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The Well Control System or the Blowout Prevention System on a drilling rig is the system that prevents the uncontrolled, catastrophic release of high-pressure fluids (oil, gas, or salt water) from subsurface formations. These uncontrolled releases of formation fluids are referred to as Blowouts. Due to the explosive nature of oil and gas, any spark on the surface can result in the ignition of the fluids and an explosion on the rig. An explosive blowout and the failure of the Well Control System were the causes of the Mocondo Well disaster that killed eleven of the rig crew on the Deep Water Horizon Rig on April 20, 2010 and resulted in 35,000 to 60,000 bbl/day of crude oil to spill into the Gulf of Mexico. We will discuss this later in the lesson.

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In the detailed rig schematic (Figure 9.02e), the well control system is comprised of:

the Accumulator (Item 18)
the Blowout Preventer (not shown in Figure 9.02e)

Figure 9.02e: Well Control System in a Modern Rotary Rig

Source: Serintel: Oil and Gas Portal Drilling Technologies

A picture of a Blowout Preventer (BOP), pronounced “B-O-P” not “bop”, is shown in Figure 9.11.

Source: Gulf of Mexico Oil Spill Blog - Blowout Preventer Evidence

The blowout preventers are the principal piece of equipment in the well control system and are operated hydraulically; pressurized fluids are used to operate pistons and cylinders to open or close the valves on the BOP. The Accumulators (Item 18 in Figure 9.02) are used to store pressurized, non-explosive gas and pressurized hydraulic fluid to run the hydraulics systems on the rig. The accumulators store enough compressed energy to operate the blowout preventers even if the Power System of the rig is not operating.

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The blowout preventer is a large system of valves each of which is capable of isolating the subsurface of the well from the rig to provide control over the well. These valves are typically stacked as shown in the Figure 9.11 and sit below the rig floor on land wells or some offshore wells; or they may sit on the seabed on other offshore wells.

A schematic diagram of a blowout preventer is shown in Figure 9.12.

Figure 9.12: Schematic Diagram of a Blowout Preventer

Source: OGES - Knowledge Market for Oil & Gas BOP Pressure Testing Procedure

Figure 9.12 shows three type of valves (there are others) – an Annular Preventer, Blind Rams, and Shear Rams. The Annular preventer is the ring-shaped piece of equipment on the top of the BOP in Figure 9.11. As the name implies, the annular preventer is used to prevent flow through the annular space between the drill string or casing and the annular preventer. The annular preventer can also be used for non-cylindrical pipe, such as the kelly, or open hole. The annular preventer consists of a doughnut shaped bladder that when in the open position allows the drill pipe to rotate but in the closed position seals the annulus. Figure 9.13 provides a schematic of the annular preventer.

Figure 9.13: Schematic Diagram of an Annular Preventer

Source: Wikipedia - Blowout preventer, Egmason licensed CC BY-SA 3.0

In Figure 9.13, the blue area represents the doughnut-shaped bladder. As mentioned earlier, in the open position, (A), the drill pipe can be rotated or can be run up or down; while in the closed position, (B), the bladder pushes out, closing off the drill pipe, kelly, or open hole. The bladder based sealing element is not as effective as the ram type sealing elements; however, almost all blowout preventer stacks include at least one annular preventer.

Schematics of the ram-type preventers: the blind rams, the shear rams, and the pipe rams (pipe rams are not shown in Figure 9.12) are shown in Figure 9.14.

Figure 9.14: Schematic Diagrams of Ram-Type Preventers

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0

This figure shows that:

blind rams isolate both the pipe and the annular space by crushing the pipe and it pinching-off when closed;
shear rams isolate both the pipe and the annular space by shearing-off the pipe when closed;
blind shear rams isolate both the pipe and the annular space by shearing-off and crushing the pipe when closed;
pipe rams isolate the annular space by wrapping around the pipe when closed.

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A blowout begins as a Kick (entry of subsurface formation fluids into the wellbore). What distinguishes a kick from a blowout is that a kick can be controlled while a blowout is uncontrollable. We have already discussed two of the defenses against kicks when we discussed drilling fluids when we listed the objectives of the drilling fluid:

control formation pore pressures to assure desired well control (apply hydrostatic and hydrodynamic pressures in excess of the formation pore pressures to prevent fluids from entering the wellbore);
deposit an impermeable filter cake onto the wellbore walls to further prevent fluids from permeable formations from entering the wellbore.

In the first objective re-quoted above, if we can keep the pressure exerted by the drilling mud greater than the pore pressure, then we know that fluids will flow in the direction of the mud to the formation. This cannot always be achieved. For example, if we drill through a natural fracture or if our mud density is too great and we inadvertently fracture one formation, then we may lose large quantities of the drilling fluid into the fracture (Lost Circulation). In this situation, instead of having the full weight of the mud column exerting pressure on a second (porous and permeable) formation, we may only have a fraction of the oil column height exerting a lower pressure on that second formation.

In the second objective re-quoted above, if we deposit an impermeable Drill Cake (filter cake) across an otherwise porous and permeable formation, then for a slightly Underbalanced Pressure (drilling fluid pressure lower than the formation pressure) we have created a seal between the wellbore and the formation. Again, this is not a Failsafe System because at greater underbalanced pressures, the higher formation pressures may be able to displace the drill cake.

The two previously discussed methods are used to help prevent a kick from occurring, but as mentioned they are not always successful, and kicks may still occur. The causes of a kick include:

insufficient mud weight (density): the hydrostatic pressure exerted by the mud column is not greater than the formation pore pressure;
improper mud replacement during tripping: while tripping out of the hole mud volu