This paper presents a new perspective in modeling and analyzing efficiency of CO2 and miscible gas injection for potential enhanced oil recovery (EOR) and CO2 storage in shale oil plays. Our major focuses are conceptual and fundamental understanding of the dominant trapping and oil recovery mechanisms behind miscible gas injection. The efficiency of the CO2 Huff-n-Puff process in shale oil production has been widely investigated in recent years because of the ultra-low permeability (1 to 100 µD) of shale oil reservoirs and poor geological connectivity between hydraulic fractured wells. Here we used hydrocarbon fluid properties of a Middle Bakken tight oil reservoir, and considered a wide range of permeability (from 1 to 100µD) and isotherm adsorption properties for CO2 and CH4. A large scale numerical model was set up to simulate and capture the important mechanisms behind various miscible gas injection scenarios. Simulation results reveal that CO2 adsorption and CH4 desorption along with molecular diffusion of hydrocarbon components are crucial in the presence of organic matter content and pores, however, recycle enriched gas injection demonstrated a high oil recovery compared to miscible CO2 injection. Although CO2 adsorption is large in organic rich shale oil based on literature measurements, CO2 efficiency in enhancing oil recovery is not as much as recycle enriched gas with ethane (C2). However, CO2 trapping may be substantial due to adsorption (5.0% to 10%) and other conventional trapping mechanisms, and the amount of CO2 trapped could be a significant fraction of the total injected amount (25% to 50% considering other trapping mechanisms such as CO¬2 dissolution, residual, and free gas). Simulation results strongly support that CO2 molecular diffusion can assist in the deep penetration of CO2 to touch larger surface area of matrix to become adsorbed, as well as dissolved in other coexisting phases and residual trapping.

1. Evaluation of CO2 Storage Capacity and
EOR in the Bakken Shale Oil Reservoirs
Hamid R. Lashgari
February 14, 2018

2. Outline
• Background
• Objective(s)
• CO2 Trapping and EOR Mechanisms
• Simulation Results
• Summary and Conclusions

3. Background: Shale Revolution
Technology built a revolution
o Horizontal well drilling
o Multistage fracturing
Shale and Tight
Oil Boom
(EIA,2017)

4. Background: Shale and Tight Oil Production
• Problem: Production growth rates are not sustainable
– Overall shale oil productivity is declining (Pressure declineing)
– GOR or/and WOR are getting higher
– Very low recovery factor ~ 6%
• Solution : EOR technology
– The best EOR candidate: Miscible gas-based EOR
– Take advantage of high density and number of wells (50,000 horizontal wells)
– Benefits will be enhancing oil production and CO2 trapped

5. Objective(s)
• Evaluate efficiency of CO2-EOR
Trapping and EOR Mechanisms
in Shale oil plays
The Bakken shale oil reservoirs
• Evaluate potential CO2 storage
capacity

6. Critical Gaps in Unconventional
Fluid flow mechanisms in nanoscale pores?
o Is Darcy flow (no-slip flow) still valid?
o How important is molecular diffusion?
Phase behavior and thermodynamic state in
nanoscale pores?
o Phase equilibrium and dissolution states
o Capillarity and confinement effect on phase
behavior?
o Contact angle and interfacial tension (IFT)?
o Pores sizes and wettability of OM and IOM?
(modified after Javadpour et al., 2015)
(Zhang and Lashgari, 2016)

7. Conventional Vs. Unconventional
• Fluid and Multiphase Flow in nanoscale
– Darcy flow?
– Gas diffusion?
– Adsorption and desorption?
– Relative permeability?
– Capillary pressure?
– Hysteresis effects?
– Contact angle and wettability
– IFT between coexisting phases
– Pores sizes in OM and IOM

8. Typical Parameters for Bakken Shale Oil
Reservoir Model
o Natural Depletion
o Huff-n-Puff CO2 Injection
Reservoir model (1610 m×805 m×16 m)
Well Configuration and 15 HFs per well
1610 m
805m

9. Typical Parameters for Bakken Shale Oil
Reservoir Model
Basic Reservoir and Fracture Properties from Middle Bakken for Simulation Study of
CO2 Huff-n-Puff Process
97 m
183 m
Parameter Value Unit
Reservoir dimension 1610×805×16 m×m×m
Number of gridblocks 132×66×1 --
Initial reservoir pressure 55.16 MPa
Production time 20 year
Reservoir temperature 115.6 oC
Initial water saturation 0.25 fraction
Total compressibility 1.45×10-4 MPa-1
Matrix permeability 1, 10, 100 µD
Matrix porosity 0.06 [-]
Stage spacing 97.5 m
Fracture conductivity 61 mD-m
Fracture half-length 91.5 m

10. Well Schedule with injection and production
Scenario (Huff-n-Puff Process)
(a) Gas Injection for 70 days (b)Soaking for 50 days (c) Production for 960 days
Natural
production
1st cycle gas
injection and
production
2nd cycle gas
injection and
production
3rd cycle gas
injection and
production
4th cycle gas
injection and
production
5th cycle gas
injection and
production
6th cycle gas
injection and
production
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21
Natural
production
1st cycle gas
injection and
production
2nd cycle gas
injection and
production
3rd cycle gas
injection and
production
4th cycle gas
injection and
production
5th cycle gas
injection and
production
6th cycle gas
injection and
production
Years
Well 2
Well 1

11. Modeling and Simulation Results

12. Bakken Shale Oil Phase Behavior
Parameters
Peng-Robinson EOS parameters for the Bakken Formation
Component
Molar
fraction
Critical
pressure
(atm)
Critical
temperature
(K)
Critical
volume
(L/mol)
Molar
weight
(g/gmol)
Acentric
factor
Parachor
coefficient
CO2 0 72.8 304.2 0.094 44.01 0.225 78
CH4-N2 0.2203 45.24 189.67 0.0989 16.21 0.0084 76.50
C2-NC4 0.2063 43.49 412.46 0.2039 44.79 0.1481 150.47
C5-C7 0.117 37.69 556.92 0.3327 83.46 0.2486 248.49
C8-C12 0.2815 31.04 667.52 0.4559 120.52 0.3279 344.90
C13-C19 0.094 19.28 673.76 0.7648 220.34 0.5671 570.11
C20-C30 0.0809 15.38 792.39 1.2520 321.52 0.9422 905.67

13. Bakken Shale Oil Simulation Parameters
Component CO2 CH4-N2 C2-NC4 C5-C7 C8-C12 C13-C19 C20-C30
CO2 0 -0.0200 0.1030 0.1327 0.1413 0.1500 0.1500
CH4-N2 -0.0200 0 0.0130 0.0784 0.1113 0.1200 0.1200
C2-NC4 0.1030 0.0310 0 0.0078 0.0242 0.0324 0.0779
C5-C7 0.1327 0.0784 0.0078 0 0.0046 0.0087 0.0384
C8-C12 0.1413 0.1113 0.0242 0.0046 0 0.0006 0.0169
C13-C19 0.1500 0.1200 0.0324 0.0087 0.0006 0 0.0111
C20-C30 0.1500 0.1200 0.0779 0.0384 0.0169 0.0111 0
Binary interaction parameters for the Bakken hydrocarbon content

14. Relative Permeability
History match
Wettability:
Neutral or mixed wet
Constant IFT:
O/G: 0 or 27 dyn/cm2
W/O: 38 dyn/cm2
Capillary number:
1 or 3.8×10-6
Petrophyscial
properties
Oil and water Oil and Gas
Wei and Lashgari et al.
2015
Alfarge et al. 2017

15. Dominant Mechanisms: Miscibility
Full miscibility of hydrocarbon composition develops a single phase described as:
• IFT value =0
• Capillary pressure value =0
• Relative permeability values =1
• Residual saturations =0
Gas Composition CO2 case
CO2 (mole fraction) 1.0
CH4(mole fraction) 0
C2(mole fraction) 0
C3(mole fraction) 0
MMP (@ Temp. 240 oF ) 2460 psi
Total surface injection rate
(scf/day) *
2×106

16. Dominant Mechanisms: Diffusion
i
i i
D
J c

 
Flux
Conductivity Driving force
Diffusion
Darcy flow
(Bulk flow)
rj
j j
j
kk
J P

 
Flux
Conductivity Driving force
• A concentration-based mass transfer
phenomena
• Bulk diffusivity
• Tortuosity
• Porosity
• Temperature
• Pressure
• Concentration

17. Dominant Mechanisms: Adsorption
Adsorption and desorption are
significant in organic rich
shale plays.
Main factors:
o TOC
o Pressure
o Temperature
(Heller and Zoback, 2014)
TOC= 5.3%
TOC= 1.2%
TOC= 5.3%
TOC= 1.8%
CO2
CH4
CO2
CH4
CO2
CH4
CO2
CH4

18. Molecular Diffusion and Adsorption
Parameters
Parameters CO2 CH4 Rock
diffusivity (cm2
/sec) in oil 0.0075 0.0005 --
diffusivity (cm2
/sec) in gas 0.0075 0.0005 --
Density (lb/ft3
) -- -- 155
Tortuosity (ft/ft) -- -- 100
Langmuir sorption constant i (1/psi) 0.0005 0.00015 --
Maximal sorption gas
max,i (gmol/lb)
3.3 1.2 --
** 1 cm2
/sec = 8.64 m2
/day; 1gm/lb =2.2046 gmol/kg
Hysteresis in sorption (Example)
CO2 adsorption and desorption experimental data
and Langmuir model
Core samples of Power River Basin (Wyoming)

19. Simulation Test Cases with Three
Different Permeability Cases
Case ID Case Description
Nd Natural depletion
CO2 CO2 injection
CO2Md
CO2 injection considering only molecular
diffusion
CO2MdAd
CO2 Injection considering molecular diffusion
and adsorption

20. Gas Diffusion
Average Gas Saturation after 20 yrs.
Case: 1µD
Case 100µD
High Gas
Saturation
Adsorption
Lower Gas
Saturation
Perm, Press , Temp, TOC, Tortuosity

21. Average Pressure over 20 yrs.
Case: 1µD
Case 10µD

22. CO2 Adsorption (gmole/ft3)
Case: 1µD Case 100µD

23. Case: 1µD
Case: 100 µD
Cumulative Oil Production
1. Diffusion (major)
2. Viscous forces & miscibility (minor)
3. Adsorption (minor)
1. Viscous forces & miscibility (major)
2. Diffusion (minor)
3. Adsorption (minor)

24. Cumulative Oil Production
Negative ImpactPositive Impact

25. Daily Oil Production over 20 yrs.
Case: 1µD Case 10µD
Diffusion and
miscibility effects

26. injection
Prod3
Prod2
Prod4 Prod5 Prod6 Prod7
N Prod1
CO2 Storage Capacity
2
2
2
1
Cumulative CO Production
Relative CO Storage
Cumulative CO Injection
 
Gas
Diffusion
Higher CO2
Trapping
Adsorption
More CO2
TrappingCase: 100µD

27. Positive Impact Positive Impact
CO2 Storage Mechanism Contribution

28. Global CO2 Mole fraction after 20 yrs.
Case: 1µD Case 100µD

29. Summary and Conclusions
• The efficiency of CO2 injection is widely investigated using Huff-n-
Puff process in ultra-low permeability (1µD to 100 µD) and poor
geological connectivity.
o Miscibility plays a main role to boost oil production with high CO2
dissolution
o Diffusion contributes between 31% to 47% in oil production and
10% to 14% in CO2 trapping
o Adsorption can potentially trap CO2 in around 0.1% to 5%

30. Thanks
Acknowledge:
Computer Modeling
Group Ltd (CMG)
Texas Advanced
Computer Center