Still in the game

Is deepwater still relevant? Shell thinks so, from optimizing its existing production to new projects. But when will the tap be turned? Elaine Maslin reports.

Shell’s Olympus platform. Photo from Shell's Flickr.

For many years, not least those leading up to 2014, deepwater exploration and production had gained a reputation for being at the expensive end of the upstream industry.

Unsurprisingly, this meant deepwater was hit hard by the downturn, as it was unable to anything like match the costs achieved by the likes of onshore unconventionals.

But, three years in to lower oil prices and the work to reduce costs and simplify projects, is paying off. Floating production vessel supplier and operator SBM Offshore noted in August that: “Break-even prices of deepwater projects have substantially improved as result of cost deflation, more fit-for-purpose scope and leaner concept designs. In particular, deepwater projects in areas with world class reservoirs have gained competitiveness against other oil and gas investment options.”

Operators – supported by new offerings in the contractor and supply chain landscape – are starting to find ways to move deepwater forward, says analyst firm Wood Mackenzie. Investment in deepwater Egypt and Senegal by BP and in deepwater Brazil by Statoil this year, shows there’s still appetite to be in deepwater plays.

According to Wood Mackenzie, 83 subsea trees were ordered in FY 2016. In 1H 2017 alone, 81 awards were made. “This result is encouraging as only part the full potential of the E&P’s and supply chain’s efforts have been realized. As time goes on and these efforts mature and are more widely applied, the potential for the subsea and deepwater markets is exciting,” says Caitlin Shaw, research director, Wood Mackenzie.

One of the majors with a significant stake in deepwater is Shell. Shell’s deepwater production is expected to increase to more than 900,000 boe/d by 2020 from already discovered, established reservoirs.

“Deepwater is a vital part of that oil and gas mix. Currently, deepwater is 7% of all conventional oil produced globally,” says Robert Patterson, executive vice president, Engineering, Shell. It is forecast that by 2040, it will be almost 11% of conventional production, at about 11 MMb/d. Deepwater is important.”

Patterson. Photo from UTC Bergen.

Patterson, who was speaking at the Underwater Technology Conference in Bergen, in June, says that, for Shell, it’s also part of the company’s history, being almost a decade since the deepwater Cognac facility was installed in the US Gulf of Mexico. “In the last few years alone, we have had eight new significant [deepwater] start-ups,” he says, including Gumusut-Kakap and Malikai (Malaysia), Bonga Northwest and Bonga Main Phase 3 (Nigeria), BC10 Phase 3 (Brazil), Cardamom, Mars B, Stones (US Gulf of Mexico), and others. Two projects are under construction, Coulomb Phase 2 and Appomattox, both in the US Gulf of Mexico. “In 2016, with those, and our combination with BG Group, we increased production from deepwater by 50% compared to 2015.”

Moving deepwater forward has meant a lot a hard work, however. “In moving forward with deepwater, we all face a challenge,” Patterson says. “Over 10-15-20 years, performance in our industry eroded in a dramatic way. In 2014, it took four times as much capital to produce a barrel of oil as it did in 2004.” Productivity in oil construction fell -22%, compared to a 41% increase in the rest of the [US] economy, he said.

One of Shell’s initiatives to address this and reduce costs has been to streamline standards and requirements, by building a comprehensive catalogue and then only selecting what is appropriate for a specific use. This has led to a substantial reduction in requirements. For example, in many equipment categories the reduction is as much as 80-90%, “changing the dynamic. We have a small enough set of requirements so we can talk about what risks there are to our suppliers,” Patterson says. “We have completed the first step of that journey with pilot projects.”

Competitive scoping has also brought “major benefits,” he says. Patterson says that during the execution of Stones, Shell had the opportunity to rethink the whole design and took US$1 billion capex savings – by minimizing use of materials and rethinking drilling efficiency.

Final investment decision (FID) was taken on Appomattox in 2015, after an initial 20% cost reduction. An additional 20% cost reduction since FID was achieved – maintaining a strong focus on safety and quality. Cost efficiencies are the results of efficient execution, significant well reductions and lower market costs, Patterson says.

Ormen Lange has been lined up to have subsea compression added to extend field life and boost recovery rates. Shell has sought a minimal safe scope and what is absolutely needed to reduce costs on a future project to make it economic. Cost have been reduced by more than 50% (since 2014). On Kaikias, estimated to contain more than 100 MMboe recoverable resources, oil and gas will be produced from four wells with flow back (single flowline) to the Ursa tension leg platform (TLP) in the US Gulf of Mexico, given FID earlier this year, a $40/bbl breakeven was achieved, “by stepping back to see what was really wanted to achieve, and how to use what Shell already had in place,” he says.

“We also looked hard at flow assurance requirements,” he adds. “Could we use a single pipeline and use an existing umbilical? We used standard subsea kit on Cardamom, and as a result brought costs down 50%.”

Engineering tools are also coming into play. For example, Shell has run Project Vantage, an integrated engineering environment, with 3D, 4D and 5D capability, to reduce working at height and in confined spaces by about a half, Patterson says.

Shell has also sought to make better use of already available technology from third parties, typically small companies with niche solutions. Part of this is about being able to evaluate them more efficiently. “We’ve gone from evaluating 30 a year, taking 9-10 months each to realize, to a thousand a year and making decisions in two months,” he says.

Patterson’s list continues, from using foam in wells, such as on the Ram Powell TLP, to help produce from wells that had been shut-in due to severe slugging, to using hot bolt clamping, and Humidor, a coating which can be applied and cure in wet conditions, which was applied on the Ursa facility.

It’s not just operators working in a silo to make these projects work, however. The supply chain landscape reacted quickly to the new norm, Shaw says. “We have seen most of the major players team up with complimentary companies to leverage their strengths and offer enhanced solutions – OneSubsea, TechnipFMC, GE-Baker Hughes. While each of these companies has its own value proposition, common themes exist around realizing cost savings via earlier engagement in the project life-cycle.”

The hope is that all this work will increase FIDs. There are positive signs but no one is shouting from the rooftops. SBM CEO Bruno Chabas noted: “In today’s oil price environment, characterized by continued low prices, deepwater field developments need to build on the competitiveness gained.”

“While FIDs are on the increase, clients remain cautious and selective,” SBM says. “As a result, the offshore services industry is gradually recovering, but with a structurally lower activity level when compared to the market over the past decade.”