Well Flows When BOP Was Removed to Install Casing Slips and Pack Off
In an unconventional field with known well flows due to injection zones, an intermediate hole section was drilled to TD and casing ran until stuck off bottom, all while managing water flow with mild H2S.
The intermediate 8.3/4” hole section was drilled to section TD at 10,0025 ft, while managing well flows with associated H2S. The casing was run, but became stuck off bottom, and was cemented in place. Having waited on cement for 32 hours and with no flow observed the BOP (blowout preventer) was removed to install the emergency casing slips and pack-off assembly. However, during this operation, flow was observed from the well.
The BOP was reinstalled and the well secured, an influx of 60 bbbls had occurred with a shut in pressure of 57 psi. The well was subsequently killed by bleeding off the pressure filling the annulus with kill weight mud and bull heading cement to provide isolation. The BOP was then removed and the emergency casing slip and pack off installed.
What happened in the well flows incident?
In an unconventional field with known well flows due to injection zones, an intermediate hole section was drilled to TD and casing ran until stuck off bottom, all while managing water flow with mild H2S. The casing was cemented in place with no returns to surface, float was bumped and held differential pressure. At 50 psi compressive strength development after ~18 hrs post cement placement, intermittent water flow with shut in casing pressures necessitated higher compressive strength development wait time.
After WOC for 32 hrs to achieve 500 psi compressive strength with no flow observed, the BOP was lifted to install the emergency slips and pack-off. ~3 hours into this operation, flow was observed and the team reinstalled the BOP and secured the well with 57 psi shut in casing pressure and 60 bbls water influx gained. Pressure was bled off to zero and well was monitored for ~2 hrs with no flow but observed to be on vacuum. The annulus was filled with 15.5 ppg mud and decision was subsequently made to squeeze the annulus with 14.8 ppg cement slurry which was performed in three stages. After the squeeze job, the well was flow checked for 1hr with no flow. BOP was then nippled down, emergency slips and packoff were installed and tested to establish barriers to annulus flow
What went wrong?
- Offset operator was not cooperative to the request to shut in their 3 nearby injectors (800-1000 BPH waterflow intensity was experienced on this pad).
- Inability to land casing conventionally leading to use of emergency slips. (The C21 slip hanger with emergency seals and packoff were installed in +/-8hrs. The C22 version provides an automatic packoff seal, energized by casing weight enabling faster installation but is not available for the casing size ran. Both versions can be lowered through a full opening BOP
stack into the wellhead with casing connection considerations). - Cement contamination due to waterflow necessitating longer WOC time.
Corrective actions and recommendations:
- Well shall be completely shut in while WOC to reach required compressive strength.
- Continue to work with regulatory body (TRC) to make top job/cement squeeze a standard
operating procedure option for when primary jobs experience severe losses. - Work with business partner to reduce transition time for the cement during waterflow events.
- Reduce directional work in the bottom section of the hole section (more likely to land hanger
in wellhead).
Content and image credit: IOGP (International Association of Oil and Gas Producers), IOGP, WCI Lesson Sharing 22-7.
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