Modern seismic methods have revealed large, deep structures in the northern Gulf of Mexico. Wilcox Group sandstones are deep (>4.5 km) to ultradeep (>6 km) exploration targets below the present-day shelf and deepwater Gulf. At these depths, reservoir quality is a critical risk factor. Petrographic study of onshore Wilcox sandstones, combined with burial-history modeling, provides insight into the main controls on regional variation of reservoir quality.

Wilcox sandstones were sourced by continental-scale drainage systems that terminated in deltas in Texas and Louisiana. Seismic data were used to identify three major sediment fairways that carried sandstone from the shelf into the deep basin in the northwestern Gulf. Sandstone composition and diagenetic history were determined by point counts of thin sections from onshore Wilcox samples from depths of 0.2– 6.7 km, at temperatures of 25–230°C. The sandstones are mostly lithic arkoses and feldspathic litharenites; metamorphic and volcanic rock fragments are the most abundant lithic grains.

Primary, intergranular porosity was lost during diagenesis mainly by compaction (grain rearrangement and ductile-grain deformation) and quartz cementation. Pores in Wilcox sandstones changed from a mix of primary and secondary pores and micropores at lower temperatures to predominantly secondary pores and micropores at temperatures >150°C as primary pores were occluded. Primary porosity, which affects permeability the most, decreased from an estimated 40% at deposition to 5–8% by 125°C and 1–2% at temperatures >200°C. Pore-type evolution with temperature alters the porosity–permeability transform.

Burial-history modeling reveals large differences in thermal history of Wilcox sandstones across the study area.  Thermal maturity of Wilcox sandstones 6 km below the deepwater Gulf of Mexico is similar to that of onshore Louisiana Wilcox reservoirs at 3.4 km (both have Ro ≈ 0.7%). Geothermal gradient in the deepwater Gulf is lower than onshore, and >3 km of allochthonous salt has been in place above the Wilcox for the past 30 m.y. Salt transmits heat effectively, thus reducing temperature and diagenesis in underlying Wilcox sandstones and preserving reservoir quality. During the past decade numerous oil discoveries have been made in Wilcox sandstones in the deepwater play. In contrast, Wilcox sandstones 8.2 km beneath the Louisiana shelf have higher thermal maturity (Ro > 2.7%). Allochthonous salt ~2.5 km thick was present for an estimated 8 m.y., but that time was apparently insufficient to lower thermal maturity. Deep, high-temperature Wilcox sandstones below the shelf have higher reservoir-quality risk.

The Gulf of Mexico (GOM) is the 9th largest body of water on earth, covering an area of approximately 1.6 million km2 with water depths reaching 4,400 m (14,300’). The basin formed as a result of crustal extension during the early Mesozoic breakup of Pangaea. Rifting occurred from the Late Triassic to early Middle Jurassic. Continued extension through the Middle Jurassic combined with counter-clockwise rotation of crustal blocks away from North America produced highly extended continental crust in the subsiding basin center. Subsidence eventually allowed oceanic water to enter from the west leading to thick, widespread, evaporite deposition. Seafloor spreading initiated in the Late Jurassic eventually splitting the evaporite deposits into northern (USA) and southern (Mexican) basins. Recent work suggests that this may have been accomplished by asymmetric extension, crustal delamination, and exposure of the lower crust or upper mantle rather than true sea floor spreading (or it could be some combination of the two). By 135 Ma almost all extension had ceased and the basic configuration of the GOM basin seen today was established. The Laramide Orogeny was the last major tectonic event impacting the GOM. It caused uplift and erosion for the NW margin from the Late Cretaceous to early Eocene.

Sedimentation in the GOM can be divided into five megasequences: Rifting to Upper Jurassic, Lower Cretaceous, Upper Cretaceous, Paleogen, and Neogene. The oldest sediments are clastics in the Upper Triassic known only from peripheral rift basins onshore. In the basin center evaporites of the Middle Jurassic Louann Formation are the oldest deposits encountered. Deformation and movement of the Louann salt affects almost all the overlying strata and plays a very important role in all aspects of the basin’s petroleum systems. Above the salt, Upper Jurassic marine shales of Oxfordian and Tithonian age comprise two of the most important petroleum source beds. In the Lower Cretaceous megasequence the Aptian age Sligo and Albian age Stuart City carbonates established basin rimming reef margins that divided shelf from deep water. These reefs sit above the structural hinge between thick and thin continental crust. In the Upper Cretaceous megasequence the Cenemanian age Woodbine-Tuscaloosa system represent the first coarse clastics to advance beyond the Lower Cretaceous shelf margin. The megasequence is capped with tsunami deposits from the Chicxulub impact on the Yucatan peninsula. The Paleogene1 and Neogene2 megasequences are dominated by major clastic inputs of the lower Wilcox1, upper Wilcox1, Vicksburg1, and Frio1, lower Miocene2, middle Miocene2, upper Miocene2, Pliocene2, and Pleistocene2. These progradational episodes not only advanced the shorelines and shelf margins significantly but also deposited thick sands (major reservoirs) in the deep GOM. The Neogene progradational episodes are strongly influenced by glacio-eustatic cycles of increasing frequency and amplitude.

Hydrocarbon exploration beneath the shallow allochthonous salt canopy of the ultra-deepwater central Gulf of Mexico has encountered three thick, sand-rich, submarine fan successions that punctuate an otherwise relatively condensed and fine-grained basin center stratigraphy. These sand-rich fans are Late Paleocene, Early Miocene, and Middle Miocene in age and each coincide with periods of very high sediment flux and basin margin instability. They are the primary exploration targets in most ultra-deepwater fields, recent discoveries, and failed exploration tests.

The underlying basement configuration contains the horsts and grabens of a rift basin setting. The deep parts of the rift became salt basins filled with the Jurassic Louann salt. During the Cretaceous, kilometers-thick salt nappes extruded from these basins onto the basin margins. The nappes may have coalesced to form a regional allochthonous salt nappe around the margin of the salt basins, similar to the modern Sigsbee Escarpment. Later clastic sedimentation caused deflation of the nappe leaving remnant salt structures behind. The remnant salt bodies form the core structures over which younger sand-rich fans are folded and draped.

Regional 3D PSDM data show that remnant salt bodies from the now deflated Cretaceous nappe form the core structure in fields at Chinook and Cascade and in recent discoveries at Stones, Das Bump, St. Malo, and Jack. Both seismic and well data show that the sand-rich outer fan of all three fan systems overlies the zone of salt nappe remnants. It would be a remarkable coincidence for the sandy outer fans of three different age depositional systems and the termination of two more widely separated (both temporally and spatially) allochthonous salt systems to stack vertically. The fact that they do suggests that both deep-water fan deposition and allochthonous salt emplacement were responding to a deeper structural control.

Seismic correlations and well data confirm that deep-water carbonate beds of Mesozoic age have been found above the shallow allochthonous salt canopy in the northern Gulf of Mexico. These rafts of carbonate strata often overlie equivalent age Mesozoic carbonates in their correct stratigraphic position below the salt canopy. The presence of displaced Mesozoic carbonate rafts above the canopy raises two important questions: 1) how did Mesozoic strata get to such a shallow level in the basin statigraphy? and 2) what effect do high velocity carbonates have on seismic imaging below shallow salt?

The origin of keel structures is presently not well understood. Empirical observations suggest that keels form in response to at least two types of subsalt deformation. The first of these two types links keels to a detachment within Oligocene-to-Eocene strata. The second type of keel-related deformation links keel formation to faults associated with extension over deep salt structures. As deformation occurs after shallow canopy emplacement, the keels are fairly recent developments geologically. Volumetrically few but intriguing observations suggest possible basement involvement in keel formation.

In overcoming the technical challenges of oil production in the Arctic, are we making the most of a strategic resource or heading for an environmental and political minefield?

The vast Arctic region is probably the last remaining unexplored source of hydrocarbons on the planet.

In the past three decades of oil exploration in the Arctic, more than 200 billion barrels of oil have been discovered. Ultimate resources are estimated at 114 billion barrels of undiscovered oil and 2000 trillion cubic feet of natural gas. If these estimates are correct, these hydrocarbons would account for more than a fifth of the world’s undiscovered reserves. This great prize, in a world of diminishing resources, has stimulated both governmental and industry interest in areas such as the US and Canadian Beaufort Sea, East and West Greenland and the Kara Sea.

Balanced against this are the considerable technical challenges of exploring and producing hydrocarbons in areas where sea ice is present for more than half the year as well as the underlying threat of damage to a pristine Arctic environment.

Harnessing the considerable resources of the ‘Final Frontier’ is going to be fraught with many technical, political and environmental challenges that will engage many minds, both scientific and political over the next half century.

Offshore Angola has to date delivered recoverable reserves in excess of 20 billion barrels of oil equivalent. This has been encountered in two distinct play systems: the Upper Cretaceous Pinda carbonates sourced by Lower Creatceous lacustrine mudstones and Tertiary deepwater slope turbidite sands sourced by underlying Upper Cretaceous marine mudstones.

Initial discoveries were made in the Pinda carbonates in shallow water offshore Cabinda during the 1980s. A move into deepwater in the mid 1990s to explore a possible extension of the play in a more distal setting, instead resulted in the discovery of the Tertiary turbidite play most notably in Block 17 at Girassol. An extension of the Girassol play into Block 18 to the south will be used to describe how high quality 3D seismic data coupled with a detailed analysis of rock properties led to an unprecedented 6 successes out of 6 wells in the block, including the giant Plutonio discovery.

The shallow Tertiary play having been largely explored, industry is turning once more to the carbonate play potential - this time in deepwater. The equivalent pre-salt carbonate play that has been so prolific in the Santos Basin of offshore Brazil on the conjugate margin is a key target with a recent significant discovery announced by Cobalt Energy at Cameia in Block 21. Given this and renewed interest in the post salt Pinda, it would seem that the Angola offshore success story is set to continue for some time to come.

Using examples from shale reservoirs worldwide, I demonstrate the diversity of shale-hosted fracture systems and present evidence for how and why various fractures systems form. Core and outcrop observations, strength tests on shale and on fractures in core, and geomechanical models allow prediction of fracture patterns and attributes that can be taken into account in well placement and hydraulic fracture treatment design. Both open and sealed fractures can interact with and modify hydraulic fracture size and shape. Open fractures can enhance reservoir permeability but may conduct treatment fluids great distances, in some instances possibly aseismically.

We have addressed the challenge of incomplete sampling of subsurface fractures through comprehensive fracture data collection in cores and image logs and careful selection of outcrops, coupled with an understanding of how fractures and their attributes scale. We also use tested mechanistic models of how fractures grow in tight sandstones and carbonates to interpret fractures in shale. In order to predict fracture patterns and attributes it is helpful to understand their mechanism of formation and timing in the context of the burial and tectonic histories of the basin in which they are forming. A key variable is the depth of burial, and thereby the temperature, pore-fluid pressure and effective stress at the time of fracture development. For the most part the origin of fractures cannot be determined from their orientation or commonly-measured attributes such as width, height and length. The mineral fill in sealed fractures does provide an opportunity, however, and we use fluid-inclusion studies of fracture cements tied to burial history to unravel their origin.

Interaction with hydraulic fracture treatments may serve to increase the effectiveness of the hydraulic fracture network, or could work against it. Factors governing the interaction include natural fracture intensity, orientation with respect to reservoir stress directions, and the strength of the fracture plane relative to intact host rock. We tested the effect of calcite-sealed fractures in Barnett Shale on tensile strength of shale with a bending test. Samples containing natural fractures have half the tensile strength of those without and always break along the natural fracture plane. Yet in other examples the weakness is in the cement itself, partly because of retained fracture porosity.

Natural fractures in shales likely grew by slow, chemically assisted (subcritical) propagation and we use a subcritical propagation criterion to model the growing fractures. The subcritical crack index is a mechanical rock property that controls fracture spacing and an input parameter for the models. We measured the subcritical crack index for several shales. The index is generally high for Barnett Shale, in excess of 100, although it does show variability with facies. By contrast, subcritical indices in the New Albany Shale are much lower, and also show considerable variability. Barnett Shale subcritical indices suggest high clustering whereas New Albany Shale subcritical indices suggest fractures are likely to be more evenly spaced, with spacing related to mechanical layer thickness. We are investigating the variability in subcritical index in shale and how it might tie to other rock properties.

Natural fractures are a prominent and dramatic feature of many outcrops and are commonly observed in core, where they govern subsurface fluid flow and rock strength. Examples from more than 20 fractured reservoirs show a wide range of fracture sizes and patterns of spatial organization. These patterns can be understood in terms of geochemical and mechanical processes across a range of scales. Fractures in core show pervasive evidence of geochemical reactions; more than is typical of fractures in many outcrops. Accounting for geochemistry and size and size-arrangement and their interactions leads to better predictions of fluid flow.

Opening-mode fracture apertures commonly follow power-law size distributions with opening displacements ranging from approximately 1 µm to 1 m. A power law forms a straight line on a log cumulative frequency versus log aperture size plot. The slope of the line is the power-law exponent, reflecting the relative number of narrow and wide fractures in the set. The pre-exponential coefficient reflects the overall fracture intensity. We will examine the variation in power-law exponent and coefficient for fracture sets in carbonate and siliciclastic rocks and analyze why such variation occurs. Fractures may open in a single event or may repeatedly open and seal. During an opening event the rate of opening competes with the fastest rates of precipitation to determine if the fracture will seal before the next strain increment. Small fractures completely seal with cement precipitated synchronously with opening, whereas large fractures may retain some porosity. The aperture size at which porosity is preserved varies, and it is controlled by the temperature of the ambient fluid, the composition and texture of the host rock and precipitating minerals, and the length of time the fracture wall is exposed to mineral precipitation, which is dependent on burial history and fracture timing. If the widest fractures are not completely sealed before the next strain increment, they may act as planes of weakness, causing strain to progressively partition into fewer fractures, which will grow wider. The extent to which this process happens should partly govern the exponent in the power-law distribution. Cements deposited whilst fractures are growing may cause fracture size distributions to vary from those found in barren fracture arrays (including many of those in outcrop).

Geochemical and fracture size interactions may also affect fracture spatial arrangements. Fractures may be evenly spaced, but more commonly fractures occur in complex and, in some cases, fractal arrays of clusters. We have developed a method, based on a two-point correlation integral, to rigorously identify different types of spatial arrangement, including periodic, random, and clustered. Our method provides a measure of preferred spacing relative to that expected from a random ordering of spacings. I will show examples from outcrop data sets and from fractures interpreted in image logs in shale gas wells.

Petroleum exploration in deep water settings is resulting in the discovery of many giant fields in reservoirs that accumulated in large channel systems on the continental slope. The architecture of these reservoirs is exceedingly complex. In the face of multi-billion dollar costs, it is more important than ever before to accurately characterize these reservoirs.

Based on detailed examination of turbidite channel analogs as revealed in 3D seismic data, exposed in outcrops, or preserved on the modern sea floor, two principal models of channel architecture have emerged: a cut-and-fill model, and a lateral accretion model. Both models are appropriate in at least some cases, but debate continues as to which model is most applicable in any specific case. Furthermore, it is not apparent how to reconcile the preserved facies distributions of turbidite channel deposits and prevailing concepts of turbulent flow behavior. For example, when high levees are present, we know that flows are thick. Concentration of sand within sinuous channel elements confirms that turbulent flows are highly stratified. However, these architectures seem to require that the lower and upper portions of a single flow follow paths with markedly different sinuosities and divergent, even opposing, trajectories. How can that happen? Further debate concerns the transition from channel to fan architectures. Some high resolution 3D seismic images suggest the presence of distinct distributary systems on some submarine fans while others do not. Outcrop examples with the best continuous lateral exposures appear to be incompatible with seismic images of distributary systems. The few excellent outcrop examples of lobes arguably are strongly biased. Are our best images from 3D seismic also biased? High resolution images of modern submarine fans calibrated to sediment cores might provide the answer, but such data are lacking. This quandary is not just academic. It has become clear from recent drilling in the Gulf of Mexico that reservoir quality in submarine fans is highly variable, often containing good permeability within channels in contrast to abundant argillaceous sands with low permeability in the lobes.

With continued research, the issues discussed above will be resolved, but the path forward, like the channels themselves, will be long and sinuous.

The results of regional deep seismic acquisition in the South Atlantic continental margins have shed new lights on the birth and development of sedimentary basins formed during the Gondwana breakup. Recent models of mantle exhumation as observed in the deep water Iberian margin have been applied extensively to the interpretation of several basins in the Eastern Brazilian and West African conjugate margins. However, the tectonic development of these basins is markedly different from the magma-poor margins, and in this lecture we emphasize the contrasts from the tectono-sedimentary features imaged in deep-penetrating seismic profiles that extend from the platform towards the oceanic crust, which indicate that the Red Sea constitutes a better analogue for the birth of divergent continental margins.

This lecture also emphasizes differences in basins developed along conjugate margins in the South Atlantic. Integration of geological and geophysical methods characterize widespread volcanism in the southernmost segment (Pelotas-Santos basins in Brazil and Namibia in West Africa), which are probably related to mantle thermal anomalies. The lack of volcanic features in local portions of the margins, particularly in the shallow-water platform regions (example, Camamu-Almada and Sergipe-Alagoas basins in northeast Brazil) are also discussed, pointing that even in these regions the continent-ocean boundary shows evidence of mantle melts and formation of wedges of seaward-dipping reflectors, as in the Jacuípe Basin.

The central segment of the South Atlantic, from Espirito Santo to Santos basins in Brazil, and from Gabon to Angola in West Africa, is characterized by a major salt basin developed with the first marine ingressions in the Late Aptian. Salt tectonics is responsible for most of the exploratory plays along the margins, with autochthonous and allochthonous salt structures associated with existing and conceptual petroleum accumulations.

An overview of the geological concepts that evolved rapidly during the last three decades brings new lights on the challenges of petroleum exploration in the ultradeep water provinces of divergent continental margins. This talk also shares with the scientific community the methods and results from the application of modern geological and geophysical tools that help in the interpretation of the crustal architecture, rift structures and the salt tectonics elements that are crucial to basin analysis studies.

As the cost of finding and extracting oil and gas rises, petroleum companies must increasingly resort to proprietary and custom technology to gain or maintain a competitive edge. In contrast, the data we purchase and human resources employed are shared throughout the industry. In order for a company to differentiate itself from its peers, it must gain a competitive edge by improving the way their human resources interact, interrogate, interpret, and most importantly understand their data. This need has fueled a technology pull from vendors and a technology push within the petroleum companies. The amount of research conducted within the industry continues to grow at a strong pace, and the speed at which new technologies are becoming obsolete is also increasing. The classroom will never be able to fully train incoming students for the software and hardware they will face on even their first day in the job, much less during their first years in the industry. It will not be the students who are the fastest and most knowledgable about a software package that will be the most agile in this changing environment; it will be those students who have mastered the fundamental geological concepts, have had cross-disciplinary training, have demonstrated creativity, and have a passion for innovation who will be best prepared for the technology evolution that will continue to drive competitiveness in the oil and gas industry. In this talk, I will show examples of how quickly our technology is evolving in this landscape and show the importance of concepts over keystrokes.

When evaluating paleosystems, there will always be a shortage of data constraints and a surplus of plausible geological scenarios for a basin evaluation. Modelling paleosystems with constraints from the modern has been used as a successful approach to better understand petroleum systems. However, as geological data spans both time and space and paleosystems are influenced from lithosphere to atmosphere so should the modelling approach. The modelling approach should be represented through geological time and encompass the effects and implications of the whole earth system. Modelling paleosystems as an integrated earth system requires the integration of tectonics, paleoclimate, source distribution and sediment routing which are all rooted in the prediction of paleotopography. Unfortunately, prediction of paleotopography comes with high uncertainty and is often poorly constrained. Source to sink concepts address the fundamental principles that influence paleotopography but the challenge exists on how to integrate these concepts into meaningful methods for the prediction of petroleum systems. These challenges are being met through industry-driven advances in novel iterative workflows and integrated technology that evaluates the petroleum system holistically through geologic time. Iterative workflows and integrated technology allow for the efficient evaluation of multiple geological scenarios to better constrain the uncertainties in the prediction of petroleum systems.

Numerous studies of sediment-dispersal systems have focused on the relative role of allogenic versus autogenic controls, and their stratigraphic imprint. Advancing our understanding of these vital issues depends heavily on geochronology. Optically stimulated luminescence (OSL) dating has progressed to the point that a plethora of research questions can now be tackled by means of the late Quaternary stratigraphic record. This presentation addresses two classic problems: (1) the response of a continental-scale fluvial system to sea-level and climate forcing over the past glacial-interglacial cycle, and (2) the nature of delta-plain aggradation over shorter (centennial to millennial) timescales. Downstream control (i.e., glacio-eustatic sea-level change) has triggered a remarkably rapid and widespread response of the Lower Mississippi River in terms of incision and aggradation, consistent with sequence-stratigraphic models. However, upstream (climate) controls modulate this fluvial response and stratigraphic architecture cannot be properly understood without fully taking this into account. In contrast, autogenic behavior dominates fluviodeltaic deposition over shorter timescales. Natural-levee and crevasse-splay deposits in the Mississippi Delta accumulate in a highly episodic fashion, challenging the classic model of gradual accretion. At any given location, distinct century-scale pulses with accretion rates on the order of centimeters per year alternate with prolonged periods of relative quiescence. This confirms observations from scaled experiments and highlights the complexity and incompleteness of the stratigraphic record, even over relatively short timescales.

Deltaic subsidence constitutes a classic geological problem, with implications for the accumulation of resource reservoirs as well as coastal degradation associated with accelerated relative sea-level rise. Therefore, disentangling the driving processes and quantifying the rates of subsidence has become a high priority, resulting in a flurry of research in and near the Mississippi Delta in the post-Katrina era. This presentation offers insights into the vigorous debate that has ensued, by means of a discussion of the relative importance of shallow versus deep crustal processes. This includes a review of isostatic adjustments associated both with local sediment loading and the aftermath of the last deglaciation, faulting, sediment compaction, and fluid extraction. It is shown that rapid progress on this complex issue is currently being made, with the potential for a new paradigm for deltaic subsidence in this region to emerge.