HOUSTON—Can deepwater oil and gas survive in a $50 per barrel (bbl) environment?

That’s a question operators such as BP Plc (NYSE: BP) are challenged with, according to Ryan Malone, projects general manager for BP’s Gulf of Mexico (GoM) operations. The rise and fall of commodity prices, which reached the $50/bbl mark in recent months only to slip to about $45/bbl amid the world’s bounty of oil, have made some skittish on deepwater profitability as the lower-for-longer price environment prompts players to change the paradigm.

When oil prices began to fall about two years ago, “We took the stance that we were going to make all of our businesses viable and commercial at $50 per barrel,” Malone said Nov. 15 while giving the state of the industry keynote during Teledyne’s Technology Focus Day.

The task required a shift in strategy, but the company’s confidence was boosted by its profit-turning track record in places such as the GoM and offshore Angola and Egypt, where subsea and deepwater technologies are present, he added.

But like its peers combating the profit-gobbling force—also known as the oversupply-driven downturn—has been challenging. BP’s underlying replacement cost profit, or net income, dropped to $933 million during third-quarter 2016 compared with $1.8 billion a year earlier. However, the supermajor continued to cut costs, with capex expected to fall to about $16 billion in 2016; guidance shared earlier this year was $1 billion to $2 billion higher.

The challenge, Malone said, is to not only get back to being competitive at $50/bbl oil, but also to “test the boundaries by targeting $25/bbl breakeven prices at some deepwater developments—“irrespective of the revenue stream and prices.”

Yet there are more obstacles today. After pointing out smaller pool size, lower exploration success rates, difficult political environments in some parts of the world and harder-to-find rock, Malone encouraged the industry to return to the basics and aim to be cheaper, faster and more reliable. He’s convinced that BP has the right structure to return profits to desired levels.

BP focuses on fast-cycle projects and targets multiple fields and reservoirs. The company has a bias toward subsea infrastructure, and it aims for smaller and simpler developments. Also key to its strategy is following proven designs and standard components, leveraging supply-led solutions, focusing on select new technology and utilizing cross-functional expertise, according to his presentation.

Favoring Subsea

Malone highlighted the BP-operated Na Kika K3 project in the U.S. GoM as an example. The development, which included subsea infrastructure tied back to the existing Na Kika Platform, went from discovery to first oil in 11 months. The company used what Malone called a “reverse engineering methodology” to do the work that would have taken 24 to 36 months at a 30% cost savings.

“We utilized a lot of inventory. We liquidated a lot that we had built up around the region. We also looked within the industry for what was available. … It wasn’t going through 10,000-page specifications and figuring out how to build the biggest, baddest, most gold-plated piece of component or kit on the seafloor,” Malone continued. “It was taking what you had, realizing the environment that you were operating in and engineering to it.”

The single-well tieback development, which started up Oct. 3, has a flexible flowline, umbilical and ancillary controls, a subsea tree, flow assurance module and metering module.

Keys to success for a larger infield expansion project—an unnamed three- to four-well tieback development with two static flowlines, a subsea chemical metering system and three subsea trees and production manifolds in a complex brownfield environment—included true front-end loading and advanced computer modeling and simulation. The project is within days or weeks of startup and is expected to come in under cost by 30%.

“These are some of the most prolific wells that we have in our entire portfolio. To be able to bring this on at a time when we need cash, when the industry wants to see that cash turned back into reinvestment, this is a big achievement for us.”

BP is also progressing with plans for its Mad Dog Phase 2 project in the U.S. GoM, having cut costs for the planned development from $20 billion to less than $10 billion. The company has also cut about three years off the previously forecast first oil, “giving increased confidence that we’re on the right track,” Malone said.

“We’re feeling very confident about not only doing the small subsea tiebacks, bigger subsea tiebacks, but also new host facilities that may be more competitive,” he added.

The BP Way

BP’s approach in today’s lower commodity price environment mirrors that of many other operators, Malone said. “We’ve got to be cheaper, faster and more reliable across the functional disciplines we deploy to execute our projects.”

For better efficiency, for example, BP’s global wells organization is managing a global fleet, looking for the best rates, while its global projects team, specifically deepwater, is measuring efficiency from a technical development cost- and subsea cost-per-well perspective.

“What we’re finding is subsea cost-per-well is largely indicative of your overall facility concept or structure,” Malone said. Costs concern more than dollars shelled out for equipment. It’s about how the field is being developed and the completion plan, he said.

Execution is essential when “building quality through choice” across its portfolio, and opportunities are plentiful and not limited to deepwater, according to Malone.

BP is working to build a global subsea execution organization, which will work with EPCs to consistently develop projects. The company is also looking at equipment costs and delivery schedules differently for subsea equipment: ditching the old way of fully built-out BP specifications for what the company could live with—what BP calls the “supplier-led solution.”

As Malone explained, that’s essentially modifying the core offering from the supplier to meet the specific needs of a particular project.

“We’ve almost trained the supply chain to wait for the next step on what the operator wants: interpretation of codes, our own bespoke wellhead interfaces having to do with trees, the number of pressure and temperature sensors,” he added, but noted a gap still exists.

Overcoming the gap takes those in the supply chain working closer with operators to understand needs and challenges, Lance continued. “We think the gap can be addressed at a lower cost and at a better schedule than what we’re getting right now.”

It’ll take collaboration and the conversation is ongoing, he added.

Velda Addison can be reached at vaddison@hartenergy.com.

Offshore