Wanted: Posters to Add to GTW Program in Canada

Contributors: Ross Clark, Michael Abrams, Joe Curiale

Concepts and technologies developed for liquid-rich unconventional plays in North America are on the verge of being exported worldwide. An “A list” of geoscientists from Canada, Europe and the United States are joining forces with AAPG Canada Region to offer GTW Canada, Nov. 3-5 in Vancouver, B.C.

Liquid-rich unconventional petroleum systems, defined as “fine-grained rock acting as both hydrocarbon source and reservoir, or a low permeability reservoir with inter-bedded or juxtaposed organic-rich shale with liquid hydrocarbon potential,” have become significant worldwide exploration targets.

Understanding the hydrocarbon charge system (source, maturity, hydrocarbon phase, burial history and retention) and production capabilities (rock properties, flow rates and resource potential) are critical for a liquid-rich unconventional play to be technically and economically successful.

Today, when it is particularly critical to address and improve our current understanding of these key plays, AAPG’s novel GTW format of interdisciplinary presentation and discussion offers an environment to discuss, debate and share knowledge.

GTW Canada will offer 16 invited presentations divided across four oral sessions. Each oral session will be followed by discussion, with a focus on “where we are headed.”

GTW Canada organizers are actively soliciting poster abstracts for the event. Poster sessions will be on display throughout the workshop, and poster presenters will be given time on the program to introduce their poster to the entire GTW audience. Poster sessions will highlight several additional aspects of the workshop theme, including commercial technologies available across the disciplines.

The four principal workshop sessions will begin with presentations on the development of liquid-rich unconventional reservoirs, with a focus on qualifying key reservoir engineering elements of an unconventional oil play.

Presentations will include specific data needed to rank prospects in terms of importance, early development assessment of an unconventional play and evaluating reservoir fluid properties required for low permeability oil reservoir analysis.

A session on liquid-rich source units follows, with a focus on specific organic and inorganic characteristics of liquid-rich plays, plus source rock case studies and geochemical characteristics.

The third session, on analytical and upcoming technologies, presents current and future analytical methods used to assist the evaluation of liquid-rich unconventional plays.

Presentations will include an overview of current approaches, discussions of microstructure and the ongoing concerns over porosity development, and applications of organic petrography.

The final session will focus on worldwide case studies of successful liquid-rich plays, and will include presentations focusing on specific active oil rich plays, including the Eagle Ford, Niobrara, Utica and Duvernay.

Canada’s Hot Activity

Excitement and global attention continues to build around the economic potential of Canada’s liquid-rich unconventional resource plays. To date more than $2.5 billion has been spent on land in and around the two play areas – one northern play area near Kaybob, the other just south of Pembina.

Among the 17 different operators that have licensed horizontal wells, Shell is most active with 17 wells, and ExxonMobil is next with 15 wells. Shell’s activity appears mostly in the northern play area, but has two wells in the southern play area; ExxonMobil is only in the northern play after buying Celtic Exploration.

One of the hottest liquid-rich unconventional shale plays, the Duvernay, has seen more than 100 horizontal wells licensed since the play’s inception approximately 30 months ago. As of this writing, there are more than 40 wells currently on production from the Duvernay.

Although production data is publicly available, interpreting the early production history of the wells is difficult for numerous reasons. Provincially reported liquid yields for C3+ vary from 40 bbls/mmcf to over 110 bbls/mmcf with operators reporting yields of up to 400 bbls/mmcf.

Production from a few wells, however, stands out. One, the Trilogy HZ Kaybob 3-13-60-20 (W5), is producing in excess of 800 mmcf and 70,000 barrels of liquids in about a year. Another is a recent Encana well announced April 24, 2013 with IP30 rates of 4 mmcf and 1,400 bbls per day.

With these results, the play has become one of the most exciting high-liquids-yield shale gas plays in North America.

Data interpretation is one of many challenges that GTW Canada conveners, presenters and participants alike will attempt to crack during the 2 1/2-day workshop. Registration, hotel room reservations and full program details are available at www.aapg.org/gtw/2013/vancouver.

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Regions and Sections

Regions and Sections Column - Carol McGowen
Carol Cain McGowen is the development manager for AAPG's Regions and Sections. She may be contacted via email , or telephone at 1-918-560-9403.

Regions and Sections Column

Regions and Sections is a regular column in the EXPLORER offering news for and about AAPG's six international Regions and six U.S. Sections. News items, press releases and other information should be submitted via email or to: EXPLORER - Regions and Sections, P.O. Box 979, Tulsa, OK 74101. 

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Meet the Authors 

This month’s column is written by the GTW Canada conveners, Ross Clark (Kallisto Energy), Michael Abrams (Apache) and Joe Curiale (Chevron).

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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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Outcrops of the Cretaceous high-porosity sandstone of the Southeast Basin, France, show two main types of deformation structures: a large number of small-offset, shear-enhanced cataclastic deformation bands (DBs); and a small number of large (meters to decameters)-offset ultracataclastic fault zones. Microstructural analyses of the cataclastic DBs show that fragmentation produces strands of cataclastic fragment-supported matrix, separated by weakly fractured host rock, which cluster to form the DBs. The ultracataclastic fault zones, however, are composed of a matrix-supported ultracataclasite material. Permeability data show that the DBs reduce host-rock permeability by 0.5 to 2 orders of magnitude, whereas the ultracataclasites reduce permeability by approximately 4 orders. Simple calculations considering the structural frequency, thickness, and permeability of these faults suggest that, although the DBs may have an impact on single-phase flow, it is most likely to be less than a 50% reduction in flow rate in extensional contexts, but it may be more severe in the most extreme cases of structural density in tectonic shortening contexts. The larger ultracataclastic faults, however, despite their much lower frequency, will have a more significant reduction in flow rate, probably of approximately 90 to 95%. Hence, although they are commonly at or below the limit of seismic resolution, the detection and/or prediction of such ultracataclastic faults is likely to be more important for single-phase flow problems than DBs (although important two-phase questions remain). The study also suggests that it is inappropriate to use the petrophysical properties of core-scale DB structures as analogs to larger seismic-scale faults.
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