NewsBase editors look at the technology and projects which have shaped the industry this year, and consider what is on the horizon in 2017
Africa Trends established in 2015 continued into 2016, with spending plans falling and companies delaying big spending plans around Africa. The deceleration manifested largely through capital expenditure cuts, a worldwide feature exacerbated by concerns over regulatory risk and mounting government debt in a number of African locales. Governments have taken some steps to attract new interest, showing increased flexibility on licence terms and launching licence terms. Spending on seismic showed some interesting signs, driven by substantially lower pricing, but drilling was in painfully short supply and offshore rig deployment fell to near-record lows. While companies seem content to run existing facilities, and continue spending on existing plans, the pre-FID pipeline has largely seized up. Royal Dutch Shell’s decision to delay approval for its Bonga South West development highlighted the problems for major project spending in Africa. Some signs of life, though, have been seen in gas production plans. Eni approved its major Zohr plan, in February, targeting a start of the end of 2017, while BP also made additional commitments in Egypt. Gas output in the country will largely go to the domestic market, which has benefited from government action on pricing, and there have also been some positive signs about restarting LNG plants. Most significantly, though, was the continued move towards the mainstream of floating LNG (FLNG). Eni is nearing FID on its Coral South plans, off Mozambique, with BP having committed to offtaking gas from the project. Given the preponderance of major offshore gas finds, FLNG appears to be a natural fit for the continent. After some havering, Schlumberger agreed to work on Ophir Energy’s Fortuna project in Equatorial Guinea, alongside Golar LNG, and Kosmos Energy has talked up FLNG for its Greater Tortue development in Mauritania-Senegal. One potentially interesting development is in transferring technologies into new regions in the deepwater. Anadarko Petroleum carried out appraisal work offshore Cote d’Ivoire at its Paon find, with an apparently successful move into horizontal drilling. The move may provide additional productivity in the offshore, but the economics are not yet clear.
Ed Reed, AfrOil editor
Middle East Sanctions on Iran were finally lifted in January 2016, six months after a deal was agreed with the UN P5+1. For all the softening of rhetoric and signals of intent from IOCs, though, certain US sanctions remain in place and have slowed the expected foreign investment flows. Nevertheless, Iran’s production profile has changed dramatically over the past year: output has increased from 2.8 million bpd in December 2015 to 3.67 million bpd in October this year, on the back of a wider market for crude from the Islamic Republic. Neighbouring Iraq has had a mixed year. The government has struggled financially, being unable to fund the rapid development of its massive oil reserves, as it has pushed back Daesh militants and begun the fight to retake the city of Mosul. The appointment of Jabbar al-Luaibi as Oil Minister in the autumn brought new optimism, though this has now subsided somewhat, following a bid round which was launched, then unceremoniously dropped in the fourth quarter. In the Kurdish north, relative calm appears to have broken out, with an ‘understanding’ between Baghdad and Erbil regarding oil production and export. However, the Kurdish Regional Government (KRG) has had its share of money troubles, falling short of expected payments to IOCs developing its resources. Hydrocarbons behemoth Saudi Arabia had a somewhat quieter year than the one before, making incremental output gains with new drilling programmes at fields including Ghawar, Khurais and Shaybah. Externally, Riyadh’s (and OPEC’s) agreement in late November to cut production by 1.2 million bpd finally brought about an uptick in oil prices, but this was limited by the market still being oversupplied. Oman has made steady progress with its headline Khazzan and Mukhaizna projects, with the former expected to produce first gas on schedule – in 2017 – providing feedstock for a new refinery and petrochemical complex at Duqm on the Al-Wusta coast. In the Eastern Mediterranean, Israel has launched a new bidding round, whilst in neighbouring Lebanon the appointment of a new government is seen as providing the stability required to press on with its own offshore auction. Syria and Yemen remain torn by war, and energy sector efforts are far outweighed by those being made to conclude the ongoing sectarian violence. Finally, Bahrain has made a surprise return to the upstream radar, appointing Italy’s Eni to assess its resource potential.
Ian Simm, MEOG editor
North America Across North America, efforts to cut costs continue to be the greatest shapers of exploration, production and technology. Shale drilling has not lost the ability to surprise the industry with its resilience. Through a combination of high-grading, cost-cutting and the trialling of new techniques, shale drillers have set new records and pushed the boundaries of what was considered possible even a year or two ago. This has included record volumes of proppant employed in frack jobs (Chesapeake used 25,000 tonnes of sand in a Louisiana well) and horizontal laterals being drilled to new lengths (an 18,500-foot [5,600m] lateral drilled by Halliburton and Eclipse Resources). We can expect these records to be broken again next year as drillers continue to experiment. As breakeven prices keep falling and some drillers at least prepare to bring more rigs on line, further technical innovations can be expected. Services providers are also stepping up their efforts here. Schlumberger is currently trialling two prototypes of its “rig of the future” in the Permian Basin, with a view to releasing the final model in 2017. While high-grading remains a major strategy, some shale drillers are moving into more difficult areas. For instance, Apache has been talking up its Alpine High discovery in the Permian Basin, though there have been warnings that the find is located in a particularly geologically challenging area, where results have previously been poor. How Apache performs remains to be seen, but a shift away from high-grading towards less productive areas will be inevitable in the coming years, as the sweet spots are tapped. While the majority of drillers – both independents and super-majors – have been focusing on shale plays, where production can be easily scaled up or down depending on oil prices, some developments have been seen offshore as well. Notable deepwater projects to come on line this year include Shell’s Stones and ExxonMobil’s Julia – both Lower Tertiary projects. Stones was notable for several innovations, including the use of 3D printing to create a prototype of the system involved – something that could become more commonplace among offshore operators in the coming years as they design increasingly complex systems. Another offshore operator of note in the US Gulf of Mexico is BP, which this year rolled out a water injection project at its Thunder Horse platform to extend the field’s life. BP anticipates this will help it to recover an additional 65 million boe. The company has also just sanctioned its Mad Dog Phase 2 development, having managed to slash the cost of the project from an initial US$20 billion to an estimated US$9 billion. The company sees potential for a bright future in the Gulf thanks to such projects, a focus on cost-cutting, standardisation and simplification. In Canada, the Fort Hills oil sands project and the offshore Hebron project are due to start up in 2017. While final investment decisions (FIDs) on megaprojects have been rare recently, a strong performance by these new projects could help revive appetite, as well as illustrate the latest technological advances. Shale will continue to dominate the North American landscape in 2017, but what few new oil sands and offshore developments there are will show that technological advances are still being pursued across the board.
Anna Kachkova, NorthAmOil editor
Latin America As predicted in our last annual review, 2016 proved to be a year of mixed fortunes for Latin America. Weak oil prices continued to weigh heavily on E&P spending. But the move away from populist leftist governments to more conservative administrations, most notably in Brazil and Argentina, is positive for inward investment in the region. Argentina’s new government under President Mauricio Macri has made great strides forward in the energy sector. Subsidies have been unwound and the administration is pushing producers hard to increase oil and gas output so expensive imports can be pared back. Macri has made ending LNG imports a goal by the end of the decade. In order for this aim to be achieved, output will have to ramp up rapidly from the Vaca Muerta shale and other unconventional plays across the country. Shale drilling costs are falling rapidly in Argentina. It currently costs US$9.5 million to drill a well in the play, down from US$10 million at the start of the year and heading closer to the US$7 million mark Macri’s team have targeted. Costs are coming down as experienced shale developers like ExxonMobil advance projects with YPF and as infrastructure improves. The government is investing heavily in enhancing local road and rail infrastructure to ease the flow of proppant and frac sand into the Vaca Muerta. Mexico’s energy reforms are starting to bear fruit, with the country’s first ever deepwater auction in December attracting a roster of the biggest names in the global oil industry. BHP Billiton, BP, CNOOC, ExxonMobil, Petronas , Pemex, Statoil and Total were all on the list. The country’s oil output has fallen below 2 million bpd this year, but it is likely to start rebounding over the next five years as the acreage sold to private companies in early bid rounds becomes more productive, and then further in the future when the coveted deepwater blocks come on stream. Production of over 3 million bpd is probable in a decade. Brazil has been the biggest story of 2016 in Latin America. The oil price collapse and the Car Wash scandal forced out the government of impeached ex-president Dilma Rouseff. A new, more business-friendly administration under President Michel Temer has taken office and, with new Petrobras president Pedro Parente, has sought to reframe the dysfunctional oil and gas industry. New laws governing the pre-salt that remove the obligation for Petrobras to be the operator of all blocks and also ease national content rules are likely to have a positive effect on development. Statoil has already taken advantage of the situation, growing its presence in the pre-salt, and others are likely to follow with the first auction of pre-salt blocks lined up for 2017. Venezuela continues to be a basket case. The economy continues to tank, though the discredited government of President Nicolas Maduro still clings on to power. Next year could see the country cross the Rubicon, however, as a default is highly likely. A strong and sustained rise in oil prices appears to be the country’s only hope, but even that might not be enough, given the mess the economy is in. Ecuador has also had a difficult 12 months on the back of weak prices. But progress has been made in developing the Ishpingo Tambococha Tiputini (ITT) project. In September the Tiputini field began pumping at a rate of 20,000 bpd, which was above government expectations. Output could rise to 50,000 bpd in 2017. The project is critical to Ecuador’s future, given that it sits on an estimated 1.7 billion barrels of reserves. Development of ITT is forecast to require about US$4 billion in total investment. Spending at Tiputini alone is estimated at around US$1.5 billion between 2014 and 2018. Finally, Peru had some positive news in late November when China’s state-run CNPC reported the discovery of an estimated 4 tcf (110 bcm) of gas spread across four structures in Block 58 at a depth of 4,000-5,000 metres. The find would add around 30% to Peru’s total gas reserves and, with the new government of President Pedro Pablo Kuczynski looking to attract greater foreign direct investment, could herald a brighter future for the county’s hydrocarbons sector.
Ryan Stevenson, LatAmOil editor
Europe The North Sea has endured a torrid couple of years since oil prices crashed. OPEC’s plan to cut production in late November looks to have put a floor under US$50 per barrel oil, but even that means that margins remain tight for operators in the high-cost region. This has led many of the big guns to review their operations, with Royal Dutch Shell and ExxonMobil reportedly considering multi-billion dollar sales of their assets in Norway. BP and Det norske oljeselskap merged their assets in Norway to create Aker BP. It now operates as one organisation and has considerable ambitions on the Norwegian Continental Shelf (NCS). The exit of the majors has created an opportunity for smaller, private-equity backed independents, like Siccar Point Energy. The company, which is backed by Blackstone, the US private equity group, and GIC, the Singaporean sovereign wealth fund, recently agreed to pay US$1 billion for the UK business of Austria’s OMV in a deal that will make it a partner of oil majors BP, Statoil and Chevron in some of the biggest remaining North Sea fields. Otherwise the tale of the North Sea in 2016 has been one of cost cutting, integration and closer collaboration. It has been a painful process but means the industry, and oilfield service providers, will emerge stronger and leaner when the projected uptick in business occurs. The Eastern Mediterranean continues to be a dynamic area. A flurry of exploration activity is anticipated in 2017, with companies searching for more gas to advance critical infrastructure projects like pipelines and LNG plants. Eni and Total are due to drill off Cyprus next year, while Lebanon is reviving a bid round and Israel is due to award more blocks.
Ryan Stevenson, EurOil editor
Asia Low oil prices drove a lot of money out of the Asian upstream this year, leaving very little funding for high-tech developments. After years of defying expectations of an imminent crude output decline, China’s majors finally bowed to production economics this year, choosing either to close older marginal fields or to curtail enhanced oil recovery (EOR) programmes at mature giants. This behaviour is likely to continue throughout 2017 as the NOCs move to conserve cash for other, high value-adding projects at home or abroad. They will also be watching how Beijing’s efforts to introduce greater private sector spending in oil and gas production unfold and affect their own assets. One area of the Chinese upstream likely to see continued spending is the unconventional gas sector. The central government has grand plans for shale gas, targeting production of 30 bcm per year by 2020 and 80-100 bcm by 2030.While the country is anticipated to surpass its target of 6.5 bcm this year, it still has a long way to go before its 2020 and 2030 targets are within reach. Further drilling and development throughout the prolific Sichuan Basin should be expected next year, with Sinopec focused on its Fuling block and PetroChina on Changning-Weiyua. Sinopec is also set to develop a new block in Wulong in partnership local government-owned Chongqing Xianglong and work will likely begin next year given that it has already been explored. Elsewhere in Asia the story is very much about the adoption of floating liquefaction or regasification capacity over more costly onshore projects. The former is fast becoming a preferred alternative in the wake of the painful lessons learned in the Australian sector in recent years, with several world-class developments there experiencing cost blowouts and delays. This shift has not necessarily been welcomed by everybody, though, with some governments worried about missing out on the greater local economic development associated with onshore facilities. Indeed, Indonesia has pushed Inpex and Shell to commit to an onshore facility after the pair originally planned to use a floating plant. As such, the scale of the project may need to be ramped up nearly fourfold to make it economically viable. Floating storage and regasification units (FSRUs), meanwhile, offer Asia’s less developed economies a quicker and significantly cheaper alternative to onshore installations for tapping into the global gas supply market. This is set to continue, with Pakistan already lined up to launch a second FSRU in June 2017. In the downstream, a new wave of investment decisions should be expected in the coming year, continuing a trend towards capacity upgrades seen this year. China’s emergence as a major fuel exporter, in part thanks to crude import reforms concerning independent refiners, has several regional downstream hubs nervous and refiners at these will be looking to ensure they remain competitive in the years to come. Vietnam has already been caught out; free trade agreements (FTAs) signed with ASEAN and South Korea are undermining the effectiveness of its own downstream, leading to several developments being cancelled.
Andrew Kemp, AsianOil & ChinaOil editor
Russia and Central Asia Western sanctions targeting the use of advanced technologies in Russia’s oil industry have failed to check production growth, with output hitting a new post-Soviet record of 11.23 million bpd in November. Some of this growth has come from challenging new projects in Yamalo-Nenets, including Gazprom Neft’s Novoportovskoye field, which is expected to deliver 50,000 bpd this year, up from a meagre 5,800 bpd in 2015. A further rise in output will be possible thanks to the launch of six Arc7 icebreakers that ensure year-round delivery of the field’s crude to market. More recently, Gazprom Neft and Rosneft started commercial operations at East-Messoyakhskoye, Russia’s northernmost oilfield. The field – which was discovered in the 1980s but was shelved until now because of inadequate technology – came on stream in September. It is slated to produce around 110,000 bpd of oil by the end of the decade. At the same time, Russia has also been able to sustain output at more mature assets with the help of enhanced oil recovery (EOR). For instance, mid-sized producer Bashneft saw extraction at its brownfield sites in the Volga-Urals region rise by 0.5% in the January-September period to around 250,000 bpd. Even so, sanctions that bar Russian oil producers from accessing sophisticated Western technology have claimed some casualties. Despite Rosneft and ExxonMobil’s discovery of 750 million barrels at Pobeda in September 2014, offshore drilling in Russia’s Arctic has ground to a halt. Moscow does not expect to bring any new Arctic projects online before 2035 and has even declared a temporary moratorium on the award of new licences. Still, Gazprom Neft’s Prirazlomnoye field stands as a testament to the region’s potential. The field is scheduled to deliver 42,000 bpd of oil in 2016 and around 100,000 bpd in 2017, up from 17,500 bpd last year. Sanctions have also complicated Russia’s efforts to tap its unconventional oil and gas reserves. Without foreign assistance, many Russian producers appear to be disinterested in exploring for these resources. The one exception is Gazprom Neft, which has been making extensive use of hydraulic fracturing and horizontal drilling this year. In October, it announced it had completed a 30-stage fracking operation at a field situated in the Bazhenov Basin. Even so, the company has slashed its production targets for the site and NewsBase believes tight oil will remain low on Russia's list of priorities. Meanwhile, in Kazakhstan, the massive Kashagan offshore field was relaunched in October after years of delays. The field, which contains 9-13 billion barrels of oil, is anticipated to produce 230,000 bpd by 2018. Production will rise even further from the plateau if the field’s partners can agree on a second development stage. In the summer, Chevron and its partners at the onshore Tengiz oilfield also signed off on a US$37 billion expansion that will raise oil output at the site by around 260,000 bpd. This will bring total production up to about 1 million boepd.