Add Energy CEO Ole Rygg - who worked closely on the Deepwater Horizon tragedy in the Gulf of Mexico, the Montara oil and gas spill in the Timor Sea and the more recent Elgin North Sea gas leak - said those events taught the industry some important lessons.

PTTEP's 2009 Montara incident in the Timor Sea happened while drilling development wells, while BP's 2010 Deepwater Horizon tragedy killed 11 people and caused a devastating environmental incident happened during exploration drilling in the Gulf of Mexico.

Speaking to Energy News during last month's visit to his Norwegian firm's Australian drilling and well engineering headquarters in Perth, Rygg said the industry as a whole has "learned quite a lot" from Deepwater Horizon.

"The learning from the Macondo incident was you had a lot of procedures in place but it boils down to the understanding of the people who actually run the operations, on the risks involved and how to deal with those risks," Rygg, who became Add's CEO in August having been with the firm since its 2008 inception, said.

"The plans and procedures and everything, as a large company, were in place [at BP]."

What really counts is understanding and actually following those procedures, and understanding the consequences.

"What changed after Macondo was that the risk and potential consequences of such an incident were not something you dealt with at the lower level in the companies [pre-Deepwater Horizon]," Rygg said.

"It went all the way to the boardrooms, which is why with large operations now they actually take this as part of the equation in looking at where they want to drill and the risks involved."

Dermot O'Keeffe, Add Energy's chief operating officer and leader of the group's Australian operations, told Energy News that preventing risk is more than just about designing the well properly with all the appropriate barriers in place - as critical as that is.

Just as important - but something which was perhaps missing or at least not widespread before Deepwater Horizon - was "management of change", where something happens while you're drilling a well and it changes the well program.

"You don't just keep going without reassessing the risks, because there may be new risks that have come into the project," O'Keeffe said.

"Even though management of change was around before Macondo, I don't think people took it that seriously, but now they do, so when something does change everyone sits down, talks about it and documents it so everyone knows that's what's happened."

These warnings are critical to consider as BP prepares for its drilling program in the Ceduna Sub-Basin that starts next year.

"It's all very well saying it's 35 days before you can deal with an incident, but could be a lot longer, because 35 days is just getting a relief well rig there, perhaps from the North West Shelf, you've then got to drill it or get a capping stack and deploy it," O'Keeffe said.

"For example, drilling a relief well on Macondo took three months, and Montara about 87 days."

Capping stack capers

BP's application to the National Offshore Petroleum Safety and Environmental Management Authority for exploration drilling noted that the integrated Subsea Well Intervention Services, Oil Spill Response Limited's dedicated subsea division, has access to the world's four capping stacks to shut-in an uncontrolled subsea well and two hardware kits to clear debris and apply dispersant to the well head.

That would create safer surface working conditions and enhancing bio-degradation.

"The SWIS equipment is suitable for the majority of known subsea wells," BP said.

"It can be deployed in water depths up to 3050m and control flow pressures up to 15 kpsi."

The four capping stack systems are strategically located around the world - Norway, Brazil, South Africa and Singapore - and are maintained ready for immediate mobilisation anywhere in the world and for onward transportation by sea and/or air in the event of an incident.

"For a response in Australia, the primary 10 kpsi capping stack system located at the Singapore facility and primary 15 kpsi capping stack system located at the Norway facility would be mobilised" for any incident in its Ceduna Sub-Basin program, BP said.

BP also has access to the Subsea First Response Toolkit via the Australian Marine Oil Spill Centre, which is stored at Fremantle in Western Australia, and is maintained by Oceaneering.

"This equipment and tooling is what is required initially to respond to a subsea blowout to clear debris, survey the site and conduct preparations required in order to run the capping stack," BP said.

With an estimated 35 days' wait to get the capping stack on site if something happens and install it, BP needs - and has - a back-up plan, which will be to drill a relief well if, as Rygg says, the capping stack either doesn't work or it's not possible to use it - "then the relief well is your only second chance".

A second rig would need to be mobilised to South Australia, most likely from the North West Shelf.

The operators have a relationship where if someone's in trouble operators they will have a rig available, but it might already be in use, so they need to make their own wells safe before they can give the rig to BP.

Make no mistake, however, BP has thought about all this, the time it takes to drill a relief well, and everything in between.

But with Shell's recent exploration failure in the Arctic (though it blamed its decision to halt any further exploration drilling on "unstable regulations"), amid ongoing environmental safety concerns, there are some who could well be justified in pondering whether industry should be drilling along the southern margin at all.

Yet this poses industry with its own conundrum.

"The problem is oil and gas isn't found everywhere on the planet, so oil companies will go where they think the highest chance of success is," O'Keeffe said.

The other consideration for the wider industry in planning operations like the Great Australian Bight venture is the pure necessity of it - and not just to the company's project pipeline for potential future revenue, but for the world itself.

"You need the discoveries as they take 10 years before they start producing, particularly in these very remote locations, which have logistics issues," Rygg said.

"You need to start looking at them now, because even with the oil price down we know the demand for oil will not stop. Soon or later you need to fill that gap."

In relation to acceptable strategies to regain control of a well, the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011 (Wells Regulations) require that BP must have a well operations management plan accepted by NOPSEMA to conduct drilling activity.

"NOPSEMA does not prescribe specific control measures or management systems of which the duty holder [BP] must implement in order to reduce impacts and risks," a spokesperson from the regulator told Energy News.

"Where a duty holder has submitted a safety case, environment plan or WOMP that does not meet the criteria for acceptance under the relevant regulations, then NOPSEMA will identify particular issues and provide flexibility to the duty holder in determining how those issues are best addressed."

The regulations, meanwhile, have specific requirements with respect to arrangements to regain control of a well.

NOPSEMA said that, at this point in time, BP has not submitted a WOMP for assessment for its proposed drilling program in the Great Australia Bight and as a result the body was unable to provide further comment.