All posts tagged news


bp Commences Oil Output From Angola’s Platina: Planned Peak is 30KBPD

bp Angola’s Platina project in Block 18 has started production. The project was brought online both ahead of schedule and under the contractor group’s initial budget. Angola’s National Agency for Petroleum, Gas, and Biofuels (ANPG) considers the project a significant reinforcement of Angola’s oil production capacity.

Platina is a subsea tie-back development to the existing Greater Plutonio floating production, storage, and offloading (FPSO) vessel on Block 18.  It will access an estimated 44 million barrels of oil reserves and, at peak, is expected to add 30 thousand barrels of oil per day to Block 18 production. The project was delivered 44 days ahead of schedule and 25% below the original budget. Its development increased expected recoverable resilient reserves by 10%. The development of resilient hydrocarbon resources focused on maximizing value from existing positions and on high-quality fast-payback new projects is central to bp’s strategy.

Belarmino Chitangueleca, Acting Chief Executive Officer of ANPG highlighted the importance of Platina’s first oil in Block 18 and its contribution to oil production levels in Angola: “With this and other projects, we are gradually meeting the objectives of preventing production decline and increasing production levels with the ongoing bidding of projects.”

Platina, the development of which was approved in December 2018, is the first new development on Block 18 since Greater Plutonio started up in 2007. It is bp’s first newly operated development in Angola since the start of production from the PSVM development in Block 31 in 2012.

Platina is the seventh new project to start production for bp worldwide in 2021. It follows new projects in Egypt, India, Trinidad, two in the US Gulf of Mexico, and an earlier project on Block 17 offshore Angola.

bp Angola is the operator and has a 46% stake in Block 18, Sinopec has a 37.72% stake and Sonangol P&P 16.28%.​


NETCO, IDSL Record Large Losses of Revenue, Says NNPC Annual Report

NNPC’s upstream technical service subsidiaries NETCO and IDSL, were badly bruised by the challenges in the oil and gas industry in 2020, recording large losses of revenue but eventually clawing victory from the jaws of defeat.

The two companies managed to each turn a profit despite their large year on year declines in revenue. NETCO made…

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Nigeria’s President Signs the Petroleum Industry Bill Into Law

President Muhammadu Buhari has signed the Petroleum Industry Bill 2021 into law.

“Working from home in five days quarantine as required by the Presidential Steering Committee on COVID-19 after returning from London on Friday August 13, the President assented to the Bill Monday August 16, 2021, in his determination to fulfill his constitutional duty”, according to a press statement issued by the Nigerian state house and signed by Femi Adesina, special adviser to the President (Media and Publicity).

“The ceremonial part of the new legislation will be done on Wednesday”, August 18, 2021, “after the days of mandatory isolation would have been fulfilled”, the statement adds.

“The Petroleum Industry Act provides legal, governance, regulatory and fiscal framework for the Nigerian petroleum industry, the development of host communities, and related matters.

“The Senate had passed the Bill on July 15, 2021, while the House of Representatives did same on July 16, thus ending a long wait since early 2000s, and notching another high for the Buhari administration”.

 


Advance Military Teams from SADC Arrive Mozambique

Advance teams from the Southern African Development Community (SADC) have arrived in Mozambique to support the battle against the Islamist terrorist groups, known locally as “Al-Shabaab”.

Colonel Omar Saranga, the Ministry’s spokesperson dismissed the news that the regional bloc’s full Standby Force, was already in the country.

The advance teams, he explained, are in Maputo and in Palma (a town in the province of Cabo Delgado), to prepare the deployment of the main force.

Saranga confirmed that General Xolani Mankayi, head of South Africa’s 43 Brigade, the rapid intervention unit of the South African National Defence Force (SANDF), will command the SADC Full Standby Force. Mankayi is already in Mozambique, “and he has been received by the Defence Minister and by the Chief of Staff of the Mozambican Armed Forces. He has received a briefing on the situation”, Saranga said. Last August, the energy press speculated that General Manyi had instructed the 43 Brigade to begin an intensive training programme for possible action in Cabo Delgado if President Cyril Ramaphosa decides to intervene. “Questions of command have been outlined in the combined planning”, Saranga offered. “Right now, what is important to say is not who will command or cease to command. The troops will be led by their respective commands, but the chief coordinator is the Republic of Mozambique”.

Islamic insurgents have killed hundreds of people and turned thousands to refugees in towns and villages located in the province and close to the Afungi Peninsula, where the TOTALEnergies operated 13 Million Metric Tonnes Per Annum Liquefied Natural Gas project is sited.

In late March 2021, just when TOTALEnergies’ workers returned to site in Afungi to continue construction, Islamic insurgents made their most sweeping attack on the neighboring Palma town.

TOTALEnergies pulled out its workers after that attack and Mozambique has since been looking for a way to permanently root out renewed attacks. Part of the effort was to call on member countries of the Southern African Development Commission (SADC) to provide military assistance.

Saranga waved aside questions regarding combat operations of Rwandan troops who arrived in the week of July 12, 2021. The questions referenced report by the independent newssheet “Carta de Mocambique, that soldiers of the Rwanda Defence Force (RDF) left their base on the Afungi Peninsula to patrol a forested area close to the town of Palma. They reportedly found a terrorist group in the Quionga administrative post, retreating towards the Tanzanian border, engaged them and killed 30 terrorists. Saranga said that questions about Rwandan forces “are operational question and I can’t answer it. It’s the force commander who can answer. The enemy may be watching our actions to see what direction we are going to take”. But he volunteered that the SADC member states who will take part in the Standby Force are South Africa, Tanzania, Angola, and Botswana, “and we are confident that, during the operations, more countries may express an interest in supporting Mozambique”.

“The SADC heads of state summit, held in Maputo on 23 June, approved a mandate for the deployment of the Standby Force”, Col. Saranga told reporters. “The objective was to support the national efforts to fight against terrorism in Cabo Delgado. Following up this mandate, in late June there was a joint planning conference, and this event outlined the next steps that should be taken to deploy the force”.

“What is happening right now is the implementation of this plan”, he continued. “The mandate envisaged that the deployment of the force should happen as from 15 July. So from 15 July to now, activities have been undertaken in order to receive this force, which is rather substantial. Steps are being taken so that it can be received and carry out its work. That means there are advance teams that are working with our troops on the ground to receive the force.


PIB: 3% of Nigeria’s Oil Industry OPEX, around $500Million, is Adequate for Hostcom Development, Say Oil Industry Leaders

By Fred Akanni, in Warri

Nigerian oil Industry leaders are reacting to agitations that 3% of Operating Expenses (OPEX) of companies licenced to operate on any hydrocarbon acreage be paid into a Host Community Trust Fund for the communities around the subject acreage, as mandated in the current draft of the Petroleum Industry Bill, is too low.

“I believe there is too much uninformed noise”, says Joseph Nwakwue, retired ExxonMobil Petroleum Engineer, former President of the Society of Petroleum Engineers (SPE), and former special assistant to the Minister of State for Petroleum Resources. “This provision is to provide direct benefits to the host community. It needs to be at a level that does not significantly increase the unit OPEX. We had estimated the impact on cost of operations and hence profitability of the upstream. I really believe 2.5% would work”.

The Petroleum Industry Bill (PIB) is close to final passage at both the House of Representatives and the Senate. But whereas the Senate has passed “the conference committee report in which 3% of companies OPEX in the last calendar year is retained for Host Community Trust Fund”, the House of Representatives stepped down the bill after an hour long, rowdy closed-door session assessing the committee report, as lawmakers from Bayelsa, Delta, and Rivers States, the country’s largest hydrocarbon producers, opposed what they consider a low contribution into Host Community Development.

Elected legislators representing the Niger Delta region at the House of Representatives, are championing 5% of the total operating expenses (OPEX) over 3%. The Niger Delta hosts over 99.9% of all hydrocarbon currently produced. The Dahomey basin, located in the country’s southwest, produces less than 1% of the nation’s output. No other sedimentary basin has contributed to the national production since first oil in 1958.

But those who routinely pay close attention to value creation in oil and gas activity, have a nuanced view.

“3% of OPEX, currently being paid to the Niger Delta Development Commission (NDDC) for the region’s development is estimated at about $500Million annually”, says Taiwo Oyedele, Fiscal Policy Partner and Africa Tax Leader at PwC, the global firm of consultants. “Unfortunately, this has not had any meaningful impact due to mismanagement. My view is that 3% of OPEX for host community development is a fair percentage given the need to make investment in the sector attractive and viable”, Oyedele explains. “I expect that the governance structure as proposed under the PIB will ensure that the funds deliver concrete results and if this is sustained, the amounts available will increase as more investments are attracted. It may also provide a compelling basis for NDDC to be scrapped and the contributions added to the Host Communities”.

The governance structure for Host Community Fund that Oyedele refers to in the PIB, is fairly rigorous. Unlike the payment to NDDC, the PIB mandates clear guidelines on governance of the funds, which, unlike NDDC, are to be locally applied, not granted “globally” to state governments. The draft of the PIB says that the Board of Trustees of Host Community Trust Fund, to be set up by the oil company/ies “shall in each year allocate from the host communities development trust fund, a sum equivalent -(a) 75% to the capital fund out of which the Board of Trustees shall make disbursements for projects in each of the host community as may be determined by the management committee, provided that any sums not utilised in a given financial year shall be rolled over and utilized in subsequent year; (b) 20% to the reserve fund, which sums shall be invested for the utilisation of the host community development trust whenever there is a cessation in the contribution payable by the oil ompany/ies; and (c) to an amount not exceeding 5% to be utilised solely for administrative cost of running the trust and special projects, which shall be entrusted by the Board of Trustee to the oil company/ies. The law also says that host community development plan shall -(a) specify the community development initiatives required to respond to the findings and strategy identified in the host community needs assessment; (b) determine and specify the projects to implement the specified initiatives; (c) provide a detailed timeline for projects; (d) determine and prepare the budget of the host community development plan; (e) set out the reasons and objectives of each project as supported by the host community needs assessments”.

Oyedele says: “I do not think the agitation (for 5% or even more of the OPEX) is warranted. More focus should be on the judicious utilisation of the 3% for Host Community in addition to 3% for NDDC and 13% Derivation for the oil producing states. All together these funds are capable of transforming the region and providing opportunities for the people”. 

Africa Oil+Gas Report asked five Chief Executives of indigenous companies, all of them demanding not to be named. Two did not respond. Two of them nodded in preference of 3% of OPEX for the Host Community Trust Fund. The third said he could live with 5%.

Still, there is one industry leader who supports even higher percentages of OPEX than the two bands that members of the National Assembly are bickering about.  “Beyond a 10% OPEX allocation, I would support a 10% equity participation in the lease”, argues Nedo Osanyande, a widely respected geoscientist, former General Manager of Sustainable Development and Community Relations at Shell Nigeria, and fellow of the prestigious Nigerian Association of Petroleum Explorationists (NAPE). “In the absence of equity participation, I’d support a 10% OPEX allocation”, he says. “Importantly, a sizeable part of this must be spent (at least initially) in community capacity development in managing this fund. Currently, the social organisation capacity is lacking. This is the reason the funds allocation so far – however inadequate –  has not been judiciously utilized”.

Mr. Osanyande says that “with the right social organization capacity, financial resources captured by elites, strong men, and the like would be reduced. Thus far, such capture results in the funds not being invested in the communities”. Arguing that everyone one gains if the communities are happy, he concludes that “hydrocarbon production could easily double, and OPEX costs halved if the hydrocarbon producing communities are happy”. 

But Mr. Osayande’s figures are not popular among his colleagues.

Says a consultant geoscientist who has worked on virtually every draft of the Petroleum Industry Bill since 2008: “Actually the 3, 5 or 10% would have been unnecessary if prior initiatives (13% Derivation, 3% NDDC, 8% Littoral State Allowance, Amnesty payments as well as Niger Delta Ministry mandates) have worked half as expected. They all have not worked because of implementation failures. Some of them are even now being copied as best practice in other countries where they are well implemented”.


ENI’s Latest Ghanaian Discovery: Eban will Reach First Oil Before Pecan Field

Italian explorer ENI has said it will fast-track the development of its latest discovery in Ghana by hooking it up to a Floating Production Storage and Offloading (FPSO) vessel, located eight kilometres away. 

On July 6, 2021, ENI announced Eban, its second discovery on the CTP Block 4 since the Akoma discovery, made in May 2019, and declared that “due to its proximity to existing infrastructure” the Eban-Akoma complex“ can be fast-tracked to production with a subsea tie-in to the John Agyekum Kufuor (JAK) FPSO, with the aim to extend its production plateau and increase production”.

The JAK FPSO is producing 56,000Barrels of Oil Per day and 130Million standard cubic feet of gas from the Sankofa-Nyame, located in the Offshore Cape Three Points (OCTP) block. “The Eban discovery is a testimony to the success of the infrastructure-led exploration strategy that Eni is carrying out in its core assets worldwide”, ENI says.

ENI has preliminarily estimated the potential of the Eban–Akoma complex between 500 and 700Million barrels of oil equivalent in place. The Eban – 1X well is sited approximately eight (8)kilometres Northwest of Sankofa Hub, where the JAK FPSO is located. It was drilled by the Saipem 10000 drillship in a water depth of 545 meters and reached a total depth of 4179 metres(measured depth). Eban – 1X proved a single light oil column of approximately 80metres in a thick sandstone reservoir interval of Cenomanian age with hydrocarbons encountered down to 3949metres (true vertical depth).

If the complex is hooked up as indicated, even if that takes 24 months, its crude and gas will reach the market before the peak of development of the Pecan field, an ultra-deep-water project operated by Aker Energy, which has been in fast-track mode since 2019. The Pecan field, which lies in 2,400 metre water depth in Deepwater Tano Cape Three Points (DWT/CT) block), was earlier held by HessCorp., an American explorer. It was acquired by Aker Energy in June 2018. First oil from the field was expected in the fourth quarter of 2021, but the consequences of COVID-19 has thrown the plans overboard.

ENI says that its new discovery has been assessed “following comprehensive analysis of extensive three dimensional (3D) seismic datasets and well data acquisition including pressure measurements, fluid sampling, and intelligent formation testing with state-of-the-art technology”. The company explains that its “acquired pressure and fluid data (oil density and Gas-to-Oil Ratio) and reservoir properties are consistent with the previous discovery of Akoma and nearby Sankofa field”, and “the production testing data show a well deliverability potential estimated at 5,000BOPD, similar to the wells already in production from Sankofa Field.

“The estimated hydrocarbon in place between the Sankofa field and the Eban-Akoma complex is now in excess of 1.1 Billion BOE and further oil in place upside could be confirmed with an additional appraisal well”, the European major explains. The Joint Venture of CTP Block 4 is operated by Eni (42.469%), on behalf of partners Vitol (33.975%), GNPC (10%), Woodfields (9,556%), GNPC Explorco (4,00%).


Tullow Oil Shifts Focus from Exploration to Production

Tullow Oil will now focus on producing all the oil it has discovered, as well as invest spare cash in hub size, near-term crude oil discoveries, rather than foraging for new oil anywhere.

The Irish company no longer wants to be seen as a leading wildcatter in Africa’s frontier, a description that it wore like a badge up until a few years ago.

“We have shifted our focus away from exploration and development and long-cycle capital commitments to a production focused company with a robust, cash generative business plan”, Rahul Dhir, the Chief Executive Officer, says in a pre-Annual General Meeting statement. 

The company’s cash cow remains the assets in Ghana. From January 2021, Tullow is implementing a 10-year business plan “which focuses over 90% of our capital investment in our high margin production assets in West Africa”, Dhir says. 

For ‘West Africa’, read ‘Ghana’, as Tullow has sold its stakes in Equatorial Guinea and most of Gabon.

The London listed junior started a multi-year drilling campaign in Ghana, planning to drill four wells in total in 2021, consisting of two production and one water injection well on its flagship Jubilee field and one gas injector well on the relatively less prolific TEN field. 

“We have successfully drilled the first Jubilee production well and the Jubilee water injector well, and the reservoirs encountered are in line with expectations. The rig will now carry out the completion of these two wells with tie-in and start-up of both wells expected in the third quarter of 2021”.

The business plan, Mr. Dhir says, “will generate material cashflow to self-fund high return, fast payback investment opportunities and reduce debt – even at low oil prices”. 

Dhir’s plan proposes: 

• Reducing our cost base: we are delivering cost savings across the business including annual G&A cash savings of $125Million. We are becoming a performance focused organisation where every barrel matters and every dollar counts.

• Improving operational performance: our ongoing operational turnaround is delivering more reliable and consistent operating performance with 98% average uptime year-to-date at Jubilee and TEN and better utilisation of our existing infrastructure.

• Rigorous capital allocation: we are focusing on high return and fast payback investments in our production assets and have significantly reduced capital allocation to long-cycle projects.

• Reducing our debt: We have sold our interests in Uganda, Equatorial Guinea and the Dussafu Marin permit in Gabon, raising over $700 million in proceeds. This asset sale programme puts us well on the way to realizing c.$1Billion over two years through assets sales and cost reductions.

• Simplifying our capital structure: we recently completed a comprehensive debt refinancing which gives us the financial stability to deliver our business plan.

• Strong ESG focus: we announced in March that we aim to become Net Zero (Scope 1 & 2) by 2030 as part of our commitment to sustainability. In addition, we maintain our commitment to social investment and developing local content.

Group production to the end of May 2021 averaged c.62,000 Barrels of Oil Per Day(BOPD), which, Dhir says, is in line with expectations. 

“This figure reflects the completion of the sale of our Equatorial Guinea interests on March 31, 2021, with no production from these assets recorded past the first quarter. On June 9, 2021, we announced the sale completion of the Dussafu Marin permit in Gabon and we will adjust our full year guidance to reflect both these divestments in our upcoming Trading Statement on 14 July 2021.

“In Ghana, our operational improvement plan is delivering results with 98% average uptime year-to-date across both the Jubilee and TEN FPSOs. As we have previously stated, reliable gas offtake and water injection are an important part of our strategy to optimise reservoir performance and address production decline”. 


South Africa Sprouts New Shoots

In the last five years, several E&P companies, primarily owned by South Africans, have left the upstream market, such that it is tempting to declare the end of the growth of South African E&Pindependents. 

JSE listed SacOil, badly burned by its dealings in Nigeria with local partners Transcorp and NigDel, has turned into a downstream company and changed its name to Efora. 

Thombo Petroleum, owned by Trevor Ridley, former Petroleum Advisor at BHP Billiton, disappeared into the folds of Canadian owned Africa Energy Corp.

But apart from Sasol Exploration and Production International, which is the most visible and best resourced South African bornE&P company, there are a number of companies to consider:

JSE and ASX listed Renergen describes itself as an integrated alternative and renewable energy business that invests in early-tage alternative energy projects.

But it started its project life six years ago by acquiring an onshore natural gas acreage from Molopo South Africa Exploration and Production. Renergen holds the first, and currently only, onshore petroleum production right in South Africa. 

Several homegrown independent South African companies, including Tshipise Energy (Pty) and Sungu Sungu Petroleum, are exploring for natural gas, in coal beds, in the Karoo and offshore Orange Basin, but their distance to development is, at best, far off. 

Renergen is the only one pumping natural gas from subsurface reservoirs into the local market. It has been supplying compressed natural gas to transportation companies since May 2016.

South African National Petroleum Company (formerly PetroSA), the only other natural gas producer in the country, is a state-owned enterprise.

Renergen is working on ramping up production from its acreage, which holds an estimated 142Billion standard cubic feet of proven and probable reserves, near Virginia, about 300km southwest of Johannesburg. It has moved intoliquefied natural gas (LNG) production, “primarily serving the growing domestic heavy duty truck market across Africa and emerging markets”, it says. Renergen has signed an offtake agreement with South African Breweries (SAB) for the supply of liquefied natural gas to power its delivery trucks. For this project, it initially rolled out compressed natural gas to a small fleet of SAB trucks in Gauteng, the country’s major commercial province.

A POTENTIAL STAR IN THE SOUTH AFRICAN E&PFIRMAMENT is Sunbird, a gas explorer and developer which owns a 76% interest in the Ibhubesi Gas Project, Block 2A, offshore of the west coast of South Africa and is the operator of the block. The company was originally owned by Australians, and was sold to South Africans in 2016. The Ibhubesi Gas Project is the country’s largest, undeveloped gas discovery, in the opinion of Sunbird and the local media. Theindependently certified gas reserves are 540 Bcf (2P) with “best estimate” prospectivity of close to 8 Tcf of gas, according to the company. The immediate focus of the project is provision of gas to the Ankerlig Power Station, an 11 year old, 1,338MW capacity thermal plant, designed to be fired by natural gas, but instead, utilizing expensive diesel fuel.Sunbird’s JV partner PetroSA, holds the remaining 24% in Ibhubesi.

Sunbird, for now, remains no more than a potential.

Five years after the Department of Environmental Affairs (DEA) issued an Environmental Authorisation (EA) for the project, the company is not anywhere close to concluding the gas sales negotiations with Eskom, the South African state power utility which owns the Ankerlig power plant. Nor is Sunbird seen to be progressing any deal to sell gas for industrial uses like Renergen is doing.  


TOTAL Boosts Gross Angolan Output With a 40,000BOPD Development

French major TOTAL, has announced the start of production from Zinia Phase 2 short-cycle project, in its prolific Block 17, in deepwater off Angola.

The field is hooked up to the existing Pazflor’s FPSO (Floating Production, Storage and Offloading unit). 

The project includes the drilling of nine wells and is expected to reach a production of 40,000 barrels of oil per day by mid-2022. 

TOTAL operates Block 17 with 38%. Partners include Equinor 22.16%, ExxonMobil 19% and BP 15.84% and Sonangol P&P (5%). The contractor group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor. 

Gross crude oil volume exported from Block 17 in March 2021 was 10, 455,209 barrels, amounting to 337, 265BOPD, according to Angolan government statistics.

Located in water depths from 600 to 1,200 metres and about 150 kilometres from the Angolan coast, Zinia Phase 2 resources are estimated at 65Million barrels of oil. 

 

 

TOTAL said that the project’s entire development “was carried out according to schedule and for a CAPEX more than 10% below budget, representing a saving of $150Million. 

“It involved more than 3Million manhours of work, of which 2 million were performed in Angola, without any incident”.

The Block 17 production license was recently extended until 2045.


ENI’s New Angolan Find to Push Net Output Beyond 115,000BOEPD

By Sully Manope

ENI’s new discovery of oil in Cuica-1 in Angola’s CabaçaDevelopment Area in Block 15/06 takes the Italian player on course of topping up its 100,000Barrels of Oil Per Day (BOPD) net in the country.

The well-head location, intentionally placed close to the Armada Olombendo FPSO East Hub’s subsea network, will allow a fast-track tie-in of the exploration well and relevant production, thus immediately creating value while extending the FPSO production plateau. It is expected that production will start within six months after discovery.

Cuica-1 encountered 80 metres total column of reservoir of light oil (38°API) in Miocene sandstones located in in a water depth of 500 metres, ENI says that this discovery translates to a size estimated between 200 and 250Million barrels of oil in place.

The company net 100,000BOPD (crude oil alone) in total export volume from Blocks O, 3/05. 3/05A, 14, 15 and 15/06 in February 2021, according to the Angolan regulatory agency, ANPG

The New Field Well (NFW) has been drilled as a deviated well by the Libongos drillship and reached a total vertical depth of 4100 metres, good petrophysical properties. The discovery well is going to be sidetracked updip to be placed in an optimal position as a producer well. “The result of the intensive data collection indicates an expected production capacity of around 10,000 barrels of oil per day”, ENI says in a statement.

“Cuica is the second significant oil discovery inside the existing Cabaça Development Area and confirms the Block 15/06 Joint Venture’s commitment to leverage the favorable legal framework on additional exploration activities within existing Development Areas, as promoted through the Presidential Legislative Decree No. 5/18 of 18 May 2018”, the company said.

“Pursuant to the discoveries of Kalimba, Afoxé, Ndungu, Agidigbo, Agogo and appraisals achieved between 2018 and 2020, Cuica represents the first commercial discovery in Block 15/06 after the re-launch of the exploration campaign post-2020 COVID-19 pandemic and the drop of oil price”. A three-year extension of the exploration period of Block 15/06 has been recently granted until November 2023.

 

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