Running coiled tubing can be an effective tool to deliquify gas wells, but this practice was discontinued in early 2000 in ConocoPhillips Lobo Field in South Texas because of problems experienced due to CO2 corrosion with standard coiled tubing metallurgy. Since 2004, ConocoPhillips has installed 90 corrosion resistant coiled tubing velocity strings as an alternative to conventional carbon steel coiled tubing. These installations have yielded 5 mmcfd in incremental gas rate and the change to a corrosion resistant metallurgy has drastically reduced the high failure rate and costly workovers that resulted from previous carbon steel installations. Various key learnings including candidate selection criteria and future application recommendations will be presented in addition to representative well types and production profiles. Metallurgy comparisons, post-use inspection findings and full-cycle cost implications will also be presented.

Running coiled tubing can be an effective tool to deliquify gas wells, but this practice was discontinued in early 2000 in ConocoPhillips Lobo Field in South Texas because of problems experienced due to CO 2 corrosion with standard coiled tubing metallurgy. Since 2004, ConocoPhillips has installed 90 corrosion resistant coiled tubing velocity strings as an alternative to conventional carbon steel coiled tubing. These installations have yielded 5 mmcfd in incremental gas rate and the change to a corrosion resistant metallurgy has drastically reduced the high failure rate and costly workovers that resulted from previous carbon steel installations. Various key learnings including candidate selection criteria and future application recommendations will be presented in addition to representative well types and production profiles. Metallurgy comparisons, post-use inspection findings and fullcycle cost implications will also be presented.

IADC Members Abstract In February 1995, the development of the British Gas E & P operated Armada field commenced when the semi-submersible Santa Fe 135 was positioned over a previously installed ten slot template and pre-drilling commenced with the objective of drilling and suspending eight wells ready for tieback and completion from the jacket and topsides to be installed in March 1997. The nature of the field development, with a centrally located platform, coupled with the multiple reservoir objectives in the Palaeocene and Jurassic, resulted in an extremely challenging pre-drilling programme involving extended reach drilling and evaluation, and potentially a new world record for the longest well drilled from a semi-submersible. The average measured depth and step out of the eight wells were 18508 ft and 13830 ft respectively, with inclinations ranging from 60 – 75 degrees. The surface casing strings were successfully batch set on all eight wells for operational efficiency. Performance in the early wells was plagued by borehole stability problems and equipment failures. Despite these difficulties, the objectives were realised, and later performance has been exceptionally good. The Armada pre-drilling experience demonstrates that performance extended reach drilling can be achieved with a third generation semi-submersible by detailed planning, motivation of the "drilling team" and careful attention to detail. Introduction The Armada complex is in the Central North Sea about 250 kilometers eastnortheast of Aberdeen and extends into 5 separate exploration licence areas. The development exploits three reservoirs, Fleming, Hawkins and Drake. The Fleming field is the largest reservoir, a Palaeocene structure approximately 24 km long by 3 km wide. The Jurassic Drake and Hawkins reservoirs are smaller accumulations which lie directly below the Fleming field. The fields have estimated reserves of 1.2 trillion cubic feet of gas and 70 million barrels of condensate. Planned maximum depletion rate is 450 mmscfd. The Armada complex is expected to be operational for between 20 and 25 years. The development concept originally involved drainage of the fields with two platforms due to the length of the Fleming field. This progressed to one platform near the south of the reservoir with a subsea development in the northern part of the field, however the economics were not sufficiently robust to allow the development to go ahead. Further concept work was undertaken to establish that a single centrally placed platform in combination with extended reach drilling was a feasible option, and this option was finally selected for the development. The planning and execution of the Armada pre-drilling programme presented a substantial technical challenge with the use of an Enhanced Pacesetter class semi-submersible in the harsh North Sea environment to drill and evaluate eight long reach wells, the eighth well representing a new semi-submersible drilling record at 23,905 ft MD. This paper explains the planning basis for the extended reach drilling on Armada, and presents drilling experience during the predrilling programme. Development Drilling Planning The development schedule for Armada allowed adequate time for both drilling conceptual and detailed design for the predrilled wells. Figure 1 represents the planning schedule and drilling implementation for the pre-drilled wells within the overall development schedule. The conceptual design had demonstrated the technical feasibility of drilling the Armada wells based on the planned targets with the readily available drilling equipment in the North Sea. P. 45^