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An extensive big bore gas well drilling and completions program is in progress to develop the giant North Field, offshore Qatar. Benefits of the big-bore concept, compared to the prior 7-in. monobore design, include reduced development costs by requiring fewer wells, and deferred installation of compression by providing higher flowing wellhead pressures. This is the widest known application of a big bore design in one single field and involves a large number of wells. Many of these wells are drilled and completed to date and believed to be among the world's most prolific gas producers. These are also the first offshore wells to incorporate big bore well design for large-scale field development and feature industry advances in equipment design and manufacture. An extensive system of detailed design review, equipment performance testing, and quality programs has been implemented to meet challenging project requirements for well reliability. The wells feature a tapered tubing design known as the "Optimized Big Bore" (OBB). This paper discusses the challenges of planning and executing these OBB wells. It reviews the initial OBB well design, anticipated North Field drilling challenges, critical equipment specifications, and design revisions resulting from optimisation efforts over the past four years. Introduction Discovered in 1971, the North Field of Qatar is the world's largest non-associated gas field, extending over 6,000 km2, and contains approximately 900 TCF of abnormally pressured natural gas. Development has taken place in several stages, commencing with initial production by Qatar Petroleum in 1991 to supply the domestic gas market. This was followed in the mid-to-late 1990s by RasGas Company Limited (RasGas) and other projects to provide LNG to export markets. More recently, the growth in global LNG demand has sparked much more extensive development. RasGas is responsible for the development of a large area of the North Field, covering more than 500 Km2, to provide natural gas supply for both new LNG trains and the growing domestic gas market. The RasGas expansion plan requires a large number of wells to be drilled in the period 2002 to 2010 from several new wellhead platforms. Production is from the massive Khuff carbonate formation, which includes several productive intervals (K1, K2, K3, and K4), situated at approximately 10,000 ft TVD. This would differ from the earlier projects of the 1990's that developed only a part of the Khuff reservoir. In total, RasGas will operate more than 90 wells producing a total of 8 Bscfd. Well deliverability from the K1 to K4 reservoirs is very high due to both formation quality, near initial reservoir pressure, and high net pay thickness. Non-hydrocarbon gas composition varies between the four Khuff intervals within each well and also across the field. Well designs evolved from packer / tubing completions intended to produce at 60 MMscfd in the initial Qatar Petroleum project, to high-rate 7-in. monobore wells in the first LNG projects able to deliver in excess of 100 MMscfd.1 However, it was recognized by RasGas and its major shareholders Qatar Petroleum and the former Mobil Oil (now ExxonMobil) that higher capacity well designs, capable of producing in excess of 150 MMscfd, could be suitable for the planned RasGas expansion projects. Although individual wells would be more expensive to construct, there were two significant advantages that would result in a more cost effective project. These would be:

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TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractFrom the start of the current phase of North Field drilling activity in 2002, RasGas Company Limited (RasGas) has continued to push the envelope in terms of both technology and operating practices in drilling and completions. Following the successful introduction of an Optimized Big Bore (OBB) well design in 2002 1,2,3 , advancements have been made in areas of drillstring design, drilling optimization techniques, management of lost circulation events and overpressured water flows, and stimulation technology associated with increasingly longer completion intervals. This paper highlights how these advancements have enabled year-on-year improvement in drilling and completion cycle times, even though well complexity has increased over the same time period.

Ageing wells in mature shallow water fields may develop corrosion of conductor and surface casings, which reduces their capacity to carry well loads. Novel conductor repair techniques were designed and piloted, a comprehensive well maintenance program was developed to mitigate and minimize the probability of structural failures and to eliminate environmental impact through lifetime of the well. Lessons learned during development and implementation of this program and specific experience from conductor repairs performed using several new techniques are invaluable for companies that experience similar corrosion issues of ageing assets. Qualitative assessment by visual inspection and quantitative detailed ultrasonic testing of several hundred conductors provided an accurate measure of metal thickness of conductor pipes from the splash zone to the wellhead. Physics-based assessment of how the corrosion impacts the well structural integrity was performed in order to establish acceptable, safe limits of corrosion and remaining wall thickness of an integral conductor pipe, which included a simplistic analytical study, detailed structural modeling and 3D finite-element analysis. These analyses allowed the development of safety guidelines and structural failure risk ranking criteria. After initial assessment through analysis of UT scans, all wells in the field have been risk-ranked and prioritized for maintenance and repairs. Cement top-up campaign took place to ensure cement filled the annulus inside conductor to provide additional structural support and stability and to slow down the internal corrosion of the conductor pipe and external corrosion of the surface casing. Blasting and coating of conductor external surfaces in order to stop any additional external corrosion has been performed. Three cost-effective rigless repair techniques to re-establish full structural integrity of the wells have been selected for pilot operations. Welded sleeves were used for several repairs but required extensive engagement of weather-dependent diving services to construct the cofferdam to create dry working area in the splash zone before welding. Two other techniques with the minimum use of diving operations have been used for the first time in the region: external reinforced cementitious grout and combined clamped-welded sleeves. Before execution of repair operations offshore, the full-scale yard testing of clamps was performed to verify capability of equipment to carry the required loads. A number of wells have been repaired using novel techniques with varying duration of operation and several technological and operational challenges related to field execution, quality of design and weather dependence. Without doubt, lessons learned from these trials are essential for future execution of repairs with these techniques. Well management program to ensure structural integrity of offshore wells will extend the life of existing wells, optimize costs by prioritizing operations and re-utilizing same conductor pipes through slot recovery for replacement wells, when necessary.