Exploration of frontier basins shall fall under the purview of the Upstream Regulatory Commission, if the Petroleum Industry Bill, under consideration at the National Assembly, becomes law in its current form.
In the wordings of the law, the Commission is now empowered to carry out the functions that the state hydrocarbon company, NNPC, currently performs through its subsidiary: Frontier Exploration Services. One passage in the PIB that expressly indicates this is Section 9, part of which says: “Where data acquired and interpreted under a Petroleum Exploration Licence is, in the judgment of the Commission, requires testing and drilling of identifiable prospects and leads, and no commercial entity has publicly expressed an intention of testing or drilling such prospects, the Commission may engage the services of a competent person to drill or test such prospect and leads on a service fee basis”.
The NNPC is performing this exact function in the ongoing drilling of Kolmani River 3, the second appraisal of the gas discovery made by Shell in 1999.
NNPC reported last year that the first appraisal, Kolmani River 2, in the Gongola Basin, encountered both oil and condensate apart from gas and that they were significant finds. The corporation did not disclose specific petrophysical details of the find, a situation that has aggravated the uncertainty in the conversation around likely economic sizes of hydrocarbon reservoirs in Nigeria’s inland basins.
NNPC is also carrying out exploration activity in the Chad Basin further northwards and has had to stop its seismic operations after insurgents attacked and killed technical workers and some of the security forces.
The PIB says that the function of the Upstream Regulatory Commission, with respect to Frontier Basins shall be to – (a) promote the exploration of the frontier basins of Nigeria; (b) develop exploration strategies and portfolio management for the exploration of unassigned frontier basins in Nigeria; (c) identify opportunities and increase information about the petroleum resources base within frontier basins in Nigeria; (d) undertake studies, analyse and evaluate unassigned frontier basins in Nigeria. The law also says that there shall be maintained, a Frontier Exploration Fund, which shall be 10% of rents on petroleum prospecting licences and petroleum mining leases. “The Commission shall manage the Frontier Exploration Fund in accordance with regulations made under this Act”.
Ghana National Petroleum Corporation (GNPC) says it has achieved the first part of the objective of “becoming a stand-alone Operator by 2019 and a world-class operator by 2027”.
But the Public Interest Accountability Committee (PIAC) demurs, arguing that GNPC is yet to achieve anywhere close to any of the objectives. But the PIAC does not explain its disagreement with GNPC’s claim to operatorship.
According to GNPC, the role of Operator will allow it to retain maximum benefits for Ghanaians including the ability to:
align reserve management policies with national development policy
control technical operations and contracting processes
allow better support of local content development
build effective systems and processes
appropriate a greater share of revenue and benefits for the nation.
“In GNPC’s assessment of progress against its overarching goal, it asserts that it has attained operatorship, citing its role in the Voltaian Basin and the OGH_WB_01 – Shallow water Block”, PIAC says in its annual report. “GNPC further points to its role in managing interests in various assets, including the Saltpond Field decommissioning activities as well as the Corporation’s capacity along the upstream value chain, and capabilities in the upstream petroleum industry, as it is a party to all upstream Petroleum Agreements in Ghana as well as its plans to operate two onshore blocks by 2021 as evidence of its operatorship status”.
PIAC says that its “assessment of GNPC’s claims in the light of the definition of operatorship under Act 919, found no evidence to support GNPC’s claim of attaining operatorship”.
Moroccan authorities have extended the permit for the onshore Sidi Moktar acreage by 24 months, as a result of COVID-19 issues.
The beneficiary of the consideration is Sound Energy.
The company says the extension is a result of regular dialogue with the regulatory authorities, L’Office National des Hydrocarbures et des Mines ONHYM, which has now added 24 months to the initial period of the Petroleum Agreement in order for the Company to complete the committed work programme.
London listed Sound Energy was awarded the petroleum agreement related to the 4,712 square kilometre Sidi Moktar permit on 12 February 2018, with an initial period of 2 years and 6 months. The Company holds an operated 75% position in the permits with the remaining 25% held by ONHYM.
The acreage is in the Essaouira basin, central Morocco
Subject to the issuance of the Joint Arreté signed by the Minister in charge of Energy and Minister in charge of Finance, the length of the initial period will now be 4 years and 6 months, commencing 9 April 2018. The work programme commitments for the initial period remain unchanged. The lengths of the first and second complimentary periods, which would commence upon the successful completion of the recently extended initial period, remain unchanged at 3 years, and 2 years and 6 months, respectively.
Welltec, the Denmark headquartered oil service provider, says that the cleaning tools it manufactures have proven highly successful during testing for something other than oil wells: geothermal well cleaning applications.
The Well Miller® has capabilities for:
– Silica removal – a common cause of geothermal production issues
– Rigless intervention
– Minimal footprint – lightweight yet high capacity tools
– Saving time and money through fast
The Well Miller Reverse Circulating Bit (RCB) is a combinable milling tool enabling the simultaneous milling, break-up, and extraction of scale. The RCB also features a turbine section allowing well fluid to be circulated through the milling bit, and for any cuttings or debris to be collected into bailer chambers for later recovery once tools are rigged down at surface.
In testing, the RCB was run against a cured blend of silica pieces (Si02), sand, and epoxy resin, to replicate the most challenging silica clean-out scenario found in a geothermal setting.
“Not only was the removal of the silica replicant compound successful, the mill bit showed almost no signs of wear, thanks to highly resistant Tungsten Carbide milling teeth”, Welltec reports I a case study.
Welltec says it is already helping clients with geothermal well construction by providing the Welltec Annular Barrier (WAB®) for zonal isolation – a life of well solution.
“In terms of maintenance and intervention, Silica scale is one of the main flow production issues found in Geothermal wells. In particular, the challenge faced with this type of material stems from its strength and high level of resistance, making it incredibly difficult to mill through”, the company explains.
Welltec believes that Geothermal energy offers the highest capacity energy form within the renewables market. ”With the ongoing development of Enhanced Geothermal Systems (EGS), the future potential is further expanded and can help to facilitate an even more efficient and sustainable way to harness the Earth’s natural energy source,” the company declares on its website.
Collaboration in the Field
Welltec continues to collaborate with industry experts and provide technology for research projects with allocated funding from the U.S. Department of Energy. In a project led by the University of Oklahoma and Veizades & Associates, Welltec will be testing its latest Welltec Annular Barrier (WAB) in multiple zones of interest at the Coso Geothermal Field, California.The WAB will be applied to achieve zonal isolation and improve mass flow through stimulation in a high temperature environment.
Welltec has recently co-authored an academic paper with Energy Development Corporation (EDC) of the Philippines, presenting highly successful well repair operations from the field. The paper highlights the benefits of repairing wells to re-establish production rather than abandoning them for new ones– in doing so, the WAB can prevent casing collapse and deformation caused by trapped water.
The case will be presented at the 42nd New Zealand Geothermal Workshop on 24-26 November, 2020.
Egypt’s state-owned Alexandria Petroleum Company (APC) will receive a quarter of a billion dollars ($250Million) from the European Bank for Reconstruction and Development (EBRD sovereign loan.
The loan is partial financing of the $647Million in water and energy efficiency upgrades at the company’s diesel refinery (Alexander Refinery).
The project will bring operations at the facility in line with European environmental safety standards and reduce emissions, the bank said.
Alexander Refinery, established in 1954, is operated by APC with a crude design capacity of 100,000 BPSD. It typically processes light Western Desert crude oil and heavy Kuwait crude oil. It began life as a small refinery with 250.000 ton/year capacity for satisfying Alexandria city and West Delta area needs from the petroleum products. APC refining capacity increased up to 4.7Million ton/year by executing three crude distillation units No. 2, No. 3 and No. 4 in the years 1963, 1968 and 1982 respectively. In 1979, a solvent production complex started in operation under the license of UOP to produce Hexane, Petroleum Ether, and Petroleum solvents. In 1982, the lube oil complex started in operation with design capacity 100.000 ton/year bright stock oil, based on fuel oil feed from Kuwait crude oil origin and in 1983 the vapour recovery unit started operation to produce Stabilized Gasoline and LPG.
Finally, in 1989, the Hexane and Kerosene complex started with annual production capacity of 22.000 ton / year hexane or 18.000 ton / year of treated Kerosene under the license of IFP, while in 1997 the spent oil re-refining unit started in operation with capacity 30.000 ton/year of spent oil and under the license of KTI. Bitumen blending, oxidation and solidification unit started in operation to produce solid bitumen packages in 25 kg blocks.
The EBRD says: “Raising the quality of fuel produced by the refinery will cut down on greenhouse gases, while the construction of a new wastewater treatment facility aims to lower the risk of seawater pollution and a new energy management system will help to reduce fuel consumption”..
The domestic base price, the price at which Nigerian gas producers are to sell to Power Plants, will be $3.2 per Million British Thermal Units (MMBtu), beginning from January 1, 2021, if the Petroleum Industry Bill (PIB) is passed into law in its current form.
But the price at which the gas-based industry, comprising companies which produce methanol, fertilizer (urea, ammonia), polypropylene, etc., will purchase natural gas, can be as low as $1.5 per MMbtu, the incoming law says. That price is special and it is calculated from a formula.
Gas users outside the power sector and the gas-based industry will pay at least $0.5 higher than $3.2 per MMbtu, and their cost of purchase will depend on negotiations with their suppliers.
The domestic base price -$3.2per MMBtu- which is specified in the third schedule of the bill, currently being debated at the Nigerian National Assembly, shall be increased every year by $ 0.05 per MMBtu until 2037, when a price of $ 4.00 per MMBtu will apply for that year and future years.
The Midstream and Downstream Regulatory Authority, “may, by regulations, change the domestic base price and the yearly increase) to reflect changed market conditions and supply frameworks”, says the bill, submitted two weeks ago by President Muhammadu Buhari.
“The objective is to establish a fully functioning free market in natural gas for domestic supplies. This is to be achieved through the voluntary supplies. Where insufficient voluntary supplies are occurring, the Authority may increase the domestic base price and, or the yearly increases. At the same time, the Authority shall monitor the gas prices in other major emerging countries and ensure that Nigeria continuous to have a price level for natural gas that is less than the average of these emerging countries in order to promote the non-oil sectors in the Nigerian economy”.
Timipre Sylva, Minister of State for Petroleum, had given hint of the gas pricing framework last August during a conversation with the Nigeran Association of Petroleum Exlorationists (NAPE). The bill, he explained, “will establish a gas base price that is higher than current levels (The current domestic base price is $2.5 er MMbtu) for producers and this base price will increase over time”.
Sylva said: “This price level should be sufficiently attractive to increase gas production significantly since this gas price will be comparable with gas prices in other emerging economies with considerable gas production.
“The price will be independent of all gas prices for LNG export and is therefore a stable basis for enhanced domestic gas development, regardless of international oil or energy development”.
Pavel Oimeke has returned to his position as Director General of Kenya’s Energy and Petroleum Regulatory Authority (EPRA), after the Employment and Labour Relations Court in Nairobi cleared him for reappointment.
Jackton Ojwang, retired Supreme Court Judge and chairman of the EPRA board said in a statement that Mr. Oimeke could now return to his job.
Oimeke, a trained engineer initially appointed on August 1, 2017, was to have commenced the second three-year term at the head of the agency on August 1, 2020, but an EPRA board meeting decided to send him on leave pending the outcome of a case where a petitioner, Emmanuel Wanjala, challenged his second term in office.
Mueni Mutung’a, the EPRA Secretary and Director of Legal Affairs, has been acting as Director General since August 17, 2020.
EPRA, a Kenyan state corporation established under the Energy Act, 2006, is the sector regulatory agency responsible for economic and technical regulation of electric power, renewable energy and downstream petroleum subsectors.
“His reinstatement follows a court order issued by in Nairobi on October 6, 2020,” Mr Ojwang’ said in a statement. “Mr Oimeke had stepped aside in August 2020 pending the hearing and determination of a court case contesting his appointment as director-general”.
Angola’s National Oil, Gas and Biofuels Agency (ANPG) has signed three Risk Service Agreements with ExxonMobil and Sonangol Pesquisa e Produção, SA (Sonangol P&P), the operating arm of the state hydrocarbon company.
Deep water blocks 30, 44 and 45, covering over 17,800 square kilometers are located between 50 and 100 kilometers from the Angolan coast, in water depths ranging from 1,500 to more than 3,000 meters.
ExxonMobil will operate the three blocks, with 60% interest, while, Sonangol P&P “will have an associative participation of 40%”, a statement by ANPG declares.
Paulino Jerónimo ANPG ‘s Chairman of the Board of Directors, remarks that ExxonMobil’s presence in the Namibe Basin, where the country has never found hydrocarbon, is a key advantage. It would, he argues, help the country to deepen the geological knowledge in the largely unexplored basin.
“The success of the work carried out in Angola by international operators, many of whom already have a consolidated presence in the country, is an extremely important factor for the development and credibility of the Angolan oil sector”, Jerónimo notes.
“We will work with the Angolan government and ANPG to identify the border areas with the best resource potential, applying our proven experience and our cutting-edge technology,” says Andre Kostelnik, ExxonMobil’s General Manager in Angola, adding that ” these new concessions are the result of the long success history of our exploration and production activities in Angola.”
Sebastião Gaspar Martins, Chairman of the Board of Directors of Sonangol, in turn, considers the extension of prospecting and exploration activities to an area unexplored in Angola to be extremely important. “We are excited to be a part of this challenging project”, he explains.
The increased speed of the Energy Transition continues to make headlines in Europe.
This is not necessarily good news for Africa. The greening of Europe could in the short and medium term have a boomerang effect in Africa, given the strong presence of the majors there.
Any argument that supporting Africa’s oil and gas industry is a step to helping bridge Africa’s energy transition becomes nul and void. The greening of Europe promised by the majors could in fact mean reducing oil and gas activities in Africa. For example, both BP and TOTAL have pledged to reduce considerably their oil and gas assets. Africa could be a prime candidate.
What is the Energy Transition doing for Africa’s Oil and Gas Industry?
Are Africa’s state oil and gas companies prepared to take on new exploration and developments as never before? Why? Simply because the oil and gas majors are choosing low carbon prospects and natural gas projects on a massive scale, leaving many potential prospects in Africa in doubt. TOTAL’s Mozambique LNG poject is expected to cost $20Billion and produce up to 43Million tonnes per annum. It will go ahead, but smaller oil and gas projects may not be treated so kindly.
Energy scenarios released by both BP and TOTAL are predicting a sharp decrease of oil production, adding to the view that exploration budgets of the majors will not be a priority item. Instead as TOTAL has explained low cost, high value projects are the goal. Squeezing more value out of its various African assets to ensure a prolonged life cycle.
For too long Africa’s new fledging state oil companies have been proxies to the international oil majors. In the process many of them have not developed technical knowledge, capability and expertise to manage and implement oil and gas projects.
Being hostage to the whims of the oil majors is no formula to ensure that a country’s oil and gas assets are to be developed. Certainly when the window of opportunity to develop oil and gas assets could be closing within the next 20-25 years.
Shuffling the Deck
A key aspect of the energy transition includes a serious analysis of company assets. Rystad, the Norwegian energy research company recently conducted a study that concluded that the world’s largest oil and gas firms could sell or swap oil and gas assets of more than $100Billion in order to adjust and transform to cleaner sources of energy.
The Rystad Energy Study, covers a wide geographical spread and includes ExxonMobil, BP, Shell, TOTAL, ENI, Chevron, ConocoPhillips, and Equinor. The eight companies may need to divest combined resources of up to 68Billion barrels of oil equivalent (boe), with an estimated value of $111Billion and spending commitments in 2021 totalling $20Billion.
The key criteria for determining whether a major would benefit from staying in a country are the company’s cash flow over the next five years, the potential growth in its current portfolio, and its presence in key E&P growth countries towards 2030. Based on this, Rystad claims that majors may seek to exit 203 country positions and, as a result, reduce their number of country positions from 293 to 90.
The Continued Need for Exploration and Development
The case for renewed oil and gas exploration has best been presented by Wood MacKenzie (Andrew Latham and Adam Wilson)who argue that whatever the pace of the energy transition, oil and gas exploration will remain critical well beyond 2040.
“Exploration will be critical in meeting this future demand. Yet exploration is widely perceived as discretionary, even unwarranted. Doubters see a world of risk, declining demand, enormous existing resources and a supply pecking order that ranks exploration squarely in last place. There’s even a public image problem in the false narrative that each new discovery somehow extends the fossil fuels era.”
The authors state that companies showing signs of fatigue with exploration are questioning their long-term commitment to upstream petroleum. Only about half the supply needed to 2040 is guaranteed from fields already onstream. The rest requires new capital investment.
Cumulative global demand for oil and gas over the next two decades will be at least 1,100Billion boe even in a 2°C scenario. It could be as much as 1,400Billion boe on their base case forecasts. Around 640Billion boe could be met by proven developed supply from onstream fields. This leaves a ‘supply gap’ of some 460Billion to 760Billion boe.
Lessons learned and some practical solutions
Of interest are lessons learned from Tullow Oil. In its 2019 annual report Tullow states that between 1999- 2009 Sub-Sahara Africa significantly increased its share of oil production and reserves.
With the oil shock of 2009 and the much deeper price collapse of 2014, larger African gas discoveries, and the US shale industry, oil discoveries have diminished on the continent.
Tullow further states that many African countries have adopted tighter fiscal terms, deterring exploration investments, rendering otherwise investable projects unviable at today’s oil prices.
Finally, decision-making has been slower, more complex as new institutions have been developed to govern the sector and governments have become more accountable to civil society. Tullow cites Uganda and Tanzania as examples of where increased industry participation was sought, but stalled because of a lack of market interest.
Additional practical measures:
Clear definitions of regulatory power: does a country’s regulatory regime define what a Ministry of Energy does as opposed to the goals of the state oil company?
Improved fiscal and tax incentives to encourage new exploration companies to participate
High on the list of priorities for these fledging state oil companies should be knowledge transfer and development of local talent, which the majors should provide.
Special teams consisting of the majors and state oil companies be set up to develop energy transition road maps.
Extra monetary or tax incentives to ensure a speedy transfer of knowledge and developing local content.
To date the international multilateral agencies- be that the World Bank, African Development Bank, or the International Monetary Fund- were reluctant to throw new petro-economies a life line, based on oil and gas potential. This should be re-evaluated so that both oil and gas and renewables can be used to evaluate a country’s financial needs. Perhaps an item for the agenda of APPO (African Petroleum Producers Organization).
At the national level state oil companies and energy agencies which support renewables must better coordinate their national energy policies.
South African criminal gangs have begun to do what Nigerian vandals have been doing for three decades.
They drill holes in pipelines and siphon fuels.
Organised syndicates stole 10Million litres of fuel in the past year in South Africa, according to a report by the Sunday Times of Johannesburg. They siphoned off fuel, in some cases into their own tankers – that are valued at around $60Million (or R1Billion) per year.
The gangs achieved this by targeting pieces of Transnet’s 3,800km underground pipelines, which transport petrol, diesel, gas, crude oil, and aviation fuel across the country.
Transnet is S.A’s state-owned logistics company. It runs the rail system; it operates the ports and builds and manages the petroleum pipeline system in Africa’s most industrialised economy.
For close watchers of the Nigerian oil industry, the petroleum theft story from elsewhere feels eerily familiar. Crude oil theft in Nigeria rose steadily in the ten years from 2007 and 2017 and peaked between 2011 and 2014; with some estimates indicating that up to $15.9Billion was lost in 2014 alone. It has grown from a localised, small scale activity into a multi-million-dollar illegal industry with many complicit stakeholders. But crude oil theft in Nigeria is different from petroleum product theft, which is just about everywhere along the state hydrocarbon company NNPC’s pipeline right of way. In Nigeria, petroleum product theft involves more than criminal gangs. It is routine.
South Africa’s Trasnet’s network of pipelines pumped 17,825 Million Metric Tonnes of products in 2019.
To put in context, Transnet’s pipeline revenue increased by 17.2% to $319Million (R5.3Billion) in 2019 (2018: $271Million (or R4,5Billion)), due mainly to the regulatory agency’s decision to increase the 2018/19 tariff for petroleum transportation. This means that the value of the theft is around 20% of the revenue accruing to the pipelines
The SundayTimes report notes, exasperatedly: “So brazen are the thieves, who have their own tanker trucks to transport the stolen product that in one case they reacted a shack on a farm where a pipeline passes and punched a hole into it to help themselves”
Transnet says it is working with the Directorate for Priority Crime Investigation (“Hawks”), National Crime Intelligence and SAPS and that the effort is “generating positive results with a number of breakthroughs in the form of arrests as well as the impounding of vehicles and fuel tankers, being recorded”.
The thefts are not good for branding for Transnet, which fancies itself as Positioning Pipelines as an international best-in-class pipeline operator and offering subject matter expertise in the pipeline arena
Its also bad at a time when Transnet is investing in more infrastructure to take advantage of the deliveries from the pipelines. The company says in its report that it invested $5.7Million (R95Million) last year in firefighting upgrades at Pipelines to ensure stringent compliance to safety standards and regulations; and $5.9Million (R99Million) IN the multi-product pipeline towards the construction of tanks.
Another reason to be worried about petroleum product theft: last year, the National Energy Regulator of South Africa (NERSA) increased the Pipelines’ allowable revenue (AR) by 7.69% for the
2020 financial year. This translates into an 11% increase in the Durban to Alrode tariff for the 2020 financial year.