Archives for posts with tag: deepwater fields

In the years since 1959, 7,367 offshore fields have been discovered globally, with 4,173 of these having been brought onstream (3,062 are still active). The average water depth of discoveries and start-ups is now far deeper than a few decades ago. But contrary to what might be expected, this appears to be not the result of gradual trends in E&P activity. Instead, deepwater activity has surged in distinct waves…

Shallow Water Drift

Offshore E&P activity began, quite naturally, in shallow waters close to shore, as a logical progression from exploiting onshore oil and gas fields in locations such as Texas and Saudi Arabia. This also reflected technological barriers: the capability did not exist to exploit deepwater fields. So from 1960 to 1996, the annual average water depth of offshore discoveries and start-ups was 94m and 59m respectively. Depths did drift slightly deeper from 1960 to 1996 as for example North Sea E&P activity moved from the Southern to the Central North Sea. But even in 1996, the mean offshore discovery water depth was just 212m. The first ever deepwater discovery was the MC 113 field in the US GoM in 1976 but this was atypical: just 4% of 3,062 offshore fields found from 1976 to 1996 were in such depths.

Deepwater Heave

The first wave of sustained deepwater E&P ran from about 1997 to 2006. It was heralded by the 1997 Neptune start-up in the US GoM in a water depth of 568m. This was the first ever Spar development and showed that US deepwater fields could be economically exploited, contributing to a rush of deepwater E&P in the GoM against a backdrop of faltering US onshore oil production growth and gradually rising oil prices. Some 440 fields in depths of at least 500m were found from 1996 to 2007; 38% of these were in the US GoM. This period also saw the internationalisation of the offshore sector, with oil companies making deepwater finds in areas like West Africa, which accounted for 26% of the 440 discoveries. Here the key enablers were subsea trees, which helped reduce field breakevens to viable levels. All told, the average depth of offshore finds from 1997 to 2006 was 402m.

Ultra-Deepwater Upsurge

A second wave of deepwater E&P has been ongoing since about 2007. Oil companies have pushed into ultra-deepwater frontiers, notably in the Santos Basin off Brazil, helped by advances in pre-salt seismic imaging, but also in the KG Basin off India, off East Africa and off countries such as Guyana or Senegal. Since 2006, with oil prices generally high, there have been 392 finds in water depths of at least 1,500m (67% of such discoveries made to date). The average water depth of discoveries in this period so far is 628m.

Ebb And Flow?

However, offshore start-ups have lagged in terms of water depth. Since 2006, the average depth of 1,032 start-ups has been just 326m (with large variance from the mean). Several factors are at play but key are high breakeven oil prices at frontier projects (especially in the downturn) inhibiting FIDs, and political risk factors.

So given current offshore markets and long term trends in start-up water depths, a tsunami of deepwater start-ups looks unlikely at present. That being said, field discovery water depths – lifted on tides of regionalised E&P activity and new technologies – have clearly risen in waves.


The rise of deepwater E&P constituted a boon for the offshore fleet, helping to drive, for example, 180% and 60% increases in the FPSO and floater fleets from 2000 to 2015. However, deepwater development has lagged exploration, and so the offshore sector is fairly exposed to projects with high breakevens – problematic, given the oil price. But could the downturn actually help deepwater E&P in the long term?

Deepwater Exploration

The first deepwater offshore discovery was not made until 1976, by which point 1,018 shallow water fields had been discovered and 350 brought onstream, and it was only in the late-1990s that deepwater E&P really took off. Oil companies began pushing deeper into the US GoM, while the internationalization of the industry in the 2000s saw a spate of deepwater discoveries off West Africa and Brazil. A robust and rising oil price helped sustain rising deepwater E&P until 2015, with India, Australia and East Africa becoming important frontiers too. The average water depth of global offshore field discoveries passed 200m for the first time in 1996, 500m in 2004 and 800m in 2012, and the number of deepwater discoveries averaged 55 per year from 2005 to 2015.

Deepwater Production

However, as the main graph shows, the mean water depth of discoveries rose much faster than did that of start-ups: the former stood at 734m in 2015, the latter at 377m. Indeed, by 2016, out of a total of 998 deepwater finds, just 27% had started up, with deepwater start-ups averaging 19 per year from 2005 to 2015. The divergence was in large part because technological barriers and cost overheads in deepwater production – subsea, SURF and MOPU – are more complex and expensive than in exploration, and efficiency gains seem to have been more limited to date as well. Deepwater project sanctioning was therefore relatively inhibited, and due to limited sanctioning, the backlog of undeveloped deepwater fields grew at a faster rate than that of shallow water fields, as indicated by the inset graph. Thus over time, the overall backlog of potential projects has become more costly and complex. Indeed, some reports suggest oil project average breakevens have risen by c.270% since 2003.

Deepwater Challenges

This is partly why the offshore outlook is challenged at present: deepwater fields have relatively high breakevens (usually $60-$90/bbl) yet also form a major part of oil companies’ portfolios. Some major oil companies have indicated that 2016 E&P spending cuts are to bite deeper off than onshore, where costs are lower (even for shale, in many cases). In January 2016, Chevron decided to axe outright Buckskin, a US GoM project in a water depth of 1,816m with a breakeven of c.$72/bbl. ConocoPhilips, meanwhile, is planning to exit deepwater altogether.

However, in order to make deepwater viable again, many companies are trying instead to cut project costs. Statoil, for example, has reduced the CAPEX of Johan Castberg by 48% and the breakeven by 40%. Some cost savings (in day rates, for instance) are likely to be cyclical; others, such as in subsea fabrication, yielding improved deepwater project economics, are likely to be more lasting. So while exposure to deepwater projects is clearly a challenge given the current oil price, cost cutting now could be to the benefit of deepwater E&P in the long run.


Plagued by constant blackouts and power shortages, Egypt appears to be facing its worst energy crisis in decades. However, following the historic discovery of the giant gas field Zohr offshore Egypt in August this year and revived interest from IOCs, it seems that the tables are set to turn. Indeed, after a period of gas production decline, Egypt’s energy outlook is getting increasingly bright.

Slide Down The Gas Pyramid

Until recently, Egypt’s gas production story had been one of growth: production climbed from 1.68 to 5.76 bn cfd between 2000-2009 and in 2003, it was sufficient to kick-start LNG exports. However, a combination of political unrest (notably the Arab Spring of 2011) and rising population has resulted in natural gas supply shortages over the last 5 years. Domestic gas demand has on average grown by 8% y-o-y, eventually outstripping supply. As a result, Egypt has been forced to re-route LNG destined for exports to domestic consumption. Indeed, at the start of 2014, BG announced it was breaking its contracts because it was unable to export enough gas. This year, Egypt resorted to importing LNG from Qatar – a bitter moment for the previous exporter.

Enter Zohr

They say that when you hit bottom, the only way is up and for Egypt, this seems to be the case. Earlier this year, ENI made what is believed to be the largest ever gas discovery in the Mediterranean, named Zohr. The field is part of the Levantine Basin, home to other prolific gas finds such as the Israeli Leviathan field. ENI puts the find down to different use of sequencing models, concentrating on carbonate rather than classical sand reservoirs. The gas giant (estimated to hold 30 tcf of lean gas) is located in water depths of 1,450m, providing an exciting departure from typical shallow exploration of mature basins in the region. Additionally, BP announced a $12 billion investment in Egypt’s West Nile Delta project: another deepwater discovery with 5 tcf of gas resources. A move to deeper waters creates opportunity for subsea development, the current production solution of choice in all of the country’s active deepwater fields. Out of the 68 active subsea units in Egypt, 40 are operated by ENI and 8 by BP. It is likely that these operators will continue to implement subsea development in their future projects.

Clash Of The Giants

Elsewhere, the discovery of Zohr was not such welcome news. There were plans to import gas via a pipeline from the Tamar field and (once in production) the competing gas giant, Leviathan, in Israel. Plans for the Leviathan field will now have to be redrawn and potentially accelerated if Israel wants a claim of the region’s LNG exports. However, following extensive regulatory and anti-trust objections, its start-up date remains uncertain.

Nevertheless, it is clear that Egypt’s fortunes are turning. The Zohr discovery, alongside other scheduled start-ups, will strengthen Egypt’s energy balance in the long-term. And the story does not end here: it has been reported that there are 7 other deepwater blocks with similar lithology to ENI’s. There is evidently a revived interest in the Levantine basin, as IOCs begin to wonder where the next giant could be hiding.