The requirement for intervention operations in long laterals continues to grow. For instance, in North America and North Sea, it is required to run 2 and 2 3/8-in coiled tubing (CT) in 12,000 and 25,000 ft laterals, respectively. One of the most critical well intervention problems nowadays is that many extended reach wells that need to be serviced are more than 30–40% unreachable and contribute to lost productivity for energy companies around the world. While increasing the CT diameter remains a theoretical option to improve reach, practically, it creates logistical challenges with onshore road transport and offshore crane lifting/deck loading limitations. Other options such as using fluid hammer and tractor tools may have reasonable operational range, but they have significant limitations by increasing circulating pressures and operational complexity. To reach the remaining 30–40% un-reachable length, lubricants are required to work in conjunction with other systems. Obviously, the use of lubricants for well interventions is not new. Typical field results of current systems show a 17–25% reduction in the coefficient of friction (CoF), from a generic 0.24 to 0.18 – 0.20. However, these results compare poorly to the industry-wide lab rotational friction tests that do not take into account any downhole parameters. CoF values between 0.03 and 0.08 are usually reported in such lab tests, but never achieved in the field. In this paper, the results of an extensive set of laboratory measurements using the first in industry linear friction apparatus are reported. This instrument was designed to take into account the downhole effects of temperature, pressure, CT sliding speed, surface roughness, and fluid composition. The lab results show that the pressure and the sliding speed have weak effects of friction, while temperature, surface roughness, and fluid type and composition have strong effects. More than 6,000 measurements were performed with many combinations of CT and casing samples and lubricants currently used in field operations. Based on these laboratory results, a new lubricant was designated that reduces the linear CoF by approximately 42–58% (from the default CoF of 0.24 to 0.10–0.14) under downhole conditions. Friction of this magnitude is expected to make it feasible to run CT in all previously un-reachable laterals and decrease the operational time when fluid hammer or tractor tools are used. Several North America field trials with the new lubricant are also reported. The field CoF values obtained are in the 0.12 to 0.14 range and validate the new laboratory methodology. Friction reduction of this magnitude is expected to double the reach in long lateral wells without lubricant. Previous field CoF calculation studies for determining predictable lateral reach are also reviewed. The laboratory and field results with the new lubricant challenge the current industry understanding of the CT friction and show great benefits for our industry in extending the reach of lateral wells.

As a result of many industry efforts, the premature fatigue failure of undamaged coiled tubing (CT) strings is almost negligible. However, despite the current understanding and control of low-cycle fatigue, CT string failures remain present in the industry. Several prior technical publications reviewed the causes and trends of CT string failures that occurred within the period of 1994 to 2005. This paper will review CT failures mechanisms and trends as observed over the last twelve years and compare them to the prior ten years period. It will also review the new failure mechanisms that have appeared with more challenging operational conditions and the associated actions taken to reduce their influence. Within one major service company, all failures that occur are analyzed for the root cause(s) of failure. This results in the identification of corrective actions to avoid their recurrence. Statistical data is kept to observe trends on failure causes. Several technical publications show that approximately 80% – 90% of CT string failures within the period of 1994 to 2005 were associated with corrosion, mechanical damage, human error, and string manufacturing problems. Actions taken in the last two decades by the CT services companies, and constant improvement implemented by CT manufacturers have reduced the influence of some of these causes. However, work in ever-more challenging well conditions (such as higher pressures, temperatures, and depths), the need to use larger-diameter and higher-strength CT, and the use of recycled fluids for the interventions, have created new issues and introduced new CT failure mechanisms. The new mechanisms within the industry include: microbiologically influenced corrosion (MIC), premature fatigue failures on bias welds of high-strength grades, and mechanical damage associated with pipe slippages. This paper will compare the failure trends reported for the period before 2005 with the trends observed for this service company within the period of 12 years after 2005 (i.e., from 2006 to 2017). The changes in the failures trends are analyzed, and examples of the newer CT failure mechanisms and the mitigating actions taken are presented.

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Horizontal fracture stimulated completions remain the de facto method of producing from shale formations. The vast majority of wells are completed using the "Plug and Perf" fracturing technique which later requires either a drill string or coiled tubing (CT) with a positive displacement motor (PDM) to remove the composite plugs. An estimated 6,000 to 8,000 wells are completed each year, with between 100,000 to 140,000 composite plugs installed in them in the U.S. alone. In extended reach horizontal completions, plug removal using CT becomes less efficient since end load forces transmitted to the PDM from the coiled tubing decrease as well depth increases.Currently many operators rely on 'word of mouth' to design and perform extended reach CT jobs, resulting in 'nonengineered' and poorly executed plug milling operations. However, one new method to extend the operating envelope of efficient coiled tubing plug milling utilizing a water hammer tool has gained significant momentum. Several water hammer tools are in common use and there is significant anecdotal evidence that their application has improved job efficiencies. This paper reviews plug milling efficiencies and general best practices from milling operations conducted in shale formations across the US (Eagle Ford, Bakken, Haynesville, Barnett and the Marcellus). The scope will cover operations completed with three different fluid hammer tools and base cases conducted without these tools.The paper will also discuss milling efficiencies, number of stalls, stuck pipe incidents, speed and frequency of wiper trips and fluid selection associated with plug milling operations. The authors believe that the information presented in this paper will provide relevant analytical data to assist operators in improving the overall efficiency of the completion process.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractTo increase the predictability of successful coiled tubing operations, a review of recorded versus predicted weights was undertaken for several Statoil operated Norwegian platforms. Results from thirty-three wells were analysed and showed that a coefficient of friction of 0.24 was applicable in most wells. Additionally, it was confirmed that deviation complexity, production rates and direction of travel had no effect on the friction coefficient.