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The world-class Middle–Upper Devonian carbonate outcrops of the Lennard Shelf, Canning Basin, Western Australia, offer a unique opportunity to examine reefal carbonate shelf-to-basin evolution in response to multiple coeval extrinsic and intrinsic drivers. Variable styles of carbonate stratigraphic architecture and heterogeneity developed as a function of the interplay between long hierarchical accommodation trends, global biological crises, greenhouse-to-transitional climatic changes, and syndepositional tectonics.
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Studying fine-grained siliciclastic deposits of late Middle Devonian in the northern Appalachian Basin provides an exquisite natural laboratory to observe the complex environments in which mud can accumulate. More detailed correlation and facies characterization of this succession provide a wealth of information and insight into the diverse transport mechanisms responsible for distributing clastics hundreds of kilometers away from a tectonically active source area.
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The Upper Jurassic to Eocene carbonate rocks of the Gargano Promontory belong to the Apulia Carbonate Platform (ACP) and provide a spectacular and complete succession of slope and base-of-slope resedimented gravity flow carbonates with preserved reservoir properties and, with its coeval carbonate platform, displaying various tectonostratigraphic architectures.
American Association of Petroleum Geologists (AAPG)
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The carbonate and siliciclastic outcrops of the Guadalupe Mountains in the Permian Basin of West Texas and New Mexico have provided a rich set of basic and advanced conceptual models for geologists across the entire spectrum of experience for carbonate-ramp and steep-rimmed–platform settings as well as the adjacent deep-water siliciclastics not dealt with here.
American Association of Petroleum Geologists (AAPG)
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Stratal geometry and lithofacies architecture from carbonate outcrops provide critical information for subsurface prediction of rock types, their spatial distribution, and reservoir quality. Such observations guide and support exploration, appraisal, development, and production strategies.
American Association of Petroleum Geologists (AAPG)
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The Honors and Awards Committee selected the 2017 winners. The awards will be given at the AAPG Annual Convention and Exhibition in Houston, in April. Committee members include: Dennis Moore, chair; Peter Baillie, Timothy Gross, Paul Hoffman, Terry Hollrah, Knut Jakobsson, Stephen Ladner, Ryan Lemiski, Melanie Peterson and Justin Vandenbrink.

American Association of Petroleum Geologists (AAPG)
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The Honors and Awards Committee selected the 2017 winners. The awards will be given at the AAPG Annual Convention and Exhibition in Houston, in April. Committee members include: Dennis Moore, chair; Peter Baillie, Timothy Gross, Paul Hoffman, Terry Hollrah, Knut Jakobsson, Stephen Ladner, Ryan Lemiski, Melanie Peterson and Justin Vandenbrink.

American Association of Petroleum Geologists (AAPG)
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The Honors and Awards Committee selected the 2017 winners. The awards will be given at the AAPG Annual Convention and Exhibition in Houston, in April. Committee members include: Dennis Moore, chair; Peter Baillie, Timothy Gross, Paul Hoffman, Terry Hollrah, Knut Jakobsson, Stephen Ladner, Ryan Lemiski, Melanie Peterson and Justin Vandenbrink.

American Association of Petroleum Geologists (AAPG)
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The Nomination and Election Committee selected the 2017 HoD officer candidates. The election of these officers by the House delegates will take place at the AAPG Annual Convention and Exhibition in Houston in April. Committee members include: Dennis Oliver Moore, Peter William Baillie, Timothy Gross, Paul F. Hoffman, Terry L. Hollrah, Knut Henrik Jakobsson, Stephen A. Ladner, Ryan Thgomas Lemiski and Melanie D. Peterson.

American Association of Petroleum Geologists (AAPG)
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The Nomination and Election Committee selected the 2017 HoD officer candidates. The election of these officers by the House delegates will take place at the AAPG Annual Convention and Exhibition in Houston in April. Committee members include: Dennis Oliver Moore, Peter William Baillie, Timothy Gross, Paul F. Hoffman, Terry L. Hollrah, Knut Henrik Jakobsson, Stephen A. Ladner, Ryan Thgomas Lemiski and Melanie D. Peterson.

American Association of Petroleum Geologists (AAPG)
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Recently Added Special Publications
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This volume covers the linkage between new transform margin research and increasing transform margin exploration. It offers a critical set of predictive tools via an understanding of the mechanisms involved in the development of play concept elements at transform margins.
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Originally published in 1991, this memoir offers a unique, detailed analysis on solving one of petroleum geology's most perplexing problems -- reservoir prediction.
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This volume contains 10 chapters on coal-bearing strata of Carboniferous through Tertiary age and is based on a special session taht was held at an AAPG Annual Meeting in New Orleans. Contributors have employed a multitude of approaches ranging from basin analysis to plant taphonomy to support a variety of views on the sequence stratigraphy, paleoclimate, and tectonics of coal-bearing strata.
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A joint publication of the AAPG and SEG, the product offers 30 profusely illustrated case studies from around the world demonstrating practical applications of 3-dimensional seismic data. It includes detailed illustrations in color and black and white, and covers fluvial-deltaic, eolian, deep-water clastic, carbonate, and structural reservoirs. Special emphasis is placed on the application of 3-D data to development drilling, reservoir characterization, and reservoir management. This atlas is designed to confirm 3-D seismic interpretation in drilling and production.
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Subsurface electromagnetic (EM) measurements, namely galvanic resistivity, EM induction, EM propagation, and dielectric dispersion, exhibit frequency dependence due to the interfacial polarization (IP) of clay minerals, clay-sized particles, and conductive minerals. Existing oil-in-place estimation methods based on subsurface EM measurements do not account for dielectric permittivity, dielectric dispersion, and dielectric permittivity anisotropy arising from the IP effects. The conventional interpretation methods generate inaccurate oil-in-place estimates in clay- and pyrite-bearing shales because they separately interpret the multi-frequency effective conductivity and permittivity using empirical models. 

We introduce a new inversion-based method for accurate oil-in-place estimation in clay- and pyrite-bearing shales. The inversion algorithm is coupled with an electrochemical model that accounts for the frequency dispersion in effective conductivity and permittivity due to the above-mentioned IP effects. The proposed method jointly processes the multi-frequency effective conductivity and permittivity values computed from the subsurface EM measurements. The proposed method assumes negligible invasion, negligible borehole rugosity, and lateral and vert ical homogeneity effects. 

The successful application of the new interpretation method is documented with synthetic cases and field data. Water saturation estimates in shale formations obtained with the new interpretation method are compared to those obtained with conventional methods and laboratory measurements. Conventional interpretation of multi-frequency effective conductivity and permittivity well logs in a clay- and pyrite-rich shale formation generated water saturation estimates that varied up to 0. 5 saturation units, as a function of the operating frequency of the EM measurement, at each depth along the formation interval. A joint interpretation of multifrequency conductivity and permittivity is necessary to compute the oil-in-place estimates in such formations. Estimated values of water saturation, average grain size, and surface conductance of clays in that formation are in the range of 0.4 to 0.7, 0.5 micro meter to 5 micrometer, and 5×10 - 7 S to 9×10 - 7 S, respectively. The proposed method is a novel technique to integrate effective conductivity and permittivity at various frequencies. In doing so, the method generates frequency-independent oil-in-place estimates, prevents under-estimation of hydrocarbon saturation, and identifies by-passed zones in shales.

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Relative permeability in shales is an important petrophysical parameter for purposes of accurate estimation of production rate and recovery factor, efficient secondary recovery, and effective water management. We present a method to estimate saturation-dependent relative permeability in shales based on the interpretation of the low-pressure nitrogen adsorption-desorption isotherm measurements. Relative permeability were determined for 30 samples from the gas — and oil — window of Eagle Ford and Wolfcamp shale formations. These sample have low-pressure helium porosity (LPHP) in the range of 0.04 to 0.09 and total organic content (TOC) in the range of 0.02 to 0.06. The samples were ashed to study the effects of removal of organic matter on the pore size distribution, pore connectivity, and relative permeability. The estimated irreducible water saturation and residual hydrocarbon saturation are directly proportional to the TOC and LPHP, and exhibit 15% variation over the entire range. Pore connectivity, in terms of average coordination number, decreases by 33% with the increase in TOC from 0.02 to 0.06. The estimated fractal dimension is close to 2.7 for all the samples. The estimated relative permeability of aqueous phase and that of hydrocarbon phase at a given saturation is inversely proportional to the TOC. Relative permeability curves of the hydrocarbon phase for geological samples from various depths in a 100-feet interval indicate that the hydrocarbon production rate will vary drastically over the entire interval and these variations will increase as the hydrocarbon saturations reduce in the formation. In contrast, relative permeability curves of the aqueous phase suggest limited variation in water production rate over the entire interval. Further, based on the relative permeability curves, the hydrocarbon production is predicted to be negligible for hydrocarbon saturations below 50% and the water production is expected to be negligible for water saturations below than 80%. Efforts are ongoing to use the laboratory-based estimates to predict field-scale production and recovery rates.

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Measurements of fluid wetting characteristic are made routinely on rock samples. However, there are no published petrophysical models to differentiate between oil-wet and water-wet fractions of a reservoir sequence using commonly available log suites. This presentation builds on our previous publication that describes the unconventional reservoir petrophysical model we have developed (Holmes, 2014). Essentially, we define four porosity components, namely total organic carbon, clay porosity, effective porosity, and “free shale porosity.” This last component is an indirect calculation if the first three components do not sum to total porosity. 

Porosity/resistivity plots can be constructed for the total porosity and interpreted in a standard fashion. These will mostly indicate a water-wet system where the effective porosity fraction is examined. A second porosity/resistivity plot compares resistivity with “free shale porosity,” and is clearly interpreted to indicate Archie saturation exponents of much larger than 2 — frequently in excess of 3 — indicating the oil-wet fraction of the reservoir system. Additionally, the plots suggest low to very low values of cementation exponent, ranging from 1.0 to 1.5.  

Examples from the Bakken of Montana and North Dakota, the Niobrara of Colorado, and the Wolfcamp and Spraberry of Texas are presented showing quantitative distinction of water-wet vs. oil-wet reservoir components.

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Interpretations of thermal maturation provide critical data needed for both conventional and unconventional resource assessments. The absence of true vitrinite in pre-Devonian sediments eliminates one of the most commonly measured geothermometers used for thermal maturity determination. Programmed pyrolysis parameters like Tmax can be of limited utility given the maturity regime. However, other organic macerals are potentially available to constrain thermal maturity. The current organic petrology study has been undertaken to provide a very detailed comparison of reflectance measurements on pyrobitumens, “vitrinite-like” material and graptolites. 

In the Appalachian Basin of North America, Cambrian-aged source rocks were deposited in shallow water mixed carbonate-siliciclastic depositional environments. Solid pyrobitumen material is found to occur in both lenticular lens/layer morphology as well as distinct pore-filling angular varieties. Published formulas to calculate Equivalent Reflectance (Eq. Ro) from solid bitumens have been applied to these discrete morphological populations. In addition, a newly developed formula to calculate Eq. Ro from angular pyrobitumen (VRc=0.866*BRo ang + 0.0274) is introduced based upon statistical evaluation of reflectance readings from a global dataset. “Vitrinite-like” organic macerals were found in rare abundance within these potential source rocks, but their occurrence enables an independent comparison to pyrobitumen Eq. Ro values. Graptolites are another organic maceral that can be evaluated via organic petrology, but caution should be utilized since these tend to show a high degree of anisotropy. The results of this investigation provide additional geochemical guidance to assist geologists in more accurately interpreting thermal maturity in the Rome Trough region of the Appalachian Basin.

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Rock-Eval hydrogen index (HI) is often used to compare relative maturities of a source horizon across a basin. Usually, there are several measurements from the source horizon at a single well, and the mean hydrogen index is calculated, or the S2 is plotted against TOC. The slope of the best fit line through that data is used as the representative HI for that well (sometimes referred to as the ‘slope HI ’ methodology). There is a potential flaw in both these methodologies; however, that renders the calculated HI as misleading if the source horizon being examined is not relatively uniform in source quality, vertically in the stratigraphic column. From a geologic perspective, it would be unusual for the source rock quality not to vary vertically in the stratigraphic column. Organic matter input, preservation, dilution, and sediment accumulation rate typically vary in many depositional environments over the millions of years required to create a thick source rock package. Nevertheless, there are source rocks which do display remarkable source-quality uniformity from top to bottom of the stratigraphic package. We have examined source rocks from several basins where the source quality is relatively uniform over the stratigraphic column, and source rocks where the source quality varies greatly over the stratigraphic column. Methodologies to assess hydrogen index at specific wells for the se two scenarios differ. Most geoscientists may not be familiar with why a single technique is not suitable for both these scenarios, or how to correctly use hydrogen index as a relative maturation proxy in the case where source rock quality is not uniform. We will demonstrate how to determine if your source rock quality is uniform or varied relative to HI over the stratigraphic column, and how to assign a hydrogen index to the different source facies when that source rock quality is not uniform. Further we will illustrate how to estimate the original hydrogen index of the different source facies and assign each a transformation ratio. The transformation ratio is a better proxy for relative maturity, since different source facies may have different present-day hydrogen indices, but their present-day transformation ratio should be quite similar.

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Submit your abstract by April 1 to be a part of this year's meeting in beautiful downtown San Antonio!

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Register now for ACE 2017 and experience a remarkable week of science, networking, activities and commemorations celebrating a century of the world’s best geosciences.

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ICE London will deliver a multidisciplinary technical program featuring unmatched global, regional and local expertise, innovations and connections. Whether you're looking for new market breakthroughs or face-time with leading geoscience professionals, you can't afford to miss ICE 2017.

American Association of Petroleum Geologists (AAPG)
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GeoExpro magazine will publish the opinion article post-APPEX Global , by Mike Lakin, APPEX Global Chairman, with their next number –out on April 10th.

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Find out the secrets of the success of the Mid-Continent’s STACK and SCOOP plays. Attend the AAPG DPA MidContinent Playmaker Forum on May 11 in Oklahoma City and learn directly from the operators who have had the most success.

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