Explorer Emphasis Article
By Ken Milam
Last year, the extraordinarily high quality of the technical program was the talk of the AAPG Annual Convention and Exhibition in Calgary, and this was at an ACE with plenty of high points to talk about. The technical program for the 2017 ACE in Houston promises to be even better than last year’s.
American Association of Petroleum Geologists (AAPG)
Added on 01 March, 2017
Explorer Emphasis Article
By Emily Llinás
Deep water and tight rocks. These terms define most new discovery trends taking place across the globe today, according to Bob Fryklund, chief strategist for upstream at IHS Markit.
American Association of Petroleum Geologists (AAPG)
Added on 01 March, 2017
Explorer Article
By Barry Friedman
Drones and other automata will be more commonplace in the oil field of tomorrow, but they have some obstacles to clear first.
American Association of Petroleum Geologists (AAPG)
Added on 01 March, 2017
Explorer Article
By David Brown
The oil and gas industry is facing a tidal wave of retirements as the Great Crew Change occurs, but the challenges of replacing technical professionals might not be as difficult as you think. On the other hand, they might be considerably worse.
American Association of Petroleum Geologists (AAPG)
Added on 01 March, 2017
Spheres of Influence Article
By Dan Jackson
Reliable access to safe, clean drinking water is something most people in the United States take for granted. We turn on our tap and out comes clean water! We brush our teeth, wash our clothes, cook our meals and bathe our children. In the United States, it’s abundant, reliable and relatively cheap. Even kings of the past didn’t have such luxury.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2017
Spheres of Influence Article
By Timothy Murin
Environmental issues are a worldwide concern - the Division of Environmental Geosciences has an obligation to provide science-based opinions of these issues to educate the public, government officials and other petroleum industry professionals.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2017
Search and Discovery Article
By Shiv P. Ojha,Siddarth Misra
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)
Added on 17 February, 2017
Search and Discovery Article
By Anthony Holmes,Dominic I. Holmes,Michael Holmes
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)
Added on 17 February, 2017
Search and Discovery Article
By Albert S. Wylie,Samuel D. Ely,Tim Ruble,Wayne R. Knowles
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)
Added on 17 February, 2017
Search and Discovery Article
By Cat Campbell,Mark H. Tobey
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)
Added on 17 February, 2017