SPE members Abstract Well 30/6-C-26A was drilled to 9327 m measured depth in January 1995 from the Oseberg C platform in the North Sea. The well has a horizontal reach of 7853 m which is a new world record in Extended Reach Drilling. The last 2100 m were drilled horizontally in the reservoir 6 – 8 m vertically above the oil water contact. This paper will describe the planning phase as well as operational challenges experienced during drilling of this well. Introduction The Oseberg Field was discovered in 1979. To develop this 27 × 5 km giant field, two platforms were located 15 km apart. To drain the oil between the platforms two subsea wells were drilled and completed (Figure 1). For the last three years Norsk Hydro together with the partners in the Oseberg Field have put up an overall goal to increase the recoverable reserves by 50 million SM3 (316 million barrels). This corresponds to a final recovery factor of 64 %. Horizontal drilling is one of the most important factors to achieve this goal. The horizontal drilling programme on the Oseberg Field is one of the most comprehensive to take place in the North Sea. The first horizontal well in the Oseberg Field was drilled in 1992. Since then a total of 17 horizontal wells have been successfully drilled and completed. The general trend during this period is that both the length of the horizontal reservoir section as well as the total depth for the wells have increased (Figure 2.). New equipment and technology as well as general field experience played an important role when deciding to go ahead with C-26A. The Oseberg Field Reservoir The reservoir units on the Oseberg Field consist of several sand units within the Middle Jurassic Brent Group (Figure 3). The main reservoir unit is the Oseberg Formation which consists of medium to coarse grained fan-delta sandstones of excellent reservoir quality. The vertical thickness is about 20–60 m and the reservoir qualities are excellent. The Etive Formation overlies the Oseberg Formation. The upper unit in the Brent Group is the Tarbert Formation which is of fair to poor quality and thickness in the south, but is a significant unit in the northern part of the field where the vertical thickness can exceed 40 m. The Ness Formation separates the Tarbert and the Oseberg formations. The Ness Formation consists of delta plain channel sandstones interbedded with overbank fine-grained sediments and coal beds. The channel sandstones are difficult to map from seismic and well data due to their size and scattered occurrence. P. 131

Gas kicks in oil-based muds have been studied with experiments in an inclined research well. A total of 24 different gas kick experiments were performed, and various parameters were varied. The instrumentation and data acquisition systems were complex, and nine surface and 10 downhole parameters were logged simultaneously. The data presented reveal the dynamic development of kicks in OBM, helps understanding the kick process and give important implications for kick detection and well control. The data are analysed with relation to physical processes and drilling operations.

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^

Several gas-influx events have occurred during drilling with oil-based mud on the Gullfaks field. These have usually started when hard chalk stringers were penetrated, and abnormal pressurized gas bearing zones were drilled into. These zones are often of low productivity ·and val ume.Based on all available data from the influxes in wells I and II, the events have been analyzed. The analysis has helped to explain the development of the influx events, and also the control phases have been evaluated.

SPE Members *Now with Petec A/S **Now with Baker Hughes INTEQ Abstract A number of gas kick experiments have been performed in a 2000 m long, 60 inclined research well. During the experiments a several of parameters were varied, such as mud density, mud type, gas concentration, and control rate of the kick. The well was heavily instrumented during the experiments, both downhole and surface. The gas distribution at start of the kick has been computed, and compared to the gas distribution out of the well which was calculated based on, measurements of the mixture density through the choke line, choke pressure and pit gain. This was done for the majority of the 24 kicks which were performed. The effect of mud density and solubility on the return distribution has been analysed. Effects of operational procedures during the kicks have been analysed as well (circulation rates and duration of close-in). The work shows that the return gas rate and gas distribution depends on the following variable; the initial gas distribution, mud type (OBM or WBM), and operational history of the kick. Optimal operational control procedures which will create the most favourable return gas distribution are recommended. Introduction Gas kicks occur seldom during drilling operations. However, for exploration drilling the kick frequency is higher than the average, and for some special wells (like high pressure, high temperature wells in the Central Graben area of the North Sea) the frequency of kicks is extremely high (approx. 2 per well). The main reason for (his is the small difference between the pore pressure and the fracture pressure, in combination with the extreme conditions which makes the control of the well pressure more difficult than in "normal" wells. Kick incidents are generally poorly documented, and the data usually consist of pit volume, shut-in pressures and choke and pump pressure. The initial influx distribution is not logged, only the volume (pit gain). The return gas distribution is not logged either. So data on how the gas distribution change from kick start to end, and how operational factors influence this have been non-existent. In the DEA-E-9 project, 24 gas kick experiments were performed, and data from a number of surface and downhole sensors were logged [1]. The data from the experiments have been extensively analysed [2, 3]. This paper summarize the analysis of the gas distribution for the experiments. GAS KICK EXPERIMENTS In the gas kick experiments performed in the DEA-E-9 project, a number of data was logged. The gas was injected through a coiled tubing which was run into the drill string down to the bit. An overview of the kick experiments is given in Appendix B. The experiments were performed in a 2020 m long research well with a maximum inclination of 63. Nitrogen and Argon gas was injected, and parameters such as mud type, mud density, gas concentration, mud flow rate, gas injection depth etc. was varied. Details of the experiments and the analysis of the data have been documented. GAS INFLOW RATE Knowledge of the gas flowrate into the well is essential to perform a detailed analysis of the kicks. The complete equation for the gas flow into the well is: (1) P. 481^