We have constructed a simple model to estimate the CO2 emissions of commercialising an oil resource, as a function of a dozen input variables: such as flaring, methane leakage, gravity, sulphur content, production processes and transportation to market.
We estimate energy return on energy invested is c7-10xacross the entire oil industry, including upstream, midstream and downstream.
Different resources are compared using our methodology. Relative advantages are seen for large, well-managed offshore oilfields and shale. Relative disadvantages are seen for heavy crudes (e.g., Oil Sands, Mexican Heavy) and producers with low regard for flaring and methane emissions (e.g., Iran, Iraq). However, gas production is lower CO2.
Download the modeland you can quickly compute approximate CO2 emissions for other resources.
This database tabulates c200 venture investmentsmade by 8 of the leading Oil Majors, as the energy industry advances and transitions.
The largest portionof activity is still aimed at incubating Upstream technologies (c40% of the investments), as might be expected.
But leading Majors are also building rapid capabilitiesin new energies (38%) and digital (36%), as the energy system evolves. We are impressed by the opportunities. Venturing is likely the right model to create most value.
The full databaseshows which topic areas are most actively targeted by venturing; including by company. We also chart which companies have gained stakes in the most interesting start-ups.
We have reviewed 42 of Shell’s GTL patent filings for 2018. They show continued progress, innovating new fuels, lubricants, renewable-heavy gasolines, waxes and detergents. Each patent is summarised and categorized in this data-file.
All of this begs the question whether there is a commercial rationale for a US replica of the Pearl GTL project, to handle the over-abundance of gas emanating from the Permian; and produce these advantaged products. It would also help reduce the risk of US LNG projects glutting the market.
We therefore model the economicsin this data-file, using prior project disclosures and our learnings from the patent history. Our base case IRR is 15%, taking in 1.6bcfd of shale gas. Resiliency is tested by varying oil and gas prices.
This data-file reviews 300 technical papers from 2018 and 350 technical papers from 2019. Hence, we can identify the cutting edge of shale technology. Each paper is summarised, categorized by topic, by country, by basin, by company and by ‘impact’.
The YoY trends in 2019 show an incredible uptick in EOR, machine learning and well spacing studies, which are fully reviewed in the file.
On our assessment, one third of the papers support material improvements in well-productivity. c98% are data-driven, including c39% using advanced computational modelling and another c20% using data to optimise operations.
The Permian hosted the most research, pulling further ahead of other basins. You may be surprised by the identities of the companies publishing the most technical papers in shale.
We have modelled the economics of CO2-EOR in shale, after interest in this topic spiked 2.3x YoY in the 2019 technical literature. Our deep-dive research into the topic is linked here.
The economics appear very positive, with a 15% IRR under our base case assumptions, and very plausible upside to 25-30%.
The model also allows you to stress-test your own assumptions such as: oil prices, gas prices, CO2 prices, CO2 tax-credits, compressor costs and productivity uplift. The impacts on IRR, NPV and FCF are visible.
This model contains our live, basin-by-basin shale forecasts. We model each of the Permian, Bakken and Eagle Ford, as a function of the rig count, drilling productivity, completion rate, well productivity and type curves. Thus, we derive production and financial expectations.
Our numbers hinge on the productivity gainsdescribed in our thematic research. Shale productivity trebled from 2012-2018. We think it can effectively double again by 2025. This would unleash 21Mbpd of US liquids production by 2025, within cash flow at a flat $50/bbl Brent input.
In 2019, the virtues of switching diesel-powered frac fleets to gas-powered electric have been extolled by companies such as EOG, Shell, Baker Hughes, Halliburton, Evolution and US Well Services.
The chief benefit is a material cost saving, quantified per well in this data-model, as a function of the frac fleet size, its upgrade costs, its fuel usage. diesel prices and gas prices.
Additional benefitsare also noted in the file, such as CO2 reductions, higher reliability, smaller pad sizes, NOX reductions and noise reductions. We also think over the long run, 200mmcfd of stranded Permian gas could be absorbed.