DRILLING & PRODUCTION
Leonard LeBlanc Houston Casing wear in the Gyda A-13 extended reach well. Diagram A Offshore producers with acreage and discoveries in water depths beyond the 3,500 ft contour are searching for the least expensive but effective production vessel for 50,000-100,000 b/d throughput volumes. If at all possible, they want the wellheads on the surface. The conventional tension-leg platform (TLP), ideal at shallower depths, must be scaled up in size to support heavier tendon loads and variable deck
Deep draft hulls key to production in ultra-deepwater
Offshore producers with acreage and discoveries in water depths beyond the 3,500 ft contour are searching for the least expensive but effective production vessel for 50,000-100,000 b/d throughput volumes. If at all possible, they want the wellheads on the surface.
The conventional tension-leg platform (TLP), ideal at shallower depths, must be scaled up in size to support heavier tendon loads and variable deck weights needed for greater depths. The higher costs become prohibitively risky.
Conventional floating production systems, including both monohull and semisubmersible units, are less costly than TLP units, but they also move wellheads to the seafloor and are designed for fields with smaller production levels and minimal intervention.
Instead, new designs to suit surface wellhead requirements tend to enclose suspended production risers and wellheads. The enclosing structure or vessel protects the risers, but decouples the hull motions from that of the enclosed risers and wellheads to some degree. In order to minimize the motion of the enclosing hull and the cost of the mooring system, however, deep submergence of a stabilizing hull is necessary. Following are several types of enclosing designs that are effective in minimal motion and decoupling:
- Raft TLP: There are several types of vessel designs featuring completely submerged hulls tensioned to the seafloor. This arrangement allows minimization of the surface structure, and lower costs, while keeping the wellheads at the surface. Aker Omega's raft tension-leg platform design, furthermost along in terms of engineering, is now the subject of a joint industry project. The Aker Omega design uses a space frame to link a submerged rectangular concrete raft with a conventional topsides deck, minimizing wave zone response and pushing the submerged tensioned hull only as deep as needed.
- Rigid riser semi: This design features a semisubmersible hull as the structure enclosing a framework within which risers and wellheads are attached. Typical of these is Kvaerner's rigid riser semisubmersible, which encloses a floating space frame structure that is constrained laterally but not vertically. The frame is tensioned to the seafloor and supports wellheads only, and the semi moves laterally with the space frame. Production and workover equipment are located on the semisubmersible. To reduce surface motions, the semisubmersible legs and underwater box frame have a deep draft.
- Spar platform: The first version of a spar-shaped producer, a design pioneered by Deep Oil Technology, is being built for Oryx's Neptune Field in the US Gulf. The 707 ft by 72 ft diameter hull will enclosed separately buoyant risers and surface wellheads within a central well. The unit will be installed in 2,000 ft of water, and is designed for a maximum production of 25,000 b/d. Unlike the other two designs which are tensioned to the seafloor, the spar will be catenary moored.
In the designs cited, as the enclosing vessel becomes less transparent to surface wave and current loads, the hull must be submerged deeper to reduce the response. At the high transparency end of the spectrum is the raft TLP with a space frame penetration, which must be submerged about 350 ft for a 5,000 ft water depth application. On the other end are semisubmersible legs and spar hulls. Semisubmersibles use leg mass to minimize response to surface motion, while the narrow spar extends as much as 750 ft for a 2,000 ft water depth deployment.
Tungsten carbide drillpipe grinds up casing when new
When newly applied, even in the smoothest versions, tungsten carbide hardbanding on drill pipe is unyielding. When turned inside casing on doglegs, through kickoffs on extended reach wells, the material will cut casing quickly. In contrast, these qualities make tungsten carbide banding superior for drill pipe protection in uncased hole sections.
Apparently, the hardbanding toughness changes after the pipe has been run through several wells. The material yields and is inclined to wear more quickly than when new.
BP found out about rapid casing wear the hard way during the drilling of extended reach wells from the Gyda platform in the North Sea. The firm's in-house publication, BP Downhole Talk, reported that BP stipulated smooth hardbanding for 6-5/8-in. drill pipe in a 7.5 km well, since alloyed piping was unavailable. The hardbanding would reduce pipe wear in the angle well sections.
Drillers managed to drill half of the 16-in. hole program before the 87.5 ppf ,18-5/8-in. casing holed at 220 meters below the seabed, about 100 meters below the platform pilings. The firm lost hundreds of bbl of drilling fluid before the problem was detected. The breach was sealed with cement, but casing integrity was lost. The solution was to install a temporary 13-3/8-in. scab casing inside 1,100 meters of 18-5/8-in. casing and seal the bottom with a packer. The wellhead was retained and a special wear bushing was used to protect the top of the 13-3/8-in. hanger assembly.
The well was successfully drilled and the scab casing was removed and replaced with a permanent 13-3/8-in. casing string run to total depth. Later trials by BP using a 13-3/8-in. casing section with new smooth hardbanded drill pipe showed severe casing wear through a 4/30-meter dogleg.
Similar experiences with tungsten carbide hardbanding were recorded in earlier BP extended reach wells on the Miller and Wytch Farm Fields. Following the tungsten carbide problems, BP switched to Arnco 200 XT hardbanding for the Wytch Farm wells to reduce wear. The Arnco 200 XT costs slightly more, but the material wears faster and can be re-applied as frequently as needed. The 200 XT material, when combined with synthetic drilling fluid, provided the needed durability.
The search for a drilling solution continues, however, since severe doglegs and extended reach and horizontal wells are a way of life. Synthetic drilling fluids, because of their inherent lubricity, are able to alleviate part of the casing wear problem in the most critical wells. However, synthetic drilling fluids are relatively expensive and difficult to dispose of without some environmental consequences.
For this reason, much of the solution will have to come from improving the wear qualities of the drill pipe hardbanding itself. Researchers are working on the problem. As reported in an earlier issue (June 1995), the Drilling Engineering Assoc-iation is examining steel-graphite arc-coated drill pipe as a substantial improvement over known hardbanding materials. Also, wear resistant alloy drill strings are now available.
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