Experimental Investigation of IOR Potential in Shale Oil Reservoirs by Surfactant and CO2 Injection: A Case Study in the Lucaogou Formation
Abstract
:1. Introduction
2. Methodology
2.1. Experimental Materials
2.1.1. Core Samples
2.1.2. Surfactant
2.2. Experimental Methods
2.3. Experimental Procedure
- (1)
- The sample was placed into a core holder. The outlet end of the core holder was connected with the back-pressure valve. And the core pore pressure is increased to 15 MPa by pump under the condition of formation temperature.
- (2)
- For one-step depletion development, the outlet pressure of the core was reduced to atmospheric pressure at one time, and the T2 spectrum of samples was tested by the NMR online displacement system.
- (3)
- For multi-step depletion development, the pressure was reduced by one-third at a time until the outlet pressure was reduced to atmospheric pressure. Each stage was maintained for 30 min.
- (4)
- When the core sample was replaced, the pressure changed to 20 MPa and 30 MPa, respectively. Steps (2) and (3) were repeated to analyze the influence of different reservoir pressure on one-step depletion development.
- (5)
- Under the condition of reservoir temperature, the core pore pressure is controlled to 20 MPa. Further, 0.2 PV of supercritical CO2 was injected by a high-pressure constant speed pump for X3 and S70. The injection rate of CO2 was 0.05 mL/min, and 0.2% AES surfactant was injected for X2 and S9. Then, the pressure was sustained for a duration of two hours.
- (6)
- The injection port was opened. After the oil in the rocks was no longer produced, the NMR T2 signals were measured. The NMR imaging of X2 and X3 was measured.
- (7)
- Procedures (1) and (2) were repeated. NMR T2 and imaging signals were measured in different cycles. This experiment comprised a total of four cycles.
- (8)
- After four stages of CO2 huff-n-puff for S70, three more cycles of surfactant imbibition were conducted. And for S9, three more cycles of CO2 huff-n-puff were conducted.
3. Results and Discussion
3.1. Performance of One-Step and Multi-Step Depletion
3.2. Performance of CO2 Huff-n-Puff and Surfactant Imbibition
3.3. Performance of Combination CO2 with Surfactant
3.4. Contribution of Different Scale Pores
3.5. Sweep Area and Efficiency of CO2 and Surfactant
4. Conclusions
- (1)
- The ultimate oil recoveries for 15 MPa, 20 MPa, and 30 MPa one-step depletion production are 4.11%, 7.0%, and 9.74%, respectively. And for multi-step depletion production, the oil recovery rate at the same pressure is increased by 1.26%, 0.04%, and 1.28%, respectively. Higher initial pressure shows higher oil recovery. And multi-step depletion production can improve the degree of oil utilization in different pores.
- (2)
- The ultimate oil recoveries of the X3 and S70 samples are 30.45% and 40.70% by CO2 huff-n-puff. Two or three cycles of CO2 injection should be sufficient for shale formations. Pore size distribution is an important factor for CO2 huff-n-puff. Oil in large pores is mainly produced. The ultimate oil recoveries of the X2 and S9 samples are 24.24% and 20.89% by surfactant imbibition. Pore size distribution is also an important factor for surfactant imbibition. And surfactant has a wider production range of pore sizes than CO2 huff-n-puff.
- (3)
- Combining the surfactant with the gas huff-n-puff approach can represent a viable method for enhancing oil recovery. After three more cycles of surfactant imbibition and CO2 huff-n-puff, the ultimate recovery rate can be increased by 11.27% and 26.27%, respectively. We should pay more attention to the effect of CO2 on a specific oil reservoir. Surfactant imbibition after CO2 huff-n-puff is the greater IOR.
- (4)
- The NMR imaging results show that the sweep area and efficiency of CO2 huff-n-puff are larger. Oil utilization is different in the first two cycles by CO2 huff-n-puff due to the heterogeneity. In the third and fourth cycles, the degree of oil utilization is barely noticeable. Oil in the whole X2 sample was partly produced by surfactant imbibition. The effect of the flowback stage is limited.
Author Contributions
Funding
Data Availability Statement
Acknowledgments
Conflicts of Interest
Nomenclature
AES | Sodium Alcohol Ether Sulphate |
BS−12 | Dodecyl dimethyl betaine |
BS−18 | Octadecyl dimethyl betaine |
DPS−2 | Dimethyldithioformamide propylsolfonic acid sodium |
KPS | Karamay petroleum sulfonate |
OP | Alkylphenol polyoxyethylene |
IFT | Interfacial tension |
IOR | Improved oil recovery |
MIP | Mercury intrusion porosimetry |
NMR | Nuclear magnetic resonance |
NEA | National Energy Administration |
TOC | Total organic carbon |
Pore shape factor | |
Content of oil in the rocks | |
Change of oil | |
Oil recovery | |
surface relaxation rate (µm/ms) | |
r | Pore radius (µm) |
S(T2) | Function of the area of the T2 spectrum |
S/V | surface–volume ratio (µm−1) |
surface relaxation |
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Sample | Length (cm) | Diameter (cm) | Porosity (%) | Permeability (mD) | Experiment |
---|---|---|---|---|---|
X1a | 2.6 | 2.5 | 15.1 | 0.65 | 15 MPa depletion |
X1b | 2.4 | 2.5 | 15.0 | 0.61 | 20 MPa depletion |
X1c | 2.5 | 2.5 | 15.5 | 0.73 | 30 MPa depletion |
X3 | 2.6 | 2.5 | 15.2 | 0.68 | CO2 huff-n-puff |
S70 | 2.6 | 2.5 | 16.8 | 0.67 | CO2 huff-n-puff + surfactant imbibition |
X2 | 2.6 | 2.6 | 15.2 | 0.69 | surfactant imbibition |
S9 | 2.5 | 2.5 | 12.8 | 0.12 | surfactant imbibition + CO2 huff-n-puff |
Number | Surfactant Type | IFT (mN/m) | Number | Surfactant Type | IFT (mN/m) |
---|---|---|---|---|---|
1 | 0.1% OP | 2.408 | 11 | 0.1% binary KPS | 1.081 |
2 | 0.2% OP | 0.500 | 12 | 0.2% binary KPS | 0.674 |
3 | 0.1% AES | 0.788 | 13 | 0.1% nonionic | 16.149 |
4 | 0.2% AES | 0.385 | 14 | 0.2% nonionic | 12.501 |
5 | 0.1% BS-12 | 2.922 | 15 | 0.1% anion | 0.345 |
6 | 0.2% BS-12 | 3.149 | 16 | 0.2% anion | 0.549 |
7 | 0.1% BS-18 | 0.402 | 17 | 0.1% BS-18 + 0.1% AES | 0.179 |
8 | 0.2% BS-18 | 0.420 | 18 | 0.1% BS-18 + 0.05% AES | 0.045 |
9 | 0.1% DPS-2 | 0.361 | 19 | 0.2% BS-18 + 0.1% AES | 0.287 |
10 | 0.2% DPS-2 | 0.403 | 20 | 0.2% BS-18 + 0.05% AES | 0.281 |
Sample | Formation Water | 0.2% AES | 0.1% DPS-2 | |||
---|---|---|---|---|---|---|
Contact Angle | Wettability | Contact Angle | Wettability | Contact Angle | Wettability | |
1 | 63.9° | water wet | 37.6° | water wet | 34.1° | water wet |
2 | 45.7° | water wet | 76.0° | water wet | 107.8° | oil wet |
3 | 115.0° | oil wet | 52.7° | water wet | 126.6° | oil wet |
4 | 106.6° | oil wet | 31.0° | water wet | 160.6° | oil wet |
IOR Method | Pore Size (μm) | Ultimate Oil Recovery (%) | Lower Limit | |||
---|---|---|---|---|---|---|
P < 0.1 | 0.1 < P < 1 | 1 < P < 10 | P > 10 | of Pore Size (μm) | ||
One-step depletion (30 MPa) | 4.64 | 1.29 | 3.81 | 0.00 | 9.74 | 0.05 |
Multi-step depletion (30 MPa) | 2.92 | 3.16 | 4.93 | 0.00 | 11.01 | 0.05 |
CO2 huff-n-puff (X3) | 1.42 | 11.48 | 17.53 | 0.03 | 30.45 | 0.10 |
Surfactant imbibition (X2) | 11.59 | 6.71 | 5.94 | 0.00 | 24.24 | 0.05 |
CO2 huff-n-puff + Surfactant imbibition (S70) | 3.00 | 21.39 | 15.94 | 0.94 | 51.97 | 0.05 |
8.20 | 2.75 | 0.10 | 0.00 | |||
Surfactant imbibition + CO2 huff-n-puff (S9) | 1.72 | 7.72 | 11.44 | 0.01 | 47.16 | 0.05 |
0.15 | 10.47 | 15.60 | 0.05 |
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Shi, Y.; Xu, C.; Wang, H.; Liu, H.; He, C.; Qin, J.; Wu, B.; Li, Y.; Song, Z. Experimental Investigation of IOR Potential in Shale Oil Reservoirs by Surfactant and CO2 Injection: A Case Study in the Lucaogou Formation. Energies 2023, 16, 8085. https://doi.org/10.3390/en16248085
Shi Y, Xu C, Wang H, Liu H, He C, Qin J, Wu B, Li Y, Song Z. Experimental Investigation of IOR Potential in Shale Oil Reservoirs by Surfactant and CO2 Injection: A Case Study in the Lucaogou Formation. Energies. 2023; 16(24):8085. https://doi.org/10.3390/en16248085
Chicago/Turabian StyleShi, Yaoli, Changfu Xu, Heng Wang, Hongxian Liu, Chunyu He, Jianhua Qin, Baocheng Wu, Yingyan Li, and Zhaojie Song. 2023. "Experimental Investigation of IOR Potential in Shale Oil Reservoirs by Surfactant and CO2 Injection: A Case Study in the Lucaogou Formation" Energies 16, no. 24: 8085. https://doi.org/10.3390/en16248085
APA StyleShi, Y., Xu, C., Wang, H., Liu, H., He, C., Qin, J., Wu, B., Li, Y., & Song, Z. (2023). Experimental Investigation of IOR Potential in Shale Oil Reservoirs by Surfactant and CO2 Injection: A Case Study in the Lucaogou Formation. Energies, 16(24), 8085. https://doi.org/10.3390/en16248085