Upstream Digitalization Could Save $75 Billion Annually

Digitalization in upstream: show me the money, a new report from global natural resources consultancy Wood Mackenzie indicates the upstream sector could see annual cost savings of $75 billion annually from digitalization by 2023.

The biggest benefit from digitalization would be the ability to uncover new resources, says Greig Aitken, principal analyst in Wood Mackenzie’s corporate analysis team. This may be from better processing of seismic data or gaining new understanding of well logs and chemical analysis.

While the ultimate goal is for machine learning and artificial intelligence to process data and spot hydrocarbon-bearing reservoirs with an almost perfect success rate, secondary benefits include making better, faster decisions on where and how to drill or whether to drill at all.

Aitken said: “By accessing effectively unlimited computing power via the cloud, Cairn Energy, which began its digital transformation in 2015, now has the ability to shave months off its 3D seismic processing. For an exploration-focused company such as Cairn, the improved speed at which it can make drill-or-drop decisions is transformational.”

since 2014, upstream operators have spent, on average, $50 billion annually on exploration. Using the 2014-2017 average activity and spend levels as the base, Wood Mackenzie’s analysis shows that over the next five years, potential cost savings of $5 billion-$7 billion (10-15 percent) per year in exploration could be achievable.

Similar savings could be achieved in drilling, completion and field development. For example, Equinor believes its “field of the future” concept will reduce offshore facility capex by around 30 percent.

Mhairidh Evans, principal analyst, upstream supply chain, said: “Such a dramatic reduction could have a top-line impact, enabling the monetization of currently sub-commercial reserves. Equinor sees most of the headline-grabbing cost cuts being enabled by automated platforms, such as Oseberg H, the first unmanned platform in the Norwegian sector.”

She added: “Worker-free environments mean smaller topsides with no accommodation modules and no supply vessels. Of course, this can only be achieved if every process can be automated or managed remotely – a point that underscores the potentially transformational impact of the digital twin.”

A digital twin is a virtual copy of a physical asset – replicating the dynamics of each valve, pipe and cable, as well as the structural integrity of the facilities. This allows simulation of outcomes on an unprecedented scale. BP is one of a number of oil and gas companies that have already implemented this technology, with the rollout of its Apex program.

“Even without automated platforms, digitalization will lead to cost savings in the pre-FEED and FEED stages of traditional developments,” Evans said. “Automated modeling can generate economic outcomes for a field under a range of development concepts and a continuum of variables. This isn’t new. But big data analytics infuses these models with real-world experience, allowing data-driven decisions to be made faster, with more confidence.”

The upstream industry’s track record in project execution has historically been a source of doubt for investors. Wood Mackenzie’s research shows that over the past decade, the average project was delivered six months late, with costs up 14 percent versus the forecast at final investment decision (FID).

The conventional industry’s opex spend is over $340 billion each year, and while new developments stand to benefit most from digitalization, it can also be implemented at existing fields, with remarkable results, says Wood Mackenzi. The analysis below is based on a five percent reduction in annual field operating costs, and a one percent increase in annual field production.

For many assets, this is already a conservative assumption. For example, Total expects an opex reduction of almost 10 percent at the under-development Culzean field in the U.K. North Sea through the application of a digital package.

Production gains through increased uptime is a potentially more valuable gain. For example, a one percent increase from each conventional producing asset on stream globally in 2018 would result in an additional 1.3 million barrels of oil equivalent per day in the market – this is roughly equivalent to the total output from Libya.

Aitken says that large shocks to the system precipitate action, and automation efforts gathered speed in the last three years following the oil price crash and subsequent recovery. BP claims to have added 30,000 barrels of production last year due to its use of the APEX system and cites an example in the Gulf of Mexico of system optimization being reduced from 24-30 hours to just 20 minutes.

While the majors may have more tools at their disposal, the transformational benefits digitalization offers are available to all, even the smallest operators, says Wood Mackenzie.


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