Executive Summary

It should not come as a surprise that the papers in this issue somehow fall under the discipline of Improved and Enhanced Oil Recovery, considering the present state of the oil and gas industry, namely an ever-growing number of mature fields combined with the latest developments in unconventional resources. We tend to easily forget how our industry, as any other, is constantly changing. This means new challenges and, as usual, research tries to respond to them in hopes of a more manageable tomorrow. It is indeed an interesting historical moment, while many opine that the productive life of our conventional resources can be extended, others see in unconventional resources the future. Yet it is the continuous exchange of knowledge that truly characterizes progress. On that note, I hope the readership enjoys the subtle crossovers of the works at hand.

Francesca Verga
Co-Executive Editor of SPE Res Eval & Eng

Improved and Enhanced Oil Recovery

The present issue’s opening paper Waterflooding in Carbonate Reservoirs: Does the Salinity Matter? dwells on the impact of the salinity of the injected brine on oil recovery during secondary and tertiary recovery modes. To this end, coreflood studies, using Indiana limestone rock samples, were carried out and, amongst other results; it was found that oil recovery using seawater as injection brine was on average 50% of the original-oil-in-place (OOIP) in the secondary recovery mode. The second paper, Field vs. Laboratory Polymer-Retention Values for a Polymer Flood in the Tambaredjo Field, also deals with experimental work. In this case, authors set out to demonstrate that by monitoring salinity and polymer concentration in produced water, polymer retention could be estimated in different portions of the Staatsolie’s Sarah Maria pilot project in the Tambaredjo field in Suriname. Finally, results from the field project were analyzed to establish field polymer-retention values for different patterns of the Sarah Maria polymer flood.

The third paper Three-Phase Relative Permeability Modeling in the Simulation of WAG Injection drifts away from laboratory work as it enters the realm of simulation. Authors propose a workflow to evaluate the effect of three-phase relative permeability models on the simulation of water-alternating-gas (WAG) injection. The workflow was applied to immiscible and miscible WAG injection simulated by use of black-oil and compositional models.

The two subsequent papers deal with heavy oil. The first, Pelican Lake Field: First Successful Application of Polymer Flooding In a Heavy-Oil Reservoir, presents the history of the Pelican Lake field and then focuses on the polymer-flooding aspects. Because the field is the first successful application of polymer flooding in much higher-viscosity oil, it opens a new avenue for the development of heavy-oil resources that are not accessible by thermal methods. Authors describe the preparation and results of the two polymer-flood pilots as well as the extension of the flood to the rest of the field (which is currently in progress). The second paper Kinetics of the In-Situ Upgrading of Heavy Oil by Nickel Nanoparticle Catalysts and Its Effect on Cyclic-Steam-Stimulation Recovery Factor studies the effect of nickel nanoparticles on in-situ upgrading of heavy oil during aquathermolysis and the effect of this process on the recovery through cyclic steam injection. Results showed that the nickel nanoparticles increased the recovery factor by approximately 22% when the nanoparticles were injected with a cationic surfactant and xanthan-gum polymer.  

A Procedure for Measuring Contact Angles When Surfactants Reduce the Interfacial Tension and Cause Oil Droplets to Spread marks the middle of the issue. Authors present a procedure in which rocks were centrifuged in surfactant solutions; therefore, the surface active agents alter the interfacial properties of the rock. Contact angles were then measured in a surfactant-free fluid with a high oil/liquid interfacial tension. The difference in contact angles before and after centrifuging indicates the effect of the surfactant on wettability. Authors argue that this procedure will allow wettability evaluations not possible with a conventional method.

The seventh paper Extension and Verification of a Simple Model for Vertical Sweep in Foam Surfactant-Alternating-Gas Displacements offers a useful tool in the initial assessment of the feasibility of overcoming gravity override over large distances, and in illustrating the advantages of a surfactant-alternating-gas (SAG) process with a single large slug of surfactant solution and a single large slug of gas, in a homogeneous reservoir. In the eighth paper High Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of Gulf of Mexico Oil Mixed With Nitrogen, compositional data and pressure/volume/temperature (PVT) data are presented for a Gulf of Mexico reservoir fluid. The results of the study indicate that one may satisfactorily conduct phase-behavior modeling in compositional reservoir simulation for high-pressure gas-injection processes.

Unconventional Resources

Authors of the ninth paper Phase Behavior and Minimum Miscibility Pressure in Nanopores modified conventional vapor/liquid equilibrium (VLE) calculations to account for the capillary pressure and the critical-pressure and -temperature shifts in nanopores. The modified VLE was then used to study the phase behavior of reservoir fluids in unconventional reservoirs. In the penultimate paper Effect of Reservoir Heterogeneity on Primary Recovery and CO Huff ‘n’ Puff Recovery in Shale-Oil Reservoirs the UTComp reservoir simulator was used to simulate both primary recovery and CO huff ’n’ puff recovery in the middle Bakken formation of the Elm Coulee field. The study suggests that reservoir heterogeneity leads to a faster decline of recovery rate in the production stage. The closing study Nonempirical Apparent Permeability of Shale shows that a combination of Darcy flow and Knudsen flow (i.e., ignoring the Klinkenberg effect), can describe gas flow for a range of Knudsen flow applicable to a shale-gas system.

Finally, as you all know the ATCE 2014 meeting is right around the corner, so what better time to catch up! I look forward to seeing many of you then, but in the meantime enjoy the read!