High water cut and water influx into production wells has become a serious problem in producing oil. Polymer gels treatment has been applied widely for near well bore regions to reduce water production. In water shut - off process, effective permeability, permeability reduction after gels treatment plays an important role for evaluating the level of reducing water cut. However, under complex reservoir conditions including pH, salinity, high pressure, and temperature, the polymer gels behavior is significantly affected by those parameters, such as pH affects to the gel strength; the difference in salinity concentration between formation water and polymer solvent (water) causes swelling phenomenon by osmotic pressure. Moreover, due to the presenting of reservoir crude oil, the shrinking phenomenon of polymer gels is taken into account. The swelling and shrinking phenomenon affect extremely on blocking porous media. Laboratory experiments are carried out to perform these behaviors in batch system which is able to work at reservoir conditions. Two types of polymer with high and low molecular weight are used; chromium acetate is used as cross-linker agents. Several gels samples are tested in ambient and reservoir conditions (high pressure, high temperature, difference in salinity and pH) to investigate polymer gels behavior. These polymer gels samples are used in injecting into the sand-pack cores. Disproportional permeability reductions are measured with each polymer type. Experiment results showed that the percent of increment in volume reaches 25 % (within 72 hours) with high salinity of polymer solvent (3%) and low salinity of formation water (0.5%). The lowest increment occurs when differential salinity is 0 % and 0.5 %. Moreover, water permeability is reduced strongly (67% of reduction) while it has less effect to oil permeability (17.5% of reduction) after polymer gels treatment. These investigations are important in evaluating the effectiveness of water shut-off process.

Gelation of gelant solutions occurs under specific conditions. The gelation time can vary from several minutes to several days, even a few months, depending on parameters, such as temperature, polymer type, polymer concentration, cross-linker concentration, initial pH, salt type, and salt concentration. Therefore, many laboratory experiments were studied to understand the gelation time before the core flooding experiments were carried out. The polyacrylamide polymers and the chromium acetates were mixed to form the gelant solutions. The results suggested the good proportion of polymer to cross-linker for the next core flooding experiments and the effects of gelation time.

Alberta's oil sands deposits, with an estimated 1.7 trillion barrels of bitumen in place, account for approximately 40% of the world's bitumen resource. And steam-assisted gravity drainage (SAGD) has opened the door to produce a large number of bitumen reservoirs in Canada. The success of SAGD has been mostly demonstrated by numerical simulation with homogeneous reservoir models. But, this process is very sensitive to reservoir heterogeneities; therefore, it is urgent and necessary to have a comprehensive understanding of the effects of reservoir heterogeneities on SAGD performance for wider and more successful implementation.This study presented a numerical investigation for evaluating the potential applicability of SAGD recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap and fracture systems in McMurray formation. In order to achieve the general vision and overcome some limitations in literature, these are of factors were evaluated in both individual and simultaneous case studies. Bitumen recovery, average oil production rate, and cumulative steam-oil ratio obtained from thermal simulation were the three main parameters used for evaluation of the attractiveness of bitumen recovery operations. The simulation results indicated that the near well regions are very sensitivity with shale layers and only long, continuous shale barriers (larger than 50m or 25%) can effect to SAGD performance at the above well regions. Besides that, the thief zones have a strongly detrimental effect on SAGD. The results also proved that SAGD recovery process enhanced in the presence of vertical fractures but horizontal fractures were harmful on the recovery. Fracture spacing was not a very important parameter in the performance of steam process in fractured models and the increasing of horizontal fractures extension will reduce ultimate oil recovery in SAGD process. This paper is a worthy guideline for SAGD operations in complex geological reservoirs.

No abstract

No abstract