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).
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