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. 

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Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated.

The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures.

Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density.

These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.

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The Tarim Basin is one of the most important hydrocabon-bearing evaporite basins in China. Four salt-bearing sequences, the Middle and Lower Cambrian, the Mississippian, the Paleogene, and the Neogene, have various thickness and areal distribution. They are important detachment layers and intensely affect the structural deformation in the basin. The Kuqa depression is a subordinate structural unit with abundant salt structures in the Tarim Basin. Salt overthrusts, salt pillows, salt anticlines, salt diapirs, and salt-withdrawal basins are predominant in the depression. Contraction that resulted from orogeny played a key function on the formation of salt structures. Growth strata reveal that intense salt structural deformation in the Kuqa depression occurred during the Himalayan movement from Oligocene to Holocene, with early structural deformation in the north and late deformation in the south. Growth sequences also record at least two phases of salt tectonism. In the Yingmaili, Tahe, and Tazhong areas, low-amplitude salt pillows are the most common salt structures, and these structures are commonly accompanied by thrust faults. The faulting and uplifting of basement blocks controlled the location of salt structures. The differences in the geometries of salt structures in different regions show that the thickness of the salt sequences has an important influence on the development of salt-cored detachment folds and related thrust faults in the Tarim Basin.

Salt sequences and salt structures in the Tarim Basin are closely linked to hydrocarbon accumulations. Oil and gas fields have been discovered in the subsalt, intrasalt, and suprasalt strata. Salt deformation has created numerous potential traps, and salt sequences have provided a good seal for the preservation of hydrocarbon accumulations. Large- and small-scale faults related with salt structures have also given favorable migration pathways for oil and gas. When interpreting seismic profiles, special attention needs to be paid to the clastic and carbonate interbeds within the salt sequences because they may lead to incorrect structural interpretation. In the Tarim Basin, the subsalt anticlinal traps are good targets for hydrocarbon exploration.

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The origin of thermogenic natural gas in the shallow stratigraphy of northeastern Pennsylvania is associated, in part, with interbedded coal identified in numerous outcrops of the Upper Devonian Catskill and Lock Haven Formations. Historically documented and newly identified locations of Upper Devonian coal stringers are shown to be widespread, both laterally across the region and vertically throughout the stratigraphic section of the Catskill and Lock Haven Formations. Coal samples exhibited considerable gas source potential with total organic carbon as high as 44.40% by weight, with a mean of 13.66% for 23 sample locations analyzed. Upper Devonian coal is thermogenically mature; calculated vitrinite reflectances range from 1.25% to 2.89%, with most samples falling within the dry-gas window. Source potential is further supported by gas shows observed while drilling through shallow, identifiable coal horizons, which are at times located within fresh groundwater aquifers. Thermogenic gas detected in area water wells during predrill baseline sampling is determined not only to be naturally occurring, but also common in the region.

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The influence of moisture, temperature, coal rank, and differential enthalpy on the methane (CH4) and carbon dioxide (CO2) sorption capacity of coals of different rank has been investigated by using high-pressure sorption isotherms at 303, 318, and 333 K (CH4) and 318, 333, and 348 K (CO2), respectively. The variation of sorption capacity was studied as a function of burial depth of coal seams using the corresponding Langmuir parameters in combination with a geothermal gradient of 0.03 K/m and a normal hydrostatic pressure gradient. Taking the gas content corresponding to 100% gas saturation at maximum burial depth as a reference value, the theoretical CH4 saturation after the uplift of the coal seam was computed as a function of depth. According to these calculations, the change in sorption capacity caused by changing pressure, temperature conditions during uplift will lead consistently to high saturation values. Therefore, the commonly observed undersaturation of coal seams is most likely related to dismigration (losses into adjacent formations and atmosphere). Finally, we attempt to identify sweet spots for CO2-enhanced coalbed methane (CO2-ECBM) production. The CO2-ECBM is expected to become less effective with increasing depth because the CO2-to-CH4 sorption capacity ratio decreases with increasing temperature and pressure. Furthermore, CO2-ECBM efficiency will decrease with increasing maturity because of the highest sorption capacity ratio and affinity difference between CO2 and CH4 for low mature coals.

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Seismic correlations and well data confirm that deep-water carbonate beds of Mesozoic age have been found above the shallow allochthonous salt canopy in the northern Gulf of Mexico. These rafts of carbonate strata often overlie equivalent age Mesozoic carbonates in their correct stratigraphic position below the salt canopy. The presence of displaced Mesozoic carbonate rafts above the canopy raises two important questions: 1) how did Mesozoic strata get to such a shallow level in the basin statigraphy? and 2) what effect do high velocity carbonates have on seismic imaging below shallow salt?

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