Category: Commentary

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Robot delivery: Unbelievable fuel economy…

fuel economy of Robot delivery

Stand on a street corner in Tallinn, in the summer of 2019, and you might encounter the scene below: not one, but two autonomous delivery robots, comfortably passing one-another.

The fuel economy of these small electric machines is truly transformational, around 100x better than a typical motorcycle (the trusty workhorse of take-aways past), around 200x better than a typical car and around 400x better than a typical pick-up.

Large implications follow for energy supply and demand, if such delivery-robots take off…

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Starship is the company commercialising the robots above, backed by the co-founders of Skype, lightly aiming to “revolutionise food and package deliveries, offering people convenient new services that improve everyday life… instant delivery works around your schedule at much lower costs”.

Over 50,000 deliveries have been completed by April-2019, including trials in California, Tallinn, George Mason University, and Milton Keynes. Based on the chart below, we estimate the fleet is traversing c400km/day. In some locations, the costs are as low as c$2/delivery, with an ambition of reaching $1/delivery as the technology scales.

What does it mean for energy demand? Take a Ford F-150 which achieves 17mpg. You can achieve a 4x fuel-economy uplift by electrifying it. Another 2.5x uplift comes from lowering the mass to 30kg. Another c40x net uplift comes from decreasing the average speed of travel to 3-5kmph. These numbers can be calculated, approximately, from the physics, in our data-file of fuel economies by vehicle type.

Direct energy economics are calculated below, based on the battery disclosures for one of Starship’s robots. A single delivery robot is implied to achieve an unheard-of c200miles/kWh. Matching the maths above, this is indeed 100-400x better than alternative transportation technologies which we have profiled.

Creation or destruction? The numbers above augur poorly for long-run demand of liquid transportation fuels. In cost terms, it is very difficult to compete with these vehicles’ incredible efficiency. What is unclear is whether such delivery vehicles destroy old demand, or create new demand, per “Jevons Paradox” that more efficient energy technology has historically increased energy demand.

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Our conclusion is to have found further evidence that transportation technology is evolving. Forward thinking energy companies will be preparing for the change, as evidenced by their patents, their projects and their venturing.

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Shale: restoring downstream balance? New opportunities in ethylene and diesel.

New opportunities in ethylene and diesel

We have all heard the criticism that shale oil is “too light”, so its ascent will create a surplus of natural gas liquids and a shortage of heavier distillates. Less discussed is the opportunity in this imbalance. Hence this note highlights one such opportunity, based on an intriguing patent from Chevron, which could convert ethylene into diesel and jet fuel, to maximise value as its shale business ramps up.

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Are ethylene, polyethylene and diesel markets broken?

US ethane production reached a new peak of 1.9Mbpd in 1Q19, having doubled since 2014. Two thirds of that ascent can be attributed to the Permian, where output rose 4x over the same time-frame and 10-15% of production is ethane. So far, the latest rises in ethane are being absorbed by new steam crackers on the US Gulf Coast. In 2018, Chevron and Exxon both started new facilities, which will each take in 90kbpd of ethane, to produce ethylene and polyethylene.

A glut of ethylene and polyethylene has resulted. S&P Platts noted in June-2019 how Gulf Coast ethylene prices had fallen to an all-time low of 12c/lb, which is down -80% from 2012-14 average levels of 60c/lb. As a consequence, polyethylene prices are also -20% since early 2018. Hence ICIS notes the risk of a “trade war” as the world must absorb growing US polyethylene supplies. Other commentators are even more cautious, arguing the ramp up of US crackers and chemicals plants will coincide with a structural decline in plastics demand. All of this would block the outlet for shale’s light components and hinder its ascent (chart below, our model downloadable here).

Fears over a diesel shortage persist on the other side of the oil product market. Shale’s light oil composition has been blamed. One European Major recently told us this is why it remains negative on the shale sector, as it cannot run shale oil effectively through its refineries, which are geared to cracking and coking heavy oils. IMO 2020 sulphur regulation compounds the fear of a diesel shortage, pulling in c2-4Mbpd of diesel into the shipping fuels market, as demand for high-sulphur fuel oil collapses.

An opportunity is thus created for an integrated oil company, if it can transform the surplus of ethane ($0.10/lb), ethylene ($0.13/lb) or other light fractions into diesel ($0.33/lb).

Seizing the opportunity: from ethylene to diesel?

What is fascinating from our review of 3,000 of the Oil Majors’ patents is that many companies are progressing technologies to seize these emerging opportunities, i.e., to convert the abundant by-products of shale into under-supplied products. For the challenge described above, we recently reviewed a Chevron patent, which can oligomerize ethylene into diesel and jet fuel. The process schematic is shown below.

Similar technologies already exist to convert ethylene into dimers, trimers and oligomers, rather than straight polyethylene. For instance, Shell’s SHOP process uses Nickel catalyst to produce alpha-olefins. Others include the Ineos process, Gulf process (ChevronPhillips), Sabic Linde α-Sablin or the IFP-Axens AlphaSelect process.

Where Chevron has an edge is in ionic liquids catalysts, which have been used elsewhere in its refining operations to achieve higher yields of very high octane alkylates for the gasoline pool. Chevron’s ISOALKY technology won Platts’ 2017 “Breakthrough Solution Award” and has been installed in a c$90M retrofit to Chevron’s Salt Lake City refinery. The first Chevron patents for alkylation of ethylene using ionic liquid catalysts go back to 2006.

The key improvements in Chevron’s latest patent filings allow ethylene to be converted into distillates. Advantages are that the ethylene only needs to be in the molar majority (>50%) for the reaction to progress, excess isoparrafin does not need to be deliberately fed and recycled, and the process can tolerate mild impurities (0-10ppm sulfur, 0-10ppm oxygenate, 0-100ppm dienes and residual trace metals, which would poison metallocene catalysts). The patent uses a HCl co-catalyst.

The commercial rationale is justified thus: “There is a need for a process that can be applied to a mixed hydrocarbon stream containing ethylene to oligomerize ethylene into a high value hydrocarbon product using ionic liquid catalysts to obtain jet and diesel fuel and satisfy increasing market demand… By converting ethylene to jet fuel and diesel blending stock, a significant value uplifting is achieved”.

The technology has been demonstrated. For example, the patent describes a continuous test-run which achieved 77% yields of product, of which c69% are distillate-range (chart below). Fuel properties are described to be excellent: 48-57 cetane number, -76F freeze point/cloud point and negligible sulphur content.

It may be interesting to explore with the company whether Chevron plans to deploy this technology, integrating around its shale portfolio.

An important principle is also illustrated for the ascent of shale: Technical solutions are under development to absorb shale’s light product slate, without permanently distorting downstream markets.

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Conclusions and Further Work?

Shale’s light product slate may create opportunities for integrated companies. Chevron’s ethylene-to-diesel patents are one example. But we have also seen a surprising uptick among other Oil Majors in patent filings for GTL, for oxidative coupling of methane and for a process to convert C3-4s into gasoline and diesel range molecules.

Our positive outlook on shale is best illustrated by our deep-dive note, Winner Takes All, but also be recent work focusing on the emerging opportunities with Fibre-Optic Sensing and Shale-EOR.

Can we help? If you would like to register any interest in the topics above, to guide our further work, then please don’t hesitate to contact us.

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Shell drives LNG in transport?

Shell in driving new LNG demand

Shell is the leading Major in driving new LNG demand, based on patent filings (chart above). As an example, we highlight a leading new technology to promote LNG demand in transportation, by mitigating the problem of boil-off.

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What is limiting LNG in transport?

LNG’s potential upside in transportation is exciting, particularly in shipping, as technologies improve and new sulphur regulation sweeps through the maritime industry (chart below, for full details see our deep-dive note, LNG in Transport: Scaling Up by Scaling Down). But challenges must also be acknowledged.

Most prominent is boil-off of LNG, which inhibits its storage over long time-frames. Boil-off typically runs at 0.15% per day, in a large, 25,000m3 tank, which means that c15% of the cargo would be lost over a 100-day period. For smaller-scale LNG, the rate is steeper, averaging c0.45% per day for a 2,500m3 tank, which in turn would cost c35% of the cargo over a 100-day period (chart below). In extremis, 1% per day boil-off is not unheard of.

Managing boil-off requires a vapor management system. Otherwise, as liquid evaporates into gas, the pressure exerted gradually rises, and eventually there is risk of exceeding the tank’s design pressure. This one one reason for the additional costs of converting a vessel to run on LNG, which can reach $17-35M for the largest tankers.

Gas Weathering is another challenge, less well-known, but crucially important. LNG is a mixture of hydrocarbon gases, all with different boiling points. Lower boiling-point components vaporize more readily. Hence over time, the higher boiling point constituents become more concentrated in the fuel tank, lowering the “methane number” of the fuel (chart below). This causes challenges. Most engine makers specify methane must comprise >80% of the fuel in a gas-fired engine. Below this level, the engine performs sub-optimally, knocking, misfiring, over-heating and potentially damaging components such as piston crowns and exhaust valves.

Shell’s improvements: a sub-cooler

To support LNG’s ascent in transportation, Shell has been the most active Major in developing new technologies. We will be elaborate further, in our upcoming research. But in 2019, one patent stands out, as the company has developed a new ‘sub-cooler’ (pictured below), to met the challenges described above.

The sub-cooler (44) is fluidly connected to the LNG storage tank (42) on a LNG-powered vessel. The tank’s temperature is continually monitored. When it exceeds a predetermined upper threshold, by say 0.25C, a small volume of LNG is pumped out (through 112) , sub-cooled (in 44) then sprayed back into the tank’s vapor space (via 114), until the tank is cooled back below a lower threshold, say, 1C below methane’s boiling point.

The invention’s equipment includes a compressor, a turbine, two heat-exchangers and use of the Brayton Cycle, most likely Air Liquide’s Turbo-Brayton refrigeration cycle using Nitrogen and/or Helium. Its advantage is reliability and low maintenance, which matter for long voyages.

Eight Advantages are Cited

  • Storage capacity is increased by providing constant and continuous vapor management, using the sub-cooling system.

  • Weathering is prevented, by sub-cooling and recycling liquefied gas, thus preserving the composition of the liquefied gas.

  • Fuel economy is thus maximised by avoiding the sub-optimal fuel-consumption caused by weathering. Shell states “Utilization of this system on gas fueled vessels will also allow for greenhouse gas emissions to be optimized”.

  • Longer journeys are thereby made more feasible.

  • Capex is saved. By employing Shell’s sub-cooler, no auxiliary consumer is required, lowering the cost of the system, potentially elminating GVU units, control valves, double wall piping, and labor and installation costs.

  • Opex may improve, due to better fuel economy, and as a larger range of input fuels can be used,

  • Safety is improved during transfer of LNG from a discharging tank to a receiving tank, providing the ability to lower temperature to 0.5-3C below the gas’s boiling temperature and “thereby limit flashing in the receiving tank during transfer”.

  • Versatility. The system can be installed in new LNG-powered vessels, new conversion of diesel vessels or retro-fitted onto existing LNG vessels. It can also be deployed in a broad range of LNG-transportation concepts (the patent mentions cruise ships, tankers, container vessels, ferries, barges, tugs… and more exotically, rail, truck, car and even planes!).

Economic Impacts to spur the ascent of gas?

The improvements above may stoke the ascent of LNG for shipping, where we are most positive with 40-60MTpa of upside seen to LNG demand after 2040 (see LNG in Transport: Scaling Up by Scaling Down).

Small-scale liquefaction for shipping is already going to be highly economical after IMO 2020, while bunkered LNG can be rendered as economic if it can harness economies of scale (model here).

The most attractive vessels to convert to run on LNG are cruisers and large container ships (data-file here).

Economics are currently more challenging for LNG trucks (model here). However, this is due to 2.5x higher vehicle costs and 2x higher maintenance costs per mile. But technical progress such as Shell’s will help.

Source: Hutchins, W. R. & Hartman, S. J. S. (2019). Liquid Fuel Gas System and Method. Royal Dutch Shell Patent US2019024847

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Greenfield LNG: Does Exxon have an edge?

Exxonmobil greenfield LNG

For large-scale capital projects in a commodity industry, harnessing better technologies tends to unlock better returns. Hence in this 7-page note we evaluate ExxonMobil greenfield LNG plant construction technology, particularly in remote geographies.

Its technical leadership is clear in our analysis of 3,000 patents across the industry. This matters as Exxon progresses new LNG investments in Mozambique, PNG and the US.

Opportunities should arise for investors in Exxon’s LNG projects, and for its partners, resource-owners and other stakeholders to maximise value.

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Lost in the Forest?

co2 sequestered by forests

In 2019, Shell pledged $300M of new investment into forestry. TOTAL, BP and Eni are also pursuing similar schemes. But can they move the needle for CO2? In order to answer this question, we have tabulated our ‘top five’ facts about forestry. We think Oil Majors may drive the energy transition most effectively via developing better energy technologies in their portfolios.

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(1). Forests should sequester 5T of CO2 per acre per annum, which is the average figure in half-a-dozen technical papers that we reviewed. However, the rates in these studies vary from 1-25 Tons per acre per annum, depending upon the species, the latitude and the rate of harvesting. Forests grow fastest in their early stages, and so paradoxically, to maximise CO2 sequestration, it may be necessary to cut them down periodically (and then re-plant).

(2). The world emits 1T of CO2 per acre per annum, which means that for forestry to absorb all of the world’s CO2 emissions, an incremental 20% of the world’s land mass must be given over to planting new forests. An extremely high number. Global carbon emissions run at 34bn tons per annum, while the world’s total land area is 37bn acres (c150M sq km).

(3). It matters where you plant. The chart above also shows a problematic skew in the world’s carbon emissions. If developed Asian countries (Japan, Korea, Singapore) wanted to offset all of their emissions by planing forests, they would need to access land areas that are c3.5x larger than their entire territories. Likewise, India and China would need to access areas equivalent to 60-80% of their own borders. To move the needle, large new forests would need to be planted in the countries on the right hand side of the chart. For the full data series, please download our data-file.

There are select opportunities in the mix, which Oil Majors can pursue. Perhaps the largest come from irrigating and afforesting desert areas. Not only are these areas large, but forests in hot areas have a tendency to grow more quickly and release more moisture, which in turn seeds clouds, which in turn reflects more sunlight and cools the planet.

(4). Environmental question marks? Forests clearly sequester CO2, but the precise climate science is surprisingly complex. Leaves absorb more sunlight than other types of land cover, increasing albedo, and warming the planet mildly. Trees can also release compounds called isoprenes, which reacts with nitrogen oxides in the air to form ozone (a greenhouse gas), while lengthening the lifespan of atmospheric methane (another greenhouse gas). Similarly, trees in tropical forests can seem to act as a conduit for soil to convey methane into the atmosphere. This deepens the need for “the right kind” of forestry investment, based on science.

(5). Capital may be better spent elsewhere? Most of the estimates we have encountered point to $20-100/ton of costs for sequestering CO2 using forests. This is competitive with other current forms of CCS (chart below, data here). However, we are also researching next-generation carbon capture technologies, which are much more competitive, below $20/ton.

To illustrate the same point another way, photosynthesis’s energy efficiency is around 0.5-1%, compared to today’s solar cells at c17% and next-generation perovskites reaching c35% (chart below). So ramping up next-genration solar could yield greater decarbonisation per unit of land area.

While we think Majors have a deep role to play in driving the energy transition, it will most likely be though game-changing technologies, which also unlock multi-billion dollar economic opportunities, per our recent note here.

References

Caldecott, B., Lomax, B. & Workman, M., (2015). Stranded Carbon Assets and Negative Emissions Technologies Working Paper. Stranded Assets Programme.

Gorte, R. (2009). U.S. Tree Planting for Carbon Sequestration. Congressional Research Service

Lenton, T.M., 2010. The potential for land-based biological CO2 removal to lower future atmospheric CO2 concentration. Carbon Management 1(1), 145–160.

Lewandrowski, J., Peters, M. & Jones, C. (2004). Economics of Sequestering Carbon in the U.S. Agricultural Sector, USDA Economic Research Service, Technical Bulletin TB-1909

Popkin, G., (2019). How much can forests fight climate change? Nature 565, 280-282

U.S. Environmental Protection Agency (2005). Greenhouse Gas Mitigation Potential in U.S. forestry and Agriculture, EPA 430-R-05-006, Washington, DC.

BP (2019). BP Statistical Review of World Energy

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Good Batteries vs Bad Batteries?

Battery efficiencies

We define a “good battery” as one that enhances the efficiency of the total energy system. Conversely, a “bad battery” diminishes it. This distinction matters and must not be overlooked in the world’s quest for cleaner energy. Electric Vehicles are most favoured, while grid-scale hydrogen is questioned.

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As renewable energy ramps up into the global energy mix (chart below, model here), the energy system will grow increasingly intermittent. This is unavoidable, because sunshine and wind speeds vary, and these variations are correlated over wide geographic areas.

Hence, batteries will be needed, to store up excess renewable generation for when the sun is not shining and the wind is not blowing. Most commentary on batteries focuses on their costs. But there is also an enormous opportunity in their efficiency…

Designed correctly, batteries can improve the efficiency of the global energy system, and accelerate the energy transition by lowering the total amount of energy that needs to be generated. Designed incorrectly, however, these variables are all worsened. The distinction is the topic of today’s note.

To make our distinction clearer, we have created a new data-file estimating the “net round trip efficiency” of different battery types. The calculation has two steps:

  • First, we measure the energy efficiency of an energy storage system (kWh given out divided by kWh put in).

  • Second, the storage system’s energy efficiency is compared with the most likely energy source that storage system will displace.

Interpretation. A score over 100% indicates a “good battery”. It is more efficient than the energy source displaced. A score below 100% indicates a “bad battery”. It is less efficient than the energy source displaced.

Examples to illustrate good vs bad batteries

Electric cars are our top example of a “good battery”, with potential to uplift energy efficiency by 3.5x. This is because electric vehicles achieve c60-80% energy efficiencies. An electric vehicle, in turn, is most likely to displace an internal combustion engine, which typically achieves 15-20% energy efficiency (chart below, model here). Mop up c100 units of excess renewable energy with an electric vehicle battery, and it therefore displaces the equivalent of 350 units of oil-energy.

The same 3.5x uplift applies to the battery in an ‘aerial vehicle‘, as we recently reviewed in depth, with flying cars set to achieve the equivalent of 140mpg (chart below).

Grid-scale batteries can also achieve impressive uplifts in efficiency, when inefficient fuel use is displaced. As a general rule of thumb, a power plant might be c50% efficient, hence replacing the power plant with renewables plus batteries can achieve a c2x efficiency uplift.

Additional opportunities are emerging to uplift system efficiency using batteries. One recent example was described by ConocoPhillips, at the Darwin LNG plant, where the gas turbines have a “sweet spot” of maximum efficiency. Battery storage allows Conoco to avoid low-efficiency turbine usage, which will will cut emissions by 20%.

Demand shifting, in the middle of our chart, deserves special mention because it is practically free and can also arguably uplift efficiency by 1-2x. It constitutes moving demand to the times when electricity is flowing abundantly into the grid. Examples range from backups at data-centers to washer-driers in homes. The practice can be encouraged by variable electricity prices, incentivising consumption when electricity supply is abundant and disincentivising consumption at times when it is scarce.

Now we arrive at the right-hand-side of our graph, where we are more cautious. Many commentators have proposed using hydrogen, molten salt or photo-electro-chemical cells as storage mechanisms, to absorb excess renewable power, for later usage…

We calculate that these “batteries” have c35-40% round-trip efficiencies: i.e., one third of the energy is lost to “charge” the battery (e.g., hydrolysing water) and another third is lost discharging it (e.g., burning hydrogen). Mop up 100 units of of renewable energy with one of these “bad batteries” and only c35-40 units can be recovered later. This means the world’s installed renewable capacity achieves less decarbonisation.

Decision-makers may wish to consider system efficiency in these terms, to maximise the impacts of both their renewable and battery investments. Efficiency and economics tend to overlap in all the models we have built.

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LNG Ships: a new record-setter?

LNG-powered ship

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 demand in 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…

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Digital Deflation: How Hard to Save $1/boe?

digital deflation

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).

Offshore-Digitization-Savings.-Cognite-Case-Study.Download

(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.

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Perovskites: Lord of Light?

Perovskite Efficiency Gains

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).

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IMO 2020. Fast Resolution or Slow Resolution?

IMO 2020 sulphur regulations

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 

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