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Why? NUPRC Yet to Publish Details of Frontier Basin Exploration Development Plan

By Adeniyi Adeoloye

The Frontier Exploration Fund section of Nigeria’s Petroleum Industry Act (PIA) 2021 was a -hot button issue during the final arguments leading to the passage of the PIA by the National Assembly.

The major contention was the money voted.

That 30% of state hydrocarbon company NNPC Limited’s profit oil and profit gas (as in the production sharing, profit sharing and Risk service contracts) goes to the Fund, aroused strong emotions from many industry watchers and the political class, particularly along the north-south divide. However, the fervour soon ebbed after assent of the bill by former President Muhammadu Buhari.

Following the enactment of the PIA, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC), the upstream regulator, formulated and gazetted several regulations aligning with the omnibus law. Among these regulations, the Frontier Basin Exploration Fund regulation is one that provides the window on the operational framework of the Fund.

On May 24, 2023, nearly 21 months after the PIA came into force, an opportunity to gain insight into the workings of the Frontier Exploration Fund emerged when NUPRC published the Frontier Basins Exploration Administration regulation. The objectives of this regulation are to “provide the general rules for the exercise of the Commission’s responsibilities with respect to frontier basins in Nigeria pursuant to section 9 of the Act”, and also to “provide a procedure for the administration of the Frontier Exploration Fund”; as well as to “attract investment to the frontier basins in Nigeria”.

Per the regulation, NUPRC is expected to “issue an annual Frontier Basin Exploration and Development Plan (the FBED Plan)”. Noting that the inaugural FBED Plan will be produced and published on the website of the Commission within three months of the regulation’s commencement, with expiration on the 31st December, 2023. Subsequently, the FBED Plan will be issued and published on January 1 of every year that follows. However, a look on the Commission’s website 3 months after the regulation was made, that is: August 2023, and later on January 1, 2024 showed no presence of the FBED Plan. Instead a strategy document released by NUPRC on January 1, 2024 titled “NUPRC Regulatory Action Plan 2024 & Near Term (2024 – 2026)”, highlighted the implementation of the Frontier Exploration Fund as part of its action plan to grow reserves and production, but lack details on the FBED Plan.

The FBED Plan as a document is supposed to contain the Commission’s exploration strategy for managing frontier acreages for the year under review. In addition, review of exploration work program in the frontier basins submitted by NNPC Limited, proposed expenditures from the Escrow Account that houses the fund, promotion of exploration activities, information on frontier basin petroleum resources, planning analysis for unassigned acreages, and outlining proposed drilling or testing operations that the Commission has requested NNPC Limited to undertake.

An inquiry to NUPRC seeking clarification on the FBED Plan as contained in the regulation up to the time of publishing this piece got the response “we are working on your request”.

Prior to the Frontier Exploration Fund, there was a division (Frontier Exploration Service) at NNPC, the predecessor entity to NNPC Limited, responsible for prospecting activities in frontier basins. Since the PIA came into force, this responsibility has been transferred to the regulator that now oversees the Frontier Exploration Fund.

In response to queries on the funding sources deployed in frontier basins, Olufemi Soneye, Chief Corporate Communication Officer of NNPC Limited stated that “Before the enactment of the Petroleum Industry Act (PIA) on August 16, 2021, Frontier Exploration activities in Nigerian Frontier Basins, including the Benue Trough and Chad Basin, were directly funded from the Federation Account. Post the PIA implementation, effective August 16, 2021, funding for frontier exploration operations shifted to Section 9 of the PIA. This involves 30% allocation from NNPC Production Sharing Contract (PSC) profit oil and gas, alongside service contracts”.

Soneye additionally expressed that “The initial exploration of the Kolmani field in Gombe/Bauchi States was funded through the Federation account. However, it now adheres to the PSC governance structure led by NEPL in collaboration with NNDC, spanning OPLs 809/810 in the Gongola Basin of Upper Benue Trough. Presently, as per PIA provisions, NNPC Ltd collaborates with NUPRC for Frontier exploration activities in basins without commercial hydrocarbon discoveries. The 2024 Frontier Exploration budget has been sanctioned by NUPRC in accordance with PIA provisions. Hence, the ongoing exploration in Nasarawa State – Middle Benue Trough (Ebenyi-1 well Drilling) and Borno State – Chad Basin (Wadi-2 well Drilling) are funded through the Frontier Basins Exploration Fund per PIA provisions. The Bauchi-Gombe Kolmani Integrated Field Development Project follows the PSC structure led by NEPL & NNDC”.

For clarity, NNDC (New Nigeria Development Company Ltd) is a company with roots from 1949 and later incorporated in 1965 to play development finance role in the northern states, and Nigeria as a whole.

The bottom line is that NUPRC’s failure to publish the specifics of the FBED Plan, as outlined in the regulation, has created an information gap on frontier prospecting operations spending, especially with the drilling campaigns in Nasarawa State, Borno State, and the ongoing “development” initiatives in Bauchi State by NNPC Limited. The lack of transparency becomes more apparent given the non production of the 2022 annual report from the state-owned enterprise, a document that would have showed the expenditure figures. For “regulatory certainty and predictability”, it is crucial for the regulator to follow the provisions outlined in its regulation.

Adeniyi Adeoloye, a petroleum geoscientist based in Calgary, Canada, is a consulting Editorial Associate with Africa Oil+Gas Report.

 

 

 

 


ENI Makes Another “Significant“  Discovery in Côte d’Ivoire

By Adeniyi Adeoloye

Italian major ENI has made yet another discovery offshore Côte d’Ivoire. This is coming after its Baleine find in 2021 which commenced production in August 2023.

The discovery, christened Calao, was penetrated by the Murene 1X well.

“Light oil, gas and condensates were encountered at different intervals in Cenomanian age reservoirs with permeability value of good to excellent”, ENI says in a release, adding that “drilling operations took place approximately 45 kilometres off the coast in block CI-205, reaching a depth of 5,000 metres in water depths of around 2,200 metres”.

The find is estimated to hold between 1 and 1.5Billion barrels of oil equivalent. If the Infrastructure led strategy of the company is still in play, this new discovered hydrocarbon pool can hit the market within a few years, the Italian explorer explains.

With Calao, ENI has made discoveries in the two blocks it acquired in Cote d’Ivoire in 2017.

Baleine was discovered in Block CI- 101.

The two deep offshore blocks, denominated CI-101 (Baleine) and CI-205 (Calao), are in the eastern part of the prolific Tano basin. Collectively, they, and cover a total area of about 2,850 square kilometers. Block CI-101 is at water depths of between 200 and 2,500 metres  and located 50kilometres  south of the capital Abidjan, while block CI-205 is at water depths of between 2,000 and 2,700 metres, and located 80 kilometres south-west from the city.

ENI has maintained a presence in Côte d’Ivoire since 2015 holding equity in various blocks including block CI-205, CI-101, CI-501, CI-801, and CI-802, all in partnership with the National Oil Company, Petroci Holding.

 

 

 

 

 

 


Angola Regulator Expects 16% Jump in Drilling Activity 

Angola National Oil, Gas and Biofuels Agency (ANPG) has announced that 43 oil wells are planned to be drilled in 2024, six more wells compared to the 37 wells drilled in 2023.

The agency lamented that the country is currently producing 1.1Million barrels daily, “quantities that would reach 1.2 million barrels of oil per day, if it weren’t for the daily losses of 90 thousand barrels of oil.

“In the last five years, the country recorded unplanned production losses of around 170Million barrels of oil, due to the aging of most of the concessions, designed to operate between 15 and 20 years, some already having existed for over 60 years”, said ANPG production director, Ana Rosa Miala.

“And our large installations such as Girassol and Dália are already more than 20 years old and this means that the systems in these installations have more failures, the failures are more recurrent. Regular preventive maintenance is no longer enough to mitigate these failures, greater effort and investment are required”, she explained.

To mitigate the sharp decline in production the agency said, “bidding for new concessions was resumed, and incentives were created for the continuous stay of the country’s old investors and the entry of new ones.

Paulino Jerónimo, the outgoing president of the board of directors of ANPG, told the press that the five-year-old regulatory agency had essentially grown in a period of tumult. Two of ANPG’s five years in existence were marked by the COVID-19 pandemic, which constituted “a great challenge” for the agency.

 

 


Africa and Latin America set to lead high-impact well drilling in 2024, eyeing rebound after poor 2023

By Rystad Energy

The upstream industry hopes 2024 can be a bounce-back year for high-impact oil and gas drilling after a lackluster 2023, with Africa and Latin America likely to spearhead activities. Rystad Energy has identified 36 potential high-impact wells to be drilled or spud in 2024, the highest annual total since we started tracking the market in 2015. This would be a sizeable jump from the 27 high-impact wells drilled last year, and operators will hope for a better success rate.

Of these 36 potentially significant wells, 13 are in Africa and 10 in Latin America, accounting for almost 64% of the global total. Explorers will drill six of these in Asia, two each in the Middle East, Europe and North America and one in Oceania, with TOTALEnergies’ planned exploration in Papua New Guinea.

Only eight of the 27 high-impact wells drilled in 2023 resulted in commercially movable volumes, a success rate of less than 30%, well below the annual average of 42%. These wells discovered volumes of 1Billion barrels of oil equivalent (BOE), a sharp decline from the 3.5Billion BOE found in 2022. These high-impact wells accounted for 20% of the 5Billion BOE discovered by all exploration activities globally last year. To make matters worse, 2023 was an expensive year, with drilling costs rising due to a significantly tighter rig market than in prior years, worsening the blow of a low success rate.

Rystad Energy classifies high-impact wells through a combination of factors, including the size of the prospect, whether they would unlock new hydrocarbon resources in frontier areas or emerging basins and their significance to an operator’s strategy.

“Despite disappointing results in 2023, the exploration industry remains confident that fortunes can turn around this year. Drillers are still investing in frontier, emerging and play-opening areas to find volumes, but they are more targeted in their exploration strategies. Companies are deprioritizing any short-term pay-off in favor of multi-year plans and focusing on wells that best fit their long-term vision. This is a fundamental shift in the market and is unlikely to change even if 2024 success remains muted,” says Taiyab Zain Shariff, vice president of upstream research at Rystad Energy.

Learn more with Rystad Energy’s Upstream Solution.

Of the high-impact wells planned this year, 14 will be drilled in frontier and emerging basins, with three opening up new plays entirely. So, despite a disappointing 2023, many operators continue exploring new plays and focusing on frontier regions. Eight planned high-impact wells target prospective offshore resources of more than 430 million BOE and considerable prospective onshore resources of more than 230 million BOE. The remaining 11 wells are strategically relevant for their respective operators, meaning exploration success would help them gain traction in the region or inform future operational decisions. If all planned wells proceed as scheduled, 2024 would see the highest number of high-impact wells drilled in at least 10 years, since we started tracking these wells in 2015.

The oil and gas majors – BP, Chevron, Eni, ExxonMobil, Shell and TOTALEnergies – typically dominate high-impact well drilling, which will continue in 2024. About 16 (44%) of the total wells planned will be drilled by these companies, with TOTALEnergies planning five, Shell three, and Chevron, Eni and ExxonMobil targeting two each. Most drilling will be undertaken in the Atlantic margin and Asian waters. National oil companies (NOCs) and internationally focused NOCs (INOCs) will account for eight (22%) of this year’s planned wells, with upstream operators responsible for 17% and smaller operators for the remainder.

Around 70% of African wells will be drilled in frontier and emerging basins or will open new plays. Important frontier wells include in the Red Sea offshore Egypt, in the Angoche Basin offshore Mozambique and in the Namibe Basin offshore Angola.

High-impact drilling in the Americas will be primarily focused on Latin America and dominated by wells that hold significance for each operator’s long-term goals rather than frontier basins. Only two of the 12 wells planned in the Americas are in North America, with one each in the US and Canada. In Latin America, a frontier well planned for offshore Argentina would be the first drilled well in the Argentine Basin. ExxonMobil also plans to drill a frontier well in the Orphan Basin offshore Canada.

A total of six high-impact wells are planned in Asia this year, including ultra-deepwater offshore drilling in Indonesia and Malaysia, the opening of India’s Andaman Basin and a potentially resource-rich well offshore China.


Invictus Formally Declares a Natural Gas Discovery in Zimbabwe

By Sully Manope, in Windhoek

Australian minnow, Invictus Energy, has moved from citing “encouraging signs of hydrocarbon”, in its drilling campaign in Zimbabwe, to formally declaring a hydrocarbon discovery.

The company is on the sidetrack to the Mukuyu-2 well, (Mikuyu-2STK), its fourth hole on the Mukuyu prospect, in the Caborra Basa project, onshore Zimbabwe.

“We are delighted to declare a gas discovery from the Mukuyu-2 sidetrack well in the Upper Angwa formation”, Scott Macmillian, Invictus’ Managing Director, declared in a statement. “The discovery represents one of the most significant developments in the onshore Southern Africa oil and gas industry for decades”.

Invictus explains that the decision to call a discovery was made after an intermediate wireline logging was run with the primary objective of obtaining hydrocarbon samples from Upper Angwa reservoirs located close to the base of the Upper Angwa formation following indications from real-time logging while drilling and mudgas.

“A limited suite of wireline logging data was acquired over the interval from 1,969metre Measured Depth (MD) to 2,975mMD in the Basal Pebbly Arkose and Upper Angwa formations, which identified multiple hydrocarbon bearing reservoirs in the Upper Angwa. A total of four hydrocarbon samples were recovered to surface from two separate zones in the Upper Angwa, using the wireline formation testing tool. A further two formation water samples were recovered from the Basal Pebbly Arkose formation”.

Wireline log interpretation calculates a preliminary net pay estimate of 13.9metres for the Upper Angwa, “however, this estimate is still subject to further calibration of the logs with core and fluid data to determine appropriate net cutoffs and subsequent pay estimates”, Invictus explains. “Significant additional gross sands were intersected within the Upper Angwa gas leg but are below the current net reservoir cutoff. These intervals may have better reservoir development elsewhere in the Mukuyu field and along with the refinement to the net pay criteria represents additional upside. Further appraisal and technical evaluation of log, core, seismic and well test data is required to determine the full extent of the resource size.

Prior to the Mukuyu-2 Sidetrack, Invictus had earlier drilled Mukuyu-1, Mukuyu 1 Sidetrack as well as Mukuyu 2. In all cases it filled the media with upbeat reports of “elevated mud gas and fluorescence were encountered and strong gas shows”.

Now “the Mukuyu-2 discovery, seven kilometres away and 450 metres updip of the Mukuyu-1 well, which can subsequently be classified as a discovery, provides confirmation of the large potential of the Mukuyu field which has a structural closure of over 200km2 “, Macmillian says. “With additional hydrocarbon bearing reservoirs ahead, the focus now is to complete the drilling and evaluation program and obtain further wireline data including fluid samples to declare an additional discovery from the Lower Angwa formation.”

Gas and fluid properties from the recovered samples will be confirmed following laboratory testing once the sample bottles are dispatched from the rig for analysis. No additional fluid samples were captured in order to preserve the wireline formation sampling tool and remaining sample chambers for use in the interpreted Lower Angwa hydrocarbon-bearing zones where thicker sandstone units were penetrated in Mukuyu-2.

The Exalo Rig 202 is drilling ahead “towards the total depth at approximately 3,400mMD sidetrack section  through the remaining Upper and Lower Angwa reservoirs where multiple hydrocarbon bearing zones were intersected in Mukuyu-2.”, Invictus notes in that report.

 


BW Energy Announces ‘New Oil’ in Gabon’s Hibiscus South

The Norwegian explorer, BW Energy has announced that the DHBSM-1 appraisal well has encountered commercial volumes of oil in the Hibiscus South satellite prospect. The company plans to return to the well to complete it as a production well in early 2024.

The DHBSM-1 well was drilled from the MaBoMo production platform to a total depth of 6,002 metres. The target area is located approximately five kilometres southwest of the MaBoMo and was drilled by the Borr Norve jack-up rig.

“Evaluation of logging data, sample examination and formation pressure measurements confirm approximately 20 metres of pay in an overall hydrocarbon column of 26.5 metres in the Gamba formation”, BW Energy explains in a statement.

“The well data confirms that the Hibiscus South structure is a separate accumulation with a deeper oil-water contact than the nearby Hibiscus Field.  This will enable the Company to book additional reserves not currently included in its annual statement of reserves and provide the opportunity to drill one or more additional production wells from the MaBoMo facility.

Preliminary evaluation indicates gross recoverable reserves of 6 to 7Million barrels of oil and approximately 16 million barrels of oil in place, in line with the mid-case pre-drill expectations reported prior to the commencement of drilling operations.


Only Five Wells Drilled in Ghana in all of Six Months

By Fred Akanni, in Accra

The drillship Noble Venturer was the only rig active in Ghana for the entire first half of 2023.

It was active on a total of nine wells on one field: the Jubilee field, in the country’s western offshore.

Out of the nine probes, Noble Venturer was drilling in five and completing in four wells during those six months.

The rig drilled J62-WI, a Water Injector, J64-P, an Oil Producer, J65-WI Water Injector, J64-P, an Oil Producer and J66-P Oil Producer. In the same period, it completed J61-P, an Oil Producer, J64-P Oil Producer. J65-WI, a Water Injector and J63-P Oil Producer.

There was no rigsite activity by any other company, including ENI, the only major oil firm operating in the country.

Norwegian junior, Aker Energy, which has reached a development stage on Deepwater Tano/Cape Three Points (DWT/CTP, had only received approval ,as of May 2023, for the new Field Development Plan.

Most E&P firms operating in Ghana are third tier independents with little risk appetite and dismal execution capacity. One company no longer has Ghana included on its presentation profile, but the authorities keep publishing claims that it has a work programme it is executing.


Angolan Rig Count Declines; the Country Moderates Output Ambition

Angolan rig activity fell slightly in September 2023, with, twelve (12) drilling units in operation, compared with 14 rigs active in August 2023.

The country’s crude oil output also continued on a downward slope for the third consecutive month in September 2023. The output was 1,112,685 barrels of oil (BOPD), compared with August 2023’s daily average of 1,128,878BOPD.

It was a mere 1.4% output drop, but Angola has declared it was pausing the ambition to reach 1.2MMBOPD, at least until sometime in 2024. Belarmino Chitangueleca, executive director at the National Agency of Petroleum, Gas and Biofuels (ANPG), reportedly told Reuters on October 18, 2023, that Angola expects to maintain its current crude oil production of 1.1MMBOPD into 2024. That’s a revision of the statement made in June 2023 by Ana Miala, the ANPG’s director of production, that the country wants “to reach, and stay around, a production of .1.2MMBOPD, in the medium term”.

At the drill sites, seven (7) drill ships, (Sonandril West Gemini, Sonangol Libongos, Valaris DS-09, Sonangol Quenguela, Transocean Skyros, Valaris DS 12 and Sapem 12000 one (1) Tension Leg Platform TLP-A, and SKD Jaya Tender were working in the deepwater, with one (1) Jack Up, Shelf Drilling’s  Tenaciou active in shallow water. There were two land drilling rigs: a FALCON HP-1000 and SA_02 land rigs.

These units carried out work in twenty-six (26) wells, compared with 27 wells in August 2023.

 


Chinese Sloppiness Fingered for Fatality as Uganda Halts Operations at an Oil Field

The Petroleum Authority Uganda (PAU) has ordered immediate halt to all operations at the Kingfisher oilfield development in the country, citing safety concerns in which the Authority emphasized it underscores the importance of ensuring the safety of oilfield workers and minimizing risks in the oil and gas sector.

The order follows a fatal accident in the area that occurred on October 6, 2023, which resulted in the death of one of the sub-contractor’s staff members.

A motor accident claimed the life of a security guard at the gate of one of the camps of the CNOOC Uganda Ltd (CUL), in Buhuka, Kyangwali sub county in Kikube District.

PAU’s executive director, Ernest Rubondo, stated that the accident was deemed unacceptable, especially considering previous incidents that the agency had brought to the attention of (CUL), the operator of the field.

Kingfisher project

In accordance with Section 177 of the Petroleum (Exploration, Development and Production) Act, 2013, the PAU directed CUL to halt all Kingfisher field development operations from 00.00 hours on Saturday, October 7, 2023, until further notice.

The PAU  also convened a meeting of top executives from joint venture partners, which include CNOOC, TotalEnergies, and Uganda National Oil Company, to review the situation and provide guidance regarding the ongoing oilfield developments.

The Kingfisher project operated by CNOOC, is one of Uganda’s oilfields undergoing intensified drilling works with the aim of being ready for oil production by 2025. The project includes the development of a central processing facility (CPF), 31 wells (including 20 producers and 11 injectors), over four well pads and 19kilometres of flowlines adjoining the CPF. The first well was spudded in January 2023.

The field development also includes the development of a lake water abstraction station and other infrastructure such as temporary and permanent camps, a materials yard and access roads.

The production from the field is expected to be 40,000 barrels per day, which will start to decline after five years.

TOTALEnergies-operated Tilenga project is projected to produce 190,000 barrels per day at peak production.


Second Well Commences in Zimbabwe’s Frontier Probe

The Australian junior, Invictus Energy, has reported the spud of Mukuyu-2 well at its 80% owned and operated Cabora Bassa Project in Zimbabwe.

The company says it is on track to complete drilling and evaluation within estimated 50-60 days. In that period it is expected to have drilled to a planned total depth of 3,750 metres and conducted petrophysical evaluation of the well

Since the last update, the Exalo Rig 202 has drilled the 17 ½” surface hole section down to a depth of approximately 496m Measured Depth (“MD”).

Rig 202 will continue to drill ahead in the 12 ¼” inch intermediate hole section through the Dande and Forest targets to a planned total section depth of approximately 2,040metre Measured Depth (MD) within the Pebbly Arkose formation before running a wireline logging evaluation suite and then setting the 9 ⅝” casing.

After setting the 9 ⅝” casing the rig will drill ahead in the 8 ½” hole section through the reminder of the Pebbly Arkose through to the primary targets in the Upper Angwa (Alternations Member) and to the Lower Angwa (Massive Member) to approximately 3,750 metres MD before running a wireline logging evaluation suite.

Mukuyu-2 Well Objectives

Mukuyu-2 will test the primary target interval, the Triassic Upper Angwa formation, sitting approximately 450metres updip from Mukuyu-1 where hydrocarbons were intersected.

The well will also penetrate multiple additional targets including the Dande (JurassicCretaceous), Forest and Pebbly Arkose (both Triassic) formations, as well as the previously untested Lower Angwa sequence within the Mukuyu anticline in the central horst structure. Invictus  will provide regular updates as the drilling campaign progresses.

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