OTC at 50: Offshore Sector More Optimistic as Oil Prices Continue To Rise
The offshore oil and gas sector is beginning to recover 2 years after oil prices bottomed out, which has led to cautious optimism in the sector. At this year’s Offshore Technology Conference, held 30 April–3 May in Houston, that feeling was evident, although there is still a strong emphasis on cost containment and efficiency.
This year was the 50th OTC, which has become a bellwether for the health of the offshore industry. Panel sessions, individual talks, and technical sessions focused on a range of topics, including the current state of the industry, reducing costs, breakthrough technologies in a low-oil-price environment, and the growing use of data analytics and digital technologies. More than 61,300 attendees from more than 100 countries gathered at the annual conference.
Below are selected highlights from the conference.
The 50th edition of OTC kicked off with a distinguished panel representing operators and service companies evaluating the contributions of the past half century. And while the panel took a look back at the significant progress and innovation that has occurred since 1969, they also painted an optimistic view of the offshore sector’s future.
The opening ceremony featured remarks from Wafik Beydoun, chairman of the OTC Board of Directors, and panelists Patrick Pouyanné, chairman and CEO, Total; Ryan Lance, chairman and CEO, ConocoPhillips; Jeff Miller, president and CEO, Halliburton; Harry Brekelmans, project and technology director, Royal Dutch Shell; Clay Williams, chairman and CEO, National Oilwell Varco (NOV); and Solange da Silva Guedes, chief exploration and production officer, Petrobras.
Speakers emphasized the progress made in the safety of offshore operations as well as the technological innovation that has occurred since the first OTC was held in a small convention hall in Houston that attracted 2,800 attendees. More than 60,000 industry professionals attended last year’s conference.
After listing some of his company’s significant offshore developments over the years in Abu Dhabi, Africa, and the North Sea, Total’s Pouyanné expressed optimism about the offshore sector’s continued health, noting that many legacy discoveries are still producing or have led to new ones. “The past also affects the future,” he said. Oil price cycles and technical challenges will continue to be managed. “In our industry, anything is possible and nothing is impossible,” he added. “What makes me very confident for the future of offshore and the deepwater industry is its capacity to innovate.”
Lance, noting emergence of unconventional onshore output, said offshore projects in the future have to work at the lower end of the oil price boundary. Projects need improved design and efficiency as well as standardization. “Design one, and build many” should be the watchword going forward, he said. The use of data analytics, machine learning, and blockchain all have potential to make the offshore sector more efficient and economic, he added.
NOV’s Williams said he is enthusiastic about the future of offshore. Particularly because of recent advances in technology. “Just like the first OTC in 1969, OTC this year is brimming with energy, passion, and people to make the industry safer and more efficient,” he said. “The lesson of the past 50 years is that creative minds and clever tools can change the world.”
Miller, Brekelmans, and Silva Guedes also pointed out the advances made in safety and technical innovation over the past 5 decades and expressed confidence that the sector would continue to innovate and work together. Shell and Petrobras have won numerous OTC awards for offshore project achievements. “The future is about being more scrupulous,” Brekelmans said. “We will need much more innovation and collaboration.”
At What Price is Offshore Comfortable?
Crude oil prices may be at multiyear highs, but offshore operators and service companies remain determined to ensure profitability at $50/bbl.
That’s because offshore operators, particularly those focused on the Gulf of Mexico, have stiff competition from onshore unconventionals, where cheaper wells and shorter cycle times are more appealing to investors. Also fresh on operators’ minds is the market volatility that shelved many of their major projects that were supposed to deliver big output increases.
During a panel discussion, Susan Farrell, vice president and co-head of EnergyWide Perspectives at IHS Markit, noted that the recent oil price increases are not driven solely by market fundaments, and it has become evident that “geopolitical risk is back in the market.”
US foreign policy is hardening, with sanctions on Iran likely to be reimposed. Venezuela has reached its production “tipping point,” losing some 400,000 B/D in 2017 and 500,000 B/D in 2018, IHS Markit estimates. Saudi Arabia needs to keep prices higher to finance its foreign policy and economic transformation, which isn’t drawing as much excitement as originally expected.
IHS Markit modeled 54 offshore projects with cost structures in third-quarter 2014 and third-quarter 2017, finding breakeven costs were cut 45–50% during that time to less than $40/BOE. Half of the costs savings came from service sector deflation, “which is a cyclical cost change that will unwind at some point,” Farrell said. Structural costs have also resulted in “dramatic savings” that are more sustainable. For the first quarter of 2018, however, “the cost changes appear to have leveled out,” she said.
Operators and service companies have claimed that “structural changes are a much bigger portion of the pie” going forward, Farrell added. “The offshore industry is on a mission to change the way they look at projects in order to compete in that short-cycle business” of onshore unconventionals, Farrell said.
Leigh-Ann Russell, BP head of global procurement and supply chain management, said her company believes the recent upward trajectory in oil prices may be short-lived, so “we cannot afford to be complacent on costs in the industry,” she emphasized. BP’s offshore unit production costs are down 46% since 2013 and at their lowest level since 2006. “We believe that 75% of our savings today are sustainable,” she said.
Russell noted that the BP-operated Mad Dog Phase 2 project in the deepwater gulf was originally slated to cost $20 billion, but collaboration between the company and its partners to simplify and standardize the platform’s design helped cut the cost to $9 billion. She highlighted the International Association of Oil & Gas Producers’ managed joint industry project (JIP33) on standardization of procurement specifications for equipment that estimates the oil and gas industry could save 10–20% on equipment spending.
In its effort to deepen cross-industry collaboration on technological development, BP’s wells business is working with McLaren Automotive to use Formula 1 technology “on a suite of tools that address one of our company’s biggest challenges: fluid loss dynamics.”
Providing a service company’s perspective, Angela Durkin, Maersk Drilling senior vice president and chief operating officer, reiterated that even though the Brent crude price is in the mid-70s/bbl, “the effect of $40–50/bbl oil is still very real to us.” Operator behavior has changed, she said, but merely removing costs isn’t enough.
The industry remains wildly inefficient, with nonproductive time still a major issue for operators. Illustrating the industry’s wastefulness, Durkin cited a report indicating it takes 60 different contractors and 6,000 invoices to construct a single offshore well.
Navigating Brazil’s Potential
Brazil seemingly offers everything an offshore oil explorer could want—enormous conventional reservoirs, many of the biggest discoveries in recent years, and a big, growing domestic market for oil and gas.
But when it came time for ExxonMobil and BP executives to talk about their recent billion-dollar splurges in deepwater offshore blocks there, they focused on past struggles.
They acknowledged the potential was huge. “Petrobras created an enormous amount of value, finding more than $40-billion worth of oil and starting up one of the great energy plays” in the world, said Erik Oswald, vice president for Americas for ExxonMobil.
His talk at the conference described ExxonMobil’s experience in Brazil as a three-act play, and the company hopes the current act turns out better.
The first act was a portfolio of promising prospects that ended in disappointment, with eight dry holes. The second was a major offshore block that ExxonMobil “loved” until it was drilled.
“We failed to understand the basic genetics of the basin. And we made a fundamental exploration mistake by putting all our eggs in one basket in a frontier play,” Oswald said.
Adding to the complexities was the 2014 oil price crash, the staggering cost of putting ultradeep fields into production far from shore, and volatile, often unfavorable, government policies.
“Geology and potential do not create competitive reservoirs,” said Felipe Abelaez, BP’s regional president Latin America, where he alluded to past policies that put some of the most promising areas off limits and increased the costs faced by operators with high fees and extremely high shares of the spending going to Brazilian suppliers.
With oil prices up from the lows, the government has softened onerous regulations and offered a steady stream of prime blocks that can be operated by international oil companies, and partnerships with Petrobras are helping both sides
A series of offshore auctions offering more attractive properties at more reasonable terms have attracted aggressive bidding.
Among the bidders is ExxonMobil, whose winning bids allowed it to go “from one of the smallest IOCs [international oil company] to one of the largest with 2.1 million acres,” Oswald said. It is too early to say how this act in the exploration drama will play out, but as a major IOC it has to keep trying. “IOCs are always looking for new resources; we do not have the luxury to miss any major play,” Oswald said.
Success will require better exploration results plus continued moves by those now in power allowing them to make money on high-priced blocks.
Abelaez was hopeful the new government “will continue this dialogue which has been absolutely fundamental to attract investment to Brazil.”
An example of what he is talking about was the recent back and forth on Brazil’s local content rules. The percentage set in many past rounds required such a large share of the cost of development to be spent in the country that the operators were not likely to ever make money.
Practically speaking, that required building floating production storage and offloading vessels (FPSOs) in Brazilian yards where demand far outstripped the capacity, leading to long delays and punishing costs.
“There are risks to ramping up some around policy issues, especially on local content that could delay deployment on some of these FPSOs,” said Matt Blomerth, head of upstream research for Latin America at Wood Mackenzie.
The problem is likely to be solved with new rules reducing the requirement, which would allow the hulls to be produced in lower-cost Asian yards, reducing the pressure on Brazilian facilities. Also fines for not meeting the local content rules have been reduced, expanding the options for operators.
That tweak is an example of how the offshore business is looking brighter, but certainly not simpler. Offshore rounds there are based on the bidding rules within the area. Some are in the production-sharing zone, where the biggest discoveries were made and where the rules allow the highest cuts for the government. Others are in the concession zone where the rates are low but past wells not so great.
Guyana and Suriname Ponder Future
Recent years have seen a burst of activity in the Guyana-Suriname Basin, as several major offshore discoveries have sparked industry interest in a nascent area that could have a significant amount of untapped reserves off the northern shores of South America. A panel discussion examined the state of business development in the area, and representatives from owner and operator companies discussed the prospects of commercial opportunities that the basin may contain.
Bob Fryklund, chief upstream strategist at IHS Energy, said the Guyana and Surinam basin is a potentially booming area. The Stabroek block, located in the basin, has been a boon for operator ExxonMobil and co-owners Hess and CNOOC Nexen since 2015, with seven major discoveries (Liza, Liza Deep, Payara, Snoek, Turbot, Ranger, and Pacora) in the block uncovering almost 800 exploration wells and estimated recoverable oil reserves of around 3.2 billion bbl. Fryklund said these discoveries, together with ExxonMobil and Hess’s continued drilling in Stabroek, indicate the possibility of a long-term successful run for companies that invest in the block.
“Guyana is still there in the area of emerging producer, but they’re moving very quickly to first production,” Fryklund said.
Ranger, ExxonMobil’s sixth discovery in Guyana, was announced in early January. ExxonMobil said it encountered 230 ft of high-quality, oil-bearing carbonate reservoir, and the exploration well was drilled to 21,161 ft depth in 8,973 ft of water. Appraisal drilling at the Ranger discovery may take place later this year.
The Pacora-1 well, announced in late February, saw the discovery of approximately 65 ft of oil-bearing sandstone reservoir that is expected to bring Guyana production to more than 500,000 B/D.
Tim Chisholm, vice president of exploration appraisal and developments for Guyana-Suriname at Hess, could not overstate the importance of a joint venture (JV) in delivering these results. He called the relationship with ExxonMobil and CNOOC “the most mature partnership” the company has in the region.
“Finding the right partners who are aligned in energy about the opportunities and the risk, particularly with frontier oil development like in Guyana and Suriname, is essential to success,” Chisholm said. “The success that we have enjoyed so far in Guyana speaks to the importance of an aligned commercial partnership that enjoins the experience that all of us have in deep water around the world.”
Chisholm’s presentation during the panel session focused on the types of partnerships needed to succeed in the region. The JV in Stabroek is an example of a successful commercial partnership. Another type of partnership is with resource owners; Chisholm said that these relationships are important to help ensure the benefits of new production are felt across communities. A successful relationship with government is also needed for industry to be able to deploy major energy projects. This means that government should develop a regulatory framework that stimulates investments and encourages local content growth.
“The state must play its role in creating the right framework in which industry and government can work collaboratively,” Chisholm said. “When governments perform their role within industry, the results can be extraordinary, bringing enormous benefits in terms of investment, social and economic growth, and job creation.”
The government of Guyana has come under fire for its production-sharing contract (PSC) with ExxonMobil, renegotiated in 2016 from an earlier PSC the two sides signed in 1999. The country negotiated a 2% royalty rate (an increase from the 1% royalty Exxon agreed to in its 1999 contract), a $1-million license fee, and $300,000 in training for Guyanese workers in the deal, along with an $18-million signing bonus. These numbers are far below what local critics say the government should have received.
Guyana business minister Dominic Gaskin defended the contract in March, telling stakeholders that the country will receive a 50% split of oil profits, but critics have still argued that the contract should be renegotiated, especially with the spike in reserves from the recent discoveries and the near-$20/bbl increase in oil price since 2016.
Suriname is looking to get more involved in the offshore space after decades of steady onshore production. The onshore Canje formation has produced 109 million bbl of crude oil from Paleocene and Eocene reservoirs over the last 35 years, but offshore remains virtually under-explored: Staatsolie, the Suriname national oil company, reports that 26 exploration wells have been drilled over a 130,000-km area, and only 14 of those wells have been drilled beyond water depths of 20 m.
Tom Ketele, nearshore drilling project manager at Staatsolie, said the country has 90 million bbl of remaining onshore reserves, which should keep the company afloat for another 50 years. However, he said the company sees no major onshore prospects outside of its existing production, making the development of new resources even more important.
“If we want to survive, we have to bring in new reserves,” Ketele said. “We have to look offshore, so we’re really focusing offshore.”
OTC at 50: Offshore Sector More Optimistic as Oil Prices Continue To Rise
01 July 2018
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