Archives for category: offshore production

Venezuela has the world’s largest proven oil reserves and is one of the founding members of OPEC. Despite this, their 2.5m bpd of oil production accounts for only 3% of global output. Venezuelan oil production declined over the last decade owing to complex geology and a difficult investment climate. However, several large IOC-operated gas fields offshore Venezuela could now offer some positivity.

The Hydrocarbon El Dorado

Venezuela’s 300bn bbl of oil reserves account for 18% of current global reserves. But 220bn bbls of these reserves are onshore in the Faja, or Orinoco heavy oil belt, which has produced around 1.3m bpd in recent years. Venezuelan heavy oil grades are a key part of world oil supply: many US refineries were designed to take its heavy grades of oil together with lighter Arab crudes, meaning the country is also important for the tanker market. But production from the Faja is expensive and technically challenging, and heavy crudes sell at a discount.

Making Heavy Work Of It

After the election of Hugo Chávez in 1999, Venezuela’s oil industry came under strain as social policies were funded by oil revenues, and reinvestment declined. After the 2003 general strike, 19,000 PDVSA employees were fired and replaced with government loyalists. Furthermore, in 2007, the government looked to capitalize on the high oil price environment by nationalizing international oil companies’ (IOCs’) assets.

Offshore production was always the minor fraction of Venezuela’s output (23%). However, lack of investment in maintenance hit it hard. This was particularly true of the very shallow water production in Lake Maracaibo, which has seen drilling for more than a century. Issues of pipeline leakage and even oil piracy on the lake helped production there decline. In total, output from the Maracaibo-Falcon basin (not exclusively offshore) fell 35% between 2008 and 2015. In total, offshore production is estimated to have dropped by about 38% to 0.57m bpd.

A Brighter And Lighter Future

The current political and fiscal situation in Venezuela offers little suggestion that it will be easy to arrest decline. However, a more permissive attitude to foreign investment may help. In October, agreements were signed to allow Chinese and Bulgarian investment to fund repairs offshore Lake Maracaibo. Perhaps more significant is the promise of gas, where greater IOC participation is permitted.

Trinidad, Venezuela’s very close neighbour, tripled their offshore production from 1998-2005. Venezuela has begun to make moves in the same direction, firstly via the Cardon IV project. The first field here, Perla, started up in 2015 run by an Eni-Repsol joint venture. As the graph shows, this has already had a small, but visible effect on Venezuelan gas output. Perla has reserves of 2.85bn boe and by Phase 3 is set to be producing 1.2 bcfd. This is likely to be added to from 2019 by up to 1 bcfd of output from the long-delayed Mariscal Sucre fields.

So, Venezuela has vast reserves but production has been falling. The political situation, combined with low oil prices, is likely to hinder any rapid turnaround in oil output. However, although progress has been slow, IOC involvement has at least provided some positive impetus for gas production offshore Venezuela.

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A few weeks ago, OPEC and other major oil producers agreed to extend 1.73m bpd of production cuts until the end of Q1 2018. Despite this, oil prices have continued to slide, with Brent failing to close above $50/bbl this week. While a range of factors have contributed to this trend, perhaps the most important is US tight oil production. So what is going on in the shale patch? And why does it matter to shipping?

How Unconventional!

If nothing else, US tight oil production retains the ability to surprise. As was noted after the OPEC meeting in May (SIW 1,273), “it remains to be seen if shale production quickly offsets” the cuts. Well, if the early signs are anything to go by, this is clearly not an impossibility.

Tight or shale oil is oil extracted from otherwise almost impermeable geology via “fracking”, a process wherein fluids mixed with sands are pumped at pressure into well bores, creating fractures in the rock through which oil and gas can flow. In terms of oil price dynamics, the key aspect of shale projects is speed: they can have lead times measured in weeks and so are very responsive to changes in oil prices. But in turn, as tight oil production ramps up, it can put pressure on prices, as recent history shows.

Remarkable Resilience

The US tight oil sector really took off in 2011, with production more than tripling from 1.70m bpd to reach a peak of 5.47m bpd in March 2015, as the graph shows. At this point, tight oil accounted for 6% of global oil supply (96m bpd) and equated to 55% of the net growth in supply from 2011. Such rapid supply growth had not been priced into markets, a key factor in the 2014 oil price plunge. A partial revival in mid-2015 was smothered as US drilling was stimulated again. And, since the US land rig count hit a new low of 380 units in May 2016, activity has again been on the up; the November 2016 OPEC deal accelerated this and the land rig count now stands at over 900 units. Tight oil production growth now equates to around 35% of the OPEC cuts. Its resilience (via cost deflation) in the face of lower oil prices continues, it seems, though it may prove self-defeating yet again. Even so, tight oil could now be a long term part of the oil price context. A few years ago, forecasters saw US tight oil production peaking circa 2020. Revised projections taking into account new technologies and updated resource surveys do not see US tight oil output peaking before the 2030s.

More Surprises?

The negative and positive implications for shipping of higher oil prices were covered in detail previously (SIW 1,273). The converse applies to lower oil prices, with offshore suffering from reduced E&P activity but the merchant fleet perhaps seeing benefits from cheaper bunkers and crude oil trade growth. Tight oil also has implications for trade flows. For example, now that export restrictions have been lifted, around 0.7m bpd of crude oil was exported from the US via tankers in Q1 2017.

So a factor that was barely on the radar a decade ago has become a key determinant of oil prices, potentially for the long haul. Moreover, tight oil has a range of ramifications for shipping that merit close monitoring. Once again, shipping appears inextricably linked to a key facet of the global economy. Have a nice day.

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China’s rapid economic growth over the last two decades has seen the country’s annual primary energy demand more than triple. Coal aside, the other key fuels powering China’s developing economy have been oil and gas. And while commodity imports have risen, economic growth has also incentivised more E&P activity in China itself. So how are things looking for China’s upstream sector, particularly offshore?

Venerable Ancestry

As of start May 2017, a total of 319 fields had been discovered offshore China (with 163 of these having been brought into production at some point) and around 5% of the active offshore fleet (over 500 units) was deployed in the country. Moreover, in 2017, 15% of total projected Chinese oil and gas production (4.43m boed) is forecast to be produced offshore.

Of course, things were not always thus. While oil extraction in China is thought to date back to antiquity, the modern industry took off during the era of Mao Zedong, in the 1950s and 1960s, with the exploitation of fields in the onshore Songliao Basin, notably the Daqing Complex, by the state. Offshore E&P was minimal before the late 1980s. As was the case in many countries, Chinese offshore oil production began at shallow water fields, in China’s case located in the Bohai Bay, Pearl River Delta and Beibu Gulf areas, which still account for 43%, 32% and 12% of the fields now active off China. A total of 139 offshore fields are in production across these three areas, of which 76% are exploited via fixed platforms. Shallow water E&P heavily influenced the development of the offshore fleet in the country: for instance, 11% of the active global jack-up fleet is deployed off China.

The Deepwater Leap Forwards

In recent years though, the drive to raise production has seen Chinese E&P shift into deeper waters, in mature areas as well as frontiers in the East China Sea, the Yinggeh Basin and the South China Sea. That being said, just 13 fields in depths of at least 500m have been found to date (the first in 2006), of which only two are active: Liwan 3-1 and Liuhua 34-2, both in the Pearl River Delta. Hence demand for high-spec floaters, MOPUs and OSVs remains limited. Deepwater E&P in China was led by IOCs, but then CNOOC began concerted independent efforts. However, this process has been slowed by the oil price downturn, which prompted the NOC to put deeper water projects such as Lingshui 17-2/22-1 and Liuhua 11-1 Surround on the backburner.

Conquering The Seas?

The outlook for Chinese offshore projects seems to have improved since the OPEC deal though, and CNOOC is reportedly planning over 120 offshore exploration wells in the next five years. But there are contrary factors, not least of which is political risk in the East and South China Seas, where China and neighbours such as Japan and Vietnam are engaged in bitter border disputes, notably over the “nine dash line”. Moreover, government plans to increase onshore shale gas output at Fuling and elsewhere may divert investment from costly offshore projects.

So there are clearly risks to continuing E&P off China in more frontier areas. But even as the country’s economy matures, energy demand growth is likely to remain substantial. The fundamentals thus suggest that the onwards march of E&P off China is likely to be far from over yet.

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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.

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In 2011, Nigerian oil production stood at 2.55m bpd (of which 71% was offshore), accounting for 7.1% of total OPEC oil production (and 40% of West African offshore oil production). Since then, Nigerian oil production has been eroded by exposure to political risk factors and weaker commodity prices, dropping to just 1.54m bpd in 2016. What, then, is the outlook for Nigerian oil production in 2017 and beyond?

A Rose-Tinted Past?

Nigeria has been an oil producing country for almost 60 years and its first producing offshore field came onstream in 1965. In the following decades, Nigerian offshore E&P was focused almost entirely in the shallow waters of the Niger Delta. Even today, there remain 104 active shallow water fields in Nigeria producing via 263 fixed platforms with an average age of 25 years. It was in the late 1990s that Nigerian E&P began moving further from shore, as oil companies sought new reserves to offset decline at mature shallow water fields. Deepwater fields were also less vulnerable to the militant activity plaguing the Delta for much of the 2000s. The first deepwater discovery in Nigeria was Abo, in 1996, which was the first such start-up too, in 2003. As of March 2017, 40 fields in water depths of at least 500m had been found off Nigeria, of which 10 had been brought onstream via a total of seven FPSOs and 253 subsea trees.

A Risky Proposition?

However, were it not for deleterious influences on Nigeria’s upstream sector in the last 10 or so years, deepwater E&P in the country could now be more prevalent still. The foremost difficulty has been the Petroleum Industry Bill (PIB), which was first introduced to the Nigerian Parliament in 2008 and which has yet to be passed. An especially contentious issue is mooted changes to deepwater fiscal terms, which IOCs argue would render deepwater projects (where breakevens tend to fall in the $60-90/bbl range) unviable. An uncertain investment climate has been compounded by court cases arising from alleged improper practices, for example at OPL 245, host to the stalled ZabaZaba project(100,00 bpd). So there have been few deepwater FIDs and just three such field start-ups off Nigeria since 2009 (versus 20 off Angola). There has thus been little deepwater oil production growth to offset onshore or shallow water field decline.

Stability Or Volatility?

Uncertainty about the PIB remains, but in 2016, disruption caused by militants, notably the Niger Delta Avengers, came to the fore: attacks on oil infrastructure saw oil production dip below 1.25m bpd at times in 2016. Moreover, weaker oil prices have hit government finances and so its ability to dampen unrest. Production recovered slightly in Q4 but conditions in the Delta remain febrile. And if oil production does continue to ramp back up to over 2.0m bpd, it could imperil gains in the oil price that followed the OPEC deal (Nigeria is exempt from quotas). If prices cannot climb above $60/bbl, there is little prospect of Nigerian deepwater projects (of which there are 13 with a total oil production capacity of over 0.81m bpd yet to be sanctioned) hitting FID any time soon.

So in the short term, Nigeria could prove a key factor in the global oil price equation. And in the long term, undoubtedly the country has a great deal of deepwater potential; however, before this is likely to be realised, numerous challenges need to be overcome. Nothing is certain.

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Natural gas is set to account for an increasing share of the global energy mix in coming years, with gas consumption growing by an average of around 1.5%-2% a year out to 2040, according to energy forecasting agencies such as the IEA. And based on recent trends, if the consensus views on natural gas prove accurate, the implications for the offshore and LNG carrier fleets are likely to be significant.

Stepping On The Pedal

In 2016, global natural gas demand stood at an estimated 347bn cfd, up by 24% on the 280bn cfd consumed in 2006. Demand for natural gas in recent years has been driven by industrialisation in developing economies (Chinese gas demand, for example, grew at a CAGR of 13% in 2006-16) and environmental concerns the world over. Historically, the majority of trade in natural gas has been by pipeline, for instance from Eurasia to Europe. In 2015, pipelines still accounted for 68% of natural gas volumes moved globally.

However, liquefied natural gas (LNG) has become an increasingly important form in which gas is traded, even given the costs of complex liquefaction and regasification facilities. Over 50% of existing nameplate liquefaction capacity at LNG export terminals (349mtpa globally) has come online since 2005. As a corollary, from start 2006 to start March 2017, the LNG carrier fleet increased from 193 to 479 vessels and tripled in total capacity to 70.2m cubic metres of LNG.

Shifting It Up A Gear

Growth in the seaborne LNG trade is in turn closely linked with growth in offshore gas production, as major LNG exporters such as Qatar and more recently Australia use offshore gas fields to provide feedstock to LNG trains. Qatar accounted for 30% of LNG exports and 22% of existing liquefaction capacity in 2016, all fed via offshore gas, mostly from the giant North Field. In 2006, offshore fields accounted for 28% of global gas production and by 2016, 31%. This is set to rise to 32% (119bn cfd) in 2017, mainly due to field start-ups off Australia that are to feed LNG projects like Wheatstone. Finding, developing and supporting offshore gas fields on Australia’s NW Shelf has created demand for a range of vessels from the offshore fleet of over 13,500 units.

More Gas In The Tank

The exploitation of these remote reserves has also spawned the FLNG concept – vessels that can be used to exploit otherwise stranded gas. The LNG markets are clearly challenged at present but in the long term, planned FLNG projects in Australia, Mozambique, Tanzania, Mauritania and other areas could potentially sustain offshore gas production growth. Another major source of gas production growth has been the US shale gas sector, where production rose from 4bn cfd in 2007 to 48bn cfd in 2016. The US accounts for over 50% of liquefaction capacity under construction (while some planned projects entail liquefaction of shale gas on near-shore FLNGs) and is set to become a major LNG exporter in coming years.

So offshore gas production has grown as a share of total global gas production, as has US shale gas. Both trends can create opportunities for LNG and offshore vessels. And if, in line with consensus expectations, gas continues to grow as a share of the energy mix, then these trends may have a long and interesting road ahead.

SIW1265:Global Natural Gas Production And LNG Export Capacity

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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