Gazprom unveils revised strategy for the Russian shelf
November 29, 2017
The gas giant’s plans assume a slow recovery in the global energy market. Joe Murphy reports from Moscow
The oil price crash and the introduction of international sanctions in 2014 brought a number of Russia’s offshore projects to a standstill. Drilling work was halted as the country’s oil and gas producers shifted their attention to cheaper plays on land. Authorities in Moscow later declared a moratorium on the issue of new offshore licences in the Arctic, aware that operators would struggle even to meet their existing exploration commitments. Some projects on the Russian shelf cannot move ahead, at least in the near term, without access to advanced Western technologies that are restricted by the US and EU sanctions regimes. Others have simply been rendered unprofitable to develop under current market conditions.
In recent weeks, however, Russia’s natural gas giant Gazprom and its oil-producing subsidiary, Gazprom Neft, have shed light on their development plans off the coast. Their revised schedule for bringing new offshore fields into production contrasts dramatically with forecasts made in the heady years when oil traded at over US$100 per barrel. This more cautious strategy assumes, at best, a slow recovery in the global energy market, in line with the Russian Economy Ministry’s guidance that oil will still be selling at under US$50 per barrel in 2020.
However, the strategy also leaves open the question of whether Gazprom will be able to secure the advanced technology necessary to develop some of the more challenging of these projects, either through domestic innovation or assistance from other suppliers, such as China.
Gazprom’s offshore strategy to date has focused mainly on the two geographical areas – the western Arctic and the Sea of Okhotsk off the coast of Sakhalin.
Pechora is host to Russia’s only producing field on the Arctic shelf. Gazprom Neft’s Prirazlomnoye deposit, situated some 60 km from the mainland in a water depth of 20 metres, was launched in late 2013. The field delivered an output of 42,000 bpd in 2016, but this is slated to rise to 50,000-52,000 bpd this year and over 60,000 bpd in 2018, thanks to continued drilling work. Output is seen eventually rising to 90,000 bpd under the field’s first development stage. Prirazlomnoye produces a blend of oil containing high levels of sulphur, making it an ideal export to refineries in northwestern Europe. It holds over 70 million tonnes (513 million barrels) in recoverable oil reserves.
Gazprom Neft’s CEO, Alexander Dyukov, noted last week that the company would conduct seismic work at Prirazlomnoye next year. This is the first stage of a secondary development phase that will target the field’s deeper layers. Prirazlomnoye remains profitable despite low oil prices, with Gazprom Neft boasting a production cost of only US$10 per barrel at the site late last year. Like other Arctic projects, it also enjoys a zero rate on export duty and other tax breaks. Still, Prirazlomnoye’s development, which was planned as early as 1992, has been mired by delays and cost overruns, highlighting the operational challenges presented in the region.
Some 16 km north of Prirazlomnoye lies Gazprom Neft’s Dolginskoye oil and gas field, discovered in 1999. The company sank a well at the site in 2014, but plans for another two wells in the following year were cancelled after the market collapse.
However, Dyukov noted last week that the explorer aimed to conduct a shoot a 3D seismic survey at the field in 2018 with a view to drilling another well the year after. A final investment decision (FID) on this well has not yet been taken. At present, the field is estimated to comprise over 200 million tonnes (1.47 billion barrels) of oil and gas in recoverable reserves.
Gazprom Neft may be unable to develop Dolginskoye further without the Western expertise and technology it used at the site in 2014. International service companies Schlumberger and Weatherford both provided technical assistance at the project prior to sanctions.
Gazprom Neft is looking for a foreign partner at the project, having signed a memorandum of understanding (MoU) with India’s ONGC on joint development in March this year. However, this partnership is designed to help shoulder costs rather than secure technology and expertise. Production at Dolginskoye is still a long way off, with Gazprom Neft estimating even before the oil price crash that the field would only be producing a modest 90,000 bpd of oil by 2027. Given delays, it is unlikely that this milestone will now be reached before the 2030s.
Gazprom’s gas projects in the Arctic are an even more distant prospect.
In a strategy outlining its strategy until 2040, released earlier this month, the company said it aimed to launch the previously shelved Shtokman gas condensate field on the Barents Sea shelf in 2028. Gazprom teamed up with France’s Total and Norway’s Statoil in 2007 to realise the troubled project. However, the partners were unable to agree on a feasible means of commercialising the field’s massive gas reserves, estimated at 3.9 tcm. Statoil and Total later exited the plan, with Gazprom conceding that the field would be left for future generations to develop.
Part of the issue was Shtokman’s gas was originally earmarked for the US market, but this became a less feasible option following the shale gas revolution in Texas and North Dakota. The field is stranded 550 km northeast of Murmansk at water depths of up to 340 metres.
In its strategy, Gazprom said the Kara Sea’s Leningradskoye gas field was not scheduled for launch until either 2034 or 2040. The field has C1+C2 reserves of 1.05 tcm of gas and 3 million tonnes (27 million barrels) of condensate. Gazprom completed an exploration well at the site earlier this year, using a Chinese-built rig.
The company also controls Rusanovskoye field, also in the Kara Sea, which is estimated to hold 779 bcm of gas and 70 million barrels of oil in ABC1+C2 resources. Bu exploration plans have been disclosed for this site.
Despite their large reserves, these gas projects represented challenging projects even when the oil market was bearish. As such, their fate remains uncertain.
Gazprom has made speedier progress in the Sea of Okhotsk, where it is developing several fields under its Sakhalin-3 project.
Last week, Dyukov said he expected to see the recently discovered Neptune oilfield come on stream in either 2025 or 2026. Previously, the executive suggested it could eventually reach an output of 90,000-100,000 bpd. The deposit, situated on the Ayashsky block, is located 55 metres from the shore of Sakhalin in a water depth of around 60 metres. Gazprom Neft confirmed the field’s existence earlier this month after a successful result at an exploration well. It is currently believed to contain 255 million tonnes of oil equivalent (1.87 billion barrels) of mostly crude oil, although exploration at the site continues.
Dyukov noted that the firm was not looking for a partner at Neptune at present, but did not rule out this option in the future. He stressed that production from the field could generate profits even at current oil prices.
Gazprom’s other Sakhalin-3 licences are for the nearby East-Odoptinsky and Kirinsky blocks. Exploration at the latter area led to the discovery of the Kirinskoye, South-Kirinskoye and Mynginskoye gas fields. Kirinskoye came online in 2014 and is scheduled to reach a peak output of 5.5 bcm per year.
According to its long-term strategy, Gazprom does not expect South-Kirinskoye to come online until 2023, versus an earlier launch date of 2021. It will eventually produce up to 21 bcm per year of gas, drawing from a resource base of 1.4 tcm. The field was targeted directly by US sanctions in 2015, complicating Gazprom’s development plans. Mynginskoye, meanwhile, is scheduled to start production in 2034.
In the last several years, Gazprom and other Russian energy companies have touted their progress in developing domestic technology that can substitute foreign imports. But according to most accounts, the Russian oil industry still remains heavily reliant on international suppliers. A report by the Russian Industry Ministry, which surfaced in the local press in February, claimed that foreign imports still accounted for 80% of equipment and technology used in the Russian upstream sector.
This suggests that Gazprom still has some way to go before it can advance its more technologically challenging and costly projects on the shelf without outside assistance.