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What happened?
While drilling the 8-1/2” (21.6 cm) hole section from 14,000-14,500 ft (4,267-4,420 m) in the overburden above the target reservoir sands, connection gases were observed, there were no indications of the well flowing.
Mud weight was increased from 11.7 ppg (1.40 g/cm3) to 11.8 ppg (1.42 g/cm3) and a moderate reduction of connection gas levels was observed.
Drilling continued to 15,168 ft (4,624 m) with continuing connection gases where a drilling break prompted the rig to stop and flowcheck. An increase of 0.9 bbl (143 litres) was seen over 15 minutes.
The flowcheck was repeated and an increase of 1.2 bbl (191 litres) was observed over 25 minutes. Both flowchecks were accepted as static based upon a decreasing trend.
Drilling continued to 15,198 ft (4,632 m) before stopping for planned mud treatment.
An extended flowcheck was performed and a gain of 3.5 bbl (555 litres) was seen over 55 mins, the well was shut in - total influx volume was estimated to be 3.5 bbl (555 litres).
Shut-in casing pressure (SICP) increased to 490 psi (33.8 bar) and shut-in drill pipe pressure (SIDPP) to 290 psi (20 bar) over a period of 2.5 hours. With pressures still rising slowly, the team elected to start the 1st circulation of the drillers’ method with a safety margin of 100 psi (6.9 bar) due to concerns about influx migration. At the end of the 1st circulation a diagnostic bleed and pressure build-up (PBU) was conducted while preparing kill mud weight (KMW), with SIDPP stabilising at 890 psi (13.2 ppg equivalent mud weight (EMW)) after 15 hours.
The well was circulated to a 13.1 ppg (1.57 g/cm3) surface mud weight (SMW) and a flowcheck after the circulation showed zero gain, well static.
Subsequently, due to high gas levels the mud weight (MW) was increased to 13.2 ppg (1.58 g/cm3).
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Why did it happen?
Connection gases had been seen drilling numerous offset wells in the field. Increases to MW had to be balanced against the risk of losses as seen on offsets, and connection gas was assumed to be manageable without increasing mud weight.
A continuation bias based on offset well experience led to two flowchecks which showed a slow and steady gain being accepted as static.
Kick pressure was above the high side pore pressure forecast. Several offset wells experienced connection gas in tight shales with static well conditions. This led to the under-estimation of high side pore pressure in the forecast. In this case, a kick was taken due to slightly higher permeability in this part of the field.
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What did they learn?
Pump off gas events should be assumed to be a result of underbalanced/close to balanced conditions (rather than wellbore breathing/ballooning) until proven otherwise.
If there is any ambiguity on the result of a flowcheck, extend the flowcheck. A fingerprint of similar flowchecks can support interpretation.
Review response to pump off gas events and ensure there is a common understanding of how to distinguish wellbore breathing from pore pressure across wells and subsurface disciplines.
Training for the rig team on flowchecks, including when an extended flowcheck is warranted, criteria required to interpret results.
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Ask yourself or your crew
How can something like this happen here (e.g. on our site)?
What safety measures (i.e. procedures, controls/barriers) do we have in place to mitigate the risk?
How do we know the risk controls/barriers are working?
What improvements or changes should we make to the procedures, controls/barriers, or the way we work?
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What happened?
While drilling the 8-1/2” (21.6 cm) hole section from 14,000-14,500 ft (4,267-4,420 m) in the overburden above the target reservoir sands, connection gases were observed, there were no indications of the well flowing.
Mud weight was increased from 11.7 ppg (1.40 g/cm3) to 11.8 ppg (1.42 g/cm3) and a moderate reduction of connection gas levels was observed.
Drilling continued to 15,168 ft (4,624 m) with continuing connection gases where a drilling break prompted the rig to stop and flowcheck. An increase of 0.9 bbl (143 litres) was seen over 15 minutes.
The flowcheck was repeated and an increase of 1.2 bbl (191 litres) was observed over 25 minutes. Both flowchecks were accepted as static based upon a decreasing trend.
Drilling continued to 15,198 ft (4,632 m) before stopping for planned mud treatment.
An extended flowcheck was performed and a gain of 3.5 bbl (555 litres) was seen over 55 mins, the well was shut in - total influx volume was estimated to be 3.5 bbl (555 litres).
Shut-in casing pressure (SICP) increased to 490 psi (33.8 bar) and shut-in drill pipe pressure (SIDPP) to 290 psi (20 bar) over a period of 2.5 hours. With pressures still rising slowly, the team elected to start the 1st circulation of the drillers’ method with a safety margin of 100 psi (6.9 bar) due to concerns about influx migration. At the end of the 1st circulation a diagnostic bleed and pressure build-up (PBU) was conducted while preparing kill mud weight (KMW), with SIDPP stabilising at 890 psi (13.2 ppg equivalent mud weight (EMW)) after 15 hours.
The well was circulated to a 13.1 ppg (1.57 g/cm3) surface mud weight (SMW) and a flowcheck after the circulation showed zero gain, well static.
Subsequently, due to high gas levels the mud weight (MW) was increased to 13.2 ppg (1.58 g/cm3).
Why did it happen?
Connection gases had been seen drilling numerous offset wells in the field. Increases to MW had to be balanced against the risk of losses as seen on offsets, and connection gas was assumed to be manageable without increasing mud weight.
A continuation bias based on offset well experience led to two flowchecks which showed a slow and steady gain being accepted as static.
Kick pressure was above the high side pore pressure forecast. Several offset wells experienced connection gas in tight shales with static well conditions. This led to the under-estimation of high side pore pressure in the forecast. In this case, a kick was taken due to slightly higher permeability in this part of the field.
What did they learn?
Pump off gas events should be assumed to be a result of underbalanced/close to balanced conditions (rather than wellbore breathing/ballooning) until proven otherwise.
If there is any ambiguity on the result of a flowcheck, extend the flowcheck. A fingerprint of similar flowchecks can support interpretation.
Review response to pump off gas events and ensure there is a common understanding of how to distinguish wellbore breathing from pore pressure across wells and subsurface disciplines.
Training for the rig team on flowchecks, including when an extended flowcheck is warranted, criteria required to interpret results.
Ask yourself or your crew
How can something like this happen here (e.g. on our site)?
What safety measures (i.e. procedures, controls/barriers) do we have in place to mitigate the risk?
How do we know the risk controls/barriers are working?
What improvements or changes should we make to the procedures, controls/barriers, or the way we work?
While drilling in the 8-1/2” (21.6 cm) hole section of an offshore gas development well using a jackup drilling unit, an influx was taken of approximately 3.5 bbls (555 litres). The well was subsequently shut-in…
Original material courtesy of the International Association of Oil & Gas Producers (IOGP)
