir
(Fig 3.)
Average reservoir properties of the selected reservoir model is given in Table 1. Minimum Miscibility Pressure
is calculated using Yellig & Metcalfe correlation. Overburden gradient of 1 psi/ft is assumed to be equal to fracture
gradient.
Table 1. Average Reservoir Properties
Properties Value
Average Porosity 21.5%
Initial Water Saturation 77.0%
Reservoir Temperature (Tres) 133.37 F
Initial reservoir pressure (Pres) 158.95 psi
Datum Depth 2403.33 ft
Thickness 57.2 ft
Bubble Pressure 704.17 psi
Permeability (avg) 82.5 mD
Oil Viscosity 1.1 cP
Oil Density 48.7 API
MMP (by Yellig & Metcalfe) 1938.06 psi
Fracture Gradient 1 psi/ft
Figure 3. Oil Saturation Distribution at Start of Simulation
EOR Method Screening
Technical criteria screening is done to check suitability of selected reservoir to CO2 EOR method. Criteria is
based on data from successful EOR project and oil recovery mechanism (Taber et al., 1997). Comparison of reservoir
and oil properties with technical criteria values is given in table 2.
Table 2. Reservoir & Oil Properties Screening to CO2 EOR Technical Criteria
Technical Criteria Field Condition Status
API oil > 22 48.7 OK
Viscosity <10 cp 1.1 cp OK
So >20% PV 58.9% OK
Depth >1800ft 2000 ft OK
Reservoir condition and oil properties passed all screening criteria. However, since initial reservoir pressure is
very low it is hardly possible to achieve miscibility condition although dissolution of CO2 in oil still happens. The
degree of CO2 solubility in oil will depend on pressure difference between average reservoir pressure and minimum
miscibility pressure.
Field Scale Simulation
Field scale simulation is done using CMG-STARSTM simulator. Corner point grid system is used for reservoir
model. Steady state (quasi-equilibrium) simple foam model is used both in co-injection method and SAG method.
Surface injection rate is varied for each method by 0.05 PV/year, 0.1 PV/year and 0.15 PV/year. Each method is
applied for 20 years, starting from 1st January 2015. Simulation constraints used in field-scale simulation is given in
table 3.
Table 3. Simulation Constraints for Field Scale
Simulation Constraints
Producer Wells
#wells 3 wells
Min. BHP 300 psi
Max. Water cut 99%
Max. Liquid Rate 500 STBD
Injector Wells
#well 8 wells
Max. BHP 1000 psi
Surface Injection Rate 0.05, 0.1, 0.15 PV/year
Basically, each cases are grouped by the method of CO2 EOR used, the definition of each case group are described
below
Case Group 1 – Continuous CO2
Conventional CO2 Flooding using pure CO2 gas, three different rates as defined before are simulated
Case Group 2 – Co-injection
Co-injection of CO2 gas and aqueous surfactant solution with 4:1 volume ratio, three different rates as
defined before are simulated.
Case Group 3 – SAG
Alternate injection between surfactant solution and gas with surfactant injected first as pad. 2 years cycle
is used to maintain small slug size as recommended by field result. Three different rates as defined before
are simulated with CO2 gas rate four times higher than surfactant rate to achieve 4:1 volume ratio.
Surfactant concentration used in simulation is given by simulator interpolation that gives the lowest IFT. For all
simulation using surfactant component, 0.000534 mole fraction of surfactant concentration is used.
Macroscopic Sweep Efficiency and Microscopic Displacement Efficiency Simulation
Reservoir section in NCE middle sector is carefully selected to simulate each aspect of recovery efficiency. To
determine areal sweep efficiency, a section consist of single layer (5x5x1 grid) and a producer well is selected. Single
injector well is then added in other side of section as in 5-spot injection. Considering more homogenous properties in
smaller section and no segregation effect, displacement efficiency and vertical sweep efficiency can be considered
constant or equal to 1 so that simulation in selected section will gives areal sweep efficiency based on recovery factor.
Similar principle is used for both areal sweep and displacement efficiency simulation. For vertical sweep efficiency,
1x10x10 grid is used to simulate gravity segregation. As for displacement efficiency, 10x1x1 grid is used to give
absolute sweep efficiency as also happens in slim-tube model. Grid model of each recovery efficiency simulation is
illustrated in Fig 4.
Figure 4. Simulation grid model for areal sweep (Ea), displacement (Ed) and vertical sweep (Ev) efficiency determination
Simulation for each recovery efficiency model is done for 5 years with injection rate of 0.6 PV/year. Simulation
constraint for recovery efficiency model is given in table 4.
Table 4. Simulation Constraint for Recovery Efficiency Model
Simulation Constraints
Producer Wells
#wells 1 well
Min. BHP 100 psi
Max. Water cut 99%
Max. Liquid Rate 100 STBD
Injector Wells
#well 1 well
Max. BHP 1000 psi
Surface Injection Rate 0.6 PV/year
Field Injection Parameter
Pressure gradient between injector and producer wells is checked to ensure bottom hole pressure constraint
does not exceed fracture gradient. Front velocity based on injection rate is also calculated to ensure the front velocity
is still within the limit of field practice.
Pressure Gradient of Injector-Producer Wells.
Distance between producer and nearest injector is calculated. Bottom hole pressure difference is then divided
by wells distance to give pressure gradient. Maximum injector bottom hole pressure is determined by using maximum
pressure gradient of 1 psi/ft. The result of calculation is given in table 5.
Table 5. Maximum injector BHP Calculation
mark Producer BHP(PSI) Distance (ft)
A T-141 325 A-A' 690
B T-113 300 B-B' 921
C T-049 300 C-C' 737
mark Injector BHP(PSI) Pressure Gradient(psi/ft)
A' T-117IW 1015 A-A' 1
B' T-112IW 1221 B-B' 1
C' T-112IW 1037 C-C' 1
It can be seen from the calculation that the bottom hole pressure constraint of 1000 psi is still below the
fracture pressure limit.
Front Velocity
Front velocity is calculated by assuming reservoir condition injection rate will not exceed the surface
injection rate due to compressibility. Rough calculation of front velocity can be done using equation 1.
𝑣𝐹𝑟𝑜𝑛𝑡 =
(𝑖𝑝
)𝑟𝑎𝑡𝑖𝑜
× 𝑞𝑖𝑛𝑗𝑒𝑐𝑡𝑖𝑜𝑛
𝐴𝑟𝑒𝑠𝑒𝑟𝑣𝑜𝑖𝑟 𝑖𝑛𝑗𝑒𝑐𝑡𝑒𝑑
… (1)
Where:
𝑣𝐹𝑟𝑜𝑛𝑡 ∶ 𝑓𝑟𝑜𝑛𝑡 𝑣𝑒𝑙𝑜𝑐𝑖𝑡𝑦 (𝑓𝑡/𝑑𝑎𝑦)
𝑞𝑖𝑛𝑗𝑒𝑐𝑡𝑖𝑜𝑛 ∶ 𝑖𝑛𝑗𝑒𝑐𝑡𝑖𝑜𝑛 𝑟𝑎𝑡𝑒 (𝑐𝑢𝑓𝑡 𝑑𝑎𝑦⁄ )
(𝑖
𝑝)
𝑟𝑎𝑡𝑖𝑜
∶ 𝑖𝑛𝑗𝑒𝑐𝑡𝑜𝑟 𝑤𝑒𝑙𝑙𝑠 𝑡𝑜 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑟 𝑤𝑒𝑙𝑙𝑠 𝑛𝑢𝑚𝑏𝑒𝑟 𝑟𝑎𝑡𝑖𝑜
𝐴𝑟𝑒𝑠𝑒𝑟𝑣𝑜𝑖𝑟 𝑖𝑛𝑗𝑒𝑐𝑡𝑒𝑑 ∶ 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑟𝑒𝑠𝑒𝑟𝑣𝑜𝑖𝑟 𝑐𝑟𝑜𝑠𝑠 𝑠𝑒𝑐𝑡𝑖𝑜𝑛 𝑎𝑟𝑒𝑎 𝑝𝑒𝑟𝑝𝑒𝑛𝑑𝑖𝑐𝑢𝑙𝑎𝑟 𝑡𝑜 𝑖𝑛𝑗. 𝑓𝑙𝑜𝑤
The calculation result of front velocity using highest injection rate used in simulation study is presented in table 6.
Based on field practice, it is assumed that the front velocity should not exceed 2 ft/day.
Table 6. Front Velocity Calculation
Area 11515 Ft2
(i/p)ratio 2.67 well/well
Inj. Rate 0.15 PV/year
Vfront 1.48 ft/day
Vfront_max 2.00 ft/day
It can be seen from the calculation that injection rate of 0.15 PV/year will gives 1.48 ft/day front velocity which still
below the limit of maximum front velocity.
Injection Pattern Optimization
Initial injection pattern of middle part of NCE sector is similar to staggered direct line drive. Most of injector
wells are located in bottom part of the reservoir which is not favorable for gas injection. The injection pattern is then
changed into peripheral pattern by altering insignificant producer well into injector well. Initial and edited well pattern
is illustrated in fig 5. and fig 6.
The use of edited well pattern increase field recovery factor up to 2%. Another benefit of using more injector well and
less producer well as in edited pattern is reducing front velocity and also lower well injection rate.
Result and Discussion
Macroscopic Sweep and Microscopic Displacement Efficiency
Recovery factor is plotted against pore volume injected to see the performance of recovery efficiency. Recovery
efficiency performance for each case is given in Fig 7 – 9.
Figure 7. Areal Sweep Performance
Figure 5. Initial Well Pattern. Red: injector, Black: producer Figure 6. Altered Well Pattern. Blue: altered well
0
5
10
15
20
25
30
35
40
0 0.5 1 1.5 2 2.5 3 3.5
Rec
ove
ry F
acto
r (%
)
Pore Volume Injected ()
Areal Sweep (Ea)
Ea SAG
Ea Coinjection
Ea Continuous
Figure 8. Displacement Efficiency Performance
Summary of recovery efficiency for each method is given in fig 10. Efficiency ratio (multiplier) of foam methods to
continuous CO2 method is calculated
0
5
10
15
20
25
30
35
40
0 0.5 1 1.5 2 2.5 3 3.5
Rec
ove
ry F
acto
r (%
)
Pore Volume Injected ()
Displacement Efficiency (Ed)
Ed SAG
Ed Coinjection
Ed Continuous
0
5
10
15
20
25
30
35
40
45
0 0.5 1 1.5 2 2.5 3 3.5
Rec
ove
ry F
acto
r (%
)
Pore Volume Injected ()
Vertical Sweep (Ev)
Ev SAG
Ev Coinjection
Ev Continuous
Figure 9. Vertical Sweep Performance
In general it can be seen that foam methods greatly improve recovery efficiency compared to continuous CO2 injection
almost 40 times. By comparing oil saturation distribution before and after foam method is applied, it can be proven
that foam successfully reduce gravity segregation effect (Fig 10 & 11). Co-injection method give slightly better
performance compared to SAG method especially for areal and displacement efficiency. The result confirm the field
experience that co-injection is better for low pressure and short distance injection. However, the grid may have to be
refined to better examine the effect of distance on foam performance. SAG somehow better in vertical sweep
efficiency compared to co-injection. The result arose indication of surfactant-partitioning effect on reservoir. This may
lead to the reason of periodic pattern resulted for SAG recovery efficiency. Compositional simulator should be used
to clarify the indication. s
Figure 11. Recovery efficiency summary
Figure 10. Oil Saturation at the Start of Simulation (left) and after CO2 flooded (right). Gravity segregation occured
Field Recovery Factor
In field scale simulation, recovery factor result is also plotted against pore volume injected to see the performance of
recovery efficiency. Recovery factor plot for co-injection, SAG and continuous CO2 in field scale model for 0.15
PV/year injection rate is given in fig 12.
Figure 13. Recovery Factor in Field Scale Simulation using 0.15 PV/year injection rate
The result of field scale simulation verify the result from recovery efficiency model. Irregular pattern of recovery
factor in SAG method happened because not all the gas converted into foam, thereby reducing recovery efficiency. It
has been reported that using smallest slug size possible may be improve SAG recovery performance. However slug
0
5
10
15
20
25
30
35
40
45
0.00 0.50 1.00 1.50 2.00 2.50
Rec
ove
ry F
acto
r (%
)
Pore Volume Injected ()
Field Recovery
RF SAG
Figure 12. Oil Saturation Distribution at the Start of Simulation (Left) and after Foam applied (right). Gravity override handled
size sensitivity is not performed in this study. The effect of varying injection rate to recovery factor is illustrated in
fig 14.
Figure 14. Field Oil Recovery factor vs. Injection Rate
Higher injection rate give higher recovery factor until a certain limit. The higher injection rate used, the higher
reservoir pressure increase will be. Continuous CO2 give poor RF increment. This result happened because CO2 is not
effective in increasing reservoir pressure due to its compressibility. Co-injection and SAG methods lower gas mobility
hence the effect of high gas compressibility is controlled. Simulation result also proved that SAG and co-injection
method gave higher reservoir pressure than continuous CO2 (fig 14).
47.47 47.47 47.75
57.70
64.01
68.31
58.38
64.08
67.67
40
45
50
55
60
65
70
75
80
0.05 0.1 0.15
RF
(%)
Injection Rate (PV/year)
Field Oil Recovery Factor (%)
Continuous
Coinjection
SAG
Figure 15. Reservoir Pressure profile for each method (blue: SAG, green: co-injection, black: continuous)
Conclusion
1. Both SAG and co-injection foam EOR methods greatly improve sweep & displacement efficiency compared
to continuous CO2 flooding based on simulation result using heterogeneous and depleted oil reservoir model.
CO2 volume required per unit volume of oil produced is also reduced by using SAG and co-injection method
2. For lower pressure and short distance injection, Co-injection gives slightly better recovery performance than
SAG. However grid refinement and well injectivity parameter should be checked to ensure valid simulation
result.
3. Increasing injection rate will increase reservoir pressure hence recovery factor increased due to oil swelling
by CO2. The relation between recovery factor and injection rate show an optimum condition exist.
4. Altering insignificant producer well into injector to create peripheral pattern may improve recovery
efficiency.
References
1. Peningkatan Perolehan Minyak dengan Injeksi Gas CO2 dan Surfaktan Secara Serempak”, Letty Brioletty,
Septoratno Siregar, Edward ML Tobing. IATMI. 2005
2. “Foam Assisted Enhanced Oil Recovery at Miscible and Immiscible Conditions”. R. Farajzadeh et al. Paper
SPE 126410 presented at 2009 Kuwait International Petroleum & Exhibition Conference, Kuwait, 14-16
December 2009
3. The Effect of Foam Stability in CO2-Foam Flooding”, K. Teerakijpaiboon, F. Srisuriyachai. Chulalongkorn
University. Thailand. 2013
4. “Enhanced Oil Recovery using Foam Injection; a Mechanistic Approach”, Rasak Mayowa Sunmonu, SPE,
Mike Onyekonwu SPE; Institute of Petroleum Studies (IPS), University of Port Harcourt/IFP School. 2013
5. “Foam assisted CO2-EOR : Concepts, Challenges, and Applications”, Seyedeh H. Talebian. Universiti
Teknologi PETRONAS. 2013
6. “Development of a New Foam EOR Model From Laboratory and Field Data of the Naturally Fractured
Cantarell Field”, Fraser Skoreyko. Computer Modelling Group. 2013
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