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Petroleum Geoscience


As introduced in a previous Seismic Tech-Notes article on Separated Wavefield Imaging [‘SWIM’], SWIM uses both the up-going pressure wavefield (‘P-UP’) and down-going pressure wavefield (‘P-DWN’) from the dual-sensor wavefield separation of GeoStreamer 3D data to fundamentally change the way that seismic migration can image the subsurface, the first 1 km or so below the surface in particular. Broadband and continuous seismic images all the way up to, and including, the seafloor seismic event—even in areas with very shallow water and where the 3D seismic surveys have towed a very large streamer spread to optimise survey efficiency. Every receiver from every streamer becomes a ‘virtual source’, thereby greatly extending the spatial extent of the migrated images, most famously mitigating the cross-line acquisition footprint associated with all 3D streamer surveys, notably those in shallow water, using large streamer spreads and with shallow targets of interest. A common vernacular has also been to describe SWIM as imaging ‘All orders of surface multiples’, which it does, but a better description is that ‘The complete seismic wavefield is being imaged’.

I discuss the power of SWIM to contribute to shallow velocity model building, imaging and interpretation below, building a platform to discuss seismic inversion and quantitative interpretation (QI) in a future article.

Shallow Velocity Model Building

Figure 1 compares shallow image gathers imaged from GeoStreamer data with Kirchhoff PSDM versus SWIM. Anyone familiar with seismic processing will understand that the fold on shallow arrival times/depths is always very small because of the combination of the 3D multi-streamer acquisition geometry and the outer trace mute applied in processing. In the worst case at the outer streamer locations for wide-tow geometry and/or shallow water areas there will in fact be zero fold for shallow depths and a very strong acquisition footprint will corrupt the shallow seismic data. The upper part of Figure 1 displays this well-known lack of shallow fold using Kirchhoff pre-stack depth migration (PSDM). Almost unbelievably, the lower part of Figure 1 illustrates how the introduction of P-DWN into a modified form of depth migration (SWIM) enables all offsets for all depths to contribute useful information using the same (GeoStreamer) survey data.

Whilst the events in the upper part of Figure 1 appear to be ‘flat’ and would satisfy a seismic processing expert picking velocities, anyone can see that it is very challenging trying to assess the ‘flatness’ of such short seismic events. In contrast, every event in the lower part of Figure 1 enables a very accurate assessment of the offset-dependent quality of the velocity model at all two-way time (TWT) or depth. Indeed, it is apparent in the SWIM gathers that the velocity model used is in fact slightly inaccurate at the far offsets (‘undercorrected’), and more sophisticated high-order/multi-offset/anisotropic velocity corrections can be applied, tested and refined with confidence. The use of SWIM in ‘Complete Wavefield Imaging’ (CWI) velocity model building has now become commonplace.

It is worth reminding ourselves that the ‘structural stability’ of depth imaging is rather useless without very accurate shallow velocity control. The 3D spatial integrity of the structures imaged, the juxtaposition of events across faults, the pull-up/push-down influence of near-surface velocity heterogeneities upon seismic-to-well ties, the ability to accurately quantify the volumes of prospects, and so on, all depend upon the seismic depth range where we historically have the worst understanding—the first 1 km below the surface.

Near Angle Illumination

It is worth noting that all SWIM events are naturally zero phase at all depths, and the angle coverage/illumination is substantially improved by comparison to conventional image gathers—particularly in terms of near-angle coverage. These considerations contribute to the spatial resolution of shallow features associated with SWIM depth slices. Whilst minimum angles in excess of 25° are routinely observed in the first 0.5 seconds on conventional angle gathers in shallow water depths (less than 300 m), the minimum angles observed on SWIM angle gathers are routinely less than 5°. This becomes particularly relevant for seismic inversion and AVO studies. We also observe in the lower part of Figure 1 that stable far angle information is available past 42° in this particular example—both because the velocity model used to convert offset to angle can be more accurate and because significantly larger offsets are imaged.

Velocity model building in complex geological regimes is increasingly moving towards using angle domain common image gathers (ADCIGs) as the preferred platform rather than traditional offset domain gathers. The challenges observed in Figure 2 are therefore also relevant to shallow velocity model building in addition to seismic inversion where small minimum incidence angles are critical to derive accurate AVO incidence and gradient information—the application for angle stacks discussed in a future article. As we will see, SWIM image gathers have densely sampled angle information for all angles of interest and all depths of interest.

Seismic Survey Geoscience
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The Impact of COVID 19 In The Downstream Oil & Gas Sector

Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.

Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.

Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and  power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.

Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.

But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.

Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.

Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)

Consumption (mmb/d)*
Refining Capacity (mmb/d)
North America



Latin America









Middle East












*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)

Market Outlook:

  • Crude price trading range: Brent – US$33-37/b, WTI – US$30-33/b
  • Crude oil prices hold their recent gains, staying rangebound with demand gradually improving as lockdown slowly ease
  • Worries that global oil supply would increase after June - when the OPEC+ supply deal eases and higher prices bring back some free-market production - kept prices in check
  • Russia has signalled that it intends to ease back immediately in line with the supply deal, but Saudi Arabia and its allies are pushing for the 9.7 mmb/d cut to be extended to end-2020, putting the two oil producers on another collision course that previously resulted in a price war
  • Morgan Stanley expects Brent prices to rise to US$40/b by 4Q 2020, but cautioned that a full recovery was only likely to materialise in 2021

End of Article

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May, 31 2020
North American crude oil prices are closely, but not perfectly, connected

selected North American crude oil prices

Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.

The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.

Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.

pricing locations of selected North American crudes

Source: U.S. Energy Information Administration

First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.

Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.

Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.

Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.

Principal contributor: Jesse Barnett

May, 28 2020
Financial Review: 2019

Key findings

  • Brent crude oil daily average prices were $64.16 per barrel in 2019—11% lower than 2018 levels
  • The 102 companies analyzed in this study increased their combined liquids and natural gas production 2% from 2018 to 2019
  • Proved reserves additions in 2019 were about the same as the 2010–18 annual average
  • Finding plus lifting costs increased 13% from 2018 to 2019
  • Occidental Petroleum’s acquisition of Anadarko Petroleum contributed to the largest reserve acquisition costs incurred for the group of companies since 2016
  • Refiners’ earnings per barrel declined slightly from 2018 to 2019

See entire annual review

May, 26 2020