‘Triggers’ lists help Shell identify, manage change in well operations

By Linda Hsieh, managing editor

Identifying change is often a forgotten step in the management of change process, said Aren’t Roggeveen, Shell.
Identifying change is often a forgotten step in the management of change process, said Aren’t Roggeveen, Shell.

There’s nothing constant in life except change. It is so pervasive that people can become blind to change, potentially resulting in additional risks. That’s why the most complex part of the industry’s management of change (MOC) process is often the ability to simply identify change, said Arent Roggeveen, RDL wells – Middle East, Russia and North Africa for Shell International E&P. “Identifying change becomes a vital and often forgotten step,” he said at the 2011 IADC Drilling HSE Europe Conference & Exhibition, 28-29 September, Amsterdam.

To provide a structure around MOC and to help employees identify change, Shell is rolling out a global effort to get the right people around the table and communicate. “What I’m encouraging the teams to do is to sit together on a weekly basis, maybe even more often, at different levels in the organization … and put HSE at the top of the agenda for the meeting and put management of change as the second item on the agenda,” Mr Roggeveen said.

The intent is to get employees to step back and think about whether anything has changed in their business – early during the planning and design stages rather than later during execution. Using a list of “triggers,” employees can look for changes that might instigate a risk assessment. Although the vast majority of changes don’t require a formal MOC, this is an opportunity where changes can be discussed and possibly elevated to a more detailed analysis that could lead to a formal MOC.

The “triggers” list includes changes to:

• Surface location, subsurface targets;

• Formation pressures/temperatures/fluid/gas composition;

• Shallow hazards, faulting;

• Formation lithologies;

• Well trajectory;

• Casing setting depths;

• Total vertical and measured depth of the well;

• Mud chemical composition;

• Packer setting depths, liner top depth;

• Cement chemical composition;

• Top of cement (TOC);

• Materials or material specifications;

• Work scope, e.g., additional coring, logging, sidetracking or other work;

• Expected well integrity, e.g., leaking safety valve, failing/dubious pressure tests, annulus pressures, etc);

• Well cost, timing; and

• Staff change-out.

During the execution phase, another list of triggers is used to consider MOC:

• Much higher/lower pore pressures, leak-off test values;

• Unexpected faults, loss zones;

• Other geological surprises (shallower formation tops, disappointing reservoir properties, absent formations);

• Troublesome formations;

• Excessive torque/drag;

• Excessive casing wear;

• Unexpected hydrocarbon-bearing zones, including unexpected shallow gas;

• Other than assumed rock fluid composition (CO2, H2S);

• Higher downhole temperatures;

• Lower TOC than planned;

• Shallower casing setting depth than planned;

• Other than expected seabed conditions;

• Staff change-outs – contractor competency issues; and

• Rig modifications.

Because risk assessment is the weakest part of the MOC process, Mr Roggeveen said, undertaking this review process as a team effort ensures sufficient expertise is involved.

The two lists presented are not exhaustive lists, he explained, but encompass “the difficult stuff” that Shell’s wells group is looking at.

Mr Roggeveen recalled an incident during a well abandonment using coiled tubing. Although the downhole temperature had been measured at 262°F, the cement recipe had been based on a temperature of 258°F. Because of this four-degree difference, the coiled tubing got stuck because of the cement’s sensitivity to temperature.

“It’s so easy in retrospect,” Mr Roggeveen said. “I think that’s what we’re all struggling with. It’s so easy in retrospect to say we didn’t do management of change properly.”

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