A method has been developed for improving both steam injection and production conformance in a thermal EOR project by utilizing intelligent well technology incorporating interval control valves (ICV), well segmentation and associated downhole instrumentation. This provides the ability to selectively open and close segmented sections of the well bore and monitor the key parameters of temperature and pressure from surface. The initial field trial is ongoing in the injector of an Orion field SAGD well pair. Development of the completion system suitable for thermal conditions, initial field trial results and plans for further development are described. Modelling shows that, depending on the level of heterogeneity present in the reservoir, an improvement of 20 to 40% in the steam oil ratio and 5 to10 % in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam trap control can be applied in a segmented horizontal well pair. A cost effective solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance resulting in increased energy efficiency and oil recovery. The method being developed is applicable to a wide range of EOR processes such as CSS, steam drive and variations. The initial field deployment in the injector well was primarily to prove operability of the system in high temperature thermal applications, to demonstrate the feasibility of modifying steam distribution and to learn for future optimization and deployment of the system. A successful installation and commissioning has substantially validated the completion technology. Early injection test results and data provide a significant improvement in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of steam injection in the well is underway and the preliminary results are discussed. Lessons learned from the trial are highlighted. The intelligent completion technology under trial, and proposed further developments, should enable more extensive use of downhole measurement and control in thermal EOR projects to improve performance.
Non-contiguous acreage positions commonly lead to drilling azimuths parallel to section boundaries. Analysis of well-performance with drilling azimuth across plays in North America reveals that on-azimuth wells (parallel to σHmin) are typically better than off-azimuth wells. A simple, but elegant microseismic trial by Athabasca Oil Corporation has two wells on the same pad, thus minimizing geological variability; one on-azimuth and one 45°-off-azimuth, from which rock failure and connectivity can be assessed. Microseismic from the hybrid fracture treatments in the two wells shows a large contrast in event density, with the on azimuth well showing far fewer events, but double the productivity. There is also a difference in treatment fluid, with the on-azimuth well having 1/3 more gel and 1/3 less slickwater, although total injected volumes are equivalent. Events were filtered in multiple ways; by stage, every 5 minutes within a stage, by fluid type, and by magnitude to understand the azimuthal, stress and completions controls on the mechanics and the productivity. The treatments of the two wells have very different spatial patterns of microseismic events as detected by both surface and downhole arrays. The 45°-off-azimuth well has a well-developed longitudinal frac which is interpreted to facilitate re-stimulation of previous stages. In-situ stress calculations show that both shear failure and bedding parallel stimulation are more likely with an off-azimuth well. Furthermore, the 45°-off-azimuth well has two distinct domains during gel treatment; near-wellbore and far-field. The intensity of structural features is interpreted to be similar between the two wells, so is not thought to control the difference in event density. Filtering by event magnitude shows that the 45°-off-azimuth well also has more larger events in the far field, presumably enabled by the higher proportion of slickwater. Several hypotheses exist to explain the poorer 45°-off-azimuth well performance: 1) near wellbore frac complexity introducing tortuosity, measured by a pressure drop after breakdown; 2) out-of-stage re-stimulation causing inefficient treatments and potential over-flushing with a loss in near well-bore conductivity supported by generally lower breakdown pressures in the 45°-off-azimuth well, and; 3) planes of shear failure pinching out, resulting in areas of stranded connectivity. A conceptual model is developed that shows how shear and tensile failure may be preferentially developed in the off- and on-azimuth wells respectively, supported by in-situ stress calculations and an analysis of the S/P ratios from microseismic amplitudes from both wells. Other authors (e.g. Cipolla et al., 2014) recognized that the size of the event cloud is not necessarily proportional to productivity, but in this trial the inconsistency is striking. The interpretation herein, supports the assertion that tensile failure in the hydraulic fracturing process is largely aseismic (e.g. Maxwell & Cipolla, 2011; Warpinski et al., 2013) and that off-azimuth drilling has a higher risk for delivering lower quality fracture treatments.
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