Category: Commentary

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Do refineries become bio-refineries?

Refineries become bio-refineries

What will happen to oil refineries during the energy transition? On our numbers, liquid oil products will be needed past 2100, long after demand plateaus in the 2020s. Cleaner, more efficient technologies are therefore required in the downstream sector. This note considers whether refineries could increasingly be converted to bio-refineries.

Refineries become bio-refineries

Our evidence comes from the patent literature, as we have reviewed 3,000 patents from the leading 25 Energy Majors. 8% are focused on new energies (chart below, full details in our deep-dive note). Eni screens as the leader for converting refineries to bio-refineries, hence this note summarises its relevant patents on the topic.

Refineries become bio-refineries

Historical Context. Use of vegetable oils in diesel engines goes back to Rudolf Diesel, who, in 1900, ran an engine on peanut oil. Palm oil and peanut oil were both used as military diesel in Africa in WWII. However, vegetable fuels were abandoned due to high costs and inconsistent quality, compared with petroleum fuels.

Today’s vegetable oil fuel-blending components primarily contain Fatty Acid Methyl Esters (FAME). However, they cannot be blended beyond c7% without causing problems in auto engines. For example, FAME has a low energy content (38kJ/kg vs diesel at 45kJ/kg), a -5 โ€“ 15C cloud point, causes pollution in tanks, polymerises to form rubbers, causes fouling, dirties filters and contaminates lubricants.

Regulation is nevertheless stoking demand for more dio-diesel, going beyond the 7% threshold. Europe Directive 2009/28/C mandates 10% renewable material in diesel by 2020, up from 5% in 2014.

Eni is therefore converting refineries to bio-refineries, to upgrade renewable materials into “green diesel”. A 0.36MTpa facility started up at Porto Marghera, Venice in 2014. A larger, 0.7MTpa facility started at Gela in 2019. Both convert vegetable oils into diesel.

Patents indicate how they work. The starting point is a conventional oil refinery, with two sequential hydro-desulfurization units. For the conversion into a bio-refinery. these units are re-vamped into a hydrodeoxygenation reactor (HDO) and a subsequent hydro-isomerization reactor (ISO), shown in the schematic below.

  • HDO occurs in the presence of hydrogen, a sulfided hydrogenation catalyst from Group VIII or VIB metals, at 25-70 bar and 240-450C.
  • ISO occurs at 250-450C, 25-70bar and a Metal (Pt, Pd, Ni) Acid catalyst on an alumino-silica zeolite framework.
  • Upstream modifications. Pre-treatment processes, surge drums and heat-exchangers are installed upstream of each reactor.
  • Downstream modifications. The output products from the reactors will contain 1-5% H2S, which is removed in an acid gas treatment unit, and then a Claus unit for sulphur recovery; both reached via new connection lines.
Refineries become bio-refineries

The main advantage of this process is cost, which is said to be 80% lower than constructing a new facility. For example, the Porto Marghera project was budgeted at โ‚ฌ200M. In its patents, Eni states: “This method is of particular interest within the current economic context which envisages a reduction in the demand for oil products and refinery marginsโ€.

Further advantages are that the produced diesel has excellent properties, including a high octane index, optimum cold properties, high calorific value and a further by-product stream of commercial LPGs. Moreover, the efficiency of the converted facility is seen to be similar to one constructed anew.

The disadvantage is that blending of free fatty acids is limited to c20%. This is why the bio-refineries so far intake 80% palm oil (which contain <0.1% free fatty acids). Eni states: โ€œThe reactor used for effecting the HDO step, deriving, through the method of the present invention, from a pre-existing hydrodesulfurization unit, may not have a metallurgy suitable for guaranteeing its use in the presence of high concentrations of free fatty acids in the feedstock consisting of a mixture of vegetable oils. The reactors of the HDO/ISO units specifically constructed for this purpose, are in fact made of stainless steel (316 SS, 317 SS), to allow them to treat contents of free fatty acids of up to 20% by weight of the feedstockโ€. Processing a broader range of vegetable oils and other waste oils would require a more costly refinery re-vamp.

Further challenges are that the production of hydrogen and other industrial above will be energy intensive. Moreover, Eni’s 1MTpa of green diesel production capacity is only equivalent to c20kbpd of fuel. It will be challenging to source sufficient feedstocks to scale bio-refineries up to meet larger portions of the world’s overall fuel needs.

Our conclusion is therefore that bio-refineries have potential when re-purposing existing downstream facilities, preserving value in the very long-term future of the industry. However, further technological improvements are required before these facilities can scale up or deliver material, and truly decarbonised hydrocarbons. Out of Eni’s other refining patents, we are most positive on Eni Slurry Technology, which is a leading technology for IMO2020 (chart below). For details of other technology leaders in energy, please see our note, Patent Leaders.

Refineries become bio-refineries

Source: Rispoli, G., F. & Prati, C. (2018). Method for Re-Vamping a Conventional Mineral Oils Refinery to a Bio-Refinery. US Patent US2018079967.

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The Ascent of LNG?

LNG demand the bull case

Gas demand could treble by 2050, gaining traction not just as the world’s cleanest fossil fuel, but also the most economical. The ascent would be driven by technology. Hence this note outlines 200MTpa of potential upside to consensus LNG demand, via de-carbonised power and shipping fuels. LNG demand could thus compound at 8% pa to 800MTpa by 2030, justifying greater investment in unsanctioned LNG projects.

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Consensus LNG demand?

A simple model of global LNG demand is shown below (and downloadable here). It is created by extrapolating recent trends in key LNG-consuming regions. The total market grew at 5.7% pa in 2013-18. At a 5.4% forward CAGR, it would reach c570MTpa by 2030. These numbers are not far from other LNG forecasters’, and thus serve as a reasonable consensus.

What excites us is the potential for technology to accelerate LNG demand. Markets are slow to reflect technological breakthroughs. Hence these new demand sources likely do not feature in consensus forecasts yet. In our view, this makes them worthy of attention.

Upside from De-Carbonised Power Generation?

The first opportunity is in de-carbonised power generation, as we have discussed in our deep-dive report, ‘de-carbonising carbon‘. We think novel technologies are reaching maturity, which can generate cost-competitive electricity (chart below) alongside an exhaust stream of pure CO2, for use in industry or for immediate sequestration. The full details are in our report.

Let us now make some approximate calculations: The world consumes 7.7bn tons of coal per annum. In energy terms, this is equivalent to c165TCF of gas, or 3,300MTpa of LNG. We believe it would be economic, and achievable, to convert c5% of this coal power to gas by 2030. Converting it to decarbonised gas could save c1bn tons of CO2 emissions per annum. In turn, this could be achieved by 200GW of de-carbonised gas-power, in 500 x 400MW power plants, each burning c50mmcfd of input gas, fed by 165MTpa of LNG. This is the first area where technology can greatly accelerate LNG demand.

Upside in Shipping?

The second opportunity is in LNG as a shipping fuel, which will become increasingly economical after IMO 2020 sulphur regulations re-shape the marine sector. The economics are shown below and modelled here.

New technologies in small-scale LNG will accelerate adoption in smaller ports, moving beyond the large port-sizes required for bunkering. The technologies and economics are explored in detail, in our deep-dive note, LNG in Transport. The economics are modeled here. To assist, Shell is also pioneering new solutions for LNG in transport.

The upshot could be 40MTpa of incremental LNG demand in the maritime industry by 2030. This is the second area where technology can greatly accelerate LNG demand.

Less positive on trucking

Is there further upside? One might expect, in an overview of LNG technologies, to find incremental upside in road vehicles: either directly in LNG-fired trucks, in gas-fired vehicles, or to produce hydrogen for fuel-cells. None of these opportunities are yet captured in our models.

The reason is economics. Compared to diesel-powered trucks, we find compressed natural gas to be c10% more expensive, LNG to be 30% more expensive and hydrogen to be around 4x more expensive (model here, chart below). We also find hydrogen to be 85% costlier than gasoline, to powers cars in Europe (model here). In most cases, electrification is the better option, as superior vehicle concepts emerge.

Our numbers do not include any incremental LNG demand in the road-transportation sector. However, it is noteworthy that replacing 1Mbpd, or c2% of the world’s road fuels with LNG would consume an incremental 50MTpa of LNG. This could cushion delays or shortfalls in decarbonised gas-power.

Potential supplies can meet the challenge.

It is only possible for the world to consume 800MT of LNG in 2030 if it is also possible to supply 800MT. While our risked forecasts are for c600MT of LNG supply in 2030 (chart below), our numbers are including just c60% of the 230MTpa of LNG capacity that is currently in the design phase, and just 15% of the 180MTpa that is currently in the discussion phase. In a generous scenario, our forecasts rise close to the 800MTpa level that is required. Please download our risked, LNG supply model to see our scenarios, and the LNG projects included.

LNG technology could thus unlock incremental LNG facilities. We are most positive on low-cost, low-CO2 sources of gas, particularly in stable and low-tax countries. To help assess the potential, we have therefore compiled a data-file of the world’s great gas resources and their CO2 content, downloadable here. Our positive outlook on US LNG is further underpinned by our positive outlook on US shale.

Conclusions: path dependency?

The numbers above are not hard forecasts. We do not believe hard forecasts are possible in a market that is shaped by unpredictable geopolitics, technologies, weather and its own price-reflexivity. However, we have argued that new technologies may unlock materially more LNG demand than is currently embedded in consensus expectations. Leading companies with leading LNG projects may benefit.

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CO2-EOR in shale: the holy grail?

CO2-EOR in shale

What if there were a technology to sequester CO2, double shale productivity, earn 15-30% IRRs and it was on the cusp of commercialization? Promising momentum is building, at the nexus of decarbonised gas-power and Permian CO2-EOR…

First, this week, we finished reviewing 350 technical papers from the shale industry’s 2019 URTEC conference. The biggest YoY delta is that publications into EOR rose 2.3x. CO2-EOR is favored (chart below). Further insights from the technical literature will follow in a detailed publication, but importantly we do not see underlying productivity growth in shale to be slowing.

Second, we re-read Occidental Petroleum’s 2Q19 conference call. More vocally than ever before, Oxy hinted it could take the pure CO2 from decarbonised power plants and use it for Permian-EOR; with its equity interest in NetPower, 1.6M net Permian acres, and leading CO2-EOR technology. Quotes from the call are below:

  • On CO2-EOR: โ€œWe are investing in technologies that will not only lower our cost of CO2 for enhanced oil recovery in our Permian conventional reservoirs, but will also bring forward the application of CO2 enhanced oil recovery to shales across the Permian, D.J. and Powder River basins”
  • On decarbonised gas power: โ€œWhat it does is, it takes natural gas combines that with oxygen and burns it together, and that’s what creates electricity and it creates that electricity at lower costs… one of our solutions is to put that in the Permian… for use in our enhanced oil recovery… It will utilize our gas that that if we sold it would make nearly as much”.
  • On the opportunity: โ€œWe are getting calls from all over the world, with people wanting our help to — figure out how to capture CO2 from industrial sources, and then what to do with it and oil reservoirs”.

Our extensive work on these themes includes two deep-dive reports linked above. Our underlying models can connect c10% IRRs on oxy-combustion gas plants (first chart below) with 15-30% IRRs at Permian CO2-EOR (second chart below). On these numbers, the overall NPV10 of an integrated system could surpass $10bn.

EOR remains one of the most exciting avenues to boost Permian production potential. So far, our shale forecasts assume little direct benefit (chart below). But an indirect benefit is implicit, as we assume 10% annualized productivity growth to 2025, which would underpin a very strong ramp-up (chart below). 2023-25 currently look well-supplied in our oil market model, due to falling decline rates, but this could be compounded by CO2-EOR.

We are more positive on the ascent of gas, stoked by increasing usage in decarbonised power. We see potential for gas demand to treble by 2050.

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Does Technology Drive Returns?

Technology return on capital

Technology drives 30-60% of energy companies’ return on capital. This is our conclusion after correlating 10 energy companies’ ROACEs against 3,000 patent filings. Above average technologies are necessary to generate above-average returns.

For the first time, we have been able to test the relationship between oil companies’ technical abilities and their Returns on Average Capital Employed (ROACE).

In the past, technical capabilities have been difficult to quantify, hence this crucial dimension has been overlooked by economic analysis in the energy sector.

Our new methodology stems from our database of 3,043 patents, filed by the Top 25 leading energy companies in 2018. The data cover upstream, downstream, chemicals and new energy technologies (chart below) . All the patents are further summarised, “scored” and classed across 40 sub-categories.

The methodology is to correlate our patent-scores for each company with the ROACE generated by the company in 2018. We ran these correlations at both the corporate level and the segment level…

Results: patent filings predict returns

Patent filings predict corporate returns. In 2018, the average of the Top 10 Integrated Oil Majors generated a Return on Average Capital Employed (ROACE) of 11%, based on our adjusted, apples-to-apples calculation methodology. These returns are 54% correlated with the number of patents filed by each Major (chart below).

Technology leaders are implied to earn c5% higher corporate returns than those deploying industry-average technologies, which is a factor of 2x.

Upstream patent filings also predict upstream returns, with an 85% correlation coefficient. The data are skewed by one Middle East NOC, which earns exceptionally high returns on capital, but even excluding this datapoint, the correlation coefficient is 65% (chart below).

The curve is relatively flat, with the exception of two outliers, implying that it is hardest to improve general upstream returns using technology. This may be because upstream portfolios are vast, spanning many different asset-types and geographies.

Downstream patent filings predict downstream returns, with an 80% correlation coefficient (chart below). However, our sample size is smaller, as we were unable to dis-aggregate downstream ROACE for all the Majors.

The curve is very steep, indicating that downstream technology leaders can surpass c20% returns on capital, versus c10% using industry-standard technologies.

Chemical patent filings predict chemical returns, with a 57% correlation coefficient (chart below). Again, our sample size is smaller, as we could only estimate chemicals ROACEs for some of the Majors.

The curve is also steep, with technology leaders earning c10-20% returns, versus low single digit returns for less differentiated players.

Overall, the results should matter for investors in the energy sector, for capital allocation within corporates, and for weighing up the benefits of in-house R&D. We would be delighted to discuss the underlying data with you in more detail.

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New Risers for pre-salt Brazil?

next-generation riser designs for pre-salt Brazil

Petrobras has patented next-generation riser designs, to handle sour-service crude from pre-salt Brazil. This is needed after prior cases of riser-failure, e.g., at Lula. Its new solution could also support development of higher-CO2 fields, such as Libra. But complexity is an order of magnitude higher. A simpler alternative is the growing potential from thermo-plastic composite pipe, which resists corrosion and is 45% more economical than conventional risers.

Pre-salt riser failures from CO2-corrosion

In 2017, Upstream Newspaper reported that Petrobras had suffered two riser failures, injecting high-CO2 gas back into the Lula and Sapinhoa reservoirs. The failures occurred after just 3-years, at risers designed to last for 25.

These failures were induced by stress-corrosion, which in turn derives from the high CO2 content in the pre-salt. For example, CO2 is reported at 8-12% at Lula.

As Petrobras moves to develop even higher-CO2 fields, such as Mero (Libra), where the gas is up to 30% CO2, it has also sought to minimise the use of flexible risers, to protect against corrosion.

New solutions… new challenges?

Improved riser solutions feature prominently in Petrobras’s 2018 patent filings, which we have reviewed. One patent localises the problem of stress-corrosion to the risers’ steel cladding, which is situated in the annulus between the riser’s barrier layer and outer sheath. The barrier layer can sometimes be breached by fluids moving through the riser.

Petrobras states:“Stress corrosion is caused by CO2 and not well-covered by international standards for flexible pipes...there is normally no way to displace gases from the annulus or minimise their corrosive effects”.

It is noted that Chevron, Schlumberger and GE have all patent solutions to detect the presence of corrosive fluids reaching the steel cladding of a riser. However, to mitigate this problem, comprehensively, in a flexible, deep-water riser with many segments, Petrobras has filed its own solution (chart below).

Inert fluids are envisaged to be swept through the annulus of the riser, removing any corrosive fluids that have accumulated. The fluid is forced through each independent segment of pipe. Leak tests can be performed to detect damaged sections.

Another argument for composites?

What strikes us about Petrobras’s solution is the added complexity. As pictured above, it will be necessary to maintain a flow of anti-corrosive fluids through each riser segment, via an additional series of injection pipes and return pipes. All of these must be fabricated, installed and maintained.

After weighing up the additional complexity of circulating anti-corrosive fluids through the cladding of flexible pipelines, we grow more positive on the relative simplicity of an alternative: themo-plastic composite risers (TCP).

These next-generation materials are corrosion-resistant, withstanding CO2 concentrations up to 50% and H2S up to 200ppm. They also deliver comparable strength to steel, at 10% of the weight, which simplifies their installation and lowers overall costs for a riser system by 45% (chart below).

For our data-file quantifying the progress-to-date and the costs of TCP, please see here.

Source: Carpigiani de Almeida, M., Cameiro Campello, G., Ribeiro, J., Mello Sobreira, R. G., Loureiro Junior, W. C. & Piza Paes, M. T. (2018). System and Method for Forced Circulation of Fluids Through the Annulus of a Flexible Pipe. Petrobras Patent 2018220361.

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De-Carbonising Cars. Can Oxy-Combustion Save Gasoline?

De-Carbonising Cars with oxy-combustion

We are positive on the opportunity to de-carbonise gas-fired power generation using next-generation combustion technologies, such as oxy-combustion, which is reviewed in our deep-dive note, ‘Decarbonising Carbon‘. Could the same technology be used in automobiles? It is more difficult. But the world’s largest oil company is nevertheless trying.

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Oxy-Combustion aims to obviate the challenging step of separating CO2 from exhaust gas by burning fuels in an atmosphere that has been purged of Nitrogen (e.g., pure oxygen and CO2). This means that the exhaust gas will comprise CO2 and H20 (i.e., no nitrogen). It can readily be de-hydrated and the CO2 can be sequestered.

(In thermodynamic terms, this requires using a mechanical cycle such as the Allam Cycle in lieu or the traditional Otto Cycle or Diesel Cycle).

This technology works. It is being trialled at three power facilities globally, to decarbonise heat and power. One very promising industry-leader is backed by Occidental. The opportunity of economically de-carbonising gas is extremely positive for global gas demand, as reflected in our own models (chart below, download here).

But could oxy-combustion be used to de-carbonise oil-fired transportation?

In our review of 3,000 patents around the industry, Saudi Aramco stands out as the company working hardest to reduce the emissions of oil-fired transportation. It published over a dozen novel vehicle designs last year (details available to ThunderSaid clients).

Almost all of its efforts aim to reduce the CO2 intensity of burning liquid fuels in auto-engines. Those using oxy-combustion go back to 2013. They have been filed in multiple geographies and updated repeatedly in 2019.

The rationale is to reduce emissions from mobile sources, which comprise 25% of global CO2 and to prevent the formation of NOXs by restricting Nitrogen from the engine. One patent states: โ€œSince pure or nearly pure 02 is combusted with the fuel, the resulting combustion product will constitute principally C02 and H20. The water can readily be condensed and separated to provide a pure, or nearly pure CO2 stream for densification and storage.โ€

The challenge with oxy-combustion is to purify the oxygen prior to combustion. Aramco’s approach is to achieve this task using electro-ceramic membranes, as commercialised by Ceramatech of Salt Lake City, Utah and Air Products. Aramco has also patented its own membrane cell designs (image below).

The drawback is that these membranes require high temperatures (700-800F). But Aramco’s patent notes this need not be problematic in an internal combustion engine, where c60% of the energy in fuels is converted into heat in to the engine, at 600-650C.

Thus a schematic of the proposed oxy-combustion engine is shown below, including a specially-enlarged air intake, and a membrane to separate N2 from O2.

Can Oxy-Combustion Vehicles be Commercialised?

Challenges of deploying oxy-combustion in a mobile vehicle are not overlooked by the patents.

(1) Space and weight limitations are more acute in a small, mobile vehicle than they are in a fixed power facility. Hence โ€œa major problem … is how to minimize the additional weight and space required by air separation componentsโ€ in, say, a car.

(2) Storing CO2 on board the mobile vehicle will be necessary, until it can be discharged at a disposal facility. This requires compression energy, to pressure the CO2 to 5-1,600kg/m3. There may be limited storage space. A network of CO2 disposal sites would also need to be developed alongside fuel retail stations.

(3) System stability. The electro-ceramic cells used to separate N2 and O2 have โ€œcapacity to produce high-purity O2 over thousands of hoursโ€. But it is not clear whether they will work under extreme temperature variations. The cells may also degrade over time, given the complex chemistry of the electro-ceramic cells: e.g., doped cerium oxide electrolyte, sintered lanthanum strontium cobalite electrodes covered with silver.

(4) System sufficiency. In some high-intensity conditions — hills, motorways — Aramco’s patents acknowledge it will still be necessary to introduce N2 to the engine, emitting NOXs and CO2.

(5) Competition with electric vehicles. Finally, the fundamental energy efficiency of combustion remains c20-30%, compared with 60-80% for electric vehicles (chart below, data here). Electric vehicles have an order-of-magnitude fewer parts, whereas oxy-combustion vehicles appear to have many more.

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We conclude there is strong potential to de-carbonise gas-fired power generation with next-generation combustion technologies. But de-carbonising oil-fired automobiles may be most readily accomplished by electrification, i.e., substituting in smaller, more-specialised electric alternatives.

Source: Hamad, E. Z. & Al-Sadat, W. I. (2013). Apparatus and Method for Oxy-Combustion of Fuels in Internal Combustion Engines. Saudi Aramco Patent WO2013142469A1.

Source 2: Ben-Mansour, H., Habib, M., Jamal, A. (2017). Gas-Assisted Liquid Fuel Oxygen Reactor. Saudi Aramco Patent US2017284661 

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Permian CO2-EOR: pushing the boundary?

Permian CO2-EOR

We see enormous opportunity from CO2-EOR in the Permian. It can double well productivity, generate 15-20% IRRs (at $50 oil) and uplift production potential from the basin by 2.5Mbpd. The mechanism and economics are covered in detail in our deep-dive note, Shale-EOR, Container Class.

But what is happening at the leading edge, as companies try to seize the opportunity?

To deploy CO2-EOR, operators must be confident in the technology. It must be predictable, with well-calibrated models informed by field-tests and laboratory studies.

Excitingly, Occidental Petroleum is developing such models. Its laboratory analysis into CO2-EOR has been published in a new SPE paper, in partnership with CoreLabs.

Oxy is at the forefront of CO2-EOR, according to our screening of patents and technical papers. It has conducted 4 x field trials, with further ambitions to lower decline rates from 2020 and drive value through its Anadarko acquisition.

This note profiles our top five findings from Oxy’s recent technical paper. CO2-EOR’s deployment is supported.

(1) CO2 was found to be “the best solvent” for huff’n’puff in the Permian, after laboratory-testing Wolfcamp cores, with CO2, methane and field gas. Under simulated reservoir conditions, around 3,600psi, bubbles of CO2 immediately began dissolving into the oil, helping to mobilise it.

(2) CO2 swelled the oil by 15-76% under the reservoir conditions tested in the study (below, right). Swollen oil is more likely to dissociate from the reservoir rock and flow into the well.

(3) Accurate ‘Equation of State’ models have been developed, matching the pressure, viscosity and well data from the laboratory study.

(4) Multiple Cycles. Huff’n’puff works by sequentially ‘huffing’ gas into a depleted shale well to entrain residual oil, then ‘puffing’ back the mixture of gas and oil. Ideally, this cycle can be repeated multiple times, recovering more oil each time (illustration below). Oxy’s laboratory study continued recovering material volumes of oil over six cycles. Lighter fractions were recovered in earlier cycles, followed by heavier fractions in later cycles. The authors concluded: “The multi-cycle incremental recovery โ€“ even at the small core plug scale โ€“ suggests the significant potential for multiple HnP EOR cycles for a future unconventional EOR project designโ€.

(5) Huge Recovery Factors. What slowed the eventual recovery of oil in the study was the high volume of oil already recovered. Initially, these shale samples contained 10.3% oil (as a percentage of the initial pore volume). By the end of the huff’n’puff trial, they contained just 2.4%, implying c77% of the oil had been drained: an incredibly high number, when compared with c 8-10% recovery factors in most analyst models. The result matches other lab tests we have seen in the technical literature (chart below). The field-scale implications of these studies are discussed in our deep-dive research.

Source: Liu, S., Sahni, V., Tan, J., Beckett, D. & Vo, T. (2019). Laboratory Investigation of EOR Techniques for Organic Rich Shales in the Permian Basin. SPE.

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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 โ€œrevolutionise food and package deliveries, offering people convenient new services that improve everyday lifeโ€ฆ instant delivery works around your schedule at much lower costsโ€.

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 ฮฑ-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: โ€œThere 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 achievedโ€.

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 tankโ€™s vapor space (via 114), until the tank is cooled back below a lower threshold, say, 1C below methaneโ€™s boiling point.

The inventionโ€™s equipment includes a compressor, a turbine, two heat-exchangers and use of the Brayton Cycle, most likely Air Liquideโ€™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 โ€œUtilization of this system on gas fueled vessels will also allow for greenhouse gas emissions to be optimizedโ€.
  • 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 gasโ€™s boiling temperature and โ€œthereby limit flashing in the receiving tank during transferโ€.
  • 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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