At the present time, more than 9,000 offshore platforms are in service worldwide, operating in water depths ranging from 10 ft to greater than 5,000 ft. Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Figure 1). The concepts range from fixed platforms to subsea compliant and floating systems. In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A.
There are different definitions of what is Well Integrity. The most widely accepted definition is given by NORSOK D-010: "Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well." Well Integrity is a multidisciplinary approach. Therefore, well integrity engineers need to interact constantly with different disciplines to assess the status of well barriers and well barrier envelopes at all times. Offshore wells are considered dry tree wells that have much similarity to onshore wells, apart from the fact the consequence of loss of containment is extremely large in respect to environment and people.
Large integrated drilling and production facilities employ Dedicated Drilling Risers which have been part of the industries practice for decades. In 1984 Conoco Hutton facility in the North Sea was the first facility to use the top-tension riser system. In the Gulf of Mexico there are several facilities using the dedicated drilling risers. The drilling risers' work as an extension from the wellbore to the drilling rig which is located on the floating production system. The typical riser configuration considered consists of the subsea wellhead connector assembly, tapered stress joint, drilling riser, tensioning joint, riser landing joint, hydro-pneumatic tensioning system and a surface blow-out preventer.
Flow assurance, by definition, focuses on the whole engineering and production life cycle from the reservoir through refining, to ensure with high confidence that the reservoir fluids can be moved from the reservoir to the refinery smoothly and without interruption. The full scope of flow assurance is shown in Figure 1. Flow assurance matters specific to subsea tieback systems are shown in Figure 1. Flow assurance is sometimes referred to as "cash assurance" because breakdown in flow assurance anywhere in the entire cycle would be expected to lead to monetary losses. A few specific flow assurance issues are discussed next.
Figure 1.6--The Baldpate Compliant Tower is one of the tallest free-standing structures in the world – Empire State Building (right) for comparison (Web Photograph, Amerada Hess Corp., New York City). Figure 1.9a--Worldwide fleet of installed and sanctioned semisubmersible FPS (courtesy of BP). Figure 1.9c--Worldwide fleet of installed and sanctioned spars (courtesy of BP). Figure 1.10--Semisubmersible FPS planned for the Thunder Horse field (courtesy of BP). Figure 1.11--Alternative proven technology field development options (courtesy of BP). Figure 1.12--Subsea production trees used in conjunction with a fixed jacket structure (Intec Engineering, Houston).
Ultradeepwater drilling units are are the technological forerunners and pioneers in the offshore drilling business. Table 1 gives some characteristics of these units, most of them drillships of extraordinary size, but some are semis as listed in Table 2. All were built in the late 1990s and early 2000s. Most have some degree of dual-rig activity (i.e., they have two drilling units on one hull). The Transocean Enterprise Class drillships (Figure 1), for example, have the capability to run two riser and two blowout preventer (BOP) systems with one system drilling and the other completing a well on a subsea template.
The importance of well-trained, motivated, skilled, safety-oriented personnel with a teamwork attitude to crew and operate offshore drilling units cannot be stressed enough. No matter how well-engineered, well-equipped, and well-maintained a mobile offshore drilling unit (MODU) is, it will not perform any better than the crew who manage, operate, and maintain it. The crew and management system are often the real determining factor concerning MODU performance and safety. This is often overlooked during the flurry of cost analysis, equipment evaluation, operating expenses assessment, and number crunching during bid analysis and MODU selection. It is often said that the low bid does not always give the best performance.
Offshore production operations can be either very similar to or radically different from land-based installations. Control valves, safety valves, and piping outlets are configured the same and use the same or similar components. Some of the valves probably will have pneumatic or hydraulic actuators to facilitate remote and rapid closure in an emergency. Also, some Christmas trees may have composite block valves instead of individual valves flanged together. The major difference, however, between land and platform well completions is the economics incentive on platforms to reduce equipment weight wherever possible and to minimize space requirements.
In the early days, ships were very attractive and the most common floating mobile offshore drilling units (MODUs). Ships mobilized quickly and could carry a large amount of operator consumables, such as casing and bulk mud. However, their motions in weather proved to be a significant disadvantage in even mild environments. If a ship-shaped unit was hit on its beam with even moderate swells, the roll could raise havoc with efficient productivity. The Offshore Co. (now Transocean) developed and patented the turret mooring system (Figure 1).