Automated Approach Optimizes Flow-Control Device Placement in SAGD Completions

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Steam-chamber conformance in steam-assisted gravity drainage (SAGD) influences the efficiency and economic performance of bitumen recovery. Conventional SAGD well-completion designs provide limited control points in long horizontal well pairs, leading to development of nonideal steam chambers. The complete paper presents an automated approach to optimizing placement of flow-control devices (FCDs) in SAGD well-pair completions. The methodology uses a coupled wellbore/reservoir model to simulate both reservoir fluid-flow behavior and detailed wellbore hydraulics. The qualities of the well-completion-design parameters and their effect on production are assessed by calculating the net present value (NPV), which is considered the basis for optimization.


The Lower Cretaceous McMurray formation hosts the majority of bitumen in the Athabasca oils sands—the largest known resource of bitumen. The formation is composed of large-scale fluvial-estuarine point bars and other laterally accreting channel systems that are highly heterogeneous. The formation has been interpreted as having three stratigraphic subdivisions: a lower continental (fluvial), a middle fluvial-estuarine unit (point-bar dominated), and an upper marginal marine deposit. The repeated erosional cut and fill events within the McMurray have led to nested and multiple stacked structures. Similarly, laterally accreting channel systems, such as point-bar deposits consisting of inclined heterolithic strata of sandwiched sand-siltstone sequences and abandoned mud channels, lead to very complex sedimentary facies relationships in which rock types change both laterally and vertically over very short distances.

SAGD completions offer the most promise of producing bitumen resources from Athabasca oil-sands deposits. The SAGD well configuration typically consists of two parallel horizontal wells within a short distance, one above the other. Steam is injected into the upper well and fluids are produced from the lower well.

These design schemes provide limited control of steam injection and liquid production along horizontal sections and adversely affect steam-chamber conformance. Operational difficulties, drilling, well completion, and reservoir parameters moderate overall SAGD performance. More specifically, these factors include hydraulic gradients and pressure drop in the tubulars, injectivity and productivity variations along the wellbore from plugging and formation damage, heat exchange, energy loss to bottom water, nonparallel well-pair placement, well undulation, and—most importantly—reservoir heterogeneity and structure. The conventional SAGD well completion needs to be modified to deliver steam efficiently throughout the reservoir interval, improve liquid-production performance, and minimize steam breakthrough.

FCD Use in SAGD Completions

Various well-completion strategies and downhole tools have been considered in order to improve steam injection and bitumen-production flow conformance. Scab liners (tubular completions) have been implemented successfully in SAGD well completions to facilitate heat conformance across the horizontal section. These have been effective in protecting electrical submersible pumps, reducing sand production, and reducing steam-to-oil ratio (SOR). Sections of blank liners have been implemented in SAGD production and injection-well completion design. Completion designs using blank pipes have been implemented to introduce variable open-to-flow areas and to meet desired skin factors. These improve overall performance by diverting flow paths between injector and producer, providing control over steam distribution, and preventing steam short-­circuiting where the distance between producer and injector is less than target values. Scab liners also may be run across nonreservoir rock intervals. Slotted liners with various slot densities, and wire-wrapped, punched, and other completion screens with various open-to-flow areas are also designed and used to control inflow to the producer and outflow from the injector. However, they provide limited control of fluid-flow rates over the entire length of the horizontal sections.

FCDs have been implemented in advanced wellbore completions to improve flow performance. A significant factor in the application of FCDs is the long-term reliability of the device to regulate flow over the lifetime of the well (e.g., 25 years). However, FCDs are passive, and fluid flow cannot be regulated on the basis of process feedback. In the case of excessive gas or water production in a segment of an oil well, the device cannot be adjusted in real time to counter the effects of higher mobility of these fluids in the reservoir. Devices equipped with sliding sleeves have been implemented to adjust and make changes to the number of ports or modify the open-to-flow area of the device to enhance production performance. Autonomous FCDs also have been designed and used in wellbore completions to actively counter highly mobile gas flow and regulate flow rate. These devices self-­regulate the drawdown by changing the flow restriction, creating both improved reservoir performance and well operation. Autonomous FCDs have been implemented with limited success, mainly because their continuous operating life is short and relatively high-cost.  

Applications of passive FCDs in SAGD well completions have shown success in improving production performance. They provide sufficient control to regulate steam distribution along the injector and fluid production in the producer, and prevent steam breakthrough. Long-term durability and compatibility of the devices in the high-temperature operating conditions of thermal-recovery processes have led to more-frequent field trials and applications.

Many authors have reported and discussed application of FCDs in thermal-recovery processes.

The complete paper includes a detailed discussion of the components of the optimization algorithm. The key techniques involved in the optimization procedure and determination of the location of FCDs in the SAGD well completion designs are highlighted.

Case Study and Results

A case study was established to form a basis for comparison by examining the application of FCDs and the performance of parameter optimization. The reservoir model was constructed from the Conoco­Phillips Surmont Phase 1 SAGD project. A typical vertical profile of the McMurray formation in the area used for this study shows an overall fining upward sequence composed of a series of upward fining cycles. It consists of a meander-belt deposit in the uppermost part of the formation and two underlying older deposits. Thin, regionally deposited fine-grained sandstone and mudstone cover the meander-belt deposit. The caprock is defined by a marine flooding surface at the base of the Wabiskaw member.

To enhance the predictive capabilities of the model, detailed geological features of the meandering channel-belt deposits were considered in construction. The geological model not only reflects the complex rock properties in 3D space, but also includes spatial-­distribution characteristics of inner structural elements.

A subcritical-type FCD available in the industry was used, and the location of devices was optimized. Liners were used for both injector and producer.

The best NPV found for this case study is greater than $7 million. This is higher than the base-case model with dual-tubing string toe-and-heel completion, which achieved an NPV of under $6 million. This translates to an approximate 7% increase in expected NPV. Additionally, using liner-deployed FCDs provides control over the entire length of the horizontal section and eliminates the need for a long tubing string. Optimal FCD placements for this example are illustrated in Fig. 1.

Fig. 1—Optimal FCD placements for the injector and producer (vertical exaggeration is 7.5 times). The optimal location is a function of pressure drop in the device and tubulars, reservoir structure, reservoir heterogeneity, and well-deviation survey (generally well undulation) for both injector and producer. OCD=outflow, ICD=inflow.


  • The proposed method determines the number of devices in each SAGD well pair and their optimal placement.
  • Reservoir structure—and detailed reservoir heterogeneity obtained from a comprehensive geological modeling of point bars—is taken into consideration in optimal device placement.
  • The application of FCDs in SAGD well-completion design leads to higher bitumen recovery at lower SOR and reduces capital costs by using smaller-diameter liner and eliminating the need for a toe tubing string.
  • Results indicate superior performance of the wells equipped with FCDs compared with conventional concentric and parallel dual-string well-completion designs.
  • Additionally, results show that use of zonal isolation in the well design is essential for compartmentalized reservoirs, such as point-bar deposits with their significant heterogeneity.
  • The optimization algorithm presented in this paper uses minimal iterations compared with previously implemented algorithms available in the literature. The algorithm entails implementing a revised trust-region method, which has been modified for solving mixed-integer problems. The algorithm finds the global minimum of the problem with significant savings in computational efforts that can be achieved in comparison with other algorithms. Although in this paper the focus has been on the optimization of the location of FCDs, the trust-region method has the potential for applications in the optimization of other nonlinear problems.
  • The integrated assisted-optimization approach considers uncertainties in geological properties and determines the optimal FCD parameters and
  • well-completion design with acceptable computational effort. This integrated work flow allowed the authors to undertake a thorough evaluation of the key subsurface uncertainties and design an overall development plan.
  • The probabilistic nature of the results legitimize quantifying the uncertainties and identifying associated risks for different completion strategies.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 193364, “Optimization of Placement of Flow-Control Devices Under Geological Uncertainty in Steam-Assisted Gravity Drainage,” by Siavash Nejadi, Stephen M. Hubbard, Roman J. Shor, SPE, Ian D. Gates, SPE, and Jingyi Wang, SPE, University of Calgary, prepared for the 2018 SPE Thermal Well Integrity and Design Symposium, Banff, Alberta, Canada, 27–29 November. The paper has not been peer reviewed.

Automated Approach Optimizes Flow-Control Device Placement in SAGD Completions

01 December 2019

Volume: 71 | Issue: 12

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