HOUSTON—Only 14% of the world’s estimated deep offshore resources—about 350 billion barrels—are produced today, meaning that 86% is still to be developed or discovered, according to Total’s Khalid Mateen.

But getting to these resources and being able to produce both hydrocarbons and profits means overcoming an array of challenges, some of which were not present a decade ago.

The fields that are being discovered today are smaller than the elephant fields that packed hundreds of millions of barrels of oil nearly 10 years ago, the vice president of engineering and technology for Total told a crowd gathered Nov. 19 for Teledyne’s Technology Focus Day.

Plus, today’s discoveries are more remote, meaning they are more difficult to develop as standalones, he continued. Operators nowadays are developing fields as tiebacks, which he believes could grow in length to 75-100 km long and push costs higher.

In some areas, the quality of oil is more complex, he continued, which adds to flow assurance management costs. “These costs are likely to go higher as we go to longer tiebacks and deeper water depths,” Mateen said.

Add to this commodity price conditions that test the economic viability of already high-cost, high-risk deep offshore projects. Capex and opex costs for such projects have nearly doubled in the last 10 years, bringing down the probability of deepwater projects.

“A lot of the cost increases came from unnecessary customization or complexity of the facility, variations in specifications and prevented any kind of standardization in the industrialization of the equipment,” Mateen said. “All of that added up. The question now is how to reduce those costs.”

Commodity price volatility has sparked a sense of urgency and soul-searching among companies seeking change.

“There is a lot of collaboration going on and simplifying complexity,” he said. “Technology should not make things more complex.”

Ways to lower costs included standardization such as standardization of modules and supply base, simplifying specifications and going with good enough designs.

But “we need to do more than that,” he said. “We are no longer developing the same kind of resources we did 10 years ago. … Even if we do simplify, we’ll still be struggling with the profitability of projects. We firmly believe that technology [is] … what is going to give us economic profitability to develop deep offshore resources.”

So which type of technologies can make the greatest impact in lowering costs?

Composite materials, which can be used in risers and intervention lines, can stand up to harsh subsea environments and is seen by some as a viable, light-weight alternative to steel.

“Composites have a lot of potential when it comes to reducing the pipeline lay costs, but composites are cost prohibitive,” Mateen said. “There is no reason why the companies should not collaborate there” to get costs down.

DNV GL is doing just that. In September, the organization launched two joint industry projects (JIP) to study affordable composite components for the subsea sector and qualify technology for more efficient linepipe production processes. The JIPs could result in a combined saving of £6.75 million (US$10.3 million.)

The DNV GL Affordable Composites JIP aims to lower the cost of qualifying composite components for subsea use by replacing large-scale tests with certification by simulation, according to DNV GL’s website. The second JIP—New Material Solutions for Flowlines—targets use of high frequency welded/submerged arc welded (HFW/SAW) pipes.

“Though there is a considerable amount of research and full-scale reeling trials for the use of HFW or SAW linepipe, as well as a good track record in terms of executed projects, a joint systematic approach to optimize the design of these linepipe for reeling is lacking,” said Leif Collberg, vice president of pipeline technology, for DNV GL Oil & Gas. “There is much to be gained through this project. We estimate that it could deliver a 20-30% reduction in pipeline material cost, corresponding to £4—5.5 million (US$6-$8.4 million) saving potential for a 30 km flowline.”

There also is room for improvement in flow assurance.

Marteen believes the industry should expand use of LDHIs, or low dosage hydrate inhibitors. The chemical inhibitors can help mitigate hydrate formation concerns, including the possibility of plugged flow lines. “We cannot afford injecting large volumes of methanol to stay away from hydrates,” Marteen said. “We need to understand it better.”

Other areas included use of subsea processing systems and industrywide collaboration.

Staying competitive and ensuring profitability to handle ever-changing market conditions requires constant innovation, Mateen said.

“One major challenge is the way the cost has gone up. Even at $100 a barrel costs were unsustainable,” Mateen said. “Technology and constant innovation is what is going to rescue us.”

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