All articles in the Oilpatch Sahara Section:


Nigeria’s High Well Costs are at the Heart of its CAPEX and OPEX Challenges

By Ahmed Gafar, in Lagos

The astronomically high drilling costs of wells in Nigeria are key to the challenges faced by operators in reining in operating and capital expenses, an industry service provider has suggested.

If Africa’s highest crude oil producer is to reach its target of delivering Four Million Barrels of Oil Per day (4MMBOPD) in the near term, those costs need to be brought down, argues Hope Okwa, Founder/ Managing Director of Hd Okwa Drilling Services.

Hope Okwa

“A 10,000 feet well producing only 3,000 BOPD costs up to $25Million to construct in Nigeria”, Okwa allows. “To move from the current 1.5MMBOPD to 4MMBOPD requires massive well construction activities, in the order of over 800 wells per year. The associated investment is $21Billion per annum. Where will this investment come from, especially in an era where top global financiers are moving their investment to renewables?”. 

Okwa is persuasive that he is not just throwing numbers around: “$25Million per well cost is true for land, swamp and shallow offshore, as the rigs all use surface blowout preventers.

“The only way is to rethink well construction efficiency, with a view to drastically reducing well costs from current levels”, he contends. “The sources of inefficiencies in well construction, is very much within our expertise”, Okwa declares: “it is very urgent to implement these solutions”, as “in nine (9) years’ time in 2030, the advanced countries will pivot away from fossil fuel.  What will then happen to Nigeria’s reserves of 37Bllion BOE?”

Cost control in oilfield activities has been a front burner issue in Nigeria. Last February, the state hydrocarbon company NNPC had an elaborate event on cost optimization, at which Timipre Silva, Minister of State for petroleum, asked the country’s 34 oil and gas producing companies to join in working towards reducing operations cost to achieve the $10 or less per barrel production cost target.

Stakeholders have responded to Ministry of Petroleum’s call for cost control by naming causes including insecurity (You need gunboats full of naval officers on the way to rig-site) and taxation (government at all levels level multiple taxes: DPR hikes costs of obligatory services, State Governments demand various tariffs, Local Governments harass operators; communities hold up work; regulators sometimes delay). 

Okwa counters that “those issues relate to production mainly, and companies are having to trade off drilling wells due to the issues mentioned and high well cost”. 

 

Okwa has 29 years industry experience, the first 14 of which he spent in AngloDutch Shell, mostly on well engineering and drilling supervision. He had a stint at BG (the defunct British Gas) as a senior well engineer in the company’s Nigerian deepwater operations. He had a five year stretch as senior drilling and workover well engineer on critical gas operations at Saudi Aramco, after which he had another stint at BP Angola as senior drilling engineer.

“We believe that if we reduce well costs drastically.. we will be able to stimulate activities”, he says. “If we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands, even local banks may be able to fund field development campaigns.

The full interview is in the link


Kuwaitis Target A Second Discovery in Abu Sennan

Kuwait Energy Company is moving the ED-50 rig to the north of the Licence, to drill another well, after the moderate success of the last one, which will soon be brought to production.

The next probe is the ASD-1X exploration well, located close to the producing Al Jahraa field. The well is targeting the Abu Roash reservoirs in the Prospect D structure and, if successful, can again be quickly be brought into production.

The last well, ASH-3, a step-out development well in the ASH Field, penetrated a gross hydrocarbon column of 59metres in the primary Alam El Bueib (AEB) reservoir target, 27.5metres of which is estimated to be net pay. The well recorded a maximum flow rate of 6,379 bopd and 6.7 mmscf/d (c. 7,720 boepd gross; 1,700 boepd net), during testing, on a 64/64″ choke, from the AEB reservoir. On a reduced, 30/64″ choke, expected to be more representative of the producing flow rates, the well flowed at 3,561 bopd and 2.9 mmscf/d (c. 4,140 boepd gross; 910 boepd net).

It was spud on the 4th January, and it reached a total depth (TD) of 4,087m MD (3,918m TVDSS) on 8th February.

“The partners, Kuwait Energy and United  Oil and Gas when brought on production over the coming days, ASH-3 will provide a significant boost to the concession-wide production rates that averaged 10,500 boepd gross (2,310 boepd net) during January 2021.

“We look forward to the spudding of the forthcoming exploration well and the remainder of our 2021 work programme,” the partners say.

 


Egypt Launches a Digital “Upstream Gateway”

Egypt’s Ministry of Petroleum says that over 10 international oil companies operating in the country, have signed membership agreement to use the new digital data repository christened Upstream Gateway

In concert with Schlumberger, the oil service giant, the Ministry launched, earlier in the week of February 18, 2021, the “Egypt Upstream Gateway, an innovative national project for the digitalization of subsurface information”.

This digital platform will also enable global access to the country’s subsurface data, “which is kept evergreen by enhancing legacy datasets through reprocessing and new studies”, the Ministry declares. “This unique digital initiative will be used to unlock the potential of Egypt’s petroleum sector and promote the country’s exploration and production potential worldwide”, says Tarek El-Molla, the country’s minister of petroleum and mineral resources.

“The Egypt Upstream Gateway will digitally promote Egypt’s oil and gas bid rounds through seamless online access to the sector’s data, as well as endorsing our exploration potential worldwide.”, Mr. El Molla stresses.

Rajeev Sonthalia, president, Digital & Integration, Schlumberger, explains that “with the launch of this industry-first platform, the Egyptian Ministry of Petroleum and its affiliates—EGPC, EGAS, GANOPE—can digitally showcase national assets to investors worldwide, in addition to leveraging the latest digital technology and solutions to accelerate discovery throughout the country.”

The Egypt Upstream Gateway provides digital access to over 100 years’ worth of accumulated national onshore and offshore seismic, non-seismic, well-log, production, and additional subsurface data under a single platform. This data, which empowers de-risked decisions through the ability to explore multiple basins and evergreen data, can be accessed virtually from anywhere using the platform’s online portal. In addition, the Egypt Upstream Gateway will host Egypt’s upcoming bid round highlighting lease availability information to national and international investors worldwide.

 

 


ENI Discovers Oil and Hooks It Up Quickly in Egypt’s Western Desert

 

By Toyin Akinosho

ENI announced a relatively small new oil discovery in Egypt and hooked it up within a month.

The discovery, in the Meleiha Concession in Egypt’s Western Desert, was achieved through the Arcadia- 9 well, drilled on the Arcadia South structure, which is located 1.5km south of the main Arcadia field already in production.

Arcadia -9 encountered 85 feet of oil column in the Cretaceous sandstones of the Alam El Bueib 3G formation. The well was drilled close to existing production facilities and is already tied-in to production, with a stabilized rate of 5,500 barrels of oil per day.

Following the discovery, two development wells, Arcadia 10 and Arcadia 11, have been drilled back-to-back, the Italian major says in a statement. The first one encountered 25 feet of oil column and the second one 80 feet, within the Alam El Bueib 3G formation. The three wells share the same oil-water contact in the discovered reservoir. Arcadia 11 also encountered 20 feet of oil pay in the overlying Alam El Bueib 3D formation.

“The new discovery adds 10,000 barrels of oil per day to ENI’s gross production in the Western Desert of Egypt”, the company explains.

ENI’s successful implementation of its infrastructure-led exploration strategy in the Western Desert through AGIBA, a joint venture between Eni and Egyptian General Petroleum Corporation (EGPC), allows a quick valorization of these new resources. 

ENI, through its subsidiary IEOC, holds a 38% interest in the Meleiha concession while Lukoil holds a 12% and EGPC a 50% interest.


ENI Finds New Gas in Egypt’s ‘Great Nooros Area’

Italian explorer ENI says it discovered a single 152 meters thick gas column in the first exploration well it drilled in the North El Hammad license, offshore Egypt’s Nile Delta.

Bashrush, as the prospect is called, is located in 22 metres of water depth, 11 km from the coast and 12 km North-West from the Nooros field and about 1 km west of the Baltim South West field, both already in production.

The gas molecules are stored in sandstones of Messinian age in the Abu Madi formation.

They have excellent petrophysical properties, ENI claims. “The well will be tested for production”, the company says.

“The discovery of Bashrush demonstrates the significant gas and condensate potential of the Messinian formations in this sector of the Egyptian Offshore shallow waters. The discovery of Bashrush further extends to the west the gas potential of the Abu Madi formation reservoirs discovered and produced from the so-called “Great Nooros Area”, the Italian giant explains.

ENI, together with its partners BP and TOTAL, in coordination with the Egyptian Petroleum Sector, will begin screening the development options of this new discovery, with the aim of “fast tracking” production through synergies with the area’s existing infrastructures.

In parallel with the development activities associated with this new discovery, ENI will continue to explore the “Great Nooros Area” with the drilling, this year, of another exploration well called Nidoco NW-1 DIR, located in the Abu Madi West concession.

ENI, through its affiliate IEOC, is 37.5%, equity holder and operator of the North El Hammad concession, in participation with the Egyptian Natural Gas Holding Company (EGAS). BP holds 37.5%, and TOTAL holds  25% of the Contractor interest.

 

 


BP Confirms Mauritania, Senegal, as Hot Spots for Natural Gas

British oil supermajor BP has announced that its recent three-well drilling campaign offshore Mauritania and Senegal has confirmed “the world-class scale of the gas resource in the region”.

Three appraisal wells drilled in 2019, GTA-1, Yakaar-2 and Orca-1, targeted a total of nine hydrocarbon-bearing zones. The wells encountered gas in high quality reservoirs in all nine zones.

The wells were the first in the region to be operated by BP. In total, they encountered 160 metres of net pay, growing confidence in the significant gas resources in the region. The overall drilling campaign was delivered 40 days ahead of schedule and $30Million under budget, BP said in a release published December 16, 2019.

Most recently, in November 2019, Orca-1 well in Block C8 offshore Mauritania, successfully encountered all five of the gas sands originally targeted. The well was then further deepened to reach an additional target, which also encountered gas.

Howard Leach, BP’s head of exploration, said: “This is an exciting result as it proves that our seismic data is identifying hydrocarbon reservoirs deeper than we had previously thought. We have identified a large prospective area with considerable resource potential in Southern Mauritania. We will now conduct further appraisal drilling to help inform future development decisions.”

The Greater Tortue Ahmeyim Phase 1 development was sanctioned in December 2018. The successful results of Yakaar-2 and Orca-1 could underpin future developments, including a possible new development in Yakaar-Teranga in Senegal and in the Bir Allah/Orca area in Southern Mauritania. The timings of both potential future developments will depend on the level of appraisal required, supporting commercial development plans and integrated gas master plans in the host nations.

BP’s partners in Block C8 in Mauritania are Kosmos Energy and SMHPM (Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier). BP’s partners in the Cayar Profond block (which includes Yakaar-2) in Senegal are Kosmos Energy and Petrosen. BP’s partners in the Greater Tortue Ahmeyim unit are Kosmos Energy, SMHPM and Petrosen.

 


Now, More Than One LNG Project for Mauritania

BP-Kosmos’ brand new Orca-1 discovery is more than a regular hydrocarbon find.

It has provided the British giant and the American junior, the confirmation of a possible second LNG project after the one already sanctioned.
The well targeted a previously untested Albian play, exceeded pre-drill expectations encountering 36 metres of net gas pay in excellent quality reservoirs, Kosmos Energy gushed in a statement. “Orca-1 extended the Cenomanian play fairway by confirming 11 metres of net gas pay in a down-structure position relative to the original Marsouin-1 discovery well, which was drilled on the crest of the anticline”.

The well location, approximately 7.5 kilometres from the crest of the anticline, proved both the structural and stratigraphic trap of the Orca prospect, which was estimated as having a mean gas initially in place (GIIP) of 13Trillion cubic feet (Tcf) of gas.

In total, we believe that Orca-1 and Marsouin-1 have de-risked up to 50Tcf of GIIP from the Cenomanian and Albian plays in the Bir Allah area, more than sufficient resource to support a world-scale LNG project. In addition, a deeper, untested Aptian play has also been identified within the area and surrounding structures”, Kosmos remarks.

The BP-Kosmos Energy consortium, in partnership with the state hydrocarbon companies of Senegal and Mauritania, took final investment decision for a 2.5Million tonnes per annum of LNG in December 2018. Commercial production for that project is scheduled for 2022.
This new discovery, from all reports, offers the opportunity for another LNG project.

“The Orca-1 result demonstrates highly calibrated AVO, which together with our exploration track record provides further confidence in our ability to predict the presence of high-quality gas charged Cenomanian and Albian reservoirs within the 400-kilometre long inboard Mauritania/Senegal gas basin2, Kosmos explains.


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.

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