Surfactant–Polymer Formulation for Chemical Flooding in Oil Reservoirs
Abstract
:1. Introduction
- -
- When there is an unfavourable mobility ratio between oil and water;
- -
- When the mobility ratio is favourable but the oil viscosity is low in reservoirs with a certain degree of heterogeneity.
- (1)
- Reduction ininterfacial tension (IFT) at the oil–water interface;
- (2)
- Alteration of rock wettability.
2. Materials and Methods
2.1. Experimental Materials and Equipment
2.1.1. Polymer and Surfactant Samples
- 1.
- Anionic surfactants based on sodium alkylbenzene sulfonate, diethanolamide of lauric acid, sodium laureth sulphate, dodecylbenzene sulfonate, and alpha-olefin sulfonate;
- 2.
- Amphoteric surfactants based on betaine and oleyl betaine.
2.1.2. Brine Model
2.1.3. Core Samples and Oil Samples
2.1.4. Experimental Equipment
2.2. Experimental Methods
2.2.1. Requirements for Polymers and Experimental Methodology
- Compatibility with the reservoir water (absence of lumps or precipitates during solution preparation). The methodology is based on the periodic visual assessment of polymer powder dissolution during solution preparation. As the polymer dissolves, the solution becomes homogeneous, and no polymer particles should remain. The acceptable dissolution time should not exceed 240 min.
- Rheological properties, specifically achieving maximum solution viscosity at minimum concentration. The methodology involves measuring the viscosity of polymer solutions at various spindle rotation speeds (shear rates) using a rotational viscometer.
- Resistance to mechanical degradation. The mechanical stability coefficient is calculated as the ratio of the viscosity of the degraded solution to the original solution. The mechanical stability coefficient should be above 0.85. The methodology involves measuring the viscosity of the polymer solution before and after vigorous stirring using a paddle mixer at high rotation speeds (2000 rpm and above).
- Thermal stability of polymers. This is determined as the ratio of the viscosity of the solution after heating and prolonged exposure to the viscosity of the original solution at reservoir temperature. The thermal stability coefficient should be above 0.85.
- Compatibility of polymer molecular weight with the reservoir properties. Given the poor reservoir properties (low-permeability zones), the polymer formulation must ensure an appropriate flow level (no excessive plugging). The key factor influencing the free flow of the polymer solution is its molecular weight. According to the information presented in [8], an empirical correlation between the number–average molecular weight and the absolute permeability of the rock has been proposed and is presented in Table 6.
2.2.2. Requirements for the Surfactant
- Good solubility in water under standard (20 °C) and reservoir conditions. The methodology is based on a visual assessment of the solution’s appearance during mixing. Some surfactants form cloudy solutions when dissolved, and in some cases, salting out or precipitation of the surfactant may occur (Figure 2). The criterion for surfactant solubility is the preservation of solution transparency for at least 3 days.
- 2.
- Ensuring a consistently low level of IFT for dispersing trapped oil and washing residual oil films from the rock. Two approaches are used to evaluate the reduction in IFT. The first method is based on assessing the phase behavior of surfactant solutions and oil (determining Winsor types), a rapid method. The second method involves a quantitative assessment of IFT in mN/m using the spinning drop method, a more accurate evaluation method.
- 3.
- Low level of adsorption on the rock. The methodology involves keeping surfactant solutions in contact with the rock (with periodic stirring) for 2 days in a thermal chamber at reservoir temperature (57 °C). After this period, the solutions are separated from the rock by centrifugation, and the residual surfactant concentration in the solution is measured. In this case, concentrations are determined indirectly, based on the dependence on interfacial tension.
- 4.
- Stability of the surfactant solution across various temperature and salinity ranges. The methodology involves measuring IFT using the spinning drop method at different temperatures and salinities.
3. Results and Discussions
3.1. Polymer Studies
3.1.1. Evaluation of Polymer Solubility
3.1.2. Rheological Curves for Polymer Samples
3.1.3. Studies on the Mechanical and Thermal Stability of Polymers
3.1.4. Evaluation of Polymer Solutions Flowability in Porous Media
- Water injection before polymer solution injection;
- Polymer solution injection;
- Water injection after polymer solution injection.
3.2. The Study of Surfactant Properties
3.2.1. Evaluation of Surfactant Solubility
3.2.2. Evaluation of Phase Behavior
3.2.3. Study of IFT Dependence on Surfactant Concentration
3.2.4. Studies of Static Surfactant Adsorption
3.3. Studies on the Surfactant–Polymer Formulation
3.3.1. Influence of Surfactant and Polymer Concentration on the Key Properties of the Formulation
3.3.2. Core Flooding Studies of the Surfactant–Polymer Formulation
- Water injection before polymer solution injection;
- Polymer solution injection;
- Surfactant–polymer solution injection.
4. Conclusions
- In the West Siberian Oil and Gas Province, there are currently a lot of mature development oil fields where the implementation of chemical EOR methods, particularly surfactant–polymer flooding, becomes relevant.
- To develop an effective surfactant–polymer composition that retains its properties under the given geological and physical conditions, and ensures an increase in the oil displacement coefficient, criteria were established, and a laboratory research program was proposed.
- To improve oil recovery from heterogeneous terrigenous reservoirs during water flooding, a composition was developed consisting of an aqueous solution of an anionic surfactant (sodium laureth sulphate, with ethyl alcohol as a solvent) at a concentration of 0.7 wt.% and partially hydrolysed polyacrylamide (of medium molecular weight, including 5 wt.% sulfonated monomeric additives) at a concentration of 0.15 wt.%.
- The addition of an anionic surfactant (sodium laureth sulphate) at a concentration of 0.7 wt.% and partially hydrolysed polyacrylamide (of medium molecular weight, including 5% sulfonated monomeric additives) at a concentration of 0.15 wt.% to the injected water reduces the interfacial tension at the “surfactant-polymer solution-oil” interface to 0.065 mN/m and increases the effective viscosity of the injected agent to 4.36 mPa·s (at a shear rate of 122.3 s−1 and a temperature of 57 °C).
- When injecting the surfactant–polymer composition, the capillary number increases by 4500 times (with a reduction in interfacial tension from 32.77 mN/m to 0.065 mN/m and an increase in the viscosity of the injected agent from 0.5 mPa·s to 4.36 mPa·s).
- The developed surfactant–polymer composition increases the oil displacement coefficient from the core sample by 0.15–0.24. Thus, the proposed composition can be recommended for application in water flooding at the target reservoir.
- Current research involves hydrodynamic modelling incorporating laboratory-derived parameters. The simulation results will inform the technology implementation design (including well patterns and pore volume injection requirements), with subsequent field deployment planned by the operator at a pilot reservoir.
Author Contributions
Funding
Data Availability Statement
Conflicts of Interest
References
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№ | Field, Country | Technology | Reservoir Type | Temperature, °C | Oil Viscosity, | Salinity, | Permeability, | Porosity | Results |
---|---|---|---|---|---|---|---|---|---|
1 | Romashkino Russia [50] | SP | Sandstone | 25 | 30 | 240 | 1300 | 0.23 | Pilot is being carried out |
2 | Kharyaga Russia [51] | SP | Carbonate | 62 | 0.8–1.1 | 200 | 300 | 0.09 | Pilot preparation |
3 | Daqing China [52] | SP | Sandstone | 52 | 12 | 6 | 1400 | 0.26 | Increase in oil production from 0.2 mt/y to 4.06 mt/y |
4 | Zhongyuan China [53] | SP | Not given | 80–90 | Not given | 120 | 716 | Not given | Increase in recovery factor by 13.7% |
5 | Jilin China [54] | SP | Not given | 55 | Not given | 14 | 163 | Not given | Increase in recovery factor by 14.8% |
6 | Liaohe China [55] | SP | Not given | 55 | Not given | 3.5 | 285.9 | Not given | Increase in recovery factor by 15.4% |
7 | Changqing China [56] | SP | Not given | 51 | Not given | 12–26 | 67 | Not given | Increase in recovery factor by 15.1% |
8 | Dagang China [57] | SP | Not given | 53 | Not given | 13.45 | 675 | Not given | Increase in recovery factor by 13.0% |
9 | Algyo Hungary [58] | SP | Sandstone | 98 | 0.64 | 0.15 | 70 | 0.23 | Not given |
Polymer | Intrinsic Viscosity, dL/g | ATBS Content, %% | Hydrolysis Degree, % | Molecular Weight, 106 Da |
---|---|---|---|---|
FP 3230S | 16.21 | 0 | 30 | 7.3 |
FP 3330S | 18.3 | 0 | 30 | 9.3 |
FP 3630S | 27.62 | 0 | 30 | 20.3 |
FP 5205 SH | 20.61 | 5 | 20 | 12.7 |
FP 5205 VHM | 23.32 | 5 | 20 | 16.1 |
FP 5115 SH | 19.84 | 15 | 20 | 11.8 |
Surfactant | Type | Chemical Formula |
---|---|---|
Sodium Alkylbenzene Sulfonate | Anionic | C12H25C6H4SO3Na |
Sodium Alkylbenzene Sulfonate | Anionic | C16H33C6H4SO3Na |
Diethanolamide of Lauric Acid | Anionic | C16H33NO3 |
Sodium Laureth Sulfate | Anionic | CH3(CH2)11(CH2CH2O)2SO3Na |
Dodecylbenzene Sulfonate | Anionic | CH3(CH2)10CH2-SO3Na |
Alpha-Olefin Sulfonate | Anionic | C14H27SO3Na |
Betaine | Amphoteric | C5H11NO2 |
Oleyl Betaine | Amphoteric | C22H43NO2 |
Parameter | Value |
---|---|
Ca2+, mg/L | 940.0 |
Mg2+, mg/L | 96.0 |
Na++K+, mg/L | 7753.1 |
Cl−, mg/L | 13,736.88 |
HCO3−, mg/L | 268.4 |
SO2−, mg/L | 1.26 |
№ | Sample Length, cm | Diameter of the Sample, cm | Porosity, % | Permeability, µm2 | Mass of the Dry Sample, g | The Mass of the Sample Saturated with Oil, g | Oil Volume, mL | Sample Volume, cm3 |
---|---|---|---|---|---|---|---|---|
Core samples for core flooding studies of polymer solutions | ||||||||
1 | 3.42 | 2.98 | 22.43 | 0.193 | 47.45 | 52.11 | 5.35 | 23.85 |
2 | 3.37 | 3.01 | 21.48 | 0.172 | 48.05 | 52.54 | 5.15 | 23.98 |
3 | 3.18 | 2.99 | 23.24 | 0.191 | 45.25 | 49.77 | 5.19 | 22.33 |
4 | 3.24 | 2.97 | 23.43 | 0.189 | 44.9 | 49.48 | 5.26 | 22.45 |
Core samples for core flooding studies surfactant polymer solutions | ||||||||
1 | 3.37 | 3.02 | 22.12 | 0.075 | 49.15 | 53.8 | 5.34 | 24.14 |
2 | 3.17 | 3.00 | 24.5 | 0.116 | 48.94 | 53.72 | 5.49 | 22.41 |
3 | 3.07 | 3.01 | 25.63 | 0.069 | 48.86 | 53.74 | 5.6 | 21.85 |
Average Molecular Weight, Million Da | Absolute Permeability, µm2 |
---|---|
>20 | 1 |
18–20 | 0.75 |
15–18 | 0.5 |
12–15 | 0.35 |
8–12 | 0.2 |
5–8 | 0.1 |
1–5 | 0.01 |
Polymer | Dissolution Time, min |
---|---|
FP 3230S | 60 |
FP 3330S | 90 |
FP 3630S | 160 |
FP 5205 SH | 120 |
FP 5205 VHM | 140 |
FP 5115 SH | 110 |
Parameter | FP 3230 | FP 3330 | FP 3630S | FP 5205 SH | FP 5205 VHM | FP 5115 SH |
---|---|---|---|---|---|---|
Initial Concentration, wt.% | 0.23 | 0.23 | 0.15 | 0.175 | 0.15 | 0.18 |
Viscosity of Initial Solution, mPa·s | 9.9 | 9.8 | 10.3 | 10.2 | 10.1 | 9.7 |
Viscosity of Degraded Solution, mPa·s | 8.9 | 8.7 | 8.8 | 9.3 | 9.1 | 9.1 |
Mechanical Stability Coefficient | 0.90 | 0.89 | 0.85 | 0.91 | 0.90 | 0.94 |
Parameter | FP 3230 | FP 3330 | FP 3630S | FP 5205 SH | FP 5205 VHM | FP 5115 SH |
---|---|---|---|---|---|---|
Viscosity of Initial Solution, mPa·s | 9.80 | 9.70 | 10.30 | 10.20 | 10.10 | 9.70 |
Viscosity of Degraded Solution, mPa·s | 8.70 | 8.20 | 8.00 | 9.60 | 9.40 | 9.40 |
Thermal Stability Coefficient | 0.89 | 0.84 | 0.78 | 0.94 | 0.93 | 0.97 |
№ | Polymer Sample | Concentration, wt.% | Effective Viscosity (7.34 s-1.57 °C), mPa·s |
---|---|---|---|
1 | FP 3630 S | 0.15 | 9.8 |
2 | FP 5205 VHM | 0.15 | 9.9 |
3 | FP 5205 SH | 0.175 | 10.1 |
4 | FP 3230 S | 0.23 | 9.9 |
Parameter | Exp. 1 | Exp. 2 | Exp. 3 | Exp. 4 |
---|---|---|---|---|
Core Sample Length and Diameter, cm | 3.2/2.98 | 3.37/3.01 | 3.18/2.99 | 3.24/2.97 |
Core Sample Porosity, % | 22.43 | 21.48 | 23.23 | 23.43 |
Core Sample Permeability, µm2 | 0.193 | 0.172 | 0.191 | 0.190 |
Polymer Sample | FP 3630S | FP 5205 VHM | FP 5205 SH | FP 3230 S |
Concentration, wt.% | 0.15 | 0.15 | 0.175 | 0.23 |
Effective Viscosity, mPa·s | 9.8 | 9.9 | 10.1 | 9.9 |
Displaced Oil Volume (by Water), mL | 2.6 | 2.65 | 2.70 | 2.9 |
Displacement Coefficient (by Water) | 0.49 | 0.51 | 0.52 | 0.55 |
Displaced Oil Volume (with Polymer), mL | 2.9 | 3.00 | 3.25 | 3.35 |
Displacement Coefficient (by Polymer) | 0.54 | 0.58 | 0.63 | 0.64 |
Increase in Displacement Coefficient | 0.06 | 0.07 | 0.11 | 0.09 |
Resistance Factor (RF) | 43.91 | 33.02 | 19.51 | 12.73 |
Residual Resistance Factor (RRF) | 8.35 | 4.17 | 3.88 | 4.86 |
Surfactant | Solubility | |||
---|---|---|---|---|
1 h | 1 Day | 2 Day | 3 Day | |
Sodium Alkylbenzene Sulfonate | Soluble | Sediment | Sediment | Sediment |
Sodium Alkylbenzene Sulfonate | Soluble | Sediment | Sediment | Sediment |
Diethanolamide of Lauric Acid | Soluble | Soluble | Opalescence | Opalescence |
Sodium Laureth Sulphate | Soluble | Soluble | Soluble | Soluble |
Dodecylbenzene Sulfonate | Opalescence | Opalescence | Opalescence | Opalescence |
Alpha-Olefin Sulfonate | Soluble | Soluble | Soluble | Soluble |
Betaine | Soluble | Soluble | Soluble | Soluble |
Oleyl Betaine | Soluble | Soluble | Soluble | Soluble |
Surfactant Type | Emulsion Type | Interfacial Tension, mN/m | Observation |
---|---|---|---|
Sodium Laureth Sulphate | Type IV | 0.001–0.0001 | Forms emulsion |
Oleyl Betaine | None | - | No emulsion |
Diethanolamide of Lauric Acid | None | - | No emulsion |
Betaine | Type II | 0.1–0.001 | Forms emulsion |
Dodecylbenzene Sulfonate | Type IV | 0.001–0.0001 | Forms emulsion |
Alpha-Olefin Sulfonate | None | - | No emulsion |
Sodium Laureth Sulfate | Betaine | Dodecylbenzene Sulfonate | ||||||
---|---|---|---|---|---|---|---|---|
Concentration, wt.% | IFT, mN/m | Temperature, °C | Concentration, wt.% | IFT, mN/m | Temperature, °C | Concentration, wt.% | IFT, mN/m | Temperature, °C |
0.1 | 0.2312 | 56.9 | 0.1 | 0.07361 | 56.8 | 0.1 | 0.47011 | 56.9 |
0.25 | 0.1154 | 56.8 | 0.25 | 0.06422 | 56.9 | 0.25 | 0.37612 | 56.9 |
0.4 | 0.04988 | 56.9 | 0.4 | 0.05423 | 57.0 | 0.4 | 0.11211 | 56.8 |
0.45 | 0.02298 | 56.9 | 0.5 | 0.03599 | 57.0 | 0.5 | 0.09691 | 56.9 |
0.5 | 0.01649 | 57.0 | 0.6 | 0.02211 | 56.9 | 0.6 | 0.08612 | 56.9 |
0.7 | 0.01512 | 56.9 | 0.7 | 0.01923 | 56.8 | 0.7 | 0.08514 | 56.9 |
1 | 0.01462 | 56.9 | 1 | 0.02017 | 56.9 | 1 | 0.03499 | 57.0 |
2 | 0.01407 | 56.9 | 2 | 0.01892 | 56.9 | 2 | 0.03511 | 57.0 |
Parameter | Sodium Laureth Sulphate | Betaine |
---|---|---|
Initial Mass of Solution, g | 51.25 | 48.11 |
Concentration, wt.% | 0.50 | 0.60 |
IFT of Initial Solution, mN/m | 0.01649 | 0.02211 |
IFT of Solution After Contact with Rock, mN/m | 0.10912 | 0.05012 |
Final Surfactant Solution Concentration, wt.% | 0.28 | 0.41 |
Static Surfactant Adsorption, µg/g | 1127.5 | 914.1 |
Parameter | Exp. 1 | Exp. 2 | Exp. 3 |
---|---|---|---|
Core Sample Length and Diameter, cm | 3.37/3.02 | 3.17/3.00 | 3.07/3.01 |
Core Sample Porosity, % | 22.12 | 24.5 | 25.63 |
Core Sample Permeability, µm2 | 0.075 | 0.116 | 0.069 |
Concentration of Polymer, wt.% | 0.15 | 0.15 | 0.15 |
Concentration of Surfactant, wt.% | 0.7 | 0.7 | 0.7 |
Displaced Oil Volume (by Water), mL | 2.9 | 3.1 | 2.1 |
Displacement Coefficient (by Water) | 0.54 | 0.56 | 0.37 |
Displaced Oil Volume (with Polymer), mL | 0.5 | 0.6 | not evaluated |
Displacement Coefficient (by Polymer) | 0.63 | 0.67 | not evaluated |
Increase in Displacement Coefficient (Polymer) | 0.09 | 0.11 | not evaluated |
RF (polymer) | 11.39 | 8,05 | not evaluated |
Displaced Oil Volume (SP), mL | 1.2 | 1.3 | 0.85 |
Displacement Coefficient (SP) | 0.86 | 0.91 | 0.53 |
Increase in Displacement Coefficient (SP) | 0.22 | 0.24 | 0.15 |
RF (SP) | 8.62 | 5.24 | 1.27 |
RRF (SP) | not evaluated | 0.96 |
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Podoprigora, D.; Rogachev, M.; Byazrov, R. Surfactant–Polymer Formulation for Chemical Flooding in Oil Reservoirs. Energies 2025, 18, 1814. https://doi.org/10.3390/en18071814
Podoprigora D, Rogachev M, Byazrov R. Surfactant–Polymer Formulation for Chemical Flooding in Oil Reservoirs. Energies. 2025; 18(7):1814. https://doi.org/10.3390/en18071814
Chicago/Turabian StylePodoprigora, Dmitriy, Mikhail Rogachev, and Roman Byazrov. 2025. "Surfactant–Polymer Formulation for Chemical Flooding in Oil Reservoirs" Energies 18, no. 7: 1814. https://doi.org/10.3390/en18071814
APA StylePodoprigora, D., Rogachev, M., & Byazrov, R. (2025). Surfactant–Polymer Formulation for Chemical Flooding in Oil Reservoirs. Energies, 18(7), 1814. https://doi.org/10.3390/en18071814