The new business of deepwater

Audrey Leon

June 1, 2017

Deepwater is ready for a comeback. Operators at this year’s Offshore Technology Conference sang the praises of a new below US$50/bbl world. Audrey Leon reports.

Image of Mad Dog in 2013. Image from BP.

If one had to choose an official anthem to encapsulate this year’s Offshore Technology Conference (OTC), it would have to be the Journey classic, “Don’t Stop Believin.”

Operators were on hand to sing the gospel of a new competitive deepwater business at US$40/bbl. BP even held a panel discussion to show how it lowered the costs associated with its Mad Dog 2 development in order to achieve a final investment decision (FID).

“The economics for deepwater investments make as much sense today as they did back in 2001 when BP sanctioned Thunder Horse,” said Richard Morrison, Gulf of Mexico regional president, BP.

Making changes

Morrison discussed how BP set out to fundamentally change to the business to make money during these “lower for longer” times.

“We refocused and paused our exploration drilling program,” he said. “We terminated a long-term rig contract, allowed two others expire, and warm-stacked another. We reset our approach to logistics. We nearly halved our fleet of vessels and helicopters, and nearly halved our Gulf of Mexico workforce since 2014, primarily onshore.

“We worked closely with our third-party suppliers to capture deflation in the market and other efficiencies,” he added. “We continued investment to boost our operating efficiencies of our production wells and our facilities. We tripled investment in well work to generate cash in the short-term. We listened to our teams and contractors and reduced the BP requirements when we were bidding for new equipment and services.”

Morrison said BP is more profitable now than the old days of high oil prices.

“Today, our cash margins in the Gulf of Mexico are better than they were when the price of oil was $80/bbl,” he said. “Because costs have come down and continue to decrease. Execution and operational efficiencies have improved substantially.”

New breakthroughs

BP’s Richard Morrison speaks at OTC 2017. Photo from BP.

Just days before OTC began, BP announced a breakthrough in seismic imaging that could help identify more than 200 MMbbl of additional resources at BP’s Atlantis field in the deepwater Gulf of Mexico, and aid drilling accuracy, not just in the Gulf of Mexico, but in other regions as well.

The technology can enhance the clarity of images collected during seismic surveys, particularly areas below complex salt structures, which were previously obscured or distorted.

Morrison told the OTC crowd that there’s much more to be done. “A much-needed step change is already underway related to the cost of exploring for new resources,” he said. “Through a combination of fit-for-purpose design, execution efficiency, and some of the reduced rig rates we have seen recently, we’re are seeing some really good things.

“For example, the average cost to drill an exploration well in the Gulf of Mexico rose to $200 million this decade. We have now seen multiple wells drilled in this industry under $100 million and as low as $50 million.

“This is transformational for the exploration and production business.”

Mad Dog Phase 2

BP’s Cindy Yeilding holding up a chunk of salt while discussing the supermajor’s new approach to seismic imaging. Photo: OTC/Rodney White.

Mad Dog Phase 2 has been a very long journey for supermajor BP, but the development has potential to be a tremendous success story. The project, which reached FID in December 2016, is now slated to cost $9 billion – but, at one point was expected to cost approximately $20 billion.

“From an exploration standpoint, we went through 15 very emotional years opening a new play; opening a new play is never easy,” said Cindy Yeilding, senior vice president, BP America. “It requires perseverance, creativity, but also good science married to very good business insights. The technology is also critical.”

Discovered in 1998, the Mad Dog field, which has Miocene sandstone reservoirs, is considered one of BP’s largest discoveries in the deepwater Gulf of Mexico. In production since 2005, the current Mad Dog truss spar facility – moored in Green Canyon 782, 100mi south of Grand Isle, Louisiana, in 4500ft of water – can produce 80,000 bo/d and 60 MMcf/d of gas. BP operates Mad Dog along with partners BHP Billiton and Chevron.

According to BP’s fact sheet on the field, Mad Dog is thought to contain approximately 4 billion boe. But, Doris Reiter, vice president, performance management, BP, told the OTC crowd that better imaging has shown that there could be nearly

5 billion boe at the field, giving BP plenty of reason to stay committed to bringing phase 2 into development.

Salty dog

Concept image of the Mad Dog 2 platform. Photo from BP.

Technology has been a huge part of unlocking the Gulf of Mexico’s vast deepwater resources. Yeilding said that in the 1980s when big discoveries like Mars and Ursa were found, the industry rushed into the area and drilled seven dry holes in a row.

“The industry went after this play and we got it dead wrong,” she told OTC. “It caused a lot of contemplation and humility, but it also caused people to call it the ‘Dead Sea.’ But, BP gave us a second shot instead of firing us.”

Yeilding says BP went back to the basics of good science and looked for the structural highs. “Petroleum high grades up into anticlines. Our big shift was to look for structures,” she said, adding: “There are many layers of salt canopy, and it really complicates the imagery. We had to come to grips with that.

“We are no longer running from the salt, we are running to it,” she told the crowd, later holding up a large block of salt for the crowd to demonstrate how hard it is to see through. “We had to drill the original Mad Dog structure on a lot of faith.” She further added that good geological principles, despite the poor imaging, indicated the potential in the area. Yeilding said from that 1998 Mad Dog discovery, the Atlantis and Thunder Horse discoveries soon followed in 1998 and 1998, respectively.

Yeilding discussed early existing seismic imaging and how the industry and BP needed to work with what they had to ensure that appraisal wells were positioned in the right spot. But, improvements still needed to be made.

“We knew we were in this for the long haul with the number of sub-salt discoveries made. We worked with our technology team and with the geophysical industry to develop a new acquisition type called wide-azimuth towed-streamer (WATS), which we field trialed in 2005-2006 at Mad Dog. This lead to the beginning of significant imaging breakthroughs.”

Reiter detailed other challenges that Mad Dog endured along the way, such as production being interrupted by Hurricane Ike in 2008, which blew the rig off the platform – this put the drilling program on hold from 2008-2013, added Aleida Rios, vice president, Gulf of Mexico Production Operations, BP. In 2011, the Mad Dog facility was shut-in for rig replacement, prep, and deck repairs, Rios said. It was a 16-month outage and the challenging part was the lift needed to replace the rig, but Rios added that the facility resumed production in 2012, and the rig restarted in 2013.

Reiter noted that the WATS gave the BP team a lot of insight that enabled the formation of its appraisal drilling plan on the southwest and west side of the field. She called Mad Dog “Big Dog” – a monster that was meant to have 33 wells. The current view, she said, is 32, not 33 wells.

“The $20 billion [price tag] clearly wasn’t the answer,” Reiter said. “The team had to go back to the drawing board. We took some time out to refocus. The demand became 90% of the resource estimate for 60% of the cost. And I can tell you we did a lot better than that.”

Reiter said that taking that pause in 2013 allowed BP to leverage new technologies. And the plan is to leverage LoSal technology on Mad Dog, she said.

Reiter said seismic will continue to play a big role in Mad Dog’s total development, noting that BP will acquire an ocean bottom node survey later this year. “Who knows, we might find another little field like Atlantis,” Reiter concluded.

Independents still believe

“Shale cannot meet global demand,” said Roger Jenkins, CEO, Murphy Oil, at an OTC panel entitled, “Deepwater still works!” He continued: “Shale cannot compete. Now is the time for deepwater to comeback.”

Jenkins shared that his company Murphy Oil plans to ramp up its global exploration. “Now is a good time to do that because there’s less competition, lower costs, better terms,” he said.

For some independents, offshore is integral to cash flow for other parts of the business. “The offshore business primarily provides cash for onshore to grow,” Jenkins said. Anadarko announced a similar strategy back when the Houston-based firm purchased the offshore assets of Freeport-McMoRan for $2 billion last year, which at the time, CEO Al Walker said would allow the company not only to grow in the Gulf of Mexico, but to add rigs to its onshore shale acreage.

Jenkins added that Murphy Oil has a competitive advantage by being in offshore with half of its production coming from there. However, both Jenkins and BP’s Morrison noted (during his own session) that there have been notable companies that have left deepwater, such as ConocoPhillips, Marathon, and the aforementioned Freeport-McMoRan – which had come into the Gulf of Mexico with much gusto after a combined $9 billion purchase of Plains Exploration and Production and McMoRan exploration in 2012. But, the times (and priorities) have changed for some. Others, like BP and Murphy, have dug their collective heels deeper into deepwater and offshore.

For example, Jenkins said Murphy Oil was excited to explore Mexico’s frontier deepwater Gulf of Mexico..

In December, Murphy Oil won Block 5 (operator, 30%), in Mexico’s deepwater Salina basin, in consortium with Ophir (23.33%), PC Carigali (a subsidiary of Malaysia’s Petronas - 23.34%), and Sierra Offshore Exploration (23.33%).

The block covers 2573sq km in 848m water depth, with an estimated 467 MMboe. Jenkins called the basin in which the block is located “prolific.”

Pemex ponders partnerships
by Melissa Sustaita

Pemex CEO José Antonio González Anaya speaks at OTC about the next five years following Mexico’s historic energy reform. Photo: OTC/Todd Buchanan.

Mexico’s state-owned oil company Pemex has come a long way since the energy reform was enacted, however, there’s still a lot of work to do, the firm’s CEO José Antonio González Anaya told an audience at the Offshore Technology Conference.

Pemex has stabilized its finances, and has targeted an average production 1.95 MMb/d for this year. González Anaya believes that Pemex can return to overall profitability by 2020.

Moving forward, González Anaya said that Pemex will take advantage of the energy reform and is planning an aggressive farm-out strategy, and creating partnerships. Pemex’s first farm-out, the Trion deepwater field with new partner BHP Billiton, was announced in December 2016.

“We are trying to accelerate [farm-outs] in many, many ways,” González Anaya said. “The signal that we want to send is that we are actively looking for partners in all of the areas.”

“The way I see it is that my successor, if he doesn’t believe in these things [partnerships, farm-outs], he better have $11 billion to develop one of these fields, because otherwise, he’s not going to be able to do it,” he said.

“We are investing a lot on exploration this year. Our target for repositioning reserves for this year is almost 1 MMbbl,” he said. “In regards to what we feel comfortable with, the answer is simple: the more the better. The more we find, and as long as it fits within our finances, we will try to increase our reserves.”

Increasing production is one of Pemex’s top priorities. And, while production from Mexico’s legendary Cantarell field has fallen steeply from 2.1MMb/d 12 years ago to just 200,000 b/d today, González Anaya noted that non-Cantarell production has increased 54% during that same period.

“The issue is that nature was generous with Mexico. But, it wasn’t eternal. It came with one Cantarell field,” he said. “We invested $50 billion pesos ($2.71 billion) in 2000; and we now have to invest $300 billion pesos ($16.2 billion) to get the oil out.”