TOTALEnergies has announced that it made a significant discovery of light oil with associated gas on the Venus prospect, located in Block 2913B in the Orange Basin, offshore southern Namibia.
“The Venus 1-X well encountered approximately 84 meters of net oil pay in a good quality Lower Cretaceous reservoir”.
TOTALEnergies commenced drilling Venus-1 almost around the same time that Shell spudded Graff-1, on the same basin, in adjacent blocks.
TOTALEnergies’ decision to announce the results of its find differs remarkably from Shell’s preference for silence on its own drilling.
Whereas there were heavy speculations about the result of Graff-1, the UK major has not made any statement about the drilling update, let alone indicate hydrocarbon footage the way its French counterpart has done. What the public knows about the so-called success of Graff-1 derived from a statement by Namcor, Namibia’s state hydrocarbon firm, which uses the word significant, but provides no context.
TOTALEnergies concludes its statement: “A comprehensive coring and logging program has been completed. This will enable the preparation of appraisal operations designed to assess the commerciality of this discovery.”
Block 2913B covers approximately 8,215 km² in deep offshore Namibia. TOTALEnergies is the operator with a 40% working interest, alongside QatarEnergy (30%), Impact Oil and Gas (20%), and NAMCOR (10%).
Buzi Hydrocarbons has reported strong indications of the existence of natural gas in the various geological formations encountered in the course of drilling, testing and completion of the BS-1 and BS-2 hole in the Búzi Block onshore Mozambique.
The company will evaluate “this possible discovery” for confirmation and subsequent information to the Government which, depending on the quantities, must approve a plan for the monetisation of the discovered resources.
The Indonesian owned Buzi Hydrocarbons describes the two probes namely the Buzi Shallow-1 (BS-01) and the Buzi Shallow-2 (BS-02) as research wells, drilled on the basis of 2,250 line kilometres of two dimensional (2D) seismic data, of which 600 line kilometres were newly acquired. “Buzi Hydrocarbons reprocessed 300 kilometres of pre-existing 2D seismic, reinterpreted 1,650 km of pre-existing 2D seismic, acquired, processed and interpreted 600 km of 2D seismic”, the report says.
“The BS-1 hole reached a total depth of 1,567 meters and throughout its drilling showed the occurrence of natural gas, in the Grudja Superior, G6, G7, G8, G9 and G10 horizons, and is awaiting production tests to confirm a possible discovery”, according to the National Petroleum Institute (INP), Mozambique’s hydrocarbon regulatory agency. “The BS-2 hole, located 1,000 metres away from the first hole, was executed with the objective of evaluating the lateral continuity of the prospective horizons of the Upper and Lower Grudja Formations, which showed manifestations of natural gas in the first hole”, the INP says in its release.
The Concession Contract for Exploration and Production agreed with the Mozambican government in 2010, provided for the execution of two exploration wells in the second and third exploration periods, respectively, INP explains. “During the hole evaluation process, Buzi Hydrocarbons injected nitrogen to remove the completion fluids in the Upper Grudja formation, a procedure that made it possible to clean the well to remove possible obstructions and allow the gas to flow conveniently during the testing. Because the process caused the appearance of flames, the preliminary occurrence of natural gas was speculated. Despite this phenomenon, the oil company continues to carry out studies in order to determine the amount of natural gas available, a procedure clearly stipulated in the Petroleum Operations Regulation, approved by Decree Nr. 34/2015, of 31 December”.
In the year 2021, the global oil industry bounced back from the depressed commodity price and the shock of the COVID-19 pandemic that disrupted the sector in the 2020 fiscal year. Before this tumultuous event, investment in new oil had been witnessing a decline, due in part, to the uncertainty posed by the energy transition. But despite this under investment, the Africa continent added some new barrels to global discoveries in 2021. In all of this, it wasn’t all bad news for Africa.
For 2021, the following are some major hydrocarbon resource discoveries made in Africa.
ENI’s Sheer Excellence of Discoveries
Italian giant ENI had a good year in Africa in the year 2021 as it unlocked many new finds in Ghana, Cote d’Ivoire, Angola and Egypt. In fact, to christen the Milan based major as ‘the explorer of the year’ won’t be out of place.
Eban Discovery (Ghana)
The “Eban” discovery in the CTP Block 4, offshore Ghana was one of many in 2021. The Eban – 1X happened to be the second well spudded in the CTP Block 4 after the initial “Akoma” discovery. The Eban prospect was drilled by “Saipem 10000 drilling ship” in water depth of 545m with the well reaching a depth of 4179metres. The reservoir penetrated according to Eni was a thick sandstone of Cenomanian age with an oil column of 80metres.
According to the company, “preliminary estimates place the potential of the Eban-Akoma complex between 500 and 700 Million Barrels of Oil Equivalent (BOE) in place”. ENI described the find as “a testimony to the success of the infrastructure-led exploration strategy that ENI is carrying out in its core assets worldwide”. The company is hopeful of fast-tracking production due to the proximity of existing infrastructure.
The CTP Block 4 is a Joint Venture with ENI holding 42.469% equity and also doubling as the operator. Other partners include Vitol (33.975%), GNPC (10%), Woodfields (9.556%), and GNPC Explorco (4%).
Baleine Discovery (Cote d’Ivoire)
The Baleine discovery in Cote d’Ivoire is coming after nearly 20 years of ‘a dry spell for discoveries’ in the deep waters of the West African country. The find was made in block CI-101 offshore Ivory Coast and announced in September of 2021.
The well was again drilled by Saipem 10000 drill ship (lucky rig) in a water depth of 1200m. The probe reached a total depth of 3445metres, according to the company. The reservoir age is said to be Santonian and Cenomanian/Albian. ENI estimates the find to be between 1.5 and 2.0Billion barrels of oil in place and some 1.8 to 2.4Trillion cubic feet of associated gas resources.
The acreage is jointly held by ENI (90%) and state hydrocarbon company Petroci Holding (10%).
Apart from the CI-101 in which Baleine was discovered, ENI has participating interests in four other offshore blocks in Ivory Coast: CI-205, CI-501, CI-504, and CI-802; with Petroci Holding being joint partner in all.
Meleiha and South West Meleiha Discoveries (Egypt)
ENI brought the year 2021 to a close with the announcement of a bunch of small discoveries in which it estimates 50 Million BOE in place in Egypt’s Western Desert. The “Meleiha development lease” discovery was made with Jasmine W-1X and MWD-21 wells; while the “South West Meleiha exploration concession” was discovered with the SWM-4X well – some 35km south of the Meleiha oil centre location.
The Jasmine W-1X and MWD-21 were discovered within clastic reservoirs of Jurassic Khatataba Formation and Cretaceous Alam El Bueib Formation respectively. In the SWM-4X well, ENI encountere an oil column of 36ft in the Cretaceous clastics of Bahariya Formation – also with excellent reservoir properties.In all, the discoveries add some 6,000 barrels of oil equivalent per day to ENI’s total output.
Partners in the assets and what they hold: “Eni, through its subsidiary IEOC, holds a 76% of Contractor’s participating interest in the Meleiha concession while LUKOIL holds the remaining 24%. Both Companies are parties in this concession with EGPC and the Government of Egypt. In the South West Meleiha concession, Eni, through its subsidiary IEOC, holds a 100% of Contractor’s participating interest. IEOC, EGPC (Egyptian General Petroleum Corporation) and the Government of Egypt participate in the concession as parties”.
The Cuica Discovery (Angola)
In further pursuit of Eni’s infrastructure led exploration strategy (ILX), it unlocked another find in block 15/06 in Angolan deep waters with an estimated oil in place of 200 to 250 Million barrels. The well was spudded on the “Cuica exploration prospect” within the “Cabaça Development Area”.
From the press release by the Italian major, the Cuica-1 NFW was drilled as a deviated well in water depth of 500m by the Libongos drillship with the well reaching a total depth of 4,100metres and encountered 80metres of oil column in Miocene sandstone reservoir with good petrophysical properties. This discovery is expected to flow about 10,000 barrels of oil daily when it is brought on stream.
Aside being the operator of block 15/06, ENI holds (36.8421%) interest whilst Sonangol P&P holds (36.8421%) and SSI Fifteen Limited (26.3158%) respectively.
ReconAfrica’s Pioneering Efforts in Namibia’s New Frontier
ReconAfrica, a Canadian oil minnow is leading efforts in Namibia’s new frontier, “Deep Kavango Basin” in the Kalahari Desert of North-eastern Namibia which further straddles North-western Botswana where it holds some “contiguous” 8.5Million acres of petroleum license.
The year 2021 was a busy year for the Vancouver based company as it undertook varying exploration efforts which included seismic data acquisitions, well drilling and Petrophysical evaluation. These efforts led to announcement of a working petroleum system given oil and gas shows, five potential reservoir zones in well (6-2) – 3 clastic and 2 carbonates.
These wells were not drilled on the basis of any seismic evaluation and they are regarded by Recon as, at best, “tests” to determine the viability of a working hydrocarbon system. Recon has reported encountering ‘oil shows’ but has insisted on not using the phrase “discovery”. With two-dimensional seismic data now acquired, Recon plans to drill “valid” exploration wells in 2022.
Oil and gas resources not only serve as a commodity to earn revenue and create jobs in resource rich African countries, it also holds the possibilities to jumpstarting industrial renaissance on the continent. These discoveries further show the potential of how the Africa continent can add to global reserves in an emerging energy future that will include oil and gas for years to come. These needs should be underpinned by Environmental Social Governance best practices in the light of energy transition.
We have to accept the fact that we Africans struggle with a sense of time. I was once invited to an independence day celebration during my time in the middle east. The events were scheduled to start at 7 pm local time. The venue was two hours drive away from where I lived in the desert. I reckoned that I would spend two hours at the events, and then drive a family member to the airport at 9.30 pm to catch an international flight. We set off at 4 pm and arrived at the venue at 615 pm. To my surprise, there was no sign of any event happening at the venue. After waiting for over two hours, just as I set to leave, that was when the first member of the organizing committee arrived! Needless to say, I missed the celebrations!
Returning home from my various sojourns overseas, I discovered that the “African Time Syndrome” had crept into the Nigerian oil and gas industry.
Examples of poor sense of time:
on more than one occasion, I have been recruited into a project as a drilling engineer, only on resumption, to discover the rig moving to the new drilling location without the drilling program, not even a draft.
Wellsite staff was mobilized very late, leaving them with no time to familiarise themselves with the project they were delivering.
Long decision-making times crippling operations with high invisible lost times.
Last-minute materials ordering often left teams to use what was available rather than what was optimal.
Rigs were allowed to remain idle for no obvious reasons, with no consideration for the oil deferment. The produced oil has a time value of money, and the longer it is kept in the ground, the less its value.
No wonder the average non-productive time in Nigeria is 40% vs 20% elsewhere. Likewise, The average well delivery time is 85 days per well in Nigeria, compared to 15 days overseas. Drilling is a highly time-dependent operation – approximately 70% of drilling cost is time-dependent. Therefore the first step to well cost improvement is to build a culture of urgency. Here are a few actions we can implement to create that culture and improve well cost:
Commence well-planning activities very early. The international oil companies have well delivery processes that run for a duration of 14 – 18 months. They invested their money in front-end activities. This allowed them to achieve a lower cost of field development and optimal produced volumes.
Resource the team with the right amount of depth and breadth of experience. Unfortunately, the right human resources are very hard to find. It appears that long periods of inactivity have taken their toll on the industry. However, there are many professionals residing outside the country, who are keen to return home.
Engender a focus on value, rather than cost. Cost focus tends to easily obscure a sense of urgency. However, a focus on value and the bigger picture helps to build the right time perspective.
Appropriate management training, together with holding people accountable for delivery helps to establish a much-needed performance culture.
Finally, consider outsourcing well construction through turnkey contracts. Relieve your organization of the burdens of staff management, surplus project materials management, distractions of drilling activities, and un-ending invoices reconciliation following drilling projects.
The Nigerian industry is suffering from under-investment at the moment, and it is imperative for us to optimally use available resources prudently.
There may be vast deposits of hydrocarbon in the Gambia, but operators of the last drilling in the country could not immediately confirm.
FAR, the Australian minnow and its partner Petronas, concluded the drilling and formation evaluation operations for the Bambo-1ST1 well offshore The Gambia but they could not announce, even from wireline logs, if there was some Gross Hydrocarbon count, let alone a Net Oil or a Net Gas Sand footage.
Bambo-1, the second well FAR will be drilling in The Gambia in three years, and the second in the country in 43 years, was initially drilled to a depth of 3,216 metres Measured Depth Below Rotary Table (MDBRT) and wireline logging data was obtained. The Bambo-1 well was then plugged and the Bambo-1ST1 (side-track) well drilled to a depth of 3,317m MDBRT after which, wireline loggings were conducted.
“The drilling and logging data obtained on the main well and the side-track well indicates that several target intervals in the well had oil shows”, was all FAR could say, “confirming a prolific oil source is present in the area”.
Samples were recovered from several levels.
As it is, this is a dry hole; the result is not so dissimilar to what FAR got with Samo-1, the first well in this same block that it drilled around this time in 2018. These two wells are the only probes that FAR has operated on its own. Until another company comes and tests these same sequences, we cannot tell whether or not the problem is the quality of FAR’s geoscience unit.
But the company offers an excuse: “The presence or otherwise of any oil will be confirmed by laboratory analysis”.
FAR then explains its operations further: ‘The side-track well was planned to be drilled to the final total depth through all target reservoirs and also to intersect zones of interest from the main well in a different location which will provide additional data and to sample potential oil. Interpretation of the cuttings and wireline logging information indicates that these zones have been charged with oil in rather poor-quality reservoirs and in traps that might have been breached, leaving behind some residual oils in the reservoirs.
“The side-track well also intersected oil shows in the Soloo Deep units not previously encountered by the original well or other wells in the area. The oil shows encountered were persistent over several hundred metres, confirming access to the prolific oil-generative kitchen is present which may open additional material exploration opportunities and running room in both the A2 and A5 Blocks. The drilling operations of the Bambo-1 well and Bambo-1ST1 side-track well were conducted safely and within the amended budget. The well and side-track are being plugged and abandoned consistent with the planned well abandonment program for this type of exploration well. Cath Norman, FAR Managing Director said.
Shell Nigeria, is continuing drilling the gas wells at ANOH, a straddle play gas development involving Shell- operated Assa North field in Oil Mining Lease (OML) 21 and Seplat operated Ohaji South field in OML 53.
A total of four wells are being planned for the project in 2021.
Shell is drilling all the wells because it is operator of the upstream segment of the ANOH gas development.
The midstream part of the project (i.e., installation of gas processing facility), is being done by each company separately; Shell and Seplat are each to output 300Million standard cubic feet per day, making a total of 600MMsf/d.
Elsewhere in the Niger Delta basin, Seplat proposes to continue its drilling campaign on the Oben field in OML 4 with two more gas wells, which are expected to produce 60 MMscf/d and 2,400BOPD combined.
Seplat has said it looks forward to commissioning its own segment of the ANOH Midstream project by 2H 2022.
UK major Shell has spudded the Graff-1 well in Namibia’s Block 2913 Petroleum Exploration License (PEL) 39, barely a week after TOTALEnergies began drilling Venus-1, offshore the same country.
It’s an intriguing place to be for a jurisdiction that hasn’t witnessed drilling by an oil major in over 25 years.
Shell is utilizing the Valaris DS-10 rig to probe a prospect which, like TOTALEnergies’ Venus-1, looks like a hub size play on three-dimensional (3D ) seismic data.
The two acreages are adjacent to each other, in deepwater Orange Basin, although TOTALEnergies’ PEL 56 is in slightly deeper waters than Shell-operated PEL 39.
The Orange basin is a major delta system that spans both Namibia and South Africa.
Shell also has operated acreages in the South African segment of the basin.
As far as hydrocarbon exploration and exploitation is concerned Namibia has been in a “hoping mode” for close to 10 years, with plans to monetise the Kudu gas accumulation, the country’s only valid hydrocarbon discovery, caught in uncertainty and drilling activities by Western minnows turning up dry after spectacular dry holes.
The feeling of despondency was lifted in January 2021 when the Canadian independent ReconAfrica claimed it had encountered a working a hydrocarbon system in the Kavango Basin, a Permian aged geosyncline located onshore.
Drilling operations were temporarily halted at 3,216 metres Measured Depth below rotary table after significant fluid losses were experienced in Bambo-1, currently being drilled offshore Gambia by the Australian independent FAR.
“These fluid losses were stabilised in accordance with standard offshore operating procedures, and FAR is now planning to plug and side-track the well to continue drilling to the planned total depth (PTD)”, the company says in a release. Prior to side-tracking and provided hole conditions remain stable, FAR is undertaking a wireline logging programme in the current well bore.
The probe is already close to the ptd, which is 3450metres Measured depth below rotary table.
FAR says that oil indications have been detected in roc cuttings and hydrocarbons have been interpreted across several intervals in the well from LWD (logging whilst drilling) data, but “further wireline logging needs to be completed to confirm the finding”.
The operator is concerned that “the addition of the side-track programme has extended the period of operations which is now expected to be completed by the end of December 2021”.
The well has been designated a “tight hole” by FAR and JV partner Petronas and as such, no information related to depth or formation is likely to be provided during the drilling beyond what is required to meet ASX continuous disclosure obligations.
Market participants should exercise care before transacting in FAR shares until such time as FAR, as Operator of the Joint Venture, makes formal ASX disclosures regarding well results.
FAR estimates that the cost to complete the well will increase from a total of $51.4Million to $61.27Million, an increase of $9.87Million or $4.935M net to FAR.
TOTALEnergies has spud the Venus-1X offshore exploration well in Namibia’s Block 2913B (PEL 56).
The well is being drilled in 3,000metres water depth by the Maersk Voyager drillship.
Venus-1 is one of the several wells proposed for drilling in Africa by International Oil Companies, that will probe prospects in deeper water than have ever before been tested (TOTALEnergies’ just concluded Ondjaba – 1 offshore Angola, in water depth of 3,600metres is another); test basins that have never been drilled before (e.g. Invictus Energy’s proposed Mzarabani – 1 in Zimbabwe) or be the first exploratory well ever drilled in a country (Galp’s Jaca-1 in Sao Tome et Principe (STP), outside the unified zone of Nigeria and STP ).
The Mzarabani 1 well by Invictus Energy will target structurally trapped gas in a 200-sq-km closure of the Mzarabani anticline which runs along the southern margin of the basin. The well’s primary target will be in the Upper Triassic Angwa Formation with potential multi Tcf of gas in place. This relatively low-cost exploration well is strategically positioned to find hydrocarbons for supply into the Southern African market.
TOTALEnergies holds a 40% interest in Block 2913B, Qatar Energy holds a 30% interest, NAMCOR, the Namibian state oil company, holds a 10% interest. Impact Oil & Gas holds a 20% interest.
FAR, the Australian independent, has commenced drilling on the Bambo-1 exploration well in Block A2, offshore The Gambia.
The Stena Ice Max drillship arrived on site on 12 November Gambian time and after completing preparations, has successfully spudded the well.
The Bambo-1 well is located approximately 85kilometres offshore The Gambia, in 930 metres of water depth and is planned to be drilled to a depth of approximately 3,400 metres.
The drilling campaign is expected to take approximately 30 days. The well is designed to drill into a series of vertically stacked targets with a combined estimated recoverable, prospective resource of 1,118 MMbbls (arithmetic sum of the Best Estimates, un-risked, 559 MMbbls net to FAR*) and FAR calculates the chance of geological success for the various horizons to range from 7% to 36%. The targets are: 1. Bambo (S390 & S400) – two shallower horizons not previously intersected. 2. Soloo (S410 & S440) – the extension of the hydrocarbon-bearing reservoirs in the adjacent Sangomar Oil Field, Senegal. 3. Soloo Deep (S552 & S562) – two additional horizons, also not previously penetrated.
Soloo Deep has a lower chance of success but higher potential volumes.