SHUT IN PROCEDURES
OBJECTIVESTo cover the shut-in procedures and diverter procedures for a surface BOP. To cover A.P.I. recommendations for these procedures which includes advantages and disadvantages.
Note: A fixed rig is defined as a drilling rig equipped with a surface BOP.
GENERAL INTRODUCTION TO SHUT-IN PROCEDURES ON A FIXED RIG
- Shut-in procedure should be agreed by contractor and operating company and posted on rig floor before drilling the well begins.
- When any positive indication of a kick is observed such as a sudden increase in flow or an increase in pit level, then the well should be shut in immediately without doing a flow check.
- If the increase in flow or pit gain is hard to detect then a flow check can be done to confirm the well is flowing.
- If surface hole is being drilled and the conductor pipe is not set in a competent formation and a shallow gas kick is taken then the gas should be diverted. This will be discussed at the end of this section.
- The procedures which follow are generalized suggestions and not necessarily applicable to any specific rig.
- Soft Close-in Procedure. For a soft close-in, a choke is left open at all times other than during a well control operation.
- The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blowout preventer.
- When the soft close-in procedure is selected for closing in a well the:
1) choke line valve is opened.
2) blowout preventer is closed.
3) choke is closed.
- This procedure allows the choke to be closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure. This is especially important if formation fracturing and broaching to the surface is likely to occur if the well is closed in without regard to the possibility of excessive initial closed- in casing pressure.
- The major disadvantage of the soft close-in procedure is that the additional time involved in opening the choke line valve and closing the choke will allow additional influx into the wellbore. This procedure will result in a larger kick volume and potentially higher casing pressure than obtained if the hard close-in procedure is used while circulating out the kick.
- Hard Close-in Procedure. For a hard close-in, the chokes remain closed at all times other than during a well control operation.
- The choke line valves are aligned such that a flow path is open through the choking system with the exception of the choke(s) itself and one choke line valve located near the blowout preventer stack.
- When the hard close-in procedure is selected for closing in a well, the blowout preventer is closed. If the casing pressure cannot be measured at the wellhead, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold.
- This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the wellbore.
- Use of the hard close-in procedure is limited to well conditions in which the maximum allowable casing pressure is greater than the anticipated initial close in pressure and a well fracture would not be expected to broach to the surface on initial closure.
- The hard close-in procedure is somewhat less complicated, can be performed by one man working on the rig floor, and is more likely to be performed without inadvertent delays in closure than the soft close- in procedure.