Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir
Abstract
:1. Introduction
- Viscosifying power: the polymer should provide the required in-situ viscosity (more precisely resistance factor) at a reasonable concentration at reservoir conditions;
- Retention: polymer loss in the reservoir should be as low as possible to minimize propagation issues and oil bank delay. This is the focus of this study;
- Injectivity: the polymer solution should propagate easily through the reservoir rock. This factor is directly impacted by viscosity and retention as well as the chemical composition of the polymer;
- Long-term stability: the polymer should be stable and provide enough viscosity throughout its transit in the reservoir;
- Cost.
2. Determination of Retention: Review of Procedures and Challenges
- Adsorption: the polymer molecules can “stick” to the rock via Van der Waals, ionic or hydrogen bonds. Adsorption is usually considered irreversible since the macromolecule can attach to the rock via many points;
- Mechanical entrapment: if the hydrodynamic volume of the molecule in solution is larger than the pore throat it encounters, then the polymer molecule can become physically trapped at the entrance of the pore;
- Hydrodynamic retention: in some cases, the molecules can be (temporarily) trapped in eddies or regions where the flow is stagnant.
- Polymer concentration can have a significant impact on retention, especially when displacing viscous oils [18].
- Polymer retention values can be 2 to 10 times lower in the presence of oil than without oil [19].
- The presence of sulfonated monomers in the polymers (ATBS) can help decrease the retention of polymers [20].
- The mineralogy of the reservoir, and especially clay and iron content, greatly impacts polymer retention [21].
- Polymer characteristics such as chemical composition, concentration, and molecular weight impact retention [22].
- Retention values vary if the experiments are conducted in aerobic vs. anaerobic conditions [23].
- The packing and ageing methodology have a significant impact on the overall results [24].
- The correlation between retention values and inaccessible pore volume in the core is still unclear [18].
- The dynamic retention method with 2 polymer fronts was used as a standard.
- The method was improved for unconsolidated rocks and technical abilities of the laboratory which conducted the tests.
- The retention values were obtained in cores at residual oil saturation, to mimic real field conditions.
- The retention studies compared polymers at iso-viscosity (0.01 Pa·s) to get as close as possible from the injection conditions.
- Effluent concentration of polymers was determined via total nitrogen concentration (TNb method).
- Polymers with different molecular weights and chemistries (with or without Acyrlamido Tertiary Butyl Sulfonate or ATBS) were compared to determine the retention trends.
- Core with different permeabilities were used to represent the heterogeneity in the field.
3. Materials
3.1. Core
3.2. Polymers and Solutions
4. Methods
4.1. Set up of Filtration Test
4.2. Determination of Polymer Retention
- Testing of polymer compositions should be performed on composite models of 5 cylindrical core samples having permeabilities of class 1 of clastic reservoirs (helium permeability of 1150–1850 md) and class 2–3 (helium permeability of 300–700 md) to simulate different sections of the reservoir. It was not possible to cover the whole permeability range, mentioned above, especially with high permeability more than 1.5 d.
- Fix weakly cemented specimens with PTFE film (polytetrafluoroethylene), without a brass mesh at the ends: using a mesh is not recommended as it can affect polymer retention at the ends of the specimens.
- Samples shall be cleaned in a Soxhlet apparatus with an alcohol and benzene mixture. The core shall be dried at a temperature not exceeding 70 °C to prevent decomposition of clay minerals.
- Samples shall be saturated with synthetic multicomponent water, its composition being as close to that of formation water as possible.
- Forming the residual water saturation (Krw) and initial oil saturation (Kio), restoring wettability of samples and all subsequent preparations shall be performed in a filtration unit to avoid a mechanical impact and destruction of core samples.
- At all stages of testing, the linear fluid injection rate should not exceed 2 m/day to ensure reproducing the actual filtration rate and capillary impregnation in actual development of the formation under study.
- More exact determination of optimum polymer slug size, formation water model, and pumping rates. Slug sizes are selected based on the heterogeneity of the reservoir, oil to polymer solution viscosity ratio and the degree of polymer adsorption to pore space. The optimum pumping volumes and rates were experimentally determined during the first experiment, as shown in Table 4.
4.3. Detection of Polymer Concentration
4.4. Determination of Tracer Concentration
5. Results and Discussion
5.1. Coreflooding Results
5.2. Polymer and Tracers Measurements
5.3. Polymer Retention Values
- The retention values are similar to other cases described in the literature for unconsolidated heavy oil formations.
- Retention decreases with the increase in permeability and the decrease in molecular weight.
- However, it was not possible to measure retention for permeabilities more than 1.2 d, which represents the majority of permeability range. So, the retention values in the reservoir should be much lower.
- The addition of ATBS in the polymer macromolecule reduces polymer retention in the studied cores. For instance, a 12 MDa (million g/mol) polymer with ATBS displays similar retention values than a 7 MDa conventional polyacrylamide in rocks with comparable permeabilities.
- Discrepancies exist between both measurements’ methods with reasons still unclear at this stage. Investigations are on-going to get a better understanding of these results.
5.4. Discussion
6. Conclusions
Author Contributions
Funding
Acknowledgments
Conflicts of Interest
Nomenclature
°C | degree Celsius |
ATBS | Acrylamido Tertiary Butyl Sulfonate |
C | concentration |
cP | centipoise |
d | Darcy |
Da | Dalton |
EOR | enhanced oil recovery |
g/cm3 | gram per cubic centimeter |
g/l | gram per liter |
IAPV | inaccessible pore volume |
Kio | relative permeability at 100% oil saturation |
Kro | relative permeability to oil |
Krw | relative permeability to water |
m/day | meter per day |
md | milli Darcy |
MDa | Million Dalton = million g/mol |
min | minute |
MPa | Million Pascal |
p | Pressure |
PFTE | polytetrafluoroethylene |
ppm | part per million = mg/kg |
PV | pore volume |
rpm | rotation per minute |
s−1 | reciprocal second |
t | time |
TNb | Total nitrogen analyzer |
TOC | Total organic carbon analyzer |
μg/g | micro gram per gram |
µL | micro liter |
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Salt | Concentration, g/L |
---|---|
NaHCO3 | 1.239 |
NaCl | 14.118 |
KCl | 0.592 |
MgCl2 | 0.594 |
CaCl2 | 0.833 |
Water salinity, g/L | 17.38 |
Experiment No. | Average Permeability, md (Helium) | Polymer | Mol. Weight Mean, MDa | Sulfate Degree, % | Concentration at 10 cP @ 7.3 s−1, ppm |
---|---|---|---|---|---|
1 | 346 | A | 18 | - | 900 |
2 | 361 | A | 18 | - | 900 |
3 | 424 | B | 12 | - | 1320 |
4 | 460 | D | 7 | - | 1250 |
5 | 552 | C | 12 | 5 | 1050 |
6 | 1229 | C | 12 | 5 | 1050 |
Formation | PK1-3 |
---|---|
Temperature, °C | 16 |
Rock pressure, MPa | 19 |
Formation pressure, MPa | 7.9 |
Water salinity, g/L | multicomponent composition |
Oil density in atmospheric conditions, g/cm3 | 0.945 |
Oil density in formation conditions, g/cm3 | 0.922 |
Oil viscosity in formation conditions, MPa·s | 111.15 |
Pumping Stages/Parameters | Experiment No. | ||||||
---|---|---|---|---|---|---|---|
1 | 2 | 3 | 4 | 5 | 6 | ||
Absolute permeability, md, average | 346 | 361 | 424 | 460 | 552 | 1229 | |
Polymer, first front | Linear injection rate, m/day | 1 | 2 | 2 | 2 | 2 | 2 |
Injected volume, PV | 3 | 12 | 12 | 12 | 12 | 12 | |
Formation water injection | Linear injection rate, m/day | 2 | 2 (10PV) and 4 (40PV) | 2 (10PV) and 4 (40PV) | 2 (10PV) and 4 (40PV) | 2 (10PV) and 4 (40PV) | 2 (10PV) and 4 (40PV) |
Injected volume, PV | 50 | 50 | 50 | 50 | 50 | 50 | |
Polymer, second front | Linear injection rate, m/day | 1 | 2 | 2 | 2 | 2 | 2 |
Injected volume, PV | 10 | 10 | 10 | 10 | 10 | 10 | |
Formation water injection | Injected volume, PV | 3 | 3 | 3 | 3 | 3 | 3 |
Linear injection rate, m/day | 1 | 2 (2PV) and 4 (1PV) | 2 (2PV) and 4 (1PV) | 2 (2PV) and 4 (1PV) | 2 (2PV) and 4 (1PV) | 2 (2PV) and 4 (1PV) |
Experiment No. | Polymer | Permeability, md | Mol. Mass, MDa | Sulfate Degree, % | Retention (Method 1), µg/g | Retention (Method 2), µg/g | Average Retention, µg/g |
---|---|---|---|---|---|---|---|
1 | A | 346 | 18 | - | NA | NA | NA |
2 | A | 361 | 18 | - | 444 | 436 | 440 |
3 | B | 424 | 12 | - | 385 | 321 | 353 |
4 | D | 460 | 7 | - | 152 | 292 | 222 |
5 | C | 552 | 12 | 5 | 124 | 290 | 207 |
6 | C | 1229 | 12 | 5 | 212 | 93 | 153 |
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Ilyasov, I.; Koltsov, I.; Golub, P.; Tretyakov, N.; Cheban, A.; Thomas, A. Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir. Polymers 2021, 13, 2737. https://doi.org/10.3390/polym13162737
Ilyasov I, Koltsov I, Golub P, Tretyakov N, Cheban A, Thomas A. Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir. Polymers. 2021; 13(16):2737. https://doi.org/10.3390/polym13162737
Chicago/Turabian StyleIlyasov, Ilnur, Igor Koltsov, Pavel Golub, Nikolay Tretyakov, Andrei Cheban, and Antoine Thomas. 2021. "Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir" Polymers 13, no. 16: 2737. https://doi.org/10.3390/polym13162737
APA StyleIlyasov, I., Koltsov, I., Golub, P., Tretyakov, N., Cheban, A., & Thomas, A. (2021). Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir. Polymers, 13(16), 2737. https://doi.org/10.3390/polym13162737