During well kill operation, crews should always be vigilant since complications can actually occur at any stage. If there’s a discrepancy in the kill plan, it needs to be noted immediately. For example, pressure gauges may stop working; they therefore should be monitored carefully. If there’s a failure, back-up gauges need to be made available during a well control operation.
In this article, it will describe common problems and complications during well kill operation which are plugged bit nozzle, plugged choke, choke washout, pump failure and string washout.
Plugged Bit Nozzle
When the drillpipe pressure increases, without a huge change in choke pressure, this suggests a plugged nozzle in the bit. To reduce drillpipe pressure to a comfortable circulating pressure, there’s normally a temptation to open the choke by the operator. However, this will lead to a bottomhole pressure decrease after a similar drop in choke pressure.
If the plugged nozzle is detected during first circulation of driller’s method, a choke operator should record new circulating pressure without changing any position of choke. If the problem is seen during second circulation of driller’s method, you can maintain casing pressure (choke pressure) until kill mud weight reaches a bit, then maintain the lasted drill pipe pressure. In another scenario during kill the well using wait and weight method (engineer’s method), if this situation occurs, you need to wait to get new stabilized circulating pressure and recalculate a new pressure schedule.
Elsewhere, the packing off around the BHA can also cause drillpipe pressure increases. As a result, circulating pressures are likely to both increase and fluctuate. To remove the problem completely, the drillstring needs to be reciprocated if possible. Unfortunately, a rapid increase can be experienced in drillpipe pressure when the bit becomes totally plugged (despite very little change in choke pressure). When this occurs, the string needs to be perforated if the problem isn’t cleared by the increased drillpipe pressure; to re-establish circulation, the perforation needs to be as close to the bit as possible. A circulating sub should be run above the bit or core barrel; this is considered good practice and is especially important in critical hole sections.
When choke pressure and drillpipe pressure increase simultaneously, this suggests a plugged choke situation. Whenever the annulus is loaded with cuttings, it’s normal to expect some plugging of the choke.
When this happens, the first step should always be to open the choke; this is important not only to clear the restriction but also to avoid over-pressuring. If unsuccessful, the pump should be stopped as quickly as possible. It is advised to switch to an alternate choke before then bleeding the excess pressure in the well; if done correctly, the displacement can then be restarted as normal. If cuttings plug the choke, over-pressuring can be prevented by displacing a kick at a slow circulation rate. With this in mind, in critical conditions, circulation rates should be minimized when there’s likely a large volume of cuttings in the annulus.
Since a sudden cut is incredibly unlikely in the choke, there’s not really a common symptom that it’s about to occur. Over time, the choke will wear so it’s important to gradually close it in and this should allow for circulating pressure maintenance. If the operator is having to do this to maintain circulating pressure, the pit volume should be checked just in case lost circulation is a problem. If there’s no loss of circulation, this suggests a worn choke. Even with the choke fully closed, there could come a point where a suitable circulating pressure is difficult to maintain. Before it gets to this stage, the worn choke should be repaired after switching the flow to a different choke.
When there’s a failure at the fluid end, a common indicator is irregular rotary hose movement along with erratic standpipe pressure. In many cases, a decrease in circulating pressure will precede this. If an operator suspects pump failure, the well should be shut-in and the pump stopped. With the second rig pump (or the cement pump, if necessary!), the displacement should be continued. After this, there should be immediate repairs to the pump.
When a washout in the drillstring occurs, the most common indication will be a standpipe pressure decrease (the choke pressure will remain unchanged). In this event, the well should be shut in and the pump should be stopped. Through drillstring manipulation and extended circulation, the washout can grow in size so this needs to be prevented.
The biggest risk in these circumstances is a washout occurring close to the surface. If this happens, displacing the influx from the hole will become difficult and unlikely; it will only be possible when the influx is above the washout. If near the bottom of the well, displacing the kick may be possible. Of course, this comes with certain risks including the parting of the drillstring with continued circulation. If the pump is restarted, it’s important to re-establish the circulating pressure no matter the washout depth. If the original circulating pressure is maintained at the standpipe, this could cause excessive downhole pressures. Through a washout, the circulation may be contained for extended periods so the circulating pressure should be re-established periodically.
Summary of pressure responses of each complication is shown in the table below.
References Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.
Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.
Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.