NewsBase Intelligence editors consider the projects and technology trends which have shaped this year, and what may be on the horizon in 2018
Pioneering technologies made slow progress in Africa during 2017, although the approval of a major floating LNG (FLNG) plant provided some optimism for the future.
A number of gas discoveries have been made – setting the stage for further FLNG schemes – but governmental consent and final investment decisions (FIDs) have been slow in coming. The exception is Eni’s Coral South FLNG project, offshore Mozambique, which is due to begin producing in 2022.
Part of the problem is that FLNG remains a largely untested phenomenon, even though the first carrier-to-liquefaction unit conversion is set to start up in Cameroon before the end of this year. Africa’s offshore gas resources are widely seen as a good fit for FLNG, but financing has been difficult, given the continually changing circumstances in the LNG market.
The most important advances, though, came in lower exploration and production costs. Total, for instance, has been working on infill drilling in Nigeria and Angola in order to seek low-cost additional barrels. Crucially these are extensions to existing infrastructure and so can begin producing in a short time after a decision to develop is given. A number of new projects are also slated to start up soon. Egypt’s Zohr field should begin producing by the end of 2017 and, in addition to some other developments, the country hopes to end LNG imports in 2018. The North African country only began importing LNG in 2015 and has two FSRUs.
The gas component of Ghana’s Offshore Cape Three Points (OCTP) block should also begin in 2018. Ghana has signed a number of LNG import deals in 2017 but import progress has been slow. While an FSRU arrived in the country in 2016 it left in mid-2017 after a lack of progress was made on hooking the vessel up to the shore.
Other notable projects starting up in Africa include Angola’s Kaombo, from the Kaombo Norte FPSO, with a second to follow. Continuing the deepwater theme, Egina will begin producing in Nigeria in 2018, in water depths of up to 1,700 metres.
A number of projects are due online shortly from Algeria, helping sustain gas production, but reports have suggested Cepsa’s Timimoun project will be pushed back to 2019.
Ed Reed, AfrOil Editor
Energy, geopolitics, economics and religion all contributed to another year of major change in the Middle East. In 2016, the ‘end of sanctions’ in Iran was the big story, while this year, the shifting sands have been in Saudi Arabia and Iraq, with Riyadh relentless in its preparations for the Aramco IPO and Baghdad dislodging the head of the Kurdistan Regional Government (KRG) after a landslide (unsanctioned) independence referendum.
2017 also effectively saw the defeat of Daesh/IS in Iraq and Syria, concluding another bloody chapter in the seemingly never-ending story of proxy influence in the region. Conflict between Sunnis and Shias – dressed as Saudi vs. Iran – has taken the form of an apparently unwinnable civil war in Yemen, political tumult in Lebanon and the blockade of Qatar.
Amid all this, investor appetite in oil and gas has returned – bolstered by higher oil prices. This will be music to the ears of the region’s petro-state governments, which have been struggling to achieve budgetary breakeven amid OPEC-imposed cuts and reduced income.
Contract awards have been slow in Iran since Total’s landmark agreement on Phase 11 of the South Pars gas field, with many companies remaining uncertain about signing on the dotted line while US President Donald Trump remains determined to do away with the ‘Iran deal’ (JCPOA). Interest in the Islamic Republic remains high, though, with super-majors, and IOCs from Italy, Norway, Spain and Germany, providing stiff competition for the usual suspects from China, India and Russia.
Qatar has been beset with issues since Saudi, Bahrain, the UAE and Egypt accused Doha of supporting extremists, and sanctions were imposed. There appears to be more to this, with many suspecting that the blockade related more to Qatar’s warming relations with Tehran. Meanwhile, in early November, US firm McDermott was awarded a deal for phase 1B of the multi-billion dollar redevelopment under way by Qatar Petroleum (QP) of the offshore Bul Hanine field.
A host of engineering deals have also been awarded in Saudi and the UAE, with an eye toward increasing production capacity both in terms of oil and, particularly in the case of Saudi, gas. Countries throughout the Middle East have rapidly growing demand for gas, and are investing heavily in refining and petrochemicals to maximise the value garnered from what is produced.
More than US$2 billion of contracts were awarded by Riyadh in November relating to plans to increase gas production from the Haradh and Hawiyah fields – the southernmost zones of the supergiant onshore Ghawar field in the kingdom’s south-east. These are central to plans to ramp up gas output from around 12 bcf (340 mcm) per day to 23 bcf (651 mcm) per day by 2025.
The push for gas has not been limited to Gulf NOCs: Royal Dutch Shell announced earlier in the year that it would be ending its involvement in the 12.8 billion barrel Majnoon field near Basra, noting that the development was no longer a good fit with its corporate strategy. The super-major hastened to add that it would retain its involvement in the Basra Gas Co. (BGC).
Struggling to harness gas associated with oil production, Iraq has announced it will soon begin supplying Kuwait with 50 mmcf (1.4 mcm) per day initially, later rising to 200 mmcf (5.7 mcm) per day, from the supergiant Rumaila field close to the shared border.
Licensing rounds are relatively rare in the Middle East, but 2017 saw auctions opened in Iraq, Israel, Jordan, Lebanon and Oman. Those in Israel and Lebanon disappointed. Greece’s Energean Oil & Gas and a consortium of Indian parastatals submitted the only bids received by the Israeli government for the 24 offshore blocks tendered by Tel Aviv in 2016.
Meanwhile, the Lebanese round had been hotly anticipated for years, but only a single consortium – comprising Eni, France’s Total and Russia’s Novatek – submitted bids for two of the five offshore licences offered.
Meanwhile, Muscat awarded licences on Blocks 30, 31, 42, 48, 49 and 52, and launched a new upstream auction in September for Block 65, 43B, 47 and 51.
Rounds in Iraq and Jordan remain ongoing, and while Amman is unlikely to grab many headlines when it announces the results in early January, the terms of any contracts awarded are likely to be generous.
In late November, Baghdad put nine blocks up for auction, eight of which are located on the borders with Iran and Kuwait, and the ninth is the country’s first offshore acreage offered. Contract terms have been central to Iraq’s difficulties in making sustainable increases in production, and Oil Minister Jabbar al-Luaibi has talked up the ‘new commercial model’ on offer as part of this new licensing round, and that it differs substantially from the fixed fee-per-barrel technical services contracts (TSCs) signed during rounds in 2009/10.
Ian Simm, MEOG Editor
During 2017, several trends from previous years continued, while others emerged. North American drillers remained focused overwhelmingly on shale plays, with the Permian Basin continuing to dominate rig counts and production. The US output decline that had been under way for much of the previous year had already started to reverse at the end of 2016, and the country’s production is predicted to rise to 9.7 million bpd by December 2017. If this trend persists into 2018 and output averages above 9.6 million bpd for the year, it would be an all-time annual record for the US.
A shift in the US’ energy policy direction came this year when President Donald Trump took office, pushing an “America First” approach that emphasises energy dominance and aims to minimise regulatory hurdles for the industry.
As part of this, the US government has sought to ease some of the restrictions on drillers working on federal land, as well as pushing to open up more offshore and Arctic drilling. However, the impact of these moves will be limited for now. In the Lower 48 states, most drilling takes place on private – rather than federal – land, and state regulations in those states that dominate oil production already tend to be industry-friendly. In regions such as the Arctic – both onshore and offshore – project economics will ultimately dictate whether producers pursue increased development in the region, though Trump’s policies will ease the way as drillers await higher oil prices.
While shale drilling continued to dominate, a few offshore, oil sands and LNG projects bucked the trend, but these were largely ventures sanctioned before the oil price downturn that are only now reaching completion. Several major deepwater projects are under construction in the US Gulf of Mexico, including Hess’ 80,000 bpd Stampede project – a rare standalone deepwater development in the current price environment – which is due to start up in early 2018.
Meanwhile, Dominion Energy’s Cove Point LNG project is gearing up to begin LNG shipments by the end of this year, adding to the boom in US oil and gas exports that has been a particularly prominent trend in the US in 2017. In Canada, ExxonMobil’s Hebron heavy oil project offshore Newfoundland and Labrador started up in late November, and will ramp up to a peak capacity of 150,000 bpd. Onshore, Suncor Energy’s Fort Hills oil sands mine is also set to start up by the end of 2017, ramping up to its peak of 194,000 bpd within 12 months.
New FIDs on megaprojects have been rare, though. Instead, shale attracted more and more players, with super-majors beginning to play a far more prominent role in unconventional development. For instance, early this year ExxonMobil said it would pay up to US$6.6 billion to more than double its holdings in the Permian Basin. The super-major was subsequently reported to have drilled wells in the Bakken play that have laterals extending for 3 miles (4.8 km), and to be closing in on the 4-mile (6.4-km) mark.
Independents have also continued to push the boundaries of horizontal drilling, with Eclipse Resources reporting that by the end of the third quarter of 2017, it had drilled 11 “super-lateral” wells averaging 18,000 feet (5,486 metres) or 3.4 miles (5.5 km).
Shale drillers have continued to pursue these and other advances, helping them to raise production despite still fluctuating oil prices. However, by the end of 2017, a new focus on capital discipline among drillers – under pressure from shareholders and investors – was emerging. Meanwhile, there are concerns that the dramatic efficiency improvements achieved by shale drillers in the past two years are now slowing, with some of the gains attributed to cost-cutting among services providers and to a focus on drilling in the most productive sweet spots. Nonetheless, the knowledge gained will allow shale players to target even less productive regions more efficiently in the future. And while they are being urged to act cautiously and not undo any oil price gains by flooding the market with a surge of new production, further output growth and new records for various aspects of shale drilling can be expected in 2018.
Anna Kachkova, NorthAmOil and Unconventional O&G Editor
There are notable signs of growing optimism in Latin America heading into 2018, as better oil prices and more business-friendly governments in several countries encourage development.
In Argentina, YPF is betting on shale and tight plays to compensate for dwindling output from its conventional reserves as they mature. The NOC is turning to technology to ramp up unconventional drilling, and has set a target of 25% production growth between 2018 and 2022, taking total hydrocarbon output to 700,000 boepd in 2022 from an average of 558,800 boepd in the first three quarters of 2017.
At first the growth will be lower than 5% per year as new projects are started for shale and tight resources, but will then speed up as they shift from pilots to mass development. YPF is investing US$21.5 billion of its own capital in the 2018-22 programme and anticipates bringing in another US$7-8 billion from its partners.
Argentina’s shale potential has attracted companies such as Chevron, Dow Chemical and ExxonMobil to form partnerships with YPF. An estimated US$7 billion is being invested this year in the Vaca Muerta, with that figure estimated to rise to US$20 billion per year from 2019, according to government estimates.
This is helping to increase output from shale and tight plays, with unconventional gas production rising 23% to 32 mcm per day in September – 26% of the 123.4 mcm per day national total. Over the same period, shale and tight oil production climbed by 22% to 45,500 bpd in September from 37,200 bpd in September 2016, the data show. This means unconventional oil accounted for 9.4% of the 484,000 bpd of national production in September.
Mexico’s energy reforms are still having a positive effect on the country’s oil sector. Pemex signed the first farm-out agreement in its eight-decade history in 2017. The deal saw the company team up with BHP Billiton to develop the Trion deepwater field, in which it is the junior partner with BHP as operator.
Mexico’s next deepwater bid round is scheduled for January, with Pemex also looking to secure more farm-outs in 2018.
It is a pivotal year in political terms for Mexico, with a new president due to be elected in July. The poll will indicate the popularity of the economic reforms that have been carried out by the incumbent Enrique Pena Nieto.
Staying on the election theme, Ecuador elected a new president in 2017 with Lenin Moreno replacing Rafael Correa. Moreno painted himself as being more business friendly than his predecessor, and some of his early moves suggested he would pave the way for growth with a softer take on Correa’s harder socialist agenda.
A positive for the oil industry came when Moreno’s administration ruled that a form of production-sharing contract (PSC) be reinstated in favour of the old system that was based on service contracts. The PSC model is more attractive to E&P firms and ought to provide some uplift in the industry. That said, there have been some concerns raised about Quito’s attempts to renegotiate the terms of oil-for-loans deals with several Asian companies. The country’s economy continues to struggle in the wake of the oil price crash and any efforts to shift the goalposts in contacts are viewed with some suspicion by investors.
Brazil continues to crawl away from the wreckage caused by the Car Wash corruption scandal, with the biggest news of the year being some new pre-salt bid rounds. Two licensing rounds held late in late October attracted bids worth a combined total of almost US$2 billion, as IOCs took advantage of new rules allowing them to own and operate fields. More rounds are due in 2018 as Brazil looks to cash in on the pre-salt’s attractiveness.
Petrobras’ president Pedro Parente is still leading the company effectively and its divestment programme will continue into the new year. Parente wants Petrobras to become a more agile operator in the market, which will see its asset portfolio slimmed down substantially, allowing the company to focus its technological expertise on the pre-salt, where oil output is well above the 1 million bpd mark now. The Lula Field alone was producing around 700,000 bpd last year.
Venezuela’s slide into full economic collapse continued in 2017. Beleaguered President Nicolas Maduro now blames the failings of the economy on state-run PDVSA and has launched a purge against the top echelons of the company’s management. Indeed, it looks like only a military coup might unseat Maduro, otherwise he may be able to cling on until the presidential election scheduled for the end of 2018.
US sanctions on Caracas have been tightened, and the country’s situation is untenable. Oil production has suffered, with output now below 2 million bpd – a shocking state of affairs for the country with the world’s largest oil reserves (which exceed 300 billion barrels).
A more positive development has been Guyana’s emergence as an oil play. The future looks bright for the country’s fledgling oil industry. Since first announcing striking oil in the Liza field in May 2015, the ExxonMobil-led consortium has bumped up its estimate for recoverable high-quality crude oil in the area several times. The Guyana-Suriname Basin is now viewed as one of the world’s most promising new offshore exploration areas, a world-class oil resource possibly comparable to Angola on the west coast of Africa – and potentially holding as much as 10 billion barrels of recoverable oil.
Ryan Stevenson, LatAmOil Editor
2018 looks like it could be the year that the UK North Sea finally bounces back after the devastation caused by the oil price crash begins to subside.
There has been a flowering of interest in the North Sea in the last 12 months, driven by a rush of largely US-backed private equity companies. Three big deals have taken place recently. Siccar Point bought a stake in the Mariner field and then followed this with the acquisition of OMV’s North Sea assets. Chrysaor paid up to US$3.8 billion for a package of assets from Royal Dutch Shell. Lastly, Neptune agreed to buy Engie’s assets for US$3.9 billion. All three of these companies are backed by US-based funds.
The increase in interest has been driven by three factors: falling service costs, a newfound sense of stability in the oil price and the emergence of something like a consensus from buyers and sellers on asset prices. Furthermore, the UK’s regulator, the Oil and Gas Authority (OGA), has proved supportive and quick to respond.
Adding to the sense of optimism, tax changes that will come into force from November 2018 should encourage billions of dollars of new investment in the region and pave the way for more deals that help to extend the life of mature fields.
Falling service costs have also been a feature in Norway, with state-backed Statoil leading the way. In late 2017, the company switched on the control room for its Valemon remotely controlled offshore platform on the Norwegian Continental Shelf (NCS). It is the first time the firm has used a fully automated offshore design at one of its projects. Meanwhile, progress at the mammoth 440,000 bpd Johan Sverdrup project continues. Statoil this year reported that cost-cutting had helped the project remain competitive, with Phase 1 investment reduced by 20% to 97 billion (US$12.3 billion) between the initial development plan and the final design.
Norway continues to expand its role as a gas provider to Europe as buyers look to reduce their reliance on Russia. Norwegian gas exports to Europe grew by 7.8% to a record high of 123 bcm throughout the 2016-17 gas year. Shipments were significantly expanded when gas output from the Troll field was expanded to 36 bcm.
The gas year runs from October to October, and marks the point when purchase contracts begin. During the last 12-month period, overall gas demand in Europe grew by around 20 bcm per year, while production fell in many European countries, particularly the Netherlands. At the country’s Groningen natural gas field, the current production cap of 21.6 bcm per year will remain in place as an “interim measure” for at least a year, whilst the government has been ordered to draft a “new and better” policy.
Meanwhile, gas consumption in Germany has expanded substantially this year. Data show that during the first nine months of this year the country consumed 9% more natural gas than in the same period of 2016 as power and heating utilities plus industry used more gas as feedstock in their plants. Berlin is also at the heart of the debate about Europe’s future as an importer of Russian gas. The EU is stepping up its efforts to regulate Russia’s controversial Nord Stream 2 project in response to member states’ concerns that Moscow will use the pipeline for political ends.
Brussels is proposing to extend EU internal energy market rules to cover offshore natural gas pipelines. Starting at the end of 2018, all new and existing import pipelines would have to meet four principles, including non-discriminatory tariffs and so-called ownership unbundling, in which a gas supplier cannot directly own a pipeline. Expected to go operational at the end of 2019, Nord Stream 2 is designed to pump Russian natural gas to Europe underneath the Baltic Sea. The pipeline would double the existing Nord Stream pipeline’s capacity to 110 bcm per year of natural gas. The EU had initially wanted to block Nord Stream 2, but Brussels switched its position on the project this year. Now it is seeking a mandate from EU member states to negotiate with Moscow over their security concerns and, per the new proposal, to regulate the pipeline. If the EU’s market proposals become law, Gazprom will have to tweak Nord Stream 2 – but the project may yet go ahead. Five European energy majors have agreed to provide financing for the pipeline. They are: Engie of France, Austria’s OMV, Royal Dutch Shell and German pair Uniper and Wintershall.
Wintershall also made the news in late 2017 with reports that it was in talks on a merger with fellow German company DEA. A deal would create a major oil company with a market value of around US$12 billion and with an asset portfolio stretching around the globe.
Ryan Stevenson, EurOil Editor
Russia / Central Asia
Another year and Russia’s struggle to curb the use of foreign technology and equipment in the oil industry continues. The government has touted the successes of this import substitution drive, but progress on the ground is difficult to gauge.
In any case, the Industry Ministry recently claimed that 52% of equipment in the oil and gas sector was still being sourced from overseas, down from 60% in 2014. This suggests Russia still has some way to go to shield its oil industry from the risk of further sanctions.
Rosneft’s Zvezda shipyard project will play an important role in limiting the use of foreign marine equipment. According to Rosneft, the complex will secure orders for the construction of 178 vessels by 2035, many of which will be used in the oil industry.
Washington ratcheted up its Russian sanctions regime over the summer in retaliation for Moscow’s alleged interference in US elections. Worsening US-Russia relations are likely to derail Schlumberger’s second bid for a stake in Eurasian Drilling, Russia’s largest oilfield services group. Russian regulators have already indicated they will block the investment.
Russia’s majors have also made a cautious return to the offshore Arctic, with Gazprom spudding a well in the Kara Sea earlier this year. Rosneft identified a large oilfield in the Laptev Sea in June, using a horizontal well drilled from the coast. The discovery opens up a new area of interest for exploration.
In November, the Rosneft-led consortium operating the Sakhalin-1 project in the country’s Far East announced the completion of the world’s longest oil well – a 15,000m horizontal – at the Orlan platform on the Chayvo oilfield. Russia’s deal on output cuts with OPEC is likely to hit production hardest at mature oilfields, with producers reducing their use of enhanced oil recovery (EOR).
In Azerbaijan, BP agreed a contract extension at the flagship ACG project with the government in September, unlocking billions of dollars of investment for boosting oil recovery at the mature fields over the next three decades.
In Kazakhstan, the world-class Kashagan project that was launched late last year has continued to ramp up production, although at a slower pace than first expected as a result of unstable gas reservoir activities. The field has helped Kazakh oil production return to growth in 2017 after several years of decline.
Joe Murphy, Former Soviet Union Editor
Developers’ in the Asia-Pacific have been focused on cost-cutting measures and efficiency gains this year, with even national oil companies (NOCs) looking to trim the fat wherever possible.
While this has left little room for experimental technologies, there have been several advances this year in one unexpected field – methane hydrate development.
While Japan is widely considered to be a pioneer in developing drilling techniques relating to the unconventional fuel – which contains 10 times as much energy as other fossil fuels – things took an interesting turn when China delivered several technological breakthroughs that have effectively made it the global leader in the space.
In March, a research team from China’s Jilin University revealed that it had developed an alternative drilling technology for tapping onshore methane hydrate deposits. The technique uses a low pressure and high temperature steam pulse to extract the gas. The Jilin team said it was looking to apply its findings to offshore deposits and that it was in talks with a state shipyard to build a suitable rig.
While the Japan Oil Gas and Metals Corp. (JOGMEC) revealed in May that it had successfully completed its first methane hydrate production trial since 2013, it had to suspend testing on the initial well owing to a significant amount of sand ingress.
The Chinese government, meanwhile, said in July that its scientists had successfully extracted gas from deposits in the Shenhu area of the South China Sea during a 60-day production trial using a domestically developed technique that prevented sand ingress. Discussions are now under way regarding the development of a pilot site at Shenhu. All this paved the way for Beijing to approve methane hydrates as a new mineral resource in November, providing legal status for its exploration and development as an energy resource.
Given the ramp-up in activity this year, and the energy security implications the fuel holds for import-dependent China and Japan, it seems reasonable to expect further development in 2018.
At the same time, China is pushing forward with development of its shale gas resources. Sinopec’s Fuling project, the largest commercial shale gas project in China, will see its production capacity expand to 10 bcm this year. Fuling is the company’s primary shale gas asset in the Chongqing municipal region, where it hopes to lift production capacity to 15 bcm by 2020.
Even as domestic unconventional projects abound, Chinese gas importers have their eye on major LNG projects set to come online in Australia next year. Royal Dutch Shell’s Prelude FLNG project, the biggest such unit in the world, is on course to come on stream in 2018, though it may slip from its intended start-up early next year. Inpex’s onshore Ichthys LNG plant, meanwhile, is expected to come online in the first half of 2018.
Both projects will help add to growing global supply even as LNG demand from China’s private and state sectors is forecast to accelerate.