Executive Summary

Tayfun Babadagli, University of Alberta

The 10 papers selected for the April 2012 issue of SPE Res Eval & Eng focus on the advancements in heavy-oil recovery, chemical enhanced oil recovery (EOR), and reservoir modeling.

Reservoir Modeling

The first three papers cover different aspects of reservoir modeling and simulation practices. Reservoir Modeling: From RESCUE to RESQML reports a new and efficient gridding standard that minimizes the amount of redundant geometric information needed to construct the grid. The new system called RESQML was first introduced in 2008 by a consortium formed to develop a transfer system for structural framework, 3D gridded models, and well data. The RESQML model provides an interaction with real-time production drilling domains, transferring giga-cell models retaining the geologic and geophysical data associated with 3D grids. The paper presents the challenges and way forward for 3D and 4D reservoir model exchanges by sharing the details of the technical designs and demonstrating the efficiency of the RESQML standard. 

The next paper, Equation-Of-State Modeling for Reservoir-Fluid Samples Contaminated by Oil-Based Drilling Mud Using Contaminated-Fluid Pressure/Volume/Temperature Data, introduces a method to correct the pressure/volume/temperature (PVT) data of oil samples contaminated by oil-based muds during the collection process. The method was described as an approach integrated with equation-of-state (EOS) modeling for "numerically cleaned" reservoir fluid compositions. The authors observed that the aromaticity of the reservoir fluid may deviate substantially from the one contaminated with oil-based mud. The numerical-cleaning procedure described did not require any nonstandard laboratory data and the suggested method can be applied to any oil-based mud and well type. Two examples with varying degrees of contamination were presented and these examples showed that the combined numerical cleaning and EOS modeling process can be used to correct the PVT properties obtained from contaminated fluid samples. 

The final Reservoir Modeling paper in the April issue, Advanced Upscaling for Kashagan Reservoir Modeling, presents an advanced upscaling approach using a field case (the Kashagan field). The effective transmissibility was upscaled rather than permeability. After comparing the two upscaling approaches (transmissibilities vs. permeability) for the huge carbonate origin Kashagan field using single-phase and gas-injection problems, they observed that transmissibility upscaling yielded runs with coarse-scale full-field simulations in a few hours without loss of consistency. The paper concluded that the permeability based coarse models are too optimistic and overestimate the intercell connectivity, resulting in inaccurate performance estimation. Transmissibility based upscaling can be a solution for large carbonate fields.

Heavy-Oil Recovery

Extensive numerical studies were conducted to evaluate the efficiency of steam-assisted gravity drainage when hexane, butane, and methane additives were coinjected with steam in the paper titled Numerical-Simulation Investigation of the Effect of Heavy-Oil Viscosity on the Performance of Hydrocarbon Additives in SAGD. Numerical tests were performed using three characteristic deposits in Canada: Athabasca, Cold Lake, and Lloydminster. It was reported that hexane coinjection was more advantageous in Athabasca than in Cold Lake and Lloydminster. Butane coinjection was beneficial in the Athabasca reservoir only at a higher butane concentration. Hexane coinjection in Cold Lake and Lloydminster decreased the steam/oil ratio by 20 and 15%, respectively. Methane coinjection into the Athabasca reservoir negatively affected the oil production but showed better performance in the Cold Lake and Lloydminster reservoirs if injected at a very low concentration to avoid steam-chamber-growth deceleration. 

An extensive experimental study supported by numerical and visualization validations is reported inMechanics of Heavy-Oil and Bitumen Recovery by Hot Solvent Injection. The experimental results on different permeabilities and sizes of sandpacks and sandstones showed that the solvent recovery by propane and butane at elevated temperatures is very sensitive to temperature and pressure. The peak recovery was obtained when the solvent was in the gaseous phase and the pressure and temperature were just near the saturation line. Visual experiments on 2D Hele-Shaw models supported by numerical modeling studies indicated that asphaltene flocculation occurred as soon as the equilibrium of the heavy oil in the system was broken by changing composition caused by solvent injection. This meant that the maximum amount of asphaltene flocculation (and deposition) took place at the first interaction of solvent injected and heavy oil. Asphaltene flocculation was higher for propane in comparison to butane but increasing flocculation did not necessarily yield more asphaltene deposition.

Chemical EOR

Effect of Alkalinity on Oil Recovery During Polymer Floods in Sandstone reported core experiments for polymer, alkali, and alkaline-polymer flooding of 5-cp crude oil on Berea sandstones. The tests were performed for their tertiary recovery potential for different polymer viscosities and alkaline concentrations with consideration of the adsorption of the polymer. It was observed that tertiary alkali produce no significant additional oil as opposed to straight polymer injection, which yields a significant pressure increase resulting in considerable oil recovery. Alkaline-polymer, on the other hand, showed a good recovery but less pressure increase and improved injectivity and reduced formation damage. A 3D numerical model study using the relative permeability data obtained was also added. 

In the paper Residual-Oil Recovery Through Injection of Biosurfactant, Chemical Surfactant, and Mixtures of Both Under Reservoir Temperatures: Induced-Wettability and Interfacial-Tension Effects, the authors presented the EOR potential of a biosurfactant produced by a Bacillus subtilis strain isolated from oil contaminated soil from an oil field in Oman. Up to 50% of residual oil recovery was obtained from coreflooding experiments when the biosurfactant was mixed with chemical surfactants, which is above the performance of the biosurfactant alone. The biosurfactant was capable of altering the wettability of the rock and its adsorption was compatible with the chemical surfactants. 

The next paper under this category, Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery, tested foam as an EOR agent for fractured oil-wet carbonates experimentally. Although it required a significant amount of foam (very high volumes of throughput), oil recovery by injection of pregenerated foam went up to 78% original oil in place compared to surfactant (2.5%), water (10%), or gas (3.9%) only injections. The foam was successful in diverting the flow into the matrix and reducing the gas mobility. 

The last paper of this category, Interwell Tracer Tests To Optimize Operating Conditions for a Surfactant Field Trial: Design, Evaluation, and Implications, presents an interwell tracer test done for well injectivity and sweep efficiency. The test that took nearly 15 months was evaluated through analytical and numerical simulations. The communication was found to be poor resulting in a low swept volume. However, the test was considered inexpensive and successful as it improved the understanding of the heterogeneity, connectivity, and sweep in the reservoir to evaluate the surfactant trial without bias. Finally, a new tracer design was optimized by correcting low sweep efficiency and poor hydraulic control through history matching of the first test.

Unconventional Gas

In the final paper of this issue of SPE Res Eval & EngEvaluation of Long-Term Gas-Hydrate-Production Testing Locations on the Alaska North Slope, the authors identified the key features of the potential test site and provided new information about natural gas occurrence in the Greater Prudhoe Bay area. After evaluating the locations in the Milne Point, Kuparuk River, and Prudhoe Bay units from geological conditions and operational risk points of view associated with conducting a successful gas hydrate production test, the Prudhoe Bay Unit L-Pad site was selected as the best candidate based on lower temperature and low geologic risk (i.e., less heterogeneity). The paper provided extensive coverage of the selection process and the data collected as to the distribution of the gas hydrate.

Tayfun Babadagli
University of Alberta