New Subsea Technology Enhances Safety In Coiled-Tubi Operations During Well Test

Abstract

ABSTRACT To preserve the safety of the rig when it is necessary to shut-in the well during coiled tubing service operations, the operator must be able to sever or pull the coiled tubing before emergency valve closure can take place. Norman y, because of the time factor, as in the case of a drill ship drive-off condition, pulling the tubing is not a viable option. The operator, therefore, has to depend upon available cutting methods. Until recently, unless the coiled tubing in use was 1- ¼-inch [3.18 cm] OD × .095 [.241 cm] wall thickness or smaller, the operator had to solely rely on the shear rams of the coiled tubing blowout preventer (BOP) to cut the coiled tubing. Since the method of choice for cutting tubing is with mechanisms that can cut at the safety valve, with the shear ram of the coiled tubing BOP as a secondary safety system, it was apparent that the cutting capabilities of available mechanisms needed enhancement to accommodate the new larger-diameter coiled tubing. This paper will describe the design and testing of a new 15,000 psi [103.4 1 MPa]-rated ball and seat mechanism that has a 3.O-inch [7.62 cm]-ID and has the capability to cut coiled tubing with OD's as large as 1-½-inches [3.81 cm] and a wall thickness of l/8- inch [.32 cm]. This is an improvement over traditional cutting mechanisms, which only offer 2- ¾-inch [6.99 cm]-ID for 15,000 psi [103.41 MPa]- rated equipment, and a cutting limitation of 1-¼-inch [3.18 cm] OD × .095 [.241 cm] wall thickness coiled tubing. The increased OD and wall-thickness sizes that can be cut with this ball and seat cutting mechanism provide the operator with a more flexible coiled tubing service program that can enhance operational safety. The mechanism is adaptable to current designs of subsea test trees in use on floaters and drilling ships. Presently, the mechanism is being incorporated into a 15,000 psi [103.41 MPa]-rated safety valve for use on a jackup or land rig (Figure 1) (Available in full paper). In addition to data from cutting tests performed with the newly-developed ball and seat mechanism, the paper will also address the applicability of this mechanism to new and existing well test safety valve designs. INTRODUCTION Since rig safety during a well test is one of the main priorities of the operator, the utilization of a reliable downhole safety valve to insure well control is of major importance. Because of its enhanced safety and flexibility characteristics, the safety valve that is normally used on a floater rig or drillship is the subsea test tree (Figure 2) (Available in full paper). This valve, which is spaced out in the BOP stack on the ocean floor, allows the operator to shut-in the well and unlatch from the test string in the event an emergency situation, such as a drive-off condition on a drillship, occurs.