Observation of the Low Salinity Effect by Atomic Force Adhesion Mapping on Reservoir Sandstones
- Tue Hassenkam (U. of Copenhagen) | Jesper Mathiesen (U. of Copenhagen) | Christian Pedersen (U. of Copenhagen) | Kim Dalby (U. of Copenhagen) | Susan Stipp (U. of Copenhagen) | Ian Ralph Collins (BP Exploration)
- Document ID
- Society of Petroleum Engineers
- SPE Improved Oil Recovery Symposium, 14-18 April, Tulsa, Oklahoma, USA
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 4.3.4 Scale, 5.4.1 Waterflooding, 5.6.5 Tracers, 5.2 Reservoir Fluid Dynamics, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.5 Processing Equipment, 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing
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Field tests have demonstrated that oil production from sandstone reservoirs increases when injected water salinity is low, i.e. ~1500 ppm total dissolved solids (TDS). In core plug tests performed at reservoir conditions, low salinity flooding has been responsible for incremental recoveries ranging from about 5 to 38%. Previous work has suggested that for the low salinity effect to manifest itself, the oil must contain polar components, the formation water must contain divalent cations and clay must be present in the reservoir, but a clear understanding of the mechanism, from fundamental chemical and physical principals, is still subject to debate.
In the work reported here, an atomic force microscope (AFM) has been used in force spectroscopy mode to investigate the nature and magnitude of the interaction between hydrocarbon molecules with carboxylic acid end groups and the pore surfaces of oil reservoir sandstones. By functionalizing the AFM tip with polar molecules we have been able to measure, quantitatively, the adhesion forces between these molecules and the mineral surfaces under 36,500 and 1500 ppm TDS artificial seawater (ASW) solutions.
Collecting these measurements in two-dimensional arrays, known as force maps, revealed that adhesion was highest on the quartz grain surfaces during exposure to the high salinity solutions and it decreased when salinity decreased in nearly all cases. The drop in adhesion was observed through several high to low salinity cycles. We interpreted certain small features that were visible on the quartz surfaces to be clay that had grown directly on the sand grains from solution during diagenesis. Adhesion on these clay surfaces also changed with modifications in salinity. We observed no difference in behaviour whether the sandstone was preserved or cleaned; both types of core demonstrated a clear low salinity response.
A method often used to increase recovery from oil reservoirs is to inject water to push the oil toward a production well. Sea water, or formation water that is produced from a rock stratum close to the well, is often used for water flooding. Sea water has a salinity around 36,500 ppm total dissolved solids (TDS) whereas the salinity in other sources of water can be 200,000 ppm or higher for very dense brines. There have been reports of enhancing oil recovery further by flooding with water of lower salinity, for example, ranging from 200 to 8000 ppm. Core plug testing as well as field tracer tests have confirmed the effectiveness of decreasing salinity (Tang and Morrow (1999), Lager et al. (2008a, 2008b), Austad et al. (2010), Morrow et al. (1998)). Considerable efforts have been made to understand the phenomenon but the molecular level processes are still subject to debate. One proposed mechanism is that a change in surface charge resulting from equilibration of the lower salinity pore fluids with species adsorbed on the reservoir minerals causes a decrease in the adhesion forces between the oil
and the mineral surfaces (Ligthelm et al. (2009)), thus shifting wettability toward water wet. Tests have shown that crucial to the effectiveness of decreased salinity is the presence of amphiphilic components in the crude oil (Freer et al. (2003), Buckley et al. (2001), Morrow et al. (1990), Buckley et al. (1998)). The processes involved are not clear but there is some evidence to suggest that the change in wettability of the rock stems from changes in the state of the ionic groups in the oil, thus releasing them. Confirming and elucidating the details for this molecular scale mechanism would contribute to finding more efficient ways to enhance oil recovery and would also contribute fundamental understanding to efforts to remediate soil and drinking water aquifers that have been contaminated by hydrocarbons.
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