Polymer-augmented Waterflooding Research Articles

Efficiency of enhanced oil recovery using polymer-augmented low salinity flooding

Oil recovery from heavy oil resources has always been a challenging task. This work is aimed at investigating the recovery efficiency of polymer-augmented low salinity waterflooding in heavy oil reservoirs. The main recovery mechanism behind low salinity waterflooding is wettability alteration to more water-wet state. On the other hand, polymer flooding is performed to control fluids mobility and hence improve displacement efficiency. Combining both recovery methods is expected to add to recovery efficiency obtained by individual methods, and the aim of this work is to explore this experimentally. In this study, several laboratory experiments were conducted using Berea and Bentheimer sandstone cores starting with base runs of continuous secondary seawater and tertiary twice and 10 times diluted seawaterflooding (low salinity). Significant incremental oil recovery was obtained when flooded with low salinity water, and 10 times diluted seawater was determined to be used as low salinity water. Contact angle and Zeta potential measurements indicate wettability alteration due to clay detachment as the main recovery mechanism. Synergy of water secondary flooding and polymer tertiary flooding at different water salinity levels proved the efficiency of hybrid low salinity polymer flooding process in Berea sandstone. Low water salinity during secondary injection mode played a major role on ultimate recovery with less contribution to tertiary polymer slug injection. High salinity waterflooding provided lower secondary recovery leaving more residual oil for polymer slug to act on at that cycle. Smaller polymer slug of 0.1 pore volume was found to be sufficient in tertiary flooding with low salinity water but with slightly slower recovery rate. Bentheimer sandstones known for its low clay content were subjected to polymer-augmented waterflooding at high and low salinity levels. Close secondary and tertiary recoveries were obtained for the two salinity levels with slower recovery rate for low salinity run. Minute clay content and water-wet characteristic as determined by contact angle measurements may explain the lack of water salinity effect on recovery. The lack of salinity role and the two shock fronts with connate water bank in between known to exist during low salinity flooding may explain the slower recovery rate encountered. Comparison of both sandstones indicates that less ultimate recovery from Berea rocks, and this can be attributed to their initial intermediate wet state in contrast to the water-wet Bentheimer sandstone rocks.

Visualization of Mobility-Control by Polymer Waterflooding through Unconsolidated Porous Media using Magnetic Resonance Imaging

This article addresses the use of Centric Scan SPRITE Magnetic Resonance Imaging (MRI) technique to visualize the performance of polymer flooding as a mobility-control technique. The fronts and interfaces between displaced and displacing fluids are monitored. The development of a piston-like displacement front, as a result of polymer-augmented waterflood, and the effect of polymer concentration on the development of a favorable water displacement front are directly observed. MRI demonstrates to be a useful imaging tool for the evaluation of the efficiency of polymer flooding. Experiments indicate a close agreement between fluid saturations determined by MRI and fluid saturations estimated from material balance.

Numerical Simulation on the Oil Recovery from an Areally Heterogeneous Reservoir by Polymer Augmented Waterflood

The influence of water-soluble polymer solution on the flow behavior and oil recovery in areally heterogeneous reservoirs with adsorption and crossflow was investigated by numerical simulation. For the reservoirs of low viscosity oil, polymer floods had a relatively small improvement on the recovery of oil. Performances of waterflood and polymer flood were not so sensitive to change in permeability variation up to σ(ln k) = 1.0. Variations in permeability fields have a pronounced effect on the tertiary oil recovery efficiency for reservoirs with viscous oil due to additional dispersion caused by the randomly heterogeneous reservoir. Oil recovery increases as the correlation length in the permeability field increases for both water and polymer floods. Anisotropic correlation length causes sudden changes in oil recovery and water-oil ratio and results in a significant decrease in oil recovery and increase in water-oil ratio over the production life.

Overview: Heavy Oil (April 2007)

The quest to produce heavy oil (gravity less than 20°API) has gone global. In the past, papers describing heavy-oil recovery generally focused on resources in the Americas and some in China and Indonesia. In the papers evaluated for this issue's heavy-oil feature, the focus ranged from the North Sea to the Middle East to the Gulf of Mexico and places in between. In many cases, the resource does not resemble the conditions that are thought to be typical for heavy oil: viscous oil held in relatively permeable, shallow sands. The fields of interest nowadays have evolved to include fractured carbonates; offshore settings; and deeper, more geologically heterogeneous heavy-oil resources. Such new settings introduce new challenges, which include highly permeable pathways and limits on reservoir access, in addition to those of large oil-phase viscosity and low reservoir energy. Despite these apparent successes, it appears that heavy-oil-recovery techniques have bifurcated. On the one hand, thermal processes deliver significant recovery factors, but are capital-intensive and sometimes difficult to implement as well as optimize. On the other hand, some new developments appear to accept relatively low recovery factors and borderline economics. Given the heavy-oil volumes in place, the range of reservoir settings, and the challenges of effective extraction, it is time to renew our efforts in R&D. Production mechanisms of the heavy-oil solution-gas-drive process are not completely elucidated; performance cannot be simulated with conventional techniques; and, consequently, it is difficult to optimize primary recovery. Waterflooding of heavy oil is summarily dismissed because of adverse mobility ratios. In cold and/or offshore environments, waterflooding, and perhaps polymer-augmented waterflooding, may present the most attractive recovery option following primary recovery. Steam injection is relatively mature, but cost-effective mobility and profile control by use of aqueous-phase surfactants, gels, or advanced well completions remains an open question. In-situ combustion achieved by air injection is technically and economically feasible, especially for deeper, thinner, higher-pressured reservoirs. Combustion is difficult to describe and control. Nevertheless, it is attractive for in-situ upgrading and sulfur removal. In short, the heavy-oil resource is trillions of barrels, but the cumulative recovery totals to date are on the order of billions of barrels. Whether the potential and promise of heavy oil is realized depends on collective action of industry, academia, and governments to deliver recovery technologies appropriate for the wide range of reservoir and oil-phase conditions. Such technologies also need to be comparatively benign from an environmental aspect. Thus, the heavy-oil challenge remains significant. Heavy Oil additional reading available at the SPE eLibrary: www.spe.org SPE 102500 "Interpretation of Heat Distribution, Remaining-Oil Saturation, and Steamflood Potential of Block Wa38, Liaohe Field" by Y. Gao, RIPED, PetroChina Co. Ltd., et al. SPE 104046 "Thermal Simulation and Economic Evaluation of Heavy-Oil Projects" by E.R. Rangel-German, SPE, Natl. Autonomous U. of Mexico and Ministry of Energy, Mexico; et al. SPE 102876 "Making Sense of the Geomechanical Impact on the Heavy-Oil Extraction Process at Peace River Based on Quantitative Analysis and Modeling" by P.R. McGillivray, Shell Canada Ltd., et al. SPE 104405 "Efficient Technology Following Cyclic-Steam Stimulation for Thick, Massive Heavy-Oil Reservoirs" by S. Liu, RIPED, PetroChina Co. Ltd., et al.

An Investigation of Polymerflooding in Limestone Reservoirs with a Bottom Water Zone

The effects of polymers on waterflooding of a limestone reservoir with or without a bottom water zone, as well as the effect of vertical and horizontal production wells on oil recovery, have been investigated in laboratory models. Sixteen core flood displacement tests were conducted to study the effect of relative oil-water layer thickness, polymer slug size, and well configuration in a production port. A qualitative comparison was made to show the difference between waterflooding and polymer-augmented waterflooding runs, where a light crude oil with a viscosity of 14.5 mPa.s was used. The results of the displacement tests showed that as the thickness of the bottom water zone increases, the ultimate oil recovery decreases. The selected polymer solution had a favorable impact on the waterflood performance. However, the worse the conventional waterflood performance was, the more effective was the polymer as a mobility control agent. For instance, when the bottom water zone was approximately as thick as the oil zone, only about 25% of Original Oil in Place (OOIP) was recovered by a waterflood, whereas with a polymer as the mobility control agent, more than 55% of OOIP was recovered. For polymer injection, the effect of slug size was discussed with the aid of concentration curves and retention rate values; and a slug of 0.60 PV was obtained as optimal. In a conventional waterflood, the horizontal production well showed slightly better oil recovery than the vertical production well with a thin bottom water zone. In polymer-augmented waterflooding, higher oil recoveries were obtained with vertical production wells as compared to horizontal production wells. This was because of the early production of polymer solutions and reductions of the swept area from investigation of concentration curves.