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

Abstract

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...

Role of Basal-Charged Clays in Low Salinity Effect in Sandstone Reservoirs: Adhesion Force on Muscovite using Atomic Force Microscope

“…Our AFM results show that increasing pH from 7 to 11 indeed decreased 80% of the adhesion force for both functional groups, confirming that low salinity water likely lifts off oil films from pore surfaces thus increasing water-wetting. Similar results were also observed by Hassenkam et al, ,, who measured adhesion force of a model oil on sandstone grains and model rocks using AFM. Their results show that low salinity water decreases the adhesion force between the model oil and both types of rock, implying that adhesion force reduction of oil and rock surface in the presence of low salinity water can be achieved at pore surfaces in reservoirs.…”

Low Salinity Effect at Pore Scale: Probing Wettability Changes in Middle East Limestone

“…On experiments in sandstone, the low salinity response can clearly be observed using CFM on treated and fresh samples. − Hassenkam and colleagues and Matthiesen and colleagues demonstrated that overall adhesion and the low salinity response are strongly influenced by the organic materials that are naturally present on all mineral surfaces, even when they have never been in contact with oil or gas. In several experiments with the same conditions as presented in this study, the average adhesion on grains from sandstone that had been solvent treated was ∼110 pN, which is comparable to the average adhesion obtained in our study on the treated sample, i.e.…”

“…There is general agreement that divalent ions must be present in the formation water, polar components are required in the crude oil, and the presence of clay in the reservoir is essential. ,, It has not yet been established if these requirements also hold for carbonate rocks. Previous work has demonstrated the effectiveness of atomic force microscopy (AFM), in chemical force mapping (CFM) mode, for observing changes in surface wettability that result from changing the salinity of the solution in contact with mineral grains from sandstones. ,,, The experiments used AFM tips functionalized with molecules ending in methyl (−CH 3 ) to make them hydrophobic or carboxyl (−COO­(H)) to make them polar, either neutral or acidic, depending on the pH of the solution. A change toward slightly more water wet pore surfaces has been suggested as one of the main causes for the low salinity response .…”