Archives for posts with tag: offshore oil production

To much fanfare and accompanied by voluminous industry coverage, Mexico recently concluded Round 1.4, the country’s first ever deepwater licensing round. However, Mexico’s shallow waters may yet have a future too: Bay of Campeche reserves remain considerable and indeed, the country’s third shallow water bid round is ongoing. It is therefore worth reviewing the current state of shallow water E&P in Mexico.

Veering Off Course

Mexican offshore oil is currently produced entirely from shallow water fields, as has always been the case. The key sources of Mexican offshore oil have been several large field complexes such as Cantarell and Ku-Maloob-Zaap. As these fields and others came online, the country’s offshore oil output grew with a robust CAGR of 6.6% from 1980 to 2004, reaching a peak of 2.83m bpd in 2004. As the graph implies, four complexes accounted for 93% of this production. Decline set in thereafter at ageing fields (production at Cantarell began at the Akal field in 1979). Pemex – the sole operator of Mexican offshore fields prior to 2014 – tried to halt production decline, but with little success, given budget and technical constraints. Thus by 2013, offshore oil production at the four key field complexes had fallen to 1.31m bpd, accounting for 69% of Mexico’s offshore oil production of 1.90m bpd.

Getting Back On Track

This situation prompted President Peña Nieto’s government to initiate energy sector reforms in 2013, opening up the country’s upstream sector to foreign companies for the first time since 1938. Pemex was granted 83% of Mexican 2P reserves in “Round Zero” in 2014. The first shallow water round, Round 1.1, followed in December 2014. Only two of 14 blocks were awarded though, reportedly due to unfavourable fiscal terms inhibiting bidding by oil companies. The authorities then improved terms before launching Round 1.2 (shallow water), Round 1.3 (onshore) and Round 1.4 in 2015. Round 1.2 was better received than 1.1: as per the inset, 60% of blocks were awarded (75% of the km2 area on offer). One of the round’s victors, Eni, has already been granted permission to drill four appraisal wells on Block 1.

Turning Things Around?

In light of these positives, there are high hopes for Round 2.1, a shallow water round launched in July 2016. Indeed, 10 out of the 15 Round 2.1 blocks are in the prolific Sureste Basin, home to the Cantarell complex. Eight of these ten areas are unexplored, so there is sizeable upside potential, and have been mapped with 3D seismic, so operators could begin drilling promptly. Moreover, the surface area of the blocks in Round 2.1 are twice that of Round 1.1. It should also be noted that according to a 2016 IEA study, Mexico’s shallow waters still account for 29% of the country’s remaining technically recoverable oil resources. Finally, with rates for a high spec jack-up in the GoM assessed at about $85-90,000/day in January 2017, down 45% on three years ago, some oil companies might be tempted to make a move on a round that could offer a relatively low cost means to grow oil reserves and production.

So arguably, Mexican shallow water E&P is on the road again. There are potential hazards of course, such as oil price volatility or Mexico’s relationship with the US. But it is not implausible to think that Mexican shallow water oil production might speed up again in the coming years.

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Global excess oil supply still looks likely to average 0.5m bpd in 2016 – sufficient, it would seem, to stop oil prices rising much above $50/bbl and therefore to forestall a recovery in E&P activity and the offshore markets. On the supply side of the equation, US shale production and Saudi policy tend to be seen as the key “swing factors”. However, an appreciable degree of relief could also come from elsewhere.

Taking A Swing At Production

West Africa, a fairly mature oil producing region, accounted for 6% (5.3m bpd) of global oil supply in 2015, including 17% (4.4m bpd) of world offshore oil production. To put this in context, world oil oversupply in 2015 stood at around 1.7m bpd – 2% of total supply, i.e. 95.8m bpd, to which the US contributed 12.6m bpd (13%) and Saudi Arabia 12.4m bpd (13%). Saudi Arabian production so far in 2016 has been stable, while US shale oil production in May 2016 was down just 8.9% on May 2015, representing a far slower decline than many observers anticipated. It follows, then, that a severe disruption to West African oil production could have significant implications for the global oil supply-demand balance. Such a scenario seems to be unfolding in Nigeria, which in 2015 produced an estimated 2.3m bpd – 43% of West African oil production. In a series of high-profile attacks, the Niger Delta Avengers (NDA, a new permutation of the old militant group MEND) have sabotaged pipes and wells in the Niger Delta, crippling onshore and shallow water output. At the same time, only 12,000 bpd of offshore capacity (from the Antan field) is set to start up in 2016, and even fixed platforms further from shore, like “Okan NWP PRP”, have come under attack. As a result, Nigerian oil production reportedly fell to 1.1m bpd in May, and 2016 production is projected to average 1.8m bpd – a production loss equivalent to 28% of oversupply in 2015.

In Full Swing No Longer

Political risk is thus one reason West Africa can be a “swing factor” in oil production; another is project economics, especially over the medium term. Angola, for instance, accounts for 43% of West African offshore oil production and 33% of projects in the region yet to reach EPC. However, most of these are deepwater FPSO hubs with high breakevens. In fact, the last project sanctioned off Angola was the $16bn Kaombo Ph.1 project in April 2014, with a reported breakeven of $74/bbl. Given the dearth of project FIDs since 2014, a paucity of start-ups is expected in 2018-21, which would feed into weaker world oil supply growth.

The Swinging Sixties

In the long term though, West Africa has the potential to act as a swing region for (offshore) oil production in the opposite direction. Given stronger oil prices, c.$60-$80/bbl, prolific projects such as Chissonga (Angola, 150,000 bpd) could be feasible again, while an oil price of c.$90/bbl would unlock the potential of many of the 39 Equatorial Margin frontier fields discovered offshore since 2010. West Africa could thus, in a favourable price environment, make an important contribution to world oil supply growth once again.

Of course, political risk and costly projects make West Africa a challenging region at present. But taking a macro view, that could actually be positive for oil prices. West Africa is clearly one among a range of important swing factors in the world oil supply-demand balance.

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On July 14th 2015, after 20 months of negotiations, Iran and the so-called “P5+1” signed the “Joint Comprehensive Plan of Action”: in return for US, EU and UN-mandated sanctions against the country being gradually lifted, Iran has agreed to roll back its nuclear capabilities. Should the deal stick, the door will open to foreign investment once more. What, then, are the possible implications for Iranian offshore oil? Should this deal stick, IOCs will soon be able to operate in Iran once more. What, then, are the possible implications for Iran’s offshore sector?

Political Locks

On the eve of the Islamic Revolution in 1979, total Iranian oil production stood at 6.0m bpd, of which around 12% (0.72m bpd) was from 13 offshore fields producing oil, all located in shallow waters and exploited via fixed platforms. The turmoil of the Revolution saw oil production drop to 1.70m bpd in 1980, and in the ensuing Iran-Iraq War, offshore fields like Salman were shut in due to military action. As a result, actual offshore oil production was less than 50% of capacity for most of the 1980s; after the War, production began to recover, peaking at 88% of capacity (0.60m bpd) in 1997. However, as US and then EU economic sanctions on Iran tightened, IOCs were forced to exit the country, depriving Iran’s offshore sector of key investment and technology. Development work slowed and much of Iran’s offshore 2P reserves (30.3bn bbl of oil; 707 tcf of gas) were locked away. At the same time, Iran lacked the resources to implement EOR at brownfields. As a result, the gap between actual and nameplate offshore production was 1.38m bpd by 2014, with production at 0.54m bpd.

Rusty Hinges

Now that sanctions are to be lifted, indications suggest Iran aims to get as much oil production as possible back onstream in 2015/16. Restoring offshore production is likely to require more than just turning the taps though. Iran’s ability to halt decline at brownfields has been curbed, in contrast to other mature producers like the U.A.E. Half of Iran’s active offshore oil fields predate the Revolution (the oldest started up in 1961). Extensive EOR work is likely to be required at such fields – one opportunity for IOCs. Thus, while offshore production is forecast to grow by 7.3% in 2015, this is mostly due to South Pars condensate production ramping up, rather than utilisation of older capacity.

An Alternative Entrance?

Iran is planning an “oil contract roadshow” in London in 2H 2015, with the stated aim of attracting foreign investment in E&P of $185 billion by 2020. However, it is likely that much of the investment will be directed towards stalled onshore projects such as Yadavaran, and to restoring production at mature onshore fields like Azadegan. A spate of onshore discoveries made from 2006 to 2008 may also be prioritised by cash-hungry Iran, particularly those in the Khuzestan province spanning the Iraq border. Some of Iran’s 7 undeveloped offshore fields like Esfandiar (532m bbl) may warrant priority, and the South Pars Oil Layer is scheduled to come onstream in 2018. But even taking into account the Caspian (home to the 2011 Sardar-e Jangal 500m bbl find), offshore oil opportunities for IOCs (and so vessel owners) may be limited at first.

It seems, then, that the offshore oil capacity gap could widen before it narrows. Certainly given its reserves Iran has long-term offshore potential, notwithstanding its troubled history. But observers expecting a quick and big uptick in oil-related offshore activity might need to be patient.

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