The Energy Axis– a digital platform where suppliers and buyers in the energy industry interact is now online.
It is an e-commerce address to find information on the production, consumption, sales, distribution, and marketing of energy.
It’s as much a place to find a directory of reliable oil and gas service companies; E&P companies (comprising IOCs and NOCs and Marginal field producers), downstream suppliers of petroleum products, as it the venue to source for gas to power players, hydropower projects, and the emerging clean and renewable energy companies, inverter dealers, Installation etc.
Funke Taylor, founder of The Energy Axis
Users also include vendors of tools/products used across the oil, gas and energy value chain: (valves, pumps, pipe, fittings, accessories petrol station consumables, etc), LPG businesses, Energy industry personnel, Power, Transport and logistics businesses.
“On the Energy Axis platform, users benefit from the presence of others as against the traditional fear of others”, says Funke Taylor, founder of The Energy Axis. “It’s an interactive space”. “They will gain immensely as businesses or individuals from tools, expanded markets, business opportunities, expert views etc.”
The Energy axis platform has come at a good time for businesses looking for expanded market opportunities. The global lockdowns enforced by COVID-19 pandemic have dis-incentivized face-to-face interactions. B to B Marketing has been moved online as trade conferences, exhibitions etc. have been postponed or out rightly cancelled.
“The Energy Axis would encourage the traditional companies to strategically digitize; people now go online more to search for products and services; search engines and social media platforms will become very powerful source of business leads”, Ms. Taylor explains.
“The much touted digital transformation is not just about technology”, Taylor says, “It includes people, processes and platforms (like the energy axis)”.
“To our users; We will help you stand out in the crowded energy marketplace “, Taylor pledges.
Musketeer 1 Big Oil: ExxonMobil, Chevron, Equinor, BP, Shell, TOTAL, and ENI
Musketeer 2 New Energy: Enel, Iberdrola , Engie, and Ørsted
Musketeer 3 Energy Africa
There is growing evidence of a new convergence between Musketeer 1: Big Oil and Musketeer 2: New Energy Companies.
Perhaps not so much convergence but cross-overs and falling by the wayside of others and in the process creating new alliances.
Little attention has been paid to Musketeer 3: Energy Africa, perhaps viewed as the junior musketeer, but nonetheless playing a significant role.
Their- All- For-One; One-For-All requires a further explanation.
Musketeer 1 Big Oil
The company is not having a Merry Christmas and there’s little to cheer about in 2021. It has recently written down between $17–$20Billion in impairment charges, seen its market cap plunge to $140Billion, and is capping capital spending at $25Billion a year through 2025, a $10Billion reduction from pre-pandemic levels.
Key questions remain: how long can ExxonMobil afford paying its sacred dividend which is costing $15Billion annually at a time when the company is bleeding red ink? Which key projects- Deepwater Offshore Guyana, Rovuma LNG Mozambique, or others- will see development spending slowing down or frozen until ExxonMobil can get its house in order? If it can get its house in order!
At first appearances the company seems to be weathering the storm somewhat better. The Chevron share has lost some of its glitter but has remained resilient over the last 5 years, continuing to hover in the $90 range. In October 2020, its market cap was $142Billion, surpassing ExxonMobil for the first time.
Why? Primarily lower debt levels, a constant dividend, and an image of being in control. Spending in the period 2022-2025 will be $14-16Billion, instead of $19-22Billion: $3.5Billion outside the USA, of which 75% will be dedicated to Tengiz in Kazakhstan and the remaining $1.5Billion elsewhere.
The Tengiz Project deserves some attention, given that it in a time of Chevron’s austerity, it is swallowing up 75% of the international oil and gas budget. Tengiz currently produces 580,000Barrels Per Day(BPD) and is to be expanded by some 260,000BPD. Total costing is estimated at $45Billion.
Expiry date for the Tengiz concession is 2033. Will this short timeframe allow Chevron to regain its investment costs? Will Tengiz, with its high development costs, become a huge white elephant? Leaving Chevron with a legacy to match that of ExxonMobil?
To date Shell has abandoned two Kashagan projects in Kazakhstan because of high costs.
This is not promising for Africa where Chevron has major operations stretched across the continent: major projects in Angola and Nigeria and interests in Equatorial Guinea, receiving very limited funding in order to bankroll Tengiz.
Equinor’s recent top management shuffle has signaled that renewable energy, offshore wind energy, will be the company’s growth engine. By mid 2021, Equinor’s Renewables Division will have its own reporting structure. It’s the most obvious sign yet that in the future offshore wind energy could be spun off as a separate company.
The key indicator is the development of Dogger Bank, located in the North Sea and expected to produce some 3.6 GW of energy, enough to light up 6Million households. It is the company’s showcase project.
Together with SSE Renewables, the joint partners of the project since 2017, Dogger Bank is heralded to become the world’s largest offshore wind farm.
More recently ENI has purchased a 20% stake in the Dogger Bank A & B Project. Why? So that, according to ENI chief executive Claudio Descalzi, it can develop the skill sets needed to better understand offshore wind energy works.
Shell has recently entered a 15-year Power Purchase Agreement (PPA) for 20% of Dogger Bank A and B. With this stake, Shell will use 480 MW of the wind farm for power offtake.
Equally important is Equinor’s Empire Wind and Beacon Wind assets off the US east coast. In September 2020, it was announced that BP was buying a 50% non-operating share, a basis for furthering a strategic relationship. The two projects will generate 4.4 GW of energy.
What is BP’s current status in the Energy Transition and what can we anticipate in 2021? Two encouraging signs:
BP’s 50% participation in Equinor’s Empire and Beacon Wind assets off the US East coast, a strategic partnership which could grow very quickly;
BP and Ørsted announced that they will jointly develop a full-scale green hydrogen project at BP’s Lingen refinery in Germany. The two firms intend to build an initial 50 MW electrolyser and associated infrastructure, which will be powered by renewable energy generated by an Ørsted offshore wind farm in the North Sea and the hydrogen produced will be used in the refinery.
Key questions remain:
BP announced that it will be spending $5Billion per year to green itself and by 2030 will have 50 GW of net regenerating capacity. To date the company has a planned pipeline of 20 GW of green generating capacity. What actions can we anticipate in 2021?
BP has announced it wants to reduce its oil production by 2030 by 40%. Which BP assets will become stranded assets? BP’s 20% share in Russia’s Rosneft?
What about BP’s assets in Africa where the company has a considerable footprint. Some examples:
In Algeria BP has helped to deliver two major gas developments at Salah Gas and In Amenas, both of which are joint ventures with Sonatrach and Equinor.
BP currently produces, with its partners, close to 60% of Egypt’s gas production through the joint ventures the Pharaonic Petroleum Company (PhPC) and Petrobel (IEOC JV) in the East Nile Delta as well as through BP’s operated West Nile Delta fields.
In Angola BP is the operator of blocks 18 and 31 and have non-operated interest in blocks 15, 17 & 20, as well as the Angola LNG plant in Soyo.
In Mauritania and Senegal, BP and its partners are developing the Greater Tortue Ahmeyim gas field with a 30-year production potential. The field has an estimated 15Trillion cubic feet of gas and is forecast to be a significant source of domestic energy and revenue.
Many of these projects are natural gas related and could provide the bridging fuel needed for the energy transition.
Between 2016-2019 Shell spent $89Billion in total investments, of which only US$2.3Billion was devoted to green energy. In 2019, Shell’s overall operating costs came to $38Billion and capital spending totaled $24Billion.
IEEFA(Institute for Energy Economics and Financial Analysis) recently evaluated Shell’s green progress. According to Clark Butler, the author of the report, Shell must shift at least $10Billion per annum or 50% of total capital expenditures from oil and gas and invest in renewable energy if they are to reduce their carbon intensity in line with their own stated goals.
At present Shell is undertaking a major cost-cutting operation, dubbed ‘Project Reshape’ across its three major divisions:
35% -40% cuts at the Upstream division where focus will be reduced to 9 core hubs such as Gulf of Mexico, Nigeria and the North Sea.
Integrated gas division, which includes the company’s LNG business, deep cuts are anticipated.
Downstream, the review is focusing on the company’s 45,000 service stations, designed to play a key role in the energy transition.
Will this be enough? By all accounts Shell is taking an incremental, testing-the -waters approach. Expect no mega-deal such as the British Gas takeover of 2015. Instead fiscal discipline in order to be able to continue paying its somewhat reduced, but still royal dividend of 4%.
There are signs of green shoots:
NortH2Vision in which Shell and Gasunie have combined forces to create a mega-hydrogen facility, fed by offshore wind farms, which by 2030 could produce 3-4 GW energy and possibly 10GW by 2040.
Completing the largest PEM electrolyser in the world at the Rheinland refinery in Germany (10 MW).
Biofuels using alternative feedstocks such as forestry, agricultural and municipal wastes.
Shell’s incremental, cautious approach may be too little too late. What is urgently required is a forward-looking strategic green roadmap.
TOTAL’s energy production in the period 2020 -2030 “will grow by one third, roughly from 3Million Barrels of Oil Equivalent Per Day (BOEPD) to 4MillionBOEPD, half from LNG, half from electricity, mainly from renewables”, according to Patrick Pouyanné, Chairman and CEO.
This is the first time that a major operator has wittingly or unwittingly translated its renewables to BOE. The golden rule was that RRR(Reserve Replacement Ratio) was always used to assess a company’s hydrocarbon reserves. According to Rystad, the RRR rate for the industry is 7%, a historic 20 year low. The norm is 100%.
This author has for some time argued that oil companies also include other fuels in their reserve count—be that wind or solar– to create a basket of energy reserves, thus increasing one’s reserve count and buttressing up one’s fossil reserves and adding value to your offshore assets.
That the petroleum classification system is in need of drastic repair is also reflected by the action taken by TOTAL in the summer of 2020. TOTAL took the unusual step of writing off $7Billion impairment charges for two oil sands projects in Canada. Both projects at the time were listed as ‘proven reserves’. Have proven reserves become the equivalent of stranded assets?
TOTAL’s strategy is focused on the two energy scenarios developed by the International Energy Agency (IEA): Stated Policies Scenario(SPS) is geared for the short/ medium term; and Sustainable Development Scenario(SDS) for medium/long term.
Taking the “Well Below 2 Degrees Centigrade” SDS scenario on board, TOTAL has in essence taken on a new classification system.
By embracing this strategy TOTAL is the only major to have seen the direct benefit of using the Paris Climate Agreement to enhance the investment climate thus supporting its deepwater portfolio in Africa and expanding its renewable energy base.
TOTAL has confirmed, on the renewables front, that it will have a 35 GW capacity by 2025, and has the ambition of adding 10 GW per year after 2025. Translated, that could mean creating an additional 250 GW by 2050. The vision is there, now the implementation.
A key to TOTAL’s success is its ability to step into projects at an early stage, some examples :
50% portfolio of installed solar activities from the Adani Green Energy Ltd., India;
51% Seagreen Offshore Wind project in the United Kingdom;
Major positions in floating wind farm projects in South Korea and France.
Total’s fiscal and technical discipline will ensure that its offshore portfolio and renewables find traction in Africa.
ENI’s 20% purchase for a stake in the Dogger Bank A & B Project is an early indication of ENI’s green future. Why? So that, according to ENI chief executive Claudio Descalzi, it can develop the skill sets needed to better understand offshore wind energy works.
ENI is also teaming up with Enel to develop two green hydrogen projects.The partners plan to produce two pilot projects; each pilot project will feature electrolysers of around 10MW.
ENI has confirmed that it will virtually be starting green projects from scratch.
Eni has pledged to reach 15 GW by 2030 and 55 GW by 2050, mainly by building its own capacity. The company’s 2050 strategic plan to reduce its carbon footprint includes the following goals:
Natural gas will account for 85% of upstream production;
80% reduction in scope 1 emissions (from company assets) scope 2(indirect emissions);
and scope 3 (entire value chain).
Musketeer 2 New Energy: Enel, Iberdrola , Engie, and Ørsted
Enel has announced that it is to invest €160Billion over the next 10 years to meet the demand for green energy and electrification. Over the next three years, about €40Billion will be spent, half of this on renewables.
Enel said almost half of its investments will be directed to developing infrastructure and networks, while the rest will be allocated to power generation. The company expects to have about 120 GW of installed capacity by 2030, almost three times more than the current level.
Expect more development projects from the international oil companies and Enel.
Spain’s largest energy group has projects in Europe(Germany, UK, and Spain), USA, and Brazil.
Up to 2021 the company will spend between €11Billion – €12Billion on investments across a broad swath of sectors including solar, wind (on and offshore), hydro plants, biogas and marine technology. Some examples:
Storengy, Engie’s gas storage arm, will provide hydrogen storage capacity for Europe’s future hydrogen market;
Construction of two solar power plants with a combined generation capacity of 30 MW in Burkino Faso;
Ocean Winds, joint venture between EDP Renewables (EDPR) and ENGIE are combining their offshore wind assets with 1.5 GW under construction, 0 GW under development, with the target of reaching 5-7 GW of projects in operation or construction, and 5-10 GW under advanced development by 2025;
126 biomass plants by 2030 capable of producing 4TWh of power.
Together with ArianeGroup, developing liquid hydrogen fuel for maritime sector;
By 2025 Engie, through its affiliate Power Corner, will have installed 1000+ mini-grids across Africa reaching 2Million people.
The Danish Offshore Wind Farm giant has since 2016 seen its share price more than quadruple. In 2016 it had a stock price of $35 and has now climbed above $140. It has a market cap of approximately €65Billion.
Currently the company has an installed capacity+ FID(final investment decision) of almost 20 GW and a build-out plan for new awards to reach 25-30 GW in the coming 15 months.
The company has projects in Taiwan, Japan, South Korea, throughout Europe (UK, Germany, Netherlands, Denmark, France, Poland, and Belgium) and the USA.
Musketeer 3 Africa
The increased speed of the Energy Transition is not necessarily good news for Africa. The greening of Europe, for example, could in the short and medium term have a boomerang affect .
The greening of Europe by the majors could mean reducing oil and gas activities in Africa. Are Africa’s oil and gas assets competitive and worthy of development, compared to other global projects?
The oil and gas majors are choosing low carbon prospects and natural gas projects on a massive scale leaving many potential prospects in doubt.
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.
How will oil and gas prospects in Africa be judged? Do the various governments have the management skills to properly assess their energy scenarios?
Many of Africa’s new fledging state oil companies, have been proxies to the international oil majors. In the process not developing 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.
Rystad, the Norwegian energy research company has recently reminded the investment community that the oil and gas majors are actively pruning their oil and gas assets and 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.
Sustainable Development Scenario(SDS) based on a well below 2C is the new classification norm, replacing the Hydrocarbon Classification System which instead of measuring provable reserves is now synonymous for stranded assets.
Musketeer 1 Big Oil is a house divided: Exxon Mobil having to finance major projects in Angola, Mozambique and Guyana and facing its own financial meltdown; Chevron using most of its international funding to prop up Tengiz in Kazakhstan, leaving little future funding for Africa.
Shell is clustering its upstream activities in nine hubs, which includes Nigeria and the Gulf of Mexico; BP is reducing by 40% its oil production. This does not bode well for Africa.
TOTAL and ENI with their African operations could play key roles in further developing Africa’s Green Transition. Their oil and gas operations will be extended and no doubt their host governments will be demanding green solutions.
Equinor, with its increased offshore wind portfolio, could see the start or emergence of new players: A combination of Equinor/BP and Musketeer 2 New Energy players such as Enel, Iberdrola , Engie, and Ørsted.
Many of Musketeer 2 New Energy players have limited or no African experience. Certainly It is imperative that both Eni and Total, together with host African governments introduce New Energy companies to these African markets.
Additional practical measures for Musketeer 3 Energy Africa:
Developing a mini-Norwegian system of having a Sovereign Wealth Fund and ensuring that the state be a participant in all concessions.
Clear definitions of regulatory power: does Government’s regulatory regime give the Ministry of Natural Resources a clear mandate as opposed to the goals of state oil company?
Improved fiscal and tax incentives to encourage new exploration companies to participate.
High on the list of priorities should be knowledge transfer and development of local talent, which the majors should provide.
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.
There is mounting evidence that the Energy Transition is showing a trend break: the western industrialized countries such as Western Europe, Japan, South Korea, and Taiwan where the Musketeer 2 New Energy Companies are finding lucrative markets; and developing countries of Africa where few of the Musketeer 2 companies are found.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands. He writes on a regular basis for Africa Oil + Gas Report.
Eunisell Production Solutions has pioneered a new business model, enabling NOCs to realise their development goals and bring their fields up to optimum operating potential, without relying on external investment.
The delay between when the blocks are awarded and when development commences, is a tangible concern for any investor or financial institution. Obstacles to the execution of development plans for these assets has indicated an insecurity of when a return on investment might be achieved, thus uncertainty and reluctance are created.
To solve the challenge, Eunisell delivers four key business benefits: 1. Faster delivery of first oil revenues. 2. Enhanced production from proven fields. 3. Engineered solutions for long term development and 4, Innovative technology.
NOCs are already reeling from the impact of Covid-19 on the industry and depressed oil prices. This means that owners will continue struggle to finance the development of their fields. Any financial assistance in that scenario would be limited at best and come at a heavy cost.
Added pressure comes from Government where owners are expected to deliver on the agreed development and output or risk losing their concessions as witnessed in recent times with the cancellation of 11 operators’ licenses. With the economic and global status quo, options are limited, if any, and this is why Eunisell has stepped in. Eunisell has been providing services based on experience, technology, economics and now, business innovation, to assist NOCs to develop their fields profitably over a measured period.
Service companies are able to design and deliver EPCC projects that will provide long term production and income for the NOCs. The problem is that these projects are inherently costly and require large payments at numerous milestones before production is actually achieved. The procurement and construction phases of these projects are extremely capital intensive and protracted.
By providing solutions, there is a positive impact on Nigeria’s GDP in addition. More oil yielded by NOCs translates into additional national revenues. Having large potential reserves not being produced, simply because a way cannot be found to bring the needed investment, facilities and technology to operators, is a negative influence on our industry, and Nigeria’s economy.
Each one of these assets or the assets currently included in the Marginal Field Bid Round that can be brought to production and developed to its full potential, represents significant increments to foreign exchange and taxes for government. Furthermore, there’s increased employment, community development and growth for the local economies.
The positive effect of bringing these fields to potential is enormous for all levels of the economy. Eunisell is in effect, acting as a technical partner, engineering and delivering the means to bring the existing production to market rapidly, generating revenue and enabling further development.
Compared to existing EPCC projects, Eunisell’s solution requires only a relatively minimal initial cost and is delivered in weeks rather than months. This immediate approach enables concurrent development of the asset. Eunisell will design and deliver the fit-for-purpose production management project, leaving operators to concentrate on long-term production expansion plans.
By working with the field owner, Eunisell assures that the solution provided serves not only short-term output yields, but is designed to meet the field’s expected potential and beyond. By providing the technical solutions and funding the development through rapid delivery of production, the capital required for field development is reduced to manageable levels. Further, the return on the original capital investment is achieved in a significantly shorter period of time.
With Eunisell’s model for success, we are using production costs to partner with the operators to develop the asset. And with Eunisell’s production enhancement and production delivery capacities, these costs can be further reduced to make depressed oil prices viable and enable funding development of Nigerian assets for the benefit of all.
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.
The Namibian government insists it does not want to ether invest, or give any form of guarantee for the Kudu gas field development.
Not even when it is meant to generate power for the country.
It is official.
This point was reiterated several times over at a recent webinar on the country’s energy strategy.
Tom Alweendo, Namibia’s minister of Mines and Energy, told the webinar, organized by Africa Energy Chamber: “the government was required to put in as either capital or certain physical concession, but unfortunately, given our situation, we are not able to do that. And what we have agreed to do is to say, can we find another way to actually develop that field using another business model in such a way that the government is not necessarily involved in that”?
The comment, versions of which Mr. Alweendo has made on other platforms over the last two years, keeps being surprising, considering that natural gas inflow into an economy, more than anything else, energises it, as industrial clusters, as a rule, generally grow around processed gas.
The current business model the Minister referred to is the plan to process a fraction of the 1.3Trillion standard cubic feet of gas in the field, use it to generate 475 MW per day of electricity, supply some power to Namibia and export some.
The Namibian government has prioritized renewables over Kudu Gas to power and NAMPOWER, the power utility, does not include the project in its Five-Year Strategic Plan. It’s okay to do renewables, but what is the planned growth of electricity to be injected in the Namibian economy? Around 1 Million Namibians lack access to electricity, which means that almost half of the country is without access at all (~53% has access & ~47% has no access). These are World Bank 2019 figures. You have a meagre population of a 2.4 Million people and you can’t even provide them electricity.
Why? A lack of industrial mindset of considerable scale.
The state is saying that it doesn’t need the electricity from Kudu, but countries that have experienced significant degree of industrialization are known to have favoured availing their citizens far more electricity power than the economy demanded. Eskom of South Africa was one such example, long before it lost its way in the profligate corruption of the Jacob Zuma years.
In Namibia, no new investment has been made on sizeable generation of electricity in the last 30 years.
THE NORWEGIAN COMPANY BW Offshore concluded its farm in into the Kudu field acreage in February 2017, taking a 56% stake, with the state hydrocarbon company NAMCOR holding a 44% stake in the upstream and midstream segments of the project. The state power utility NAMPOWER, with its partners, will install the power plant, offtake the gas and convert it to electricity. But neither state owned enterprise has been able to get hold of their share of financing the project because the government is not keen.
NAMCOR was hoping that BW Offshore would carry it by paying its 44%, after the ministerial consent had been granted. But that did not happen. Further downstream, NAMPOWER is challenged in raising finance for its 51% share of the power generation side of the project.
The invoice for the Kudu Power Station in 2016, was about $749Million of which 75% would be raised as debt (limited recourse). The gas field development was expected to cost $1.15illion (70:30 debt/equity). The entire funding to get the project started was slightly less than $2Billion, although it’s not clear now what the cost will be, in the light of the current Pandemic induced crisis which has forced down the cost of EPC contracts.
Again, Kudu is not only about electricity. Access to natural gas has been known to benefit economies.
Mr. Alweendo is not interested. And the Namibian government is not prepared to do any thinking on its own around the development. “We haven’t had a formal engagement (with BW) as yet since last year(2019) to see how far did we get to see if we can take if off the ground”, he told the webinar. “But certainly, I still think it is a potential development that can be carried out and the economic potential and the economic benefit coming from that is so immense and therefore, as a government, we will still want to see that happening but we just need to come up with a different business model than the one which was actually grafted earlier”.
As multinational oil and gas companies (the IOCs) divest their interests in mostly onshore ventures in the Gulf of Guinea, new local E&P companies emerge, taking advantage of the divested interests. In many cases these new local ventures underestimate the challenge of maintaining production at inherited levels, and of developing and pursuing growth plans. Danite Limited recognises these challenges and seeks to support these private firms in a cost-effective way. We see the key challenges as follows:
Entrepreneurs that are new to the E&P sector often struggle with the time frame for making returns on their investment. An investor in the downstream oil and gas sector is basically a trader. The most critical success factors in that sector are: (a) A safe and efficient supply and distribution system that keeps costs really low (in view of the razor-thin profit margins), and (b) Attractive retail outlets which consumers would want to patronise. If the investor gets these things right in the downstream, he should be fine.
However, the upstream is a totally different ball game. The most critical success factors are (a) Technology, and (b) Safety and Environment. Drilling a couple of dry wells can sink the business. A few years ago, one multinational company drilled two dry wells offshore Nigeria at a total cost of almost US$200m and that was the end of its venture in the country. On safety and the environment, we have read of some of the world’s worst disasters in the Gulf of Mexico and how respected multinational companies have paid very dearly in both human lives, money and reputation.
Danite Limited seeks to support new investors into the industry by helping them understand the investment journey so they can manage their expectations, and by giving them sound steers as they embark on their first field developments. Sometimes, if they so request, we can provide a project manager who would work with the client’s resources to deliver successful projects.
There is the immediate challenge of technical resourcing due to the dearth of capable technical manpower in the country. The newcomers typically seek to attract experienced technical resources from the IOCs. They soon find out that these technical experts sometimes with decades of experience would not easily leave their current employers with all the stability associated with IOCs, to join newcomers where a lot more is required of them, and with all the uncertainty of what lies ahead. Despite this challenge, with enough carrots, the newcomers do manage to attract some experienced technical resources. Often, these are resources that are close to normal retirement from the multinationals and so have little to lose by retiring early. But the future of the business cannot hinge on senior retired professionals – the newcomers need to invest in some inexperienced resources – typically graduates of technical disciplines – who can be developed very rapidly to be productive. Danite Limited offers to help develop such rookies through training programmes offered by industry veterans. Within a few weeks of employment, young graduates would be able to deliver real useable work that add value.
Affordable Software Tools:
There are well-known big names in the industry when it comes to software tools. For example, when you talk of process simulation, Aspen’s HYSIS is the industry standard. For pipeline studies, you speak of PipeSim – a Schlumberger product. These products have deservedly made their name from the patronage of the industry heavyweight operators. This has fuelled astronomical prices of these products, often beyond affordability of a new entrant into the business. However, from a technical standpoint, these software tools are based on well-known engineering principles, formulae and correlations, and their functionality can be replicated by much more affordable alternatives. This is the concept Danite Limited promotes – Provide useable tools without the mega-prices of the big names. For example, Danite’s RaffloLive (https://rafflolive.com) is a perfect solution for carrying out flow assurance studies of pipelines such as are encountered in the oil and gas fields. RaffloLive is the online version of what used to be a PC-based software called Rafflo, developed in the eighties by the current CEO of Danite Limited. After rigorous testing and validation, Rafflo was adopted by one of the leading IOCs in Nigeria as the official tool for pipeline flow assurance studies. That IOC used Rafflo for 13 years until the company received a directive from its headquarters to only use global industry software. Retaining the core Rafflo engine, Danite has re-created it into RaffloLive – a full on-line application that only requires a web browser to run. It does not require anything to be installed on the user’s device as everything is online. Even an Android tab or an iPad can be used to simulate huge pipeline networks with RaffloLive. It is offered by subscription only. However, participants at our training course on Pipeline Planning and Design automatically receive a 30-day license that enables them carry out hands-on exercises.
Field Development Planning:
The seeds of failure of many failed E&P projects are sown at the development planning stage. At this stage, you need your most experienced professionals who, working as an integrated team of surface and subsurface professionals, with other supporting disciplines like Safety, Environment and Corporate Social Responsibility (CSR), would develop optimal concepts. Danite Limited offers this service.
Dr Raphael Sunday Awoseyin founded Danite Limited. He has four decades experience in the upstream and downstream sectors of the petroleum industry, covering project management, facilities engineering, maintenance and management of oil and gas production facilities, processing and distribution, process re-engineering and business process integration. He has led formulation of standards, business processes and procedures for upstart E&P companies and championed skills and career development planning for thousands of operations
personnel. He led implementation of SAP (ERP system) for the largest Shell E&P company in the world.
He holds a First-Class BSc (Hons) degree in Mechanical Engineering from University of Greenwich, London and a PhD, also in Mechanical Engineering, specialising in Pipeline Hydraulics. He is a graduate of IMD (Lausanne) Program for Executive Development and of Wharton (University of Pennsylvania) Executive Development Program. He is a Master of Business Process Re-engineering.
The front-end engineering design phase for a proposed greenfield liquefied natural gas (LNG) import terminal at the Port of Matola, in the Mozambican capital of Maputo, is underway and the developers of the project are now intensifying discussions with potential energy and industrial off-takers in both Mozambique and South Africa.
The project is being developed by the Beluluane Gas Company (BGC), a joint venture between French energy multinational Total and Southern African natural gas group Gigajoule. Mozambique’s State-owned gas company, ENH, also has a share in the project, which is currently scheduled to begin operating in 2023.
In 2019, Mozambique awarded an LNG import concession to BGC and approved the construction of a 16-km, 28-inch pipeline linking the terminal to the existing Matola Gas Company (MGC) transmission network.
The Mozambican market consumes about 30 petajoules (PJ) per year of natural gas to gas-to-power and industrial off-takers. The vast majority is supplied through the MGC network which is also connected to the 865-km Rompco pipeline that currently transports some 150 PJ a year of natural gas to industrial customers in South Africa, including Sasol’s fuels and chemicals facilities in Secunda and Sasolburg.
The gas transported to South Africa is produced at Sasol’s Pande and Temane gas fields, in southern Mozambique.
The development of the LNG terminal is being timed, however, to fill a supply gap that is anticipated to arise when production from those gas fields begins to taper from 2023 onwards. Ahead of the Covid-19 pandemic, the Industrial Gas Users Association of Southern Africa was forecasting a potential yearly gas shortfall in South Africa of up to 98 PJ from 2025 onwards.
The Rompco pipeline has a nameplate capacity of 220 PJ and Gigajoule Managing Director Johan de Vos and Total LNG business development director Shammi Herai report that the Matola terminal is being profiled to eventually match Rompco’s full capacity.
“Initially, we expected that most of the customers would be in South Africa, but we are receiving strong interest in Mozambique, which could shift the terminal’s supply equation materially,” De Vos says.
Besides servicing gas-to-power and industrial customers that are already linked to the gas network, the project includes scope for a cryogenic facility able to load trucks with LNG destined for customers that have no direct access to the existing pipeline infrastructure. “This is a very exciting market segment and we are contemplating a sculpted design that enables us to supply this market with more than 20 PJ of gas yearly as from 2023 onwards.”
Herai, meanwhile, is equally enthused by the prospect of deploying the gas in support of the region’s push to increase the penetration of variable renewable energy into the electricity mix. BGC is also keeping close tabs on Eskom’s plans for the repurposing of four coal-fired power stations in the Mpumalanga province, which could include a gas-to-power component.
In addition, Central Térmica de Beluluane (CTB) secured a concession in 2019 for a 2 GW power plant project in Beluluane Industrial park, which will be supplied by BGC.
“Multiple discussions with interested parties are already under way despite the restrictions imposed by Covid-19 lockdowns, and the project is still on
course to reach final investment decision (FID) in the first half of 2021,” Herai explains.
BGC, De Vos highlights, needs the market to supply information with regards to industrial energy requirements as well as on-site power demand to enable it to progress to an FID as soon as possible and also to improve prospects for the supply of competitively priced natural gas.
“Infrastructure is a fixed component so it is in the interest of all customers that BGC aggregates sufficient volume to have significant economies of scale. The price to each customer will cover the molecule price and infrastructure costs, which means that all customers benefit from higher volumes.”
The process of securing commitments from customers is continuing in parallel with the front-end engineering design, which has been initiated after the BGC technical team resolved the critical technical and environmental issues confronting the project.
The front-end engineering design studies, meanwhile, are being advanced following the signing, in November, of a joint development agreement between Total and Gigajoule. Once completed, BGC will go out on enquiry to secure the services of an engineering, procurement and construction partner.
BGC will install a floating storage and regasification unit (FSRU) at a dedicated berth in the Port of Matola and has received strong interest from shipowners, many of which have been negatively affected by the deferment or delay of projects as a result of the Covid-19 pandemic.
In fact, Herai says the availability of an FSRU is no longer seen as a critical-path item given recent market developments and the focus currently is on securing the best possible commercial value, which could assist in lowering the overall cost of the project.
The harbour itself has recently been dredged to sufficient dimensions for handling the LNG vessels; a fact that has been confirmed through navigation studies and detailed simulations. Most of the Total LNG fleet is made up of vessels able to carry 170 000 m3 of LNG. Some minimal dredging will be required for a new turning circle and berthing pocket as the LNG terminal will be located at a last berthing dock in the harbour.
“We see this project as a game-changer for gas and potentially gas-to-power in Southern Africa. There is currently insufficient natural gas supply for market growth and the power generation needs in Southern Africa; a scenario that is likely to worsen as output from the Pande and Temane gas fields declines,” De Vos asserts.
“The Matola gas terminal is also ideally placed to supply regasified LNG to industrial customers, while its proximity to the existing high-voltage Motraco interconnector means that gas can begin to play a more significant role as a complement to renewable energy power plants in between South Africa and Mozambique,” Herai concludes.
Interested parties can provide their gas and power demand information on the BGC website: www.bgc.co.mz
This post is sponsored by Festac News Press Limited
Low oil prices, combined with the COVID-19 pandemic, are putting pressure on oil and gas companies to reduce operational costs through efficiency and optimization. There is only a limited number of ways to achieve this — by downsizing, reducing production, or implementing digital transformation. While a quick fix, downsizing and production reduction are not sustainable solutions. As such, more and more oil and gas companies are looking at the strategic advantages of digital transformation, driven by cloud computing, Internet of Things (IoT), big data, and Artificial Intelligence (AI).
Digitization: A Must for the Oil and Gas Industry
According to Accenture Technology Vision 2019, of the 168 oil and gas executives surveyed, 85% from upstream and 90% from downstream companies said that they were currently implementing one or more of the following technologies: Distributed Ledger Technology, AI, Extended Reality, and Quantum Computing (DARQ).
In recent years, most large oil and gas companies have increased investment in digital transformation. Internationally, large multinationals have launched their own digital and intelligent oilfield construction plans, such as the Digital Oilfield by ExxonMobil, Integrated Development by ConocoPhillips, Smart-Field by Royal Dutch Shell, I-Field by Chevron, and E-Field by BP.
Chinese enterprises have also been actively implementing new digital strategies in the industry. China National Petroleum Corporation (CNPC) has built an exploration and production cloud platform, as well as over 50 digital management systems, including exploration and development, refinery and chemical engineering, and service support, among others. Sinopec has set up three digital platforms for operation management, production operation, as well as information infrastructure and O&M. In addition, it has built several technology-driven solutions, such as ProMACE, smart factory, Chememall, and Epec. At the same time, China National Offshore Oil Corporation (CNOOC) is developing on-going plans for intelligent oilfields. It has successfully built unmanned platforms, and has piloted multiple projects on intelligent exploration, oil production, asset management, and drilling and completion.
Oil and gas companies are rapidly investing in digital and intelligent projects to improve exploration and development efficiency and reduce production costs. Ultimately, the industry looks to seize the opportunities that digital transformation has to offer.
A Difficult Road to Digital Transformation
Each upstream enterprise progresses at a different pace during digital transformation. Various companies in the oil and gas industry have achieved different levels of development in data monitoring and collection, device networking, data analysis, and predictive maintenance; the industry overall has had some success in these domains. However, the further the industry transforms digitally, the more challenges it faces.
Zhang Tiegang, former Deputy Chief Engineer of Daqing Oilfield Exploration and Development Research Institute, introduced the three key pain points in the digital transformation of the oil and gas industry at the Huawei Oil and Gas Virtual Summit 2020 held on July 15.
Massive Data Growth
Compared with other industries, oil and gas manages an even larger amount of data. For example, the amount of seismic data is increasing at an unprecedented speed. As oil and gas exploration becomes more difficult, the process requires more precise seismic wave exploration techniques. Broadband, wide-azimuth, and high-density (BWH) seismic data collection is particularly important, amounting to nearly 1 TB/km2. The exploration area is constantly expanding and the originally collected high-resolution seismic data in just a single work area may amount to over 17 TB. In addition, the continuous increase in historical data records further speeds up data growth.
Increased Computation Workload and Complexity
The ever-increasing data volume leads to a sharp increase in the computation workload. For example, the computation workload of pre-stack reverse time migration (RTM) and storage volume are 10 and 50 times higher than before, respectively. To ensure comprehensive and accurate understanding of oilfield production dynamics, the computation requirements of large-scale reservoir numerical simulation also increase significantly. Therefore, oilfield companies have increasingly high requirements on data processing technologies. More and more complex algorithms — such as anisotropic pre-stack depth imaging, RTM, and full waveform inversion (FWI) — also pose higher requirements on computational capabilities.
Weak Information Infrastructure
Equipment rooms, computing, storage, and IT O&M constitute the information infrastructure system of oil and gas enterprises. Most companies used to build their own, resulting in many equipment rooms with high energy consumption and low security. At the same time, low server configuration and utilization are no longer able to meet the requirements of massive data processing. In addition, the existing shared storage devices come from different providers and feature low capacity, unable to store massive data. Moreover, O&M departments face increasing pressure to hire highly skilled personnel to ensure the O&M of independent and scattered IT with a poor intelligence level.
Partnership Can Help Oil & Gas Streamline Digital Transformation — Who Will the Partners Be?
The digital transformation of oil and gas enterprises is a huge systematic undertaking. Therefore, technical support from IT companies is indispensable.
Partnership Between Oil and Gas Enterprises and IT Companies (Some Cases)
Every large oil company has chosen to form partnerships for digital transformation. In this case, IT companies provide oil and gas enterprises with comprehensive digital solutions by using advanced technologies such as AI, big data, and cloud computing.
Take the partnership between Huawei and Daqing Oilfield Company as an example. Cloudification is key for digital transformation. However, data, computing, and facilities present serious challenges. To address these, Daqing Oilfield Company cooperated with Huawei to build a cloud data center, achieving an elastic supply of IT resources. The computing power of the data center now reaches 1,000 trillion FLOPS — a 300% increase in efficiency. Thanks to the elastic supply of computing and storage resources, the acquisition period has been reduced from three days to three hours. At the same time, servers with super computing power and the cloud-based deployment environment optimize data processing by 3 to 10 times. To achieve this, production data is transmitted to the cloud center through the high-speed dedicated network for processing. The calculation results are automatically sent back to the data center for archiving and management, ensuring the security of the core oilfield data.
In addition, Huawei has developed multiple technical service capabilities for oilfield digitization by using technologies such as AI, big data, and 5G. By deploying HUAWEI CLOUD, SONATRACH (Algeria) has successfully transitioned to cloud-based IT by deploying a company-wide ERP system. With AI, big data, and industrial IoT technologies, Huawei has built a fault prediction model for predictive maintenance of pumping units. Huawei has also built the largest industrial 5G oilfield lab in Europe’s biggest oil refinery, as well as implemented future-oriented services such as inspection robots, wireless sensors, “connected” employees, and predictive maintenance. Recently, Shengli Oilfield and Huawei recently signed a strategic cooperation agreement to build a cloud platform and 5G-based intelligent oilfields.
Efficiency and cost are the competitiveness indicators of the oil and gas industry. As a leading global ICT solutions provider, Huawei is continuously working with oil and gas partners to reduce costs, increase efficiency, and achieve digital transformation.
In line with the strategy of increasing reserves and production, how to maximize value from historical exploration and development data has become a new requirement of CNPC. Together with partners, Huawei planned and built a computing AI platform for CNPC, to implement AI training and big data analytics. The customer has now applied AI in multiple ways, such as artificial lift fault diagnosis and seismic first arrival wave identification. The value of underused historical exploration and production data has been fully explored.
Huawei built a local, dedicated cloud for Daqing Oilfield, to provide oil and gas exploration computing. This in turn helped Daqing to optimize its costs and shift high-performance exploration and development computing services from CAPEX to OPEX. By reusing ten PB of historical exploration data, the cloud helped improve computing power by 833 percent, and increase the annually processed area from 400 square kilometers to 2000 square kilometers.
Strong partnerships are essential in the oil and gas industry, regardless of the digital transformation strategies a company may adopt. Alone, digital transformation is difficult, due to its complex technical requirements. The key for success is to build strong and strategic partnerships with industry leaders, ensuring a clear scope of cooperation. In this period of digital transformation, it is critical for oil and gas enterprises to choose their partners wisely — it will define the industry trends, but more importantly, it will determine who will become the new industry leaders.
The Welltec Annular Barrier WAB®, a flexible, high performance production parker, is one of the results of a 26year long series of innovations which began with the Well Tractor® , the conveying device that launched Welltec in place as a top draw subsurface solutions service provider.
The company’s Development and Engineering (D&E) department is responsible for bringing new ideas to life and transforming innovation into reality. It is this ability to think differently and then do differently that forms the foundations on which Welltec is built. The company manufactures her products in-house, embedding automated processes to proffer completions and interventions solutions.
The main Manufacturing sites are based in Denmark with Intervention services produced in Allerød, a small community just north of Copenhagen, and Completion products made in Esbjerg, the Danish oilfield hub.
Below are pictures from a recent tour to the company’s facilities at Allerød and Esbjerg.
Revolution Minerals Ltd has recently introduced a revolutionizing technology in boosting oiland gas well production– PetroBoost®, a patented method for exerting a combined effect on the near-wellbore region of a producing formation.
PetroBoost technology is the result of many years of scientific research and lab testing by leading Russian and Ukrainian scientific institutes focused on research into hydrogen energy.
PetroBoost technology has been successfully tested in collaborations with major oil and gas companies in a broad variety of wells with differing geological conditions. These companies include Gazprom, Novatek, Tatneft in Russia, Eni SPA in Turkmenistan and others.
The PetroBoost technology effectively enhances well production increasing ultimate recovery factors of oil and gas reservoirs. PetroBoost technology is effective in oilfields where traditional stimulation technologies struggle, including viscous oil, those with high paraffin content, oil rims, tight formations, etc.
Address: 86-90 Paul Street, London EC2A 4NE, United Kingdom