Low-salinity waterflooding is a relatively new method for improved oil recovery that has generated much interest. It is generally believed that low-salinity brine alters the wettability of oil reservoir rocks towards a wetting state that is optimal for recovery. The mechanism(s) by which the wettability alteration occurs is currently an unsettled issue. This paper reviews recent studies on wettability alteration mechanisms that affect the interactions between the brine/oil and brine/rock interfaces of thin brine films that wet the surface of reservoir rocks. Of these mechanisms, we pay particular attention to double-layer expansion, which is closely tied to an increase in the thickness and stability of the thin brine films. Our review examines studies on both sandstones and carbonate rocks. We conclude that the thin-brine-film mechanisms provide a good qualitative, though incomplete, picture of this very complicated problem. We give suggestions for future studies that may help provide a more quantitative and complete understanding of low-salinity waterflooding.

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Thin liquid films in improved oil recovery from low-salinity brine

Recently, low salinity brine injection has been given a great interest as a technique for enhanced oil recovery (EOR) by waterflooding. Varying experimental results have been reported in the literature, from many promising results to limited or no effects of low salinity. The application of low salinity water in combination with other established EOR processes (e.g., surfactant flooding and polymer flooding) is of great interest. The combined processes involve dampening capillarity to avoid trapping of mobilized oil, reducing residual oil saturation (Sor), and altering frontal stability and sweep. In this article, we address the questions of timing of LS injection and the added benefit of polymer injection. Secondary-mode (at initial water saturation) and tertiary-mode (after seawater residual oil saturation) low salinity waterflooding experiments were performed on outcrop Berea sandstone core material. The main results are the oil recovery efficiencies of these two different flooding modes. These results...

Enhanced Oil Recovery (EOR) by Combined Low Salinity Water/Polymer Flooding

Chemical enhanced oil recovery is another strong growing technology with the potential of a step change innovation, which will help to secure future oil supply by turning resources into reserves. While Substantial amount of crude oil remains in the reservoir after primary and secondary production, conventional production methods give access to on average only one-third of original oil in place, the use of surfactants and polymers allows for recovery of up to another third of this oil. Chemical flooding is of increasing interest and importance due to high oil prices and the need to increase oil production. Research in nanotechnology in the petroleum industry is advancing rapidly and an enormous progress in the application of nanotechnology in this area is to be expected. Nanotechnology has the potential to profoundly change enhanced oil recovery and to improve mechanism of recovery. This paper, therefore, focuses on the reviews of the application of nano technology in chemical flooding process in oil recovery and reviews the application nano in the polymer and surfactant flooding on the interfacial tension process.

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A review on applications of nanotechnology in the enhanced oil recovery part A: effects of nanoparticles on interfacial tension

Evidence, mechanisms and improved understanding of controlled salinity waterflooding part 1: Sandstones ☆

Recent advances in application of nanotechnology in chemical enhanced oil recovery: Effects of nanoparticles on wettability alteration, interfacial tension reduction, and flooding

Polymer flooding is one of the most successful chemical EOR (enhanced oil recovery) methods, and is primarily implemented to accelerate oil production by sweep improvement. However, additional benefits have extended the utility of polymer flooding. During the last decade, it has been evaluated for use in an increasing number of fields, both offshore and onshore. This is a consequence of (1) improved polymer properties, which extend their use to HTHS (high temperature high salinity) conditions and (2) increased understanding of flow mechanisms such as those for heavy oilmobilization. A key requirement for studying polymer performance is the control and prediction of in-situ porous medium rheology. The first part of this paper reviews recent developments in polymer flow in porous medium, with a focus on polymer in-situ rheology and injectivity. The second part of this paper reports polymer flow experiments conducted using the most widely applied polymer for EOR processes, HPAM (partially hydrolyzed polyacrylamide). The experiments addressed highrate, near-wellbore behavior (radial flow), reservoir rate steady-state flow (linear flow) and the differences observed in terms of flow conditions. In addition, the impact of oil on polymer rheology was investigated and compared to single-phase polymer flow in Bentheimer sandstone rock material. Results show that the presence of oil leads to a reduction in apparent viscosity.

Polymer Flow in Porous Media: Relevance to Enhanced Oil Recovery

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Wettability and Oil Recovery by Low Salinity Injection

Polymer flooding is an established enhanced oil recovery (EOR) method; still, many aspects of polymer flooding are not well understood. This study investigates the influence of mechanical degradation on flow properties of polymers in porous media. Mechanical degradation due to high shear forces may occur in the injection well and at the entrance to the porous media. The polymers that give high viscosity yields at a sustainable economic cost are typically large, MW > 10 MDa, and have wide molecular weight distributions. Both MW and the distributions are altered by mechanical degradation, leading to changes in the flow rheology of the polymer. The polymer solutions were subjected to different degrees of pre-shearing and pre-filtering before injected into Bentheimer outcrop sandstone cores. Rheology studies of injected and produced polymer solutions were performed and interpreted together with in situ rheology data. The core floods showed a predominant shear thickening behavior at high flow velocities, which is due to successive contraction/expansion flow in pores. When pre-sheared, shear thickening was reduced but with no significant reduction in in situ viscosity at lower flow rates. This may be explained by reduction in the extensional viscosity. Furthermore, the results show that successive degradation occurred which suggests that the assumption of the highest point of shear that determines mechanical degradation in a porous media does not hold for all field relevant conditions.

Impact of Mechanical Degradation on Polymer Injectivity in Porous Media.

Water soluble polymers have attracted increasing interest in enhanced oil recovery (EOR) processes, especially polymer flooding. Despite the fact that the flow of polymer in porous medium has been a research subject for many decades with numerous publications, there are still some research areas that need progress. The prediction of polymer injectivity remains elusive. Polymers with similar shear viscosity might have different in-situ rheological behaviors and may be exposed to different degrees of mechanical degradation. Hence, determining polymer in-situ rheological behavior is of great significance for defining its utility. In this study, an investigation of rheological properties and mechanical degradation of different partially hydrolyzed polyacrylamide (HPAM) polymers was performed using Bentheimer sandstone outcrop cores. The results show that HPAM in-situ rheology is different from bulk rheology measured by a rheometer. Specifically, shear thickening behavior occurs at high rates, and near-Newtonian behavior is measured at low rates in porous media. This deviates strongly from the rheometer measurements. Polymer molecular weight and concentration influence its viscoelasticity and subsequently its flow characteristics in porous media. Exposure to mechanical degradation by flow at high rate through porous media leads to significant reduction in shear thickening and thereby improved injectivity. More importantly, the degraded polymer maintained in-situ viscosity at low flow rates indicating that improved injectivity can be achieved without compromising viscosity at reservoir flow rates. This is explained by a reduction in viscoelasticity. Mechanical degradation also leads to reduced residual resistance factor (RRF), especially for high polymer concentrations. For some of the polymer injections, successive degradation (increased degradation with transport length in porous media) was observed. The results presented here may be used to optimize polymer injectivity.

https://www.mdpi.com/1996-1073/12/1/49/pdf

Behruz Shaker Shiran

Papers

Enhanced Oil Recovery (EOR) by Combined Low Salinity Water/Polymer Flooding

Polymer Flow in Porous Media: Relevance to Enhanced Oil Recovery

Wettability and Oil Recovery by Low Salinity Injection

Impact of Mechanical Degradation on Polymer Injectivity in Porous Media.

Polymer Injectivity: Investigation of Mechanical Degradation of Enhanced Oil Recovery Polymers Using In-Situ Rheology