The drilling of a borehole or well is typically carried out using a steel pipe known as a drill pipe or drill string with a drill bit on the lowermost end. The drill string comprises a series of tubular sections, which are connected end to end. The entire drill string is typically rotated using a rotary table or top drive mounted on top of the drill pipe, and as drilling progresses, a flow of mud is used to carry the debris and/or cuttings created by the drilling process out of the wellbore. Mud is pumped down the drill string to pass through the drill bit, and returns to the surface via the annular space between the outer diameter of the drill string and the wellbore (generally referred to as the annulus). For a subsea well bore, a tubular, known as a riser, extends from the rig to the top of the wellbore and provides a continuous pathway for the drill string and the fluids emanating from the well bore. In effect, the riser extends the wellbore from the sea bed to the rig, and the annulus also comprises the annular space between the outer diameter of the drill string and the riser.
The use of a blowout preventer (BOP) to seal, control and monitor oil and gas wells is well known, and these are used on both land and off-shore rigs. During drilling of a typical high-pressure wellbore, the drill string is routed through a BOP stack toward a reservoir of oil and/or gas. The BOP is operable, in the event of a sudden influx of formation fluid into the wellbore (a kick) to seal around the drill string, thus closing the annulus and stopping tools and formation fluid from being blown out of the wellbore (a blowout). The BOP stack may also be operable to sever the drill string to close the wellbore completely. Two types of BOP are in common use, ram and annular, and a BOP stack typically includes at least one of each type. The original design of an annular BOP is described in U.S. Pat. No. 2,609,836.
A typical BOP has a sealing element and a fluid pressure operated actuator mounted in a housing. The actuator divides the interior of the housing into two chambers (an “open chamber” and a “close chamber”), and substantially prevents flow of fluid between the two chambers. The actuator is movable, by means of the supply of pressurized fluid to the close chamber, to urge the sealing element into sealing engagement with a drill pipe extending through the BOP (the closed position), and, by means of the supply of pressurized fluid to the open chamber, to release the sealing element from sealing engagement with the drill pipe (the open position). Certain types of BOP are configured such that, when there is no drill pipe in the BOP, the sealing element can close on itself to close completely the BOP stack, and thus also the wellbore.
The supply of pressurized fluid for actuation of the BOP typically comprises a pump which is operable to pump fluid into an accumulator via a line containing a non-return valve. Fluid flow lines are provided to connect the accumulator to the open chamber and the close chamber and at least one valve is provided to control flow of fluid from the accumulator to the open or close chamber.
An example of a typical annular BOP and fluid pressure control system is described in U.S. Pat. No. 4,098,341. Alternative embodiments of a BOP and their control systems are described in U.S. Pat. Nos. 3,044,481, 3,299,957 , 4,614,148, 4,317,557 and 3,128,077.
Various configurations of seals suitable for use in mineral extraction systems are also described in U.S. Pat. No. 8,800,648, US 2013/0043657 and US 2014/0203516.
FIG. 1 is a schematic illustration of a transverse cross-section through a conventional, prior art, elastomeric sealing element 10′ of the type used in conventional, prior art, blowout preventers a) in a relaxed state and b) in a compressed state. When in the relaxed state, the elastomeric sealing element 10′ has a generally annular transverse cross-section. When the blowout preventer is closed, the elastomeric sealing element 10′ is compressed so as to reduce the diameter of the space it encloses. To do this, radially inwardly directed forces are applied to the elastomeric sealing element 10′, either directly or by virtue of the elastomeric sealing element 10′ being pushed against the BOP housing by a piston which is movable generally parallel to the longitudinal axis of the BOP.
The resulting deformation/folding pattern on the elastomeric material will be based on the least resistance region of the elastomeric sealing element 10′ and will depend on either the buckling modes of the elastomeric ring or the defects/weak regions of the elastomer. As a consequence, there is no control over the folding pattern at the inner surface of the elastomeric sealing element 10′ which will create irregular folds as shown in FIG. 1b. Irregular folds creates high strains in certain folds and low strains in other folds, and the highly strained regions of the elastomeric material will have a tendency for faster crack growth/lesser life due to the availability of high strain energy density on the critical folding regions. Moreover, the sealing surface generated between the elastomeric sealing element 10′ and a tubular drill string 12′ extending through the BOP will be perfect in some regions and not in other regions where the elastomeric sealing element 10′ is still spaced from the tubular string. This variation in the sealing surface means that a very high compressive force is required to seal completely around the tubular string.
USPTO Backgrounds
USPTO Backgrounds