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“Nigeria’s top Problem is Well Cost: We are Out to Solve it”

PARTNER CONTENT/Hd Drilling Services

Hope Okwa, Founder/Chief Executive Officer Hd Drilling Services, sees the high cost of well construction as major impediment to Nigeria’s meeting its goal of achieving 4Million Barrels of Oil Per Day of crude oil in the short term.

 “If we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands”, he tells Africa Oil+Gas Report’s Ahmed Gafar, “even local banks may be able to fund field development campaigns”.

He also fields questions on a range of issues, from opportunities that newly awarded marginal fields throw up to demand for Nigerian hydrocarbon.

A bachelors and masters degree holder in engineering from the University of Benin (Nigeria) and Heriot Watt University in the UK respectively, Okwa has 29 years of post graduation industry experience, the first 14 of which he spent in AngloDutch Shell, mostly on well engineering and drilling supervision. He had a stint at BG (the defunct British Gas) as a senior well engineer in the company’s Nigerian deep-water operations. He had a five year stretch as senior drilling and workover well engineer on critical gas operations at Saudi Aramco, after which he had another 18-month stint at BP Angola as senior drilling engineer.

 Excerpts from the conversation.

Hd Okwa Drilling advertises itself as a company with a laser focus on oilfield drilling services. How did you come to this realisation?

 

  • The Nigerian Government targets Four Million barrels of oil per day (4MMBOPD), but the country is barely achieving 1.5MMBOPD due to high well cost. A 10,000 ft well producing only 3,000 BOPD costs up to $25Million to construct. To move from current 1.5MM to 4MM BOPD requires massive well construction activities, in the order of over 800 wells per year. The associated investment is $21Billion per annum. Where will this investment come from, especially in an era where top global financiers are moving their investment to renewables? The only way is to rethink well construction efficiency, with a view to drastically reducing well costs from current levels.
  • The sources of inefficiencies in well construction, is very much within our expertise, as a demonstrated through the several SPE papers we have authored.
  • It is very urgent to implement these solutions. In nine (9) years’ time, by 2030, the first world will pivot away from fossil fuel. What will then happen to Nigeria’s reserves of 37 Billion BOE?
  • We believe we have the solutions to reduce well costs in Nigeria by as much as 70%. I have a track record of this achievement from my employment with Shell, BG-Group, BP, Saudi Aramco, as well as many local operators. Hd Okwa Drilling is collaborating with operators and service companies to deliver wells that are only 30% of the standard cost. We hope to have an opportunity to talk about these alliances and collaborations in the course of this discussion.

Mele Kyari, Group Managing Director of NNOC, and Timpre Silva, Minister of State for Petroleum, at the launch of  the Nigerian Upstream Cost Optimisation Programme (NUCOP) in Abuja, last February

When you say: A 10,000 feet well producing only 3000 BOPD costs up to $25Million to construct, are you referring to an onshore well or a shallow offshore well?

The statement is true for land, swamp and shallow offshore. These use surface blowout preventers.

Ad if a 10,000feet well is considered too expensive at $25Million in Nigeria, what is the reference round the world? What are you benchmarking against?

My reference is Canada/USA, where the rig rate for land is $32,000/day comparable with $25,000/day for Nigeria. A 10,000 ft land well takes 8 days to drill while it takes 83 days in Nigeria. The Canada/USA cost is less than $2 million, while Nigeria is $25 million. The Canadians and Americans achieve the success by efficient well design (without gold plating as we do in Nigeria, efficient supply chain management, avoiding NPT and applying the science of drilling optimisation. We are experts in these areas. I should add that we are currently preparing to execute a $5 million horizontal well for a Nigerian marginal operator, applying our technigues.. 

Your website indicates that there’s an entire business proposition around well services that require some single mindedness. and how is the journey so far?

The establishment of Hd Okwa Drilling Services is a milestone in its own right. We have had opportunities to offer advice on Well Design, NPT avoidance, cost improvement, personnel recruitment, etc for various operators. In the years ahead, we plan to expand these offerings to technical consulting, staff development on cost-reducing well delivery processes and dealing with the complexity of supply chains in Nigeria.

Rig activity has taken a dive in Nigeria in the past year. What has been Hd Okwa Drilling’s Business Strategy in this prolonged period of silence?

We may ascribe the direct cause of rig activity collapse to the COVID-19 outbreak.  However, I suspect the underlying cause of this sharp decrease in drilling activity may not be far from the high cost of wells, as I highlighted earlier, and the challenge of obtaining investment cash in an environment where everyone is going to renewables.

We believe that if we reduce well costs drastically, through our activities, we will be able to stimulate activities. For example, if we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands, even local banks may be able to fund field development campaigns.

Over 200 companies are expected to form 57 Special Purpose Vehicles (SPVs) to develop 57 Marginal Fields in the next 36 Months. How is Hd Okwa working on taking advantage?

Here is where we hope to make the most impact. In the past, many marginal field winners have struggled to bring oil to market due to several challenges, related to investment funds availability.  Many of the marginal operators are going to need to drill 3-5 wells to realise their field potentials. Without support from our activities, each operator will try to raise $75 – $125Million for field development. With our expertise, this could just be only $15 – $25Million, which is within the capability of local banks. We have assembled a repertoire of options available to marginal operators e.g. from our bespoke consulting services, to full project management through our sister company H-PTP Energy services, or our supply chain improvement alliances The Well Engineering Platform, etc.  Through these outlets Hd Okwa Drilling services hopes to transform the well delivery landscape in the country and catalyse a speedy development of the marginal resources.

What is your outlook on Nigeria’s Upstream sector for 2021?

The environment is very challenging. There is demand for Nigerian oil with the ongoing commissioning of Dangote’s 650,000 BOPD refinery, and several modular refineries. These refineries will help reduce dependence on imported fuel, and not only satisfy local consumption, but fulfil demand across Africa and many of the developing world, who would still be dependent of oil consumption for the foreseeable future. As our contribution to the preparation, we are developing local manpower by running courses like the

  • Well Design Masterclass,
  • Re-Entry and Workover Engineering Masterclass,
  • Abandonment and Decommissioning Planning Masterclass.

We also extending our collaborations to experts overseas, who we are bringing to run specialist training in Nigeria for Nigerians, at very low price. We are also developing ourselves in readiness for the future challenges. For example, I am completing my Master of Science in Innovation and Entrepreneurship at the No.1 Business School in Europe, HEC Paris. Thus, we are ready to make our contribution to energise the Nigerian oil sector.

Nigeria exports oilfield service expertise outside the country. Are you one of such providers? Does Hd Okwa Drilling have Pan African ambitions?

Not at the moment. The focus of Hd Okwa Drilling Services is Nigeria. In North America, drilling planning has really advanced, and the gap with Africa is very wide. So, we focus on Nigeria first, then we can expand to the other African countries later.  Let charity begin at home.

Hd Okwa Drilling takes training a so seriously that it’s a full component of its spectrum of business. This is quite unusual in the Nigerian industry. Is training a highly monetised component of your business portfolio?

A direct answer is ‘NO’. However, we need a pipeline of skilled professionals to master the techniques and processes that we deploy.  One way of doing this is through training and mentorship. We have established several specialists’ courses relating to efficient well delivery. These courses are available to both individuals and operators, at a fraction of the cost. Training cannot pay back if we are to consider the efforts we put in, as these courses are at the cutting edge of the future of well engineering.  They cover Well Design Masterclass, Re-Entry and Workover Engineering Masterclass, Abandonment and Decommissioning Planning Masterclass, Efficient Cementing Technology, etc. We also organise team alignment workshops, well challenge sessions, drill-the-well-on-paper (DWOP) exercises, in addition to our normal specialist courses. Our resource persons are the leaders on the well engineering disciplines within Nigeria and the global industry.

The International Association of Drilling Contractors (IADC) Nigerian Chapter is always talking about training about quality and capacity of rig personnel, about safety on rigsite. Is your company looking at Collaboration with IADC?

We have it as part of our strategy to collaborate with the IADC Nigerian Chapter, on manpower development for the Nigerian industry.  We are in the process of founding a Well Engineering professional organisation. When completed, the organisation will also be part of our springboard for driving down well costs in Nigeria by accelerating competence development of professionals through mentoring by Nigerian professionals with extensive international experience.

I am curious about a company calling itself strictly a Drilling Service company; why can’t you simply describe yourself as a full subsurface solutions provider?

Of course, we are a subsurface consultancy group. However, expertise in the other areas of petroleum engineering abound. As drilling requires long training and mentorship to attain professional maturity, it appears to be the area in serious need of attention. If well costs are allowed to continue to grow, the current lull in well construction activities will linger too long. There is need for urgency, as we cannot predict what would happen to Nigeria’s oil after 2030, which is only nine years time!

I see that you count Shell, Amni, and First E&P as part of your clientele. For indigenous companies who are mushrooming in Nigeria, the logistics of integrated project management can be so challenging they’d do better to outsource it. Is this the space you are after?

Shell, Amni, First E&P, Monipulo, Elcrest, Addax, etc, are some of the beneficiaries of our expertise and we have worked in one form or the other with these organisations. However, we are a technical consulting organisation. We use our expertise to help operators, reduce well costs. We do this by facilitating well design improvement, helping them eliminating non-productive times, and training and mentorship of personnel. Our project management activities are carried out through another organisation that we contribute expertise to.

Out of the several specialisations in Hd Okwa Drilling services: Well Cost Improvement Catalysis, Strategic Expertise & Technical Consulting, Well Operations Risk Elimination, which of them does Hd Okwa Drilling find most forward looking? And which are you best at?

Our expertise covers all areas, and we need all of them as arsenal to attack the monster of well costs escalation. We operate through several avenues:

  • In Non-Productive-Time elimination for example, our research showed that all NPT’s in the Nigerian drilling operations are caused by four main events namely Well control, wellbore instability, equipment failures and human errors. These events constitute 30% of the total time spent at the well site on a well. We have developed expertise that we use to support operators to eliminate these events.
  • Invisible lost time constitutes the least beneficial activity to the drilling operation, but are being carried because they can’t be detected. This time constitutes up to 50% of wellsite times.  We collaborate with international experts to develop well operations analytics software. We currently support two – SMARD and CI Drill.  Both software are creating disruption in the well analytics space. These two-software combined can eliminate up to 30% of all invisible lost times.
  • Drilling project management requires high level of expertise. The country has relied on Shell to develop drilling expertise for the industry in Nigeria. However, as the company has shrunk over the years, so have the number of professionals they develop.  We contribute technically to H-PTP Energy Services which is full services well projects management organisation founded by like-mind professionals with strong international expertise.
  • We have developing collaborations and alliances with service suppliers to the drilling business to help them improve their services to international standards.
  • I act as Technical expert in well engineering such as expert witness, standards development, expert opinions, etc.
  • We have supported a financial service organisation to advise them on energy project funding.
  • We act as well examiner, in line with international standards, where we look at drilling project plans, and offer recommendations for improvement.
  • We conduct workshops to drive the ideas through the clients’ teams.
  • And, of course, training services. We are very good in this area.

The last annual report by Shell sounded so despondent about their experience out on the Nigerian oilfield environment. What is your message to international investors about the future of the Nigeria’s oil and gas market?

We need investors to help us develop the 4MMBOPD we need to develop the economy and enjoy the benefits of oil and gas. I think investors can help to improve the technical space in the local industry by patronising local expertise. For example, our organisation consists of high-level professionals with experience of global oil and gas industry, as well as internal consultancies such as McKinsey & co, as well as PWC, among others.  These professionals understand international standards and procedures, and are able to offer advice to international level.

On the whole, the development of local refineries will help insulate the industry from the vagaries of international oil market cycles. With a population of 200Million citizens, Nigeria is the country to invest in. And the oil and gas leads the way.


Nigeria’s High Well Costs are at the Heart of its CAPEX and OPEX Challenges

By Ahmed Gafar, in Lagos

The astronomically high drilling costs of wells in Nigeria are key to the challenges faced by operators in reining in operating and capital expenses, an industry service provider has suggested.

If Africa’s highest crude oil producer is to reach its target of delivering Four Million Barrels of Oil Per day (4MMBOPD) in the near term, those costs need to be brought down, argues Hope Okwa, Founder/ Managing Director of Hd Okwa Drilling Services.

Hope Okwa

“A 10,000 feet well producing only 3,000 BOPD costs up to $25Million to construct in Nigeria”, Okwa allows. “To move from the current 1.5MMBOPD to 4MMBOPD requires massive well construction activities, in the order of over 800 wells per year. The associated investment is $21Billion per annum. Where will this investment come from, especially in an era where top global financiers are moving their investment to renewables?”. 

Okwa is persuasive that he is not just throwing numbers around: “$25Million per well cost is true for land, swamp and shallow offshore, as the rigs all use surface blowout preventers.

“The only way is to rethink well construction efficiency, with a view to drastically reducing well costs from current levels”, he contends. “The sources of inefficiencies in well construction, is very much within our expertise”, Okwa declares: “it is very urgent to implement these solutions”, as “in nine (9) years’ time in 2030, the advanced countries will pivot away from fossil fuel.  What will then happen to Nigeria’s reserves of 37Billion BO?”

 

Okwa’s benchmark is North America. “In Canada/USA, the rig rate for land is $32,000/day compared with $25,000/day for Nigeria. A 10,000 feet land well takes eight (8) days to drill while it takes 83 days in Nigeria. The Canada/USA cost is less than $2Million, while Nigeria is $25Million. The Canadians and Americans achieve the success by efficient well design (without gold plating as we do in Nigeria, efficient supply chain management, avoiding NPT and applying the science of drilling optimisation. We are experts in these areas. I should add that we are currently preparing to execute a $5Million horizontal well for a Nigerian marginal operator, applying our techniques”..  

Cost control in oilfield activities has been a front burner issue in Nigeria. Last February, the state hydrocarbon company NNPC had an elaborate event on cost optimization, at which Timipre Silva, Minister of State for petroleum, asked the country’s 34 oil and gas producing companies to join in working towards reducing operations cost to achieve the $10 or less per barrel production cost target.

Stakeholders have responded to Ministry of Petroleum’s call for cost control by naming causes including insecurity (You need gunboats full of naval officers on the way to rig-site) and taxation (government at all levels level multiple taxes: DPR hikes costs of obligatory services, State Governments demand various tariffs, Local Governments harass operators; communities hold up work; regulators sometimes delay). 

Okwa counters that “those issues relate to production mainly, and companies are having to trade off drilling wells due to the issues mentioned and high well cost”. 

 

Okwa has 29 years industry experience, the first 14 of which he spent in AngloDutch Shell, mostly on well engineering and drilling supervision. He had a stint at BG (the defunct British Gas) as a senior well engineer in the company’s Nigerian deepwater operations. He had a five year stretch as senior drilling and workover well engineer on critical gas operations at Saudi Aramco, after which he had another stint at BP Angola as senior drilling engineer.

“We believe that if we reduce well costs drastically.. we will be able to stimulate activities”, he says. “If we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands, even local banks may be able to fund field development campaigns.

The full interview is in the link


Michael Ajukwu Takes the Chairmanship of LEKOIL 

Michael Onochie Ajukwu, a Nigerian businessman, has been named Chairman of LEKOIL Limited, after Metallon Corporation succeeded in getting the three directors it nominated into the company’s board of directors, at the Extraordinary General Meeting (EGM) of the company on January 8 2021.

He takes over from Mark Simmonds, the British diplomat and politician, who had been in the position for just about a year.

Mr. Simmonds is as high profile as they come. He was Britain’s Foreign & Commonwealth Office Minister with responsibilities for Africa, the Caribbean, UK Overseas Territories, International Energy and Conflict Prevention. He served as a Member of the UK Parliament for fourteen (14) years and was also a senior advisor to the then Prime Minister, David Cameron.

Simmonds took over the Chairmanship at a time of huge reputational challenges for LEKOIL: the company’s shares were in a headlong crash in January 2020, after the AIM listed firm discovered that a $184 Million loan it had announced was fraudulent.

But LEKOIL had not been able to live down the smear. And it was one of the issues that Metallon Corporation raised, two months after it bought 15% share of the company and moved in for board changes.

“I am honoured to assume the position of Chairman of LEKOIL and would like to thank my predecessor, Mark Simmonds, for his contributions to the Company”, Ajukwu, known in Lagos  business circles for his closeness to South African brands and Nigerian banking interests, said. “I look forward to working with my colleagues on the Board and the management of LEKOIL to deliver a high performing company anchored on strong governance structures that produces value for all shareholders.”

The path to Mr. Ajukwu’s chairmanship was cleared when Mr. Simmonds chose to step down as Chairman at the EGM and all resolutions that Metallon put to the meeting were duly passed, with Metallon’s nominated directors, including Michael Ajukwu, Thomas Richardson and George Maxwell invited to join the Board with immediate effect.

Mr. Simmonds noted his intention to stand down from board Chairmanship role with immediate effect with a new Chairman to be appointed by the enlarged board of directors.

 


San Leon Pushes Its Oza Field Farmin into 2021

The AIM listed minnow; San Leon Energy, says that its planned investment in the 400 Barrel Per Day Oza Field onshore Niger Delta will not be realized until 2021.

The company says that the parties it is negotiating with “have agreed to extend the completion date to early in the new year”.

“As previously announced, worldwide restrictions put in place in response to the Covid-19 pandemic have slowed the logistical process in concluding the conditions precedent in the Subscription Agreement”, San Leon says in a note.

“Nevertheless progress continues to be made and the trading subsidiary of a major oil company, which along with a local Nigerian bank, is to provide a five year term debt to (licence holder) Millenium Oil and Gas Company Limited, Decklar’s local partner, has provided a further written confirmation of its support of the transaction”, San Leon explains.

“Given the proximity of the Christmas holiday period, the parties have decided to review the status of the outstanding conditions in the new year and assess at that time what remains outstanding”.

 


Uganda Invites Bids for Installation of Seismic Data Transcription System

The Petroleum Authority of Uganda has invited sealed bids from eligible bidders for the provision of, among other things:

Supply, Installation, Commissioning and Post Implementation Support for a Fully Functional/Turnkey Seismic Data Transcription System.

The deadline for bid submission is 8th January, 2021 at 10:00am.

The procurement shall be subjected to the PPDA guideline on reservation on schemes to promote local content in public procurement.

Full details of bid requirements are to be found in this link.

 

 


Ranking the Majors on Energy Transition

By Gerard Kreeft

 

 

 

 

 

 

Musical Chairs in Slow Motion

What is the status of the energy transition plans of the various oil and gas majors as they struggle to reduce their carbon footprint? What strategies  and energy scenarios are they developing? How can they be ranked? Below is an overview of their plans.

Equinor

Equinor is perhaps the company all of the majors are watching most closely. Equinor is dedicated to maintaining its oil and gas assets and also preparing to make massive investments in offshore wind energy. Equinor argues that its offshore oil and gas experience will complement its offshore wind activities.

Yet the stock market is not convinced. Currently an Equinor share is selling for approximately $15 (New York Exchange); in 2018 a share was valued at $25. Whether both oil and gas and offshore wind energy have a combined added value is a question that must still be answered. To date Equinor insists that the company’s strategy is that of defending  its  twin pillars of oil and gas and offshore wind.

While it may be too early to encourage spinning off wind energy as a separate company, it is important to watch Equinor’s plans for the future. Dogger Bank, located in the North Sea and which will produce some 2.6 GW of energy, enough to light up 4.5Million households, is the company’s showcase project.

Equinor is on course to produce 4-6GW energy by 2026 and 12-16 GW by 2035. Market leader Orsted has a current capacity of 10GW. In Europe the need for new energy in 2023 is expected to be 60GW.

Equinor’s more traditional natural gas business continues to be a reliable source of income: the company is Europe’s second largest gas supplier. Combined volumes from Equinor and SDFI(Norwegian state’s gas volumes) constitute more than 20% of Europe’s gas market.

A final footnote: Equinor has been in Angola since 1991. With it’s 17 employees the company in 2019 had an average daily oil and gas production of 140,000BOE! A small example of how Angola is helping Equinor make its offshore wind farms bankable.

TOTAL

TOTAL, always a player to watch, has not disappointed. The company has embarked on a strategy of reducing spending, selling marginal North Sea assets, buying Tullow’s Uganda assets at fire sale prices, and financing  Mozambique LNG with off-balance sheet funding.

TOTAL, with its deepwater track record in Angola Block 17, will certainly play a key role in new deepwater projects. Its Brulpadda Deepwater Project in South Africa(drilled to a final depth of more than 3,600 meters)  bears testimony of its deepwater agility. In Africa TOTAL is the undisputed energy champion helping to leapfrog exploration and development hurdles ensuring that oil and gas projects are implemented, on time and under budget.

TOTAL is also becoming an offshore wind player in the North Sea. Recently it purchased from SSE Renewables the majority stake in the Seagreen 1 project which can generate 1.14GW energy.

TOTAL also entered the Spanish electrical market with its purchase of Energias de Portugal’s portfolio of some 2.5Million customers, representing an electrical generating capacity of nearly 850 megawatts.

Through Eren, its affiliate, TOTAL develops projects in countries where renewable energy provides an economically viable response to growing power demand. Eren, in 2016, delivered a 10MW facility for the Soroti Power Plant, Uganda’s first-grid connected solar plant generating clean energy for 40, 000 households. In 2018 Eren installed the world’s largest hybrid solar/thermal plant with a capacity of 15MW for the IAMGOLD Mine in Burkino Faso. The company also provided two photovoltaic power plants (PV) with a capacity of 126MW for the Benban Complex, Aswan Province, Egypt.

According to TOTAL, low carbon electricity could account for 40% of its sales by 2050. TOTAL’s gross low carbon power generation capacity is 9GW, including 5GW from renewable energy.

ENI

ENI’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).
  • Production of 55 GW electrical generating capacity.

ENI produces 1.8 Million barrels of oil equivalent a day (1.8MMBOEPD), and has a large geographical presence throughout Africa, including Algeria, Angola, Egypt, Gabon, Ghana, IvoryCoast, Kenya, Libya, Morocco, Mozambique, Nigeria, Republic of Congo, South Africa and Tunisia.

The company’s operated  Zohr field is believed to be the largest-ever gas discovery in Egypt and the Mediterranean. In August 2019, production from the field reached more than 2.7Billion cubic feet of gas per day (bcf/d), roughly five months ahead of the development plan.

ENI’s key asset in Angola is the West Hub and East Hub projects, Block 15/06(ENI 36.84%, operator). Over a period of four years, eight fields have been started, four in 2018 alone. ENI also leads the New Gas Consortium(NGS), which has the mandate to explore for natural gas to be developed and supplied to Angola LNG and the domestic gas market .  NGS was created as a result of the oil and gas reforms implemented in 2018-2019: allowing companies for the first time to explore and develop natural gas assets.

Snam, Italy’s independent natural gas company, and formerly an ENI affiliate has participated in the European Gas for Climate study. The study concluded that transporting biomethane and hydrogen through existing the existing natural gas networks could result in annual savings of €217Billion by 2050.

BP

The sector is waiting, with bated breath, to see how BP’s new CEO Bernard Looney will transform the European giant to a “ net zero company”  by 2050 or sooner. No doubt BP is looking for participation in new renewable mega- energy projects.

Size matters and the time for action is now given that Looney is still in his honeymoon period. The company has introduced a far-reaching organizational change, but is this simply shuffling deck chairs on the Titanic or will we see new strategic changes?

Currently BP produces 3.7MMBOEPD. Adding a possible 1MMBOEPD of renewable energy to the reserve count can only bring a smile to the face of a BP shareholder, possibly ensuring that the 6+% annual  dividend is  safe.

Will shareholders decide that moving into a new strategic direction-taking renewables on board in a massive way- will guarantee in the long term their golden dividend? Possibly avoiding that BP’s oil and gas assets be viewed as  stranded assets.

Shell

Shareholders are united in their desire to see a greener company. Between 2016-2019 Shell spent $89Billion in total investments, of which only $2.3Billion was devoted to green energy. Its green playbook is uncertain but Shell will have to make a mega-deal to ensure it can play catch up. True Shell can boost that  natural gas/LNG in which they are a market leader, is the cleanest hydrocarbon. Will this satisfy shareholders?

If Shell wants to have an immediate green presence then a deal, much like the British Gas takeover in 2015, will be the precedent the company will follow. A possible target: Orsted, the Danish Offshore Wind Farm giant. Since 2016, Orsted’s share price has more than quadrupled. In 2016 it had a stock price of $35 and in mid-July 2020 $140( Danish Exchange). Orsted has a market cap of approximately $ 60Billion. Shell’s takeover of British Gas had a price tag of $52Billion. Although expensive by today’s prices, can Shell not afford to make a deal?

A promising and a more long-term scenario is  the NortH2 vision 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.

Chevron

Pre-Paris Chevron was viewed as the poster-child everyone respected and awed. Daily production of 3MMBOEPD, an annual dividend that has consistently increased for the last 32 years and  world class projects. Some examples:

Tengiz in Kazakhstan which in 2018 celebrated its 25th anniversary and geared to produce up to 1MMBOEPD.

Africa-Angola,Egypt,Nigeria and Republic of Congo– having a daily production of 412, 000BOEPD.

Gorgon LNG which is producing 15Million tonnes of LNG per annum for Asian-Pacific clients.

Post-Paris raises serious questions whether Chevron understands what the Energy Transition is about. Yes, Chevron has an ESG(environmental, social and governance) policy managed and implemented at the highest levels in the company. Key measures listed include:

Lowering greenhouse gases;

CCS(Carbon, Capture and Storage) project at the Gorgon LNG project;and

Various health, educational amd community development projects.

Yet there is a complete lack of any strategic discussion whether renewable fuels play a role. Chevron’s entire energy transition strategy is solely done within the confines of the fossil bubble. The one example given is  developing  a 29MW system of solar panels at Chevron’s Lost Hills operation. Lost hills indeed! Surely this is a script for a Monty Python energy transition film!

In 2019 Chevron wrote off $8Billion impairment cost for its Marcellos and Utica shale operations as well as Big Foot, a Gulf of Mexico (GOM) project . Will more write downs follow? For example Tengiz, with its highly sulfur based oil, could well become an ugly duckling. Sub-Saharia Africa could also turn sour. Angola, once the darling of the continent, has seen its oil production slip to 1.2MMBOPD.

Taken together Kazakhstan and Africa account for almost 50% of Chevron’s daily production. Is there a Plan B?

As a possible insurance policy  Chevron has purchased Noble Energy, also a fossil based strategy, for $13Billion.

Chevron once the poster-child of the industry could become the black swan and a mere reflection of what it now is.

ExxonMobil

ExxonMobil, with its headquarters in Irving Texas, produces 2.28MMBOEPD. Its DNA was forged in John D. Rockefeller’s Standard Oil Company of  the 1880s.

Its world class projects include:

Rovuma LNG, Mozambique, in which the company will own a 25% indirect interest in offshore Area 4. ExxonMobil will lead the construction and operation of all future natural gas liquefaction and related facilities, while Eni will continue to lead the Coral floating LNG project and all upstream operations.

Kizomba A,B,B Block 15 Angola, has to date produced over 2Billion barrels of oil and gas. Earlier  this year the Block 15 agreement was extended to 2032. A multi-year drilling pact was signed which is expected to produce an additional 40 000 barrels per day.

ExxonMobil is well known for its technical excellence and project management style geared to ensure maximum efficiency. Its style is top-down, like an army on the march. Many companies are willing to nominate ExxonMobil as a project operator knowing that this will on a dollar-for-dollar basis  generate the best results.

ExxonMobil, at least publicly, will not participate in energy transition discussions, but is willing to pursue scientific endeavors geared to reduce CO2 levels. For example, scientists from ExxonMobil, University of California, Berkeley and Lawrence Berkeley National Laboratory have discovered a new material that could capture more than 90 percent of COemitted from industrial sources, such as natural gas-fired power plants, using low-temperature steam, requiring less energy for the overall carbon capture process.

Laboratory tests indicate the patent-pending materials, known as tetraamine-functionalized metal organic frameworks, capture carbon dioxide emissions up to six times more effectively than conventional amine-based carbon capture technology.

In ExxonMobil’s Outlook for Energy: A perspective to 2040 the company states ”Oil and natural gas make up about 55 percent of global energy use today. By 2040, 10 of the 13 assessed 2oC scenarios project that oil and gas will continue to supply more than 50 percent of global energy. Investment in oil and natural gas is required to replace natural decline from existing production and to meet future demand under all assessed 2oC scenarios.”

The report continues:”Global energy demand rises by 20 percent; market demand trends differ for OECD and non-OECD. Continued innovation will help OECD economies expand while reducing their energy demand by about 5 percent and energy-related CO2 emissions by nearly 25 percent. In the non-OECD countries however, energy use and emissions will rise along with population growth, increased access to modern energy and improving living standards.”

 Conclusions

Seven profiles varying in scenario and strategy:

  1. Equinor beting heavily on wind energy and see their oil and gas assets and experience as complementary.
  2. TOTAL, which has Africa as a home base, has the dexterity to be a deepwater player and innovative in the current energy transition.
  3. ENI, which has unveiled its 2050 plans, has the ambition to move forward but details are sketchy.
  4. BP, Beyond Petroleum, willing, but where is the plan?
  5. Shell, wants a green miracle, but will it happen?
  6. Chevron, laid-back California-style will not make you an active participant in the energy transition.
  7. ExxonMobil, their technical excellence and discipline could become an asset to the other IOCs.

Gerard Kreeft,  BA ( Calvin University ) and  MA (Carleton University, Ottawa, Ontario, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. He writes on a regular basis for Africa Oil + Gas Report.

 

 


US EXIM Bank Provides the Largest Financing for Moza LNG, with $4.7Billion

United States’ Export Import (EXIM) bank says it has initiated “the process of providing $4.7Billion in financing a major integrated liquefied natural gas (LNG) project in Mozambique”.

The money is the largest committed by any lender to the 13 Million Tonnes Per Annum project, led by French major TOTAL.

The Mozambique LNG project will cost $20Billion to develop, but TOTAL is borrowing $14.9Billion from 28 financiers.

EXIM bank is one of eight Export Credit Agencies financing the project, the priciest hydrocarbon development on the continent. Other ECAs, aprt from US EXIM Bank, are: Japan Bank for International Corporation (JBIC), Nippon Export and Investment Insurance (NEXI), UK Export Finance (UKEF), Servizi Assicurativi del Commercio Estero of Italy (SACE), Export Credit Insurance Corporation of South Africa (ECIC), Atradius Dutch State Business (Atradius), Export-Import Bank of Thailand (EXIM Thailand)”,

There are also 19 commercial banks involved, of which Standard Bank of South Africa, is leading with $485Million loan. The Africa Development Bank, which is neither an ECA nor a commercial bank, is putting $4000Million in financing.

US EXIM bank’s involvement is primarily to support American contractors involved in the project. It says its funding “will support an estimated 16,700 American jobs over the five-year construction period”. Those jobs are at 68 suppliers located in eight states — Florida, Georgia, Louisiana, New York, Oklahoma, Pennsylvania, Tennessee, and Texas — and the District of Columbia. Follow-on sales are expected to support thousands of additional jobs across the United States.

“As the Mozambique LNG project marks further milestones, we want to underscore EXIM’s continuing commitment to this project,” said EXIM President and Chairman Kimberly A. Reed. “This project continues to serve as a great example of how a revitalized EXIM can help ‘Made in the USA’ products and services compete in a fierce global marketplace and counter competition from countries like China and Russia. It also reinforces EXIM’s strong support for President Trump’s Prosper Africa initiative to unlock opportunities for U.S. businesses in Africa. This authorization will stand as a reminder to companies across the board in all industries: EXIM is open, and we want to work with you to help fill financing gaps in the market to support our great American workers and exporters.”

A US EXIM Bank press release says that the transaction supports the Trump Administration’s Prosper Africa Initiative, “a whole-of-government economic effort to substantially increase two-way trade and investment between the United States and Africa.”

Launched in December 2018, Prosper Africa brings together the resources of more than 15 U.S. government agencies, including EXIM, to connect U.S. and African businesses with new buyers, suppliers, and investment opportunities.

 


Digital Transformation in Oil & Gas—How to Choose the Right Partners?

PAID POST

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.

  1. 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.

  1. 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.

  1. 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.

  1. Improved efficiency

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.

  1. Reduced cost

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.


TOTAL Will Now Drill Follow Ups in South Africa, From September 2020

TOTAL will return to drill in the rough waters offshore South Africa’s Cape Agulhas in September.

The French major will be commencing a multi-well drilling programme, beginning with the spud of the Luiperd Prospect, in the first follow -up to the Brulpadda oil and gas discovery it encountered in February 2019.

Luiperd-1, reputed to be the largest prospect in the Paddavissie Fairway (on which the Brulpadda itself is hosted), will be the first to be drilled by the semisubmersible rig Deepsea Stavanger, operated by Odfjell Drilling.  Two other wells are expected to follow in short order.

That the rig is currently mobilizing from Norway to South Africa, indicates the end of the idle period in the agreement between TOTAL South Africa and Odfjell Drilling. The programme was to have commenced in first quarter 2020, but restrictions effected by COVID-19 complications compelled the two parties to agree  that “Deepsea Stavanger will remain idle in Norway for a period prior to the mobilisation of the rig” and that “Odfjell Drilling will be compensated by TOTAL during this idle time”. The agreement also indicated that “once the idle period is complete, the rig will mobilise to South Africa to commence its charter as planned”.

Africa Energy, a minority partner in the licence holding and operations, declares its excitement “to begin the next phase of exploration drilling on Block 11B/12B offshore South Africa. in order to spud well by September”. The Canadian minnow explains that the prospect, Luiperd ’has been de-risked by the nearby Brulpadda discovery and subsequent 3D seismic work.”

Block 11B/12B is located in the Outeniqua Basin 175 kilometres off the southern coast of South Africa. The block covers an area of approximately 19,000 square kilometers with water depths ranging from 200 to 1,800 meters. The Paddavissie Fairway in the southwest corner of the block includes several large submarine fan prospects.

TOTAL is operator with a 45% participating interest in Block 11B/12B, while Qatar Petroleum and Canada Natural Resources have 25% and 20% participating interests, respectively.

 


ENI Finds New Gas in Egypt’s ‘Great Nooros Area’

Italian explorer ENI says it discovered a single 152 meters thick gas column in the first exploration well it drilled in the North El Hammad license, offshore Egypt’s Nile Delta.

Bashrush, as the prospect is called, is located in 22 metres of water depth, 11 km from the coast and 12 km North-West from the Nooros field and about 1 km west of the Baltim South West field, both already in production.

The gas molecules are stored in sandstones of Messinian age in the Abu Madi formation.

They have excellent petrophysical properties, ENI claims. “The well will be tested for production”, the company says.

“The discovery of Bashrush demonstrates the significant gas and condensate potential of the Messinian formations in this sector of the Egyptian Offshore shallow waters. The discovery of Bashrush further extends to the west the gas potential of the Abu Madi formation reservoirs discovered and produced from the so-called “Great Nooros Area”, the Italian giant explains.

ENI, together with its partners BP and TOTAL, in coordination with the Egyptian Petroleum Sector, will begin screening the development options of this new discovery, with the aim of “fast tracking” production through synergies with the area’s existing infrastructures.

In parallel with the development activities associated with this new discovery, ENI will continue to explore the “Great Nooros Area” with the drilling, this year, of another exploration well called Nidoco NW-1 DIR, located in the Abu Madi West concession.

ENI, through its affiliate IEOC, is 37.5%, equity holder and operator of the North El Hammad concession, in participation with the Egyptian Natural Gas Holding Company (EGAS). BP holds 37.5%, and TOTAL holds  25% of the Contractor interest.

 

 

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