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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A series of short and steep unidirectionally migrating deep-water channels, which are typically without levees and migrate progressively northeastward, are identified in the Baiyun depression, Pearl River Mouth Basin. Using three-dimensional seismic and well data, the current study documents their morphology, internal architecture, and depositional history, and discusses the distribution and depositional controls on the bottom current–reworked sands within these channels.

Unidirectionally migrating deep-water channels consist of different channel-complex sets (CCSs) that are, overall, short and steep, and their northeastern walls are, overall, steeper than their southwestern counterparts. Within each CCS, bottom current–reworked sands in the lower part grade upward into muddy slumps and debris-flow deposits and, finally, into shale drapes.

Three stages of CCSs development are recognized: (1) the early lowstand incision stage, during which intense gravity and/or turbidity flows versus relatively weak along-slope bottom currents of the North Pacific intermediate water (NPIW-BCs) resulted in basal erosional bounding surfaces and limited bottom current–reworked sands; (2) the late lowstand lateral-migration and active-fill stage, with gradual CCS widening and progressively northeastward migration, characterized by reworking of gravity- and/or turbidity-flow deposits by vigorous NPIW-BCs and the CCSs being mainly filled by bottom current–reworked sands and limited slumps and debris-flow deposits; and (3) the transgression abandonment stage, characterized by the termination of the gravity and/or turbidity flows and the CCSs being widely draped by marine shales. These three stages repeated through time, leading to the generation of unidirectionally migrating deep-water channels.

The distribution of the bottom current–reworked sands varies both spatially and temporally. Spatially, these sands mainly accumulate along the axis of the unidirectionally migrating deep-water channels and are preferentially deposited to the side toward which the channels migrated. Temporally, these sands mainly accumulated during the late lowstand lateral-migration and active-fill stage.

The bottom current–reworked sands developed under the combined action of gravity and/or turbidity flows and along-slope bottom currents of NPIW-BCs. Other factors, including relative sea level fluctuations, sediment supply, and slope configurations, also affected the formation and distribution of these sands. The proposed distribution pattern of the bottom current–reworked sands has practical implications for predicting reservoir occurrence and distribution in bottom current–related channels.

Desktop /Portals/0/PackFlashItemImages/WebReady/upper-miocene-to-quaternary.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 3665 Bulletin Article

Sequence stratigraphy and coal cycles based on accommodation trends were investigated in the coal-bearing Lower Cretaceous Mannville Group in the Lloydminster heavy oil field, eastern Alberta. The study area is in a low accommodation setting on the cratonic margin of the Western Canada sedimentary basin. Geophysical log correlation of coal seams, shoreface facies, and the identification of incised valleys has produced a sequence-stratigraphic framework for petrographic data from 3 cored and 115 geophysical-logged wells. Maceral analysis, telovitrinite reflectance, and fluorescence measurements were taken from a total of 206 samples. Three terrestrial depositional environments were interpreted from the petrographic data: ombrotrophic mire coal, limnotelmatic mire coal, and carbonaceous shale horizons. Accommodation-based coal (wetting- and drying-upward) cycles represent trends in depositional environment shifts, and these cycles were used to investigate the development and preservation of the coal seams across the study area.

The low-accommodation strata are characterized by a high-frequency occurrence of significant surfaces, coal seam splitting, paleosol, and incised-valley development. Three sequence boundary unconformities are identified in only 20 m (66 ft) of strata. Coal cycle correlations illustrate that each coal seam in this study area was not produced by a single peat-accumulation episode but as an amalgamation of a series of depositional events. Complex relations between the Cummings and Lloydminster coal seams are caused by the lateral fragmentation of strata resulting from the removal of sediment by subaerial erosion or periods of nondeposition. Syndepositional faulting of the underlying basement rock changed local accommodation space and increased the complexity of the coal cycle development.

This study represents a low-accommodation example from a spectrum of stratigraphic studies that have been used to establish a terrestrial sequence-stratigraphic model. The frequency of changes in coal seam quality is an important control on methane distribution within coalbed methane reservoirs and resource calculations in coal mining. A depositional model based on the coal cycle correlations, as shown by this study, can provide coal quality prediction for coalbed methane exploration, reservoir completions, and coal mining.

Desktop /Portals/0/PackFlashItemImages/WebReady/accommodation-based-coal-cycles-and-significant.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 5686 Bulletin Article

West Edmond field, located in central Oklahoma, is one of the largest oil accumulations in the Silurian–Devonian Hunton Group in this part of the Anadarko Basin. Production from all stratigraphic units in the field exceeds 170 million barrels of oil (MMBO) and 400 billion cubic feet of gas (BCFG), of which approximately 60 MMBO and 100 BCFG have been produced from the Hunton Group. Oil and gas are stratigraphically trapped to the east against the Nemaha uplift, to the north by a regional wedge-out of Hunton strata, and by intraformational diagenetic traps. Hunton Group reservoirs are the Bois d'Arc and Frisco Limestones, with lesser production from the Chimneyhill subgroup, Haragan Shale, and Henryhouse Formation.

Hunton Group cores from three wells that were examined petrographically indicate that complex diagenetic relations influence permeability and reservoir quality. Greatest porosity and permeability are associated with secondary dissolution in packstones and grainstones, forming hydrocarbon reservoirs. The overlying Devonian–Mississippian Woodford Shale is the major petroleum source rock for the Hunton Group in the field, based on one-dimensional and four-dimensional petroleum system models that were calibrated to well temperature and Woodford Shale vitrinite reflectance data. The source rock is marginally mature to mature for oil generation in the area of the West Edmond field, and migration of Woodford oil and gas from deeper parts of the basin also contributed to hydrocarbon accumulation.

Desktop /Portals/0/PackFlashItemImages/WebReady/Bulletin-hero-2013-07jul.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 3770 Bulletin Article

Analog outcrops are commonly used to develop predictive reservoir models and provide quantitative parameters that describe the architecture and facies distribution of sedimentary deposits at a subseismic scale, all of which aids exploration and production strategies. The focus of this study is to create a detailed geological model that contains realistic reservoir parameters and to apply nonlinear acoustic full-waveform prestack seismic inversion to this model to investigate whether this information can be recovered and to examine which geological features can be resolved by this process.

Outcrop data from the fluviodeltaic sequence of the Book Cliffs (Utah) are used for the geological and petrophysical two-dimensional model. Eight depositional environments are populated with average petrophysical reservoir properties adopted from a North Sea field. These units are termed lithotypes here. Synthetic acoustic prestack seismic data are then generated with the help of an algorithm that includes all internal multiples and transmission effects. A nonlinear acoustic full-waveform inversion is then applied to the synthetic data, and two media parameters, compressibility (inversely related to the square of the compressional wave velocity vP) and bulk density, ρ, are recovered at a resolution higher than the shortest wavelength in the data. This is possible because the inversion exploits the nonlinear nature of the relationship between the recorded data and the medium contrast properties. In conventional linear inversion, these details remain masked by the noise caused by the nonlinear effects in the data. Random noise added to the data is rejected by the nonlinear inversion, contributing to improved spatial resolution. The results show that the eight lithotypes can be successfully recovered at a subseismic scale and with a low degree of processing artifacts. This technique can provide a useful basis for more accurate reservoir modeling and field development planning, allowing targeting of smaller reservoir units such as distributary channels and lower shoreface sands.

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See Also: DL Abstract

As the cost of finding and extracting oil and gas rises, petroleum companies must increasingly resort to proprietary and custom technology to gain or maintain a competitive edge. In contrast, the data we purchase and human resources employed are shared throughout the industry.

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