Deepwater Gulf exploration starts to rebound
The US Gulf of Mexico is experiencing an uptick in exploration, but the way companies operate in the region has changed due to the downturn in oil prices
Exploration in the US Gulf of Mexico appears to be on the up after several years in decline. However, the lower oil price environment has forced operators in the region to change their approach to exploration, and this trend is still playing out.
A return to the development of new megaprojects appears likely in the coming years—and indeed necessary if producers are to replace lost barrels from mature, declining operations. For now, a strategy focused on subsea tiebacks and the expansion of existing operations is the preferred option for many Gulf drillers. At the same time, though, a few—mostly majors—are pushing to open frontier deepwater regions. These players will be instrumental in kicking off a new cycle of megaproject development.
The outlook for Gulf exploration is increasingly positive, following several years characterised by low activity, despite mounting concerns that more investment was urgently needed in order to meet future oil demand. Mfon Usoro, an upstream research analyst at consultancy Wood Mackenzie, says that based on activity seen so far this year, Gulf exploration is on track to increase for the first time in three years. "We've had about four discoveries this year so far, estimated at slightly over 200mn bl oe," she adds.
In part, the uptick can be attributed to smaller companies coming back to the region. Usoro notes that, of the discoveries announced so far this year, only Shell's Blacktip can be considered a major find, estimated by Wood Mackenzie at around 200mn bl oe.
The consultancy estimates all the other discoveries hold reserves below 20mn bl oe. Usoro notes US independent W&T Offshore's recent discovery with the Gladden Deep well, which the operator estimated as having 7mn bl oe of reserves on a gross basis. "Previously you would never have heard of 7mn bl oe being commercial and a company wanting to go forward with it," she says.
Shell hopes Appomattox will be at the centre of subsea development in the Norphlet
Despite its size, Gladden Deep is illustrative of the broader trend of Gulf operators trying to leverage existing infrastructure. "The hub and spoke strategy with infrastructure-led exploration (ILX) has been the favoured means of exploration in the Gulf of Mexico in recent years," Joachim Gregersen, an analyst at the consultancy Rystad Energy, says. "Gulf of Mexico explorers still support expectations of the strategy being carried forward in the coming years, as a focus on shorter lead times and rapid returns on investments is rubbing off from US tight oil."
The high risk of drilling a dry hole, combined with the costs involved, has been a major deterrent for operators looking at deepwater Gulf projects in recent years, but ILX mitigates this risk to some extent. "With ILX the prospects have, more often than not, somewhat similar and known reservoir characteristics, which helps with reducing the risks associated with exploration," Gregersen says.
However, while the number of discoveries is on the rise, combined they account for an increasingly smaller volume of oil. Rystad estimates that about three quarters of the finds made in 2018 were infrastructure-led, but that this represented less than one-third of the discovered volumes. "The share of ILX discoveries has remained more or less the same since 2014. This provides medium-term concerns around the ability of these discoveries to replace the barrels lost from fields in decline," Gregersen says. "With short duration and scope for one to two wells in the current rig contracts we don't see this trend changing any time soon."
Bucking the trend to an extent are the majors, who never left the Gulf and have more resources to devote to deepwater drilling. "The majors are targeting more material barrels and more complex geologic plays," Usoro says. However, they have also had to make changes to how they operate, in order to improve the economics of their Gulf projects. Even as they continue to push the boundaries of deepwater exploration, majors are increasingly focused on boosting production from their existing platforms, via subsea tiebacks and other ventures.
BP, for example, announced in May that it had sanctioned the Thunder Horse South Expansion Phase 2 project. This is the latest in a series of expansions at Thunder Horse—where BP also implemented a water injection project to boost production in 2016. BP says there are further ILX opportunities across its Gulf platforms. The company credits breakthroughs in seismic imaging technology and reservoir characterisation as being responsible for its recent discoveries. It has identified a further 1bn barrels of oil in place (OIP) at Thunder Horse, as well as an additional 400mn barrels of OIP at Atlantis. Further seismic imaging is planned for both fields.
Shell is also pursuing a strategy of maximising the production potential of its hubs in the Gulf, including through waterflood and tiebacks. The company notes, for example, that there has been a nearly 80pc increase in production from its Mars corridor since 2013, with new output attributed to well management, in-field and near-field development and optimised waterflood performance.
But even Shell's existing hubs are now pushing into new frontier regions, with the start-up of the Appomattox project in May marking the first commercial production from the Jurassic Norphlet formation. Shell hopes Appomattox will be at the centre of subsea development in the Norphlet, having made other discoveries in the formation including Vicksburg, Rydberg, Fort Sumter and Dover. And despite focusing on near-field targets, Shell says some of its exploration wells will be aimed at new geological opportunities in frontier basins.
200mn bl oe — Shell's Blacktip discovery estimate
Wood Mackenzie's Usoro agrees that the Jurassic is worth watching, with Chevron's Ballymore find in the play estimated by the consultancy to have reserves of around 400mn bl oe. The Lower Tertiary—or Paleogene—also remains of interest to Gulf operators, having generated considerable buzz before oil prices started falling.
The deeper, ultra-high pressure Lower Tertiary fields are thought to have major potential. "We estimate those fields hold over 2bn bl oe in reserves," says Usoro. Progress could be made soon, with Wood Mackenzie expecting Chevron's Anchor to be sanctioned in 2019. This could lead to additional prospects in the same formation being drilled out, as new subsea tieback opportunities emerge and make it more cost-effective to explore the region further.
Norway's Equinor agrees that there is considerable potential to be found in the Paleogene as well as in the more mature Miocene, which is popular among the independents returning to the Gulf.
One notable exception to the rule that bigger players dominate frontier regions is US independent LLOG Exploration, which is moving into the lower tertiary. The company brought Buckskin-a subsea tieback to the Lucius spar-on-line in mid-June, and Usoro notes that LLOG recently took on another Lower Tertiary field with Shenandoah.
Rystad's Gregersen believes that LLOG's recent moves—selling Gulf assets to Murphy Oil and picking up new leases in the deeper parts of Green Canyon and Keathley Canyon—signal a shift back to exploration for the company. LLOG may be an outlier for now, but if Lower Tertiary activity picks up again, other independents may begin to follow in its footsteps eventually.
"A shift in geological targets from the typical Miocene sands to the technically challenging Lower Tertiary trend will likely not occur before the majors prove it technically viable," Gregersen says. "When that happens, we might see a new cycle of megaprojects being approved." This is still some way off, but Gulf operators appear to be showing early signs of moving in that direction.