Multiple records have just been broken for an LNG-powered ship, as construction completed at Heerema’s “Sleipnir” heavy-lift vessel (charted above). It substantiates our recent deep-dive note, which sees 40-60MTpa upside to LT LNG demand, from large, fuel-intensive ships, after IMO 2020.
Sleipnir is a record-setting crane-lift vessel, with capacity to pick up 20,000T. This eclipses the prior records in offshore oil and gas, which were around 12,000T, set by the Heerema Thialf and the Saipem 7000. Hence Sleipnir has already lined up 18 contracts, starting with the 15,800T topsides for Israel’s Leviathan gas field, and progressing on to Johan Sverdrup Phase II.
Sleipnir is a record-setting LNG vessel, burning gas as its primary fuel (although it can also burn diesel). With a displacement of 273,700T, we estimate it is the heaviest LNG-powered vessel ever built (eclipsing the largest such container ships, at 220,000T). With a cost of $1.5bn, we estimate it is also the most expensive LNG-powered ship ever built (eclipsing Carnival’s $1.1bn AidaNova cruise ship). It has the world’s first Type-C LNG tank in an enclosed column. Numbers are updated in our data-file here.
There is upside to LNG demandin large, fuel-intensive ships, especially cruise- and container ships, after IMO 2020. Small-scale LNG may offer an economic “bridge”, while bunkering becomes increasingly attractive as volumes per port scale past c80kTpa. Forward-thinking Majors are already investing to capture the future market.
Finally, for a video of the construction vessel being constructed…
A typical offshore operator can very readily save $1/boe via continued, digital deflation; which is tantamount to $1bn per annum at a c3Mboed Oil Major.
Our numbers are derived from a case study by Cognite, which is among the leaders in oilfield digitization, collaborating with cutting-edge E&Ps, as described below.
Digitization remains the most promising opportunity to improve offshore economics. But the gains are granular and can only be seen by delving into the detail…
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This short note will focus further upon three particular avenues for digital deflation, which collectively account for $0.6/boe of cost savings at a typical offshore operator.
All are achieved using greater data instrumentation, as highlighted in Cognite’s recent case study, based on working alongside Aker-BP, which we calculate can save $1/boe across the operator’s portfolio (chart below).
(1). Production Optimisation can be attained by increasing the throughputs in processing units, such as separators. In Cognite’s example, this is safely achieved by using better data from multi-phase flow-meters upstream of the processing units. Better data enables better performance. Deferrals associated with the flow-meter calibration are also reduced by 30-50%.
(2). Smart maintenance of equipment can be achieved by greater monitoring. For instance, the Ivar Aasen sends data back to shore, in real time, on 90,000 information packages, including 18,000 valves, all the wells, compressors, pumps and generators. Cognite’s example is at these shut-down valves and fire dampers, which now require 80% fewer maintenance hours to check. In addition, the number of hours per miantenance check is reduced by 90%.
(3). Improved information flow to “digital workers” improves productivity. As context, maintenance of a large process unit (e.g., a 1st stage separator) may require 1,300 planning hours per year, but this can be improved using data (video below). In turn, this superior planning reduced the time spent on routine inspections by c50%, increasing the number of monthly maintenance jobs by 10% and with better HSE performance.
A virtual visit to an offshore oil platform, instrumented by Cognite. Live data are displayed and can be further interrogated for planning purposes …
Digital improvements offer great potential to improve offshore economics. However, as we have highlighted, no individual improvement is a magic bullet. Uplifting IRRs, particularly on new greenfield projects by say, 5pp, requires progress on as many as twenty different dimensions (chart below).
This is where Thunder Said Energy can help, screening the economic opportunities and best-practices across different companies, using our databases of patents and technical papers.
Perovskites are the fastest-improving solar innovation. The best test-cells hit a new record of 28% efficiency last year, with line-of-sight to the mid-30s, i.e., 2x more efficient than today’s silicon photovoltaics. A Major is at the cutting edge.
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Today’s renewable technologies are not sufficient to deliver a rapid energy transition. On our numbers, the world will still need 120Mbpd of oil by 2050, while the need for gas will treble, even with $300bn pa invested in wind and solar (chart below, model here) .
What can accelerate the transition is next-generation technology, delivering more energy at a lower cost.
In the solar space, the most exciting opportunity we have reviewed so far is Perovskites. Their efficiency has improved faster than any other solar cells, since the first examples were tested in 2009. There is now line-of-sight to reach 2x higher efficiency than today’s solar cells (c17%), for lower costs.
Five Facts about Perovskites
(1) Perovskites are a mineral class (named after a 19th Century Russian Count). They exhibit exceptional optoelectronic properties: A low band gap means it is easy for incoming photons to dislodge electricity (electrons). Low thermalization losses mean that these liberated electrons are effectively conducted to electrodes, without their energy being dissipated.
(2) The most common cell designs sandwich a layer of MethylAmmonium Lead Iodide (band gap of 1.55 eV) in between an ‘electron carrier’ and a ‘hole carrier’, which are in turn sandwiched between a gold cathode and a fluorided tin oxide anode. A 400nm film of this material can absorb almost all photons in visible light.
(3) Costs should in principle be lower than today’s photovoltaics, due to eliminating the intricate and energy-intensive processing of silicon. Instead, Perovskites crystallise out of a solution onto a substrate. c35% of the cost is the “hole transport layer” and c20% is the gold cathode, both of which are being improved.
(4) Constant innovation is taking place in the technical literature. Mixing perovskites with different cations or silicon can improve the stability of the cells, and liberate more electrons. Efficiency is hindered when liberated electrons recombine at the boundaries of Perovskite “grains”, hence these grain boundaries can be “passivated”. Finally, efficiency can also be improved with better transport materials, electrodes and at the interfaces between materials.
(5) Not there yet. We have classified Perovskites at TRL5. So far, most Perovskites degrade within 500-1,000 hours, due to moisture, oxygen and ultra-violet light, while achieving c200-days’ lifespan is documented as remarkable. Outdoor applications have not been proven. The test cells developed in the lab typically cover 1cm x 1cm. And most use lead, which is toxic.
In conclusion, the technology is exciting, and improving rapidly, but it is also long-dated. It requires committed investors who understand the long-term potential…
Driving the Transition
Reviewing patents and technical papers around the energy industry, what has surprised us most is the Oil Majors’ involvement at the cutting edge of next-generation renewables technology. Leading Majors want to drive the transition: strengthening their societal license to operate and capitalising on vast new opportunities in the future energy system.
It is no different in solar. In 2017, Equinor participated in the £31M Series D funding of Oxford PV, the company at the forefront of Perovskite research, and holding the most recent records for Perovskite cell efficiency. Equinor’s involvement will support Oxford PV gear up to a more commercial phase.
This adds to the other Majors’ efforts at the forefront of solar. We have reviewed 37 patents across the group, and have characterised the leading companies’ efforts here (chart below).
The downstream industry is currently debating whether IMO 2020 sulphur regulations will be resolved quickly or slowly. We think the market-distortions may be prolonged by under-appreciated technology challenges.
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As context, from 2020, it will no longer be permitted to burn fuels with 3.5% sulphur in the marine segment. Their maximum permitted sulphur content will fall to 0.5%. In principle, refining cracks will move, advantageously for low-sulphur diesel and disadvantageously for high-sulphur fuel oil.
Over time, this should provide an economic incentive to construct incremental hydro-processing and hydro-conversion technologies. However, it still may not be so simple as to construct a few extra hydro-processing units. Not all sulphur is equal.
Hard Sulphur and Easy Sulphur
On the one hand, aliphatic sulphur compounds are easily treated. The process uses a hydrogen partial pressure of 10-30kg/cm2, 180-370C temperatures, and liquid:catalyst ratio up to 4:1. The catalyst contains Cobalt, Nickel and/or Molybdenum on an aluminium oxide framework. This is industry-standard technology, available to all.
However, highly branched molecules are harder. One class, dibenzothiophenes, is pictured below. Their structure impedes the sulphur “heteroatom” from reaching the active site on the catalyst. Run it through a low-spec hydrotreater, and it comes out the other side… unchanged.
Another challenge with aromatic sulphur-containing compounds is their under-saturation. Traditional hydroprocessing techniques, aimed primarily at reducing sulphur, also tend to saturate these aromatic rings which “can increase the amount of hydrogen consumed during hydroprocessing by as much as an order of magnitude”. This is problematic at refineries with limited hydrogen. It adds cost.
It may be under-appreciated how much of the sulphur in the world’s fuel market is “difficult sulphur”, rather than “easy sulphur”. For example, if we take Saudi Arabia’s production, comprising the most abundant crude oil streams on the planet, the more challenging sulphurs comprise 0.5% of Arab Light, and 1.3% of Arab Heavy.
As Aramco’s patents note “it is very difficult to upgrade existing hydrotreating reactors” and “the economical removal of refractory sulfur-containing compounds is exceedingly difficult to achieve”. Especially if the end target is to reach higher European and US standards of 0.1% sulphur caps.
Resolving the Impasse: Large Investments?
There are solutions to this challenge. Indeed, Aramco has filed patents for methods of removing these more challenging sulphurs. One is to build a new separation unit, distill the crude into two separate streams, isomerise the ‘hard sulphur’ stream, re-combine it with the ‘easy sulphur’ stream, then hydro-treat the mixture. Hydrocracking these compounds is another option, breaking them down into lighter, smaller, “easier sulphur” molecules.
Both of these options require large investment, with multiple processing units and ancillary units. It follows that the ultimate refinery projects used to re-balance the market post-IMO 2020 are not simple hydoprocessing projects.
Against this backdrop, fears over the energy transition make it increasingly difficult to justify large, long-term investments. Particularly in Europe.
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Opportunities amidst the Challenge?
So if the market-distortions of IMO 2020 have longevity, who will stand to benefit? We are maintaining a data-file of the ‘Top Technologies for IMO 2020’ around the industry, which give specific companies an edge. The data file now contains over 25 technologies across 7 Majors.
References
Al-Shahrani, F., Koseoglu, O. R. & Bourane, A. (2018). Integrated System and Process for In-Situ Organic Peroxide Production and Oxidative HeteroAtom Conversion. Saudi Aramco Patent.
Koseoglu, O. R., (2018). Integrated Isomerisation and Hydrotreating Process. Saudi Aramco Patent CN107529542
Hanks, P. (2018). Trim Alkali Metal Desulfurisation of Refinery Fractiions. ExxonMobil Patent US2018171238
This note contains our ‘Top Five’ conclusions about the Oil Majors’ research partnerships, drawing off our database of 3,000 oil company patents. Different companies have importantly different approaches. We can quantify this, by looking at the number of patents co-filed with partners (chart above).
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(1) Working with Academia. TOTAL stands out as collaborating most closely with academic institutions, by a wide margin. In 2018, it filed 75 such patents, of which two-thirds were with French institutions. Aramco was next with c40 patents co-filed with Academia. Eni and Repsol filed c4-5 each.
(2) Working with Services. Chevron stands out as working most closely with the Services industry, as it is co-developing two particular technologies: “electro-crushing drilling” with Halliburton, and distributed acoustic sensing with Silixa. We expect Chevron to have a lead in both technologies, before they are licensed out to the broader industry.
(3) Working with Customers. Exxon has co-filed most patents with its customers: advanced lubricants with Toyota and advanced plastics with packaging companies. The moat around Exxon’s IP in both areas is extremely impressive.
(4) Working Internationally. Aramco runs the most global research collaborations, with 5-10 patents filed in each of 5 international countries. This is unusual, as most other companies confine their research partnerships to their home countries (below).
(5) Working Independently. Shell and Equinor run the most independent research processes, filing 96% and 98% of their patents solo. We have been impressed with the technical specialisations both organizations have built up in-house.
Our full database of 3,000 patents is exclusively available to TSE’s subscribers, including short summaries of each patent. For further information, please email us, contact@thundersaidenergy.com
Global energy investment will need to rise by c$220-270bn per annum by 2025-30, according to the latest data from the IEA, which issued its ‘World Energy Investment’ report this week. We think the way to achieve this is via better energy technologies.
Specifically, the world invested $1.6bn in new energy supplies in 2018, which must be closer to $1.8-1.9bn, to meet future demand in 2025-30– whether emissions are tackled or not. The need for oil investment is most uncertain. More gas investment is needed in any scenario. And renewables investment must rise by 15-100%.
Note: data above includes $1.6trn investment in energy supplies and c$250bn in energy efficiency measures
Hence the report strikes a cautious tone:“Current market and policy signals are not incentivising the major reallocation of capital to low-carbon power and efficiency that would align with a sustainable energy future. In the absence of such a shift, there is a growing possibility that investment in fuel supply will also fall short of what is needed to satisfy growing demand”.
We do not think the conclusions are surprising. Our work surveying 50 investors last year found that fears over the energy transition are elevating capital costs for conventional energy investments (below).
Meanwhile, low returns make it challenging to invest at scale in renewables.
We argue better energy technologies are the antidote to attracting capital back into the industry. That is why Thunder Said Energy focuses on the opportunities arising from energy technologies. Please see further details in our recent note, ‘What the Thunder Said’. For all our ‘Top Technologies’ in energy, please see here.
References
IEA (2019). World Energy Investment. International Energy Agency.
We categorised 300 of the Oil Majors’ technologies according to their technical maturity. We find the most exciting examples are not the most technically mature, but those on the cusp of commercialisation. Majors that work on earlier-stage technologies also have better overall technologies (c50% correlation coefficient). Hence, to create value, it is important to maintain a constant funnel of technology opportunities.
When we assess an energy technology, we score it on four dimensions: how far does it advance the industry-standard? How large is the potential economic impact? How proprietary is it? And finally, is it “ready”?
To quantify the final category, we use the industry-standard conceptual framework of ‘Technology Readiness Levels’ (TRLs), which are summarised below. It is worth being familiar with this categorization, as it recurs throughout our work.
But when do technologies get exciting?
To some extent, “excitement” depends upon your perspective. Venture funds may find most value on the earlier rungs of the ladder. But most companies and investors get excited in the later stages. We can measure this. The results are surprising.
Below, we have summarised our “TSE Technology Scores” for 300 technologies, used by the 25 oil and gas companies that we follow. The highest scores appear to be for technologies at Readiness Level Seven (chart below).
Even though these technologies are less mature than TRLs 8-9, we think they are more exciting. This is unexpected. As discussed above, our “Technology Scores” specifically award higher marks to more mature technologies, and penalise those that are less mature.
On the other hand, maybe it is not so surprising. Opportunities at TRL7 are, by definition, new and cutting-edge. Conversely, the shine tends to wear off for more mature technologies, that have already spread around the industry.
What does it means for companies?
If the most exciting technologies are the ones on the cusp of commercialisation, it is important that leading companies can embrace them. We think the answer is to maintain a rich funnel of opportunities, including those at earlier stages. Our data suggest that the technology-leaders around the industry are doing exactly this…
Below, we rank the 25 oil and gas companies that we follow. We find a 50% correlation between the companies that are working on ‘earlier stage’ technologies and those that have better overall technologies.
“Technology Scores” across 25 Oil and Gas companies, which are tracked by TSE
Investable insights. To develop a lead in technology, you have to be involved in developing technology. If your sole approach is to buy mature technologies off the shelf, you will only access them later, and with less theoretical context than the leaders. We think this explains the correlation above. We also think it matters for investing in the best energy companies, where technical capabilities are starkly different (below).
“Technology Scores” across 20 Oil and Gas Companies, which are tracked by TSE
How can we help? For our full database of 300 technologies, scores by company, or by industry sub-segment, please contact us. We can also provide consultancy services on your company, highlighting areas where there is most scope for improvement, by reference to peers’ best-practices.
An exciting aspiration in wind technology is to obviate large, expensive “towers”, and unleash tethered kites into the skies. They can access 2-4x more wind-power at greater altitudes, and at 50-90% lower costs. Intriguingly, we have discovered Exxon and Shell are at the forefront of pursuing this new wind opportunity offshore, based on their patents and filings.
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Oil Majors & Wind Energy
If you search the internet for Exxon’s “wind power” business, you are most likely to encounter its range of lubricants for wind-turbines. Its largest public foray so far is a 250MW commitment to offtake wind power into its Permian operations from Orsted’s Sage Draw wind farm.
For Shell, the narrative is around scaling up today’s wind turbines, under its $1-2bn new energies capex commitment. Its most recent bid was for a 2.5GW wind consortium, 8-miles off Atlantic City; off the heels of its 730MW Borssele III-IV project from the Netherlands.
Yet we have found new evidence that both of these Super-Majors are actively looking to a novel offshore wind technology, with potential to unlock larger quantities of energy at materially lower costs.
The theory: aiming higher?
Wind power in the earth’s atmosphere increases with altitude, as shown below. At 300m, it should be possible to access 2x more power than at 80m, based on global average wind speeds, modelled here.
The challenge for conventional wind is how to access these higher wind speeds. The 4,000m foundation and 700T tower already comprise c35% of a typical, 80m wind-turbine’s overall cost.
Hence there is an entire green-tech industry dedicated to “flying wind”. These are airborne drones that submit their power back down to ground level via a tether. The academic literature estimates costs per-kW could be 10-50% the level of conventional wind turbines. “Technology Readiness” ranges from Level 3 to Level 7.
The most famous example would be Makani, which tested a 600kW capacity vehicle in 2017, with the backing of Google (video below). Scroll half-way through the video, to 17-minutes, and you see the tethered craft mid-flight, conducting a looping series of nose-dives: when the vessel surpasses 85mph, according to our calculations, its on-board propellors could be beaming a full 600kW of power back down the tether-cable, towards the base-station. The glider is then carried back up to altitude like a kite, before commencing another dive.
https://www.youtube.com/watch?v=CKFlMDUHtLg
Exxon and Shell are examining what to do with this technology
ExxonMobil has filed a series of patents to deploy tethered kites offshore, “opening up a resource system which is four times greater than the electrical generation capacity of the entire United States” (in the patents’ own words).
The image below shows Exxon’s concept for an offshore wind farm, with 25 kites (each with 20kW-5MW capacity), arranged in 5 rows of 5. Each row of kites has its own umbilical, electrical module and distribution cable.
The patent includes some comprehensive considerations: the tether system, its connection to a floating structure, the anchor piles, a quick-disconnect system, and offshore maintenance procedures.
Exxon’s floating offshore wind concept?! (150) is a local electrical distribution cable, (146) is an underwater electrical module and (152) is an offshore substation.
Exxon continued refining these patents in 2018, with at least three further filings (in the jurisdictions of Argentina and Taiwan… read into that what you will). We have contacted the company for a comment on any plans to test or pilot the technology, and will update this article with any answers.
Meanwhile, Shell is also stepping up its interest in offshore wind kites. In February-2019, it signed its own partnership with Makani, saying that it “plans to kick-off testing of this new floating offshore system with demonstrations in Norway later this year”. Previously, Shell also invested €6M in Kite Power Systems, another aerial wind concept.
So we have here, an intriguing secret race between two of the largest Oil Majors, at the cutting edge of offshore wind-tech.
Sources & References
Zillman, U., (2015). The Trillion Dollar Drone. Airborne Wind Energy Conference 2015
Hart, C., & Bushby, D. (2017). Airborne Power Generating Crafts Tethered to a Floating Structure. Patent WO2017218118.
Goldstein, L. (2015). Theoretical analysis of an airborne wind energy conversion system with a ground generator and fast motion transfer. Energy Volume 55, 15 June 2013
It would be unwise to under-estimate the complexity of creating a new LNG province, with a 50MTpa prize on the table in Mozambique. After the first two trains are in motion, the longer-term opportunity is potentially “another Qatar”. But only if Mozambique can compete for capital with US greenfields and brownfield expansions.
Hence we have reviewed 200 of Chevron’s patents from 2018. The company’s ability to develop a new, deep-water LNG province is notable. Ten examples are tabulated below.
It was interesting how many of the patents were filed in Australia and may have derived from learnings at Gorgon and Wheatstone.
For a primer on different LNG process technologies, please see our data-file (here).
Find this work interesting? If so, please sign up for our distribution list.
EOG has patented a system to deploy pressure and temperature sensors in its frac plugs, which are then retrieved at the surface, providing low cost data on each frac stage. The data can be used to improve subsequent frac stages. We model the economic uplifts at +$1M NPV and +5% IRR per well (at $50 oil).
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EOG screens among the leaders in shale technology, based on the patents and technical papers we have reviewed so far. However, the company is secretive over its intellectual property, notoriously banning camera-phones from its well-sites and publishing fewer technical papers relative to its peers.
However, last year EOG filed a patent for one of its data-methodologies, which we believe is being applied in its operations in Texas.
Specifically, EOG is housing “sensor pods” in its frac plugs. Each of these pods can record 50-100k data points, logging temperature and pressure during a frac stage. Later, the frac plugs are released, and retrieved back at the surface, where their data can be downloaded.
This methodology allows EOG to measure actual frac pressures down-hole, close to the perforations, for each, individual frac stage. The readings are likely to be much more accurate than the inferences from the surface. Downhole temperatures can also be measured.
Why is this useful?
First, the data can be used to enhance EOG’s modelling of the fracture network. In turn, this can be used to infer mechanical properties of the formation, and optimise future frac stages: tailoring perforation geometry, injection rates, sand concentrations, fluid viscosity and chemicals compositions.
Moreover, the data can be used to detect problems. If a frac stage has not been properly isolated, then pressure will not build up as much on either side of the frac plug. If a well is unexpectedly flowing(/not flowing), then downhole fluids will be warmer (/cooler). In another design, the sensors can be placed in neighbouring wells to detect frac hits.
If all of these factors can increase well productivity by c10%, then we estimate the NPV uplift at $1M NPV or +5% IRR per well. The technology breaks even if it can uplift EURs by c2.5%. These numbers vary based on the oil price (chart below, model here).
Wouldn’t fibre be better?
We have seen other operators making enormous strides deploying down-hole fibre-optics, to monitor pressure and temperature, meter-by-meter, in real-time across a 20,000ft well. This would offer more granular data, immediately. I.e., you would not need to wait until the sensor pods are retrieved at the surface to download their data.
However, we do not believe the cutting edge of fibre is currently practical for common usage in the shale patch: running the complete works of fiber-optics across an offshore well can surpass $1M. As we have learned from other patent-filings, retrievable plugs can be run “at a fraction of the cost associated with a tethered downhole sensor”. Our numbers above assumed $0.4M incremental costs for deploying EOG’s sensors across a 40-stage stimulation.
Another leading example of big-data
As we have highlighted in ‘Winner Takes All‘, shale is increasingly a ‘tech’ industry, harnessing advanced modelling or data-based optimisation in 60% of the 300 technical papers we reviewed from 2018 (chart below). So here is a cutting edge example from EOG.
Bustos, O, Raizada, S., James, C. et al (2018). Completion and Productions Apparatus and Methods Employing Pressure and/or Temperature Tracers. US Patent No 2018/0252091 A1
Naldrett, G., Cerrahoglu, C. and Vahue, M. (2018). Production Monitoring Using Next Generation Distributed Sensing Systems. Petrophysics. Volume 59.
Deffenbaugh, M., Ham, G. D., & Alvarez, J., O., et al (2016). Method And Device For Obtaining Measurements Of Downhole Properties In A Subterranean Well. Saudi Aramco Patent US2016320769
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