IOGP Well Control Incident Lesson Sharing
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Flow observed from the annulus 2 hours after the completion of a 13 3/8” casing cementing operation. The flow noted has been deemed a controlled well control event.


After completing a 13 3/8” casing cementing operation, and while waiting on weather (WOW) to lay down the cement head post cement job with the casing hanger running tool still connected, flow from the annulus side was observed. The flow started 45 minutes after the cement was in place. The initial flow observed was approximately 2.1 bbl/hr to the trip tank. After 2 hours, and observing flow in excess of predicted thermal expansion values, the well was shut in on the upper annular BOP with pressures being monitored.

IOGP Wells Expert Committee/Well Control Incident Subcommittee believes that this incident description contains sufficient lessons to be shared with the industry. We further encourage the recipients of this mail to share it further within their organization.


After completing cementing operations on the 13" 3/8 casing and while WOW to lay down the cement head post cement job with the casing hanger running tool still connected, flow from the annulus side was observed starting 45 minutes after cement in place with an overall increase in trip tank of 2.1bbl/hr. After 2 hours, and observing flow in excess of predicted thermal expansion values, the well was shut in on the upper annular BOP. Pressure was 1140 psi on the Drillpipe running string and 1240 psi on Casing.

Over the course of 2 days a series of controlled diagnostic bleeds were carried out on both the casing and annular side. It was concluded that the observed flow and pressure build-up on the annulus side was not due to thermal expansion, but that an influx of formation fluid had most likely entered the wellbore and we had an annulus flow channel from formation to surface. Attempts were made to bullhead the suspected influx back to the formation. However, injection pressure was limited by the presence of a burst disk in the 22” surface casing. Following a risk assessment, and recognizing that the rate of influx had stabilized at a low rate, it was agreed to open the BOP, release the running tool and recover the casing landing string, and then run in with the casing seal assembly on the Drillstring and secure the 13 5/8" x 22" annulus by setting this seal assembly in the wellhead. This operation was a success and the incident closed.

What Went Wrong?:

  • The investigation team found that failure of the annular fluid barrier occurred because the cement slurry failed to create a barrier to well flow, allowing the formation fluids to flow through the cement either before the well was shut in, or during the first annular pressure build.
  • The primary cement program was to place a 3 slurry cement job design. Each slurry was intended to reach a static gel strength value that would prevent flow while the slurries on top and the mud column would remain liquid and transmit hydrostatic pressure. The primary mitigations failed because the 3 slurries became intermixed within the 13 3/8” inch casing during placement and the distinct and separate performance of each slurry was not achieved.
  • A cement evaluation log was run and interpreted showing overall good cement placement with small tortuous flow paths within the cement sheath indicative of post placement flow into a setting cement column. These flow paths were analyzed to be analogous with flow paths within some cement columns in other areas labelled as “worm holes” to characterize their small size and tortuous path. These defects are indicative of post-placement flow during setting of the cement column, as opposed to micro annulus flow paths generated by pressure cycling.

 

Corrective Actions and Recommendations:

  • Long cement columns above permeable zones create a high post cement placement flow potential; this risk should be adequately highlighted in the Cement Execution Program.
  • Sensitivities to the success, or failure, of key risk mitigations should be considered and discussed to inform future operational decisions. Do not rely on a multi-slurry designs with engineered gel strength transition as the primary mitigation for post placement flow.
  • Error on keeping the well shut-in for a longer period of time after a major cementing operation to give the cement more time to setup.
  • The D&C engineering team should adequately communicate the risk of post cement placement flow to the offshore execution team within the Cement Execution Program to assure a common understanding of the risk and the mitigations that are in place. Ideally, in any Cement Execution Program, post cement placement flow risk should always be highlighted with mitigations detailed in the program.


safety alert number: 329
IOGP Well Control Incident Lesson Sharing http://safetyzone.iogp.org/

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