When injecting low salinity (LS) water, it is believed that destabilization of oil layers adhering to mineral surfaces could be a contributing mechanism to enhanced oil recovery (EOR). Surfactant flooding is a proven EOR technique by increasing the capillary number. The combination of LS water at reduced capillarity can avoid retrapping of destabilized oil and exceed recoveries of either of the techniques applied alone. In this study, we have used an alcohol propoxy sulfate mixed with an internal olefin sulfonate to compare the oil recovery in a low salinity surfactant (LSS) flooding process at moderately low IFTs to that of an optimal salinity surfactant (OSS) injection process at ultralow IFT. The surfactant formulation was selected on the basis of an initial screening phase using a North Sea crude oil and diluted seawater. Its effect on oil recovery efficiency in different injection scenarios was investigated using crude oil aged Berea sandstone cores. The results showed comparable recoveries for the LSS flooding at a capillary number 2 orders of magnitude lower than that for the surfactant flooding at ultralow IFT. In addition, retention values in the latter case were around 60% higher than for the LS case. On the basis of this, it appears that the LSS process may be more economically efficient than an OSS injection process at ultralow IFT.

During the last decades colloidal dispersion gels (CDG) have been applied as an EOR method, providing sweep improvement in reservoirs with unfavourable mobility ratio. Our core flood results also indicate an improved microscopic sweep or microscopic diversion by CDG. This paper investigates the oil mobilization properties of nano-sized silica particles in comparison to nano-sized CDG particles and discusses the underlying mechanisms of microscopic flow diversion.Improved microscopic displacement efficiency has traditionally been coupled to changes in capillary number. However, this approach is insufficient to describe processes like low salinity injection, colloid dispersion gels, and microbial enhanced oil recovery.This paper presents a new concept of EOR by improved microscopic displacement defined as microscopic diversion. This method involves pore blocking and diversion of injection fluids. Multi-phase flow experiments using nano-sized silica particles attempts to investigate the effect (inelastic) nano-sized fines migration can have on oil mobilization by microscopic diversion.The oil mobilization properties were investigated by core floods using well-defined nano-sized silica particles in comparison with injection of CDG, polymer or silica particles dispersed in a polymer solution.. Core floods were performed on water-wet Berea sandstone cores with permeabilities of approx. 500 mD. The comparison of inelastic silica particles, polymer solutions and nano-sized CDG particles allowed an evaluation of the importance of viscoelastic properties for microscopic diversion.

Summary Field trials have demonstrated increased oil recovery by injection of colloidal dispersion gels (CDG). Characteristics of these trials include reservoirs characterized by high permeability heterogeneity and low injection water salinities. The enhanced oil recovery (EOR) has been attributed to improved waterflood sweep in the rather heterogeneous reservoirs where this method has been applied. This study presents an investigation of the applicability of CDG at higher salinity, and particularly sandstone North Sea oil reservoir applications. Earlier laboratory work and field trials involving CDG have involved relatively low reservoir temperatures and low injection water salinity (~5000 µg/g). This study involves experiments at high temperature (85°C) and salinity (~35 000 µg/g). When crosslinking is complete, the CDG solutions have slightly lower viscosities than the corresponding polymer solutions, and they also appear to be more stable at high temperatures. In preparation for a field pilot, several coreflood experiments have been conducted. Significant increase in oil recovery resulting from CDG injection has increased the interest for a field trial in a North Sea oil field. On average, 40% of the remaining oil after waterflooding was produced by CDG injection in linear corefloods, and a mechanism of microscopic diversion is proposed to explain these results. Our hypothesis is that CDG injection can contribute as an EOR method, giving both a microscopic diversion and a macroscopic sweep.

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Field trials have demonstrated increased oil recovery by injection of colloidal dispersion gels (CDG). Characteristics of these trials include reservoirs characterized by high permeability heterogeneity and low injection water salinities. The enhanced oil recovery (EOR) has been attributed to improved waterflood sweep in the rather heterogeneous reservoirs where this method has been applied. The present study presents an investigation of the applicability of colloidal dispersion gels at higher salinity, and in particular directed at North Sea oil reservoir applications. Earlier laboratory work and field trials involving CDG have involved rather low reservoir temperatures and low injection water salinity (~ 5000 mg/g). This study involves experiments at high temperature (85 °C) and salinity (~35 000 mg/g). When cross-linking is complete the CDG solutions have slightly lower viscosities than the corresponding polymer solutions, and they also appear to be more stable at high temperatures. In preparation for a field pilot, several core flood experiments have been made. Significant increase in oil recovery due to CDG injection has increased the interest for a field trial in a North Sea oil field. On average, 40 percent of the remaining oil after waterflooding was produced by CDG injection in linear core floods, and a mechanism of microscopic diversion is proposed to explain these results. Our hypothesis is that CDG can contribute as an EOR method giving both a microscopic diversion and a macroscopic sweep. Introduction Polymer gel treatments have been widely used to improve sweep efficiency or reduce production of unwanted water. Bulk gel injection involves high polymer (typically 5000 mg/g) and cross-linker concentrations to form strong gels in the near wellbore area. These systems are characterized by a continuous network of polymer molecules formed by intermolecular cross-linking. In the colloidal dispersion gels (CDG), however, the polymer concentration is too low (typically 100 - 1000 mg/g) for the formation of such a continuous network. Instead, interactions are dominated by intramolecular cross-linking, with minimal intermolecular cross-links connecting a relatively small number of molecules. This structure with individual bundles of cross-linked polymer molecules of colloidal dimensions (1–100 nm) dispersed in water has given rise to the name colloidal dispersion gels. The first report on use of colloidal dispersion gels in the field was published by Mack and Smith in 1994(Mack and Smith, 1994). A total of 29 field projects were evaluated, of which 19 were deemed successful with incremental oil recoveries ranging from 1.3 to 18.2%. Nearly all reported field trials involve heterogeneous reservoirs and relatively fresh injection water. Injection water salinity is said to be limited to less than 30 000 mg/g total dissolved solids, however, the authors offer no physio-chemical explanation as to why such a salinity limit should exist. With respect to the mechanisms by which CDG injection increases oil recovery, Mack and Smith suggest that CDG provides in-depth control of permeability variation by being sufficiently slow forming to allow placement deep in the formation in the primary water flow paths. This view has later been supported by Chang et al.(2006) based on experiences from a field pilot of CDG technology in the Daqing Oil Field in China.