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.
Frac packing is a completion technique that merges two distinct processes-hydraulic fracturing and gravel packing. The main challenge of a frac-pack completion is the successful creation of high-conductivity fractures with the tip-screenout (TSO) technique and the placement of proppant within those fractures and in the annulus between the screen and wellbore wall. This is further compounded by having to do so in an ultra high-permeability environment, in which high fluid-leakoff rates are evident.From 1997 to 2006, job data from more than 600 frac-packing operations, representing an estimated 5% of the worldwide total, have been compiled into a database. This paper reviews well information and key frac-packing parameters. Also summarized are engineering implementations and challenges, best practices, and lessons learned. Essential frac-pack design parameters that were attained from the step-rate test (SRT) and minifrac test are evaluated. These include bottomhole pressure, rock-closure time, and fracturing-fluid efficiency. Downhole pressure and temperature are also discussed because of their importance to the post-completion efficiency evaluation and fracturing-fluid-optimization phase.Worldwide case histories are provided that demonstrate how to both deploy different frac-packing systems and pack the wellbore during extreme conditions with improved packing efficiency and a higher chance of success. Frac-Packing Downhole Tools and ProcedureDeepwater completions have constantly challenged placement design. Pumping rates have been increased to handle longer treatment intervals or to maximize proppant placement. Therefore,
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.
Passive inflow control devices (PICDs) have been in use for decades as a tool to manage both frictional effects within the completion system and reservoir heterogeneities that result in an unbalanced injection or production profile. These tools provide an additional pressure drop at select points along a well lateral, evening the distributed flow profile and maximizing economic recovery of oil and gas. Conventional applications of PICDs have become increasingly well understood, yet novel uses still exist, such as the use of PICDs in steam-assisted gravity drainage (SAGD) environments. The SAGD well is characterized by a number of challenges, including poor development of the steam chamber, low reservoir pressure, uneven oil production, and contrasting reservoir permeability. In this paper a typical Albertan SAGD environment is considered against known PICD behavior to quantify the economic benefits of PICD use in the SAGD well pair. Furthermore, the specific benefits of hybrid-geometry autonomous PICDs are highlighted for use in the production well, focusing on possible "steam trap" effects with this geometry. Lessons learned regarding PICD simulation in a thermal environment are shared, outlining a suggested workflow for future modeling work.
This paper covers the novel application of combining shape memory polymer (SMP) conformable screen with inflow control devices (ICD) to provide operational efficiency, wellbore stability and production enhancement in unconsolidated reservoirs openhole completion. It is not uncommon to have unconsolidated reservoirs with permeability heterogeneity. It becomes more challenging when the formation sands are non-uniform and poorly sorted. The Conventional solution for these type of reservoirs encompasses the use of gravel pack techniques in combination with sand control screens that are equipped with inflow control devices (ICD). However, operational execution is complex and risky especially when openhole isolation packers are added to isolate and compartmentalize the multiple zones. An alternative solution to this challenge is the simplified combination of SMP conformable screen with ICD. An SMP conformable screen with ICD replaces the burdensome gravel pack operation, provides conformable sand control and maximizes the benefits of the already proven inflow control technology. This integrated application brings efficiency to well site operation by reducing the quantity of downhole accessories, reducing rig site operating hours, and saving overall capital expenditures (CAPEX) or operating expenditures (OPEX). The shape memory polymer provides improved wellbore stability and efficient sand control regardless of the uniformity of formation sands in the different reservoir layers. The combination with ICDs will ensure that production longevity and recovery are optimized by efficiently equalizing inflow profiles. Technical contributions which include filtration performances, inflow control modeling and completion fluid management are provided to expatiate on the performance analysis of this innovative approach in resolving a critical challenge in horizontal sand control completions.
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