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The structural history of the Mississippi Canyon, Atwater Valley, western DeSoto, and western Lloyd Ridge protraction areas in the northeastern deep-water Gulf of Mexico is of a basin influenced by complex salt tectonics that controlled the formation of intraslope minibasins and sediment distribution.
American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true 10.1306/09011609186 Geometry and kinematics of Neogene allochthonous salt systems in the Mississippi Canyon, Atwater Valley, western Lloyd Ridge, and western DeSoto Canyon protraction areas, northern deep-water Gulf of Mexico
 
The petroleum geology of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas, offshore northern Gulf of Mexico, is controlled by the interaction of salt tectonics and high sedimentation rate during the Neogene and resulted in a complex distribution of reservoirs and traps.
American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true 10.1306/09011610093 Petroleum geology of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas, northern deep-water Gulf of Mexico: Traps, reservoirs, and tectono-stratigraphic evolution
 
The petroleum systems of two adjacent Miocene intraslope minibasins in the northern deep-water Gulf of Mexico are modeled to investigate why one of them produces primarily gas but the other produces oil. Specifically, the Mensa field produces gas from a faulted four-way closure that overlies a turtle structure, whereas the adjacent Thunder Horse field produces from a turtle structure with four-way structural closure.
American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true 10.1306/09011608153 Three-dimensional petroleum systems modeling of the Mensa and Thunder Horse intraslope basins, northern deep-water Gulf of Mexico: A case study
 
Thunder Horse and Mensa are two of the largest fields of oil or gas, respectively, in the northern deep-water Gulf of Mexico. The fields are present in adjacent intraslope minibasins, located approximately 12 mi (19 km) apart in Mississippi Canyon. Both fields illustrate important complexities of deep-water sedimentation.
American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true 10.1306/09011608160 Sequence stratigraphic evolution of the Mensa and Thunder Horse intraslope basins, northern deep-water Gulf of Mexico—Lower Cretaceous through upper Miocene (8.2 Ma): A case study
 
The structural framework and evolution from the Middle Jurassic to the present of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas consist of a complex history influenced by basement fabric, multiple stages of salt movement, and gravitational gliding.
American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true 10.1306/09011609187 Regional structural setting and evolution of the Mississippi Canyon, Atwater Valley, western Lloyd Ridge, and western DeSoto Canyon protraction areas, northern deep-water Gulf of Mexico
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The AAPG Foundation is committed to the next generation of geoscientists, from introduction of geology through hands-on programs to grants and scholarships that aid students with their studies.

American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/preparing-the-next-generation-of-geoscientists-hero.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true Preparing the Next Generation of Geoscientists
 

This ProTracks marks our last column as chairs of the Young Professionals Special Interest Group (YP SIG). We have been involved with the YPs for a collective 17 years.

American Association of Petroleum Geologists (AAPG)
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In a recent EXPLORER, Marlan Downey lamented that he had not fully appreciated the idea that source rocks could serve as reservoir rocks for oil and natural gas. He was not alone.

American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/a-retrospective-on-source-rocks-as-reservoir-rocks-hero.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true A Retrospective on Source Rocks as Reservoir Rocks
 

Determination of petrophysical properties such as water saturation, effective porosity and permeability, can be carried out using extended elastic impedance approach.

American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/quantifying-shallow-seismic-anomalies-hero.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true Quantifying Shallow Seismic Anomalies
 

I have very much enjoyed representing the Division as its president. It has given me the opportunity to work with all levels of AAPG membership in the United States and internationally. AAPG is truly a global organization.

American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/murin-tim.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true Appreciation for a Year of Service
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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The publication places particular emphasis on the kind of data that allows trends to be established that can be projected far into the future. It provides the foundation for readers to broaden their knowledge about past energy consumption and its sources of supply. It also furnishes a glimpse into the future of how, and how much, energy will be consumed in the 21st century and what sources will most likely supply it.

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Noted authority Andrew Robinson compiled this research for all geoscientists interested in this region stretching from Greece to the Caspian Sea. Scientists, many from the area, explore the diverse and complex geotectonism.
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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.

Show more American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/sd-Improved-Oil-in-Place-Estimates-in-Clay--and-Pyrite-Bearing-Shales-hero.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true Improved Oil-in-Place Estimates in Clay- and Pyrite-Bearing Shales
 

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.

Show more American Association of Petroleum Geologists (AAPG)
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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.

Show more American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/sd-A-Petrophysical-Model-to-Distinguish-Water-Wet-and-Oil-Wet-Fractions-hero.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true A Petrophysical Model to Distinguish Water-Wet and Oil-Wet Fractions of Unconventional Reservoir Systems Using Triple-Combo Log Suites
 

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.

Show more American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/sd-Assessing-Thermal-Maturity-in-Cambrian-Source-Rocks-Rome-Trough-Appalachian-Basin-Organic-Petrology-Complexities-hero.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true Assessing Thermal Maturity in Cambrian Source Rocks, Rome Trough, Appalachian Basin: Organic Petrology Complexities
 

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.

Show more American Association of Petroleum Geologists (AAPG)
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Unlike many workshops that focus on new technologies for doing “this” or “that,” this workshop on Decision Based Integrated Modeling (DBM) is going to focus on “doing the right thing” for the “right reasons.”

American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/mer-gtw-decision-based-integrated-resevoir-modeling-hero.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true 27-28 October 2017 | Muscat, Oman Block Your Calendar for This Unique GTW on Decision Based Modeling!
 

On 12th June 2017 under the umbrella of the AAPG VGP program, Edith was able to deliver a lecture at the University of Johannesburg.

American Association of Petroleum Geologists (AAPG)
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The 2017 AAPG GTW workshop on Unconventional hydrocarbons successfully kicked-off on 20th June at the Century City Conference Centre in Cape Town, South Africa.

American Association of Petroleum Geologists (AAPG)
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The oil and gas industry encourages work–life balance amongst its professionals, hence the Young Professionals (YP) of the Nigerian Association of Petroleum Explorationists (NAPE) and the African Region of the American Association of Petroleum Geologists (AAPG) led by Austin Mgbemere and Demola Lanisa respectively, had a Social Hangout at the Lekki Conservation Centre, Lagos on 18th March, 2017.

American Association of Petroleum Geologists (AAPG)
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The fourth AAPG/EAGE workshop will be the first of its kind in terms of solely focusing on the experiences gained in exploring and developing tight reservoirs in the Middle East across the different disciplines (geology, geophysics and engineering).

American Association of Petroleum Geologists (AAPG)
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