Analysis of the AAPG giant fields database reveals that there has been a step change in volumes of oil attributed to non-structural traps in the last 20 years. Why is that – and where should we be looking for them?
Next year marks the end of another decade of global oil and gas exploration, which will be highlighted in 2020 in an upcoming AAPG Memoir, Giant Fields of the Decade 2010–2020. In the last decade, 89 giants have been discovered, and 226 since 2000. With 60% of global production coming from giant fields (defined as those with more than 500 MMboe recoverable), geoscientists owe it to themselves to understand their discovery history, basin setting, petroleum system and trapping mechanisms.
Figure 1. Since 2000, almost 50% of giant fields discovered have been in stratigraphic or combination traps. a: Giant fields creaming curve by trap type. b: Giant fields discovered since 2000 by trap type (Bboe).
AAPG has maintained a GIS database of giant fields discovered up through 2009 (Horn, 2011) and this database has been updated since then for the upcoming memoir and provides new insight into changes in exploration focus and technological advancements. Analysis of trap types of recent giants has, surprisingly, shown a substantial contribution from combination and stratigraphic traps; this is a true step-change from prior decades.
3D Seismic the Key for Successful Stratigraphic Trap Exploration
It has been almost 40 years since Michel Halbouty published his landmark paper on subtle trap exploration (Halbouty, 1981). Historically, only 10–15% of global giant fields were found in stratigraphic and combination traps. Multiple seals and a limited number of pay zones are the size-limiting factor in these kinds of plays. Single pay traps require large areas in order to become giants, or thick reservoirs like carbonate reefs or deepwater turbidites. The biggest barrier, however, has been limited seismic resolution to make these subtle traps obvious. Inherently, there is no reason to sink money in subtle traps that are poorly imaged or understood – so the key is to make them easy to see.
Those of us who started our careers with hard copy logs, 2D seismic and hand-contoured maps, relied heavily on geological intuition to contour both structural and stratigraphic elements to find stratigraphic traps. The result was a high failure rate, with most well locations being concept driven, rather than data driven with good reservoir and seal imaging from seismic. Many of the giant stratigraphic traps drilled without 3D seismic were initially located either too far up-dip in tight waste zones, or low on the trap where relative permeability and high water saturations tested water with poor shows. In these cases, many of the fields went unrecognised for years, as operators dismissed the oil and gas shows as indicative of failed traps. In addition, structure maps from 2D seismic often bear little resemblance to geometries mapped from 3D data. Even today, many dry holes provide the keys to finding new, big fields from wells abandoned by operators failing to understand their own oil and gas shows. Lag time from initial discovery to full realisation of the size of big traps often exceeded a decade. It is no wonder than many exploration managers advised against stratigraphic trap exploration.
With the start of widespread acquisition of 3D seismic data, however, success rates began to pick up. In 2003, at the age of 95, Michel Halbouty edited AAPG Memoir 78, in which he noted that stratigraphic trap exploration success had jumped to 22% in the 1990s, a clear result of better seismic imaging. This trend has continued. As Figure 1 shows, these nonstructural discoveries have accelerated in the last 20 years. Nearly 50% of the giants discovered since 2000 were in combination and stratigraphic traps.
Where are Stratigraphic Traps Found?
Where are these fields? The map in Figure 2 shows the global distribution of stratigraphic and combination traps discovered in the last 20 years, including some fields that are less than 500 MMboe in size but are considered significant potential play openers. The summary numbers given in subsequent figures, however, are only for fields with a minimum recoverable resource of 500 MMboe. The decade from 2000–2010 is covered in detail in AAPG Memoir 113 (Merrill and Sternbach, 2017) and Mann et al., 2007. A more thorough treatment of the discoveries to the end of 2016 is in Dolson et al., 2017.
Figure 2. Giants and significant combination and stratigraphic trap discoveries of the last 20 years. Classes: Giant: 0.5 – 5 Bboe; Super Giant > 5 Bboe; Mega giant: > 50 Bboe.
Figure 2 shows a wide variety of play types but with a concentration of giant fields in passive margin and cratonic settings. These traps are not limited by age (see Figure 3), but Mesozoic petroleum systems dominate, with Cenozoic and Palaeozoic traps usually being smaller, while, surprisingly, a major Neo-Proterozoic gas discovery has been reported in East Siberia. Carbonate and clastic reservoirs essentially comprise similar volumes, but analysis of the traps indicates that reefs, turbidite and tight gas are where major reserve additions have been made.
Reefs and passive margin turbidites provide thick, readily identifiable targets on seismic, with seal being the major risk factor. Mesozoic plays benefit from rich source rocks in Lower Cretaceous through Upper Cretaceous shales, which formed during the early break-up of Pangea, aided by the hot-house climates prevalent in the Campanian-Turonian period.
Major hubs of carbonate reef exploration are the Santos-Campos Basin sub-salt lacustrine carbonates, the Miocene/Cretaceous Zohr trend offshore Egypt and Cyprus, and the northern Caspian Basin (Pri-Caspian Carboniferous). Successful Mesozoic and Tertiary turbidite plays have been found in many coastal settings, notably in the northern Caspian and the Rovuma Basin, offshore Senegal and Mauritania, the north-west shelf of Australia and the prolific Lisa area offshore Guyana.
Figure 3. Giants fields found in the last 20 years, by lithology, age and trap type.
High quality 3D seismic and DHI plays have helped make the turbidite plays less risky. Pri-Caspian reefs and the Zohr complex were so large and easily imaged that they were drilled on 2D data. The prolific sub-salt carbonates of the Santos Basin, however, were essentially not visible on pre-2000 2D seismic data. Long offset data acquired in the 2001–2002 period imaged the pre-salt rifts and high shoulders. However, the discovery of the Libra Field (Figures 4A and 4B) was a surprise, as it was located in lacustrine carbonates with multi-darcy reservoirs, often hydro-thermally altered.
Tight gas has seen substantial reserve growth, particularly in China, as well as in Cambrian and Neo-Proterozoic strata in Oman. For example, the Sulige Field (42 Tcfg) is part of a complex of other fields in the Ordos Basin with tight gas resource potential up to 145 Tcf, with 80 Tcf already discovered. Most of these traps remain poorly understood (Dai, 2016; Jinxing et al., 2015). A giant tight oil shale and siltstone discovery in Bahrain in 2018 appears to be either a new stratigraphic or unconventional trap.
Human Insight Still Needed
Seismic imaging of reservoir facies has now become a required skill set of any interpreter. Seals, reservoirs and traps become more apparent and can be modelled quantitatively and then used in petroleum systems migration modelling. Integration of petroleum systems elements, tested and validated with wells and field data, should be a standard workflow for any company.
Figure 4. Examples of improved 3D seismic imaging of reservoirs and seals. Figure 4A is modified from Rassenfoss (2017); 4B from Carlotta et al. (2017) and Figure 4C modified from Palermo et al. (2014). The fluvial channel example shown in 4D is courtesy of UHCL, by permission of the Ministry of Energy of Chad.
Nothing, however, replaces the human insight that leads to new ideas, often in old areas. The prolific >100 Tcfg Rovuma Basin turbidite play, Figure 4C, was visualised by three experienced geoscientists at Cove Exploration, and then farmed-out to majors for funding. Increasingly, this has become an exploration model for larger companies, who rely on the experience and intuition of proven explorers in small companies to envision new plays and then provide the cash to test them.
The Buzzard Field combination trap was made possible by examination of a downdip well with 3–5m of oil pay abandoned behind pipe. Likewise, the Horseshoe-Willow area topset play in Alaska offset a 2002 dry hole with pay behind pipe in shallow Cretaceous horizons virtually ignored by the industry. Caelus Energy’s Smith Bay giant turbidite field, also in Alaska, was made by transferring knowledge of Cretaceous source rock and interbedded fan plays on the west coast of Africa to similar tectonic and stratigraphic settings in Alaska. It apparently took ‘outsiders’ to ‘think out of the box’ and find oil where the major operators had missed it for over 50 years.
More details of these trends and others will be available soon in AAPG’s next Giant Fields Memoir, scheduled for completion next year. In the meantime, more giant fields will be discovered, made possible by creative insight and steady improvement in seismic imaging and petroleum systems migration and charge modelling.
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