How Naturally Adsorbed Material on Minerals Affects Low Salinity Enhanced Oil Recovery

Matthiesen, J.; Bovet, N.; Hilner, Emelie; Andersson, Martin; Schmidt, Diedrich A.; Webb, Kevin J.; Dalby, Kim N.; Hassenkam, Tue; Crouch, Jonathan; Collins, I.R.; Stipp, S. L. S.

doi:10.1021/ef500218x

Cited by 61 publications

(92 citation statements)

References 32 publications

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“…Although the particles came from the same reservoir core plug, their topography and surface composition were very different. The images were consistent with images taken by other researchers on material from the same core plug and from different samples 13,16 . Fig.…”

Section: Dlvo Theorysupporting

confidence: 89%

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A pH-Resolved View of the Low Salinity Effect in Sandstone Reservoirs

et al. 2016

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Core plug and field tests have shown that significantly more oil can be produced from sandstone reservoirs when the water that is injected to maintain pressure in the reservoir has lower salinity than regular seawater. We investigated the adhesion between functional groups known to dominate in crude oil and grains from reservoir sandstone as a function of pH and salinity. We used atomic force microscopy (AFM) in chemical force mapping mode, and we functionalized the AFM tips both with −CH 3 , to model adhesion of hydrophobic molecules, and with −COO(H), to model polar compounds. As the pH increased, the adhesion force decreased. The behavior was similar for the two types of tips, but adhesion was higher for the polar tip. The average adhesion at pH 4.5 for the −COO(H) tip in artificial seawater (ASW) was close to 300 pN, and 200 pN in ASW diluted by a factor of 20. For the −CH 3 tip, adhesion was ∼200 pN in high salinity and 140 pN in low salinity. Regardless of the salinity, adhesion decreased as pH increased. To gain understanding about the controlling processes, we examined our data in light of the Dejarguin−Landau−Verwey−Overbeek (DLVO) theory and the Henderson−Hasselbalch expression. The commonly used form of the DLVO relationship could not account for the pH dependence. It predicts adhesion to be independent of pH in high-salinity solution and strongly dependent on pH in low salinity, opposite to the experimental evidence. Although DLVO theory cannot be expected to quantitatively represent real systems, it is unlikely that DLVO would predict reversed behavior. Our results indicate that the extended double layer, which is one of the prevailing explanations for the low salinity effect, is not the full explanation. Decrease in surface charge density at low salinity plays an important role. The change in adhesion as pH increases above 5.5, which is the typical pH of sandstone reservoirs, to the neutral range could enhance oil recovery. This is probably a factor in the effectiveness of alkaline flooding and might be an inherent factor in the production that results from flooding with seawater, which is typically pH 8.3. However, the buffering effect in sandstone reservoirs, which maintains pH at ∼5.5, suggests that benefits from controlling pH for EOR could be marginal.

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Section: Dlvo Theorysupporting

confidence: 89%

“…Recent work, for example, has demonstrated that adsorbed organic compounds, which are associated with all natural surfaces, change wetting properties 13,14 . Although crude oil is a complex mixture of many organic compounds, it is primarily the functional groups that deter- mine which adhere on the pore surfaces.…”

Section: Introductionmentioning

confidence: 99%

A pH-Resolved View of the Low Salinity Effect in Sandstone Reservoirs

et al. 2016

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“…The adhesion is an indication of the attractive interactions between the brine/oil and brine/quartz interfaces of thin brine films in reservoir rocks. Diluting the brine makes the quartz surface more water-wet and reduces the adhesion to oil [35]. The experimentally measured adhesion force as a function of salinity can be fitted well with force predictions from DLVO theory [36 • ].…”

Section: Zeta Potential Contact Angle Oil Recovery and Afm Measurementioning

confidence: 86%

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

Myint

Firoozabadi

2015

Current Opinion in Colloid & Interface Science

270

214

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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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“…For the low salinity solution, we simply diluted the stock high salinity solution by about 25 times, to produce a solution that was 1,500 ppm. We also used synthetic formation water that we made to reflect the composition of the water that was present in the oil reservoir where the core was taken, before the oil was produced, composition is published in Matthiesen et al (Matthiesen et al 2014). The solutions were made by dissolving the salts in ultrapure deionised water (MilliQ) that had resistivity >18 M ·cm.…”

Section: Methodsmentioning

confidence: 99%

A Fast Alternative to Core Plug Tests for Optimising Injection Water Salinity for EOR

Hassenkam

Andersson

Hilner

et al. 2014

SPE Improved Oil Recovery Symposium

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Core tests have demonstrated that decreasing the salinity of injection water can increase oil recovery. Although recovery is enhanced by simply decreasing salt content, optimising injection water salinty would offer a clear economic advantage for several reasons. Too low salinity risks swelling of the clays which would lead to permanent reservoir damage but evidence of effectiveness at moderate salinity would offer the opportunity to dispose of produced water. The goal is to define boundary conditions so injection water salinity is high enough to prevent reservoir damage and low enough to induce the low salinity effect while keeping costs and operational requirements at a minimum. Traditional core plug testing for optimising conditions has some limitations. Each test requires a fresh sample, core testing requires sophisticated and expensive equipment, and reliable core test data requires several months because cores must be cleaned, restored and aged before the tests can begin. It is also difficult to compare data from one core with results from another because no two cores are identical, making it difficult to distinguish between effects resulting from different conditions and effects resulting from different cores. Gathering statistics is limited by the time required for each test and the fact that core material is in short supply. Thus, our aim was to explore the possibility of a cheaper, faster alternative. We developed a method that uses atomic force microscopy (AFM) to investigate the relationship between the wettability of pore surfaces and water salinity. We functionalise AFM tips with organic molecules and use them to represent tiny oil droplets of nonpolar or polar molecules and we use sand grains removed from core plugs to represent the pore walls in sandstone. We bring our "oil" close to the sand grain surface and measure the work of adhesion between the tip and the surface. Repeated "feeling" the surface with the tip produces data that can be converted to maps of adhesion and contact angle. Adhesion work is proportional to wettability and is directly correlated with the salinity of the fluid in contact with the tip and the particle surface. From our measurements, the threshold values for the onset of the low salinity response is 5,000 to 8,000 ppm, which benchmarks remarkably well with observations from core plug tests. Changing either the type of "oil" on our probe or the character of the grain surface both affect the adhesion response. From a mechanistic perspective, the correlation between salinity and adhesion provides evidence for the role of electrical double layer expansion in the low salinity response; expansion of the double layer decreases oil wettability. Because AFM experiments can be done relatively quickly on very little material, it gives the possibility of testing salinity response on samples from throughout a reservoir and for gathering statistics. Our approach provides a range of data that can be used to screen core plug testing conditions and to provide extra data that would be too...

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How Naturally Adsorbed Material on Minerals Affects Low Salinity Enhanced Oil Recovery

Cited by 61 publications

References 32 publications

A pH-Resolved View of the Low Salinity Effect in Sandstone Reservoirs

A pH-Resolved View of the Low Salinity Effect in Sandstone Reservoirs

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

A Fast Alternative to Core Plug Tests for Optimising Injection Water Salinity for EOR

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