Steam-assisted gravity drainage (SAGD) has become the de-facto standard for commercial development of heavy oil and bitumen (HO-B) reserves in a significant number of fields. Although SAGD has proved to be a highly effective technique, many uncertainties and unanswered questions still exist, leaving room to improve production and optimize the economics of a SAGD installation. One notable improvement originating from recent field experience is the novel usage of injection/inflow control devices (ICDs) in a conventional SAGD well pair. The use of a properly designed ICD completion is proving beneficial to both steam chamber development as well as improving the inflow profile of the producing well of the SAGD pair. Work conducted in the Surmont field of Alberta, Canada provided an excellent starting point to optimize flow control improvements to the SAGD process. However, significantly more needs to be added to the discussion to establish best practices for ICD selection and usage and to quantify the benefits gained from using autonomous ICDs in HO-B reservoirs. It is the goal of this paper to provide a useful reference for ICD behavior and theory, selection criteria, the unique role of ICDs in managing steam chamber development, steam fingering control, and management of the subcool temperature (steam trap control). Representative field simulations of Albertan bitumen sand are used as the basis for describing overall trends in the use of flow control in the SAGD process.
The integrity of Steam-Assisted Gravity Drainage (SAGD) wells are often threatened by the very steam that provides the process its name. High rate steam production, or the adiabatic flashing of steam condensate to a vapor state, often creates an environment of Љflashing erosionЉ, erosive damage created by the water-cutting effect of high velocity wet steam or the corrosive elements (e.g., carbonic acid) that can be associated with low temperature condensate. Condensate flashing to steam also carries additional risk from Љcavitation erosionЉ, erosion of completion equipment that occurs from the sudden shock wave impacts caused by the implosion of small liquid-free zones with the condensate, similar to the wellunderstood water hammer effect. Conventionally, to prevent the production of live steam or the flashing of steam condensate, operators have relied upon choking production rates based upon monitored temperature differences between injected and produced fluids. However, this methodology based on subcool carries its own risks and undermines the economic viability of SAGD projects. Another approach is to improve conformance of steam injection and fluid production by installing inflow/injection control devices (ICDs) in either, or both, the SAGD injector and producer. If properly designed, these devices in the producer can equalize heel-to-toe influx of bitumen emulsion, provide greater control of the sub-cool, and behave as an autonomous (or self-regulating) valve. This presentation will focus upon this last design objective. By coupling published performance equations for various ICD designs with steam behavior equations, competing designs will be evaluated for their likelihood of steam flashing within a SAGD completion and their respective ability to control flashed steam prior to the steam creating damage in the completion. Further, the discussion will examine possible future avenues of research, such as ICD designs with a steam throttle effect driven through a velocity-sensitive choking of steam production.
The concept of one completion tool affecting overall recovery from a field may seem unlikely at first thought. This is due to the fact that standard procedures in the oil industry have long designed completions on a well to well basis rather than analyzing the effect that said completions would have on field-wide hydrocarbon recovery. When the deliverability of a reservoir is evaluated, the well is usually thought of as a pressure point, a simplification used to make predictive modeling easier. However, when multiple wells are drilled and completed with maximized reservoir contact, the completions used within these wells have significant impact on the overall recovery from their associated drainage areas. As such, wells should no longer be treated merely as pressure points if one desires a realistic premise from which to predict field performance. This paper revolves around simulations carried out comparing cases with different completion installations. The completion designs were as follows: 1-Standard Screen 2-Passive Inflow Control Devices (PICD) with Open-Hole Isolation PackersThe use of PICDs is not widely understood by the industry as the operational criteria that determine the technology's effectiveness have not made it universally necessary. These essential screening criteria have been largely explored in published literature, particularly the works of Martin P. Coronado, et al. Yet once a positive assessment has been made and PICD is seen as a viable option, an execution of a time-dependent simulation for describing completion performance over time should be the next step in the process. Evaluating the performance of a completion over time is extremely important as conditions are always changing throughout the life of the well. Examples of conditions that need to be factored into the performance of the completion include the following:1-Fluid Saturations 2-Changing fluid properties (Pressure and temperature dependent) 3-Reservoir Pressure 4-Production Drawdown (Pressure difference between the drainage region pressure and flowing bottom hole pressure) a. Associated flow rates at the sand face and into the completion In all modeled scenarios, the criteria to justify the use of PICD were met. Establishing a link between the completion design and a numerical reservoir simulator was achieved, with the resulting output evaluated by researchers. When comparing the simulated completion types, the effectiveness of installing PICDs was made apparent with results that showed a significant increase in recovery factor of up to 4% when compared to the Standard Screen case.
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