Well Control
Engineers first institute primary well control to mitigate hydrocarbons from entering the wellbore while drilling, as discussed in the previous lessons. However, if primary well control is unsuccessful, the imbalance in pressure allows hydrocarbons to enter the wellbore.
The purpose of secondary well control is to mitigate unwarranted flow of hydrocarbons into the wellbore – a kick. To attenuate this unwanted flow of formation fluids, the blowout preventers (BOP) are activated. The essential purpose of a blowout preventer is to seal the wellbore, preventing hydrocarbons that have entered the wellbore from reaching the surface.
A blowout preventer consists of a large valve at the top of a well that can be closed if a ‘kick’ registers loss of control of formation fluids. By closing this valve, usually remotely, the drilling crew should be able to regain control of the well, increase the mud weight, and eventually open the BOP and continue operations safely.1Schlumberger. (n.d.). Blowout Preventer. In Schlumberger Oilfield Glossary. Retrieved June 30, 2021 from https://glossary.oilfield.slb.com/Terms/b/blowout_preventer.aspx
BOPs vary in their specifications. Some can effectively close over an open wellbore. Some are designed to seal around tubular components in the well (drillpipe, casing or tubing). Others are fitted with hardened steel shearing surfaces that can actually cut through drillpipe.
BOPs Should be Regularly Checked and Maintained
Because of their critical importance to the safety of the crew, the rig, and the wellbore itself, BOPs are regularly inspected, tested, and refurbished. Frequency and procedures are determined by a combination of risk assessment, local practice, well type, and legal requirements. Tests vary from daily function testing to monthly or less frequent testing on wells with low probability of well control problems.2Schlumberger. (n.d.). Blowout Preventer. In Schlumberger Oilfield Glossary. Retrieved June 30, 2021 from https://glossary.oilfield.slb.com/Terms/b/blowout_preventer.aspx
To maintain primary well control, it is important to maintain constant bottomhole pressure. Bottomhole pressure is the pressure, typically measured in pounds per square inch (psi), at the bottom of the well. As previously discussed in our lesson on Primary Well Control, bottomhole pressure must equal or exceed formation pressure to prevent fluids flowing into the well. However, dramatic increases in bottomhole pressure could also cause further risks, such as fractures in the formation, consequential leakage of fluid out of the wellbore, a loss of primary well control, and a subsequent ‘kick.’