This paper highlights the current state of fiber optic distributed acoustic sensing (DAS) technology by reviewing its application to hydraulic fracture diagnostics in a multi fractured horizontal well (MFHW). It will be shown that, with the advent of DAS, a gap in the feedback — which could previously occur using various hydraulic fracture diagnostic options — has been filled. Results are shared that were obtained from the first successful application of high resolution DAS during the placement of multiple hydraulic fractures in a horizontal well that was completed with an open hole packer and frac valve system. Observations of the real time acoustic soundfield in the near wellbore (NWB) region during hydraulic fracturing are presented as high resolution images. These images have enabled an analysis of key dynamic aspects of the fracturing process. In examining the resultant data, it has become apparent that DAS has overcome some limitations intrinsic in other diagnostic tools such as distributed temperature sensing (DTS), microseismic monitoring, and tracer programs. An overview of the well design is provided as well as selected samples from the dataset which highlight some of the events that were observed during the hydraulic fracturing process. Sample images are used to demonstrate the current capability of DAS measurement, selected both from the real time soundfield display (SFD) and from processed high resolution soundfield maps. DAS processing methods are briefly discussed, as well as two categories of field observations— which highlight some of the mechanical reliability aspects of the swell packer/ball actuated frac sleeve system, as well as some aspects of the near wellbore region during hydraulic fracturing such as single or multiple fracture initiation sites and the general behaviour of wellbore fluids over the course of the fracture treatment. Distributed acoustic sensing using a single mode optic fiber has been described in recent literature (Molenaar, 2011) for applications involving the recording of acoustic events during various stages of well completion and stimulation. The current paper provides further description on how DAS works and shares results from a high resolution DAS survey, obtained while placing multiple hydraulic fractures in a horizontal well, completed in a tight sand using an openhole ball actuated valve system with swell packers for fracture isolation. Earlier findings are supported, in particular that DAS will enable an improved understanding of in-wellbore activities and, in so doing, that it will enable optimization of hydraulic fracturing design and execution. It is recognized that much is yet to be learned in the processing of fiber optic DAS data, but also that it would be beneficial to share the work that has been completed to date to facilitate accelerated development of DAS processing technology.

The literature describes several applications where Aphron fluid technology has been applied in both drilling and re-entry scenarios and includes an extensive description of how this fluid system works. A highly efficient leak-off prevention mechanism makes aphron based fluid systems beneficial for certain completion and workover applications as well, where formation damage could be avoided by the practical elimination of fluid-fluid or fluid-rock interaction or where simply the workover objectives can be achieved by obtaining efficient circulation of fluid to surface. Completion and workover applications for this fluid system have not been extensively reported. This paper reviews three applications of Aphron fluid technology in different completion and workover scenarios. The selected cases were reviewed to present some of the technical and operational lessons learned and to some extent discuss the observed formation cleanup behavior. The following three applications were reviewed: completion of a dual string sour gas well, using an oil based aphron system for kill fluid, with practically no kill fluid loss to a hydraulically fractured formation; the completion of additional zones within a depleted dolomitic limestone formation on two wells where the method of Aphron fluid placement was found to significantly affect fluid losses; and finally, the enabling of the provision of annular pressure support at pressures which approached the hydraulic fracture opening pressure of a shallow zone while hydraulically fracturing a deeper zone through tubing with a packer. Introduction The mechanisms by which the Aphron fluid system operates make it a reliable tool for certain completion and workover applications. These mechanisms have been described extensively in the literature (Brookey 1998; Ivan et al 2001; Growcock et al. 2005a; Catalin et al. 2002; Hoff, O'Connor and Growcock 2005). Moreover, the presentation of field performance data for Aphron fluids in drilling and re-entry operations is also extensively published (Ivan et al. 2001; White et al. 2003; Brookey et al. 2003; Rea et al. 2003 and Kinchen et al. 2001). Lessons learned from the performance of Aphron fluids in a wide range of applications have caused a specific profile to evolve for the effective use of this fluid technology. Brookey (1998) showed that the high low shear rate viscosity (HLSRV) of the Aphron fluid system, which provides the proper environment for aphron bubble formation and survival, also provides a high resistance to flow under low shear conditions, which significantly inhibits initial fluid loss to the formation. Brookey (1998), supported by Ramirez et al. (2002) showed that the creation of aphron aggregates is an effective filtrate control mechanism which further reduces fluid loss. Formation damage prevention is attributed to the inert gas which makes up the majority of an aphron aggregate, combined with the limited amount of fluid invasion into a potential leakoff zone. Adverse fluid-fluid and fluid-rock reactions are prevented because the completion and workover fluid is not available as a reactant or contaminant.

Performance optimization of steam assisted gravity drainage (SAGD) well pairs requires awareness of unique and sometimes complex downhole processes. Reservoir monitoring tools commonly used to characterize the downhole pressure and temperature environments include thermocouples, pressure gauges, and discrete or distributed fiber-optic sensors. Distributed temperature sensing (DTS), the most common fiber-optic measurement used for SAGD reservoir monitoring, has been widely adopted for SAGD production monitoring due to its ability to accurately measure a wide variety of temperatures in harsh environments. High-measurement density along the entire SAGD well length has proven to be useful for both production optimization (Krawchick et al. 2006) and well-integrity applications. Though DTS monitoring is a primary downhole measurement tool for thermal production, other sensors may further characterize the nature of SAGD well performance when used in conjunction with DTS. Alone, temperature and pressure measurements may not yield a complete understanding of the inflow contribution in SAGD production wells. For instance, the effects of complex heat transfer may mask reservoir temperatures. Additionally, high temperatures are not always indicative of inflow and cooler liner temperatures may not signify the absence of production contribution. Distributed acoustic sensing (DAS), which is used to measure acoustic frequency and intensity in 1-m intervals along the length of a fiber-optic line, is another downhole measurement tool currently being evaluated for its ability to provide additional downhole wellbore information. Although DAS has been commonly used to characterize the acoustic environment in hydraulically fractured horizontal wells (MacPhail et al. 2012, Holley et al. 2015), it has not been extensively applied in SAGD well pairs. This paper shares select DAS and DTS monitoring data from a pilot well, the results of which improved the operator's understanding of the nature of the SAGD production. In late 2012, Devon Canada installed DTS multi-mode fiber in several production wells at SAGD assets in the McMurray Oil Sands. Single-mode fiber utilized for DAS were deployed in conjunction with multi-mode fiber, allowing simultaneous logging of DTS and DAS data throughout the wellbore. Temperature and acoustic datasets were obtained at different representative flow conditions, including stable production, rate step-down, early time shut-in, and well startup. The combined analysis of DTS, DAS, and surface production data shows that DAS was able to identify steam flashing and qualitatively define production inflow contribution and gas/liquid composition. Due to the complex, bi-directional flow in the trial well, some of these conclusions would not have established without the observations obtained from DAS monitoring.

This paper is a case history which examines the successful application of Intelligent Completion (IC) technology in a cost sensitive, mature, onshore North American environment where an existing hydrocarbon miscible flood (HCMF) horizontal injection well was retrofitted to manage the injection support of two geologically distinct reservoir regions covering two well patterns. The value of IC technology is explored in this early deployment which saw a relatively low cost application targeted towards a mature asset. The beneficial results of this application of IC technology were measured in terms of well intervention cost savings and affected oil production. This paper presents a relative comparison of those benefits. Though this application of IC technology was originally justified by the avoidance of certain future well interventions to modify the injection profile, an analysis of the affected pattern production in the post-installation period showed that the benefit to the operator was appreciably more from enhanced reservoir management than from the cost savings which were associated with workover avoidance. Based on the success described in this case history, and reflecting upon the trends of intelligent well and smart field technology, the authors explore reasons for its relatively slow uptake in moderate production rate, brownfield applications. Large scale reservoir management of miscible flood projects using intelligent well and smart field technologies should provide significant value in terms of improved solvent/oil ratio through more efficient monitoring and management of the flood. This is probably the most compelling value proposition for IC technology application in moderate production rate land applications. This case history is intended to provide credible evidence of the benefit of IC technology in an application with cost challenges analogous to those faced by operators who are responsible for cost sensitive, moderate production assets. Secondly, it is intended to encourage the IC technology providers to develop more solutions for the brownfield segment of the industry, where profitability and value definition can be challenging. Introduction Intelligent completion technology provides the ability to partition a wellbore into distinct segments, and to monitor and control the flow of fluids into or out of each segment, upon demand, without physical intervention. The first integrated application of this technology took place in the North Sea in 1997, and to date, close to 600 wells have been equipped with intelligent well completions world wide. The key elements of intelligent well technology are packers or seal elements which allow partitioning of the wellbore, flow control valves, downhole sensors, power and communications infrastructure, and a surface data acquisition and control system to remotely gather data and actuate the flow control valves. The downhole sensors may be electronic or optical fiber based, and typically measure pressure, temperature or flow rate. The function of the flow control valves may be binary (on-off) or choking, and are typically adjusted by hydraulic or electro-hydraulic actuation systems. Each wellbore segment is usually associated with a separate hydrocarbon reservoir, a separate layer or compartment within a reservoir with complex geology, separate laterals in a multi-lateral well, or with segments of long horizontal wells. By using the capabilities of downhole monitoring and flow control, the flow of fluids into or out of the reservoir can be modified to restrict or exclude unwanted effluents, to commingle separate reservoirs in a controlled fashion (Konopczynski, 2003) and to improve the hydrocarbon recovery efficiency of the development project. Intelligent completions have been applied to production wells, injection wells, and dumpflood wells (Glandt, 2003) in offshore platform, subsea and land based locations.

High torque-and-drag (T&D) values can increase the difficulty of installing tubing in extended reach steam-assisted gravity drainage (SAGD) wells. Extra surface applied compressional force (tubing jacks) is often needed to land the tubing, leading to increased completion operation time and costs, and increased hazard potential. In many cases the likelihood of sinusoidal and helical buckling of the production tubing is also significant. A method of running tubing in extended-reach horizontal wells is presented which uses pipe floatation to reduce sliding friction in the lateral section. For SAGD wells in the subject area, the operator was able to eliminate the use of tubing jacks to run production tubing to the toe of the well. Data was acquired that allowed the comparison of tubing load conditions, both with and without the floatation method. This data was also compared with torque-and-drag (T&D) modeling results to illustrate the reduction in friction that was achieved and quantify the benefit of the method.Typically, SAGD wells are completed with two strings of tubing: a long tubing string landed near the toe of the well, and a short tubing string landed near the heel of the well. This is to facilitate the circulation of steam in the early stages of well development. Landing tubing at the toe of the well can be challenging in high ratio extended-reach wells due to the combined effects of frictional forces in the lateral section and the relatively shallow vertical depth of the reservoir.The conventional method to land tubing in extended-reach or mega-reach SAGD wells utilizes tubing jacks, also known as Љpull-downsЉ, to apply force to the tubular after it stops moving under its own weight. This method can be used to successfully land tubing, but is inefficient due to additional rig up time for the jack equipment, and slow run-in-hole speeds when compared to running tubing into the well under its own weight. Additionally, tubing that encounters resistance when running in the hole, is more susceptible to helical and sinusoidal buckling which can result in early fatigue, plastic deformation and lock-up of the tubing during running (Wu and Juvkam-Wold 1993).