AAPG Publications

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This paper shows how non-uniform sources-receiver spacing in a 3D land acquisition creates footprints that could easily be mistaken for geology.
American Association of Petroleum Geologists (AAPG)
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Geomechanical restoration methods are dependent on boundary conditions to ensure geological consistency of the restored model in terms of geometry and strain. Classical restoration boundary conditions, such as flattening a datum horizon, may lead to inconsistent displacement and strain fields.
American Association of Petroleum Geologists (AAPG)
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The Cretaceous hosts the highest hydrocarbon potential among all geological stratigraphic sequences worldwide, and the Lower Cretaceous in coastal southeastern China, with the development of black mudstones and shales, has potential for hydrocarbon generation.
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 10.1306/0503171617917074 Hydrocarbon potential of the Lower Cretaceous mudstones in coastal southeastern China
We use experimental (analog) models to examine the 3D fault geometries and interactions that develop during two phases of non-coaxial extension. In the models, a homogeneous layer of wet clay undergoes two phases of extension whose directions differ by 45°.
American Association of Petroleum Geologists (AAPG)
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Three-dimensional petroleum systems modeling used in combination with stochastic methods can provide a powerful toolset to predict the presence of oil and gas in undrilled exploration prospects.
American Association of Petroleum Geologists (AAPG)
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The AAPG Foundation’s Trustee Associates are looking for some new members – and for a limited time, joining this terrific and important group is easier than ever.

American Association of Petroleum Geologists (AAPG)
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The Association leadership has made the decision to allow non-members to temporarily join SIGs and TIGs to preview what these groups have to offer.

American Association of Petroleum Geologists (AAPG)
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The present day Cretaceous Codell oil and gas development in the central portion of the Denver Basin of Colorado can be attributed to an earlier effort in bringing the Codell to the attention of the industry.

American Association of Petroleum Geologists (AAPG)
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Many areas of the western Barents Sea host shallow as well as deep-seated hydrocarbon accumulations from which fluids are migrating to the sea floor. Evidence of past episodes of gas migration can be seen in the form of pockmarks on the sea floor as well as vertical pipes or chimneys on seismic sections.

American Association of Petroleum Geologists (AAPG)
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Having just returned from a fantastic Annual Convention and Exhibition in Houston, to celebrate the 100th anniversary of AAPG, I’m feeling very encouraged about the future of our Association.

American Association of Petroleum Geologists (AAPG)
Desktop /Portals/0/PackFlashItemImages/WebReady/draucker-anne-2017-05may.jpg?width=100&h=100&mode=crop&anchor=middlecenter&quality=75amp;encoder=freeimage&progressive=true Excitement for the Next 100 Years
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 17 papers in this volume cover topics such as a method to estimate the amount of oil/gas accumulation using the concept of equivalent grain size in seal rock, and oil/gas migration to and spill-point geometry of petroleum traps; two case studies of fault seal assessment applied to normal faults in Tertiary clastic reservoirs in offshore Sarawak and offshore Gulf of Thailand; and physical analog studies of the development of extensional faults.

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Divided into two parts with 14 chapters and 5 appendices, the data presented in this volume allows faults to be mapped and correlated with more confidence than before, basin evolution to be examined over a long time period, and some relationships between tectonics and sedimentation to be studied.
Recently Added

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)
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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.

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)
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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.

Show more American Association of Petroleum Geologists (AAPG)
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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.

Show more American Association of Petroleum Geologists (AAPG)
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Early bird registration closes Thursday, May 25. Don't miss out on registration and hotel discounts - register now!

American Association of Petroleum Geologists (AAPG)
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The summer of 2017 is the summer for AAPG and the Visiting Geoscientist Program! Each Tuesday and Thursday, beginning 6 June, join Visiting Geoscientist Fred Schroeder for a one-hour live webinar. The series follows a two-semester course designed and developed by Schroeder to instruct students on the basics of geology and geophysics in the petroleum industry.

American Association of Petroleum Geologists (AAPG)
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Give your company maximum exposure to a target audience of qualified geoscientists and engineers connecting on all things unconventional. Grab your sponsorships for the industry's premier science-based conference and marketplace for unconventional exploration, drilling, and production technologies.

American Association of Petroleum Geologists (AAPG)
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Attend the premier event focused on the latest science and technology applied to the exploration, appraisal, analysis, and development of unconventional resources. URTeC remains the only event that brings the entire asset team together under one roof to connect on all things unconventional.

American Association of Petroleum Geologists (AAPG)
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Get involved in AAPG N.E.T., an online space for TIGs and SIGs where you can Network, Engage and Talk with other geoscientists.

American Association of Petroleum Geologists (AAPG)
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