2017: Exploration hot spots

Elaine Maslin

December 21, 2017

Senegal and Mauritania are set for a raft of activity as two major projects move towards putting both countries on the deepwater map, while Cyprus waits in the wings. Elaine Maslin reports. (First published in the December 2017 OE.)

Rokhaya Diallo Gunning. Photo from Offshore Energy.

After dwelling in relative oilfield obscurity for decades, Senegal is set to make it on the map as a deepwater offshore oil and gas producing nation.
Two major deepwater projects, in 1000-3000m water depth, are brewing in the country, which has otherwise only hosted minor levels of onshore production.

Following their “basin opening” discoveries in 2014-15, first gas is targeted on the Greater Tortue Area LNG development in 2021, with first oil on the SNE (Shelf North Edge) field following, in 2021-23. Both projects have been driven by independents, Cairn Energy and Kosmos Energy.

The Tortue-1/Guembeul-1 gas find is thought to be the largest ever offshore West Africa with 15 Tcf of recoverable dry gas discovered so far, and up to about 25 Tcf with the play extending discoveries of Marsouin-11 and Taranga to the north (in Mauritania) and south (Senegal).

Meanwhile, SNE, which was 2014’s world’s largest oil discovery, is described by investment analysts Mirabaud as the “jewel in the crown.”

Rokhaya Diallo Gunning, chief of geological basin division, Petrosen, Senegal’s national oil company, told a global opportunities session at the Offshore Energy exhibition and conference in Amsterdam, in October, that until 2014, Senegal was largely underexplored. There are eight offshore production sharing contracts at the moment and one open offshore block.

Starting in 2014, the country saw the first offshore drilling since 1993. This resulted in Cairn Energy making the FAN-1 and SNE-1 discoveries in the Rufisque, Sangomar and Sangomar Deep production sharing contract (PSC), which stretches from the shoreline to deep offshore.

The following year, Kosmos made the Tortue-1 (Ahmeyim), discovery, followed by Guembeul-1 in 2700m water depth in 2016, both on the St. Louis Profond license, and then Ahmeyin-2, in Block C-8 in neighboring Mauritania – which together form the “GTA finds” (Guembeul, Tortue and Ahmeyim). Together, these amount to 25 Tcf of discovered gas resource along the inboard Senegal River fairway, with potential of over 50 Tcf, Gunning says.

Kosmos made the Teranga-1 discovery in 2016, in 1800m water depth in the Cayar Offshore Deep license. With BP now on board, the even further offshore Yakaar-1 discovery, in 2550m water depth, was the first successful test of the outboard basin floor fairway, Gunning says. Yakaar is also in the Cayar Offshore Deep.

Photo from OE Staff.

SNE options
After a string of appraisal wells in 650-1400m water depth, including drill stem tests, and further exploration wells, Cairn is planning its development options for the SNE field.

Gunning says that Cairn is planning a phased, standalone floating production (FPSO) development, targeting 75,000-125,000 bo/d, with 1-2 MMbbl oil storage, with potential for expansion with satellite developments. This could be using an existing, redeployed FPSO or a conversion or newbuild.

Initially, up to 25 wells would be drilled, comprising producers and water and gas injection, Gunning says. The first phase would target 240 MMbbl in the S500 lower SNE reservoir. Subsequent phases would target the S400 upper reservoir, with future potential for further subsea infrastructure and wells installed. Engagement of subsea contractors started prior to tendering, which was expected to start by the end of the year.

According to Gunning, updated gross 2C resources in SNE are 563 MMbbl. The firm would need 200 MMbbl to have the foundation for an economic field development, she says. SNE also has 0.3 Tcf of associated gas, and more than 1 Tcf of recoverable non-associated gas.
Life of field capex is US$12/bbl, Gunning says, with $2.3 billion capex to first oil, about 60% of which is development drilling, with 16 wells pre-drilled. Final investment decision (FID) for SNE is being targeted by 2018, with first oil to follow in 2021-2023.

GTA moving forward
BP became operator of GTA after taking a major stake in Kosmos’ exploration blocks in Mauritania and Senegal in December 2016 and April 2017. BP is targeting final investment decision on the GTA – also known as Greater Tortue Complex — development in 2018, based on a near shore Floating LNG project, Gunning says. Senegal and Mauritania’s governments, whose maritime zones the fields cut across, are expected to form a cooperation agreement over the development by the end of the year.

Breakeven on the project is less than $5/Mcf, Gunning says. Two FLNG vessels are being planned, with first gas from the first 2.3 MTPA unit planned by 2021, via four wells, and the second 2.3 MTPA train in 2023, with 15 wells in total and capacity for up to 20 wells.

The subsea infrastructure would see a daisy-chained manifold and looped flowline arrangement, with two, 120km-long, 18in production flowlines, connected to a floating production vessel, for gas pre-treatment and condensate stabilization and storage. The FPSO and FLNG trains would be located at a nearshore breakwater and sea island, which would also host an LNG carrier berth.

Both the SNE and GTA projects will drive the development new port infrastructure, Gunning says. These projects are by all means not the only games in town, however. Teranga and Yakaar, with 20 Tcf Pmean gas resource in the Cayar Offshore Deep, could form a second LNG hub, Kosmos says.

Meanwhile, in Mauritania, Kosmos is also looking at the Hippocampe and Lamantin prospects. However, in late October, Kosmos’s Hippocampe-1 well came up dry. In Senegal, Kosmos is looking at the Requin Tigre prospect with an estimated 60 Tcf unrisked resource. This is outboard of the Tortue gas discovery. Indeed, Senegal’s deep plays, all have extension in the ultra-deep, Gunning says.

While exploration in Senegal and Mauritania has been dominated by smaller players, the entry of BP and Woodside (subject to an argument over pre-emption rights FAR Ltd claims), as partners to Cairn and Kosmos, was followed by the entry of Total.

In May, Total was awarded a PSC for the 10,357sq km Rufisque Offshore Profond block, holding 90% interest alongside Petrosen. Total also signed a cooperation agreement with Petrosen and Senegal’s Ministry of Energy and Renewable Energy Development under which Total will perform studies to assess the exploration potential of Senegal’s ultra-deep offshore and become operator of an exploration block.

Exploration 2.0 is how the latest phase of offshore exploration is described in Cyprus. It could also be described as exploration post-Zohr.

Egypt’s major Zohr discovery made many look at the Mediterranean differently, including Cypriot waters. Demetris Fessas, executive manager, at the Cyprus Hydrocarbons Company, told the global opportunities session at Offshore Energy there is a lot of activity in the region.

Cyprus is relatively new to offshore exploration. The country held its first offshore round in 2007, with 11 blocks awarded, followed by Block 12 in 2008, resulting in the 2011 Aphrodite discovery by Noble Energy. A development and production plan is now being discussed with the government. A base case is a floating host with export capacity up to 800 MMscf/d, Fessas says. An export pipeline could take the gas to Egypt, he says, adding that sales negotiations are ongoing. “The idea is to use the idle LNG facilities at Idku and Damietta,” he says. Both have been idle since the uprising in Egypt. However, plans for LNG export were parked until the results of the next round of exploration are known. Aphrodite’s FID is expected in late-2019. First gas could be late 2022.

Since then, further blocks were awarded in the 2012 and 2016 licensing rounds, with Eni taking Blocks 2, 3, 6, 8, 9 and 11 (2, 3 and 9 with Kogas and 11 with Total). Shell (via BG Group) has joined Noble Energy on Block 12, and ExxonMobil and Qatar Petroleum hold Block 10. “Today, eight of 13 blocks offered are currently under license,” Fessas says.

Many are interested in “Exploration 2.0.” The original activities offshore Cyprus focused on the clastic plays, Fessas says. “After Zohr, 6km from our exclusive economic zone, we reviewed the carbonate prospects [similar to Zohr] and found potential,” Fessas says. “The third round was held on back of that.”

The Onesiphorus West exploration well drilled using the West Capella drillship in 1698m water depth, on Block 11 by Eni, earlier this year, confirmed the carbonate play does exist in Cyprus, although it wasn’t a commercial discovery. Results of this well are being used to plan 2-3 exploration wells on Blocks 3, 6 and 8 in 1H 2018. Reuters reported in early November that Total and Eni were planning to start drilling late 2017, early 2018 in Block 6.

Meanwhile, ExxonMobil is also planning at least two wells on Block 10 in 2H 2018, Fessas says.

Demetris Fessas. Photo from Offshore Energy.

“Regionally, there is a lot of activity. Israel has Leviathan (under development), Tamar (producing, but could expand), and Karish (considering an FPSO). In Egypt, there’s the Zohr discovery, with first gas due by the end of the year, and West Nile Delta Deep. Lebanon is also progressing with its first licensing round. Three companies (Eni, Total and Novatek in a consortium) made the only bids in Lebanon’s first offshore licensing round, announced late October. However, as OE went to press in early November, the country’s Prime Minister Saad Hariri suddenly and unexpectedly resigned his post during a trip to Saudi Arabia.

“There are lots of activities in Cyprus and in the region, a lot of these have used Cyprus as a mobilization base to support activities. It’s not an easy neighborhood, but Cyprus being part of the EU bring stability and benefits of that.”