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The Three – Service Sector- Musketeers of the Energy Transition: The Emerging Energy Value Chain

By Gerard Kreeft









All- For-One; One-For-All

Musketeer 1 Oilfield Services

Musketeer 2 New Energy Service Companies

Musketeer 3 Energy Service Companies Africa

There is growing evidence of a new convergence between Musketeer 1 Oilfield Services  and Musketeer 2 New Energy Service 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  Service Companies Africa- perhaps viewed as the junior musketeer, but nonetheless playing a significant role.

Their- All- For-One; One-For-All requires  further explanation.

Peak Oil and What to Anticipate From the Majors

Rystad Energy is a preminent independent energy research and business intelligence company, headquartered in Oslo, Norway.

The COVID-19 pandemic, according to the company, has accelerated the global peak demand for oil to 2028, instead of 2030 and cut peak oil demand to 102Million Barrels Per Day. This corresponds with BP’s peak oil analysis of 2025 and demand of 100MMBOPD.

Nonetheless, Rystad  calculated that oil demand,  in 2020, declined to 89.3MMBOPD, compared with 99.6MMBOPD in 2019. This is now termed “COVID-19 induced demand destruction”.  It is only in 2023 that demand will recover to pre-Covid-19 levels and jump back to 100.1MMBOPD.

There is also little evidence from the oil and gas majors to indicate that there will be a quick recovery. In 2021 the sector’s growth in Africa will be halting and slow:

ExxonMobil: Deepwater Offshore Guyana,  Rovuma LNG Mozambique are the company’s key challenges. Expect little else and no plans on renewables.

Chevron: Only $1.5Billion dedicated to possibly Angola, Equitorial Guinea and Nigeria. Attention is focused on Tengiz, Kazakhstan which is receiving 75% of Chevron’s budget outside the USA. Only fossil-based investments.

Equinor: Attention is largely  being devoted to expanding its offshore windpark capacity, all outside Africa.

ENI: With its large African footprint in Angola, Nigeria and Egypt the company is in prime position to expand its African operations. Green energy plans are being made.

Shell: reducing its oil and gas assets to 9 key hubs which includes Nigeria. Green shoots on the horizon.

TOTAL: its Brulpadda and Liuperd (Leopard) prospects in South Africa, together with its Mozambique LNG project will be the focal points in 2021. Little room for further plans. Green plans play a strategic role.

BP: intends to reduce its oil production by 40% .How will this affect the Greater Tortue Ahmeyim  development in Mauritania and Senegal, its Algerian, Angolan and  Egyptian assets? The first green plans are being unveiled.

Musketeer 1 : Oilfield Services

Global demand for oilfield services (OFS), measured in the total value of exploration and production (E&P) company spending, has in 2020 dropped a massive 25% as a result of the Covid-19 caused oil demand destruction, According to Rystad.

Spending in 2020 is at year’s end expected  to be $481Billion and take the first step to recovery will take place in 2021.

“The recovery will accelerate further in 2022 and 2023, with OFS spending by E&Ps reaching some $552Billion and $620Billion, respectively. Despite the boost, purchases will not return to the pre-COVID-19 levels of $639Billion achieved in 2019.”


Audun Martinsen, Rystad Energy’s Head of Energy Research, argues that the comeback will not be visible across all OFS segments. Well services and the pressure pumping market will be the first to see a boost, while other markets will need to get further depressed before recovering.

“Despite the recovery in oil prices, it will take many quarters before all segments of the supply chain see their revenues deliver consistent growth. In case of an upturn, operators would prefer flexible budget items with production increments and high-return investments with short pay-back times. Therefore, we expect well service segments to be the first to recover, while long-lead segments will pick up much later.“

  • Maintenance and operations: is poised for consecutive yearly rises in the next three years after slumping to $167Billion this year from $202Billion in 2019.
  • Well services and commodities: is set for a similar recovery, but only after slumping to $152Billion in 2020 from $231Billion in 2019 – the biggest decline among segments in absolute numbers.
  • Drilling contractors: falling to $46Billion in 2020 from $62Billion in 2019, and then rising to $57Billion in 2023.
  • Subsea segment: will fall from $25Billion in 2019 to $22Billion in 2021 – before starting to rebound to $24Billion in 2022 and to $29Billion in 2023.
  • EPCI: fell to $81Billion in 2020 from $105Billion in 2019, sliding further to $74Billion in 2021, before rising back to $81Billion in 2022 and growing to $106Billion a year later.
  • Seismic: declined to $12Billion in 2020 from $15Billion in 2019, dropping to $10Billion in 2021, before rebounding to $11Billion in 2022 and to $13Billion a year later.

The Players- BakerHughes, Halliburton and Schlumberger

Baker Hughes, Halliburton and Schlumberger, the traditional giants of the service providers, have experienced a long trek through the wilderness. Is relief on the way? A mixed bag.

Their stock prices have tanked: in December 2016 Baker Hughes’s share price was $65, now December 2020, it was $21; Schlumberger in December 2016 was $85, December 2020 it had dropped to $21; Halliburton in December 2016 was $55; in  December 2020 it was $19.

81,000 jobs have been lost since November 2019, to go by the report of the Petroleum Equipment and Services Association  (PESA).  In a recent forum PESA President Leslie Beyer stated: “The majors are making carbon reduction and setting net zero goals. Then they’re turning to their OFS sector partners and saying, ‘How are you going to help us get there?’”.  How indeed!

The strategies of both Halliburton and Schlumberger are defensive and show little reason for optimism:

Halliburton on its website talks about further digalization of its services, lower capital intensity and being committed to provide technologies that reduce emissions/environmental footprint.

Olivier Le Peuch, Schlumberger’s CEO, recently announced a major strategic restructuring creating four new divisions- Digital & Integration, Production Systems, Well Construction, Reservoir Performance.

Within the confines of the E&P bubble both major service companies continue on with what they anticipate what the IOCs (International Oil Companies) are dictating: belt tightening, a reduced head count, with the hope for a better tomorrow. Simply re-shuffling the deck chairs on the Titanic.

The one exception is Baker Hughes who has recently unveiled a forward looking strategy focused on CCS (Carbon Capture Storage), Hydrogen, and Energy Storage. Key themes for the Energy Transition.

The Drillers

Hans Hagelberg, Bassoe Offshore, has estimated that in the last 12 months the offshore rig fleet has lost almost 42%, or $30Billion of its total value. A large portion of the global fleet is now cold stacked. Of the 103 cold stacked, 94 have been stacked for 12 months or longer.

West Africa has been one of the hardest hit areas in 2020, according to IHS Markit: the region saw 11 contract cancellations from March to July 2020, the most of any area. Most of those cancellations were associated with jackups.

Jackup utilization in West Africa fell from 71% in September 2019 to 29% in September 2020, while drillship utilization fell from 48% to an abysmal 19% in the same time frame, according to Bassoe.

Dayrates for drillships in West Africa are currently between $150,000 and $200,000 per day, while jackups currently sit between $70,000 and $90,000. Looking to 2021, Teresa Wilkie, Offshore Rig Market Analyst, Bassoe,  rig utilization in West Africa is likely to stay flat, unless there is a marked increase in oil demand. With rig oversupply set to continue in the region, she expects dayrates to remain at the same level in 2021; further reductions are unlikely as the current rates are around operating cost level.

Marine Contractors- Two  key players- TechnipFMC & Heerema

Marine contractors have not been sitting idle. They are demonstrating adaptation and innovation.

The 2017 merger of Technip and FMC featured distinct market segments: subsea, onshore and offshore and surface projects. Now Technip Energies- entailing LNG, sustainable chemistry and decarbonization- is being spun off, creating new innovative options.

Arnaud Pieton, President and CEO of Technip Energies, says that the company is well placed to produce green hydrogen, given  that some  270 plants worldwide have their origin with TechnipFMC.  A strategic alliance with McPhy, a builder of electrolyzers, is expected to help enhance the production of green hydrogen. 

Heerema, which had its own enormous fabrication yard in Angola,  recently announced that it shut down operations citing poor  market conditions and sustained low oil price.  Instead the company is investing in the Offshore Wind Sector.

Heerema Marine Contractors recently signed a contract  to support the construction of the Changhua Windfarm Phase 1 project, Offshore Taiwan. Heerema will take on the installation of 21 jacket foundations (4 legged) for the Changhua project.

Musketeer 2 New Energy Service Companies

Siemens Energy

Siemens Energy has operations in 90 countries offering a full project cycle of services: generation, transmission and storage from conventional to renewable energy. Two examples:

  • Service center and a training academy in Egypt. The service center is the first of its kind in the region, combining a repair center, a tooling center and a spare-parts warehouse under one roof; and
  • Siemens Energy will supply six SGT-800 industrial gas turbines to the Mozambique LNG Project that will be used for low-emissions onsite power generation.


Cummins operates in 51 countries in Africa and market leader in fuel cell and hydrogen production technologies. Cummins began developing its fuel cell capabilities more than 20 years ago.

In 2019 Cummins purchased Hydrogenics, a leader in hydrogen technology. This accelerated Cummins’ ability to further innovate and scale hydrogen fuel cell technologies across a range of commercial markets.

Two examples of Cummins’s presence in Africa:

  • Cummins Angola operations, which is a joint venture partnership with Angolan ProjectNet. Cummins Angola currently occupies 1,000-square meters of office and parts outlet space, as well as 1,750-square meters of rehousing.  Cummins is working closely with the Angolan government to maximize the Private Public Partnership Framework to invest in the energy sector.
  • Cummins has supplied a power solution based around four of its 630 kVA generator sets to Standard Chartered Bank in Ghana. The system will provide the bank’s head office in Accra with standby power whenever interruptions to the grid supply require it.

ITM Power

ITM Power Plc designs and manufactures products which generate hydrogen gas, based on Proton Exchange Membrane (PEM) technology. This technology only uses electricity (renewable) and tap water to generate hydrogen gas on-site and can be scaled  up to 100MW+ in size.

Two examples:

  • The REFHYNE project to be installed and operated at the world’s largest hydrogen electrolyser at the Shell Rhineland Refinery in Wesseling, Germany.The PEM electrolyser, built by ITM Power, will be the largest of its kind to be deployed on a large industrial scale.
  • HyDeploy the £6.8Million project, funded by Ofgem and led by Cadent and Northern Gas Networks, UK, is an energy trial to establish the potential for blending up to 20% hydrogen into the normal gas supply to reduce carbon dioxide emissions. HyDeploy will run a year-long live trial of blended gas on part of the University of Keele gas network to determine the level of hydrogen which could be used by gas consumers safely and with no changes to their behaviour or existing domestic appliances. ITM Power is supplying the electrolyser system.

Musketeer 3: Energy Service Companies Africa

Musketeer 3 has huge challenges if Africa is to be lit up by 2025. The African Development Bank envisages:

  • 160 GW of new capacity for On-grid generation;
  • 130Million new connections for On-grid transmission and grid connections;
  • 75Million connections for Off-grid generation, an increase 29 times more than what Africa generates today;
  • Access to clean cooking energy for 130Million households.

There is a strong need to enhance the capability of Musketeer 3- Energy Service Companies Africa- to build coalitions across the sector and the region,  including the oil and gas and the renewable sector.

Some examples

  • Clean Energy Corridor which aims to support integration of cost-effective renewable power options to national systems, promote its cross-border trade and support creation of regional markets for renewable energy. The Clean Energy Corridor initiative has two African components:   (1.) African  Clean Energy Corridor(ACEC) for the member countries of Eastern and Southern African power pools.  (2.) West African Clean Energy Corridor(WACEC) within the Economic Community of West African States.
  • Partners should also include National Governments and their National Power Companies, including companies from Asia, Europe, the Americas, and the Middle East.
  • Finally this should include the oil and gas sector accustomed to carrying out large -scale projects. Providing them an opportunity to participate and be a partner in renewable energy.

The increased speed of the Energy Transition is not necessarily good news for Africa. The greening of Europe by the  majors could  mean reducing oil and  gas activities in Africa.

Why? Simply because the oil and gas majors are choosing  low carbon prospects and natural gas projects on a massive scale  leaving many potential prospects in doubt. Other smaller oil and gas projects will not be treated so kindly.

How will oil and gas prospects in Africa be judged? Do the various governments have the management skills to properly assess their energy scenarios?

Do they have the technical knowledge, capability and expertise to manage and implement oil and gas projects?

Then there is the matter of developing national service companies which have the technical capacity and knowledge to implement projects.


  1. Musketeer 1- Oilfield Services is in the sunset of his youth. Oilfield Services will continue but in a diminished marketplace. With the majors cutting back their oil and gas investments there is little room for optimism. Halliburton and Schlumberger must seriously re-examine their energy scenarios. Baker Hughes is showing investors that they have a Plan B.  Also the marine contractors- both TechnipFMC and Heerema- are making bold energy transition moves.
  2. Musketeer 2- New Energy Service Companies are defining the energy transition. Siemens Energy, Cummins and ITM Power are examples of new companies delivering energy systems for a renewable world.
  3. Musketeer 3- Energy Service Companies Africa could well become an alliance of national oil and gas companies, power companies and service companies in order to meet the requirements of the energy transition. They could well receive assistance from Musketeer 2-New Energy Service Companies.

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.



Libya’s Massive Crude Oil Engine

Libya has five major onshore sedimentary basins, they are:

  • Sirt Basin, Murzuq Basin
  • Kufra Basin
  • Ghadamis Basin
  • Cyrenaica Platform
  • Tripolitanian Offshore Basin

The main producing basins of Libya are in order of importance the Sirt, Ghadamis, Murzuq and the offshore Tripolitanian basin. Location of major Sedimentary Basins of Libya (click on hot spots on map to visit pages). Epirogenic movements with vertical nature are limited to uparching and faulting and included Mesozoic-Tertiary basins of Sirt and Cyrenaica (NE Libya). Tectonic movements occurred in northern Libya were responsible for the large sedimentary sequences in Libyan basins. The generation and entrapment of hydrocarbon in Libya was controlled by the tectonic history of each individual basin. According to Energy Intelligence Research, in 2003 Libya was the 11th largest exporter of petroleum in the world. Libya reached the peak of 3.3 million barrels a day in 1970 and currently produces only about 1.7 million barrels of crude a day. According to NOC, only around 30 per cent of Libya has been explored for hydrocarbons, Libya wants to return production to that peak level by 2010. There are about 320 producer field with total reserve exceed 50 billion barrels of oil and 40 trillion cubic feet of gas. Oil field distribution worldwide, notice that 4Q0 the oil reserve is from Middle East and North Africa Libya includes several hydrocarbon provinces of which the most important is Sirt Basin. This Basin contains some sixteen giant oil fields with about *117 Billion barrels of in place proven recoverable oil These form 89°c of all the discovered Libyan petroleum reserves. This basin is considered to be the most prolific oil basin in north Africa with an oil gravity that ranges between 44 and 32 API, and a sulphur content of between 0.15 and 0.66%. The Sirt Basin includes Cretaceous and Paleocene reservoir sequences and Upper Cretaceous Sirt Shale is a major source rock for this basin.

The Ghadamis intracratonic basin consists of up to 6000 metres of dominantly elastic Paleozoic through Mesozoic strata with an estimated three billion barrels of recoverable oil. The Upper Silurian Akakus Formation and the Tadrart – Ouan Kasa formations are the most prolific oil producing horizons.

The Muzurq Basin is filled with Cambrian through Quaternary deposits, with a maximum total thickness of more than 3000 metres in the central part of the basin, In the area to the north, where oil reserves are some 1 billion barrels, the potential reservoirs include the Memouniat, Acacus and Tadrart- Kasa sandstones. The major source rock in this basin is the Silurian Tanezzuft Shale.

To the present time no commercial discoveries have yet been made in the Mesozoic-Tertiary rocks of Cyrenaica and Paleozoic of Al Kufra Basin.

However recent work on stratigraphy and geochemistry of the Cyrenaican Platform suggests the probability of major potential reserves of oil and gas from Cretaceous and early Tertiary Rocks. Similarly the Devonian sandstones have been found to contain some gas shows in central Cyrenaica.

The offshore basins are considered to be highly prospective but has been exposed to only limited exploration to date. The major offshore oil production is in Tripolitania Basin from the El-Bouri oilfield that is producing about 60,000 BOPD, with an estimated two billion barrels proven recoverable crude oil reserves. On December 17, 2008, Hess Corp. reported an exploratory well has encountered a 160 metres gross hydrocarbon section at various intervals in an offshore extension of the Sirt Basin.

This paper is intended as an online introduction to the geology of Libya and its petroleum resources with links to maps and cross sections assembled from a variety of publications and geological sources by Hassan Salem Hassan (Swalem to his family), for his PhD geological studies at the University of South Carolina and his academic advisor Christopher Kendall.

World regions with major oil reserves and projected but undiscovered oil resources. Source: Energy Information Administration The figure on page 15 features a slump structure exposed on the coast of northern Cyrenaica (Al Jabal Al Akhdar). This region has been unstable since the initiation of an inversion of the topography in the Santonian time that uplifted Al Jabal Al Akhdar. This event was undoubtedly responsible for the folding of the Late Cretaceous-Early Tertiary rocks of northern Cyrenaica. The presence of contorted beddings in the figure matches that seen in more than two horizons of Al Athrun Formation. The structures above are characteristic of a gravity induced soft sediment slump, probably in a slope setting, suggesting a continuation of tectonic activity during Campanian time. Hassan Salem Hassan provides the scale.

Hassan S. Hassan, PhD Candidate, Advisor: Dr. Christopher Kendall, University of South Carolina, Department of Geological Sciences, Phone No. (803) 777- 5202, 701 Sumter Street, Room # 61 7 Columbia, SC 29208,

Editor’s Note: The figure of 117 billion barrels, as estimated recoverable reserves for Sirte Basin, is at odds with those of the BP Statistic Review, which is widely considered the bible of the industry.

Geosteering in Complex Fields (Angola) Following Girassol/Jasmim field experience, geosteering in Angola’s

By Antoine Massalal, Nigel Williamsi, TOTAL E & P Angola

Block 17, Dalia and Rosa fields, has enabled Total EP Angola to drill long, complex, single and multi- reservoir, horizontal and sub-horizontal wells, with great success. The initial planning of high offset geosteered wells, in the project stage, enabled TEPA to minimise the number of sub-sea manifolds and the number of wells, necessary, in order to bring the two fields into development, and to maximise the number and length of reservoir penetrations.

Real-time geosteering of such complex wells inside a single dynamic flow unit, even though still a challenge, is currently achieved with a high success ratio, also in thin (less than l0m thick) sandbodies. Successful geosteering of these wells has further enabled optimisation of the well pattern. As new information has become available during field development, it appears sometimes possible to substitute 2 wells by a more complex geosteered well, with multi- reservoir targets. The tools enabling successful geosteering of wells in Blockl7 are the excellent seismic image quality, coupled with the availability of ‘At Bit’ logging whilst drilling technology. In addition, Total’s Sismage’ seismic software enables sharing of data between the rig-site and Luanda, thus allowing the tie-in of the well in the seismic image, in real-time.

Finetuning Lithofacies and Reservoir Modeling using Borehole Images and Neural Networks

By Simone Di Santo’, Schlumberger Technical Services Inc., Angola, with Nilton Carvalho Rakesh Dhir Tank Gacem, Sonangol P&P.

The determination and definition of reservoir flow units is critical to developing an accurate and useful model of reservoir behaviour. Given that this model will ultimately guide significant capital expenditures such as interventions and infill drilling, it is crucial that the maximum accuracy be achieved. In this paper we describe how all available petrophysical data, with an emphasis on high resolution micro-image data, is used to delineate geological fades and ultimately define the reservoir flow units.

In our example we look at a deepwater field offshore West Africa with a number of wells, all with a variety of petrophysical data. We show how this data is integrated to first determine the range of fades to be identified and then to assign each metre of reservoir to a particular facies such that the resolution and accuracy of the flow unit determination is maximized.

We finally show how the results of the facies and flow unit identification are included in the reservoir simulation and reservoir modeling software to enhance reservoir understanding in order to optimize interventions and infield drilling.

Application of Outcrop Analogues to Optimize LWD Acquisition for More Confident Formation Evaluation in High Angle and Horizontal Wells, E. Tyurin and M. Benefield’, Baker Hughes, INTEQ

Outcrop analogues are very helpful in generation of the reservoir depositional model but are restricted in their application to formation evaluation. They represent a missed opportunity, in particular in the interpretation of high angle and horizontal (HA/HZ) well log response. In our vision they give us access to the depositional controls on vertical and lateral petrophysical rock properties variations as well as actual geometry of the geological bodies; both matters are critical for confident formation evaluation in HA/HZ well setting. The primary objective of this study is the integration of geological answers and petrophysical information to construct forward models of our high technology LWD datasets. We assign a major significance to the visual comparison of the rock picture and a simulated tool response, supported by a detailed petrophysical analysis. We initially used the Ainsa 1 Pyrenean deepwater turbidite outcrop with the petrophysical properties of analogous offshore West Africa reservoirs. Across- channel geological complexity (thin layering and low NTG in marginal part; pinch-outs, amalgamations and rock property variation in the axial part) is valuable to demonstrate improved strategies of interpretation solutions in channel to lobe turbidite settings. Steps to forward model the LWD data include many of today’s reservoir characterization procedures: sedimentological description, lithofacies to petrofacies associations, core and field scale 3D petrophysical properties simulation, upscaling, true resistivity matrix generation and resistivity anisotropy evaluation. Forward modeling of tool response accounts for different measurement natures, geometries and DOl’s (from meters in resistivity to cm in radioactivity, images and magnetic resonance). The range of the results acquired shows that basic LWD suites often do not provide an accurate result in a heterogeneous environment. For example, in our case water saturation is overestimated by around 30% total through improper use of the classical data. Our study highlights that reservoir parameterization in the presence of all scales of heterogeneities, sand mixtures and thin laminations is enhanced through proper application of gamma ray, resistivity, density, neutron and NMR for the pore volumetrics and imaging for the geobody shaping. Using the approach to a contrasted West Siberian field case with inherent low resistivity contrast and invasion of WBM demonstrates further interpretational challenges. The work ultimately permits a more confident selection of logging suites and subsequent improvement in application of the acquired data to formation evaluation in high angle and horizontal well situations.

Advanced Geosteering with Azimuthal Deep Resistivity Helps in Optimal Well Placement, NOVEMBER 2009, By Roland Chemali

Halliburton, Sperry Drilling Services

Early production, as well as ultimate oil and gas recovery, from a reservoir often depends on the timeliness and the accuracy geosteering decisions. Exiting the reservoir during drilling results in costly non-productive intervals.Even staying within the reservoir but in a non-optimal location eventually leads to early water break-through while leaving behind valuable attic oil. In recent years, azim

Fig 1- Geosteering with deep resistivity images from azimuthal deep resistivity LWD.

uthal deep resistivity measurements have been recognized as beneficial to real-time steering decisions. Because of their deep investigation, they give adequate warning to prevent from exiting the reservoir. Their azimuthal sensitivity clearly points to the direction of preferred evasive actions. Best results are achieved by jointly interpreting several measurements from the azimuthal deep resistivity, corresponding to multiple depths of investigation. In the simplest cases, the up-down resistivity curves exhibit a characteristic behavior that has proven valuable both to petrophysicists and to geosteering engineers. When approaching overlaying shale, for example, the up-curve consistently reads the resistivity of the reservoir while the down-curve exhibits amplified horns beneficial to reservoir navigation. Resistivity images feature bright spots whose progression with increasing depth of investiga

tion facilitates avoidance of unwanted boundaries. 4 new measurement designated as Geosignal features strong lateral sensitivity. The Geosignal from the deepest spacing is best suited to provide an early indication of the approaching boundary, with a near- exponential dependence on the distance to

Fig 2- Geosteering with up-down and with bright spot resistivity images from an azimuthal deep resistivity LWD.

boundary. Examples from around the world are shown in detail to help illustrate the applications.

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