Abstract
Clean sandstone, with minimal clay content, is expected to be strongly water wet once the rock has been through an effective cleaning process. Even samples containing significant clay minerals are usually expected to be water wet after appropriate cleaning. However, tests carried out on core samples from Fields in three different global locations show mixed indices, even for clean state samples where no aging with crude oil has taken place. A few hypotheses for this behaviour considered herein are: whether the cleaning method was adequate, whether wettability was altered by an external factor, or if wettability was due to mineral composition. This paper presents the results obtained from wettability studies on fresh, clean and restored state core plug samples from three different Fields. Wettability indices were obtained by using the combined Amott-USBM method. Petrography was performed on sample end-trims to investigate the possible presence of halite or barite in the clean state samples, thought to be from drilling fluid infiltration, which should have been removed by the methanol cleaning cycle. This showed no organic material or salt (halite), negating wetting change from inefficient cleaning. From a reactive clays [1] model perspective, these rock samples are considered clean-sand (i.e. illite/ smectites- as total clay content), determined by XRD analysis, are lower than 10%. SEM and XRD results showed the presence of grain-coating chlorite in one sample set and glauconite grains in the others. Only once the unusual wettability indices were obtained was the grain-coating chlorite identified as chamosite by SEM/EDX, which is an iron-rich form of chlorite. The presence of chamosite or glauconite appears to influence the wetting tendency. In summary, USBM vs Amott wettability indices of the analysed samples are consistent between both methods, showing a mixed to oil-wet tendency for all samples where chamosite was identified, regardless of the initial test condition. Samples with glauconite appeared to be more mixed wet after wettability restoration. The results suggest that iron rich clay/mineral content is the main contributor to the oil wet tendency of the evaluated rocks.
Highlights
Wettability is an important rock-fluid property that controls how fluids are distributed and flow within porous media [1]. It is the result of a complex interaction of forces, related to the reservoir fluid system and the rock composition, and has a major impact on capillary behaviour, core electrical measurements [2, 3, 4], relative permeability tests and residual saturations [5]
Lab testing requires representative wettability conditions to ensure the results are representative for input to reservoir simulation
The general assumption, for conventional reservoirs, is that before hydrocarbons migrated into the reservoir, the rock was water wet because the grains were only in contact
Summary
Wettability is an important rock-fluid property that controls how fluids are distributed and flow within porous media [1]. Current recommended industry approach [1] is to restore the wettability by appropriate cleaning (to mimic prehydrocarbon migration, water-wet conditions), establish representative formation water saturation, introduce representative reservoir oil and apply pressure and temperature for “sufficient” time. Both techniques have pros and cons and require deliberation of what might be the most appropriate approach for a particular reservoir being studied, based on the core material and fluids available to testing and the contracted laboratory equipment limitations. Sample saturated in synthetic formation water and desaturated to Swi under lab oil Amott-USBM testing carried out Sample saturated in synthetic formation water and desaturated to Swi under lab oil Lab oil replaced with corresponding crude oil and aged for 40 days at elevated temperature and nominal backpressure (200 psi)
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