TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Sognefjord reservoir (Jurassic) in Troll Field, Norwegian North Sea, is drilled horizontally in 9½" hole from 1,800 m to 3,100 m in length. The reservoir consists of loose sands, subdivided into clean and micaceous units and local hard calcareous cemented zones. These sections must be drilled in a tight horizontal plane, approximately one meter above the oilwater contact to maximize oil production. The oil bearing strata is typically between 12 m and 27 m thick. Most steering is done in the vertical plane to keep the well within the narrow target window (~1 m TVD or less) and in the optimum azimuth to place the well in the desired reservoir sand.Historically this section has been drilled with steerable motor assemblies and tungsten carbide insert roller cone bits. The use of polycrystalline diamond compact (PDC) bits was precluded due to problems associated with toolface control in the loose sands. With the advent of a rotary steerable tool (RSS) came the prospect of long runs with specialized PDC bits. After major area specific problems were encountered a joint task force was assembled, consisting of a drilling operator and an integrated service company, to attempt to improve drilling performance in the reservoir section.Three main areas of potential improvement were identified: 1. Improve reliability of the RSS (including MWD). 2. Increased ROP in hard calcite cemented sandstones. 3. Mapping and prediction of calcite cemented zones.The team concentrated on rock strength analysis, simulator testing of new PDC designs, BHA vibration modeling and analysis of depth based drilling, MWD & vibration data. Modified BHA's and Troll specific antiwhirl PDC bits, along with revised drilling practices, were applied in the field. This allowed step improvements in drilling performance to be achieved. Overall, meters/BHA increased from 264 m to ~640 m. The new bit designs also increased the overall average ROP from ~10 to 20 m/hr and improved instantaneous ROP in the calcareous sandstone sections. Savings in rig time on the Troll development are potentially immense as approximately 60 wells remain to be drilled. This paper will highlight the need for a systematic approach, including problem definition, data collection, solutions implementation and results benchmarking.

Wells on the Jupiter field, UK Southern North Sea, require relatively long (1,000 - 5,372 ft) horizontal 6" hole sections to be drilled through the Permian age, Rotliegendes sandstone reservoir. Tight target tolerances on true vertical depth necessitate good directional control over the entire section length. Historically, the following technology combinations were utilised to drill these sections; high-speed turbines run in conjunction with polycrystalline diamond compact (PDC) drill bits or diamond impregnated bits; conventional low speed Positive Displacement Motors (PDMs) coupled with both roller cone bits and PDC bits. Drilling with turbines resulted in heavy drill bit wear due to high rotational speeds and required significant periods of orientation to combat the inherent left hand walk tendencies of the assemblies. Conventional PDM and roller cone assemblies gave rise to multiple trips due to bit bearing life limitations on run length. The problems of erratic PDC bit torque and stalling of conventional motors due to variable weight transfer coupled with motor torque output limitations, made attempts to use this combination unsuccessful. The development of a new generation PDM that was able to produce significantly more power and torque than conventional motors, at comparable bit speeds, was introduced to overcome these problems. Compared with turbines the new generation Extra Power Motor, (XPM), was found to be easier to control, monitor and optimise, as both revolutions per minute (RPM) and power output are directly proportional to drilling fluid flow rate and motor differential pressure respectively. In conjunction with the new XPM technology, application specific PDC bits featuring a unique tandem gauge were designed to maximise hole quality and therefore provide more even weight transfer to the bit. This combined with an optimised PDC cutting structure facilitated smooth torque output at the bit-rock interface and so supported the use of the new motor technology. This paper uses case histories to describe how the application of this new technology on three wells led to a step improvement in performance when compared to conventional drilling methods. Gross section rate of penetration (ROP) was improved by up to 300%, and the operator achieved the longest horizontal section to date through the Rotliegendes. Future developments to meet ongoing challenges and realise the full potential of this technology are also presented. Introduction This paper documents the application of the XPM and application specific PDC technology in drilling a series of 6" hole sections on Conoco's Jupiter field located in block 49/22 in the UK Southern North Sea (Fig. 1). The reservoir rock in this field is the Leman sandstone formation, part of the Permian age desert-facies1 Rotleigendes Group, located towards the southwestern margins of the Southern Permian Basin. Overlying this is a sequence of Permian age Zechstein carbonates and evaporites, consisting of interbedded units of anhydrite, dolomite, halite and limestone (Fig. 2). The 6" hole sections, on wells 49/22-N3 and N2z were drilled with conventional turbine and PDM technology2,3, and three 6" hole sections on wells N4, N5 and N6 were drilled predominantly with XPM technology (Fig. 3), during the period May 1999 to November 2000. Typically these sections were drilled out from a 7" (32 ppf, HC110) liner, with the shoe set in the basal Zechstein Werraanhydrit formation. Well profiles varied depending on the specific target locations, but were typically planned to reach 90° by total depth (TD) of the 8 1/2" hole. The 6" sections were then drilled for the most part horizontally, predominantly through the Leman sandstone.