With conventional oil reserves in decline, energy companies are increasingly turning to enhanced oil recovery (EOR) processes to extend the productive life of oilfield wells. Laboratory-scale core floods, in which one fluid displaces another from the pore space of a rock core, are widely used in petroleum research for oilfield evaluation and screening EOR processes. Achieving both macro- and pore-scale understandings of such fluid displacement processes is central to being able to optimise EOR strategies. Many of the mechanisms at play, however, are still poorly understood. In this thesis nuclear magnetic resonance (NMR) has been used for quantitatively, non-invasively and dynamically studying laboratory core floods at reservoir-representative conditions.

Spatially-resolved relaxation time measurements (L-T1-T2) have been applied to studying a special core analysis laboratory (SCAL) protocol, used for simulating reservoir oil saturations following initial oil migration (primary drainage) and characterising core samples (capillary pressure curves). Axial heterogeneities in pore filling processes were revealed. It was demonstrated that upon approaching irreducible water saturation, brine saturation was reduced to a continuous water-wetting film throughout the pore space; further hydrocarbon injection resulted in pore pressure rise and wetting film thinning.

L-T1-T2 techniques were also applied to a xanthan gum polymer-EOR flood in a sandstone core, providing a continuous measurement of core saturation and pore filling behaviours. A total recovery of 56.1% of the original oil in place (OOIP) was achieved, of which 4.9% was from xanthan. It was demonstrated that deposition of xanthan debris in small pores resulted in small-pore blocking, diverting brine to larger pores, enabling greater oil displacement therein.

L-T1-T2, spectral and pulsed field gradient (PFG) approaches were applied to a hydrolysed polyacrylamide (HPAM)-EOR flood in a sandstone core. A total recovery of 62.4% of OOIP was achieved, of which 4.3% was from HPAM. Continued brine injection following conventional recovery (waterflooding) and EOR procedures demonstrated most moveable fluid saturation pertained to brine, with a small fraction to hydrocarbon. Increases in residual oil ganglia size was demonstrated following HPAM-EOR, suggesting HPAM encourages ganglia coalescence, supporting the “oil thread/column stabilisation” mechanism proposed in the literature.

NMR relaxometry techniques used for assessing surface interaction strengths (T1/T¬2) were benchmarked against an industry-standard SCAL wettability measurement (Amott-Harvey) on a water-wet sandstone at magnetic field strengths comparable to reservoir well-logging tools (WLTs). At 2 MHz, T1/T2 was demonstrated to be weakly sensitive to the core wettability, although yielded wettability information at premature stages of the Amott-Harvey cycle. This suggests the potential for NMR to deliver faster wettability measurements, in SCAL applications or downhole WLT in situ reservoir characterisation.