This data-file tracks the construction progress of 30 FPSOsthat are being deployed in the Brazilian pre-salt oil province. In each case, we quantify the vessel’s oil and gas handling capacity, development timing and recent news.
We also compare the FPSOs’ gas-handling capacity with regional pipeline capacity. There will only be room to monetize one-third of the pre-salt’s produced gas volumes by the mid-2020s. The rest must be re-injected (chart below).
This data-file tracks the Lula oilfield, well-by-well, FPSO-by-FPSO, aggregating data from over 100 production reports, which are published monthly by Brazil’s national hydrocarbon regulator.
Hence we have formulated “production forecasts” for each FPSO, and for the entire field; in 2H19 and in 1H20. This matters for oil markets; and for pre-salt producers, such as Petrobas, Shell and Galp.
Our outlook is for slowing growth, due to rising water- and gas-cuts, which are reviewed well-by-well. One FPSO is now definitively constrained by gas-handling capacity. Another is off-plateau due to maturity. Six Lula FPSOs are now negotiating water-cuts, as shown in the data-file.
1H19 production was lower than expected, at just 72% of total installed FPSO capacity. Our notes attribute the drivers, and contextualise the growth ahead.
TOTALis currently pioneering the greatest advances in plastic-recycling technologies among the Majors, based on our database of 3,000 patents.
This data-filecovers the comprehensive mixing of chromium-catalysed polyethylene, to reduce defects and increase the strength of post-consumer resins. In turn, this extends their use to films, containers and pipes.
Four different measures of defectrates are correlated with four different extrusion methodologies.
The filealso includes a summary of TOTAL’s plastic recycling patents. Overall it should be possible to uplift plastic recycling margins by $50-100/ton.
Production optimisation can uplift mature fields’ output by 5-20%, varying production rates, chokes, pump-rates and EOR strategies, well-by-well across a field. It’s another way to stave off decline rates. But how?
This data-file summarises the methodologyemployed by BP, based on the most detailed patent we have seen on the topic, in our screen of 3,000 patents across the industry. BP is a leader in this area. Having digitised most of its operated assets, production optimisation comes next.
The typical challenge across the industry, is that as many as 20-30 changes may be required to optimise a large field, which is time-intensive for engineers to perform manually, hard-to-prioritise, hard-to-sequence and prone to errors that might defy operational constraints on individual wells.
BP’s system iteratesthrough potential changes, selects the most promising candidates, validates that they comply with operating constraints, and shifts production to an optimal state (chart above).
This data-fileincludes our summary of BP’s patent, schematics for its implementation, data behind our chart above and a ranking of BP’s “digital technology” versus other Majors that we have assessed.
Advanced reservoir modelling can stave off production declinesat complex offshore assets. This data-file illustrates how, tabulating production estimates based on a technical paper published by Eni, an industry leader in applying high-speed computing power in its upstream operations.
Specifically, the paper simulates an offshore field-cluster in a single, Integrated Asset Model that covers 31 wells, drilled into 3 reservoirs (each is modelled in detail, with a total of 1.9M reservoir cells), 34 pipes, 4 oil platforms and 3 delivery points. Each iteration of this model takes an average of 3.5-hours to run.
Production can be uplifted by 60% according to the simulation, both in terms of EUR and in terms of year 5-7 production rate. 9pp of the uplift is achieved by simple reservoir optimisation. Another 21pp of uplift is achieved by identifying the key bottleneck, and building a new separation & boosting platform to alleviate it. A further 29pp of uplift comes from optimising the development plan for the new platform.
Emerging digital technologies appear to be keeping LT oil-markets better supplied than many expect, with production upside for the industry’s technology-leaders.
Equinor is deploying three world-class technologies to mitigate Johan Sverdrup’s decline rates, based on reviewing c115 of the company’s patents and dozens of technical papers. This 15-page note outlines how its efforts may unlock an incremental $3-5bn of value from the field, as production surprises to the upside.
We have modelled the economics of Equinor’s Johan Sverdrup oilfield, using public disclosures and own estimates. Our model spans >250 lines of inputs and outputs, so you can flex key assumptions, such as oil prices, gas prices, production profiles and costs. In particular, we have tested the impact of different decline rates and recovery factors on the field’s ultimate value.
Technology leadership determines offshore capex. Specifically, this data-file measures a -88% correlation coefficient between different Major’s offshore patent filings in 2018 and their projects’ capex costs.
The details: We have tabulated the number of Offshore Patents filed in 2018, across 25 leading Majors, from our sample of 3,000 patents. We have also tabulated a dozen, recent, offshore greenfields operated by these companies, which were sanctioned in 2017-19. Investments from Aramco, BP, Equinor, Exxon, Petrobras, TOTAL and Shell are included.
The lowest-cost projects are not “easy oil”. The most economical project in the entire sample, at $17M/kboed, has a complex gas cap with a risk of asphaltene precipitation. Also in the ‘Top 5’ are an Arctic greenfield, an ultra-deepwater carbonate with unusually high-CO2 and an ultra-high pressure deep-water field. Economical development depends on leading technology.
To see the projectsincluded in the analysis, please download the data-file…