Happy New Year. The oil prices hovered around $90 per barrel during 2012 and the focus on Canadian oil sands with $1 trillion barrels of original bitumen-in-place in the Athabasca region continued. Federal government stated that if all the energy projects currently slated over the next 25 years are developed, they will contribute $4 trillion to Canada’s gross domestic product and generate as many as 1 million jobs. A large portion of these projects are related to oil sands. While the demand for innovative and environmentally sustainable oil-sands extraction technology will continue to execute these oil-sands projects, market access seems to be another Achilles heel for the industry. Not only is there a discount between the benchmark West Texas Intermediate (WTI) and Brent crudes, but western Canadian oil production is being discounted again relative to WTI. The situation is compounded further by the currently large price differential between heavy and light oil, which disadvantages heavy-oil and bitumen producers further because of the constrained access to specialized refineries needed to process heavy oils. The difficult task of getting the export infrastructure built has to start now. Expanded production of bitumen will be essential in maintaining Canada’s role as the major source of crude oil in the 21st century if we can find the right balance between oil-sands development, market access, security of supply, and the environment. We have an excellent selection of papers in this first issue of 2013 to expand our technology perspective.
Although it was introduced by Roger Butler more than 30 years ago in 1978, steam-assisted-gravity drainage (SAGD) is still in its infancy. While there are a number of successful commercial projects, we also encounter projects that are experiencing challenges. Jorshari and O’Hara describe one such challenge in a heavy-oil pool where one of the producers had a compromised wire-wrapped screen and could not produce. The problem was successfully remedied by drilling another producer in the opposite direction.
Solution gas is produced in SAGD field operations. Historically, it has been impossible to simulate this phenomenon numerically without using artificial-gas properties. The accurate prediction of the performance becomes even more critical in mature projects as companies contemplate methane coinjection during the later stages of operations, which could lower the energy intensity and environmental impact while potentially increasing reserves. Gittins, Gupta, and Zaman describe a numerical simulation study for fully understanding and being able to describe the impact of gas on SAGD performance without having to use any tricks. They show that axial-pressure gradients and the resulting axial flow of steam and noncondensable gas may be a critical mechanism.
Another way to reduce the environmental impact and operating cost of thermal recovery methods is to combine it with solvent injection. However, the phase behaviour data on heavy oils and solvents is scarce, particularly at high temperatures. Li and Yang present an investigation where the phase behaviour of propane, butane, and heavy-oil systems at high pressures and elevated temperatures is studied experimentally and results are matched with an equation-of-state model.
With more than 15,000 wells drilled, the Horseshoe Canyon of western Canada has emerged as a significant unconventional coalbed methane gas play in North America. The complex geological history of the coals and noncoal interbeds has imparted strong vertical and lateral heterogeneities that make the play difficult to characterize using conventional methods. In this follow up work, Clarkson, Behmanesh, and Chorney focus on wells with inclining gas production and compare the use of multilayer and equivalent single-layer-well-test analyses.
Relative permeability is one of the most important parameters in understanding and predicting reservoir performance. Although most of the relative permeability measurements in the laboratory are two-phase measurements, many reservoir processes involve the simultaneous flow of three phases. In most cases, two-phase data is used to extrapolate to three-phase flow by the use of empirical correlations obtained from steady-state data. Dehghanpour and DiCarlo present an experimental study where they compare the three-phase transient data with steady-state data and find differences.
Our last paper deals with the removal of formation damage caused by drilling. One of the weighting agents used during drilling is manganese tetraoxide. Moajil and and Nasr-El-Din present their experimental results and provide some recommendations for the removal of filter cake formed by drilling fluid weighted with Mn3O4 particles to ensure the effectiveness of the cleaning operations.
Gökhan Coskuner has more than 25 years of industry experience and currently works as Manager of EOR and New Technology in the Heavy Oil and Gas Division of Husky Oil Operations Limited. Previously, he worked as Asset Manager and Reservoir Engineering and Development Lead in oil sands, as a team leader involved in the development and optimization of two deep basin gas fields, and as a reservoir engineer in projects ranging from gas storage to offshore field delineation and development. Before joining Husky Oil, he worked for Agip as a reservoir engineering advisor, for Scientific Software Intercomp as a senior consulting associate, and at Imperial Oil, Shell Canada, and the Petroleum Recovery Institute in various research capacities. He holds a B.Sc. degree from the Middle East Technical University in Turkey, and M.Sc. and Ph.D. degrees from the University of Alberta, all in petroleum engineering. He is currently the Executive Editor of the Journal of Canadian Petroleum Technology. He was a long-time member of the Journal of Canadian Petroleum Technology Editorial Review Board, a director of the Petroleum Society, and the general chairman for the 2004 Canadian International Petroleum Conference. He was the recipient of the Petroleum Society’s Outstanding Service Award in 2009.
A horizontal well-pair configuration concept which has been executed at Husky Energy in the field of SAGD heavy oil in Canada is presented. In A New SAGD-Well-Pair Placement: A Field Case Review, first the early I3-I4 SAGD well pair and its lower than expected production performance are discussed. It is followed by a production improvement plan and remediation program. A 3D reservoir simulation study and execution of the plan in order to construct an alternative producer well concept are explained, including sidetrack options. The I3A producer well drilled in a countercurrent placement concept, where its toe is located beneath of the heel of its companion injector well, Well I4. Also, the temperature log and the historical data are compared. The SAGD well pair is on operation and its early performance is compared in the paper with the reservoir simulation study. In the end, a conclusion and lessons learned are summarized.
Simulation of Noncondensable Gases in SAGD-Steam Chambers compares live- and dead-oil SAGD simulations using a 3D coupled wellbore to reservoir simulations to investigate the impact of axial-pressure gradients on solution-gas accumulation in SAGD steam chambers. The simulations showed that use of large-diameter tubing in the SAGD-injection well would cause steam to preferentially flow into the reservoir at the high pressure points and then axially along the steam chamber, rather than axially along the liner and out into the steam chamber. The resulting axial flow of steam was predicted to sweep solution gas to discrete locations in the steam chamber, where it accumulates and ultimately gets produced through the production well. Based on similarities between the SAGD steam-chamber growth and performance predicted by this simulation and field observations, it is hypothesized that flow restrictions may develop over time in real SAGD-injection wells leading to axial sweep of solution gas which may help explain why solution gas tends to be produced in real SAGD well pairs to a greater extent than predicted with simulations.
The paper Phase Behaviour of C3H8/n-C4H10/Heavy-Oil Systems at High Pressures and Elevated Temperatures presents phase behaviour data, including saturation pressures and swelling factors, that are measured for the C3H8/n-C4H10/heavy-oil systems over a wide temperature range of 298.85 to 396.15 K by using a pressure/volume/temperature set up. The measured viscosity data of heavy oil dissolved with C3H8 and/or n-C4H10 are also presented. Significant viscosity reduction and swelling effect of heavy oil can be achieved with dissolution of C3H8 and/or n-C4H10. Modelling results of the saturation pressures and swelling factors of the C3H8/n-C4H10/heavy-oil systems by using the Peng-Robinson equation-of-state are discussed. In addition, five viscosity mixing rules are examined in terms of their accuracy of correlating the measured viscosity of the C3H8/n-C4H10/heavy-oil systems.
Production-Data and Pressure-Transient Analysis of Horseshoe Canyon Coalbed-Methane Wells, Part II: Accounting for Dynamic Skin discusses the use of a dynamic skin to account for Horseshoe Canyon coal well productivity changes caused by cleanup of drilling fluids, for example. Incorporation of this dynamic skin into production analysis allows type-curve and straight-line techniques to be used in the face of changing well productivity. The technique is demonstrated with simulated and field examples. The dynamic-skin approach may also be useful for other reservoir types in which wells exhibit productivity changes.
A Comparative Study of Transient and Steady-State Three-Phase Oil Permeability reports measurements of two- and three-phase oil relative permeability using the saturation profiles obtained from two- and three-phase gravity drainage experiments. It is found that the transient three-phase relative permeability differs than the previously measured steady-state relative permeability. The three-phase relative permeability is fit using the two-phase relative permeability by using the Stone I and saturation-weighted interpolation models. It is explained how Stone I and saturation- weighted interpolation can be used to predict oil permeability usefully during a three-phase tertiary displacement.
Formation Damage Caused by Improper Mn3O4-Based Filter-Cake-Cleanup Treatments discusses complexity of filter-cake reactions with organic acids and chelating agents, and determines formation damage caused by using such fluids to remove manganese tetraoxide (Mn3O4)-based filter. Cleanup of filter cake is a difficult task and becomes more challenging in deep wells that are drilled with high-density Mn3O4-based drilling fluids. Mn3O4 is a strong oxidizing agent, which will result in complex interactions with most cleaning fluids. The examined cleaning fluids produced insoluble reaction products that will cause formation damage worse than the original filter cake. This paper will guide petroleum engineers to avoid using such acids and chelating agents to acidize or remove the filter cake in the presence of materials (e.g., Mn3O4).