Search

Summary A laboratory study on microsphere injection in a large volume (1 pore volume) was conducted to explore its oil recovery capacity as a flooding agent. This work aims to a Middle-East reservoir with oil-wet high-permeable carbonate in nature. An etched micromodel was made based on the pore network of natural core plugs and the pore network treated to oil-wet with silicon oil. Water flooding was conducted to displace oil at reservoir temperature (95°C), followed by 1 pore volume microsphere injection. A significant oil recovery was obtained using a microsphere concentration ranged from 0.5% to 5%. As a comparison, microsphere was injected into a water-wet micromodel to recover oil after water flooding, which also shows very positive results. This work proved the concept that microsphere injection can enhance the oil recovery in both oil-wet and water-wet reservoirs, once the treatment is conducted with sufficient amount and over the threshold microsphere concentration.

Summary The potential reservoirs in the Realgrunnen play in the Southwestern Barents Sea are heavily influenced by the complex burial history of the area. A combination of present day shallow reservoirs and formerly buried over 2 km deeper causes challenges when doing a geophysical reservoir characterization. Wells drilled in the area display amplitude anomalies, but majority has been water wet when drilled. By creating rock physics models and combining with AVO parameters Intercept and Gradient running an inverse modelling scheme (IRPM) in the AVO domain we try to link amplitude anomalies in the AVO domain with wireline log results to provide a quantitative seismic interpretation methodology for de-risking exploration in shallow areas of complex tectonic events.

The presence of polymer molecules in an altered wettability core and its possible interactions with the solid phase is the subject of this study. Experiments were carried out in Bentheimer sandstone which wettability is altered by an ageing process. The wettability index after ageing (WI = 0.075) shows an intermediate wettability. After ageing we carried out spontaneous imbibition tests by putting in contact the core with brine or polymer solution (HPAM, C = 2500ppm) or in a sequence (first with brine and then with the polymer solution) For each experiment we measure the volume of oil recovered by spontaneous imbibition, this oil volume gives us an evaluation of the core wettability, the higher the recovered oil volume, the more water wet is the core. The experimental data show that final oil production by spontaneous imbibition is higher when the core was kept for a long time in contact with polymer solution rather than with brine. Moreover if the core is put in contact with polymer after having been immerged in brine, we notice a significant increment of produced oil. All these results confirm that the polymer has an interaction with the solid phase and makes the core more water wet.