Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. An outer steel shell that connects a drill ship, jackup or floater to the well template on the ocean floor. The drill string is run through the riser and the returning mud and cutting flow u the drill pipe / riser annulus.
The majority of offshore fields have been developed with conventional fixed steel platforms. One common feature of fixed steel structures is that it is essentially "fixed" (i.e., it acts as a cantilever fixed at the seabed). This forces the natural period to be less than that of the damaging significant wave energy, which lies in the 8- to 20-second band. As the water depth increases, these structures begin to become more flexible, and the natural period increases and approaches that of the waves. The consequence of this is the structure becomes dynamically responsive, and fatigue becomes a paramount consideration.
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.
The growth and evolution of offshore drilling units have gone from an experiment in the 1940s and 1950s with high hopes but unknown outcome to the extremely sophisticated, high-end technology and highly capable units of the 1990s and 2000s. In less than 50 years, the industry progressed from drilling in a few feet of water depth with untested equipment and procedures to the capability of drilling in more than 10,000 ft of water depth with well-conceived and highly complex units. These advances are a testament to the industry and its technical capabilities driven by the vision and courage of its engineers, crews, and management. From an all-American start to its present worldwide, multinational involvement, anyone involved can be proud to be called a "driller." Since the beginning in the mid-1800s until today, the drilling business commercially has been very cyclic. It has been and still is truly a roller-coaster ride, with rigs being built at premium prices in good economic times and ...
Perhaps one of the most important ventures in the area of high-cost technologies for deepwater challenges is the development of dual gradient drilling systems (DGDSs). DGDS is often referred to as riserless drilling. It is generally accepted that DGDS is required in water depths of 5,000 ft. There have been a number of unpublished examples, however, in which application of the technology was needed in water depths as shallow as 3,000 ft. The need for DGDS is caused by the reduced fracture gradient of formations below the mudline, resulting from the reduced weight, or gradient (0.5 vs. 1.0 psi/ft), which, itself, is a result of water above the mudline as viewed from a drillship operating at sea level.
The seafloor temperature in deepwater locations is approximately 40 F, but it can approach 32 F. The temperature downhole can exceed 300 F. The drilling fluid should exhibit the appropriate rheological properties throughout this wide range. In the riser near the mudline, the fluid is apt to thicken excessively from exposure to the cold seafloor temperature. SBFs that contain little or no commercial clay appear to remain the most stable under these conditions. These clay-free and low-clay systems rely on emulsion characteristics to achieve the desired rheological properties and provide sufficient barite suspension. Seismic data can help operators to predict and evaluate the risk of encountering an SWF on a given well.
The BC-10 asset, located in deep water offshore Brazil, produces heavy oil in the range of 16 to 24 °API. In this article, two examples of production optimization for this field will be provided (further examples are available in the complete paper). This paper evaluates the feasibility of a number of production- and export-riser configurations for ultradeepwater applications.
New long-term contracts between offshore drillers and equipment makers reduce downtime and risks associated with key components, from blowout preventers to risers. This paper evaluates the feasibility of a number of production- and export-riser configurations for ultradeepwater applications. This paper presents results from full-scale testing of a flexible riser equipped with embedded sensors for distributed-temperature sensing (DTS).
A project spearheaded by ExxonMobil, Shell, Chevron, and the Southwest Research Institute (SwRI) has been established to advance separation technology through improved testing methods and collaboration between users and suppliers. The simplest way to measure return on investment for an offshore water treatment system is to determine whether using the system actually reduces the risk of paying a fine for violating water pollution laws.
A study using a dynamic multiphase-flow software simulated a rapid-unloading event and determined the gas fraction in the riser annulus and the effect on riser fluid levels. The Troll field is one of the largest gas producers discovered off Norway, but ensuring its long-term future required finding ways to drill wells in an increasingly fragile formation to develop its rich oil reserves. The list of wells drilled using dual gradient includes one drilled in the “eastern Gulf of Mexico,” which could be more precisely described as offshore Cuba. A previous attempt to drill an exploration well in ultradeep water in the Gulf of Mexico (GOM) did not reach its objective.