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Reprocessed 3D Seismic Data For Red Sea Bid Round

Schlumberger and TGS say that a new Three Dimensional (3D) seismic reimaging project will be available before the close of Egypt’s offshore Red Sea international bid round on 15 September 2019.

The project comprises reimaging data from three overlapping seismic surveys totalling 3600km2 that were acquired between 1999 and 2008—the only available 3D data in this part of the Red Sea.

It includes the integration of all legacy seismic and non-seismic data and will apply advanced imaging technologies to better define complex subsalt structures.

The project, which is supported by industry pre-funding, will be carried out by TGS and WesternGeco®, the geophysical services product line of Schlumberger.

The two companies say their collaborative approach “will help our clients identify high-potential play segments, assess exploration risks and accelerate hydrocarbon discovery.”

“The Red Sea 3D reimaging project follows a multi-client 2D seismic acquisition programme that was completed in March 2018 as the initial step in mitigating the complex salt imaging challenges in the area,” said Kristian Johansen, CEO, TGS. “The underexplored offshore Egyptian Red Sea area is made up of large, untested structures that offer exceptional growth opportunities for oil companies.”

Schlumberger and TGS have a long-term commitment with the Egypt Ministry of Petroleum and South Valley Egyptian Petroleum Holding Company (GANOPE) to acquire and process seismic data and promote the prospectivity of the Egyptian Red Sea.


More Gas Found In Senegal/Mauritania

By Mohammed Jetutu, North Africa Correspondent

BP and partners have confirmed their expectation that the gas resource at Greater Tortue Ahmeyim, offshore Senegal will continue to grow over time and could lead to further expansion of the 10 Million Tonnes Per Annum (10MMTPA) LNG project.

The companies encountered approximately 30 meters of net gas pay in high-quality Albian reservoir in the Greater Tortue Ahmeyim-1 well (GTA-1), drilled on the eastern anticline within the unit development area of Greater Tortue. The Greater Tortue Ahmeyim LNG project is on track to deliver first gas in the first half of 2022, and the well (which has been designed as a future producer) will be used to further optimize the development drilling plans for the BP-operated project.

The GTA-1 well was drilled in approximately 2,500 meters of water, approximately 10 kilometers inboard of the Guembeul-1A and Tortue-1 wells, to a total depth of 4,884 meters.

Meanwhile, Kosmos Energy, the original holder of the licence, is continuing the process to sell down its interest to 10% has received considerable interest from the industry, with initial bids expected over the summer, and transaction conclusion anticipated by year end.”

The Ensco DS-12 rig is enroute to spudding the Yakaar-2 appraisal well in Senegal, before drilling the Orca-1 exploration well in Mauritania, which is expected to spud late in the third quarter. Partners in the cross-border Greater Tortue Ahmeyim project, located offshore Mauritania and Senegal, include SMPHM, Petrosen, BP, and Kosmos.



ENI Discovers Even More In The Mediterranean

By Mohammed Jetutu, in Alexandria

Italian explorer ENI says it is evaluating a new discovery in the Nour North Sinai Concession, in the Eastern Egyptian Mediterranean.

The deepwater well Nour-1 New Field Wildcat (NFW), was drilled in a water depth of 295 meters about 50 km North of the Sinai peninsula.

The rig used was the semi-submersible Scarabeo-9. The well was drilled to a total depth of 5,914 meters.

Nour-1 encountered 33 meters of gross sandstone pay “with good petrophysical properties and an estimated gas column of 90 meters in the Tineh formation of Oligocene age”, ENI says in a release. “The well has not been tested, however an intense and accurate data acquisition has been carried out”.

In the concession, which is in participation with Egyptian Natural Gas Holding Company (EGAS), ENI is the operator with a 40% stake, BP holds a 25% stake, Mubadala Petroleum a 20% stake while Tharwa Petroleum Company a 15% stake of the contractor’s share.

The JV Operator will start the feasibility studies to accelerate the exploitation of these new resources leveraging the synergies with existing facilities and infrastructures, after finalizing the discovery evaluation.

ENI has operated in Egypt since 1954 through its subsidiary Ieoc.

The Great Gambian Hope Did Not Materialise

By Fred Akanni

A frustrating dry hole defines FAR’s first attempt as an operating company

The hope that The Gambia would join the new hydrocarbon rich countries in the North West African margin failed to materialise with the much anticipated well by FAR, the Australian explorer.

Using funds from Petronas, the Malaysian state hydrocarbon firm, FAR drilled its first operated well, Samo-1, offshore The Gambia, to a total depth of 3,240metres.

While admitting that wireline logging had not been completed at the time it went to press with the well results, FAR reports that “interpretation of the wireline logs so far indicates that the main target horizons are water-bearing. Oil shows were encountered at several levels indicating that the area has access to an active hydrocarbon charge system. The well also encountered excellent reservoir and seal facies, indicating that all the key components for a successful trap are present”.

The well operations to date have been conducted safely, efficiently, ahead of schedule and within budget.

FAR had said previously that the Samo-1 well location was picked on the basis of the processing and interpretation of a Multi-Client, Broadband three dimensional (3D) data, acquired by Polarcus in 2015.  The well was drilled in approximately 1,017 m water depth and 112 km  offshore Gambia in the highly prospective Mauritania-SenegalGuinea-Bissau-Conakry (MSGBC) basin. Far had also said it conducted detailed mapping and detailed well engineering of the Samo Prospect, before approving the Samo-1 well location.

Petronas funded 80% of the cost of the Samo-1 well up to a maximum total gross cost of $45Million, under the terms of the farm in agreement agreed to by Petronas and FAR in February 2018. Patronas hd, by then farmed into 40% of the block, reducing FAR ‘s stake to 40%. In addition to the well costs, Petronas agreed to pay FAR cash consideration of $6Million plus 80% of non-well back costs exploration programme.

“As the first offshore well in forty years and the first modern well, the data that has been collected at Samo-1 and the ongoing interpretation will be critical to unlocking the hydrocarbon potential in the area. The well will be plugged and abandoned, consistent with the plan for this exploration well.

The Government of The Gambia confirmed a six-month extension to the current licence to end June 2019 to allow for evaluation of the Samo-1 well results”.

Panoro Looks to Spud Tunisian Well in Mid 2019

Panoro Energy has announced a Heads of Terms agreement with Compagnie Tunisienne de Forage (CTF), the Tunisian state-owned drilling contractor, for the use of the CTF-4, a 2,000-horsepower onshore rig, or equivalent drilling rig, for the drilling of the Salloum West-1 well (SAMW-1) located in the Sfax Offshore Exploration Permit (SOEP). The spud date of the SAMW-1 well is anticipated to be in the first half of 2019 and is subject to the entry into a second renewal period of the SOEP for a period of 3 years, and the subsequent approval of the final drilling program and budget by ETAP. Advanced discussions for the renewal are ongoing with the Tunisian Authorities.

The announcement to spud the SAMW-1 well, to be directionally drilled from the shore as a deviated well, comes only 3 months after the closing of the acquisition of DNO Tunisia AS.

The primary objective of the SAMW-1 well is the Bireno formation, at approximately 3,200 metres vertical depth, where the Company has identified, based on 2D and 3D seismic data, what it believes to be an extension of the Salloum structure to the west. The SAMW-1 well will target an independent fault compartment up-dip from the Salloum-1 well which was drilled by British Gas in 1992 and tested the Bireno formation at a rate of 1,846 bopd.

The objective of the SAMW-1 well is to prove up additional resources in the vicinity of the Salloum-1 well and subsequently fast-track the development of Salloum through a tie-in to existing adjacent oil infrastructure.

The decision to drill this new well is supported by rig availability, cost-savings due to drilling equipment for the well already being owned and stored in Panoro’s Sfax warehouse, existing 2D and 3D seismic covering the SAMW-1 location, close proximity to the Salloum-1 discovery well, the existing adjacent oil infrastructure, and a high chance of success.

The expenditure on SAMW-1 well will be funded from Panoro’s existing financial resources. The well costs will also be an added to the existing substantial cost pool of SOEP which will be fully recoverable against future revenues through crude oil sales.

Zomo-1; Likely Fifth Success or First Duster

Savannah’s Fifth Success or First Duster?

Savannah Petroleum has moved the GW 215 Rig to drill the fifth well in its exploration campaign in the Niger Republic.

Zomo-1, spudded on September 8, follows Bushiya-1, Amdigh-1 Kunama-1 and Eridal-1, all drilled by the British explorer between March and August 2018, and all of which encountered crude oil bearing zones, considered by Savannah to be of commercial size.

But none of the wells have been tested, so there is no clear handle on flow assurance.

As with others, Zomo-1 is located in the R3/R4 PSC Area in the Agadem Basin, south east of the republic of Niger. It is also, as with the rest, designed to evaluate potential oil pay in the Eocene Sokor Alternances as the primary target.

The well is planned to be drilled to a total depth of 2,438metres Drilling is expected to take between 30 and 35 days.

The Company plans to log all prospective sections within the well, with further logging employed for hydrocarbon bearing sections. “In the success case, the well will be suspended for future re-entry and further evaluation, which could include well testing”, the company says.

Savannah Makes The Fourth Oil Discovery in A Row

Savannah Petroleum has announced the fourth consecutive crude oil discovery in the Agadem Rift Basin (ARB) in the Republic of Niger.


The Eridal-1 well is the latest reported successful probe in the British operator’s four well campaign, which started with Bushiya-1 and continued with Amdigh-1 and Kunama-1.


None of the wells have been tested, so their deliverability is not entirely clear.


“Production tests are expected to be performed on at least two of the four wells as a precursor to the Company’s plans to implement our Niger Early Production Scheme (“EPS”)”, the company has explained.


All the wells were drilled in the R3 portion of the R3/R4 PSC Area in the ARB, South East Niger.


Preliminary results of Eridal-1, based on the interpretation of the available data set (which includes wireline logs, fluid sampling and pressure data) indicate that the well has encountered a total estimated 13.6m of net oil bearing reservoir sandstones in the E1 reservoir unit within the primary Eocene Sokor Alternances objective. Wireline logs indicate the reservoir properties to be good quality and the available data indicates light oil consistent with Savannah’s discoveries to date, and in line with offset wells and the depth/API trend observed across the basin. Oil samples from the E1 reservoir unit have been taken and returned to surface using wireline testing equipment.


The well was drilled by the GW 215 Rig to a total measured depth of 2,542m, and encountered the main objective targets at, or near, their prognosed depths. The well took a total of 14 days to reach target depth, and all operations are expected to be completed within 23 days of spud. This compares with a pre-drill expectation of 22 days to reach target depth and 30 – 35 days to complete all drilling operations. No significant geological or drilling hazards were encountered.


Eridal-1 is currently being suspended for future re-entry.


Testing is expected to require standard production completion equipment to be installed in the wells, enabling them to be connected to the proposed EPS. This well testing programme is currently being planned for later in the year and the Company intends to provide further details in due course. The Company does not expect to provide a discovered resource and volumes report until the well test programme has been completed and evaluated.

SDX Finds “A Lot Of Oil” in Egyptian Appraisal

By Mohammed Jetutu, in Cairo

London listed SDX Energy has made an oil discovery it considers significant at its Rabul 5 Well in the West Gharib Concession in Egypt.
The junior has 50% Working Interest in the concession and is a joint operator.

Rabul-5 encountered 151 feet of net heavy oil pay across the Yusr and Bakr formations, quite a lengthy footage by Egyptian standards. The oil an average porosity of 18%. (With estimated reserves of 2.5Billion barrels, Egypt produces less than 700,000Barrels a day, according to BP’s latest Review of Energy Statistics).

The well was drilled to 5,280 feet total depth. SDX says that further evaluation of the discovery is ongoing, after which the Company expects the well to be completed as a producer and connected to the central processing facilities at Meseda. “Following completion of the Rabul 5 well the Company will move on to the Rabul 4 location, the second of two appraisal wells planned for the Rabul feature in 2018.

SDX Hopes For 150Billion Scuf In New Prospects

By Mohammed Jetutu, in Cairo

Egypt focused junior SDX Energy, is targeting 150Billion standard cubic feet of gas in two new wells proposed to be drilled from mid March 2018.
IbnYunus-1X and Kelvin-1X wells, in the South Disouq concession, will be drilled by the ST-6 rig, owned by the Sino-Tharwa Drilling Company, with which SDX has signed a rig contract for four firm wells and one contingent well.

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Kosmos Hits Three Dry Holes Out Of Four in NW Africa

By Toyin Akinosho
One failed due to charge access, another for lack of trap, the third being evaluated….

Kosmos has encountered another dry hole in its campaign to find oil (and some gas) in the sequences outboard of its gas discoveries in the NW Africa margin.

The prospect, Requin Tigre-1 (Tiger Shark), in Senegal’s Saint Louis Offshore Profond block “was fully tested but did not encounter hydrocarbons”, the company declared on Monday, February 5, 2018.

Requin Tigre-1 was the fourth of a four well drilling programme which featured Yaakar-1, Hipoccampe-1, and Lamantin-1. This particular well was targeted at finding gas, and extending the 15-25Tcf Tortue play.

The well drilled to a total depth of 5,200 meters and was designed to evaluate Cenomanian and Albian reservoirs in a structural-stratigraphic trap, charged from an underlying Neocomian-Valanginian source kitchen. “Post-well analysis is currently ongoing to determine the reasons it was unsuccessful”, Kosmos lamented.

The four prospects are all located in combination strat/structural plays, with Cenomanian-Turonian and Albian oil source kitchen “with increased probability for liquids”.

But Yaakar-1 was the only one that was successful and even then, what it encountered was gas, which wasn’t the primary objective.
Kosmos had encountered tanker loads of natural gas in the Northwest African margin and was hoping to find oil in prospects located outboard of these gas tanks.

Hippocampe-1, drilled in approximately 2,600 meters of water in Block C-8, offshore Mauritania, “encountered well-developed reservoirs in both exploration targets but these proved to be water bearing”. Kosmos’ earth scientists believe that this prospect failed due to a lack of charge access in this part of the play fairway.

Lamantin-1 also came up water wet. Located in Block C-12 offshore Mauritania in approximately 2,200 meters of water, it was drilled to a total depth of 5,150 meters and was designed to evaluate a previously untested Lower Campanian base of slope fan supplied from the Nouakchott River system, trapped in a combination structural-stratigraphic feature, and charged from underlying, oil-prone Cenomanian/Turonian and Albian source rocks. But the Campanian reservoir objective was water bearing with some residual hydrocarbons due to, Kosmos believes, “a lack of trap, related to a combination of up-dip sand pinch-out and top / base seal effectiveness”.

Kosmos, a passionate exploration company, looks on the bright side: “With each exploration well drilled, we deepen our understanding of this newly emerging basin, further refining our geologic model and geophysical tools. Requin Tigre was the last well in our second phase of exploration of the deepwater Cretaceous petroleum systems offshore Mauritania and Senegal targeting large basin floor fan structures.

We have delivered one success (Yakaar) in four wells in this second phase programme, following three successes in three wells (Tortue, Marsouin, Teranga) in the first phase programme targeting inboard structures on the slope. Overall we have discovered gross resource of 40 trillion cubic feet, at a net cost of $0.20 per barrel of oil equivalent benefiting from the partner carry, and have created the potential for two world scale LNG hubs. We will rigorously evaluate our large inventory of prospects across Mauritania and Senegal ahead of the next phase of exploration offshore the two countries.”

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