Complications during well control operations Stopping the control operation, Plugged chokes, Change in circulating kill rate, Plugged bit nozzles, Kick caused by loss of circulation below production zone, Complete power failure during the controlling operation
1 Stopping the control operation
Control operations may have to be stopped because of equipment failure or for checking static pressures at certain stages of the control process. If the control operation is interrupted, the choke must be closed immediately. The standpipe pressure should not be allowed to be bled off to its theoretical value to avoid the possibility of more influx entering the well bore. The closed-in period must be kept as short as possible.
If a long shutdown period is unavoidable, the well has to be observed in order to avoid the pressuring effect of the gas due to migration. "Kick control by the volumetric method" should be applied if bleeding off is necessary. For long duration shutdowns, consider to close an upstream valve, instead of merely relying on the choke.
The procedure to check for trapped pressures is described here (Click Link)
2 Plugged chokes
Cuttings, loose formation particles, etc., may plug the choke and cause a sudden rise in pressure in the annulus and drillpipe. If this happens, another choke must be opened, or pumping must be stopped immediately to avoid over-pressuring the well.
In order to take prompt action and to ensure that the correct operational steps are made, it is essential that:
·there is good communication between all persons involved at all stages of the well control operation;
·the actual pressures on drillpipe and annulus are always known.
If the chokes become partially plugged and the decision is made not to interrupt the operation for cleaning the chokes, it may be necessary to reduce the pumping speed, because of too high standpipe pressures.
3 Change in circulating kill rate
During well killing operations the circulating rate may have to be reduced because of higher than preferred pumping pressures or pumping speed may have to be increased if faster pumping is desired.
The procedure to change the circulating rate and to determine the new circulating pressure during phases 2, 3 and 4 of the killing operation is as follows:
·Maintain Pchoke constant for the short period it takes to change the circulating rate to the selected pumping speed.
·Read Pst at the new pump rate and maintain Pst constant thereafter.
The procedure to change the circulating rate in phase 1 when mud of a different mud gradient is pumped is as follows:
·Calculate the average mud weight (Wav) in the string at the time pumping is stopped or changed.
·Calculate Pdp' at the time pumping is stopped/changed.
·Maintain Pchoke constant for the short period it takes to change the circulating rate to the selected pumping speed.
·Read Pst' at the new pump rate and plot this pressure at time T1 (change in circulation rate).
·Calculate Pc1' = Pst' - Pdp'.
·Calculate
Pc2=Pc1 * new mud weight / average mud weight
·Plot Pc2' at time T2 (end phase 1).
·Connect points Pst' and Pc2' with a straight line. This line represents the standpipe pressure whilst pumping the new mud to the bit.
4 Plugged bit nozzles
When plugged nozzles occur whilst pumping at a constant pump rate, Pst will increase. If, after opening the choke further, Pst remains higher than expected and Pchoke drops, the nozzles may be partially plugged, or there is a restriction in the annulus. Newly adjusted standpipe pressures will have to be used during further well killing operations. (Always check if the valves upstream of the Pchoke measuring point are fully open).
The Pst graph needs to be revised according to the procedure used for changing the circulating rate, regardless if any change in circulating rate has taken place. Always keep in mind that nozzles can "un-plug" again after a while, and graphs should be re-adjusted accordingly.
5 Kick caused by loss of circulation below production zone
Loss of circulation may occur when a lower pressured formation is penetrated with a mud weight required to control an overlying higher pressured reservoir. The shallower, higher pressured zone may produce as the mud level drops in the annulus.
Control of the well should be re-established by pulling the bit above bottom as high as possible, close in the well in the normal manner, and then pumping mud preceded by a reasonable LCM pill into the annulus. Small amounts of clean mud should be pumped into the drillpipe at regular intervals simultaneously to prevent blockage of the bit nozzles. If deemed necessary the mud density can be reduced to the extent that it will just control the upper (kick) zone, but should not or need not be increased since the original density was adequate to overbalance the upper zone.
When the LCM pill has reached the loss zone (i.e. on bottom), the entire annulus content including any influxes will have been displaced into the loss zone, and if plugging is effective the well should be dead and under control. At the moment that the LCM pill reaches the loss zone and plugging is accomplished, in theory an increase in pump-pressure (i.e. squeeze pressure) should be observed. However, do not attempt to continue squeezing with the prime aim of obtaining a pressure increase. Most important is that the LCM pill is in place and is given the time to be effective. At this moment, when squeezing is completed, pumping into the drillpipe should also be stopped and the well should be closed in and observed for a reasonable period.
Subsequently, the choke should be opened for a flow check, and if no flow, the BOP can be opened and careful normal circulation resumed to ensure that the well remains stable enough at least to be able to make a roundtrip.
Drilling ahead may not be possible, because losses could re-occur as soon as the bit enters, disturbs, and removes the remains of the LCM pill on bottom. In that case the sequence has to be repeated, possibly having to revert to soft plugs or even eventually setting cement plugs by means of open-ended drillpipe.
It should be noted that the above procedure entails that the rig set-up should be such that pumping simultaneously into the drillpipe and down the annulus is possible.
6 Complete power failure during the controlling operation
The provision of an emergency system to maintain pressure on the BOP accumulator unit, in case of a complete power failure during well control operations, shall be available on each rig.
This requirement could be met by one of the following options:
·Have an independent power supply or emergency generator linked with the accumulator system.
·Connect a small diesel-driven compressor to the accumulator air pumps.
·Install an independently (e.g. diesel) powered cement pump with gravity fed suction lines from the mud/water tanks. Provision should be made for delivery lines to the well and also to the BOP accumulator unit.