Joint HGS International & General Dinner - Sheriff Lecture

Monday, November 16, 2015
Westchase Hilton • 9999 Westheimer
Social Hour 5:30–6:30 p.m.
Dinner 6:30–7:30 p.m.
Cost: $45 pre-registered members; $50 for non-members/ ALL walk-ups (Credit Cards Now Accepted);
$40 for Emeritus/Life/Honorary; $10 for students if pre-registered and pre-paid.
To guarantee a seat, you must pre-register on the HGS website and pay with a credit card.  You may walk up and pay at the door if extra seats are available.  Please cancel by phone or email within 24 hours before the event for a refund.  Online & pre-registration closes Friday, November 13 at 12:00 p.m.

The Sheriff Lecture is held annually in collaboration between HGS and the University of Houston Department of Earth and Atmospheric Sciences in honor of former faculty member Dr. Robert Sheriff.  The event is designed to bring together members of the Houston geological community and showcase the students and research in geology happening at UH.  The lecture will be preceded by a student poster session, a short overview of the dcepartment, and the presentation of the distinguished alumni award.

Speaker:  Kevin M. Bohacs

ExxonMobil Upstream Research Company

Order from chaos-mudstones as hydrocarbon sources, reservoirs, and seals: their common characteristics and genetics, essential differences, and recognition criteria

All ‘shales’ are not the same, but neither are they all unique. Finding common elements among the mudstone units that serve as hydrocarbon sources, reservoirs, and seals is essential for advancing our understanding of these complex rocks and making wise economic decisions.

Source, reservoir, and seal mudstones share many attributes from composition and depositional controls to stratigraphic distribution (Figure 1; e.g., Bohacs and Lazar, 2008; Lazar et al., 2015). Effective hydrocarbon source, reservoir, and seal mudstones all tend to have significant organic-carbon and clay-mineral content, well-preserved bedding, and early diagenetic cements (Figure 2; Bohacs, 2007; Bohacs et al., 2013). The organic matter in source rocks tends to be well preserved and enriched in hydrogen. In addition, good seals generally have less than 20% silt content and dominantly ductile components, whereas mudstone reservoirs are generally dominated by planktonic input of carbonate or silica that yields lithofacies amenable to induced stimulation (i.e., ‘brittle’ rocks; Figure 2; Bohacs, 2007). A significant thickness of each fine-grained facies and appropriate state of thermal maturity is required for economic effectiveness. These shared attributes allow us to leverage insights and models developed for source rocks to predict seal and reservoir facies.

Source Rocks: In terms of stratal stacking and architecture, source-prone biogenic-rich mudstones at the depositional sequence scale have been shown to occur in a limited number of physiographic settings, each with characteristic occurrence, stratal stacking, distribution, and character of TOC, HI, and fossil material (e.g., Bohacs, 1998). The term “physiographic setting” is an abbreviation for the complex of geomorphic and sedimentation processes that produce a given setting prone to accumulating biogenic-rich rocks. The utility of the physiographic setting factor is that it is portrays a fairly detailed picture of the mudstone depositional system that can be determined from typical exploration data (sequence-stratigraphic framework, facies, paleogeographic maps).  The setting has direct implications for the vertical and lateral distribution of biogenic material within a depositional sequence, especially in the marine realm.

For example, in marine Constructional Shelf Margin (CSM) settings, organic-carbon and biogenic content generally increases in each parasequence up to the maximum-flooding downlap surface (MF-DLS), then decreases step wise. In this setting, shoreline clastic dispersal systems are directly coupled to the basinal depositional areas. Thus parasequences generally decrease in thickness and increase in biogenic content towards the basin; organic-matter type changes systematically from terrigenous, low-hydrogen content proximally to marine, high-hydrogen content distally. In contrast, the Platform-Ramp (P-R) setting contains parasequences that are relatively thick in basinward positions and thin (or lap on) toward basin margins. The distribution of organic matter differs significantly from the CSM: the P-R setting shows little or no organic-facies changes towards the limit of fine-grained deposition. Maximum organic-carbon content occurs in the basal TST and decreases stepwise to background levels at the MF-DLS.

Mudstone reservoirs: Using the same approach, ‘shale’ reservoirs can be grouped into meaningful sets or families for analysis and comparison based on geological age, stratal stacking, and depositional setting, leveraging our long-standing approach to source rocks and carbonate reservoirs, thus enabling transfer of lessons appropriately among plays. Although they accumulate in a variety of settings (convergent and divergent margins; marine and lacustrine; wave- , river-, and tide-dominated shelves, slopes, and basin floors), prolific shale-reservoir-play strata have several essential attributes in common: sensitively dependent on pre-existing and contemporaneous bathymetry, moderate clay-mineral content, parallel-bedded fabrics, early diagenetic cements, and significant biogenic content of both source-prone organic matter and brittle lithofacies. 

Recently, we recognized that all major shale-gas plays can be grouped into four main families, based on repeated patterns of stratal stacking of biogenic-rich physiographic settings at the sequence-set scale:

1. Marine, Basal Platform-Ramp sequence overlain by one or more Distal Constructional Shelf Margin sequences (transgressive to highstand sequence set); e.g., Utica (Pt Pleasant-Flat Creek-Indian Castle), Marcellus (Union Springs-Oatka Creek-Burket), Horn River (Evie-Otter Park-Muskwa), Antrim (Norwood-Lachine-u. Antrim), Woodford (lower-middle), Fayetteville (lower-middle-upper), Haynesville-Bossier, Eagle Ford (lower-upper) Shales 
2. Marine, Distal stacked Lowstand Systems Tracts (LSTs) in intra-shelfal basins (lowstand sequence set); e.g., Barnett, Floyd Shales
3. Marine, Individual Constructional Shelf Margin sequence -- upper Transgressive Systems Tract (TST) through lower Highstand Systems Tract (HST; distal downlap within sequence); e.g., Niobrara, Lewis, Mowry Shale, Gammon, Cody, Mancos, Pierre, Hilliard-Baxter-Mancos, Excello Shales
4. Lacustrine, Balanced-Filled sequences -- transgressive to highstand sequence set; e.g., Frederick Brook Formation

Mudstone Seals: Hydrocarbon seals are also amenable to this sequence-stratigraphic-based analysis. A good seal rock is typically fine-grained, with abundant clay-mineral content, less than 20% silt-sized particles, and more than 2 wt.% TOC (Fig. 1.2). Thus, many good source rocks are also good seals—they typically have high capillary entry pressures, are laterally continuous with relatively slowly varying character, and are relatively ductile. Some organic-matter-poor, clay-mineral-rich mudstones can also serve as a seal. Seal and source rocks can accumulate in many of the same depositional settings, with seals also formed in somewhat higher sedimentation rate areas with abundant clay minerals and in evaporative environments, both shallow/proximal and deep/distal. Sequence stratigraphy has been shown to provide the context within which seal potential and behavior can be predicted (e.g., Dawson and Almon, 1999, 2002, 2005; Jonk et al., 2009). A classic example from the Gulf of Mexico shows that for mudstones with the same clay-mineral content, those within transgressive systems tracts have significantly higher capillary entry pressures than those in highstand systems tracts (Dawson and Almon, 199).

This approach enables early identification of the essential elements of a hydrocarbon play from regional context and stratal patterns that can be imaged on seismic and well-log data. And, this approach focuses further data acquisition on attributes critical for economic viability.

So what? But, you might wonder, why all this geology?— aren’t these ‘engineering’ plays?? As it turns out, the equations that govern volumetric source potential, resource in place, and fluid production rates are linear in almost all terms. Hence, it then follows that each of the factors are of equal importance for the overall character of the mudstones in a hydrocarbon system. Some of the geological variables, however, have much wider ranges than others, and therefore can have a larger quantitative influence on calculations of source yield, resource in place, or producibility. Indeed, the net volume of reservoir rock (area x thickness x net:gross) is the dominant factor in the resource-in-place equation, by a factor of 600 or more (e.g., Figure 3).

For the mudstone reservoir portion of the hydrocarbon system, examination of the formulae used for both resource in place and producibility reveals that 35% of the variables are solely rock properties, and that an additional 53% are combinations of rock properties with geologically influenced factors (fluid, basin-history, reservoir pressure, or completions parameters). Essentially only one factor (wellbore radius) out of 14 variables is solely an ‘engineering’ factor.

These quantitative considerations are the motivation for the detailed treatment of geological factors in mudstone reservoir plays. These factors are the essential foundation upon which to build economic success, by convolving them with appropriate drilling, completions, and production practices. Similar attention to geological details is critical to understanding from where the hydrocarbons come, what their composition will be, and where they will be trapped—the other two-thirds of the hydrocarbon system.

Kevin M. Bohacs, from Greenwich, Connecticut, received his B.Sc. (Honors) in geology from the University of Connecticut in 1976 and his Sc.D. in experimental sedimentology from M.I.T. in 1981(where he built and operated the world's largest flume). He joined Exxon Production Research Company in Houston, Texas in 1981, working with Peter Vail, Bob Mitchum, John Van Wagoner, and others on incorporating process-based facies modeling into the development of sequence stratigraphy at the outcrop, core, and well-log scale. He is presently Senior Research Scientist and works with the Hydrocarbon Systems and Stratigraphy and Reservoir Systems divisions.

At ExxonMobil Upstream Research Company, he leads the application of sequence stratigraphy and sedimentology to fine-grained rocks from deep sea to swamps and lakes, in basins around the world. His primary focus is to integrate field work, subsurface investigation, and laboratory analyses to inform business decisions. He works closely with exploration affiliates in evaluating the fine-grained portion of their hydrocarbon systems, teaches field schools in sequence stratigraphy, sedimentology, basin analysis, and field safety leadership, and conducts field work for research and exploration.

He has written more than 101 scientific contributions on the stratigraphy and sedimentology of mudstone, hydrocarbon source rocks, and lake systems, and received numerous best paper and career achievement awards and served as a distinguished lecturer for many societies around the world.