Big Data adds up to big savings for upstream players

Although the oil and gas industry is a leader in technological innovation, the exploration and production (E&P) sector has been a laggard in its adoption of Big Data. Embracing advances in analytics, machine learning and artificial intelligence (AI) could pay big dividends for the industry, according to market analyst Wood Mackenzie, which estimates that the upstream sector could see annual cost savings of $75bn from digitalisation by 2023. These savings can be realised at every stage of the upstream lifecycle, it says.

Greig Aitken, Principal Analyst in Wood Mackenzie’s Corporate Analysis Team, says: ‘Digitalisation offers multiple prizes in exploration. The biggest would be to uncover new resources. This may be from better processing of seismic, or new understanding of well logs and chemical analysis. Not only would this offer E&P companies the bonanza of finding new resources in existing acreage, but anyone with a competitive advantage in exploration would have a material advantage in licensing or mergers and acquisitions (M&A).’

While the ultimate goal is for machine learning and AI 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 continues: ‘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, $50bn/y 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 $5–7bn/y in exploration could be achievable. Similar savings could be achieved in drilling and completion, but digitalisation’s potential benefits really come to the fore in field development.

Mhairidh Evans, Principal Analyst, Upstream Supply Chain, says: ‘The primary financial impact will be to substantially reduce capital costs. Equinor believes its “field of the future” concept will reduce offshore facility capex by around 30%. Such a dramatic reduction could have a top-line impact, enabling the monetisation 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 adds: ‘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. The benefits will be seen across the E&P lifecycle, from planning and development to production and decommissioning. This is not the stuff of science fiction – BP is one of a number of oil and gas companies that have already implemented this technology, with the roll-out of its Apex programme.

‘Even without automated platforms, digitalisation will lead to cost savings in the pre-FEED and FEED stages of traditional developments,’ states Evans.

‘Automated modelling 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% versus the forecast at FID (final investment decision). The application of digitalisation through the development phase will become an important element to maintaining good project delivery.

The operational phase forms the backbone of the conventional industry’s spend, with over $340bn spent on opex each year, according to Wood Mackenzie. While new developments stand to benefit most from digitalisation, it can also be implemented at existing fields, with remarkable results. Total, for example, expects an opex reduction of almost 10% at the Culzean field which is under development in the UK North Sea through the application of a digital package.

Production gains through increased uptime are the other, potentially more valuable, side of the equation. For example, a 1% increase from each conventional producing asset onstream globally in 2018 would result in an additional 1.3mn boe/d in the market – this is roughly equivalent to the total output from Libya, reports Wood Mackenzie.

Aitken adds: ‘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 optimisation being reduced from 24–30 hours to just 20 minutes.’

Wood Mackenzie’s research shows that digitalisation is not a fad, nor is it ‘just an IT project’. Companies that don’t get onboard will fall behind. And while the majors may have more tools at their disposal, the transformational benefits digitalisation offers are available to all, even the smallest operators.

For more on digitalisation upstream, see Petroleum Review’s forthcoming December 2018/January 2019 issue.

Figure 1: Digitalisation in the E&P lifecycle
Source: Wood Mackenzie