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Secondary Well Control Methods

Procedures for dealing with a kick will depend on a variety of conditions, including the type of drilling rig being used and the operation currently being performed on the well.  Drillers could be tripping pipe in or out of the hole, or they might have the drillbit on bottom while actively drilling. 

Bit on Bottom Example

As an example, if the bit is on bottom and drilling with a rotary table rig when a kick is detected, pipe rotation is stopped, and the drill string is raised so that the kelly and a tool joint are above the rotary table. The pumps are shut down and the blowout preventer (BOP) is closed. (The specific BOP that is closed is typically the annular preventer, as described more fully on the next page.) Raising the drill string before closing the BOP assures a better hydraulic seal in that the rubber gasket of the annular preventer closes on a cylindrical drill pipe joint as opposed to the square cross-section kelly. 

The Wait-and-Weight Method

Closing the BOP seals the annulus, and as the formation fluids (the kick) enter the wellbore, they increase the fluid volume in the now confined annular space, which in turn causes the wellbore pressure to rise. A typical procedure at this point is called The Wait-and-Weight Method. The drill crew waits for the wellbore pressure to rise to balance with the formation fluid pressure, causing the formation fluid flow into the wellbore to stop. The new balanced wellbore pressure is recorded and the appropriate kill mud weight is calculated. The pumps are restarted, the higher mud weight is introduced in the drill string at the surface and pumped downhole, with the annular fluids being routed to the surface through the choke line to clear the hole of the insufficient weight mud that is also contaminated with formation fluids. Once an entire wellbore fluid circulation cycle is complete, the appropriate weight mud will be present in the drill pipe and the annulus. The surface choke line can be closed, the annular preventer opened and the well bore conditioned so that drilling can continue.

Blowout Preventers

If standard procedures to kill the well after taking a kick don’t work, the flow from the formation that produced the kick can get out of control and cause what is called a blowout. The blowout could involve uncontrolled flow to the surface, or if the BOP’s do their job to seal the well below the rig floor, the uncontrolled fluid could exceed formation pressure or fracturing pressure in a shallower (lower pressure) formation and cause a downhole blowout. Remedies to this more serious case of loss of well control will be discussed in the lesson on Tertiary Well Control.

BOPs are mounted on top of the surface casing, which is the anchor point for sealing the well if the need arises. Normally, there are more than one type mounted on a BOP stack. There are well-defined methods for using BOP equipment. If the equipment has been properly maintained and used correctly, the BOPs should work.

A BOP stack secured to the top of the wellbore, known as the wellhead. The drilling floor can be seen from below at the top of the photograph.

Additional Functions of BOPs

In addition to BOPs sealing the well in case of a ‘kick’, they have additional functions. BOPs were developed to cope with extreme erratic pressures and uncontrolled flow emanating from a well reservoir during drilling. In addition to controlling the downhole pressure and the flow of oil and gas, BOPs are intended to prevent pipe, tools, and drilling fluid from being blown out of the wellbore when a blowout threatens. They also regulate and monitor wellbore pressure. BOPs are critical to the safety of crew, rig, and environment, and to the monitoring and maintenance of well integrity. They are intended to provide fail-safety to the systems that include them.1Blowout Preventers. (June 3, 2021). In Wikipedia. https://en.wikipedia.org/wiki/Blowout_preventer

Power Failure and the Accumulator

What if power fails during a rig crisis? Crew members can control the BOP with the use of a device known as an accumulator unit, or BOP Closing Unit. Accumulators are placed in hydraulic systems for the purpose of storing energy to be released and transferred throughout the system when it is needed to accomplish specific operations. Well pressure-control systems typically incorporate sufficient accumulator capacity to enable the blowout preventer to be operated with all other power shut down.2Schlumberger. (n.d.). Accumulator. Schlumberger Oilfield Glossary. Retrieved June 30, 2021 from https://glossary.oilfield.slb.com/en/terms/a/accumulator

Image Credits: Photo Courtesy Paul Bommer

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