OverviewThe articles presented in this issue cover a diverse set of topics under the umbrella of unconventional resource exploitation. The first two articles are focused on improvements in the simulation of steam-assisted gravity drainage (SAGD). The remaining three articles address subjects in the areas of bitumen and solvent mixture characterization, petrophysical analysis of tight gas or oil formations, and wellbore leakage in CO 2 sequestration, respectively.
A New and Practical Workflow for Large MultiPad SAGD Simulation—An Oil-Sands Case Study by Colin Card and a team of associates from Computer Modelling Group and Statoil intends to extend reservoir simulation of the SAGD process to large multipad models. The authors present a clear and thoughtful description of a workflow to achieve this end. The focus of the workflow is on “tuning” to improve the run time and stability of large SAGD simulation models. There are three aspects to this tuning: geological tuning to clean up the fundamental reservoir model; numerical tuning to balance run time against the quality of the solution; and, dynamic grid tuning to balance the accuracy of a fine-grid solution with the reduction in run time on a dynamically coarsened grid. The authors provide a detailed commentary on an example they have selected to illustrate the key points of their workflow, and for which they have achieved a reduction in simulation run time by nearly an order of magnitude. As the authors note, their methodology is generic in the sense that it could be applied to the simulation of any recovery process. It will be interesting to see how the concepts presented in this article are taken up by others working in reservoir simulation.
Practical Control of SAGD Wells with Dual Tubing Strings by Terry Stone and a set of colleagues drawn from Schlumberger and Chevron presents the results of a simulation study on methods for operating SAGD well pairs with dual-tubing strings on the basis of monitoring injection- and production-well temperatures. The focus of the study is on improving the uniformity of steam-chamber development in heterogeneous reservoirs. The approach taken by the authors in their simulations is to try to enforce a specified temperature offset between the injector and producer by controlling steam-injection rates in each injection string through the use of a proportional-integral-derivative (PID) feedback controller. They offer a detailed argument as to the advantages of this approach. The authors used several synthetic permeability patterns to test the effectiveness of the PID controller in coping with reservoir complexity. In general, their results were positive. However, as the authors imply, the use of simulation to explore the effects of well operation strategies on SAGD reservoir performance is still in a state of development. Much remains to be done in this field.
Modelling of Bitumen and Solvent-Mixture Viscosity Data Using Thermodynamic Perturbation Theory by Mohsen Zirrahi and coauthors from the University of Calgary presents a semitheoretical model to predict the viscosity of solvent-saturated bitumen over a range of temperature and pressure. The model is tuned by using experimental data on the viscosity of the pure solvent to fit some of the parameters and experimental data on the viscosity of the solvent-saturated bitumen to fit other parameters. The predictive capability of the model was tested against a publicly available set of experimental data on the viscosity of solvent-saturated Cold Lake bitumen, involving four different solvents (methane, nitrogen, carbon dioxide, and ethane). As the authors note, the results of the testing against this data set showed acceptable accuracy. This is promising. However, further testing of the model would likely be prudent before it is applied under conditions outside the range covered in the data set tested (e.g., those that could occur in steam-based bitumen recovery processes involving solvent coinjection).
Quantitative Properties From Drill Cuttings To Improve the Design of Hydraulic-Fracturing Jobs in Horizontal Wells by Camilo Ortega and Roberto Aguilera from the University of Calgary intends to develop a tool to improve the design of multistage hydraulic fracturing in horizontal wells drilled in tight gas or oil reservoirs. The authors propose a method to extract quantitative information from drill-cuttings samples taken from a horizontal well in a tight formation, and to combine this information with offset well logs to obtain estimates for petrophysical and geomechanical properties because they vary in the formation along the horizontal well. The estimated parameter values can be represented in a so-called “cut log” for the horizontal well to identify potential intervals for stimulation with hydraulic fracturing. The authors emphasize that their approach is not intended to replace detailed petrophysical and geomechanical studies, but rather a pragmatic use of drill cuttings to obtain quantitative information about the reservoir when cores are not available. While they use a case study involving a tight gas formation in western Canada exploited with horizontal wells to illustrate the key procedures in their method, they note that their methodology should also be suitable for applications in either unconventional or conventional reservoirs regardless of the type of well used for exploitation of the resource.
Effect of Dynamic Loading on Wellbore Leakage for the Wabamun Area CO2-Sequestration Project by Runar Nygaard and a team of colleagues from the Missouri University of Science and Technology and RPS Energy Canada presents the results of a study evaluating the leakage potential of existing wells within a prospective CO 2 storage area west of Edmonton. The focus of the article is on a simulation-based exploration of potential leakage pathways in a CO 2 sequestration well that could be generated by mechanical and thermal loading. The approach followed in the simulation study was to model the mechanical behaviour in a representative vertical segment of a cased borehole within an interval of the caprock above the zone targeted for CO 2 sequestration. The results of the numerical modelling indicate that there is a risk to wellbore integrity under certain conditions as a consequence of mechanical damage to the cement sheath between the casing and the formation, either through tensile fractures forming in the cement or a disruption of the bond between cement and casing. While the authors view their work as an improvement on previous geomechanical analyses of wellbore leakage problems in CO 2 sequestration wells, it is clear that they feel substantially more work remains.
About the Issue CoordinatorRon Sawatzky is a Principal Researcher with Alberta Innovates—Technology Futures in Edmonton, with 25 years of experience working in research and development for heavy-oil recovery processes. For many years, he served as a team leader for the cold production research group within the Heavy Oil & Oil Sands business unit at Alberta Research Council. Sawatzky was an SPE Distinguished Lecturer in 2008-09. He obtained a PhD in applied mathematics from the University of Alberta in 1987.
Paper SummariesA New and Practical Workflow for Large MultiPad SAGD Simulation—An Oil-Sands Case Study presents a detailed methodology to tune highly heterogeneous multi-million cell multi-well pair SAGD simulation models for optimum numerical performance. Two approaches are used sequentially: first, a 3D sub-model is tuned numerically to optimize performance; secondly, dynamic gridding is applied to selected 2D cross-section models and the parameters controlling the dynamic gridding are optimized for run time and accuracy when compared to the original fine grid 2D cross sections; finally the 3D sub-model with dynamic gridding applied is retuned numerically. All the tuning is conducted using a commercial thermal reservoir simulator and commercial multi-objective function optimization softwares. Recommendations are also provided for cleaning up the geological model to improve simulation performance.
Practical Control of SAGD Wells with Dual Tubing Strings discusses the ability to improve steam utilization and conformance in a Steam Assisted Gravity Drainage bitumen recovery process using conventional dual tubing strings in both the injector and producer. Steam injection from each string is controlled by a Proportional-Integral-Derivative (PID) feedback controller that monitors temperature differences between injected and produced fluids in each half of the well pair. This technology is examined with accurate simulation studies that look at various types of reservoir heterogeneity, update frequency of the controllers and ability of the controllers to cope with flow paths that are either forming or firmly established.
Modelling of Bitumen and Solvent-Mixture Viscosity Data Using Thermodynamic Perturbation Theory presents a semi-analytical viscosity model to estimate the viscosity of solvent-saturated bitumen, a key parameter for engineering design and simulation of bitumen production and transportation. This model can be used to predict the viscosity of pure solvents (CH 4, C 2H 6, N 2, CO, CO 2) and solvent-saturated bitumen. The proposed model provides an accurate prediction of the viscosity of bitumen saturated with light hydrocarbon and non-hydrocarbon solvents. The experimental data of Cold Lake bitumen were used to calibrate the model. These data cover the typical T-P-x ranges of heavy oil recovery processes.
Quantitative Properties From Drill Cuttings To Improve the Design of Hydraulic-Fracturing Jobs in Horizontal Wells discusses the successful application of a new methodology with a view to improving the results of multi-stage hydraulic fracturing in horizontal wells. The uniqueness of the approach is that drill cuttings, a direct source of information that has been used mostly qualitatively in the past, is used in this study quantitatively for determination of porosity, permeability, Poisson’s ration, Young Modulus and Brittleness Index. This information is integrated with binocular microscope observations of structural features and petrology. Knowledge of these combined properties allows optimization of stimulation jobs. The methodology is illustrated with the use of a case history in a tight gas formation in the Western Canada Sedimentary Basin.
One of the main risks identified with storing CO 2 into the subsurface is the potential for leakage through existing wells penetrating the cap rock.
Effect of Dynamic Loading on Wellbore Leakage for the Wabamun Area CO2-Sequestration Project evaluates the integrity of wells in conducted as a part of a feasibility study of large scale injection in a study area near Lake Wabamun. Potential leakage is discussed in the paperon the basis of the knowledge of well design, current well status, and historical regulations in the area. The paper also outlines the methodology and results by conducting finite element simulations in order to evaluate the risk of creating leakage pathways by thermal and pressure changes caused by CO 2 injection. The study concludes that the risk of well leakage is less than first anticipated and that the total number of wells required to be re-entered was low.