Bruce S. Hart
Bruce S. Hart is an Adjunct Professor in the Sciences Department at Western University, London, Ontario Canada. He was previously a research scientist with Statoil/Equinor studying shale and other types of unconventional reservoirs (Vaca Muerta, Eagle Ford, Bakken, Marcellus, etc.) to enhance exploration and development efforts. Prior to joining Statoil, Hart held a similar position with ConocoPhillips. Prior to that, he was a Tenured Professor in the Earth and Planetary Sciences Department at McGill University, and held research/teaching positions at New Mexico Tech, Penn State and the Geological Survey of Canada. He toured as the 2017 AAPG/SEG Distinguished Lecturer, the 2009 SEG Distinguished Lecturer, and as a Guest Lecturer for the Canadian Society of Petroleum Geologists in 2006. He has authored or coauthored more than 60 peer-reviewed publications (three of which have won Best Paper awards) on shales, seismic attributes, clastic sedimentology, fractured reservoirs, pore-pressure prediction, sequence stratigraphy, and other topics. He has more than 50 other publications as SPE and URTeC papers, papers in trade journals, extended abstracts, etc. He authored a digital textbook on seismic interpretation for AAPG and has given short courses on that topic in Houston, London, Cairo, Kuala Lumpur, Calgary, Vienna, and elsewhere.
2017 SEG/AAPG Distinguished Lecturer
Bruce presented two lecture topics.
Five things geophysicists should know about shale plays
The shale revolution caught geophysicists off guard. Shales had been studied for a variety of reasons (e.g., relationships between velocity, compaction, and pore pressure) but not as low-porosity reservoirs that show vertical heterogeneity at all possible scales. Consequently, many geophysicists have framed shale-play imaging problems using inappropriate tools and paradigms. In this presentation, I present five characteristics of shale plays that should enable improved geophysical analyses.
1. The term “shale play” has become meaningless. Originally intended to describe gas production from fine-grained source rocks (“source-rock reservoirs”), the term is now applied almost indiscriminately to production from nearly any type of low-permeability rock (e.g., shaly sandstones, carbonates).
2. Source-rock reservoirs aren’t clay dominated. Hydraulic fracturing is needed to establish commercial production from these rocks. Clays make the rocks ductile and harder to fracture. As such, the clay content of shale plays is generally less than 50%. The remainder of the rock is usually composed of fine-grained calcite and/or quartz, organic matter, and other minerals.
3. Links between VTI anisotropy and clay or organic content are not straightforward in source-rock reservoirs. Scanning electron microscopy often reveals textures that are incompatible with the conceptual models used to develop mathematical models of shales.
4. HTI anisotropy is complicated by natural fracture geometries. Aligned natural fractures generally combine with bedding to produce systems that are best described as orthorhombic. In some cases, multiple fracture orientations produce systems that are effectively isotropic.
5. Integration of geophysical and geologic data and concepts is needed to significantly advance geophysical research on shale reservoirs. This effort will allow geophysicists to define which assumptions are reasonable, which analogs are appropriate, what appropriate ranges of properties are, etc.
The Ice Age and the giant Bakken oil accumulation
The United States Geological Survey estimated (2013) that the Late Devonian to Early Mississippian Bakken Formation holds in excess of 7 billion barrels (~1.1 billion m3) of recoverable oil, making it one of the top 50 oilfields in the world. Most of the production comes from shallow-marine sandstones of the Middle Bakken Member that are directly overlain and underlain by extremely organic-rich shale source rocks (Upper and Lower Bakken Shale members respectively). Although not oil-productive everywhere, the Middle Bakken forms a relatively sheet-like unit that covers an area of more than 200,000 square miles (~520,000 km2) of the intracratonic Williston Basin.
The vertical juxtaposition of shallow-marine reservoir and more distal source rocks over such a large area, without intervening transitional facies, is unusual from a stratigraphic perspective. One possible explanation would require global fluctuations of sea level to drive geologically rapid and extensive shoreline movements in this relatively stable basin. Forced regression associated with falling sea level could explain the lack of transitional facies (e.g., inner shelf) between the distal Lower Bakken Shale and the overlying sandstones of the Middle Bakken (a sharp-based shoreface). Subsequent sea-level rise would have caused rapid and extensive transgression, leading to the observed stratigraphic relationships between the Middle and Upper Bakken members. But what could have caused the changes in global sea level?
A considerable body of evidence points to a Late Devonian-Early Mississippian ice age that covered portions of Gondwanaland (e.g., parts of present-day Brazil) that were situated at high latitudes. This ice age consisted of more than one glacial/deglacial cycle. Water is drawn out of the world ocean during glaciations, causing global sea level to fall. Some evidence indicates at least 100 m of sea-level drop for one of the Famenian glaciations, which would have effectively drained the Williston Basin and induced shoreline progradation. Melting of the ice sheets would have caused transgression and reflooding of the basin and deposition of the Upper Bakken Shale. Other basins around the world record similar evidence for glacioeustacy near the Devonian-Mississippian transition. The repeated glacial/deglacial cycles at this time are expressed differently in each basin, reflecting the interplay between fluctuations of global sea level and each basin’s history of subsidence and sediment supply.
SEG Best Paper in Interpretation Award 2013
Fall 2009 SEG Distinguished Lecturer
Bruce presented two lecture topics.
Reservoir-Scale Seismic Stratigraphy: A Call to Integration
The introduction of seismic stratigraphic techniques in the 1970s gave sedimentary geologists in the petroleum industry and Academia new tools for predicting lithology and analyzing the depositional history of sedimentary basins. Seismic stratigraphy originally focused on large-scale exploration problems and was based on analyses of 2-D seismic data in areas that were relatively "data poor" (i.e., few logs, core or production data). Although these conventional seismic stratigraphic analyses are still used fruitfully, new challenges and opportunities confront the petroleum industry as it faces the need to improve recovery from mature fields.
These areas are commonly data rich (lots of log, core and production data), and covered by relatively small 3-D seismic surveys that do not image all of the sequences or systems tracts that the reservoir rocks are part of. As such, a new mindset is needed, here termed "reservoir-scale seismic stratigraphy," to help geoscientists maximize the stratigraphic information they can extract from seismic data. Integration of geologic and geophysical concepts and data is critical.
Techniques employed by geophysicists for at least the past decade (inversion, seismic attribute studies, seismic facies analysis, etc.) need to become routine parts of the sedimentary geologist's toolkit, whereas seismic interpreters need to study outcrops, core and modern analogs in order to anticipate the presence of depositional features that cannot be resolved seismically. This cross-disciplinary interaction will undoubtedly spawn new breakthroughs in sedimentary geology, reflection seismology, petroleum geology and related fields (e.g., hydrogeology). These are exciting times.
A recording of the lecture is available.
Basin-Centered Gas Accumulations: Revisiting the type areas with integrated datasets
The basin-centered gas concept has evolved considerably in the 30 years since the publication of Master's AAPG Bulletin paper that compared the Deep Basin of Alberta to the San Juan Basin of New Mexico and Colorado. In both areas, Masters noted that gas-charged, low-permeability Cretaceous sandstones are present over broad areas in the deeper part of the basin. Furthermore, the gas-charged sandstones appeared to be in stratigraphic continuity with wet sands around the margins of the basin. The basin-centered gas concept was widely adopted, but has since come under attack.
It is time to revisit the type areas, summarize existing knowledge, and integrate 3-D seismic, log, core, outcrop, and production data to study the controls on gas production. Commercial production from Cretaceous sandstones of the San Juan Basin is made possible by extensive regional fractures, and is enhanced by fracture stimulations. These tight sands are gas charged everywhere in the deepest, central portion of the basin. Integration of 3-D seismic and other data show that production "sweet spots" in this basin are generated by fracture swarms that are related to subtle structural features. On the other hand, production sweet spots in the Deep Basin are clearly stratigraphic in origin.
Chert-rich shoreface and foreshore sandstones and conglomerates lack quartz overgrowths and produce gas, whereas stratigraphically contiguous quartzose deposits have abundant quartz overgrowths and are tight. Natural fractures are generally not well enough developed in the Deep Basin to allow the tight sands to produce. In the Deep Basin, gas appears to be trapped downdip from water because of both stratigraphic discontinuities and a "permeability jail" in the tight quartzose sandstones. The mechanism that traps gas downdip from water in the San Juan Basin has yet to be defined publicly but, like the Deep Basin, there is no conventional structural trapping mechanism.