A comparison of foam stability at varying salinities and surfactant concentrations using bulk foam tests and sandpack flooding

Nasr, Negar Hadian; Mahmood, Syed Mohammad; Akbari, Saeed; Hematpur, Hamed

doi:10.1007/s13202-019-0707-9

Cited by 17 publications

(4 citation statements)

References 33 publications

(34 reference statements)

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“…Increase in foam stability due to a decrease in the foam collapse rate in saline surfactant solutions has been shown in experimental studies using bubble columns, but the bubbles size and initial foam volume decrease (Varade and Ghosh 2017;Behera et al 2014;Nasr et al 2020). For each type of surfactant solution, there is a limiting salinity, above which the lamellas rupture.…”

Section: Impact Of Salinity On Foamability and Foam Stabilitymentioning

confidence: 89%

Effects of water salinity on the foam dynamics for EOR application

Rudyk

Al-Khamisi

Al-Wahaibi

2021

J Petrol Explor Prod Technol

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Factors limiting foam injection for EOR application are exceptionally low rock permeability and exceedingly high salinity of the formation water. In this regard, foam formation using internal olefin sulfonate is investigated over a wide salinity range (1, 5, 8, 10, and 12% NaCl) through 10 mD limestone. The relationships between pressure drop (dP), apparent viscosity, liquid flow rate, total flow rate, salinity, foam texture, and length of foam drops at the outlet used as an indicator of viscosity are studied. Foaming is observed up to 12% NaCl, compared to a maximum of 8% NaCl in similar core-flooding experiments with 50 mD limestone and 255 mD sandstone. Thus, the salinity limit of foam formation has increased significantly due to the low permeability, which can be explained by the fact that the narrow porous system acts like a membrane with smaller holes. Compared to the increasing dP reported for highly permeable rocks, dP linearly decreases in almost the entire range of gas fraction (fg) at 1–10% NaCl. As fg increases, dP at higher total flow rate is higher at all salinities, but the magnitude of dP controls the dependence of apparent viscosity on total flow rate. Low dP is measured at 1% and 10% NaCl, and high dP is measured at 5, 8, and 12% NaCl. In the case of low dP, the apparent viscosity is higher at higher total flow rate with increasing gas fraction, but similar at two total flow rates with increasing liquid flow rate. In the case of high dP, the apparent viscosity is higher at lower total flow rate, both with an increase in the gas fraction and with an increase in the liquid flow rate. A linear correlation is found between dP or apparent viscosity and liquid flow rate, which defines it as a governing factor of foam flow and can be considered when modeling foam flow.

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Section: Impact Of Salinity On Foamability and Foam Stabilitymentioning

confidence: 89%

Effects of water salinity on the foam dynamics for EOR application

Rudyk

Al-Khamisi

Al-Wahaibi

2021

J Petrol Explor Prod Technol

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“…They found that as the temperature increased, the foam quality factor decreased, indicating reduced foam stability. Nagar Nadia Nasr et al [110] conducted a comparative study on foam stability, investigating the impact of salinity and surfactant concentrations through bulk foam tests and sandpack flooding. They used the mixed anionic and amphoteric surfactant MFOMAX with pure nitrogen.…”

Section: Value Of L E S Foam Stability To Oilmentioning

confidence: 99%

Optimizing Oil Recovery: A Comprehensive Review of Foam Applications in Enhanced Oil Recovery.

SAKHI

2024

Preprint

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As global oil demand continues to rise and operators scale back on exploration investments, the adoption of enhanced oil recovery (EOR) technology is becoming increasingly essential. This approach strategically aims to optimize reserves in existing fields, maximizing production through efficient processes. In recent years, there has been a notable surge in the adoption of foam applications in EOR. These foam applications are particularly effective in managing gas mobility in injector wells and preventing gas blockages in production wells. The use of foam has proven to be an effective method for addressing reservoir heterogeneity concerns, including viscosity fingering, gravity segregation, and channeling. These solutions maintain operational stability while improving the efficiency of oil recovery. However, persistent challenges remain ongoing, such as foam solution quality, foamability, stability under high pressures and temperatures, and interactions with the oil phase. Thus, ongoing research and development are crucial to overcome these challenges and optimize the use of foam in enhanced oil recovery. This paper aims to comprehensively review and synthesize the most pertinent studies on foam-based enhanced oil recovery (EOR). The study thoroughly investigates the factors that affect foam stability and efficiency, offering a comprehensive understanding of foam generation in porous media. The paper review identifies knowledge gaps and proposes methods to incorporate physical understandings of experiments into assessments of foam project performance. The paper explores the applications of foam in laboratory and field settings, highlighting recent advancements in improving foam stability.

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“…37 Figure 17 shows that with the increase of salinity, the liquid carrying rate of UT-6 gradually decreased, and when the salinity increased to 80 000 mg/L, the liquid carrying rate of UT-6 could still reach 70.2%, indicating that UT-6 had the liquid carrying capacity to meet the production requirements when the salinity was 80 000 mg/L. 38 3.6. Surface Tension Reduction Capacity.…”

Section: Dynamic Liquid Carrying Capacitymentioning

confidence: 99%

Study on Screening and Evaluation of Foam Drainage Agents for Gas Wells with High Temperature and High Pressure

et al. 2023

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Foam drainage gas recovery technology is a chemical method to solve the serious bottom-hole liquid loading in the middle and late stages of gas well production, and the optimization of foam drainage agents (referred to as FDAs) is the key to the technology. According to the actual reservoir conditions, a high-temperature and high-pressure (HTHP) evaluation device for FDAs was set up in this study. The six key properties of FDAs, such as HTHP resistance, dynamic liquid carrying capacity, oil resistance, and salinity resistance, were evaluated systematically. Taking initial foaming volume, half-life, comprehensive index, and liquid carrying rate as evaluation indexes, the FDA with the best performance was selected and the concentration was optimized. In addition, the experimental results were verified by surface tension measurement and electron microscopy observation. The results showed that the sulfonate compound surfactant (UT-6) had good foamability, excellent foam stability, and better oil resistance at high temperature and high pressure. In addition, UT-6 had stronger liquid carrying capacity at a lower concentration, which could meet the production requirement when the salinity was 80 000 mg/L. Therefore, compared with the other five FDAs, UT-6 was more suitable for HTHP gas wells in block X of the Bohai Bay Basin, whose optimal concentration was 0.25 wt %. Interestingly, the UT-6 solution had the lowest surface tension at the same concentration, with the generated bubbles being closely arranged and uniform in size. Moreover, in the UT-6 foam system, the drainage speed at the plateau boundary was relatively slower with the smallest bubble. It is expected that UT-6 will become a promising candidate for foam drainage gas recovery technology in HTHP gas wells.

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A comparison of foam stability at varying salinities and surfactant concentrations using bulk foam tests and sandpack flooding

Cited by 17 publications

References 33 publications

Effects of water salinity on the foam dynamics for EOR application

Effects of water salinity on the foam dynamics for EOR application

Optimizing Oil Recovery: A Comprehensive Review of Foam Applications in Enhanced Oil Recovery.

Study on Screening and Evaluation of Foam Drainage Agents for Gas Wells with High Temperature and High Pressure

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