It’s a smaller, more focused exploration world as we start 2018. Elaine Maslin discusses the main themes for 2018 with Wood Mackenzie’s Andrew Latham (First published in the January 2018 OE, access full issue here).
|A drillship with Table Mountain, offshore South Africa, in the background. Photo from iStock.|
First, let’s look back at 2017. Wood Mackenzie’s Vice President Global Exploration Andrew Latham says that the year saw the trend towards a smaller scale exploration industry, with continued attention being paid to deepwater. He expects this to continue into 2018. In 2017, operators were acreage “re-loading,” and getting back to profitability, although exactly how profitable they are now was yet to be seen, as of late 2017.
Global conventional on- and offshore exploration spend was forecast at US$35-40 billion for 2017, and landed at $40 billion, according to Wood Mackenzie ($35-40 billion is 30-40% of what it was prior to the downturn). For 2018, it is expected to slip to $37 billion.
In terms of exploration results, 2017 didn’t hold many surprises. The 1.4-2 billion bbl (in place) Zama light oil discovery, by Talos Energy in shallow waters offshore Mexico, was not seen as a huge exploration risk, Latham says. There were also continued exploration successes in Guyana, where ExxonMobil made its fifth find, further building on the massive 2-2.5 billion boe (recoverable) 2015 Liza discovery. There were also more gas discoveries in Mauritania, home to Kosmos/BP’s “world class” Tortue field, with 25 Tcf estimated in the Greater Tortue Complex. Decent new volumes in Russia were also not unexpected.
Some discoveries in lower horizons in the Campos basin, offshore Brazil, by Petrobras, which could hold more than 700 MMboe, were more notable, Latham adds.
2018: What lies ahead
For 2018, a smaller, focused-exploration industry is set to remain in place. “There are fewer companies now that are serious about exploration than we have seen for quite a while,” Latham says. “That’s really an extension of what we saw in 2017. Side by side with that, there’s growing awareness that most of those companies are chasing similar things – it’s all about deepwater sweet spots, particularly oil prone ones, and particularly around the Atlantic Margin.
“And because they [those exploring in these areas] have similar perspective on all of those, that means the level of competition is getting much higher. The most extreme example of that was in the Brazilian round in October,” with higher prices paid for access to acreage, Latham says.
Brazilian regulatory agency, ANP said that the 2nd round generated approximately $1.05 billion in signature bonuses and $93.4 million in planned investments. Meanwhile, the 3rd pre-salt round generated about $876 million in signature bonuses and will bring in approximately $140 million in investments.
For 2018 licensing rounds, where big explorers see potential, big bids are likely to continue, Latham says, which could create a problem around high access to acreage costs, we haven’t been seen for a couple of years now.
The refocus on deepwater exploration is partly due to it becoming more attractive commercially. “We certainly see a lot of the best deepwater oil plays breaking even (with 10% full cycle return as a breakeven) in the $40/bbl range,” Latham says. “That’s Guyana, Brazil, Senegal... That’s being enabled by low exploration and development costs. Drilling costs in particular are much lower. It’s also enabled by companies focusing on the best rocks with high-permeability, and so higher production rates per well.”
A Transocean drillship stationed in Guanabara Bay, Brazil, with the Sugar Loaf in the background. Photo from iStock.
Taking a wider look, the exploration and production landscape offers up an interesting theme. Onshore unconventional is typically seen as one of the threats to the upstream offshore oil and gas business (alongside solar and other renewables in the longer term). Deepwater exploration has also been seen as an expensive play.
Yet, according to analysis by Wood Mackenzie looking at trends over the past 100 years of exploration, “A largely onshore history [of oil production] is [now] becoming polarized between deepwater and unconventionals.” For many serious explorers, the choice is between unconventionals or deepwater, Latham says.
Wells to watch
So, where are the wells to watch for 2018? Latham says that 2018 has more potential than last year. His top picks are:
- Guyana – ExxonMobil is drilling its latest well offshore Guyana in the Stabroek Block: Ranger-1. It spudded 11 October 2017, using the Stena Carron drillship, and was due to take three months.
- Brazil – More activity is expected offshore Brazil, including possibly Total’s Foz do Amazonas (Mouth of the Amazon) well, if it secures regulatory permits. An application to drill was denied in 2017, with the environmental regulator Ibama (Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis) citing lack of information. Environmentalists and scientists say it’s too close to the Amazon reef.Brazil – Also in
- Brazil, Petrobras is planning wells in the Espirito Santo basin, which would prove new plays, Latham says.
- Mexico – Meanwhile, Pemex is eyeing the Yaxxtaab-1 wild cat in the shallow waters of the Campeche Basin, offshore Mexico, billed as the first pre-salt well offshore Mexico, while Total is planning a wildcat in the Perdido Fold Belt.
- Aruba – Repsol is planning a wild cat well off this small Caribbean Island.
- Namibia – Tullow Oil is aiming to start drilling on the Cormorant prospect in the Walvis Basin, offshore Namibia, in September. While it’s not the biggest well, a discovery in Namibia would be significant, Latham says.
- Senegal – BP is due to drill the Requin-Tigre (Tiger Shark) well, with Kosmos, outboard of the Tortue discovery. It is estimated to have 60 Tcf resource potential.
- South Africa – Total has hired the Deepsea Stavanger to drill a wild cat well offshore South Africa. “Total are very excited about it. It’s a challenging environment but, by all accounts, the subsurface looks very good,” says Latham.
- Gambia – FAR is planning to drill the Samo prospect late 2018. Samo is believed to be similar to the SNE field properties, in neighboring Senegal. It will be the only exploration well to be drilled offshore The Gambia since the Jammah-1 well drilled in 1979.
- Morocco – Eni has lined up the Saipem 12,000 drillship to drill in the Rabat Deep Offshore license offshore Morocco, starting Q1.
- Nova Scotia – BP is planning to drill a single exploration well, in the Scotia Basin, offshore Nova Scotia, Canada, starting in Spring 2018. Drilling is expected to take 120 days using the West Aquarius semisubmersible.
- Norway – Statoil may go back to the Korpfjell prospect, which failed to offer commercial hydrocarbons in 2017, and drill to test another reservoir.
Other areas to watch include Montenegro, Cyprus and Portugal, where Eni is planning to drill, and Papua New Guinea, which Total is assessing.
“All the majors are the ones to watch in these wells and any licensing rounds coming up,” Latham says. “There’s also a cohort of the usual suspects, Cairn Energy, Tullow Oil and Kosmos.
“But, the number of fairly committed, fairly high-impact explorers is only about 15,” he continues. “The number that can move a large discovery in deep water through to development, as operator, is smaller again. It’s a pretty small club of companies outside the majors, i.e. Petrobras. There are pros and cons to limited competition. For governments and small companies, it means there’s a limited range of potential operators for your projects.”
Deep, but effective
Water depth in which explorers were drilling reached new records in 2016, with the Raya well, offshore Uruguay. But, while water depths have remained high, well depth has seen a retreat. Deepwater exploration is targeted, and not focusing so much deep horizons with high-pressure, high-temperature objectives, Latham says.
This is part of the reason drilling has been cheaper, as wells have not been as long or complex. Drilling costs could also continue to fall, as there are still rigs out there that remain on the high day rates signed pre-2014, due to the length of term for which they were hired. As each of these finally end their term, rates will drop, reducing exploration costs further, Latham notes. “This is one of the reasons why we might see lower spend next year, but we won’t see fewer wells,” he adds.
Looking more at specific “heartland” regions, the US Gulf of Mexico has seen success and is likely to continue with some success in infrastructure-led exploration, such as that by LLOG, which sees 20-30 MMboe scale prospects tied into existing infrastructure.
In the UK North Sea, there is also some infrastructure-led exploration, but some companies are trying some new play exploration, Latham says. “I see this as being probably what the North Sea needs,” he says.
Statoil made a discovery in the eastern Moray Firth this year, while BP is drilling carboniferous prospects in the southern gas basin. “It’s a slightly risker but larger test, and we’ll probably see more of those generally different types of play tests this year as well, targeting 100 MMbbl.”