Nano-Water-Alternating-Gas Simulation Study Considering Rock–Fluid Interaction in Heterogeneous Carbonate Reservoirs †
Abstract
:1. Introduction
2. Simulation Model
2.1. Fluid Modeling
2.2. Description of a 1D Core Model
2.3. Description of a 3D Core Model
3. Results and Discussion
3.1. Results of 1D Simulations
3.2. Results of 3D Simulations
3.2.1. Results of Oil Recovery by NWAG
3.2.2. Results of CO2 Storage by NWAG
4. Conclusions
- The 1D core models based in CMG-GEM were simulated to evaluate the applicability of the NWAG method, and 1D core models based on CMG-GEM were simulated. Sensitivity analyses were conducted on the factors influencing WAG, followed by the incorporation of the effects of nanoparticles on wettability improvement and absolute permeability reduction using CMOST. The results confirmed that applying the NWAG method enhanced both oil recovery and CO2 storage efficiency.
- To construct a 3D reservoir model, a Dykstra–Parsons coefficient of 0.4 was set for heterogeneity, and Carlson’s relative permeability curve with a gas saturation threshold of 0.3 was applied to incorporate history matching. Applying the NWAG method to the 3D model considering heterogeneity and history matching yielded results for oil recovery and CO2 storage capacity based on each influencing factor.
- The optimal conditions for oil recovery were determined to be an NWAG ratio of 3:1, slug size of 0.1 HCPV, and SiO2 mole fraction of 0.001, achieving approximately 71.8% oil recovery. Optimal CO2 storage conditions were found with an NWAG ratio of 1:2, slug size of 0.1 HCPV, and SiO2 mole fraction of 0.03, resulting in 11,397 tons of CO2 storage.
- Increasing the SiO2 concentration rapidly increased oil recovery in the initial stages. Therefore, using a higher concentration of nanofluids can initially lead to quick oil recovery, whereas a lower concentration of nanofluids expands the adsorption area, resulting in long-term effectiveness. CO2 storage tended to plateau after reaching a certain range. Additionally, higher nanoparticle concentrations were found to increase the reservoir pressure and alter the wettability, thereby enhancing the CO2 storage effectiveness.
Author Contributions
Funding
Data Availability Statement
Conflicts of Interest
Abbreviations
API | American Petroleum Institute |
CMG | Computer modeling group |
EOR | Enhanced oil recovery |
HCPV | Hydrocarbon pore volume |
NWAG | Nano-water-alternating gas |
OOIP | Original oil in place |
PR-EOS | Peng–Robinson equation of state |
WAG | Water-alternating gas |
WOC | Water oil contact |
SNP | Silica nanoparticle |
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Component | Mole Fraction | Molecular Weight | Critical Pressure (Atm) | Critical Temperature (K) | Parachor | Acentric Factor |
---|---|---|---|---|---|---|
N2 | 2.07 | 28.01 | 33.5 | 126.2 | 41 | 0.040 |
CO2 | 0.74 | 44.01 | 72.8 | 304.2 | 78 | 0.225 |
H2S | 0.12 | 34.08 | 88.2 | 373.2 | 80 | 0.100 |
CH4 | 7.49 | 16.04 | 45.4 | 190.6 | 77 | 0.008 |
C2H6 | 4.22 | 30.07 | 48.2 | 305.4 | 108 | 0.098 |
C3H8 | 7.85 | 44.10 | 41.9 | 369.8 | 150 | 0.152 |
NC4 | 6.55 | 58.12 | 37.5 | 425.2 | 186 | 0.193 |
NC5 | 4.59 | 72.15 | 33.3 | 469.6 | 228 | 0.251 |
C6–9 | 21.55 | 102.50 | 29.8 | 556.4 | 297 | 0.331 |
C10–17 | 22.02 | 184.00 | 19.9 | 692.3 | 508 | 0.584 |
Parameters | W3 | Fluid Model in This Study |
---|---|---|
API (°) | 31 | 29.3 |
Saturation pressure (psi) | 714 | 700 |
Oil density at Pc (kg/m3) | 806.4 | 816 |
Parameters | Values |
---|---|
Number of grid blocks | 1(K) |
Length | 10 cm |
Diameter | 3.14 cm |
Porosity | 0.18 |
Permeability | 50.0 md |
Rock compressibility | 5.8 × 10−7 1/kPa |
Pressure | 17,340 kPa |
Temperature | 85.6 °C |
Bulk volume | 77.3 cm3 |
Pore volume | 13.9 cm3 |
Initial oil saturation | 0.7 |
Original oil in place (OOIP) | 6.13 × 10−5 bbl |
Parameters | Values |
---|---|
Number of grids | 5(K) |
Thickness | 50 m |
WOC depth | 1050 m |
Reference pressure | 15,000 kPa |
Grid top | 1000 m |
Porosity | 21.9–28% |
Permeability | 31–75 md |
Pressure | 15 MPa |
Temperature | 37 °C |
Initial oil saturation | 0.8 |
NWAG Ratio | Slug Size | Nanoparticle Conc. (wt.%) |
---|---|---|
1:3 | 0.001 | |
0.1 HCPV | ||
1:2 | 0.005 | |
1:1 | 0.01 | |
0.2 HCPV | ||
2:1 | 0.02 | |
3:1 | 0.3 HCPV | 0.03 |
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Ko, S.; Park, H.; Jang, H. Nano-Water-Alternating-Gas Simulation Study Considering Rock–Fluid Interaction in Heterogeneous Carbonate Reservoirs. Energies 2024, 17, 4846. https://doi.org/10.3390/en17194846
Ko S, Park H, Jang H. Nano-Water-Alternating-Gas Simulation Study Considering Rock–Fluid Interaction in Heterogeneous Carbonate Reservoirs. Energies. 2024; 17(19):4846. https://doi.org/10.3390/en17194846
Chicago/Turabian StyleKo, Seungmo, Hyeri Park, and Hochang Jang. 2024. "Nano-Water-Alternating-Gas Simulation Study Considering Rock–Fluid Interaction in Heterogeneous Carbonate Reservoirs" Energies 17, no. 19: 4846. https://doi.org/10.3390/en17194846
APA StyleKo, S., Park, H., & Jang, H. (2024). Nano-Water-Alternating-Gas Simulation Study Considering Rock–Fluid Interaction in Heterogeneous Carbonate Reservoirs. Energies, 17(19), 4846. https://doi.org/10.3390/en17194846