Well Control: Wrong Practices While Manipulating Fluids

Well control: wrong practices for influx detection while manipulating fluids at the surface.

In a well control incident, while drilling the 8 ½” section, an 8m³ drilling fluid transfer to the active pit was carried out from the reserve pit which was not equipped with sensors. At this point, a sudden increase of SPP and mud flow-out percentage were detected, and bubbling was observed from the rig floor. The well was shut in, showing the following data: SICP stabilized at 2700 psi, SIDPP at 75 psi (float valve present in the BHA) and an approximate gain of 15 m³.

The well was controlled by implementing the driller’s method with a final MW of 2.24 sg (after four cycles of mud weight increments).

What went wrong in this well control incident?

• The pit volume increase was masked by the ongoing drilling fluid transfer operation. The total gas influx was estimated between 10-20 m³
• The pore pressure estimated for well design (1.78 sg) was significantly lower than the pore pressure encountered (estimated at 2.18 sg)
• People’s awareness of the associated risks proved to be low; gas had been circulated while drilling, but it was not associated with the fluids’ transfer risk
• Detection systems did not work as intended: The theoretical threshold for detection was 0.8m³ (5 bbls), but the system allowed an influx >10m³

Corrective actions and recommendations

• Implement a program to increase people awareness of well integrity operations and associated risks
• Review and enhance influx detection system
• Define clear instructions for transferring fluids at surface to avoid losing control of the active system
• Implement detection drills for well influx to reduce closing time. Reinforce procedural adherence both for the supervisory staff and the crew

Source: Well Control Lesson Sharing 21-3, IOGP (International Association of Oil & Gas Producers).