Archives for category: Oil fields

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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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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The expansion of European settlement in North America – the pushing westwards of the frontier – has come to be seen as a defining part of American culture, spawning a whole genre of films and books set in the historical “Wild West”. That same pioneering spirit seems to be alive still today, at least in the US Gulf of Mexico (GoM), where 49 ultra-deepwater field discoveries have been made in the last decade.

Once Upon A Time In The Gulf

Offshore E&P in the US GoM began in the 1930s, picking up pace in the 1950s. By the end of 1975, a total of 444 shallow water fields had been discovered in the area and 256 of these had been brought into production. Gas fields predominated, accounting for 75% of discoveries and 31% of start-ups. Early E&P in the area made extensive use of jack-up drilling rigs and lift-boats. Fixed platforms were the favoured development method, with 86% of the 256 start-ups using fixed platforms. Thus were the first pioneering steps taken in exploiting the US GoM.

For A Few Dollars More

However, compelled by the need to find new reserves, oil companies active in the US GoM began pushing outwards, into deeper waters: the first deepwater discovery in the area was made in 1976. The frontier has now moved quite a way onwards since those early days. The average distance to shore of the 129 offshore discoveries in the area since start 2007 is 145km, while 72% (93) of these fields are in water depths of 500m or greater. The focus has also shifted from gas to oil: 58% of the 129 finds were oil fields, including 81% of the 93 deepwater finds. The US GoM has been dubbed one corner of the “Golden Triangle” of deepwater E&P and (supported by high oil prices until 2015) it has accounted for 16% and 19% of deepwater and ultra-deepwater finds globally since 2007. As shown by the graph, this was in spite of a slowdown in the wake of Deepwater Horizon. Floater utilisation dipped to 80% in 2011 but recovered, and a peak of 54 active floaters in the area was reached in January 2015 (26% of the active fleet).

Manifest Destiny?

So US GoM exploration was a major beneficiary of a high oil price. But how might it fare in a potential “lower for longer” price scenario? The outlook for jack-ups is bleak, with utilisation in the area standing at 24% as of December 2016. Simply put, the shallow water GoM is gas prone, and gas fields in the area are generally not competitive with onshore shale gas. At the US GoM (ultra-)deepwater frontier though, things do not look quite as bad as might be expected. On the one hand, over the last two years, floater utilisation has gradually fallen to 70%, as owners have struggled with rig oversupply, and dayrates are severely pressurised. On the other hand, there have been large finds made since 2014, such as Anchor and Power Nap, and wells are underway or planned for potentially major prospects such as Dawn Marie, Warrior, Castle Valley, Hershey, Hendrix, Sphinx and Dover. Many oil companies see the US GoM as a core area, and are prepared to invest to bolster oil reserves, even via drilling of, for example, costly HPHT reservoirs in the Lower Tertiary Wilcox formation.

As in the Wild West, at times things can be tough at offshore frontiers. Rig owners (and others) are experiencing this in the US GoM. But with some oil companies taking a long-term view, the pioneering spirit may not have been snuffed out yet.

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The African continent accounts for 16% (490) of active offshore fields and 17% (535) of offshore fields that are either under development or are potential developments globally. It is also home to key offshore exploration frontiers. However, the nature of E&P activity varies widely across the continent, as is clear from analysing the offshore areas into which Africa can be divided: North, South, East and West Africa.

North Africa: Old Fields?

A total of 217 oil or gas fields are located offshore North Africa, of which 112 are in production (95% in shallow waters). In this mature area, offshore oil production is projected to stand at 0.34m bpd in 2016, down 37% on the area’s peak of 0.54m bpd in 1991. Bar the possible restoration of offshore oil production lost in the “Arab Spring”, decline is set to continue. However, North African offshore gas production still has significant growth potential, forecast as it is to grow with a CAGR of 8.4% from 4.29bn cfd in 2016 to stand at 8.86bn cfd in 2025. This projected growth is driven by gas projects such as Zohr Ph.1 ($3.5bn; 1bn cfd) and Ph.2 ($10bn; 7bn cfd). The Zohr field, a frontier find in a water depth of 1,450m in the Levantine Basin, exemplifies the ongoing rise of deepwater E&P in the area.

South Africa: Few Fields

South African offshore production is minute in a global context. The area is home to just 17 offshore fields (only seven active, two having shut down in 2013). Although not without potential, E&P in the area has stalled in the downturn, as IOCs have cut and reprioritised E&P spending.

East Africa: New Fields

Unlike North and West Africa, East Africa has little history of offshore E&P: 88% of the area’s 41 offshore fields were discovered after 2009. The average water depth of these “frontier” finds is 1,570m and 92% are gas fields (with total reserves of more than 168 tcf). Offshore gas production in the area is projected to hit 2.82bn cfd in 2025 (from 0.13bn cfd in 2016) as fields are developed as part of LNG projects such as Coral FLNG Ph.1 ($7bn; 0.433bn cfd). However, further FID slippage at these frontier projects is a risk in the weaker energy price environment.

West Africa: Costly Fields?

West Africa constitutes one corner of the ‘Golden Triangle’ of deepwater E&P: of the 368 active fields in the area, 83% are in shallow waters (in the Gulf of Guinea and Angola) but 43% of 364 potential developments are in depths of more than 500m. The area has major deepwater production growth potential, even though it already accounted for 17% (4.35m bpd) of global offshore oil production in 2015. However, West Africa is a key offshore ‘swing’ region in terms of CAPEX and production: planned FPSO hubs such as MDA (Angola) tend to have high breakevens (c.$70/bbl+), so project FIDs have been scant since 2014. Frontier finds from Ghana up to Mauritania (39 since 2009) could yield more viable production growth though, and exploration in these waters has continued in the downturn.

In conclusion then, the African continent is home to a range of offshore field and project trends. Although there are some similarities across the continent in terms of “frontier” E&P, water depths and other factors, to get a grip on African offshore E&P, it is necessary to take the full range of available data and “drill down” into it.

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