This paper outlines a new technique for running production casing from semi-submersible drilling rigs on highly deviated wells and was used for the first time on the Captain Field, UKCS, operated by ChevronTexaco. The technique, which incorporates selective-flotation techniques, has been used successfully on three subsea wells to date. This is believed to be the first employment of the above technique on semi-submersible rigs. Introduction ChevronTexaco operates the Captain Field (85% share) in the U.K. sector of the North Sea. The only partner in the field is the Korean Captain Company Ltd (KCCL). The field is currently being drilled and developed from the Captain ‘A’ WPP (wellhead protection platform) and the Captain ‘B’ subsea manifold. Production from both installations is routed to the Captain FPSO (floating production, storage and offloading vessel). The Captain sands are thin (typically 150 to 250 ft) and horizontal sections of 4000 to 8000 ft are required for efficient drainage. These sands are also relatively shallow at approximately 2900 ft true vertical depth (TVD) subsea with a 365 ft water depth. The shallow and lateral nature of the sands has required the application of extended reach drilling and completion technology, and has, in many instances, tested the boundaries of extended reach drilling (ERD). Consequently, vertical depth vs displacement ratios of completed wells are usually greater than three, some greater than four (see Fig. 1 for a comparison with industry practice). The traditional definition for an extended reach well is a TVD vs. horizontal displacement ratio greater than two. (See Fig. 2 for a typical ERD wellpath from spud to 9–5/8" shoe on Captain.) This results in challenges when running production casing which were met by applying selective flotation methods for the first time to a subsea well. The operational issues associated with the technique and how the consequent hazards were mitigated against and contingency plans put in place are explained. The lessons learned from performing the technique on the three wells to date will also be outlined. Subsea Well Construction The 11 3/4 in. × 9 5/8 in. production casing shoe is set in the pay sand at a 90° angle, often at a displacement greater than 5000 ft. Vertical depth vs. displacement ratios to the 95/8 in. casing shoe are frequently 1.5 and greater. These long sections of production casing at high angles have sometimes been difficult to run to total depth (TD) because of open hole (OH) friction which results in a lack of available weight to run the casing (See Fig. 2 for a schematic of shoe positions). The salient casing features are covered in Table 1 below.

This paper describes how torque and drag (T&D) analysis was used to successfully drill extended reach (ERD) wells in the Captain field in the North Sea. The issues and best practices associated with using this basic real-time drilling technique, particularly on Captain subsea development wells drilled from 2000 to 2003, are explained. The paper also explains the tactics used in overcoming issues such as how far could we drill and the associated risk. The applicability of available T&D reduction technologies and why many of them were eliminated as possible solutions reinforced the criticality of good T&D analysis on this project. The Captain subsea wells have the highest aspect ratio (unwrapped displacement [UD] / true vertical depth [TVD]) ever for development wells drilled and completed from a floating vessel. Although the wells are short in displacement for ERD wells, the shallow nature of the reservoir requires the application of T&D analysis, which has been at the core of good ERD drilling principles and practices for some time. This paper outlines what T&D analysis is and why it is important. The design of the bottomhole assembly (BHA) and drilling string, drilling string buckling, friction factor (FF) analysis, casing sanding considerations, trajectory design, and wellbore tortuosity all must be considered in applying this basic technique to field operations. Other issues such as why it is often misunderstood or badly applied, the importance of calibration with offset data, and conditions that effect FF determination are explained.

Summary This paper outlines a new technique for running production casing from semisubmersible drilling rigs on highly deviated wells that was used for the first time on the Captain field, United Kingdom Continental Shelf (UKCS), operated by ChevronTexaco. The process, which incorporates selective-flotation techniques in which air at atmospheric pressure is trapped in the bottom of the casing string to lighten the casing during deployment in the high-angle part of a highly deviated well, has been used successfully on four subsea wells to date. This is believed to be the first implementation of this technique on semisubmersible rigs. Introduction ChevronTexaco operates the Captain field (85% share) in the U.K. sector of the North Sea. The only partner in the field is the Korean Captain Co. Ltd. (KCCL). The field is currently being drilled and developed from the Captain "A" wellhead-protection platform (WPP) and the Captain "B" subsea manifold. Production from both installations is routed to the Captain floating production, storage, and offloading (FPSO) vessel. Captain sands are thin (typically, 150 to 250 ft), and horizontal sections of 4,000 to 8,500 ft are required for efficient drainage. These sands are also relatively shallow, at approximately 2,900 ft true vertical depth (TVD) subsea with a 365-ft water depth. The shallow and lateral nature of the sands has required applying extended-reach-drilling (ERD) and -completion technology and has, in many instances, tested the boundaries of ERD. Consequently, vertical-depth/displacement ratios of completed wells are usually greater than three, with some greater than four (see Fig. 1 for a comparison with industry practice). The traditional definition for an ERD well is a TVD/horizontal-displacement ratio greater than two. (See Fig. 2 for a typical ERD wellpath from spud to 9 5/8-in. shoe on Captain.) This caused challenges in running production casing that were met by applying selective-flotation methods to a subsea well for the first time. The operational issues associated with the technique, how consequent hazards were mitigated against, and the contingency plans put in place are all explained. The lessons learned from performing the technique on the four wells is also outlined. The use of selective flotation is quite common on platform or land wells and has been advocated and used since the early 1990s.1-4 It has never been used from a floating vessel as a deployment technique, mainly because of concerns with an evacuated marine riser if air ever entered the casing/openhole (OH) annulus during operation and with the impact of rig heave. Subsea Well Construction The 11 3/4- ´ 9 5/8-in. production-casing shoe is set in the pay sand at a 90° angle, often at a displacement greater than 5,000 ft. Vertical-depth/displacement ratios for the 9 5/8-in. casing shoe are frequently 1.5 and greater. These long sections of production casing at high angles have sometimes been difficult to run to total depth (TD) because of OH friction, which results in a lack of available weight to run the casing (see Fig. 2 for a schematic of shoe positions). The salient casing features are covered in Table 1. If the wells have a dogleg severity (DLS) > 8° /100 ft, the 9 5/8-in. casing with NK3SB (shown in Table 2) is used to account for higher bending loads and casing wear. The 11 3/4-in. casing remains unchanged. For wells in which the casing is run conventionally, 40-lbm/ft casing is used, thus creating less OH drag and extending the operational envelope by use of conventional methods. Methods of Reducing OH Drag An extensive independent engineering study* was undertaken to determine the best methodology for running the casing. The study identified many means of reducing casing drag by using friction-reduction techniques in production hole sections. Torque-and-drag (TAD) software was used to model the original casing design and to examine the effect of friction-reducing enhancements, such as roller centralizers and dogleg reduction. It was decided that the best option to ensure landing casing was selective flotation (buoyancy assist). However, the study did take a rigorous look at the alternatives for Well 13/22a-B6. The typical measures have been:Using lighter casing on bottom, with heavier casing on top.Reducing the cumulative DLS with rotary-drilling systems or modified slide-drilling techniques.Selecting a highly inhibitive polymer/KCL (potassium chloride)/glycol mud system.Using speciality lubricants.Idealizing the placement of casing centralizers to avoid "ploughing" and minimize friction.Spotting friction-reducing glass beads in the hole immediately before running casing.Placing heavy casing below the wellhead to add weight.Using hanging-off drill collars (DCs) to provide additional weight.Pushing the casing in.5 All the preceeding alternatives have been tried elsewhere, but they have shortcomings when applied to a Captain-subsea-development well.

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