**2. Well barriers for maintaining and regaining well control**

A well barrier, an item that prevents the fluid flow from the well to the surrounding, is essential to maintaining well control. The two-barrier principle is widely adopted by different regulatory authorities across different petroleum provinces. These two barriers, which are required to be independent of each other, are usually categorized as *primary* and *secondary* barriers with the primary barrier being the closest to the reservoir—the potential source of formation fluids. During the drilling phase, the hydrostatic pressure exerted by drilling fluid is the primary barrier. Thus, the use of the term *primary well control* which refers to prevention of formation fluids into the wellbore by a static drilling-fluid column. The active secondary barrier while drilling is the BOP while the wellhead seals, casing, and cement serve as passive secondary barriers. One exception to the two-barrier rule applies while drilling the top-hole i.e., the first hole section drilled prior to the installation of the Surface BOP on the wellhead. If primary control is lost while drilling the top-hole, the formation fluids from the well are rerouted away from the drilling rig via a diverter [1, 5]. For completion or work-over operations, the designation of a barrier as either primary or secondary is dependent on activities executed during this phase. While the barriers are similar to the drilling barriers for certain aspects of the operation, towards the end of operations sequence, the barriers will be mechanical only, similar to the ones which exist in the production phase. For example, operations carried out through tubing with the well underbalanced with respect to reservoir pressure no longer have the wellbore fluid as a barrier. In a production or injection wells, where packers exist, they will typically become the primary barriers, as they seal off the annulus, the tubing below the surface-controlled subsurface safety valve (SCSSV), and the SCSSV. On the other hand, the secondary barrier envelope would be made up of the tubing above the SCSSV, the X-mas tree main flow side, the casing/wellhead, and the annulus side of the X-mas tree. While the loss of well control can occur anytime during drilling operations, the risk associated with loss of well control is assessed during the well planning phase which precedes well construction [5, 6].

A well control incident occurs when there is a failure either of the barrier(s) or in activating the barrier(s) resulting in an unintentional flow of formation fluid into the wellbore, another formation or to the external environment [7, 8]. The unintended flow of fluids from the formation into the wellbore (a kick) can occur due to several reasons such as insufficient drilling fluid weight (density), not properly filling the drilled hole either while tripping in or out of the well (adding pipe to the drill string to lower it further into the wellbore or removing pipe from the drill string to bring it closer to the surface), swabbing (a decrease in bottomhole pressure due pulling the drill string too quickly), cutting of the drilling fluid by the formation fluids (reduction of drilling fluid weight due to dilution with gas) and lost circulation.

When drilling conventionally, following a kick, loss of well control is prevented by activating the BOP, which in this case is secondary barrier. Failure to close the BOP timely following loss of primary well control would result in increasing influx volume and flow in the annulus of the well. The risk of inability to close the BOP grows with increase in the flow rate. Therefore, successful activation of the BOP is increased by early kick detection. Where there is a substantial kick size, there exist a high chance of subsurface leaks occurring, this can be mitigated by a fast shut-in [1, 4]. Following closure of the BOP valves, the well is circulated with a higher density drilling fluid using one of the three constant bottomhole pressure (BHP) methods namely waitand-weight method, driller's method, and the concurrent method. If properly applied, constant pressure at the hole bottom is achieved and prevent additional influx into the well [1, 5].
