Despite reductions in exploration spend, work goes on. Elaine Maslin speaks with Wood Mackenzie’s Andrew Latham to find out where explorers will aim their drillbits this year.
Stena DrillMAX. Photo from Stena Drilling.
With investment expected to be less than half of what it was in 2014, operators are likely to be spending their cash more wisely than ever in 2017.
The global exploration budget is expected to be US$40 billion in 2017. This is about the same as in 2016, despite oil prices rising and stabilizing somewhat, but it is less than half that during 2012-2014, according to Wood Mackenzie.
While there may be an uptick in the future, 2017 isn’t likely to see much of it, says Andrew Latham, vice president, Global Exploration Research at Wood Mackenzie, with spending expected to remain flat through to 2018. So, where will the limited 2017 spending go?
Overall, there’s likely to be a strong focus on nearfield or “infrastructure-led” exploration, where it is easy to monetize, Latham says: value is key. Shell, for example, said that 80% of its $2.5 billion exploration investment would be in this realm, Latham adds. “That emphasis on nearfield, low risk, but high value barrels, will count for many in the industry.”
But, those who are looking for a bit more excitement, there are a few glimmers of light. Some companies remain enthusiastic about deepwater exploration, and there are those looking at where positive break even economics give them an edge.
South America has a couple of hot spots, including Guyana, next to Venezuela, where ExxonMobil has focused its interest. The supermajor made its giant >1.4 billion boe Liza find there in 2015, and has been assessing it ever since. Liza was the first commercial discovery in the country for 50 years. Guyana’s government said that Exxon could make an investment decision in 2017. It’s large scale oil and that can mean breakeven returns that work even below the current oil price, Latham says. The fiscal regime also makes Guyana favorable, he says.
Total’s apparent success on the Raya well offshore Uruguay, between Brazil and Argentina, as well as interest in the country’s latest licensing round, could see a return to drilling there. The Raya reservoir was believed to be good, but precious little information has been released, Latham says. Perhaps the majors know more: Exxon, Statoil and Total have taken more equity in Block 13, in Guyana’s Punta del Este basin, in a deal with Shell. Block 13 had originally been awarded to BG Group, now part of Shell.
The Dhirubhai Deepwater KG2 drillship. Image from Transocean.
A similar trend could be mirrored on the other side of the Atlantic, on the West African Transform Margin; another area where ExxonMobil has spun the bit. Recently, ExxonMobil spudded its deepwater Mesurado-1 well in Liberia-13 Block – Exxon’s first in the country and one of the first there for a while, Latham notes. The Mesurado-1 well is in 2438m (8000ft) water depth, according to partner Canadian Overseas Petroleum. The Ebola outbreak in 2014 delayed drilling.
Independents Kosmos Energy and Cairn Energy, while smaller players, have some cash with which to play, and will be looking closely at Senegal, following their recent discoveries there.
Kosmos, which also has a hand in exploration offshore Suriname/Guyana in South America, has played a leading role in opening the Mauritania/Senegal Atlantic Margin basin, West Africa, with the Greater Tortue Complex discoveries comprising some 25 Tcf of discovered gas resource offshore Senegal. The firm is now planning a second exploration phase, further offshore – and looking for liquids. The “multi-million” barrel Requin-Tigre (Tiger Shark) is on the firm’s mid-2017-start drilling list, alongside the Lamantin prospect.
In December 2016, BP announced it would join Kosmos off Senegal and Mauritania, making a $1 billion investment in a region it hopes will become a future LNG hub.
Meanwhile, Cairn, which made the major 2014 SNE and FAN discoveries offshore Senegal to the south of Kosmos’ acreage, plans to further prove up and add to this resource, as it works towards a development concept. The firm has contracted the Stena DrillMAX drillship for two-wells, with options, starting Q1 2017. The current outline plan is a 30-well floating production development, potentially starting up in 2021-23.
Myanmar, once bereft of activity due to international trade embargoes, has been back in the limelight, with large discoveries, including the Thalin-1 well in AD7 block in February 2016, by Woodside Energy. The activity will continue in 2017: Woodside recently contracted the Dhirubhai Deepwater KG2 (a deepwater drillship) for a year-long campaign in the region in 2017.
Another possible hot spot could be the eastern part of Norwegian Barents Sea, which has recently been opened to the industry. The Norwegian Petroleum Directorate (NPD) estimates that almost half of recoverable undiscovered resources remaining in the Norwegian Continental Shelf are expected to be proven in the Barents Sea.
In August 2016, Statoil set out its 2017 drilling plans for the Barents. While the majority of Statoil’s 5-7 well campaign will focus on existing areas – around Goliat for example – the Korpfjell well, in PL859 (which covers 12 blocks), awarded in the 23rd licensing round, will break new ground, being to the far east and north of Norway’s licensing area.
It is set to be a highly watched well. NPD says that PL859 was the most sought-after license in the round. Statoil describes Korpfjell as being high-risk/high-reward, while partner Lundin believes a structural closure in the license to be 850sq km and over four times the size of that seen in Johan Sverdrup, according to Edison, an investment research firm.
Lundin also sees a 570sq km aerial closure in the Signalhornet Dome in PL857 and describes the potential of the region as being in the order of multi-billion barrels.
Over in the US Gulf of Mexico, however, exploration is more challenging, with deeper wells making costs higher, Latham says. Discoveries in 25,000ft deep reservoirs make break-even prices high. “There is lots of exploration potential, but it is slightly up the cost curve.”
Drilling expectations have shifted somewhat offshore Australia. BP had been working towards drilling on the Great Australian Bight. But, after numerous knock-backs by Australian authorities, amid strong public opinion against drilling in this area, the firm dropped its plans. That was really one of the main unknown plays in Australia,” Latham says. The spotlight now falls on Chevron; however, it’s not likely Chevron will drill here in 2017, he adds.
Beyond 2017, the Black Sea could draw investment. A number of gas discoveries have been made offshore Romania – including the Domino gas discovery. Most recently, Total revealed it had made a deepwater oil discovery offshore Bulgaria. While little has been disclosed about the find, the fact that it is oil, not gas, will heighten interest, Latham says.
The positive news from Bulgaria seems to have inspired drilling in the Turkish Black Sea, Latham says. It may be good timing. “It’s a very isolated drilling region and always been high cost because of that,” he says. “As costs are low at the moment, it’s quite a good time for those that can afford [it].”
Trying something different
It’s not all about seeking out plays in new basins or frontiers, however. Some are also taking a new look at mature areas like the North Sea, such as Statoil.
“It’s been our view for a while that UK exploration is stuck in a rut and destroying value, even at $100/bbl,” Latham says. “Success rates have not been great and discovery costs are exceedingly high.” What has been found has often been pools too small to commercialize, he adds.
“Statoil is trying to do something new in the UK,” he says. The firm has three firm wells planned for 2017, and at least two are trying new things. One is east of Shetland, the Jock Scott prospect, in which BP recently agreed to take a stake. Another, in the central North Sea, will be on a trend with Premier Oil’s Bagpuss heavy oil discovery, which sits in a shallow reservoir (the likes of which Statoil has been addressing in the Barents Sea).
West of Shetland will also be a focus for Nexen, which has two high-pressure, high-temperature wells planned for there, including one on Craster, mid-2017. This is another prospect in which BP has picked up interest.
While frontier plays are less fashionable in this low-capex environment, operators are not idle. “What we are seeing is the bigger companies are using this opportunity to grow their exploration portfolios,” Latham says, “acquiring licenses at low cost, which contrasts to how difficult it was when oil was $100/bbl. They are taking options for medium-longer term, with not so many commitment wells. Clearly, companies have eye on a 5-10 year view of potential higher prices.”
Fred. Olsen’s Bolette Dolphin drillship in Colombia. Photo from Anadarko Petroleum.
Colombian exploration heats up
By Audrey Leon
After forming its own offshore-focused offshoot in January 2016, Colombian state oil company Ecopetrol expressed its intentions to stabilize its production with a more “aggressive” exploration drilling program this year .
“We will be aggressively drilling in the offshore in Colombia next year,” said Ecopetrol CEO Juan Carlos Echeverry on a November 2016 conference call.
Most of the offshore projects underway are in the northwest of the country, in the Caribbean Sea, an area which Ecopetrol called important to its plans. Ecopetrol’s Exploration Vice President Max Torres noted that of the 15 exploration wells the Colombian operator plans to drill in 2017, five will be offshore.
“Our big bet or big promise is offshore,” Torres said during the conference call. “[In 2017], we’re going to be drilling Brahma, which is a sort of an appraisal of our discovery in Aragua, and two new prospects like Molusco and Siluro. So, as you see, aggressive activity and big promises for the future.”
Colombia actively marketed its offshore resources during its 2014 Round, offering 13 offshore blocks, 10 in the Caribbean and three in the Pacific. The round saw Repsol and Anadarko pick up further exploration blocks.
US Independent Anadarko had previously announced in its 31 October operations report that it will drill the Purple Angel-1 prospect in Q4 2016, Anadarko operates Purple Angel and Kronos with 50% working interest. Ecopetrol holds the other 50%.
The Purple Angel-1 appraisal well is designed to test objectives similar to those of the Kronos discovery. Kronos, in a frontier deepwater basin in the Fuerte Sur block, was drilled to 12,200ft (3720m), and encountered 130-230ft (40-70m) of net natural gas pay in summer 2015. Fred. Olsen’s Bolette Dolphin drillship drilled Kronos prospect and is under contract to Anadarko until 2018. Vessel Tracker placed the drillship near Cartagena, Colombia as of 19 November.
The Brahma prospect is part of the Tayrona Block, which is operated by Brazil’s Petrobras (40%). It’s partners on Tayrona include Ecopetrol (30%), Spain’s Repsol (20%) and Norway’s Statoil (10%). Tayrona, offshore Guajira, is home to the 2014 Orca-1 discovery.
The Molusco (Spanish for Mollusk) prospect is inside Block RC-9, operated by Ecopetrol along with partner India’s ONGC.
The Siluro prospect is inside the RC-11 block, operated by Spain’s Repsol (50%) in partnership with Ecopetrol. According to a 2014 presentation from Repsol, Siluro is in 90m of water and will target the lower Miocene carbonate.
Anadarko also announced in late October that it has completed the Esmeralda 3D seismic survey, covering almost 30,000sq km, making it Anadarko’s and Colombia’s largest 3D survey and one of the largest 3D surveys in the world.