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A significant problem confronting Operators in modern field development and production is that created by loss of functionality of the surface controlled subsurface safety valve (SCSSV) due to blockage of, or damage to, the hydraulic control line. The consequent loss of hydraulic pressure to the valve means its closure, the resultant loss of production and the need to provide an alternative safety system in order to continue exploiting the wells reserves Currently two alternatives are available:○A full scale workover to pull tubing, replace the inoperable control line and restore functionality to the SCSSV.○Installation of a velocity or dome charged subsurface controlled subsurface safety valve (SSCSSV). The former approach requires a major expense, which may not be justifiable in a mature well, while the reliability offered by the latter approach typically does not meet well integrity requirements and can sometimes lead to reduced production. Nederlandse Aardolie Maatschappij (NAM) has been faced with this problem in many onshore and offshore wells and was determined to find an alternative solution. Based on the successful completion of a previous development project, NAM asked Weatherford to jointly develop a solution to this problem, which would allow the installation of an alternative control line without the expense of a workover. In this paper the authors will review the problems associated with loss of control line functionality and consequent SCSSV malfunction. They will go on to describe in detail the joint project which led to the development, testing, and eventual field deployment of the Weatherford Damaged Control Line (WDCL) Safety Valve featuring surface control, which can be installed using wireline and capillary string techniques. Introduction In any and all field developments which incorporate surface controlled subsurface safety valves a significant potential problem exists with the hydraulic access conduit. When a control line is used to provide hydraulic power to the safety valve, the danger is ever present that it could become blocked or damaged thus rendering the safety valve inoperable. When such a situation occurs there are normally two possible alternatives to be considered in order to restore safety valve control to the well and thereby facilitate continued safe production:○The well can be worked over to pull the tubing, replace the damaged control line and recomplete the well with a functioning safety system. This approach involves major expenditure which, in more mature wells, can often be financially unjustifiable because the remaining reserves may be insufficient. In the case of NAM operations the approximate cost of such a workover is in the range 6 - 8 million Euros which makes it a fiscally unattractive approach.

As part of its objectives to increase recoverable reserves and reduce development costs in Norway's Oseberg field, Norsk Hydro has aggressively employed extended reach horizontal drilling over the past four years. Critical to the success realized in the Oseberg development program has been the use of an integrated steerable drilling assembly that features a near-bit sensor providing real-time measurements of the well path, thus enabling drilling in a corridor of one to two meters. Problems with orienting fixed cutter bits in the highly demanding sliding mode necessitated the use of tungsten carbide insert (TCI) roller cone bits to follow the required trajectory. This paper describes the development of new IADC 437 and 447 Class TCI bits, which culminated in a unique gauge cutting structure with diamond-enhanced, chisel-shaped cutting elements. The authors will review the bearing, seal and cutting structure limitations of conventional roller cone bits used in earlier Oseberg wells, emphasizing the negative impact of excessive gauge wear and short bearing life to overall well costs. Laboratory and field data will be presented, with emphasis on the lessons learned during extensive cutting structure and bearing/seal examinations. The successful application of the new design in the Oseberg development drilling program will be discussed in detail. Introduction Norway's Oseberg field, located approximately 130 km north-west of Bergen, was discovered in 1979 and is presently being developed via two platforms - the Oseberg B and C - which are situated 15 km apart. The Oseberg reservoir section is located in the Middle Jurassic comprising several sand units: the Tarbert Upper and Lower Ness, Etive and Oseberg formations (Fig. 1). The Tarbert shows subangular and subrounded sandstones moderately sorted with a thickness of up to 60 m TVD. Firm and blocky coal and silty claystones sequences interbed the sandstones in the Ness formation. The Etive shows angular to subrounded sandstones with silicate cementation and siltstones at the base. The Oseberg formation is the main reservoir, consisting of medium to coarse-grained fan delta sandstones of excellent reservoir quality. The vertical thickness is 20 to 60 m TVD. The Rannoch claystone sequence separates the Etive and Oseberg formations. The first horizontal well was drilled on the field in 1992, and since then 20 wells have been successfully drilled and completed. Over that time, the lengths of both the horizontal section and the Total Measured Depth (TMD) have increased progressively. In 1995, Well C-26A established a then-world record with its 7,853 m horizontal displacement. In that well, the horizontal section was 2,100 m and the total depth 9,325 m. In early 1996, the first multi-lateral wells - C12A, B and C - were successfully drilled from the Oseberg C platform. To maximize the recoverable hydrocarbons in the horizontal reservoir sections, the deviations from the trajectory have to be kept within a tight tolerance on vertical and tangential variations (often 1m). The tight tolerances force the operator to drill the reservoirs with a reservoir navigation tool (RNT). Both fixed cutter (PDC) and roller cone tungsten carbide insert drill bits (TCI) are used, depending on the lithology and operating demands. Historically, dulled TCI bits exhibited severe abrasive wear in the gauge area, frequently resulting in under-gauge hole and early seal failures. Thus, to avoid the risk of losing cones, the operator was forced to pull bits after short times on bottom. Lost cones generally cause difficult and expensive fishing jobs. P. 541^

In designing completions for deep, high-temperature applications, operators have historically concentrated their efforts on two sections, either the upper or lower completion. By focusing solely on the two sections, operators have been unable to maximize the compatibility of the entire well completion. An organized, well-planned, incremental approach to the two components of the well completion leads to safer, more efficient installations and long-term operability. This paper will discuss the challenges associated with deep gas completions and how a systematic approach to overall completion design can save time and money while establishing a safe installation process. In addition, it will cover the emerging technologies in the completions field for the deep gas marketplace and how they can improve completion design effectiveness.

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