Selective Flotation of Casing From a Floating Vessel
- G. Rae (ChevronTexaco Upstream Europe) | H. Williams (K&M Technology Group) | J. Hamilton (SPS Intl.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2004
- Document Type
- Journal Paper
- 94 - 103
- 2004. Society of Petroleum Engineers
- 1.6.1 Drilling Operation Management, 1.6.10 Running and Setting Casing, 1.11 Drilling Fluids and Materials, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.4.3 Sand/Solids Control, 1.10 Drilling Equipment, 2 Well Completion, 4.5.3 Floating Production Systems, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 3 Production and Well Operations, 1.14.1 Casing Design, 1.7.6 Wellbore Pressure Management, 1.6.6 Directional Drilling, 1.7.5 Well Control, 1.6 Drilling Operations, 1.14 Casing and Cementing, 4.2.4 Risers
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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.
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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