Ambastha

Papers in this issue of SPE Res Eval & Eng focus on enhanced oil recovery, reservoir modeling, and tight gas/shale reservoirs. The following is a brief outline of the papers in this issue primarily in authors' words.

Enhanced Oil Recovery

A Microvisual Study of the Displacement of Viscous Oil by Polymer Solutions reports on water/oil and polymer-solution/oil displacement experiments in a 2D etched-silicon micromodel. Conventional hydrolyzed polyacrylamide solutions and newly developed associative polymer solutions with concentrations ranging from 500 to 2,500 ppm were tested. The crude oil had a viscosity of 450 cp at test conditions. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water breakthrough and low recoveries. Above a concentration of 1,500 ppm, plugging of the micromodel by polymer and lower oil recovery were observed for both polymer types. The associative and conventional polymer solutions improved oil recovery by approximately the same amount. The associative polymers, however, showed more-stable displacement fronts in comparison with conventional polymer solutions. Based on hydrolysis experiments, Chemical Degradation of Polyacrylamide Polymers Under Alkaline Conditions shows that auto-retarding kinetics under alkaline conditions limits hydrolysis at 100°C whereas complete hydrolysis occurs under neutral conditions. In-situ hydrolysis of initially unhydrolyzed polyacrylamide is proposed as a promising strategy for alkaline/surfactant/polymer floods because the injectivity of the unhydrolyzed polyacrylamide will be greater than that of hydrolyzed polyacrylamide because of its lower initial viscosity. The lower initial viscosity is not a disadvantage because once it has been hydrolyzed in situ, its viscosity will increase. The Effect of Redox Potential and Metal Solubility on Oxidative Polymer Degradation is an attempt to resolve some of the discrepancies in the literature regarding the occurrence and extent of oxidative degradation, as well as to present a coherent framework for discussing the multitude of possible radical reactions. Sodium carbonate and bicarbonate are demonstrated to play a key role in stabilizing polymer against multiple reported sources of degradation, and it seems likely that this is caused by their effect on iron solubility. Care must be taken to ensure that degradation is not caused by the injection of a polymer solution containing oxygen into a formation containing iron. Sodium dithionite can be added downstream of the last exposure to oxygen to combat degradation in field applications. The use of sodium carbonate may also mitigate degradation owing to the oxidation of iron (II) during polymer hydration. Systematic Surveillance Techniques for a Large Miscible WAG Flood describes a systematic approach for applying enhanced oil recovery surveillance tools and methods in large miscible WAG floods in the Ivishak reservoirs at the Prudhoe Bay field and Eileen West End of the North Slope, Alaska, USA. Highlights of these surveillance methods are (1) designed and implemented by a multidisciplinary team, (2) based on proven theory and corroborated with field data, (3) require easily obtainable and relatively inexpensive field data and analysis, and (4) applied from fault-block down to zone levels. Implementation of these tools has helped to identify the efficiency of flood patterns and areas of poor performance, which then can be modified through infill drilling, well recompletion, or WAG-ratio modification to maximize enhanced oil recovery. Study of Alkaline/Polymer Flooding for Heavy-Oil Recovery Using Channeled Sandpacks presents the results of a laboratory study of alkaline/polymer flooding for heavy-oil recovery, including viscosity measurements, flood tests conducted in channeled sandpacks, residual-resistance-factor determination, and residual-oil-distribution tests. A heavy oil with a viscosity of 1,202 cp and an acid number of 1.07 (mg KOH/g oil) and produced brine collected from a heavy-oil reservoir in Alberta, Canada, are used in this study. Pressure buildup during chemical-slug injection is the key to the improvement of displacement efficiency. Flood tests also show that alkaline/polymer flooding is more efficient than either alkaline flooding or polymer flooding. The optimal formulation for the heavy oil used in this study is 0.4% NaOH + 0.2% Na2CO3 + 1,000 mg/L of polymer, with a tertiary oil recovery of 25–30% of original oil in place over waterflooding. Solvent-Type and -Ratio Impacts on Solvent-Aided SAGD Process uses an extensive 2D simulation study to better understand the drainage mechanism of steam with solvent coinjection in the steam-assisted gravity-drainage process. This paper shows that the condensation time difference of solvent and steam results in different films of gas solvent, liquid solvent, and water along the fluid interface. Coinjecting the solvent at low concentration ratios can take advantage of the solvent dilution effect without losing too much heat effect from steam. In addition, this study indicates that coinjection of suitable solvent mixtures may lead to better performance than injection of pure solvent in the field.

Reservoir Modeling

Innovative Alternative to Full-Field Compositional Modeling--Case Study of the North Kuwait Jurassic Complex discusses an integrated asset modeling framework in which multiple separate reservoir models are coupled through global constraints to meet gas delivery targets. The solution uses a black-oil delumping technique to obtain compositional well streams while running black-oil simulation models. Comparison of results obtained from a compositional model with those obtained from a black-oil model using black-oil delumping shows excellent agreement. A Multiresolution Analysis of the Relationship Between Spatial Distribution of Reservoir Parameters and Time Distribution of Well-Test Data develops a multiresolution wavelet approach to estimate the spatial distribution of reservoir parameters, by performing the nonlinear least-squares regression in the wavelet domains of both time and space. As a test of the approach, authors applied the model to well-test problems involving 1D (radially composite) reservoir systems. The inverse problem was solved to estimate the distributed permeability values by performing the nonlinear least-squares regression in the wavelet domains (time and space). Results obtained were compared with those obtained from the conventional nonlinear regression approach, using all the pressure/time data and the full set of spatial reservoir parameters. The time/space wavelet approach provides a good means to integrate different data properly while avoiding the inclusion of irrelevant data during nonlinear regression.

Tight Gas/Shale Reservoirs

Cumulative-Gas-Production Distribution on the Nikanassin Tight Gas Formation, Alberta and British Columbia, Canada evaluates performance of 271 wells producing exclusively from the Nikanassin and equivalent formations in a large area of more than 15 000 km2 in the Western Canada Sedimentary basin, Alberta and British Columbia, Canada. Cumulative-production characteristics within each area were evaluated with a variability distribution model developed recently for naturally fractured reservoirs. Analysis of the distributions leads to the conclusions that the Nikanassin is a very heterogeneous formation and that there is significant potential for massive infill drilling to drain the formation efficiently. Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs proposes an alternative approach to estimate expected ultimate recovery from wells in which fracture flow is dominant and matrix contribution is negligible. For fracture flows at a constant flowing bottomhole pressure, a log-log plot of rate over cumulative production vs. time will yield a straight line with a unity slope regardless of fracture types. In practice, a slope of higher than unity is normally observed because of actual field operations, data approximation, and flow regime changes. A rate/time or cumulative production/time relationship can be established on the basis of the intercept and slope values of this log-log plot and initial gas rate. Field examples from several supertight and shale gas plays for both dry and high-liquids gas, and oil production, were used to test the new model. The results show that this alternative approach is easier to use, gives a reliable estimated ultimate recovery, and can be used to replace the traditional decline methods for unconventional reservoirs.

As you study your favorite paper(s) to enhance your own knowledge and/or apply in your work activities, please recognize that SPE welcomes further "discussion" of any of the papers published in any SPE journal, including this one. Therefore, please feel free to submit discussion of a paper either online or by mail to SPE.

Sincerely,

Anil Ambastha, Chevron