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Petroleum & Petrochemical Engineering Journal Research Article 11 min read

Simulation Study of CO2 Injection in Tight Oil Reservoirs

Haijun F, Nzuetom Mbami SW* and Wakam Fogaing M*
* Corresponding author
ISSN: 2578-4846  10.23880/ppej-16000209  Received: November 15, 2019  Published: November 29, 2019
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Keywords
Tight oil reservoirs CO2 injection Hydraulic fracturing Simulation model
Abstract

The exploitation of Tight oil reservoirs has become a topic of interest to many searchers; the choice of methods and techniques to use, depending on the characteristics of the fluids in place is the main focused point for this purpose. Tight oil formation is formation with an ultra-low permeability (less than 0.1 mD); Horizontal well and hydraulic fracturing were identified by many searchers as the main methods to exploit this kind of reservoir. However, some new knowledge about the improvement of the oil recovery helped us to understand that there is still a lot of remaining oil in the reservoir after applying these methods: we chose CO2 huff-n-puff process to enhance the oil recovery. In this paper, we used The Bakken oil formation study as our base case. Our work is focused on parameters that can improve oil recovery without spending a high cost. We noticed that some parameters such as reservoir permeability, number of fracture per stage, CO2 injection rate, number of CO2 huff-n-puff cycle, CO2 injection time and fracture permeability can be key parameters for the improvement of the oil recovery.

Introduction

The Bakken formation with multiple oil-bearing layers is one of major productive tight oil reservoirs in North America [1], where Middle Bakken and Three Forks are the two primary layers for oil production since they have the best reservoir qualities such as porosity and oil saturation [2]. Figure 1 presents the location map of the Williston Basin with structure contours [3]. It has been reported that the Middle Bakken has an estimated average oil resource of 3.65 billion barrels and Three Forks has an estimated average resource of 3.73 billion barrels [4]. The combination of two technologies (horizontal well and hydraulic fracturing) has been considered as the best way to produce this kind of formation. During hydraulic fracturing, a total of about 182,500 bbl of fluid and 2,555,000 lbs of proppant are pumped for each well in the Middle Bakken and 153,000 bbl of fluid and 2,454,000 lbs of proppant for each well in the Three Forks [5]. The main goal of proppant is to keep the created hydraulic fractures open with enough fracture conductivity. There are many proppant types used in the Bakken formation, such as sand, ceramic, resin-coated sand or their combinations [6]. Ceramic proppant can provide not only a higher fracture conductivity but also a greater longevity and durability than sand or resin-coated sand [7]. In this paper, CO2 huff-n-puff injection has been chosen as an enhanced oil recovery method for the Bakken formation; this process consists of three stages such as CO2 injection, CO2 soaking, and production, as shown in Figure 2. During the early soaking period, injected gas penetrates into the rock matrix and repressurizes the limited area around the fracture network and depleted area [8].

Figure 1: Location map of the Williston Basin with structure contours [3].
Click to enlarge
Figure 1: Location map of the Williston Basin with structure contours [3].

The CO2 injection in tight oil reservoirs is defined as the following conceptual steps: CO2 first flows into and through the fractures; then it diffuses into the matrix and oil moves out of pores through swelling and reduced viscosity; finally, the oil will be driven into the fractures and the wellbore with the CO2 pressure gradient [9]. From the literature review Arshad A, Al-Majed A, Maneouar H, [10], it has been shown that CO2 injection can be injected as immiscible or miscible flooding but immiscible flooding is less effective than miscible flooding. The miscibility development between CO2 and the crude oil at the reservoir conditions of pressure and temperature is a key factor affecting the recovery; it has a strong effect on the microscopic efficiency which is directly related to the recovery factor. Two kinds of miscibility can occur; first contact miscibility and multiple contact miscibility. First contact miscibility happens when a single phase is formed when CO2 is mixed with the crude oil [10]. Multiple contact miscibility occurs when miscible conditions are developed in situ, through composition alteration of the CO2 or crude oil as CO2 moves through the reservoir [10]. It can be achieved at pressures above the minimum miscibility pressure (MMP). MMP is the pressure at which the reservoir fluid develops miscibility with CO2 and is a very important parameter in a well-designed CO2 flooding project.

A numerical reservoir simulation was also studied with a 20 ft × 20 ft × 10 ft Grid cells dimension. CMG-GEM, 2017 was used as an appropriate simulator to model multiple hydraulic fractures and fluid flow in tight oil reservoirs. A sensitivity study helped us to understand that some parameters can affect oil recovery.

Figure 2: During the early soaking period, injected gas penetrates into the rock matrix and repressurizes the limited area around the fracture network and depleted area [8].
Click to enlarge
Figure 2: During the early soaking period, injected gas penetrates into the rock matrix and repressurizes the limited area around the fracture network and depleted area [8].

Mathematical Formulation

As it is a compositional model, the masse conservation equation for component i becomes:

$$ - \nabla . \left[ \alpha \left(c _ {i g} \rho_ {g} v _ {g} + c _ {i l} \rho_ {l} v _ {l}\right) \right] + \alpha q _ {i} = \alpha \frac {\partial}{\partial t} \left[ \alpha \left(c _ {i g} \rho_ {g} v _ {g} + c _ {i l} \rho_ {l} v _ {l}\right) \right] $$ where 𝛼 is the geometric factor; 𝑐𝑖𝑔 the mass fraction of component i in the gas phase; 𝑐𝑖𝑙 the mass fraction of component i in the liquid phase l; ⍴𝑔 the gas density and ⍴𝑙 the liquid density.

kk Introducing Darcy’s law for each phase rf f

v μ =− f

    ∂  ∇ ∇ − ∇ + ∇ − ∇ + = +       ∂       i=1,2…N Some equations must be considered to resolve the previous equation.

α ρ α ρ ρ ρ ρ ρ α α α ρ α ρ μ μ

c kk c kk g D g D q c v c v t

( ) ( ) ( ) . ig g rg il l rl g g l l i ig g g il l l g l cig kigo cio n = = ∑ cig k

1 1 = A tight oil reservoir of 20 ft × 20 ft × 10 ft Grid cells dimension was built. The average matrix permeability of the reservoir is 0.7 ×10−2 mD and average porosity 5.6 %. The average thickness of the reservoir is 5ft. Formation oil density is 600 kg/𝑚3 and formation oil viscosity is 1.2 mPa.s. The GOR is 60. 𝑚𝑚. The formation pressure is 12 MPa and the crude oil volume factor is 1.127. Figure 3 presents the reservoir model including 4 fracturing stages for the Bakken tight oil reservoir. Three effective fractures per stage.

cig kigw ciw $$ \sum_ {k = 1} ^ {n} c _ {i o} = 1 $$

= $$ \sum_ {k = 1} ^ {n} c _ {i w} = 1 $$

𝑆𝑜 + 𝑆𝑤 + 𝑆𝑔= 1

𝑃𝑐𝑜𝑤= 𝑃𝑜 − 𝑃𝑤

𝑃𝑐𝑔𝑜= 𝑃𝑔 − 𝑃𝑜

Reservoir Characteristics and Numerical Simulation Model

Reservoir Description

Figure 3: 3D reservoir model including 4 fracturing stages for Bakken tight oil reservoir. Three effective fractures per stage.
Click to enlarge
Figure 3: 3D reservoir model including 4 fracturing stages for Bakken tight oil reservoir. Three effective fractures per stage.

parameters during history matching are listed in Table 1. Furthermore, some relative permeability curves such as water-oil relative permeability and liquid-gas relative permeability were obtained by tuning them to fit a good history matching as shown in Figure 7.

Figure 4: Bottom hole pressure input for history matching.
Click to enlarge
Figure 4: Bottom hole pressure input for history matching.
Figure 5: History matching for Oil flow rate.
Click to enlarge
Figure 5: History matching for Oil flow rate.
Figure 6: History matching for Gas flow rate.
Click to enlarge
Figure 6: History matching for Gas flow rate.
Figure 7: Relative permeability curves for a good history matching.
Click to enlarge
Figure 7: Relative permeability curves for a good history matching.

Water-oil relative permeability curve Liquid-gas relative permeability curve Figure 7: Relative permeability curves for a good history matching.

ParameterValueUnit
The model dimensions10500 ×2640 ×50ft
Initial reservoir temperature7800Psi
Production time1.2Year
Reservoir temperature245℉
Initial water saturation0.41Value
Total compressibility1 × 10−6𝑝𝑠𝑖−1
Matrix permeability5μD
Matrix porosity0.056Value
Horizontal well length8828ft
Number of stages15Value
Total number of fractures60Value
Fracture conductivity50mD-ft
Fracture half-length215ft
Fracture height50ft

Table 1: Parameters used for history matching (Bakken formation).

Based on a tight oil reservoir, a simulation model of CO2 huff-n-puff process in a horizontal well with multi- stage fractures is built. In this work, we first of all started by producing for four years and then the horizontal well is converted to CO2 injector with injection rates of 100 MSCF/day. After six months of injection, the well is shut- in and soaking for three months. Finally, the well is put back in production for one year. This represents one cycle of CO2 huff-n-puff. The cycle will start again at the end of the year of production and will cover the 30 years.

Many cases are studied in this simulation to investigate the sensitivity study. For the base case, we set up one fracture per stage for a total of 4 stages. For each stage fracture width is 0.03 ft, fracture half-length is 1300

  • 𝐶−𝐶 𝐶−𝐶30, and their corresponding molar fractions are 0.01%, 22.03%, 11.67%, 28.15%, 9.4% and 8.08%, respectively. Table 3 presents the order detailed input
  • Component
  • Molar
  • Fracture
  • Critical Pressure
  • Critical
  • Temperature (k)
  • Critical Volume (atm)
  • (L/mol)
  • Factor
  • CO2
  • 0.0001
  • 72.8
  • 304.2
  • 0.094
  • 44.01
  • 0.225
  • 𝑁2-𝐶1
  • 0.2203
  • 45.24
  • 189.67
  • 0.0989
  • 16.21
  • 0.0084
  • 𝐶1-𝐶4
  • 0.2063
  • 43.49
  • 412.47
  • 0.2039
  • 44.79
  • 0.1481
  • 𝐶5-𝐶7
  • 0.117
  • 37.69
  • 556.92
  • 0.3324
  • 83.46
  • 0.2486
  • 𝐶8-𝐶12
  • 0.2815
  • 31.04
  • 667.52
  • 0.4559
  • 120.52
  • 0.3279
  • 𝐶13- 𝐶19
  • 0.094
  • 19.29
  • 673.76
  • 7649
  • 220.34
  • 0.5672
  • 𝐶20-𝐶30
  • 0.0808
  • 15.38
  • 792.4
  • 1.2521
  • 321.52
  • 0.9422

Table 2: Compositional data for the Peng-Robinson EOS in Bakken.

ParameterValueUnit
The model dimensions20 ×20 ×10ft
Initial reservoir temperature7800Psi
Production time30Year
Reservoir temperature240℉
Initial water saturation0.2Value
Total compressibility1 × 10−6𝑝𝑠𝑖−1
Matrix permeability0.007μD
Matrix porosity0.056Value
Horizontal well length8828ft
Number of stages4Value
Total number of fractures12Value
Fracture conductivity6.9mD-ft
Fracture half-length1300ft
Fracture height10ft

Table 3: Compositional data for the Peng-Robinson EOS in Bakken.

Results and Discussions

As mentioned above, eight uncertain parameters (as listed in Table 4) were studied to analyze the sensitivity of CO2 huff-n-puff process in the Bakken tight oil. The effect

ParameterValue 2Base caseValue 3
Number of fracture123
CO injection rate, Mscf/day
2		50100500
CO injection time, month
2		369
Number of cycle31710
CO soaking time, month
2		536
Fracture permeability, mD500230800
Fracture half-length, ft65013002000
Reservoir permeability, mD0.0030.0070.01

Table 4: Eight parameters used for sensitivity study.

Figure 8: Pressure distribution at 30 months for the best case.
Click to enlarge
Figure 8: Pressure distribution at 30 months for the best case.

Effect of Number of Fracture per Stage on Oil Recovery Factor

For this case, we successively set up 1, 2, and 3 fractures per stage; while keeping the other parameters the same as those in the base case. We obtained an oil recovery factor of 8.3%, 8.56%, and 8.67% respectively as shown in Figure 9. It can be seen that the oil recovery increases with an increase of the number of fracture per stage.

Figure 9: It can be seen that the oil recovery increases with an increase of the number of fracture per stage.
Click to enlarge
Figure 9: It can be seen that the oil recovery increases with an increase of the number of fracture per stage.

Effect of CO2 Injection Rate on oil Recovery

Factor

For this case, we successively set up CO2 injection rate to be 50 Mscf/day, 100 Mscf/day, and 500 Mscf/day; while keeping the other parameters the same as those in the base case. We obtained an oil recovery factor of 2.56%, 8.3%, and 8.6% respectively as shown in Figure 10. It can be seen that the oil recovery increases with an increase of CO2 injection rate.

Figure 10: It can be seen that the oil recovery increases with an increase of CO2 injection rate.
Click to enlarge
Figure 10: It can be seen that the oil recovery increases with an increase of CO2 injection rate.

Effect of CO2 Injection Time on Oil Recovery

Factor

For this case, we successively set up CO2 injection time

Figure 11: Effect of CO2 injection time on oil recovery factor.
Click to enlarge
Figure 11: Effect of CO2 injection time on oil recovery factor.

Effect of Number of CO2 Huff-N-Puff Cycle on Oil Recovery Factor

For this case, we successively set up the number of cycle to be 3, 10, and 17; while keeping the other parameters the same as those in the base case. We obtained an oil recovery factor of 5.43%, 7.9%, and 8.67% respectively as shown in Figure 12. It can be seen that the oil recovery increases with the increase of the number of CO2 huff-n-puff cycle.

Figure 12: It can be seen that the oil recovery increases with the increase of the number of CO2 huff-n-puff cycle.
Click to enlarge
Figure 12: It can be seen that the oil recovery increases with the increase of the number of CO2 huff-n-puff cycle.

Effect of CO2 Soaking Time on Oil Recovery

Factor

For this case, we successively set up CO2 soaking time to be 3 months, 5 months, and 6 months; while keeping the other parameters the same as those in the base case.

We obtained an oil recovery factor of 8.67%, 8.87%, and 8.93% respectively as shown in Figure 13. It can be seen that the oil recovery increases with the increase of the soaking time.

Figure 13: It can be seen that the oil recovery increases with the increase of the soaking time.
Click to enlarge
Figure 13: It can be seen that the oil recovery increases with the increase of the soaking time.

Effect of Fracture Permeability on Oil Recovery Factor

For this case, we successively set up the fracture permeability to be 230 mD, 500 mD, and 800 mD; while keeping the other parameters the same as those in the base case. We obtained an oil recovery factor of 8.67%, 8.87%, and 8.97% respectively as shown in Figure 14. It can be seen that the oil recovery increases with the increase of the fracture permeability.

Figure 14: It can be seen that the oil recovery increases with the increase of the fracture permeability.
Click to enlarge
Figure 14: It can be seen that the oil recovery increases with the increase of the fracture permeability.

$$ = \frac {A K \Delta P}{\mu L} (1) $$

AK P q L μ

Darcy’s law: D

3 $$ = \frac {w e ^ {3} \Delta p}{1 2 \mu L} (2) $$

we p q L μ Poiseuille’s law:

12 p

3 $$ \frac {A K \Delta P}{\mu L} = \frac {w e ^ {3} \Delta p}{1 2 \mu L} $$

Combining 1 and 2 we get

3 we K=

k is the intrinsic fracture permeability.

12 A From the equations we can deduce that the flow rate increases with the increase of fracture permeability; that is why this parameter is really important when studying CO2 injection in tight oil reservoirs.

Effect of Fracture Half-Length on Oil Recovery Factor

For this case, we successively set up the fracture half- length to be 650 ft, 1300 ft, and 2000 ft; while keeping the other parameters the same as those in the base case. We obtained an oil recovery factor of 8.5%, 8.67%, and 8.7% respectively as shown in Figure 15. It can be seen that the oil recovery increases with the increase of the fracture half-length.

Figure 15: It can be seen that the oil recovery increases with the increase of the fracture half-length.
Click to enlarge
Figure 15: It can be seen that the oil recovery increases with the increase of the fracture half-length.

Effect of Reservoir Permeability on Oil

Recovery Factor

For this case, we successively set up the reservoir permeability to be 0.003 mD, 0.007 mD, and 0.01 mD;

while keeping the other parameters the same as those in the base case. We obtained an oil recovery factor of 7.9%, 8.67%, and 8.86% respectively as shown in Figure 16. It can be seen that the oil recovery increases with the increase of reservoir permeability.

Figure 16: It can be seen that the oil recovery increases with the increase of reservoir permeability.
Click to enlarge
Figure 16: It can be seen that the oil recovery increases with the increase of reservoir permeability.

Summary and Conclusions

After performing a series of simulations for the CO2 huff-n-puff process for enhanced oil recovery in the Bakken formation, the following conclusions can be drawn: 1. The relative permeability curves, such as water-oil relative permeability and liquid-gas relative permeability are obtained based on history matching with a fractured well from the Middle Bakken. 2. The case with three effective hydraulic fractures within one perforation stage has the highest incremental oil recovery factor compared to the other cases with one and two fractures within one perforation stage.

3. A comparison of the oil recovery factor with and without gas injection has proved that it is higher when injecting gas (Figure 17). 4. CO2 molecular diffusivity is a significant factor in the reservoir simulation model to capture the real physics mechanism during CO2 injection into the tight oil reservoirs 5. Oil recovery factor increases with the increasing number of cycle of CO2 huff-n-puff, number of fracture per stage, CO2 injection time, CO2 injection rate, CO2 soaking time, fracture permeability; fracture conductivity and reservoir permeability. 6. The range for the incremental oil recovery factor at 30 years of production is obtained as 2.56% - 8.97%.

Figure 17: Comparison of oil recovery factor with and without CO2 injection based on the case of three fractures per stage.
Click to enlarge
Figure 17: Comparison of oil recovery factor with and without CO2 injection based on the case of three fractures per stage.

Acknowledgment

I would first of all like to acknowledge the National Natural Science Foundation of China under Grant no. 51574265 for the financial support of this work. I would also thank China University of Petroleum (East China) for the assistance during the realization of this work and Computer Modeling Group Ltd. for providing the CMG- GEM software.

Nomenclature

Nomenclature bbl = barrels MMP = Minimum miscibility pressure, psi CMG = Computer Modeling Group GOR = Gas oil ratio Mscf = 103 standard cubic feet, 𝑓𝑡3 mD = 103 Darcy

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@article{haijun2019,
  title   = {Simulation Study of CO2 Injection in Tight Oil Reservoirs},
  author  = {Haijun F, Nzuetom Mbami SW* and Wakam Fogaing M},
  journal = {Petroleum & Petrochemical Engineering Journal},
  year    = {2019},
  volume  = {3},
  number  = {4},
  doi     = {10.23880/ppej-16000209}
}
Haijun F, Nzuetom Mbami SW* and Wakam Fogaing M (2019). Simulation Study of CO2 Injection in Tight Oil Reservoirs. Petroleum & Petrochemical Engineering Journal, 3(4). https://doi.org/10.23880/ppej-16000209
TY  - JOUR
TI  - Simulation Study of CO2 Injection in Tight Oil Reservoirs
AU  - Haijun F, Nzuetom Mbami SW* and Wakam Fogaing M
JO  - Petroleum & Petrochemical Engineering Journal
PY  - 2019
VL  - 3
IS  - 4
DO  - 10.23880/ppej-16000209
ER  -