Effect of Oil and Water Interfacial Tension on Oil Recovery of Surfactant-Polymer Flooding

2012 ◽  
Vol 524-527 ◽  
pp. 1798-1801
Author(s):  
You Yi Zhu ◽  
Yi Zhang ◽  
Qing Feng Hou ◽  
Hua Long Liu ◽  
Guo Qing Jian
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Core Flooding ◽  
Physics Simulation ◽  
Low Interfacial Tension ◽  
Incremental Oil Recovery

The oil and water (O/W) interfacial tension affecting on oil recovery of surfactant-polymer (SP) flooding was studied based on Berea core flooding tests. The results of SP flooding physics simulation tests showed that when the O/W interfacial tension decreased, the incremental oil recovery of SP flooding increased accordingly, when the O/W interfacial tension decrease to 5×10-3mN/m level, near the highest oil recovery of SP flooding can be obtained. The SP flooding system with low interfacial tension can obtain 7-15% incremental oil recovery more than that with high IFT system.

Effects of Surfactant Partitioning Coefficient and Interfacial Tension on the Oil Displacement in Low-Tension Polymer Flooding

2021 ◽  
Author(s):  
Mingyan Liu ◽  
Kwanghoon Baek ◽  
Fransico Argüelles Vivas ◽  
Gayan Aruna Abeykoon ◽  
Ryosuke Okuno
Keyword(s):  
Interfacial Tension ◽  
Partition Coefficient ◽  
Oil Recovery ◽  
Partition Coefficients ◽  
Polymer Flooding ◽  
Oil Displacement ◽  
Low Interfacial Tension ◽  
Surface Active ◽  
Low Tension ◽  
Secondary Mode

Abstract Complex surfactant formulations have been applied to generate an ultra-low interfacial tension (IFT) (e.g., 10-3 dyne/cm) between the displacing water phase and the displaced oil phase in chemical enhanced oil recovery (CEOR), where the residual oil after waterflooding can be largely recovered as an oil bank. This paper is concerned with a simpler, lower-cost CEOR, in which a sole additive of surface active solvent (SAS) makes low-tension displacement fronts in polymer flooding (e.g., 10-2 dyne/cm) without involving ultra-low IFT microemulsion phase behavior. The main objective of this research is to technically verify such low-tension polymer (LTP) flooding for a secondary-mode oil displacement through a sandpack of 9.5 Darcy. Previous research found that 2-ethylhexanol-7PO-15EO (2-EH-7PO-15EO, or "7-15") as SAS was able to reduce the IFT between polymer solution and the reservoir oil from 15.8 dyne/cm to 0.025 dyne/cm. In this research, the effect of SAS partition coefficient on LTP flooding was studied as an additional factor for SAS optimization. In particular, the comparison between two SAS species, 2-EH-4PO-15EO (4-15) and 2-EH-7PO-25EO (7-25), was important, because they had similar IFT values, but markedly different partition coefficients. The IFT was 0.18 dyne/cm with 4-15 and 0.20 dynes/cm with 7-25; and the partition coefficients were 1.61 with 4-15 and 0.68 with 7-25 at the experimental temperature, 61°C. These two SAS species were compared in secondary-mode LTP flooding with a slug of 0.5 wt% SAS for 0.5 pore-volumes injected (PVI). The oil recovery factor at 1.0 PVI was 65% with 4-15 and 67% with 7-25. At 5.0 PVI, it was 74% with 4-15 and 84% with 7-25. Although these two SAS species gave comparable IFT values, their oil-displacement efficiencies were quite different because 7-25 propagated more efficiently in the sandpack with the smaller partition coefficient. The smaller partition coefficient helped the SAS flow more efficiently in the aqueous phase with less retention in the remaining oil. Optimization of SAS likely requires taking a balance between lowering the partition coefficient and lowering the IFT. The SAS recovery at the effluent was 61% for the 4-15 SAS and 78% for the 7-25 SAS. The propagation of the 4-15 SAS was retarded approximately by 1.0 PVI in comparison to that of the 7-25 SAS. The adsorption of the 4-15 and 7-25 SAS were 0.019 mg/g sandpack and 0.020 mg/g sandpack. With a similar IFT reduction, the SAS with a smaller partition coefficient (i.e., 7-25) resulted in less retention, less retardation, and more oil production for a given amount of injection.

Ultra-Low Interfacial Tension of a Surfactant under a Wide Range of Temperature and Salinity Conditions for Chemical Enhanced Oil Recovery

2018 ◽  
Vol 55 (3) ◽  
pp. 252-257 ◽  
Author(s):  
Derong Xu ◽  
Wanli Kang ◽  
Liming Zhang ◽  
Jiatong Jiang ◽  
Zhe Li ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Wide Range ◽  
Low Interfacial Tension

scholarly journals Investigation on degradation mechanism of polymer blockages in unconsolidated sandstone reservoirs

e-Polymers ◽  
2020 ◽  
Vol 20 (1) ◽  
pp. 55-60
Author(s):  
Wenting Dong ◽  
Dong Zhang ◽  
Keliang Wang ◽  
Yue Qiu
Keyword(s):  
Oil Recovery ◽  
Degradation Mechanism ◽  
Injection Pressure ◽  
Polymer Flooding ◽  
Core Flooding ◽  
Reservoir Properties ◽  
Thermal Analyzer ◽  
Sandstone Reservoirs ◽  
Suction Index ◽  
Weighing Method

AbstractPolymer flooding technology has shown satisfactorily acceptable performance in improving oil recovery from unconsolidated sandstone reservoirs. The adsorption of the polymer in the pore leads to the increase of injection pressure and the decrease of suction index, which affects the effect of polymer flooding. In this article, the water and oil content of polymer blockages, which are taken from Bohai Oilfield, are measured by weighing method. In addition, the synchronous thermal analyzer and Fourier transform infrared spectroscopy (FTIR) are used to evaluate the composition and functional groups of the blockage, respectively. Then the core flooding experiments are also utilized to assess the effect of polymer plugs on reservoir properties and optimize the best degradant formulation. The results of this investigation show that the polymer adsorption in core after polymer flooding is 0.0068 g, which results in a permeability damage rate of 74.8%. The degradation ability of the agent consisting of 1% oxidizer SA-HB and 10% HCl is the best, the viscosity of the system decreases from 501.7 to 468.5 mPa‧s.

scholarly journals The Demulsification Properties of Cationic Hyperbranched Polyamidoamines for Polymer Flooding Emulsions and Microemulsions

Processes ◽  
2020 ◽  
Vol 8 (2) ◽  
pp. 176 ◽  
Author(s):  
Yangang Bi ◽  
Zhi Tan ◽  
Liang Wang ◽  
Wusong Li ◽  
Congcong Liu ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Oil Removal ◽  
Tertiary Oil Recovery ◽  
Oil Concentration ◽  
Ft Ir ◽  
The Stability ◽  
Excellent Stability ◽  
Demulsification Efficiency

Polymer flooding emulsions and microemulsions caused by tertiary oil recovery technologies are harmful to the environment due to their excellent stability. Two cationic hyperbranched polyamidoamines (H-PAMAM), named as H-PAMAM-HA and H-PAMAM-ETA, were obtained by changing the terminal denotation agents to H-PAMAM, which was characterized by 1H NMR, FT-IR, and amine possession, thereby confirmed the modification. Samples (300 mg/L) were added to the polymer flooding emulsion (1500 mg/L oil concentration) at 30 °C for 30 min and the H-PAMAM-HA and H-PAMAM-ETA were shown to perform at 88% and 91% deoil efficiency. Additionally, the increased settling time and the raised temperature enhanced performance. For example, an oil removal ratio of 97.7% was observed after dealing with the emulsion for 30 min at 60 °C, while 98.5% deoil efficiency was obtained after 90 min at 45 °C for the 300 mg/L H-PAMAM-ETA. To determine the differences when dealing with the emulsion, the interfacial tension, ζ potential, and turbidity measurements were fully estimated. Moreover, diametrically different demulsification mechanisms were found when the samples were utilized to treat the microemulsion. The modified demulsifiers showed excellent demulsification efficiency via their obvious electroneutralization and bridge functions, while the H-PAMAM appeared to enhance the stability of the microemulsion.

scholarly journals Experimental Study on the Physical Performance and Flow Behavior of Decorated Polyacrylamide for Enhanced Oil Recovery

Energies ◽  
2019 ◽  
Vol 12 (3) ◽  
pp. 562 ◽  
Author(s):  
Shuang Liang ◽  
Yikun Liu ◽  
Shaoquan Hu ◽  
Anqi Shen ◽  
Qiannan Yu ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Displacement Effect ◽  
Microscale Model ◽  
Water Cut ◽  
Viscosity Stability

With the rapid growth of energy consumption, enhanced oil recovery (EOR) methods are continually emerging, the most effective and widely used was polymer flooding. However, the shortcomings were gradually exposed. A novel decorated polyacrylamide might be a better alternative than polymer. In this work, the molecular structure and the properties reflecting the viscosity of decorated polyacrylamide, interfacial tension, and emulsification were examined. In order to better understand the interactions between decorated polyacrylamide and oil as well as the displacement mechanism, the displacement experiment were conducted in the etched-glass microscale model. Moreover, the coreflooding comparison experiments between decorated polyacrylamide and polymer were performed to investigate the displacement effect. The statistical analysis showed that the decorated polyacrylamide has excellent characteristics of salt tolerance, viscosity stability, and viscosification like polymer. Besides, the ability to reduce the interfacial tension in order 10−1 and emulsification, which were more similar to surfactant. Therefore, the decorated polyacrylamide was a multifunctional polymer. The displacement process captured by camera illustrated that the decorated polyacrylamide flooded oil mainly by means of ‘pull and drag’, ‘entrainment’, and ‘bridging’, based on the mechanism of viscosifying, emulsifying, and viscoelasticity. The results of the coreflooding experiment indicated that the recovery of decorated polyacrylamide can be improved by approximately 11–16% after water flooding when the concentration was more than 800 mg/L, which was higher than that of conventional polymer flooding. It should be mentioned that a new injection mode of ‘concentration reduction multi-slug’ was first proposed, and it obtained an exciting result of increasing oil production and decreasing water-cut, the effect of conformance control was more significant.

Non-Edible Oil Based Surfactant For Enhanced Oil Recovery

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Ijoma Onyemaechi
Keyword(s):  
Methyl Ester ◽  
Sodium Hydroxide ◽  
Sodium Carbonate ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Synthetic Surfactant ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Incremental Oil Recovery ◽  
Increasing Demand

Abstract After the primary and secondary oil recoveries, a substantial amount of oil is left in the reservoir which can be recovered by tertiary methods like the Alkaline-Surfactant Flood. Reasons for having some unproduced hydrocarbon in the reservoir include and not limited to the following; forces of attraction fluid contacts, low permeability, high viscous fluid, poor swept efficiency, etc. Although, it is possible to commence waterflooding together chemical injection at the start of production. Reservoir simulation with commercial simulator, could guide in selecting the most appropriate period to commence chemical flooding. In this study, the performance of a new synthetic surfactant produced from Jatropha Curcas seed was compared with that of a selected commercial surfactant in the presence of an alkaline and this shows that the non-edible Jatropha oil is a natural, inexpensive and a renewable source of energy for the production of anionic surfactants and a good substitute for commercial surfactants like Sodium Dodecyl Sulphate (SDS). The Methyl Ester Sulfonate (MES) surfactant showed no precipitation or cloudiness during stability test and was able to reduce the Interfacial Tension (IFT) to 0.018 mN/m and 0.020 mN/m in the presence of sodium carbonate and sodium hydroxide respectively as alkaline at low surfactant concentration. The optimum alkaline surfactant formulation in terms of oil recovery performance obtained from the core flooding experiment corresponds to a concentration of sodium carbonate (0.5wt%), sodium hydroxide (0.5wt%) mixed in distilled water and Methyl Ester Sulfonate (MES) surfactant (1wt%). The injection of 0.5 percentage volume of alkaline surfactant slug produced an incremental oil recovery of 26.7% and 29% respectively. With these incremental oil recoveries, increasing demand for hydrocarbons product could be met, and returns on investment portfolio will be improved.

Analyzing the Influence of Salinity on Produced Water Re-Injection

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Chimgozirim Prince Ejim
Keyword(s):  
Oil Recovery ◽  
Produced Water ◽  
Core Sample ◽  
Production Performance ◽  
Core Flooding ◽  
Daily Rate ◽  
Reservoir Conditions ◽  
Cumulative Production ◽  
Water Disposal ◽  
Incremental Oil Recovery

Abstract Produced water reinjection (PWRI) is one of the methods employed by oilfield operators to optimize production while conforming to increasingly stringent produced water disposal policies. Different produced water species from different facilities also have different salinities as a result of entrainment of treatment fluids, precipitation of salts at surface conditions, etc. During re-injection operations, the salinity of the injection fluid has to be accounted for as it affects the production. Previous studies have focused on laboratory analysis by core flooding. While this approach is indeed reasonable and offers a first-hand impression of the reservoir conditions, it presents a problem of cost and the age-old opinion that the core sample may not be representative of the entire reservoir. Therefore, I have employed a computer modeling approach using a commercial simulator to analyze the influence of salinity on production during produced water re-injection. It was found that the salinity truly affects production. Re-injection of produced water with salinity equal to the reservoir salinity of 1000 ppm was compared to three cases of re-injection of produced water from extraneous sources having salinities of 100 ppm, 500 ppm and 10000 ppm. It was found that salinity of 10000 ppm gave the best oil production performance for the reservoir model; a daily rate of 40 STB/DAY and an oil cumulative production of 40,000 STB. Incremental salinity of injected produced water led to incremental oil recovery. The mechanism resulting in incremental recovery was attributed to the increase in viscosity and decrease in mobility as the salinity increases.

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