Technology SummaryKC Yeung, Brion Energy - Issue Coordinator
A variety of subjects are covered by the five technical papers included in this issue.
Since proposed by Roger Butler in 1989, vapour-assisted petroleum extraction (VAPEX) has been touted by some as a possible alternate recovery process to steam-assisted gravity drainage (SAGD) for the oil sands in the near future. However, it is realized that the viscosity of the bitumen in Alberta would be too high for VAPEX to become viable commercially. Butler had at one time suggested to me that it might be better to try out VAPEX in reservoirs with lower viscosity first and learn from there. Interest in VAPEX has dropped over the last few years because of a low rate of production, high cost of injected solvent, and also probably low natural gas price—which makes people to stay with SAGD. With continuous noises on the environmental impact of thermal methods using steam, interest in heated VAPEX has picked up, as evidenced by the current field pilot implementation of the N-Solv and the enhanced solvent extraction incorporating electromagnetic heating (ESEIEH) processes. The paper Experimental Evaluation of Heated VAPEX Process by Haghighat and Maini provides a temperature (and thus the viscosity), below which the performance of heated VAPEX would not be improved significantly. With that information, it could also suggest what initial reservoir viscosity VAPEX would be viable.
Another unconventional resource which is getting more conventional each year is tight gas. A hybrid approach combing analytical and empirical methods is proposed in the paper Effect of Heterogeneity in a Horizontal Well with Multiple Fractures on the Long-Term Forecast in Shale Gas Reservoirs by Nobakht et al. to provide a long-term forecast of multifractured horizontal wells with heterogeneous completion (different fracture lengths). One cannot underestimate the usefulness of these simpler (than numerical simulation) methods, especially when there are time and resources constraints. This method is tested by comparing to a simulated case and an actual field case and will be further tested in future against different fracture networks.
In our first of the two papers in Well Tests, Short Term Testing Method for Stimulated Wells—Field Examples by Kutasov describes an unconventional well-testing method not just for the developed radial flow (which the conventional approach of using the Ei function can be applied), but also for the linear of linear-radial transition flow periods. In essence, this method can be applied for any values of flowing or shut-in time and will work best at large values of negative skin factors (i.e., for stimulated wells). This technique is validated by a buildup test conducted in two acid-fractured oil wells. The second well-test paper, Rescaled Exponential and Density-Based Decline Models: Extension to Variable Rate/Pressure-Drawdown Conditions by Ayala et al., deals with more-realistic gas well-testing situations where the bottomhole pressure (BHP) and flow rate both decline in time instead of assuming the BHP remains constant. Again, this modified analytical decline model is validated by comparing with numerical simulation results.
Finally, in the Geostatistics for Reservoir Delineation paper, Impact Map for Assessment of New Delineation Well Locations by Zagayevskiy and Deutsch, a methodology is proposed to guide the placement of delineation wells. The authors pointed out that fewer delineation wells can be drilled if they are placed smartly by producing an impact map and making the selection based on the highest impact to reduce the local and global uncertainty in the volume of original oil in place or other alternate properties. Both numerical and analytical approaches can be used for impact-map calculation. The latter approach does not require a significant amount of realizations and generates more-stable results, but care must be taken to select the proper model response in order to account for the dynamic properties of the reservoir.
About the Issue Coordinator
KC Yeung is Director of Oil Sands Technology at Brion Energy in Calgary, Alberta. He has worked in the heavy-oil industry for more than 36 years, primarily in the area of reservoir development. Yeung has been involved in various in-situ field projects, including cyclic steam stimulation (CSS), steamflood, in-situ combustion, cold heavy-oil production with sand (CHOPS), and SAGD.
Yeung was a Distinguished Lecturer for the Petroleum Society of CIM. He has given lectures and training courses on heavy-oil recovery and SAGD in Canada, the United States, China, South America, and the Middle East to promote Canada’s in-situ heavy-oil technology. Yeung was also a member of the evaluation committee on the SPE Reprint Series No. 61, Heavy Oil Recovery. He holds BSc (with distinction) and MSc degrees in mechanical engineering, both from the University of Hawaii.
Yeung was the 2005–2006 president of the Canadian Heavy Oil Association (CHOA) and the 2007 chairman of the Petroleum Society of CIM. He received the Lifetime Achievement Award from the Petroleum Society of Canada in 2009 and the SPE Regional Services Award from SPE Canada in 2011.
Effect of Temperature on VAPEX Performance discusses the experimental evaluation of VAPEX performance at elevated temperatures. VAPEX tests were conducted in a preheated physical model over a range of 22 to 60ºC, using propane as solvent. VAPEX experimental setup, procedure, and operating conditions are described. Free-fall-gravity drainage as a key mechanism contributing to oil production parallel to the VAPEX mechanism is discussed. The maximum possible rate of enhancement that can be obtained by increasing the formation temperature is quantified. Results can be used to define the upper limit of oil rates achievable with heated solvent injection and also to assess the applicability of VAPEX to warm reservoirs naturally.
Short Term Testing Method for Stimulated Wells –Field Examples discusses the successful application of the new solution of the diffusivity equation for a cylindrical source in processing pressure/time data for stimulated wells. For stimulated wells, the dimensionless time based on the apparent well radius can be small. As a consequence, the conventional assumption of where the wellbore is considered as a linear source (radial regime of flow) is not valid. The new solution can be used for small values of dimensionless time (typical for linear and transitional regimes of flow). For two acidized oil wells, the buildup pressure/time data (taken before the Horner Plot data) were used to determine the formation permeability and skin factor. The suggested method can be applied by production managers of oil companies to evaluate the efficiency of wellbore stimulation operations (hydraulic fracturing or acidation) conducted by oilfield service companies.
Rescaled Exponential and Density-Based Decline Models: Extension to Variable Rate/ Pressure Drawdown Conditions demonstrates that gas/well decline-curve forecasting under variable BHP conditions can be undertaken successfully on the basis of density-based approaches that use rescaled exponential models and also circumvents pseudotime and material-balance pseudotime calculations when written in terms of cumulative production and actual material balance.
In Impact Map for Assessment of New Delineation Well Locations, an approach is developed to place wells at locations that have the highest impact on our assessment of resource uncertainty. The current well locations and uncertainty, structural complexity and fluid contacts are processed in a mathematical model to predict the impact of drilling at any particular locations. Two algorithms are developed to compute the impact map, which summarizes the influence of drilling a new well at any location of the lease area. The numerical approach is straightforward to implement, but computationally expensive for large complex petroleum systems. An analytical approach is more efficient for these complex problems. The research results are demonstrated with simple synthetic and a realistic case study. The approach is suitable for numerous reservoir settings where delineating the reservoir and reducing uncertainty are priorities.