Forests can offset 15bn ton of CO2 per year from 3bn global acres. But is there potential to afforest any of the worldโs 11bn acres of arid and semi-arid lands, by desalinating and distributing seawater? Our 18-page note answers this question. While the energy economics do not work in the most extreme deserts (e.g., the Sahara), $60-120/ton CO2 prices may be sufficient in semi-arid climates, while the best economics of all use waste water from oil and gas, such as in the Permian basin.
The opportunity and challenges for nature based solutions to climate change are outlined on pages 2-4, explaining the rationale for afforesting deserts.
Precedents for afforesting deserts, including detailed case studies from the Academic literature, are reviewed on pages 5-8.
Water requirements are quantified, based on data from 60 tree species and the forestry industry, on pages 9-10.
The energy economics of desalinating and piping water are presented on pages 11-12.
The challenges of afforestation in the most extreme desert environments are modelled on page 13, showing why it is almost impossible to grow forests in the Sahara. The CO2 costs of supplying sufficient water could exceed the CO2 absorbed by new trees.
Supplementing rainfall in marginal lands is a more compelling economic model (e.g., adding the equivalent of 100mm new rainfall to marginal lands with c300-400mm), as shown on page 14.
The best case we can find is to use Permian waste water. Costs of desalination could be lower than current costs of disposal, while Permian upstream operations on the reforested acreage could be made carbon neutral, per pages 16-17.
A short list of companies exposed to the theme is presented on page 18.
SuperMajorsโ shale developments are assumed to differ from E&Psโ mainly in their scale and access to capital. Superior technologies are rarely discussed. But new evidence is emerging. This 11-page note assesses 40 of Chevronโs shale patents from 2019, showing a vast array of data-driven technologies, to optimize every aspect of unconventionals.
Page 2 explains how we assessed Chevron’s shale patents, to identify technologies that could support guidance for 900kboed of Permian production by 2023.
Page 3 sets out Chevron’s technologies for shale exploration and appraisal, based on recent seismic patents.
Page 4 sets out Chevron’s technologies for shale drilling, based on recent patents, many of which are co-filed with Halliburton, around a specific innovation.
Pages 5-8 set out Chevron’s technologies for shale completions, through an array of sophisticated, proprietary and increasingly digital technologies. These will not only help in the Permian, but also in de-risking international basins.
Page 8 sets out Chevron’s potential edge in completion fluids. We are particularly excited by the promising results from field-tests of anionic surfactants.
Page 9 sets out Chevron’s data-driven flowback practices, including productivity gains from field tests in the Vaca Muerta.
Pages 10-11 set out Chevron’s technologies for upgrading NGLs into gasoline-, jet- and diesel-range products, using industry-leading ionic liquid catalysts.
Page 11 concludes with implications for the broader shale industry.
Shale growth has been slowing due to fears over the energy transition, as Permian upstream CO2 emissions reached a new high in 2019. We have disaggregated the CO2 across 14 causes. It could be eliminated by improved technologies and operations, making Permian production carbon neutral: uplifting NPVs by c$4-7/boe, re-attracting a vast wave of capital and growth. This 26-page note identifies the best opportunities.
Pages 2-5 show how fears over the energy transition have slowed down shale growth in 2019.
Pages 6-10 disaggregate the CO2 intensity of the Permian, by source and by operator, based on over a dozen models we have constructed.
Pages 11-15 argue why increased LNG development is the single greatest operational opportunity to reduce Permian CO2 intensity.
Pages 16-18 summarise advances in methane mitigation technologies and their impacts.
Pages 19-23 outline and quantify the best opportunities to lower CO2 from digital initiatives, renewables, lifting and logistics.
Pages 24-25 quantifies the sequestration potential from CO2-EOR, which could offset the remaining CO2 left after all the other initiatives above.
Our conclusion is to identify three top initiatives that companies and investors should favor. Industry leading companies are also suggested based on the patents and technical literature we have reviewed.
The key challenge for the US shale industry is to continue improving productivity per well, as illustrated repeatedly in our research. Hence, this short note reviews an advance in fracturing fluids, which has been patented by BP. Diverter compositions are optimised across successive pressurization cycles, to create dendritic fracture geometries, which will enhance stimulated rock volumes.
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BP has patented a novel regime of fracturing fluids,which can be deployed across multiple pressurization sequences in its shale completions. The first sequence contains permanent diverting agents, introduced to create bi-wing and large fractures, then flowed back. The second fluid contains temporary, near-field diverting agents, which will dissolve in situ, usually within 24-72 hours, to expand the fracture network. Similarly, the third fluid contains temporary, far-field diverting agents.
The purpose of this completion design is to create dendritic fracture geometries. The diverting agents prevent fracturing fluids from leaking into the formation, so that primary, then secondary, then tertiary fracture networks can be created independently, each improving reservoir fluid conductivity (chart below).
The approach is data-driven. The formation of new fractures, with increasingly dendritic geometries, can be inferred from a linear slope between instantaneous shut in pressures on successive pressurization cycles. The fracturing fluids’ composition is also said to be determined based on Instantaneous Shut in Pressures, in-situ stress calculations and flowback volumes.
The permanent diverting agents may comprise mesh proppant, walnut hulls, large grain size proppants or particulates, such as polylactic acid, benzoic acid flakes, rock salt, calcium carbonate pellets. Small mesh size is envisaged (40-70 to 100 mesh), with low concentrations (0-0.1 lb/gal) to mitigate the risk of screen-outs.
The temporary diverting agents are not specifically disclosed in the patent, but are intended to dissolve in response to temperature, salinity, pH or other parameters. They may be pumped alongside proppant or standalone.
The patent is increasing evidence that Oil Majors are now innovating at the cutting edge of shale, in order to drive productivities higher. For a review of which companies screen as having the most advanced shale technologies, from the patent literature, please see our recent note, Patent Leaders.
Source: Montgomery, R., Hines, C. & Reyna, A. (2018). Hydraulic Fracturing Systems and Methods. BP Patent US2018202274
2019 has evoked resource fears in the shale industry. They are unfounded. Even as headline productivity weakened, underlying productivity continues improving at an exciting pace. These conclusions are substantiated by reviewing 350 technical papers, published by the shale industry in summer-2019. Major improvements are gathering momentum, in shale-EOR, machine learning techniques, digitalization and frac fluid chemistry.
Page 2 compares 2019’s shale performance to-date with our January forecasts, identifying that initial-month producutivity has been 20% weaker YoY.
Page 3-4 shows how continued productivity improvements matter, to unlock >20Mbpd of potential US shale output, plus $300bn of FCF by 2025 (at $50/bbl oil).
Pages 5-8 explain away the apparent degradation in resource productivity: it is a function of three alterations to completion designs.
Pages 9-12 outline 350 technical papers from the shale industry in summer-2019. They restore confidence: the industry is not facing systemic resource issues.
Page 12 covers 24 technical papers into “parent-child” issues. We were surprised by the number that were ‘negative’ versus the pragmatic solutions offered in others.
Page 13, 14 & 17 cover leading digitalization technologies: deployment of machine learning increased 5x YoY, while DAS/DTS increased 3x YoY in 2019.
Pages 14-16 cover the maturation of shale-EOR, which was the greatest YoY improvement, reaching 32 papers in 2019. The cutting-edge of EOR is exciting.
Page 18 outlines other technical highlights to drive future productivity higher.
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: โWe 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: โWhat 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: โWe 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.
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 oilby 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.
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: โThere 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.
Will Shale-EOR add another leg of unconventional upside? The topic jumped into the โTop 10โ most researched shale themes last year, hence we have reviewed the opportunity in depth. Stranded in-basin gas will improve the economics to c20% IRRs (at $50 oil). Production per well can rise by 1.5-2x. The theme could add 2.5Mbpd to 2025 output.
Pages 3-5 review the theory of shale EOR. Its recovery factors could in principle surpass conventional EOR.
Pages 6-7 review lab results and field trials. They have been promising, suggesting >1.5-2x production uplifts should be attainable.
Pages 8-10 review the economics in detail. Our full model is informed by technical papers, and can be downloaded here.
Page 11 tabulates key statistics for using CO2 as a huff-n-puff injectant, the economic opportunities for carbon capture, but also the challenges.
Pages 12-13 attempt to quantify the production upside from shale EOR, by adapting our basin models.
Pages 14-15 cover the remaining challenges, including E&P patent-filing insights.
Page 16 lists a handful of companiesat the forefront of shale-EOR, including some earlier-stage start-ups.
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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