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What’s All This Talk About Lockdown Sleeves?

Contributor: Derek Park
Posted: 04/06/2015
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Soon after the Macondo disaster the US authorities (at that time BOEMRE, the Bureau of Ocean Energy management, Regulation and Enforcement) issued what became known as the ‘drilling safety rule’. In reality the rule contained several requirements which addressed well bore integrity and well control equipment. Included amongst them was a requirement that

‘The operator must ensure that the latching mechanisms or lock down mechanisms are engaged upon installation of each casing string or liner’ .

This interim requirement was reconfirmed when the final rule was issued towards the end of last year by the new US authority BSEE (Bureau of Safety and Environmental Enforcement).

So what does BOEMRE’s early insistence on casing lockdown tell us about what happened on Deepwater Horizon? Members of Congress and a committee of MP’s in the UK have suggested that BP ’did not deploy the casing lockdown sleeve that would have prevented the seal from being blown out of the well’ . But some pretty influential people have got hold of the wrong ends of several sticks here and there was hope that things would be clarified during the BP Trial held in New Orleans earlier this year. But no, confusion still seems to reign. So what is all this talk about lockdown sleeves?

First let’s look at what the lockdown sleeve isn’t. It is not a device designed to prevent casing rising in the wellhead during drilling, so it cannot fulfil the BSEE requirement to lockdown casings as they are installed string by string. Casing hangers are designed with integral locking devices which latch as each string is landed so what does the BSEE concern tell us about Macondo and the wider offshore industry?

BSEE are concerned that drilling ahead with casings not locked down is potentially dangerous but we know that BP, and this is common with other operators, made the conscious decision to remove the primary locking device from the casing hanger. They were happy leaving the casings unlocked, always intending to use the lock-down sleeve, a secondary device, to secure the casings at the end of drilling as part of the temporary abandonment procedure.

It is wrong to conclude that BP happened to install the lock down sleeve at the wrong time. What they failed to do was to use the casing system in the way it was designed to be used, and lock down each casing as it was landed using the integral locking device, so why? Things get even more curious considering that the cost of installing the secondary lockdown sleeve has been estimated at two million dollars, requiring a trip for a lead impression tool before running in the sleeve itself. There is also a requirement to hang 100,000 lbs of drill pipe, referred to as the tail pipe, below the running tool. Why would an operator want to do that when, using a simple lock ring on the casing hanger does the same job at no extra cost?

Before we answer that question let’s look at the possible implications of leaving the casings unlocked and particularly how this could have influenced the blow out. Inside and outside the trial we have heard several theories suggesting that there was annular flow, perhaps from a shallower hydrate formation, as well as ‘conventional flow’ through the production casing. At the trial BP were adamant that the casing had not lifted and unseated the seal, forensic examination having shown no erosion across the annular seal assembly in sharp contrast to the severe erosion seen on the BOP and drill pipe.

This however is not the time to debate the various theories but irrespective, the decision to leave the casings loose and rely on the subsequent setting of the lockdown sleeve did have implications for the events that followed.

BP decided that setting the sleeve would be last step in the temporary abandonment (TA) procedure and therefore be done after the setting of the final abandonment cement plug. Because of the need to leave space for the tail pipe, the cement plug had to be set deeper in the well which in turn meant that more mud had to be displaced to allow the plug to be set in seawater. Irrespective of what happened, that decision, a direct consequence of the casing hangar having been left loose in the wellhead, clearly eroded the safety margin in the well.

On top of that, doubts about the integrity of the unlocked annular seal resulted in a more cautious approach to the subsequent well kill operations and possibly several unnecessary weeks of flow and pollution before the well was brought under control.

So to return to the key question, why were the casings not locked down as they were landed using the integral locking rings? We have seen that this would have improved the integrity of the well and saved the cost of fitting the lock down sleeve. On surface wellheads the casings are always locked immediately after casing is cemented so what is different subsea? Suppliers confirm that they can instantly lock down their hangers so why is the US regulator having to legislate to make it happen?

The truth is that integral lock-rings are unreliable and difficult to remotely activate in an environment full of drilling waste and debris. When a lock ring fails to expand it may prevent the annular seal from seating, inviting expensive remedial measures and the possibility of damage to the wellhead bore.

Even when fitted and working properly, the stack up tolerances associated with multiple hangers standing end on end requires considerable slack to be built into the system. This allows the hangar seals to move over time to the detriment of integrity. Lock-down sleeves were developed as secondary back up for the integral devices and as a means to extend the life of subsea annular seals. However, because of the difficulties inherent in the use of the lock rings, the lock down sleeve has in many cases it become the only device used.

Some of the reluctance to use the integral locking rings could also stem from the difficulty of release once locked in place. This can make it all but impossible to release the un-cemented section of the final casing string and removes the option of side-tracking the well later in its life.

It can be seen from statements made at the Macondo hearings that prior to the incident it was not unusual for operators to dispense with the primary means of locking down casing, preferring instead to rely on the secondary lock-down sleeve for production applications. In practice this sleeve can only be fitted once drilling is completed and therefore can never offer any protection during the drilling phase. It is futile to speculate that the Macondo blow-out could somehow have been prevented by fitting the lock-down sleeve earlier. The only way to improve well integrity during the drilling phase would have been to lock down the casings with the primary device.

The requirements of BSEE are clear:

‘the operator must ensure that the latching mechanisms or lock down mechanisms are engaged upon installation of each casing string or liner’

These legal requirements can only be met by installing and using the integral devices on each casing hangar and we have seen how problematic this can be.

Three questions therefore remain.

1. Since the drilling safety rule was issued in 2010, has every casing on every deep-water well in United States been locked down as required by BSEE?

2. What position have the UK HSE and DECC taken on the issue of instantly locking down subsea casing hangars, and what are the rules regarding capacity requirements?

3. How many pre-Macondo wells, including abandoned exploration wells, are sitting with loose casings, especially in areas where shallower hydrate formations etc. are known to be problematic?

Any answers?

Contributor: Derek Park