Think About It: New Ideas Equal New Success

Some older members of AAPG may remember when geologists, geophysicists and engineers worked under separate supervision and in separate departments in oil and gas companies. It may be hard for some of you to believe, but in many companies there literally was a geology department, a geophysics department and an engineering department.

Why were the disciplines separated? I really don’t know.

Probably, though, it was due primarily to the conceived value of integrated confidential data. I also suspect unhealthy competition, as well as some misguided mistrust, between the different disciplines contributed to the limited sharing of data within a company. By separating the disciplines access to information was carefully controlled, and only upper level management could see the big picture.

Another reason might be educational background. My dad, who also is a geologist and longtime AAPG member, reminded me that geologists, geophysicists and engineers used to be educated separately.

Physicists were hired to be geophysicists, he said. They generally didn’t have any geological course work. And engineers were not required to take any geological courses before they were hired to be petroleum engineers. As a result, it was natural to separate the disciplines into departments.

One older geologist/friend who worked for a major oil company told me that in his era he had to get special permission to look at seismic (2-D) sections, for which specific security was in place to handle their restricted use by geologists – usually under the watchful eye of a senior geophysicist.

My first job was with Cities Service Oil Company. Geologists, geophysicists and engineers were all in our separate departments, and even when we were all working on the same project we worked separately. We geologists generated prospects; they then were vetted for economics by engineers and “shot-out” seismically by the geophysicists.

While I was working at Cities Service, however, things began to change between geologists and geophysicists. The big catalyst seemed to be the publication in 1977 of AAPG Memoir 26, “Seismic Stratigraphy: Applications to Hydrocarbon Exploration.”

At that point geologists began to realize that seismic sections could show more than anticlines and synclines.

In Memoir 26, Peter Vail and his colleagues at Exxon Production Research postulated that seismic reflections are time synchronous and do not necessarily follow lithologic boundaries.

This controversial statement created much debate between geologists and geophysicists – and forced us to begin a dialog about exactly what seismic reflections represent geologically.

You might think it obvious that the two societies that represent petroleum geologists and geophysicists, AAPG and Society of Exploration Geophysicists (SEG), would get together often and have many joint projects where we could exchange ideas. However, there have been very few.

Those few, however, have been notable.

SEG started in 1930 as Society of Economic Geophysicists. In 1932, they changed the name to Society of Petroleum Geophysicists and became affiliated with AAPG, holding joint meetings with AAPG for more than 20 years.

In 1937, they changed their name to what it has been since then: the Society of Exploration Geophysicists.

In 1972, AAPG and SEG co-published Memoir 16, “Stratigraphic Oil and Gas Fields.” Twenty-four years later, in 1986, AAPG and SEG co-published Memoir 42, “Interpretation of Three Dimensional Seismic Data,” written by AAPG member Alistair Brown. It has been a tremendous success and is now in the seventh edition.

This year SEG and AAPG are joint partners in two potentially very significant new projects:

One, initiated by SEG, is a new journal to be called, INTERPRETATION. As described in the March EXPLORER , SEG and AAPG will share editorial responsibilities and expenses for this publication.

INTERPRETATION will be less technical than SEG’s Journal of Geophysics and more technical, in terms of geophysics, than the AAPG BULLETIN.

The other huge new project was initiated by AAPG through an idea generated by AAPG’s former executive director, Rick Fritz, about a new conference that brings AAPG back together with SEG for the first time for joint involvement in a meeting since the 1950s.

The meeting will be called the Unconventional Resources Technology Conference, or URTeC for short.

URTeC, however, is being started not just by SEG and AAPG but also in partnership with the Society of Petroleum Engineers (SPE) – and this new, science-driven event marks the first time all three societies have been in such partnership.

The first URTeC will be held Aug. 12-14 in Denver.

Finally, geologists, geophysicists and engineers are formally getting together to share ideas concerning the exploration for and development of unconventional reservoirs.

Why was URTeC created? It is the understandable product of blending the disciplines for more effective exploration and development of unconventional resource plays. For example, engineers realize that an understanding of geological variation of shale gas reservoirs leads to better completion designs and, therefore, higher initial flow rates and higher EURs.

I sincerely hope all of this is just the beginning. Previous AAPG presidents like Dick Bishop have dreamed of the benefits of inter-society cooperation. One can only imagine what synergism between AAPG, SEG and SPE will create.

At first we were hesitant to trust each other, but we realized the more we combined our skills the better we were at finding oil and gas.

If we all forget our self-interests and work together we only have one place to go – onward and upward!

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President's Column

President's Column - Ted Beaumont

Edward A. "Ted" Beaumont, AAPG President (2012-13), is an independent consultant with Cimarex Energy.

President's Column

AAPG Presidents offer thoughts and information about their experiences for the Association. 


See Also: Bulletin Article

Estimation of the dimensions of fluvial geobodies from core data is a notoriously difficult problem in reservoir modeling. To try and improve such estimates and, hence, reduce uncertainty in geomodels, data on dunes, unit bars, cross-bar channels, and compound bars and their associated deposits are presented herein from the sand-bed braided South Saskatchewan River, Canada. These data are used to test models that relate the scale of the formative bed forms to the dimensions of the preserved deposits and, therefore, provide an insight as to how such deposits may be preserved over geologic time. The preservation of bed-form geometry is quantified by comparing the alluvial architecture above and below the maximum erosion depth of the modern channel deposits. This comparison shows that there is no significant difference in the mean set thickness of dune cross-strata above and below the basal erosion surface of the contemporary channel, thus suggesting that dimensional relationships between dune deposits and the formative bed-form dimensions are likely to be valid from both recent and older deposits.

The data show that estimates of mean bankfull flow depth derived from dune, unit bar, and cross-bar channel deposits are all very similar. Thus, the use of all these metrics together can provide a useful check that all components and scales of the alluvial architecture have been identified correctly when building reservoir models. The data also highlight several practical issues with identifying and applying data relating to cross-strata. For example, the deposits of unit bars were found to be severely truncated in length and width, with only approximately 10% of the mean bar-form length remaining, and thus making identification in section difficult. For similar reasons, the deposits of compound bars were found to be especially difficult to recognize, and hence, estimates of channel depth based on this method may be problematic. Where only core data are available (i.e., no outcrop data exist), formative flow depths are suggested to be best reconstructed using cross-strata formed by dunes. However, theoretical relationships between the distribution of set thicknesses and formative dune height are found to result in slight overestimates of the latter and, hence, mean bankfull flow depths derived from these measurements.

This article illustrates that the preservation of fluvial cross-strata and, thus, the paleohydraulic inferences that can be drawn from them, are a function of the ratio of the size and migration rate of bed forms and the time scale of aggradation and channel migration. These factors must thus be considered when deciding on appropriate length:thickness ratios for the purposes of object-based modeling in reservoir characterization.

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The geometries of clay smears produced in a series of direct shear experiments on composite blocks containing a clay-rich seal layer sandwiched between sandstone reservoir layers have been analyzed in detail. The geometries of the evolving shear zones and volume clay distributions are related back to the monitored hydraulic response, the deformation conditions, and the clay content and strength of the seal rock. The laboratory experiments were conducted under 4 to 24 MPa (580–3481 psi) fault normal effective stress, equivalent to burial depths spanning from less than approximately 0.8 to 4.2 km (0.5 to 2.6 mi) in a sedimentary basin. The sheared blocks were imaged using medical-type x-ray computed tomography (CT) imaging validated with optical photography of sawn blocks. The interpretation of CT scans was used to construct digital geomodels of clay smears and surrounding volumes from which quantitative information was obtained. The distribution patterns and thickness variations of the clay smears were found to vary considerably according to the level of stress applied during shear and to the brittleness of the seal layer. The stiffest seal layers with the lowest clay percentage formed the most segmented clay smears. Segmentation does not necessarily indicate that the fault seal was breached because wear products may maintain the seal between the individual smear segments as they form. In experiments with the seal layer formed of softer clays, a more uniform smear thickness is observed, but the average thickness of the clay smear tends to be lower than in stiffer clays. Fault drag and tapering of the seal layer are limited to a region close to the fault cutoffs. Therefore, the comparative decrease of sealing potential away from the cutoff zones differs from predictions of clay smear potential type models. Instead of showing a power-law decrease away from the cutoffs toward the midpoint of the shear zone, the clay smear thickness is either uniform, segmented, or undulating, reflecting the accumulated effects of kinematic processes other than drag. Increased normal stress improved fault sealing in the experiments mainly by increasing fault zone thickness, which led to more clay involvement in the fault zone per unit of source layer thickness. The average clay fraction of the fault zone conforms to the prediction of the shale gouge ratio (SGR) model because clay volume is essentially preserved during the deformation process. However, the hydraulic seal performance does not correlate to the clay fraction or SGR but does increase as the net clay volume in the fault zone increases. We introduce a scaled form of SGR called SSGR to account for increased clay involvement in the fault zone caused by higher stress and variable obliquity of the seal layer to the fault zone. The scaled SGR gives an improved correlation to seal performance in our samples compared to the other algorithms.
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Characterization of oil shale kerogen and organic residues remaining in postpyrolysis spent shale is critical to the understanding of the oil generation process and approaches to dealing with issues related to spent shale. The chemical structure of organic matter in raw oil shale and spent shale samples was examined in this study using advanced solid-state 13C nuclear magnetic resonance (NMR) spectroscopy. Oil shale was collected from Mahogany zone outcrops in the Piceance Basin. Five samples were analyzed: (1) raw oil shale, (2) isolated kerogen, (3) oil shale extracted with chloroform, (4) oil shale retorted in an open system at 500degC to mimic surface retorting, and (5) oil shale retorted in a closed system at 360degC to simulate in-situ retorting. The NMR methods applied included quantitative direct polarization with magic-angle spinning at 13 kHz, cross polarization with total sideband suppression, dipolar dephasing, CHn selection, 13C chemical shift anisotropy filtering, and 1H-13C long-range recoupled dipolar dephasing. The NMR results showed that, relative to the raw oil shale, (1) bitumen extraction and kerogen isolation by demineralization removed some oxygen-containing and alkyl moieties; (2) unpyrolyzed samples had low aromatic condensation; (3) oil shale pyrolysis removed aliphatic moieties, leaving behind residues enriched in aromatic carbon; and (4) oil shale retorted in an open system at 500degC contained larger aromatic clusters and more protonated aromatic moieties than oil shale retorted in a closed system at 360degC, which contained more total aromatic carbon with a wide range of cluster sizes.
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See Also: DL Abstract

Numerous studies of sediment-dispersal systems have focused on the relative role of allogenic versus autogenic controls, and their stratigraphic imprint. Advancing our understanding of these vital issues depends heavily on geochronology.

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