The demand for drilling and completing horizontal wells in both conventional and unconventional oil and gas plays has drastically increased in recent years. A growing economic and environmental appetite for ever increasing horizontal lengths continues to apply pressure on drilling and completion technologies. Although well engineering programs have improved and adapted to solve some of these issues, coil tubing reach capabilities can, at times, become the limiting design factor for horizontal wells. To tackle this issue, the industry has developed and adopted the use of downhole friction reduction tools to optimize and extend the range of coil tubing. Using case history from Shell Canada’s Groundbirch shale gas development, this paper will compare and analyse the effectiveness of three different downhole friction reduction tools currently available to industry. While this paper will discuss the use of Tubing Force Analysis (TFA) modeling software to obtain representative values for comparison, the focus of the study is to compare the overall effectiveness of the three friction reduction tools using actual field data.

The Shell Canada Fox Creek asset is located in West Central Alberta and has development activities focused on the Duvernay reservoir. Efficient, horizontal, plug and perf wells, are key to delivering economic production from this unconventional light tight oil play. Unlocking more acreage per well, through the application of longer laterals, contribute significantly to CAPEX reduction. Although intervention-less completions are a future aspiration, well intervention is still required for plug removal to assure stimulated intervals are able to flow unimpeded. A number of initiatives were actioned collaboratively across service providers and well delivery teams, to support well intervention to the limits of Coiled Tubing (CT) milling operations on the FC734 D well. Considering the length of this well (7349mMD), a new string design was required to achieve the maximum depth as well as to provide the required WOB for milling operations. Horizontal wells with long laterals, such as in this case, require heavy wall tubing in the vertical section to beyond the heel into the lateral. Using a special custom-designed transition section in the Coiled Tubing string enabled the CT to reach the maximum depth. Utilizing fluid rheology application provided a means to keep track of Reynold's number in a real-time fashion to ensure turbulent flow regime downhole, and in turn, to optimize solid transport as well as chemical consumptions. The application of fluid rheology resulted in wiperless milling operation in the extended reach applications. The flagship unit in the fleet was utilized in this operation. Generation four of the CT unit was designed in such a way that it can carry up to 8,345m of 60.3mm(2-3/8in) CT pipe. There were different technological advancements, industry-leading features, and custom engineering used in the design of this unit. Such features include customized PLC automation, user-friendly remote operation, advanced informative human-machine interface displays, and real-time data acquisition and data storage from vast arrays of operational sensors. There is a twofold impact on the field development plan when the total measured depth (MD) was increased. First, this enables the operator to increase step out/generate drilling optimized trajectories without sacrificing lateral length. Second, the 400m/well increase in MD when applied principally to the lateral length netted an average increase of 250m/lateral in the subject area and reduced the well count by 4% (pad count reduction of 10%). The synergy impact of utilizing several variables resulted in successful operations. Those variables are field development plan (well design), custom string design (CT reach), real-time fluid rheology (solid transport), and the application of an advanced CT unit (equipment advancement). The successful delivery of the FC734 D well demonstrated the value of collaborative design and best practice sharing and has extended the technical design limit of well lengths across Shell Unconventional.

As the industry advances on horizontal drilling and slim hole design, well completion and specifically hydraulic fracture stimulation remains the most expensive part of the well construction process in Unconventionals. Proppant and fluid make up a significant portion of the stimulation cost of a well, it is therefore a key lever in cost reduction. This submission will examine the transition from Conventional to Unconventional stimulation designs with respect to technical and economic factors that drive fluid and proppant optimization. The authors will then focus on the industry journey in multiple step change transitions from high viscosity fluid system with high strength premium proppants towards low viscosity fluid system and lower strength natural proppant. In each case, technical justifications based on theory, laboratory testing, or field trial data from Shell unconventional basins will be discussed. The authors will also briefly review several strategic approaches in proppant and fluid sourcing from the logistics perspective. Relevant cost data will also be used to reflect the overall impact of the evolution. This paper reveals that significant cost reduction can be achieved by right sizing fracture conductivity through reduction on premium high strength proppants and shifting towards a low viscosity system, as well as leveraging appropriate supply chain strategy.